Document ID: EPA-HQ-OAR-2013-0602-0001
Agency: epa
Document Type: Proposed Rule
Title: Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units
Posted Date: 2014-06-18T04:00Z

[Federal Register Volume 79, Number 117 (Wednesday, June 18, 2014)]
[Proposed Rules]
[Pages 34829-34958]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2014-13726]

[[Page 34829]]

Vol. 79

Wednesday,

No. 117

June 18, 2014

Part II

 Environmental Protection Agency

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40 CFR Part 60

Carbon Pollution Emission Guidelines for Existing Stationary Sources: 
Electric Utility Generating Units; Proposed Rule

  Federal Register / Vol. 79 , No. 117 / Wednesday, June 18, 2014 / 
Proposed Rules  

[[Page 34830]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2013-0602; FRL-9911-86-OAR]
RIN 2060-AR33

Carbon Pollution Emission Guidelines for Existing Stationary 
Sources: Electric Utility Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: In this action, the Environmental Protection Agency (EPA) is 
proposing emission guidelines for states to follow in developing plans 
to address greenhouse gas emissions from existing fossil fuel-fired 
electric generating units. Specifically, the EPA is proposing state-
specific rate-based goals for carbon dioxide emissions from the power 
sector, as well as guidelines for states to follow in developing plans 
to achieve the state-specific goals. This rule, as proposed, would 
continue progress already underway to reduce carbon dioxide emissions 
from existing fossil fuel-fired power plants in the United States.

DATES: Comments on the proposed rule. Comments must be received on or 
before October 16, 2014. Comments on the information collection 
request. 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 June 
18, 2014, a comment to the OMB is best assured of having its full 
effect if the OMB receives it by July 18, 2014.
    Public Hearing. Four public hearings will be convened. On July 29, 
2014, one public hearing will be held in Atlanta, Georgia, at the Sam 
Nunn Atlanta Federal Center Main Tower Bridge Conference Area, 
Conference Room B, 61 Forsyth Street SW., Atlanta, GA 30303, and one 
will be held in Denver, Colorado, at the EPA's Region 8 Building, 1595 
Wynkoop Street, Denver, Colorado 80202. On July 30, 2014, a public 
hearing will be held in Washington, DC, at the William Jefferson 
Clinton East Building, Room 1152, 1201 Constitution Avenue NW., 
Washington, DC 20004. On July 31, 2014, a public hearing will be held 
in Pittsburgh, Pennsylvania at the William S. Moorhead Federal 
Building, Room 1310, 1000 Liberty Avenue, Pittsburgh, Pennsylvania 
15222. The hearings in Pittsburgh, Pennsylvania, Atlanta, Georgia, and 
Washington, DC, will convene at 9:00 a.m. and end at 8:00 p.m. (Eastern 
Standard Time). The hearing in Denver, Colorado, will convene at 9:00 
a.m. and end at 8:00 p.m. (Mountain Daylight Time). For all hearings 
there will be a lunch break from 12:00 p.m. to 1:00 p.m. and a dinner 
break from 5:00 p.m. to 6:00 p.m. Please contact Ms. Pamela Garrett at 
919-541-7966 or at garrett.pamela@epa.gov to register to speak at one 
of the hearings. The last day to pre-register in advance to speak at 
the hearings will be Friday, July 25, 2014. Additionally, requests to 
speak will be taken the day of the hearings at the hearing registration 
desk, although preferences on speaking times may not be able to be 
fulfilled. If you require the service of a translator or special 
accommodations such as audio description, please let us know at the 
time of registration.
    The hearings will provide interested parties the opportunity to 
present data, views or arguments concerning the proposed action. The 
EPA will make every effort to accommodate all speakers who arrive and 
register. Because these hearings are being held at U.S. government 
facilities, individuals planning to attend the hearing should be 
prepared to show valid picture identification to the security staff in 
order to gain access to the meeting room. Please note that the REAL ID 
Act, passed by Congress in 2005, established new requirements for 
entering federal facilities. These requirements will take effect July 
21, 2014. If your driver's license is issued by Alaska, American Samoa, 
Arizona, Kentucky, Louisiana, Maine, Massachusetts, Minnesota, Montana, 
New York, Oklahoma, or the state of Washington, you must present an 
additional form of identification to enter the federal buildings where 
the public hearings will be held. Acceptable alternative forms of 
identification include: Federal employee badges, passports, enhanced 
driver's licenses and military identification cards. We will list any 
additional acceptable forms of identification at: http://www2.epa.gov/cleanpowerplan/. In addition, you will need to obtain a property pass 
for any personal belongings you bring with you. Upon leaving the 
building, you will be required to return this property pass to the 
security desk. No large signs will be allowed in the building, cameras 
may only be used outside of the building and demonstrations will not be 
allowed on federal property for security reasons.
    The EPA may ask clarifying questions during the oral presentations, 
but will not respond to the presentations at that time. Written 
statements and supporting information submitted during the comment 
period will be considered with the same weight as oral comments and 
supporting information presented at the public hearing. Commenters 
should notify Ms. Garrett if they will need specific equipment, or if 
there are other special needs related to providing comments at the 
hearings. Verbatim transcripts of the hearings and written statements 
will be included in the docket for the rulemaking. The EPA will make 
every effort to follow the schedule as closely as possible on the day 
of the hearing; however, please plan for the hearings to run either 
ahead of schedule or behind schedule. Additionally, more information 
regarding the hearings will be available at: http://www2.epa.gov/cleanpowerplan/.

ADDRESSES: Comments. Submit your comments, identified by Docket ID No. 
EPA-HQ-OAR-2013-0602, by one of the following methods:
    Federal eRulemaking portal: http://www.regulations.gov. Follow the 
online instructions for submitting comments.
    Email: A-and-R-Docket@epa.gov. Include docket ID No. EPA-HQ-OAR-
2013-0602 in the subject line of the message.
    Facsimile: (202) 566-9744. Include docket ID No. EPA-HQ-OAR-2013-
0602 on the cover page.
    Mail: Environmental Protection Agency, EPA Docket Center (EPA/DC), 
Mail code 28221T, Attn: Docket ID No. EPA-HQ-OAR-2013-0602, 1200 
Pennsylvania Ave. NW., Washington, DC 20460. 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 the EPA, 725 17th St. NW., Washington, DC 20503.
    Hand/Courier Delivery: EPA Docket Center, Room 3334, EPA WJC West 
Building, 1301 Constitution Ave. NW., Washington, DC 20004, Attn: 
Docket ID No. EPA-HQ-OAR-2013-0602. Such deliveries are accepted only 
during the Docket Center's normal hours of operation (8:30 a.m. to 4:30 
p.m., Monday through Friday, excluding federal holidays), and special 
arrangements should be made for deliveries of boxed information.
    Instructions: All submissions must include the agency name and 
docket ID number (EPA-HQ-OAR-2013-0602). The EPA's policy is to include 
all comments received without change, including any personal 
information provided, in the public docket, available online at http://www.regulations.gov, unless the comment includes information claimed to 
be Confidential

[[Page 34831]]

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: Mr. 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-2013-0602. Clearly mark the part or all of the information 
that you claim to be CBI. For CBI information on 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 you claim as CBI. In addition to one complete version of 
the comment that includes information claimed as CBI, you must submit a 
copy of the comment that does not contain the information claimed as 
CBI 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 you also submit a separate copy of your 
comments to the contact person identified below (see FOR FURTHER 
INFORMATION CONTACT). If the comment includes information you consider 
to be CBI or otherwise protected, you should send a copy of the comment 
that does not contain the information claimed as CBI or otherwise 
protected.
    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, William Jefferson Clinton Building 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 federal 
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 be available on the Worldwide Web (WWW). 
Following signature, a copy of this proposed rule will be posted at the 
following address: http://www2.epa.gov/cleanpowerplan/.

FOR FURTHER INFORMATION CONTACT: Ms. Amy Vasu, Sector Policies and 
Programs Division (D205-01), U.S. EPA, Research Triangle Park, NC 
27711; telephone number (919) 541-0107, facsimile number (919) 541-
4991; email address: vasu.amy@epa.gov or Ms. Marguerite McLamb, Sector 
Policies and Programs Division (D205-01), U.S. EPA, Research Triangle 
Park, NC 27711; telephone number (919) 541-7858, facsimile number (919) 
541-4991; email address: mclamb.marguerite@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:

ACEEE American Council for an Energy Efficient Economy
AEO Annual Energy Outlook
AFL-CIO American Federation of Labor and Congress of Industrial 
Organizations
ASTM American Society for Testing of Materials
BSER Best System of Emission Reduction
Btu/kWh British Thermal Units per Kilowatt-hour
CAA Clean Air Act
CBI Confidential Business Information
CCS Carbon Capture and Storage (or Sequestration)
CEMS Continuous Emissions Monitoring System
CHP Combined Heat and Power
CO2 Carbon Dioxide
DOE Department of Energy
ECMPS Emissions Collection and Monitoring Plan System
EERS Energy Efficiency Resource Standard
EGU Electric Generating Unit
EIA Energy Information Administration
EM&V Evaluation, Measurement and Verification
EO Executive Order
EPA Environmental Protection Agency
FR Federal Register
GHG Greenhouse Gas
GW Gigawatt
HAP Hazardous Air Pollutant
HRSG Heat Recovery Steam Generator
IGCC Integrated Gasification Combined Cycle
IPCC Intergovernmental Panel on Climate Change
IPM Integrated Planning Model
IRP Integrated Resource Plan
ISO Independent System Operator
kW Kilowatt
kWh Kilowatt-hour
lb CO2/MWh Pounds of CO2 per Megawatt-hour
LBNL Lawrence Berkeley National Laboratory
MMBtu Million British Thermal Units
MW Megawatt
MWh Megawatt-hour
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System Commissioners
NAS National Academy of Sciences
NGCC Natural Gas Combined Cycle
NOX Nitrogen Oxides
NRC National Research Council
NSPS New Source Performance Standard
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
NYSERDA New York State Energy Research and Development Authority
OMB Office of Management and Budget
PM Particulate Matter
PM2.5 Fine Particulate Matter
PRA Paperwork Reduction Act
PSB Public Service Board
PUC Public Utilities Commission
REC Renewable Energy Credit
RES Renewable Energy Standard
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RIA Regulatory Impact Analysis
RPS Renewable Portfolio Standard
RTO Regional Transmission Operator
SBA Small Business Administration
SBC System Benefits Charge
SCC Social Cost of Carbon
SIP State Implementation Plan
SO2 Sulfur Dioxide
Tg Teragram (one trillion (10 \12\) grams)
TSD Technical Support Document
TTN Technology Transfer Network
UMRA Unfunded Mandates Reform Act of 1995
UNFCCC United Nations Framework Convention on Climate Change
USGCRP U.S. Global Change Research Program
VCS Voluntary Consensus Standard

[[Page 34832]]

    Organization of This Document. The information presented in this 
preamble is organized as follows:

I. General Information
    A. Executive Summary
    B. Organization and Approach for This Proposed Rule
II. Background
    A. Climate Change Impacts From GHG Emissions
    B. GHG Emissions From Fossil Fuel-Fired EGUs
    C. The Utility Power Sector
    D. Statutory and Regulatory Requirements
III. Stakeholder Outreach and Conclusions
    A. Stakeholder Outreach
    B. Key Messages From Stakeholders
    C. Key Stakeholder Proposals
    D. Consideration of the Existing Range of Policies and Programs
    E. Conclusions
IV. Rule Requirements and Legal Basis
    A. Summary of Rule Requirements
    B. Summary of Legal Basis
V. Authority To Regulate Carbon Dioxide and EGUs, Affected Sources, 
and Treatment of Categories
    A. Authority To Regulate Carbon Dioxide
    B. Authority To Regulate EGUs
    C. Affected Sources
    D. Implications for Tribes and U.S. Territories
    E. Combined Categories and Codification in the Code of Federal 
Regulations
VI. Building Blocks for Setting State Goals and the Best System of 
Emission Reduction
    A. Introduction
    B. Building Blocks for Setting State Goals
    C. Detailed Discussion of Building Blocks and Other Options 
Considered
    D. Potential Combinations of the Building Blocks as Components 
of the Best System of Emission Reduction
    E. Determination of the Best System of Emission Reduction
VII. State Goals
    A. Overview
    B. Form of Goals
    C. Proposed Goals and Computation Procedure
    D. State Flexibilities
    E. Alternate Goals and Other Approaches Considered
    F. Reliable Affordable Electricity
VIII. State Plans
    A. Overview
    B. Approach
    C. Criteria for Approving State Plans
    D. State Plan Components
    E. Process for State Plan Submittal and Review
    F. State Plan Considerations
    G. Additional Factors That Can Help States Meet Their 
CO2 Emission Performance Goals
    H. Resources for States To Consider in Developing Plans
IX. Implications for Other EPA Programs and Rules
    A. Implications for NSR Program
    B. Implications for Title V Program
    C. Interactions With Other EPA Rules
X. Impacts of the Proposed Action
    A. What are the air impacts?
    B. Comparison of Building Block Approaches
    C. Endangered Species Act
    D. What are the energy impacts?
    E. What are the compliance costs?
    F. What are the economic and employment impacts?
    G. What are the benefits of the proposed action?
XI. 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
    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
XII. Statutory Authority

I. General Information

A. Executive Summary

1. Purpose of the Regulatory Action
    Under the authority of Clean Air Act (CAA) section 111(d), the EPA 
is proposing emission guidelines for states to follow in developing 
plans to address greenhouse gas (GHG) emissions from existing fossil 
fuel-fired electric generating units (EGUs). In this summary, we 
outline the proposal; discuss its purpose; summarize its major 
provisions, including the EPA's approach to determining goals; describe 
the broad range of options available to states, including flexibility 
in timing requirements both for plan submission and compliance 
deadlines under those plans; and briefly describe the estimated 
CO2 emission reductions, costs and benefits expected to 
result from full implementation of the proposal.
    This rule, as proposed, would continue progress already underway to 
lower the carbon intensity of power generation in the United States 
(U.S.). Lower carbon intensity means fewer emissions of CO2, 
a potent greenhouse gas that contributes to climate change. This 
proposal is a significant step forward in the EPA and states partnering 
to reduce GHG emissions in the U.S. The proposal incorporates critical 
elements that reflect the information and views shared during the 
unprecedented effort that the EPA has undertaken, beginning in the 
summer of 2013, to interact directly with, and solicit input from, a 
wide range of states and stakeholders. This effort encompassed several 
hundred meetings across the country with state environmental and energy 
officials, public utility commissioners, system operators, utilities 
and public interest advocates, as well as members of the public. Many 
participants submitted written material and data to the EPA as well.
    Nationwide, by 2030, this rule would achieve CO2 
emission reductions from the power sector of approximately 30 percent 
from CO2 emission levels in 2005. This goal is achievable 
because innovations in the production, distribution and use of 
electricity are already making the power sector more efficient and 
sustainable while maintaining an affordable, reliable and diverse 
energy mix. This proposed rule would reinforce and continue this 
progress. The EPA projects that, in 2030, the significant reductions in 
the harmful carbon pollution and in other air pollution, to which this 
rule would lead, would result in net climate and health benefits of $48 
billion to $82 billion. At the same time, coal and natural gas would 
remain the two leading sources of electricity generation in the U.S., 
with each providing more than 30 percent of the projected generation.
    Based on evidence from programs already being implemented by many 
states as well as input received from stakeholders, the agency 
recognizes that the most cost-effective system of emission reduction 
for GHG emissions from the power sector under CAA section 111(d) 
entails not only improving the efficiency of fossil fuel-fired EGUs, 
but also addressing their utilization by taking advantage of 
opportunities for lower-emitting generation and reduced electricity 
demand across the electricity system's interconnecting network or grid.
    The proposed guidelines are based on and would reinforce the 
actions already being taken by states and utilities to upgrade aging 
electricity infrastructure with 21st century technologies. The 
guidelines would ensure that these trends continue in ways that are 
consistent with the long-term planning and investment processes already 
used in this sector, to meet both region- and state-specific needs. The 
proposal provides flexibility for states to build upon their progress, 
and the progress of cities and towns, in addressing GHGs. It also 
allows states to pursue policies to reduce carbon pollution that: (1)

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Continue to rely on a diverse set of energy resources, (2) ensure 
electric system reliability, (3) provide affordable electricity, (4) 
recognize investments that states and power companies are already 
making, and (5) can be tailored to meet the specific energy, 
environmental and economic needs and goals of each state. Thus, the 
proposed guidelines would achieve meaningful CO2 emission 
reduction while maintaining the reliability and affordability of 
electricity in the U.S.
a. Proposal Elements
    The proposal has two main elements: (1) State-specific emission 
rate-based CO2 goals and (2) guidelines for the development, 
submission and implementation of state plans. To set the state-specific 
CO2 goals, the EPA analyzed the practical and affordable 
strategies that states and utilities are already using to lower carbon 
pollution from the power sector. These strategies include improvements 
in efficiency at carbon-intensive power plants, programs that enhance 
the dispatch priority of, and spur private investments in, low emitting 
and renewable power sources, as well as programs that help homes and 
businesses use electricity more efficiently. In addition, in 
calculating each state's CO2 goal, the EPA took into 
consideration the state's fuel mix, its electricity market and numerous 
other factors. Thus, each state's goal reflects its unique conditions.
    While this proposal lays out state-specific CO2 goals 
that each state is required to meet, it does not prescribe how a state 
should meet its goal. CAA section 111(d) creates a partnership between 
the EPA and the states under which the EPA sets these goals and the 
states take the lead on meeting them by creating plans that are 
consistent with the EPA guidelines. Each state will have the 
flexibility to design a program to meet its goal in a manner that 
reflects its particular circumstances and energy and environmental 
policy objectives. Each state can do so alone or can collaborate with 
other states on multi-state plans that may provide additional 
opportunities for cost savings and flexibility.
    To facilitate the state planning process, this proposal lays out 
guidelines for the development and implementation of state plans. The 
proposal describes the components of a state plan, the latitude states 
have in developing compliance strategies, the flexibility they have in 
the timing for submittal of their plans and the flexibility they have 
in determining the schedule by which their sources must achieve the 
required CO2 reductions. The EPA recognizes that each state 
has differing policy considerations--including varying emission 
reduction opportunities and existing state programs and measures--and 
that the characteristics of the electricity system in each state (e.g., 
utility regulatory structure, generation mix and electricity demand) 
also differ. Therefore, the proposed guidelines provide states with 
options for meeting the state-specific goals established by the EPA in 
a manner that accommodates a diverse range of state approaches. This 
proposal also gives states considerable flexibility with respect to the 
timeframes for plan development and implementation, providing up to two 
or three years for submission of final plans and providing up to 
fifteen years for full implementation of all emission reduction 
measures, after the proposal is finalized.
    Addressing a concern raised by both utilities and states, the EPA 
is proposing that states could choose approaches in their compliance 
plans under which full responsibility for actions achieving reductions 
is not placed entirely upon emitting EGUs; instead, state plans could 
include measures and policies (e.g., demand-side energy efficiency 
programs and renewable portfolio standards) for which the state itself 
is responsible. Of course, individual states would also have the option 
of structuring programs (e.g., allowance-trading programs) under which 
full responsibility rests on the affected EGUs.
    The EPA believes that, using the flexibilities inherent in CAA 
section 111(d), this proposal would result in significant reductions of 
GHG emissions that cause harmful climate change, while providing states 
with ample opportunity to design plans that use innovative, cost-
effective strategies that take advantage of investments already being 
made in programs and measures that lower the carbon intensity of the 
power sector and reduce GHG emissions.
b. Policy Context and Industry Conditions
    This proposal is an important step toward achieving the GHG 
emission reductions needed to address the serious threat of climate 
change. GHG pollution threatens the American public by leading to 
potentially rapid, damaging and long-lasting changes in our climate 
that can have a range of severe negative effects on human health and 
the environment. CO2 is the primary GHG pollutant, 
accounting for nearly three-quarters of global GHG emissions \1\ and 82 
percent of U.S. GHG emissions.\2\ The May 2014 report of the National 
Climate Assessment \3\ concluded that climate change impacts are 
already manifesting themselves and imposing losses and costs. The 
report documents increases in extreme weather and climate events in 
recent decades, damage and disruption to infrastructure and 
agriculture, and projects continued increases in impacts across a wide 
range of communities, sectors, and ecosystems.
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    \1\ Intergovernmental Panel on Climate Change (IPCC) report, 
``Contribution of Working Group I to the Fourth Assessment Report of 
the Intergovernmental Panel on Climate Change,'' 2007. Available at 
http://epa.gov/climatechange/ghgemissions/global.html.
    \2\ Table ES-2 ``Inventory of U.S. Greenhouse Gas Emissions and 
Sinks: 1990-2012'', Report EPA 430-R-14-003, United States 
Environmental Protection Agency, April 15, 2014.
    \3\ U.S. Global Change Research Program, Climate Change Impacts 
in the United States: The Third National Climate Assessment, May 
2014. Available at http://nca2014.globalchange.gov/.
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    The President's Climate Action Plan,\4\ issued in June 2013, 
recognizes that climate change has far-reaching harmful consequences 
and real economic costs. The Climate Action Plan details a broad array 
of actions to reduce GHG emissions that contribute to climate change 
and affect public health and the environment. One of the plan's goals 
is to reduce CO2 emissions from power plants. This is 
because fossil fuel-fired EGUs are, by far, the largest emitters of 
GHGs, primarily in the form of CO2, among stationary sources 
in the U.S. To accomplish this goal, President Obama issued a 
Presidential Memorandum \5\ that recognized the importance of 
significant and prompt action. The Memorandum directed the EPA to 
complete carbon pollution standards, regulations or guidelines, as 
appropriate, for modified, reconstructed and existing power plants by 
June 1, 2015, and in doing so to build on state leadership in moving 
toward a cleaner power sector.
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    \4\ The President's Climate Action Plan, June 2013. http://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf.
    \5\ Presidential Memorandum--Power Sector Carbon Pollution 
Standards, June 25, 2013. http://www.whitehouse.gov/the-press-office/2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards.
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    The way that power is produced, distributed and used is already 
changing due to advancements in innovative power sector technologies 
and in the availability and cost of low carbon fuel, renewable energy 
and energy efficient demand-side technologies, as well as economic 
conditions. In addition, the average age of the coal-fired generating 
fleet is increasing. In 2025, the average age of the coal-fired 
generating fleet is

[[Page 34834]]

projected to be 49 years old, and 20 percent of units would be more 
than 60 years old if they remained in operation at that time. 
Therefore, even in the absence of additional environmental regulation, 
states and utilities can be expected to be, and already are, making 
plans to address the changes necessitated by the aging of current 
assets and infrastructure. With change inevitably underway between now 
and 2030, a CAA section 111(d) rulemaking for CO2 emissions 
is timely and can inform current and ongoing decision making by states 
and utilities, as well as private sector business and technology 
investments. As states develop their plans, they will make key 
decisions that will stimulate private sector investment and innovation 
associated with reducing GHG emissions. We expect that many states will 
consider the opportunities offered for their respective economies as a 
result of this investment.
    The proposed guidelines are designed to build on and reinforce 
progress by states, cities and towns, and companies on a growing 
variety of sustainable strategies to reduce power sector CO2 
emissions. At the same time, the EPA believes that this proposal 
provides flexibility for states to develop plans that align with their 
unique circumstances, as well as their other environmental policy, 
energy and economic goals. All states will have the opportunity to 
shape their plans as they believe appropriate for meeting the proposed 
CO2 goals. This includes states with long-established 
reliance on coal-fired generation, as well as states with a commitment 
to promoting renewable energy (including through sustainable forestry 
initiatives). It also includes states that are already participating in 
or implementing CO2 reduction programs, such as the Regional 
Greenhouse Gas Initiative (RGGI), California's ``Global Warming 
Solutions Act'' and Colorado's ``Clean Air, Clean Jobs Act''.
    States would be able to rely on and extend programs they may 
already have created to address the power sector. Those states 
committed to Integrated Resource Planning (IRP) would be able to 
establish their CO2 reduction plans within that framework, 
while states with a more deregulated power sector system could develop 
CO2 reduction plans within that specific framework. Each 
state, including states without an existing program, would have the 
opportunity to take advantage of a wide variety of strategies for 
reducing CO2 emissions from affected EGUs. The EPA and other 
federal entities, including the U.S. Department of Energy (DOE), the 
Federal Energy Regulatory Commission (FERC) and the U.S. Department of 
Agriculture, among others, are committed to sharing expertise with 
interested states as they develop and implement their plans.
    States would be able to address the economic interests of their 
utilities and ratepayers by using the flexibilities in this proposed 
action to: (1) Reduce costs to consumers, minimize stranded assets, and 
spur private investments in renewable energy and energy efficiency 
technologies and businesses; and (2) if they choose, work with other 
states on multi-state approaches that reflect the regional structure of 
electricity operating systems that exists in most parts of the country 
and is critical to ensuring a reliable supply of affordable energy. The 
proposed rule gives states the flexibility to provide a broad range of 
compliance options that recognize that the power sector is made up of a 
diverse range of companies that own and operate fossil fuel-fired EGUs, 
including vertically integrated companies in regulated markets, 
independent power producers, rural cooperatives and municipally-owned 
utilities, all of which are likely to have different ranges of 
opportunities to reduce GHG emissions while facing different challenges 
in meeting these reductions.
    Both existing state programs (such as RGGI, the California Global 
Warming Solutions Act program and the Colorado Clean Air, Clean Jobs 
Act program) and ideas suggested by stakeholders show that there are a 
number of different ways that states can design programs that achieve 
required reductions while working within existing market mechanisms 
used to dispatch power effectively in the short term and to ensure 
adequate capacity in the long term. These programs and programs for 
conventional pollutants, such as the Acid Rain Program under Title IV 
of the CAA, have demonstrated that compliance with environmental 
programs can be monetized such that it is factored into power sector 
economic decision making in ways that reduce the cost of controlling 
pollution, maintain electricity system reliability and work within the 
least cost dispatching principles that are key to operation of our 
electric power grid. The proposal would also allow states to work 
together with individual companies on potential specific challenges. 
These and other flexibilities are discussed further in Section VIII of 
the preamble.
a. CAA Section 111(d) Requirements
    Under CAA section 111(d),\6\ state plans must establish standards 
of performance that reflect the degree of emission limitation 
achievable through the application of the ``best system of emission 
reduction'' that, taking into account the cost of achieving such 
reduction and any non-air quality health and environmental impacts and 
energy requirements, the Administrator determines has been adequately 
demonstrated (BSER).\7\ Consistent with CAA section 111(d), the EPA is 
proposing state-specific goals that reflect the EPA's calculation of 
the emission limitation that each state can achieve through the 
application of the BSER. This calculation reflects the degree of 
emission limitation that the state plan must achieve in order to 
implement the BSER that the EPA has determined has been adequately 
demonstrated and that, in turn, would be required to be, and via the 
calculation, has been, applied for the affected EGUs in each state. A 
CAA section 111(d) state plan will differ from a state implementation 
plan (SIP) for a criteria air pollutant national ambient air quality 
standard (NAAQS) in several respects, reflecting the significant 
differences between CAA sections 110 and 111. A CAA section 110 SIP 
must be designed to meet the NAAQS for a criteria air pollutant for a 
particular area--not for a source category--within a timeframe 
specified in the CAA. The NAAQS itself is based on the current body of 
scientific evidence and, by law, does not reflect consideration of 
cost. By contrast, a CAA section 111(d) state plan must be designed to 
achieve a specific level of emission performance that has been 
established for a particular source category within a timeframe 
determined by the Administrator and, to some extent, by each state. 
Moreover, the emission levels for the source category reflect a 
determination of the BSER, which incorporates consideration of cost, 
technical feasibility and other factors.
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    \6\ See also 40 CFR 60.22(b)(5).
    \7\ Under CAA section 111(a)(1) and (d), the EPA is authorized 
to determine the BSER and to calculate the amount of emission 
reduction achievable through applying the BSER. The state is 
authorized to identify the standard or standards of performance that 
reflects that amount of emission reduction. In addition, the state 
is required to include in its state plan the standards of 
performance and measures to implement and enforce those standards. 
The state must submit the plan to the EPA, and the EPA must approve 
the plan if the standards of performance and implementing and 
enforcing measures are satisfactory. This is discussed in more 
detail in Sections IV, VI, VII and VIII of this preamble, as well as 
in the Legal Memorandum.
---------------------------------------------------------------------------

    To determine the BSER for reducing CO2 emissions at 
affected EGUs, the EPA considered numerous measures that are already 
being implemented and can be implemented more broadly to

[[Page 34835]]

improve emission rates and to reduce overall CO2 emissions 
from fossil fuel-fired EGUs. Overall, the BSER proposed here is based 
on a range of measures that fall into four main categories, or 
``building blocks,'' which comprise improved operations at EGUs, 
dispatching lower-emitting EGUs and zero-emitting energy sources, and 
end-use energy efficiency. All of these measures have been amply 
demonstrated via their current widespread use by utilities and states.
    The proposed guidelines are structured so that states would not be 
required to use each and every one of the measures that the EPA 
determines constitute the BSER or to apply any one of those measures to 
the same extent that the EPA determines is achievable at reasonable 
cost. Instead, in developing its plan, each state will have the 
flexibility to select the measure or combination of measures it prefers 
in order to achieve its CO2 emission reduction goal. Thus, a 
state could choose to achieve more reductions from one measure 
encompassed by the BSER and less from another, or it could choose to 
include measures that were not part of the EPA's BSER determination, as 
long as the state achieves the CO2 reductions at affected 
EGUs necessary to meet the goal that the EPA has defined as 
representing the BSER.
    As explained in further detail in Sections VI, VII and VIII of this 
preamble regarding the agency's determination of the BSER, the EPA is 
offering the opportunity via this proposal to comment on the proposed 
BSER, the proposed methodology for computing state goals based on 
application of the BSER, and the state-specific data used in the 
computations. Once the final goals have been promulgated, a state would 
no longer have an opportunity to request that the EPA adjust its 
CO2 goal. The final state-specific CO2 goals 
would reflect any adjustments as appropriate based on comments provided 
to the EPA to address any data errors in the analysis for the proposed 
goals. We expect that states will be able to meet the CO2 
goals because they will represent the application of the BSER for the 
states' affected sources.
    This proposed rule sets forth the state goals that reflect the BSER 
and guidelines for states to use in developing their plans to reduce 
CO2 from fossil fuel-fired EGUs. The preamble describes the 
proposed expectations for state plans and discusses options that the 
EPA has considered. It also explains the EPA's authority to define the 
BSER, as well as state goals, and each state's responsibility to 
develop and implement standards of performance that will achieve its 
CO2 goal. Additional detail on various aspects of the 
proposal is included in several technical support documents (TSDs) and 
memoranda, which are available in the rulemaking docket.
    The proposal was substantially informed by the extensive input from 
states and a wide range of stakeholders that the EPA sought and has 
received since the summer of 2013. The EPA invites further input 
through public comment on all aspects of this proposal.
2. Summary of the Proposal's Major Provisions
a. Approach
    In developing this proposed rulemaking, the EPA is implementing 
statutory provisions that have been in place since Congress first 
enacted the CAA in 1970 and that have been implemented pursuant to 
regulations promulgated in 1975 and followed in subsequent CAA section 
111(d) rulemakings. These provisions ensure that, in concert with the 
provisions of CAA sections 110 and 112, new and existing major 
stationary sources operate in ways that address their emissions of 
significant air pollutants that are harmful to public health and the 
environment. These requirements call on the EPA to develop emission 
guidelines, which reflect the EPA's determination of the BSER, for 
states to follow in formulating compliance plans to implement standards 
of performance to achieve emission reductions consistent with the BSER. 
In following these provisions, the EPA is proposing a BSER based on 
strategies currently being used by states and companies to reduce 
CO2 emissions from EGUs.
    The CAA, as interpreted by the courts, identifies several factors 
for the EPA to consider in a BSER determination. These include 
technical feasibility, costs, size of emission reductions and 
technology (e.g., whether the system promotes the implementation and 
further development of technology). In determining the BSER, the EPA 
considered the reductions achievable through measures that reduce 
CO2 emissions from existing fossil fuel-fired EGUs either by 
(1) reducing the CO2 emission rate at those units or (2) 
reducing the units' CO2 emission total to the extent that 
generation can be shifted from higher-emitting fossil fuel-fired EGUs 
to lower- or zero-emitting options.
    As the EPA has done in making BSER determinations in previous CAA 
section 111(d) rulemakings, the agency considered the types of 
strategies that states and owners and operators of EGUs are already 
employing to reduce the covered pollutant (in this case, 
CO2) from affected sources (in this case, fossil fuel-fired 
EGUs).\8\ Across the nation, many states, cities and towns, and owners 
and operators of EGUs have shown leadership in creating and 
implementing policies and programs that reduce CO2 emissions 
from the power sector while achieving other economic, environmental and 
energy benefits. Some of these activities, such as market-based 
programs and GHG performance standards, directly require CO2 
emission reductions from EGUs. Others reduce CO2 emissions 
by reducing utilization of fossil fuel-fired EGUs through, for example, 
renewable portfolio standards (RPS) and energy efficiency resource 
standards (EERS). For example, currently 10 states have market-based 
GHG emission programs, 38 states have renewable portfolio standards or 
goals, and utilities in 47 states run demand-side energy efficiency 
programs. Many individual companies also have significant voluntary 
CO2 emission reduction programs.
---------------------------------------------------------------------------

    \8\ The final emission guidelines for landfill gas emissions 
from municipal solid waste landfills, published on March 12, 1996 
and amended on June 16, 1998 (61 FR 9905 and 63 FR 32743, 
respectively) are one example, as they allow either of two 
approaches for controlling landfill gas--by recovering the gas as a 
fuel, for sale, and removing from the premises, or by destroying the 
organic content of the gas on the premises using a control device. 
Recovering the gas as a fuel source was a practice already being 
used by some affected sources prior to promulgation of the 
rulemaking.
---------------------------------------------------------------------------

    Such strategies--and the proposed BSER determination--reflect the 
fact that, in almost all states, the production, distribution and use 
of electricity can be, and is, undertaken in ways that accommodate 
reductions in both pollution emission rates and total emissions. 
Specifically, electricity production, at least to some extent, takes 
place interchangeably between and among multiple generation facilities 
and different types of generation, a fact that Congress, the EPA and 
the states have long relied on in enacting or promulgating pollution 
reduction programs, such as Title IV of the CAA, the NOX SIP 
Call, the Cross State Air Pollution Rule (CSAPR) and RGGI.
    As a result, the agency, in quantifying state goals, assessed what 
combination of electricity production or energy demand reduction across 
generation facilities can offer a reasonable-cost, technically feasible 
approach to achieving CO2 emission reductions. States, in 
turn, will be able to look broadly at opportunities across their

[[Page 34836]]

electricity system in devising plans to meet their goals. Importantly, 
states may rely on measures that they already have in place, including 
renewable energy standards and demand-side energy efficiency programs, 
and the proposal details how such existing state programs can be 
incorporated into state plans. States will also be able to participate 
in multi-state programs that already exist or may create new ones.
    Thus, to determine the BSER for reducing CO2 emissions 
at affected EGUs and to establish the numerical goals that reflect the 
BSER, the EPA considered numerous measures that can and are being 
implemented to improve emission rates and to reduce or limit mass 
CO2 emissions from fossil fuel-fired EGUs. These measures 
encompass two basic approaches: (1) Reducing the carbon intensity of 
certain affected EGUs by improving the efficiency of their operations, 
and (2) addressing affected EGUs' mass emissions by varying their 
utilization levels. For purposes of expressing the BSER as an emission 
limitation, in this case in the form of state-level goals, we propose 
to base these two approaches on measures grouped into four main 
categories, or ``building blocks.'' These building blocks can also be 
used as a guide to states for constructing broad-based, cost-effective, 
long-term strategies to reduce CO2 emissions. The EPA 
believes that the application of measures from each of the building 
blocks can achieve CO2 emission reductions at fossil fuel-
fired EGUs such that, when combined with measures from other building 
blocks, the measures represent the ``best system of emission reduction 
. . . adequately demonstrated'' for fossil fuel-fired EGUs. The 
building blocks are:
    1. Reducing the carbon intensity of generation at individual 
affected EGUs through heat rate improvements.
    2. Reducing emissions from the most carbon-intensive affected EGUs 
in the amount that results from substituting generation at those EGUs 
with generation from less carbon-intensive affected EGUs (including 
NGCC units under construction).
    3. Reducing emissions from affected EGUs in the amount that results 
from substituting generation at those EGUs with expanded low- or zero-
carbon generation.
    4. Reducing emissions from affected EGUs in the amount that results 
from the use of demand-side energy efficiency that reduces the amount 
of generation required.
    The four building blocks are described in detail in Sections VI of 
this preamble. As explained in that section, the EPA evaluated each of 
the building blocks individually against the BSER criteria and found 
that each of the building blocks independently merits consideration as 
part of the BSER. The EPA also evaluated combinations of the building 
blocks against the BSER criteria--in particular, a combination of all 
four building blocks and a combination of building blocks 1 and 2.
    Based on that evaluation, the EPA proposes that the combination of 
all four building blocks is the BSER. The combination of all four 
blocks best represents the BSER because it achieves greater emission 
reductions at a lower cost, takes better advantage of the wide range of 
measures that states, cities, towns and utilities are already using to 
reduce CO2 from EGUs and reflects the integrated nature of 
the electricity system and the diversity of electricity generation 
technology. Section VI of this preamble also explains how the EPA 
considered more aggressive application of measures in each block. This 
includes consideration of more extensive application of measures that 
the EPA determined do represent a component of the BSER (such as more 
extensive or accelerated application of demand-side measures), as well 
as consideration of options in some blocks that the EPA determined 
would not represent the BSER for existing sources (such as the 
inclusion of retrofit carbon capture and storage or sequestration (CCS) 
on existing EGUs).
    As part of the BSER determination, the EPA considered the impacts 
that implementation of the emission reductions based on the combination 
of the blocks would have on the cost of electricity and electricity 
system reliability. As the preamble details, the EPA believes that, 
both with respect to the overall proposed BSER and with respect to the 
individual building blocks, the associated costs are reasonable. 
Importantly, the proposed BSER, expressed as a numeric goal for each 
state, provides states with the flexibility to determine how to achieve 
the reductions (i.e., greater reductions from one building block and 
less from another) and to adjust the timing in which reductions are 
achieved, in order to address key issues such as cost to consumers, 
electricity system reliability and the remaining useful life of 
existing generation assets.
    In sum, the EPA proposes that the BSER for purposes of CAA section 
111(d), as applied to existing fossil fuel-fired EGUs, is based on a 
combination of measures that reduce CO2 emissions and 
CO2 emission rates and encompass all four building 
blocks.\9\ We are also soliciting comment on application of only the 
first two building blocks as the basis for the BSER, while noting that 
application of only the first two building blocks achieves fewer 
CO2 reductions at a higher cost.
---------------------------------------------------------------------------

    \9\ The EPA notes that under the proposed BSER, some building 
blocks would apply to some, but not all, affected sources. 
Specifically, building block 1 would apply to affected coal-fired 
steam EGUs, building block 2 would apply to all affected steam EGUs 
(both coal-fired and oil/gas-fired), and building blocks 3 and 4 
would apply to all affected EGUs.
---------------------------------------------------------------------------

    In determining the BSER, we have considered the ranges of 
reductions that can be achieved by application of each building block, 
and we have identified goals that we believe reflect a reasonable 
degree of application of each building block consistent with the BSER 
criteria. Relying on all four building blocks to characterize the 
combination of measures that reduce CO2 emissions and 
CO2 emission rates at affected EGUs as the basis for the 
BSER is consistent with strategies, actions and measures that companies 
and states are already undertaking to reduce GHG emissions and with 
current trends in the electric power sector, driven by efforts to 
reduce GHGs as well as by other factors, such as advancements in 
technology. Reliance on all four building blocks in this way also 
supports the goals of achieving significant and technically feasible 
reductions of CO2 at a reasonable cost, while also promoting 
technology and approaches that are important for achieving further 
reductions. Finally, the EPA believes that the diverse range of 
measures encompassed in the four building blocks allows states and 
sources to take full advantage of the inherent flexibility of the 
current regionally interconnected and integrated electricity system so 
as to achieve the CO2 goals while continuing to meet the 
demand for electricity services in a reliable and affordable manner.
    The EPA recognizes that states differ in important ways, including 
in their mix of existing EGUs and in their policy priorities. 
Consequently, opportunities and preferences for reducing emissions, as 
reflected in each of the building blocks, vary across states. While the 
state-specific goals that the EPA is proposing in this rule are based 
on consistent application of a single goal-setting methodology across 
all states, the goals account for these key differences. The state-
specific CO2 goals derived from application of the 
methodology vary because, in setting the goals for a state, the EPA 
used data specific to each state's EGUs and certain

[[Page 34837]]

other attributes of its electricity system (e.g., current mix of 
generation resources).
    The proposed BSER and goal-setting methodology reflect information 
provided and priorities expressed during the EPA's recent, extensive 
public outreach process. The input we received ranged from the states' 
desires for flexibility and recognition of varying state circumstances 
to the success that states and companies have had in adopting a range 
of pollution--and demand-reduction strategies. The state-specific 
approach embodied in both CAA section 111(d) and this proposal 
recognizes that ultimately states are the most knowledgeable about 
their specific circumstances and are best positioned to evaluate and 
leverage existing and new generation capacity and programs to reduce 
CO2 emissions.
    To meet its goal, each state will be able to design programs that 
use the measures it selects, and these may include the combination of 
building blocks most relevant to its specific circumstances and policy 
preferences. States may also identify technologies or strategies that 
are not explicitly mentioned in any of the four building blocks and may 
use those technologies or strategies as part of their overall plans 
(e.g., market-based trading programs or construction of new natural 
combined cycle units or nuclear plants). Further, the EPA's approach 
allows multi-state compliance strategies.
    The agency also recognizes the important functional relationship 
between the period of time over which measures are deployed and the 
stringency of emission limitations those measures can achieve in a 
practical and reasonable cost way. Because, for this proposal, the EPA 
is proposing a 10-year period over which to achieve the full required 
CO2 reductions, a period that begins more than five years 
from the date of this proposal, a state could take advantage of this 
relationship in the design of its program by using relevant 
combinations of building blocks to achieve its state goal in a manner 
that provides for electricity system reliability, avoids the creation 
of stranded assets and has a reasonable cost.
b. State Goals and Flexibilities
    In this action, the EPA is proposing state-specific rate-based 
goals that state plans must be designed to meet. These state-specific 
goals are based on an assessment of the amount of emissions that can be 
reduced at existing fossil fuel-fired EGUs through application of the 
BSER, as required under CAA section 111(d). The agency is proposing 
state-specific final goals that must be achieved by no later than the 
year 2030. The proposed final goals reflect the EPA's quantification of 
adjusted state-average emission rates from affected EGUs that could be 
achieved at reasonable cost by 2030 through implementation of the four 
building blocks described above.
    The EPA recognizes that, with many measures, states can achieve 
emission reductions in the short-term, though the full effects of 
implementation of other measures, such as demand-side energy efficiency 
(EE) programs and the addition of renewable energy (RE) generating 
capacity, can take longer. Thus, the EPA is proposing interim goals 
that states must meet beginning in 2020. The proposed interim goals 
would apply over a 2020-2029 phase-in period. They reflect the level of 
reductions in CO2 emissions and emission rates and the 
extent of the application of the building blocks that would be 
presumptively approvable in a state plan during the ramp-up to 
achieving the final goal.
    The EPA is proposing to allow each state flexibility with regard to 
the form of the goal. A state could adopt the rate-based form of the 
goal established by the EPA or an equivalent mass-based form of the 
goal. A multi-state approach incorporating either a rate- or mass-based 
goal would also be approvable based upon a demonstration that the 
state's plan would achieve the equivalent in stringency, including 
compliance timing, to the state-specific rate-based goal set by the 
EPA.
    We believe that this approach to establishing requirements for 
states in developing their plans responds both to the needs of an 
effectively implemented program and to the range of viewpoints 
expressed by stakeholders regarding the simultaneous need for both 
flexibility and clear guidance on what would constitute an approvable 
state plan. We likewise believe that this approach represents a 
reasonable balance between two competing objectives grounded in CAA 
section 111(d)--a need for rigor and consistency in calculating 
emission reductions reflecting the BSER and a need to provide the 
states with flexibility in establishing and implementing the standards 
of performance that reflect those emission reductions. The importance 
of this balance is heightened by the fact that the operations of the 
electricity system itself rely on the flexibility made available and 
achieved through dispatching between and among multiple interconnected 
EGUs, demand management and end-use energy efficiency. We view the 
proposed goals as providing rigor where required by the statute with 
respect to the amount of emission reductions, while providing states 
with flexibility where permitted by the statute, particularly with 
respect to the range of measures that a state could include in its 
plan. This approach recognizes that state plans for emission reductions 
can, and must, be consistent with a vibrant and growing economy and 
supply of reliable, affordable electricity to support that economy. It 
further reflects the growing trend, as exemplified by many state and 
local clean energy policies and programs, to shift energy production 
away from carbon-intensive fuels to a modern, more sustainable system 
that puts greater reliance on renewable energy, energy efficiency and 
other low-carbon energy options.
c. State Plans
i. Plan Approach
    Each state will determine, and include in its plan, emission 
performance levels for its affected EGUs that are equivalent to the 
state-specific CO2 goal in the emission guidelines, as well 
as the measures needed to achieve those levels and the overall goal. As 
part of determining these levels, the state will decide whether it will 
adopt the rate-based form of the goal established by the EPA or 
translate the rate-based goal to a mass-based goal. The state must then 
establish a standard, or set of standards, of performance, as well as 
implementing and enforcing measures, to achieve the emission 
performance level specified in the state plan. The state may choose the 
measures it will include in its plan to achieve its goal. The state may 
use the same set of measures as in the EPA's approach to setting the 
goals, or the state may use other or additional measures to achieve the 
required CO2 reductions.
    A state plan must include enforceable CO2 emission 
limits that apply to affected EGUs. In doing so, a state plan may take 
a portfolio approach, which could include enforceable CO2 
emission limits that apply to affected EGUs as well as other 
enforceable measures, such as RE and demand-side EE measures, that 
avoid EGU CO2 emissions and are implemented by the state or 
by another entity. The plan must also include a process for reporting 
on plan implementation, progress toward achieving CO2 goals, 
and implementation of corrective actions, if necessary. No less 
frequently than every two rolling calendar years, beginning January 1, 
2022, the state will be required to compare emission performance 
achieved by affected EGUs

[[Page 34838]]

in the state with the emissions performance projected in the state 
plan, and report that to the EPA.
    In this action, the EPA is also proposing guidelines for states to 
follow in developing their plans. These guidelines include 
approvability criteria, requirements for state plan components, the 
process and timing for state plan submittal and the process and timing 
for demonstrating achievement of the CO2 emission 
performance level in the state plan. The proposed guidelines provide 
states with options for meeting the state-specific goals established by 
the EPA in a flexible manner that accommodates a diverse range of state 
approaches. The plan guidelines provide the states with the ability to 
achieve the full reductions over a multi-year period, through a variety 
of reduction strategies, using state-specific or multi-state approaches 
that can be achieved on either a rate or mass basis. They also address 
several key policy considerations that states can be expected to 
contemplate in developing their plans.
    With respect to the structure of the state plans, the EPA, in its 
extensive outreach efforts, heard from a wide range of stakeholders 
that the EPA should authorize state plans to include a portfolio of 
actions that encompass a diverse set of programs and measures that 
achieve either a rate-based or mass-based emission performance level 
for affected EGUs but that do not place legal responsibility for 
achieving the entire amount of the emission performance level on the 
affected EGUs. In view of this strong sentiment from stakeholders, the 
EPA is proposing that state plans that take this portfolio approach 
would be approvable, provided that they meet other key requirements 
such as achieving the required emission reductions over the appropriate 
timeframes. Plans that do directly assure that affected EGUs achieve 
all of the required emission reductions (such as the mass-based 
programs being implemented in California and the RGGI states) would 
also be approvable provided that they meet other key requirements, such 
as achieving the required emission reductions over the appropriate 
timeframes.
ii. State Plan Components
    The EPA is proposing to evaluate and approve state plans based on 
four general criteria: (1) Enforceable measures that reduce EGU 
CO2 emissions; (2) projected achievement of emission 
performance equivalent to the goals established by the EPA, on a 
timeline equivalent to that in the emission guidelines; (3) 
quantifiable and verifiable emission reductions; and (4) a process for 
reporting on plan implementation, progress toward achieving 
CO2 goals, and implementation of corrective actions, if 
necessary. In addition, each state plan must follow the EPA framework 
regulations at 40 CFR 60.23. The proposed components of states plans 
are:

 Identification of affected entities
 Description of plan approach and geographic scope
 Identification of state emission performance level
 Demonstration that plan is projected to achieve emission 
performance level
 Identification of emission standards
 Demonstration that each emission standard is quantifiable, 
non-duplicative, permanent, verifiable, and enforceable
 Identification of monitoring, reporting, and recordkeeping 
requirements
 Description of state reporting
 Identification of milestones
 Identification of backstop measures
 Certification of hearing on state plan
 Supporting material
iii. Process for State Plan Submittal and Review
    Recognizing the urgent need for actions to reduce GHG emissions, 
and in accordance with the Presidential Memorandum,\10\ the EPA expects 
to finalize this rulemaking by June 1, 2015. The Presidential 
Memorandum also calls for a deadline of June 30, 2016, for states to 
submit their state plans. The EPA is proposing that each state must 
submit a plan to the EPA by June 30, 2016. However, the EPA recognizes 
that some states may need more than one year to complete all of the 
actions needed for their final state plans, including technical work, 
state legislative and rulemaking activities, coordination with third 
parties, and coordination among states involved in multi-state plans. 
Therefore, the EPA is proposing an optional two-phased submittal 
process for state plans. Each state would be required to submit a plan 
by June 30, 2016, that contains certain required components. If a state 
needs additional time to submit a complete plan, then the state must 
submit an initial plan by June 30, 2016 that documents the reasons the 
state needs more time and includes commitments to concrete steps that 
will ensure that the state will submit a complete plan by June 30, 2017 
or 2018, as appropriate. To be approvable, the initial plan must 
include specific components, including a description of the plan 
approach, initial quantification of the level of emission performance 
that will be achieved in the plan, a commitment to maintain existing 
measures that limit CO2 emissions, an explanation of the 
path to completion, and a summary of the state's response to any 
significant public comment on the approvability of the initial plan, as 
described in Section VIII.E of this preamble.
---------------------------------------------------------------------------

    \10\ Presidential Memorandum--Power Sector Carbon Pollution 
Standards, June 25, 2013. http://www.whitehouse.gov/the-press-office/2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards.
---------------------------------------------------------------------------

    If the initial plan includes those components and if the EPA does 
not notify the state that the initial plan does not contain the 
required components, the extension of time to submit a complete plan 
will be deemed granted and a state would have until June 30, 2017, to 
submit a complete plan if the geographic scope of the plan is limited 
to that state. If the state develops a plan that includes a multi-state 
approach, it would have until June 30, 2018 to submit a complete plan. 
Further, the EPA is proposing that states participating in a multi-
state plan may submit a single joint plan on behalf of all of the 
participating states.
    Following submission of final plans, the EPA will review plan 
submittals for approvability. Given the diverse approaches states may 
take to meet the emission performance goals in the emission guidelines, 
the EPA is proposing to extend the period for EPA review and approval 
or disapproval of plans from the four-month period provided in the EPA 
framework regulations to a twelve-month period.
iv. Timing of Compliance
    As states, industry groups and other stakeholders have made clear, 
the EPA recognizes that the measures states have been and will be 
taking to reduce CO2 emissions from existing EGUs can take 
time to implement. Thus, we are proposing that, while states must begin 
to make reductions by 2020, full compliance with the CO2 
emission performance level in the state plan must be achieved by no 
later than 2030. Under this proposed option, a state would need to meet 
an interim CO2 emission performance level on average over 
the 10-year period from 2020-2029, as well as achieve its final 
CO2 emission performance level by 2030 and maintain that 
level subsequently. This proposed option is based on the application of 
a range of measures from all four building blocks, and the agency 
believes that this approach for compliance timing is reasonable and 
appropriate and would best support the optimization of overall

[[Page 34839]]

CO2 reductions. The agency is also requesting comment on an 
alternative option, a 5-year period for compliance, in combination with 
a less stringent set of CO2 emission performance levels. 
These options are fully described in Section VIII of this preamble, and 
the state goals associated with the alternative option are described in 
Section VII.E of this preamble. The EPA is also seeking comment on 
different combinations of building blocks and different levels of 
stringency for each building block.
    The EPA is also proposing that measures that a state takes after 
the date of this proposal, or programs already in place, which result 
in CO2 emission reductions during the 2020-2030 period, 
would apply toward achievement of the state's 2030 CO2 
emission goal. Thus, states with currently existing programs and 
policies, and states that put in place new programs and policies early, 
will be better positioned to achieve the goals.
v. Resources for States
    To respond to requests from states for methodologies, tools and 
information to assist them in designing and implementing their plans, 
the EPA, in consultation with the U.S. Department of Energy and other 
federal agencies, as well as states, is collecting and developing 
available resources and is making those resources available to the 
states via a dedicated Web site.\11\ As we and others continue to 
develop tools, templates and other resources, we will update the Web 
site. We intend, during the public comment period, to work actively 
with the states on resources that will be helpful to them in both 
developing and implementing their plans.
---------------------------------------------------------------------------

    \11\ www2.epa.gov/cleanpowerplantoolbox.
---------------------------------------------------------------------------

3. Projected National-Level Emission Reductions
    Under the proposed guidelines, the EPA projects annual 
CO2 reductions of 26 to 30 percent below 2005 levels 
depending upon the compliance year. These guidelines will also result 
in important reductions in emissions of criteria air pollutants, 
including sulfur dioxide (SO2), nitrogen oxides 
(NOX) and directly emitted fine particulate matter 
(PM2.5). A thorough discussion of the EPA's analysis is 
presented in Section X.A of this preamble and in Chapter 3 of the 
Regulatory Impact Analysis (RIA) included in the docket for this 
rulemaking.
4. Costs and Benefits
    Actions taken to comply with the proposed guidelines will reduce 
emissions of CO2 and other air pollutants, including 
SO2, NOX and directly emitted PM2.5, 
from the electric power industry. States will make the ultimate 
determination as to how the emission guidelines are implemented. Thus, 
all costs and benefits reported for this action are illustrative 
estimates. The EPA has calculated illustrative costs and benefits in 
two ways: One based on an assumption of individual state plans and 
another based on an assumption that states will opt for multi-state 
plans. The illustrative costs and benefits are based upon compliance 
approaches that reflect a range of measures consisting of improved 
operations at EGUs, dispatching lower-emitting EGUs and zero-emitting 
energy sources, and increasing levels of end-use energy efficiency.
    Assuming that states comply with the guidelines collaboratively 
(referred to as the regional compliance approach), the EPA estimates 
that, in 2020, this proposal will yield monetized climate benefits of 
approximately $17 billion (2011$) using a 3 percent discount rate 
(model average) relative to the 2020 base case, as shown in Table 
1.\12\ The air pollution health co-benefits associated with reducing 
exposure to ambient PM2.5 and ozone through emission 
reductions of precursor pollutants in 2020 are estimated to be $16 
billion to $37 billion using a 3 percent discount rate and $15 billion 
to $34 billion (2011$) using a 7 percent discount rate relative to the 
2020 base case. The annual compliance costs are estimated using the 
Integrated Planning Model (IPM) and include demand-side energy 
efficiency program and participant costs as well as monitoring, 
reporting and recordkeeping costs. In 2020, total compliance costs of 
this proposal are approximately $5.5 billion (2011$). The quantified 
net benefits (the difference between monetized benefits and compliance 
costs) in 2020 are estimated to be $28 billion to $49 billion (2011$) 
using a 3 percent discount rate (model average). As reflected in Table 
2, climate benefits are approximately $30 billion in 2030 using a 3 
percent discount rate (model average, 2011$) relative to the 2030 base 
case assuming a regional compliance approach for the proposal. Health 
co-benefits are estimated to be approximately $25 to $59 billion (3 
percent discount rate) and $23 to $54 billion (7 percent discount rate) 
relative to the 2030 base case (2011$). In 2030, total compliance costs 
for the proposed option regional approach are approximately $7.3 
billion (2011$). The net benefits for this proposal increase to 
approximately $48 billion to $82 billion (3 percent discount rate model 
average, 2011$) in 2030 for the proposed option regional compliance 
approach.
---------------------------------------------------------------------------

    \12\ The EPA has used social cost of carbon (SCC) estimates--
i.e., the monetary value of impacts associated with a marginal 
change in CO2 emissions in a given year--to analyze 
CO2 climate impacts of this rulemaking. The four SCC 
estimates are associated with different discount rates (model 
average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th 
percentile at 3 percent), and each increases over time. In this 
summary, the EPA provides the estimate of climate benefits 
associated with the SCC value deemed to be central: The model 
average at 3 percent discount rate.
---------------------------------------------------------------------------

    In comparison, if states choose to comply with the guidelines on a 
state-specific basis (referred to as state compliance approach), the 
climate benefits in 2020 are expected to be approximately $18 billion 
(3 percent discount rate, model average, 2011$), as Table 1 shows. 
Health co-benefits are estimated to be $17 to $40 billion (3 percent 
discount rate) and $15 to $36 billion (7 percent discount rate). Total 
compliance costs are approximately $7.5 billion annually in 2020. Net 
benefits in 2020 are estimated to be $27 to $50 billion (3 percent 
model average discount rate, 2011$). In 2030, as shown on Table 2, 
climate benefits are approximately $31 billion using a 3 percent 
discount rate (model average, 2011$) relative to the 2030 base case 
assuming a state compliance approach. Health co-benefits are estimated 
to be approximately $27 to $62 billion (3 percent discount rate) and 
$24 to $56 billion (7 percent discount rate) relative to the 2030 base 
case (2011$). In 2030, total compliance costs for the state approach 
are approximately $8.8 billion (2011$). In 2030, these net benefits are 
estimated to be approximately $49 to $84 billion (3 percent discount 
rate, 2011$) assuming a state compliance approach.

[[Page 34840]]

  Table 1--Summary of the Monetized Benefits, Compliance Costs, and Net
            Benefits for the Proposed Guidelines in 2020 \a\
                           [Billions of 2011$]
------------------------------------------------------------------------
                                   3% Discount rate    7% Discount rate
------------------------------------------------------------------------
            Proposed Guidelines Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\............                   $17.
                                 ---------------------------------------
Air pollution health co-benefits  $16 to $37........  $15 to $34.
 \c\.
Total Compliance Costs \d\......  $5.5..............  $5.5.
Net Monetized Benefits \e\......  $28 to $49........  $26 to $45.
                                 ---------------------------------------
Non-monetized Benefits..........  Direct exposure to SO2 and NO2.
                                  1.3 tons of Hg.
                                  Ecosystem Effects.
                                  Visibility impairment.
------------------------------------------------------------------------
              Proposed Guidelines State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\............                    $18
                                 ---------------------------------------
Air pollution health co-benefits  $17 to $40........  $15 to $36.
 \c\.
Total Compliance Costs \d\......  $7.5..............  $7.5.
Net Monetized Benefits \e\......  $27 to $50........  $26 to $46.
                                 ---------------------------------------
Non-monetized Benefits..........  Direct exposure to SO2 and NO2.
                                  1.5 tons.
                                  Ecosystem effects.
                                  Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2020, and are rounded to two significant
  figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SCC than to the other estimates because CO2 emissions are long-lived
  and subsequent damages occur over many years. The benefit estimates in
  this table are based on the average SCC estimated for a 3% discount
  rate, however we emphasize the importance and value of considering the
  full range of SCC values. As shown in the RIA, climate benefits are
  also estimated using the other three SCC estimates (model average at
  2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile
  at 3 percent). The SCC estimates are year-specific and increase over
  time.
\c\ The air pollution health co-benefits reflect reduced exposure to
  PM2.5 and ozone associated with emission reductions of directly
  emitted PM2.5, SO2 and NOX. The range reflects the use of
  concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 90
  percent of total monetized co-benefits from PM2.5 and ozone. These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to allow differentiation
  of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the proposed
  guidelines and a discount rate of approximately 5%. This estimate
  includes monitoring, recordkeeping, and reporting costs and demand
  side energy efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global social cost of carbon at a 3 percent discount rate
  (model average). The RIA includes combined climate and health
  estimates based on these additional discount rates.

  Table 2--Summary of the Monetized Benefits, Compliance Costs, and Net
            Benefits for the Proposed Guidelines in 2030 \a\
                           [Billions of 2011$]
------------------------------------------------------------------------
                                   3% Discount rate    7% Discount rate
------------------------------------------------------------------------
            Proposed Guidelines Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\............                   $30.
                                 ---------------------------------------
Air pollution health co-benefits  $25 to $59........  $23 to $54.
 \c\.
Total Compliance Costs \d\......  $7.3..............  $7.3.
Net Monetized Benefits \e\......  $48 to $82........  $46 to $77.
                                 ---------------------------------------
Non-monetized Benefits..........  Direct exposure to SO2 and NO2.
                                  1.7 tons of Hg and 580 tons of HCl.
                                  Ecosystem Effects.
                                  Visibility impairment.
------------------------------------------------------------------------
              Proposed Guidelines State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\............                   $31.
------------------------------------------------------------------------
Air pollution health co-benefits  $27 to $62........  $24 to $56.
 \c\.
Total Compliance Costs \d\......  $8.8..............  $8.8.
Net Monetized Benefits \e\......  $49 to $84........  $46 to $79.
------------------------------------------------------------------------

[[Page 34841]]

 
Non-monetized Benefits..........  Direct exposure to SO2 and NO2.
                                  2.1 tons of Hg and 590 tons of HCl.
                                  Ecosystem effects.
                                  Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2030, and are rounded to two significant
  figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SCC than to the other estimates because CO2 emissions are long-lived
  and subsequent damages occur over many years. The benefit estimates in
  this table are based on the average SCC estimated for a 3% discount
  rate, however we emphasize the importance and value of considering the
  full range of SCC values. As shown in the RIA, climate benefits are
  also estimated using the other three SCC estimates (model average at
  2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile
  at 3 percent). The SCC estimates are year-specific and increase over
  time.
\c\ The air pollution health co-benefits reflect reduced exposure to
  PM2.5 and ozone associated with emission reductions of directly
  emitted PM2.5, SO2 and NOX. The range reflects the use of
  concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 90
  percent of total monetized co-benefits from PM2.5 and ozone. These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to allow differentiation
  of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the proposed
  guidelines and a discount rate of approximately 5%. This estimate
  includes monitoring, recordkeeping, and reporting costs and demand
  side energy efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global social cost of carbon at a 3 percent discount rate
  (model average). The RIA includes combined climate and health
  estimates based on these additional discount rates.

    There are additional important benefits that the EPA could not 
monetize. These unquantified benefits include climate benefits from 
reducing emissions of non-CO2 greenhouse gases (e.g., 
nitrous oxide and methane) \13\ and co-benefits from reducing direct 
exposure to SO2, NOX and hazardous air pollutants 
(e.g., mercury and hydrogen chloride), as well as from reducing 
ecosystem effects and visibility impairment.
---------------------------------------------------------------------------

    \13\ Although CO2 is the predominant greenhouse gas 
released by the power sector, electricity generating units also emit 
small amounts of nitrous oxide and methane. See RIA Chapter 2 for 
more detail about power sector emissions and the U.S. Greenhouse Gas 
Reporting Program's power sector summary, http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.html.
---------------------------------------------------------------------------

    In addition to the cost and benefits of the rule, the EPA projects 
the employment impacts of the guidelines. We project job gains and 
losses relative to base case for the electric generation, coal and 
natural gas production, and demand side energy efficiency sectors. In 
2020, we project job growth of 25,900 to 28,000 job-years \14\ in the 
power production and fuel extraction sectors, and we project an 
increase of 78,800 jobs in the demand-side energy efficiency sector.
---------------------------------------------------------------------------

    \14\ A job-year is not an individual job; rather, a job-year is 
the amount of work performed by the equivalent of one full-time 
individual for one year. For example, 20 job-years in 2020 may 
represent 20 full-time jobs or 40 half-time jobs.
---------------------------------------------------------------------------

    Based upon the foregoing, it is clear that the monetized benefits 
of this proposal are substantial and far outweigh the costs.

B. Organization and Approach for This Proposed Rule

    This action presents the EPA's proposed emission guidelines for 
states to consider in developing plans to reduce GHG emissions from the 
electric power sector. Section II provides background on climate change 
impacts from GHG emissions, GHG emissions from fossil fuel-fired EGUs 
and the utility power sector and CAA section 111(d) requirements. 
Section III presents a summary of the EPA's stakeholder outreach 
efforts, key messages provided by stakeholders, state policies and 
programs that reduce GHG emissions, and conclusions. In Section IV of 
the preamble, we present a summary of the rule requirements and the 
legal basis for these. Section V explains the EPA authority to regulate 
CO2 and EGUs, identifies affected sources, and describes the 
proposed treatment of source categories. Section VI describes the use 
of building blocks for setting state goals and key considerations in 
doing so. Sections VII and VIII provide explanations of the proposed 
state-specific goals and the proposed requirements for state plans, 
respectively. Implications for the new source review and Title V 
programs and potential interactions with other EPA rules are described 
in Section IX. Impacts of the proposed action are then described in 
Section X, followed by a discussion of statutory and executive order 
reviews in Section XI and the statutory authority for this action in 
Section XII.
    We note that this rulemaking overlaps in certain respects with two 
other related rulemakings: The January 2014 proposed rulemaking that 
the EPA published on January 8, 2014 for CO2 emissions from 
newly constructed affected sources,\15\ and the rulemaking for modified 
and reconstructed sources that the EPA is proposing at the same time as 
this rulemaking. Each of these three rulemakings is independent of the 
other two, and each has its own rulemaking docket. Accordingly, 
commenters who wish to comment on any aspect of this rulemaking, 
including a topic that overlaps an aspect of one or both of the other 
two related rulemakings, should make those comments on this rulemaking.
---------------------------------------------------------------------------

    \15\ 79 FR 1430.
---------------------------------------------------------------------------

II. Background

    In this section, we discuss climate change impacts from GHG 
emissions, both on public health and public welfare, present 
information about GHG emissions from fossil fuel fired EGUs, and 
summarize the statutory and regulatory requirements relevant to this 
rulemaking.

A. Climate Change Impacts From GHG Emissions

    In 2009, the EPA Administrator issued the document known as the 
Endangerment Finding under CAA section 202(a)(1).\16\ In the 
Endangerment Finding, which focused on public health and public welfare 
impacts within the United States, the Administrator found that elevated 
concentrations of GHGs in the atmosphere may reasonably be anticipated 
to endanger public health and welfare of current and future 
generations. We summarize these adverse effects on public health and 
welfare briefly here.
---------------------------------------------------------------------------

    \16\ ``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) (``Endangerment Finding'').
---------------------------------------------------------------------------

1. Public Health Impacts Detailed in the 2009 Endangerment Finding
    Climate change caused by human emissions of GHGs threatens public 
health in multiple ways. By raising average temperatures, climate 
change

[[Page 34842]]

increases the likelihood of heat waves, which are associated with 
increased deaths and illnesses. While climate change also increases the 
likelihood of reductions in cold-related mortality, evidence indicates 
that the increases in heat mortality will be larger than the decreases 
in cold mortality in the United States. Compared to a future without 
climate change, climate change is expected to increase ozone pollution 
over broad areas of the U.S., including in the largest metropolitan 
areas with the worst ozone problems, and thereby increase the risk of 
morbidity and mortality. Other public health threats also stem from 
projected 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. 
Increased coastal storms and storm surges due to rising sea levels are 
expected to cause increased drownings and other health impacts. 
Children, the elderly, and the poor are among the most vulnerable to 
these climate-related health effects.
2. Public Welfare Impacts Detailed in the 2009 Endangerment Finding
    Climate change caused by human emissions of GHGs also threatens 
public welfare in multiple ways. Climate changes are expected to place 
large areas of the country at serious risk of reduced water supplies, 
increased water pollution, and increased occurrence of extreme events 
such as floods and droughts. Coastal areas are expected to face 
increased risks from storm and flooding damage to property, as well as 
adverse impacts from rising sea level, 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 extreme weather from climate change threatens energy, 
transportation, and water resource infrastructure. Climate change may 
exacerbate ongoing environmental pressures in certain settlements, 
particularly in Alaskan indigenous communities. Climate change also is 
very likely to fundamentally rearrange U.S. ecosystems over the 21st 
century. Though some benefits may balance adverse effects on 
agriculture and forestry in the next few decades, the body of evidence 
points towards increasing risks of net adverse impacts on U.S. food 
production, agriculture and forest productivity as temperature 
continues to rise. These impacts are global and may exacerbate problems 
outside the U.S. that raise humanitarian, trade, and national security 
issues for the U.S.
3. New Scientific Assessments
    As outlined in Section VIII.A. of the 2009 Endangerment Finding, 
the EPA's approach to providing the technical and scientific 
information to inform the Administrator's judgment regarding the 
question of whether GHGs endanger public health and welfare was to rely 
primarily upon the recent, major assessments by the U.S. Global Change 
Research Program (USGCRP), the Intergovernmental Panel on Climate 
Change (IPCC), and the National Research Council (NRC) of the National 
Academies. These assessments addressed the scientific issues that the 
EPA was required to examine, were comprehensive in their coverage of 
the GHG and climate change issues, and underwent rigorous and exacting 
peer review by the expert community, as well as rigorous levels of U.S. 
government review. Since the administrative record concerning the 
Endangerment Finding closed following the EPA's 2010 Reconsideration 
Denial, a number of such assessments have been released. These 
assessments include the IPCC's 2012 ``Special Report on Managing the 
Risks of Extreme Events and Disasters to Advance Climate Change 
Adaptation'' (SREX) and the 2013-2014 Fifth Assessment Report (AR5), 
the USGCRP's 2014 ``Climate Change Impacts in the United States'' 
(Climate Change Impacts), and the NRC's 2010 ``Ocean Acidification: A 
National Strategy to Meet the Challenges of a Changing Ocean'' (Ocean 
Acidification), 2011 ``Report on Climate Stabilization Targets: 
Emissions, Concentrations, and Impacts over Decades to Millennia'' 
(Climate Stabilization Targets), 2011 ``National Security Implications 
for U.S. Naval Forces'' (National Security Implications), 2011 
``Understanding Earth's Deep Past: Lessons for Our Climate Future'' 
(Understanding Earth's Deep Past), 2012 ``Sea Level Rise for the Coasts 
of California, Oregon, and Washington: Past, Present, and Future'', 
2012 ``Climate and Social Stress: Implications for Security Analysis'' 
(Climate and Social Stress), and 2013 ``Abrupt Impacts of Climate 
Change'' (Abrupt Impacts) assessments.
    The EPA has reviewed these new assessments and finds that the 
improved understanding of the climate system they present strengthens 
the case that GHGs endanger public health and welfare.
    In addition, these assessments highlight the urgency of the 
situation as the concentration of CO2 in the atmosphere 
continues to rise. Absent a reduction in emissions, a recent National 
Research Council of the National Academies assessment projected that 
concentrations by the end of the century would increase to levels that 
the Earth has not experienced for millions of years.\17\ In fact, that 
assessment stated that ``the magnitude and rate of the present 
greenhouse gas increase place the climate system in what could be one 
of the most severe increases in radiative forcing of the global climate 
system in Earth history.'' \18\
---------------------------------------------------------------------------

    \17\ National Research Council, Understanding Earth's Deep Past, 
p. 1.
    \18\ Id., p.138.
---------------------------------------------------------------------------

    What this means, as stated in another NRC assessment, is that:

    Emissions of carbon dioxide from the burning of fossil fuels 
have ushered in a new epoch where human activities will largely 
determine the evolution of Earth's climate. Because carbon dioxide 
in the atmosphere is long lived, it can effectively lock Earth and 
future generations into a range of impacts, some of which could 
become very severe. Therefore, emission reductions choices made 
today matter in determining impacts experienced not just over the 
next few decades, but in the coming centuries and millennia.\19\
---------------------------------------------------------------------------

    \19\ National Research Council, Climate Stabilization Targets, 
p. 3.

    Moreover, due to the time-lags inherent in the Earth's climate, the 
Climate Stabilization Targets assessment notes that the full warming 
from any given concentration of CO2 reached will not be 
realized for several centuries.
    The recently released USGCRP ``Climate Change Impacts'' assessment 
\20\ emphasizes that climate change is already happening now and it is 
happening in the United States. The assessment documents the increases 
in some extreme weather and climate events in recent decades, the 
damage and disruption to infrastructure and agriculture, and projects 
continued increases in impacts across a wide range of peoples, sectors, 
and ecosystems.
---------------------------------------------------------------------------

    \20\ U.S. Global Change Research Program, Climate Change Impacts 
in the United States: The Third National Climate Assessment, May 
2014 Available at http://nca2014.globalchange.gov/.
---------------------------------------------------------------------------

    These assessments underscore the urgency of reducing emissions now: 
Today's emissions will otherwise lead to raised atmospheric 
concentrations for thousands of years, and raised Earth system 
temperatures for even longer. Emission reductions today will benefit 
the public health and public welfare of current and future generations.
    Finally, it should be noted that the concentration of carbon 
dioxide in the atmosphere continues to rise dramatically. In 2009, the 
year of the Endangerment Finding, the average concentration of carbon 
dioxide as

[[Page 34843]]

measured on top of Mauna Loa was 387 parts per million.\21\ The average 
concentration in 2013 was 396 parts per million. And the monthly 
concentration in April of 2014 was 401 parts per million, the first 
time a monthly average has exceeded 400 parts per million since record 
keeping began at Mauna Loa in 1958, and for at least the past 800,000 
years according to ice core records.\22\
---------------------------------------------------------------------------

    \21\ ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt.
    \22\ http://www.esrl.noaa.gov/gmd/ccgg/trends/.
---------------------------------------------------------------------------

B. GHG Emissions From Fossil Fuel-Fired EGUs

    Fossil fuel-fired electric utility generating units (EGUs) are by 
far the largest emitters of GHGs, primarily in the form of 
CO2, among stationary sources in the U.S., and among fossil 
fuel-fired units, coal-fired units are by far the largest emitters. 
This section describes the amounts of those emissions and places those 
amounts in the context of the national inventory of GHGs.
    The EPA prepares the official U.S. Inventory of Greenhouse Gas 
Emissions and Sinks \23\ (the U.S. GHG Inventory) to comply with 
commitments under the United Nations Framework Convention on Climate 
Change (UNFCCC). This inventory, which includes recent trends, is 
organized by industrial sectors. It provides the information in Table 3 
below, which presents total U.S. anthropogenic emissions and sinks \24\ 
of GHGs, including CO2 emissions, for the years 1990, 2005 
and 2012.
---------------------------------------------------------------------------

    \23\ ``Inventory of U.S. Greenhouse Gas Emissions and Sinks: 
1990-2012'', Report EPA 430-R-14-003, United States Environmental 
Protection Agency, April 15, 2014.
    \24\ Sinks are a physical unit or process that stores GHGs, such 
as forests or underground or deep sea reservoirs of carbon dioxide.

                                 Table 3--U.S. GHG Emissions and Sinks by Sector
                             [Teragram carbon dioxide equivalent (Tg CO2 Eq.)] \25\
----------------------------------------------------------------------------------------------------------------
                             Sector                                    1990            2005            2012
----------------------------------------------------------------------------------------------------------------
Energy..........................................................         5,260.1         6,243.5         5,498.9
Industrial Processes............................................           316.1           334.9           334.4
Solvent and Other Product Use...................................             4.4             4.4             4.4
Agriculture.....................................................           473.9           512.2           526.3
Land Use, Land-Use Change and Forestry..........................            13.7            25.5            37.8
Waste...........................................................           165.0           133.2           124.0
                                                                 -----------------------------------------------
Total Emissions.................................................         6,233.2         7,253.8         6,525.6
Land Use, Land-Use Change and Forestry (Sinks)..................         (831.3)       (1,030.7)         (979.3)
                                                                 -----------------------------------------------
Net Emissions (Sources and Sinks)...............................         5,402.1         6,223.1         5,546.3
----------------------------------------------------------------------------------------------------------------

     
---------------------------------------------------------------------------

    \25\ From Table ES-4 of ``Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2012, Report EPA 430-R-14-003, United 
States Environmental Protection Agency, April 15, 2014.
---------------------------------------------------------------------------

    Total fossil energy-related CO2 emissions (including 
both stationary and mobile sources) are the largest contributor to 
total U.S. GHG emissions, representing 77.7 percent of total 2012 GHG 
emissions.\26\ In 2012, fossil fuel combustion by the electric power 
sector--entities that burn fossil fuel and whose primary business is 
the generation of electricity--accounted for 38.7 percent of all 
energy-related CO2 emissions.\27\ Table 4 below presents 
total CO2 emissions from fossil fuel-fired EGUs, for years 
1990, 2005 and 2012.
---------------------------------------------------------------------------

    \26\ From Table ES-2 ``Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2012'', Report EPA 430-R-14-003, United 
States Environmental Protection Agency, April 15, 2014.
    \27\ From Table 3-1 ``Inventory of U.S. Greenhouse Gas Emissions 
and Sinks: 1990-2012'', Report EPA 430-R-14-003, United States 
Environmental Protection Agency, April 15, 2014.

           Table 4--U.S. GHG Emissions From Generation of Electricity From Combustion of Fossil Fuels
                                                  [Tg CO2] \28\
----------------------------------------------------------------------------------------------------------------
                          GHG emissions                                1990            2005            2012
----------------------------------------------------------------------------------------------------------------
Total CO2 from fossil fuel combustion EGUs......................         1,820.8         2,402.1         2,022.7
    --from coal.................................................         1,547.6         1,983.8         1,511.2
    --from natural gas..........................................           175.3           318.8           492.2
    --from petroleum............................................            97.5            99.2            18.8
----------------------------------------------------------------------------------------------------------------

     
---------------------------------------------------------------------------

    \28\ From Table 3-5 ``Inventory of U.S. Greenhouse Gas Emissions 
and Sinks: 1990-2012'', Report EPA 430-R-14-003, United States 
Environmental Protection Agency, April 15, 2014.
---------------------------------------------------------------------------

C. The Utility Power Sector

    Electricity in the United States is generated by a range of 
sources--from power plants that use fossil fuels like coal, oil, and 
natural gas, to non-fossil sources, such as nuclear, solar, wind and 
hydroelectric power. In 2013, over 67 percent of power in the U.S. was 
generated from the combustion of coal, natural gas, and other fossil 
fuels, over 40 percent from coal and over 26 percent from natural 
gas.\29\ In recent years, though, the proportion of new renewable 
generation coming on line has increased dramatically. For instance, 
over 38 percent of new generating capacity (over 5 GW out of 13.5 GW) 
built in 2013 used renewable power generation technologies.\30\
---------------------------------------------------------------------------

    \29\ U.S. Energy Information Administration (EIA), ``Table 7.2b 
Electricity Net Generation: Electric Power Sector Electric Power 
Sector,'' data from April 2014 Monthly Energy Review, release date 
April 25, 2014. Available at: http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07.02B&freq=m.
    \30\ Based on Table 6.3 (New Utility Scale Generating Units by 
Operating Company, Plant, Month, and Year) of the U.S. Energy 
Information Administration (EIA) Electric Power Monthly, data for 
December 2013, for the following renewable energy sources: solar, 
wind, hydro, geothermal, landfill gas, and biomass. Available at: 
http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_6_03.

---------------------------------------------------------------------------

[[Page 34844]]

    This range of different power plants generates electricity that is 
transmitted and distributed through a complex system of interconnected 
components to industrial, business, and residential consumers.
    The utility power sector is unique in that, unlike other sectors 
where the sources operate independently and on a local scale, power 
sources operate in a complex, interconnected grid system that typically 
is regional in scale. In addition, the U.S. economy depends on this 
sector for a reliable supply of power at a reasonable cost.
    In the U.S., much of the existing power generation fleet in the 
infrastructure is aging. There has been, and continues to be, 
technological advancement in many areas, including energy efficiency, 
solar power generation, and wind power generation. Advancements and 
innovation in power sector technologies provide the opportunity to 
address CO2 emission levels at affected power plants while 
at the same time improving the overall power system in the U.S. by 
lowering the carbon intensity of power generation, and ensuring a 
continued reliable supply of power at a reasonable cost.

D. Statutory and Regulatory Requirements

    Clean Air Act section 111, which Congress enacted as part of the 
1970 Clean Air Act Amendments, establishes mechanisms for controlling 
emissions of air pollutants from stationary sources. This provision 
requires the EPA to promulgate a list of categories of stationary 
sources that the Administrator, in his or her judgment, finds ``causes, 
or contributes significantly to, air pollution which may reasonably be 
anticipated to endanger public health or welfare.'' \31\ The EPA has 
listed more than 60 stationary source categories under this 
provision.\32\ Once the EPA lists a source category, the EPA must, 
under CAA section 111(b)(1)(B), establish ``standards of performance'' 
for emissions of air pollutants from new sources in the source 
categories.\33\ These standards are known as new source performance 
standards (NSPS), and they are national requirements that apply 
directly to the sources subject to them.
---------------------------------------------------------------------------

    \31\ CAA Sec.  111(b)(1)(A).
    \32\ See 40 CFR 60 subparts Cb-OOOO.
    \33\ CAA Sec.  111(b)(1)(B), 111(a)(1).
---------------------------------------------------------------------------

    When the EPA establishes NSPS for new sources in a particular 
source category, the EPA is also required, under CAA section 111(d)(1), 
to prescribe regulations for states to submit plans regulating existing 
sources in that source category for any air pollutant that, in general, 
is not regulated under the CAA section 109 requirements for the NAAQS 
or regulated under the CAA section 112 requirements for hazardous air 
pollutants (HAP). CAA section 111(d)'s mechanism for regulating 
existing sources differs from the one that CAA section 111(b) provides 
for new sources because CAA section 111(d) contemplates states 
submitting plans that establish ``standards of performance'' for the 
affected sources and that contain other measures to implement and 
enforce those standards.
    ``Standards of performance'' are defined under CAA section 
111(a)(1) as standards for emissions that reflect the emission 
limitation achievable from the ``best system of emission reduction,'' 
considering costs and other factors, that ``the Administrator 
determines has been adequately demonstrated.'' CAA section 111(d)(1) 
grants states the authority, in applying a standard of performance to 
particular sources, to take into account the source's remaining useful 
life or other factors.
    Under CAA section 111(d), a state must submit its plan to the EPA 
for approval, and the EPA must approve the state plan if it is 
``satisfactory.'' \34\ If a state does not submit a plan, or if the EPA 
does not approve a state's plan, then the EPA must establish a plan for 
that state.\35\ Once a state receives the EPA's approval for its plan, 
the provisions in the plan become federally enforceable against the 
entity responsible for noncompliance, in the same manner as the 
provisions of an approved SIP under CAA section 110. Although affected 
EGUs located in Indian country operate as part of the interconnected 
system of electricity production and distribution, those EGUs would not 
be encompassed within a state's CAA section 111(d) plan. Instead, a 
tribe that has one or more affected EGUs located in its area of Indian 
country \36\ would have the opportunity, but not the obligation, to 
establish a plan that establishes standards of performance for 
CO2 emissions from affected EGUs for its tribal lands.
---------------------------------------------------------------------------

    \34\ CAA section 111(d)(2)(A).
    \35\ CAA section 111(d)(2)(A).
    \36\ The EPA is aware of at least four affected sources located 
in Indian Country: Two on Navajo lands--the Navajo Generating 
Station and the Four Corners Generating Station; one on Ute lands--
the Bonanza Generating Station; and one on Fort Mojave lands, the 
South Point Energy Center. The affected EGUs at the first three 
plants are coal-fired EGUs. The fourth affected EGU is an NGCC 
facility.
---------------------------------------------------------------------------

    The EPA issued regulations implementing CAA section 111(d) in 
1975,\37\ and has revised them in the years since.\38\ (We refer to the 
regulations generally as the implementing regulations, and we refer to 
the 1975 rulemaking as the framework regulations.) These regulations 
provide that, in promulgating requirements for sources under CAA 
section 111(d), the EPA first develops regulations known as ``emission 
guidelines,'' which establish binding requirements that states must 
address when they develop their plans.\39\ The implementing regulations 
also establish timetables for state and EPA action: States must submit 
state plans within 9 months of the EPA's issuance of the 
guidelines,\40\ and the EPA must take final action on the state plans 
within 4 months of the due date for those plans,\41\ although the EPA 
has authority to extend those deadlines.\42\ In the present rulemaking, 
the EPA is following the requirements of the implementing regulations, 
and is not re-opening them, except that the EPA is extending the 
timetables, as described below.
---------------------------------------------------------------------------

    \37\ ``State Plans for the Control of Certain Pollutants From 
Existing Facilities,'' 40 FR 53,340 (Nov. 17, 1975).
    \38\ The most recent amendment was in 77 FR 9304 (Feb. 16, 
2012).
    \39\ 40 CFR 60.22. In the 1975 rulemaking, the EPA explained 
that it used the term ``emissions guidelines''--instead of emissions 
limitations--to make clear that guidelines would not be binding 
requirements applicable to the sources, but instead are ``criteria 
for judging the adequacy of State plans.'' 40 FR at 53,343.
    \40\ 40 CFR 60.23(a)(1).
    \41\ 40 CFR 60.27(b).
    \42\ See 40 CFR 60.27(a).
---------------------------------------------------------------------------

    Over the last forty years, under CAA section 111(d), the agency has 
regulated four pollutants from five source categories (i.e., sulfuric 
acid plants (acid mist), phosphate fertilizer plants (fluorides), 
primary aluminum plants (fluorides), Kraft pulp plants (total reduced 
sulfur), and municipal solid waste landfills (landfill gases)).\43\ In 
addition, the agency has regulated additional pollutants under CAA 
section 111(d) in conjunction with CAA

[[Page 34845]]

section 129.\44\ The agency has not previously regulated CO2 
or any other greenhouse gas under CAA section 111(d).
---------------------------------------------------------------------------

    \43\ See ``Phosphate Fertilizer Plants; Final Guideline Document 
Availability,'' 42 Fed. Reg. 12,022 (Mar. 1, 1977); ``Standards of 
Performance for New Stationary Sources; Emission Guideline for 
Sulfuric Acid Mist,'' 42 FR 55,796 (Oct. 18, 1977); ``Kraft Pulp 
Mills, Notice of Availability of Final Guideline Document,'' 44 FR 
29,828 (May 22, 1979); ``Primary Aluminum Plants; Availability of 
Final Guideline Document,'' 45 FR 26,294 (Apr. 17, 1980); 
``Standards of Performance for New Stationary Sources and Guidelines 
for Control of Existing Sources: Municipal Solid Waste Landfills, 
Final Rule,'' 61 FR 9905 (Mar. 12, 1996).
    \44\ See, e.g., ``Standards of Performance for New Stationary 
Sources and Emission Guidelines for Existing Sources: Sewage Sludge 
Incineration Units, Final Rule,'' 76 FR 15,372 (Mar. 21, 2011).
---------------------------------------------------------------------------

    The EPA's previous CAA section 111(d) actions were necessarily 
geared toward the pollutants and industries regulated. Similarly, in 
this proposed rulemaking, in defining CAA section 111(d) emission 
guidelines for the states and determining the BSER, the EPA believes 
that taking into account the particular characteristics of carbon 
pollution, the interconnected nature of the power sector and the manner 
in which EGUs are currently operated is warranted. Specifically, the 
operators themselves treat increments of generation as interchangeable 
between and among sources in a way that creates options for relying on 
varying utilization levels, lowering carbon generation, and reducing 
demand as components of the overall method for reducing CO2 
emissions. Doing so results in a broader, forward-thinking approach to 
the design of programs to yield critical CO2 reductions that 
improve the overall power system by lowering the carbon intensity of 
power generation, while offering continued reliability and cost-
effectiveness. These opportunities exist in the power sector in ways 
that were not relevant or available for other industries for which the 
EPA has established CAA section 111(d) emission guidelines.\45\
---------------------------------------------------------------------------

    \45\ See ``Phosphate Fertilizer Plants; Final Guideline Document 
Availability,'' 42 FR 12,022 (Mar. 1, 1977); ``Standards of 
Performance for New Stationary Sources; Emission Guideline for 
Sulfuric Acid Mist,'' 42 FR 55,796 (Oct. 18, 1977); ``Kraft Pulp 
Mills, Notice of Availability of Final Guideline Document,'' 44 FR 
29,828 (May 22, 1979); ``Primary Aluminum Plants; Availability of 
Final Guideline Document,'' 45 FR 26,294 (Apr. 17, 1980); 
``Standards of Performance for New Stationary Sources and Guidelines 
for Control of Existing Sources: Municipal Solid Waste Landfills, 
Final Rule,'' 61 F R 9905 (Mar. 12, 1996).
---------------------------------------------------------------------------

    In this action, the EPA is proposing emission guidelines for states 
to follow in developing their plans to reduce emissions of 
CO2 from the electric power sector.

III. Stakeholder Outreach and Conclusions

A. Stakeholder Outreach

1. The President's Call for Engagement
    Following the direction of the Presidential Memorandum to the 
Administrator (June 25, 2013),\46\ this proposed rule was developed 
after extensive and vigorous outreach to stakeholders and the general 
public. The Presidential Memorandum instructed the Administrator to 
inaugurate the process for developing standards through direct 
engagement with the states and a full range of stakeholders:
---------------------------------------------------------------------------

    \46\ Presidential Memorandum--Power Sector Carbon Pollution 
Standards, June 25, 2013. http://www.whitehouse.gov/the-press-office/2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards.

    Launch this effort through direct engagement with States, as 
they will play a central role in establishing and implementing 
standards for existing power plants, and, at the same time, with 
leaders in the power sector, labor leaders, non-governmental 
organizations, other experts, tribal officials, other stakeholders, 
and members of the public, on issues informing the design of the 
program.
2. Educating the Public and Stakeholder Outreach
    To carry out this stakeholder outreach, the EPA embarked on an 
unprecedented pre-proposal outreach effort. From consumer groups to 
states to power plant owner/operators to technology innovators, the EPA 
sought input from all perspectives.
    The EPA began the outreach efforts with a webinar and associated 
teleconferences to establish a common understanding of the basic 
requirements and process of CAA section 111(d). The August 27, 2013 
overview presentation was offered as a webinar for state and tribal 
officials, ``Building a Common Understanding: Clean Air Act and 
Upcoming Carbon Pollution Guidelines for Existing Power Plants.''
    The EPA followed up on the presentation by offering four national 
teleconference calls with representatives from states, tribes, 
industry, environmental justice organizations, community organizations 
and environmental representatives. The teleconferences offered a venue 
for stakeholders to ask questions of the EPA about the overview 
presentation and for the EPA to gather initial reactions from 
stakeholders. Stakeholders and members of the public continued to view 
and refer to the overview presentation throughout the outreach process. 
By May 2014, the presentation had been viewed more than 5,600 times.
    The agency also provided mechanisms for anyone from the public to 
provide input during the pre-proposal development of this action. The 
EPA set up two user-friendly options to accept input during the pre-
proposal period--email and a web-based form. The EPA has received more 
than 2,000 emails offering input into the development of these 
guidelines.
    These emails and other materials provided to the EPA are posted on 
line as part of a non-regulatory docket, EPA Docket ID No. EPA-HQ-OAR-
2014-0020, at www.regulations.gov. All of the documents on which this 
proposal is based are available at Docket ID No. EPA-HQ-OAR-2013-0602, 
at www.regulations.gov. However, while the information collected 
through extensive outreach helped the agency formulate this proposal, 
we are not relying on all of the documents, emails, and other 
information included in the informational docket that was established 
as a part of that outreach effort, nor will the EPA be responding to 
specific comments or issues raised during the outreach effort. Rather, 
we have included in the docket for this proposal all of the information 
we relied on for this action.
    The agency has encouraged, organized, and participated in hundreds 
of meetings about CAA section 111(d) and reducing carbon pollution from 
existing power plants. Attendees at these various meetings have 
included states and tribes, members of the public, and representatives 
from multiple industries, labor leaders, environmental groups and other 
non-governmental organizations. The direct engagement has brought 
together a variety of states and stakeholders to discuss a wide range 
of issues related to the electricity sector and the development of 
emission guidelines under CAA section 111(d). The meetings occurred in 
Washington, DC, and at locations across the country. The meetings were 
attended by the EPA Regional Administrators, managers and staff and who 
are playing or will play key roles in developing and implementing the 
rule.
    Part of this effort included the agency's holding of 11 public 
listening sessions; one national listening session in Washington, DC 
and 10 listening sessions in locations in the EPA regional offices 
across the country. All of the outreach meetings were designed to 
solicit policy ideas, concerns and technical information from 
stakeholders about using CAA section 111(d).
    This outreach process has produced a wealth of information which 
has informed this proposal significantly. The pre-proposal outreach 
efforts far exceeded what is required of the agency in the normal 
course of a rulemaking process, and the EPA expects that the dialog 
with states and stakeholders will continue throughout the process and 
even after the rule is finalized. The EPA recognizes the importance of 
working with all stakeholders, and in particular with the states, to 
ensure a clear and common understanding of the role the

[[Page 34846]]

states will play in addressing carbon pollution from power plants.
3. Public Listening Sessions
    More than 3,300 people attended the public listening sessions held 
in 11 cities across the country. Holding the listening sessions at the 
EPA's regional offices offered thousands of people from different parts 
of the country the opportunity to provide input to EPA officials in 
accessible venues. In addition to being well located, holding the 
sessions in regional offices also allowed the agency to use resources 
prudently and enabled a variety of the EPA staff involved in the 
development and ultimate implementation of this upcoming rule to attend 
and learn from the views expressed.
    More than 1,600 people spoke at the 11 listening sessions. Speakers 
included Members of Congress, other public officials, industry 
representatives, faith-based organizations, unions, environmental 
groups, community groups, students, public health groups, energy 
groups, academia and concerned citizens. Participants shared a range of 
perspectives. Many were concerned by the impacts of climate change on 
their health and on future generations, others worried about the impact 
of regulations on the economy. Their support for the agency's efforts 
varied.
    Summaries of these 11 public listening sessions are available at 
www.regulations.gov at EPA Docket ID No. EPA-HQ-OAR-2014-0020.
4. State Officials
    Since fall 2013, the agency provided multiple opportunities for the 
states to inform this proposal. In addition, the EPA organized, 
encouraged and attended meetings to discuss multi-state planning 
efforts. Because of the interconnectedness of the power sector, and the 
fact that electricity generated at power plants crosses state lines, 
states, utilities and ratepayers may benefit from states working 
together to address the requirements of this rulemaking implementation. 
The meetings provided state leaders, including governors, environmental 
commissioners, energy officers, public utility commissioners, and air 
directors, opportunities to engage with the EPA officials.
    Agency officials listened to ideas, concerns and details from 
states, including from states with a wide range of experience in 
reducing carbon pollution from power plants. The agency has collected 
policy papers from states with overarching energy goals and technical 
details on the states' electricity sector. The agency has engaged, and 
will continue to engage with, all of the 50 states throughout the 
rulemaking process.
5. Tribal Officials
    The EPA conducted significant outreach to tribes, who are not 
required to--but may--develop or adopt Clean Air Act programs. The EPA 
is aware of three coal-fired power plants and one natural gas-fired EGU 
located in Indian country but is not aware of any EGUs that are owned 
or operated by tribal entities.
    The EPA conducted outreach to tribal environmental staff and 
offered consultation with tribal officials in developing this action. 
Because the EPA is aware of tribal interest in this proposed rule, the 
EPA offered consultation with tribal officials early in the process of 
developing the proposed regulation to permit tribes to have meaningful 
and timely input into its development.
    The EPA sent consultation letters to 584 tribal leaders. The 
letters provided information regarding the EPA's development of 
emission guidelines for existing power plants and offered consultation. 
None have requested consultation. Tribes were invited to participate in 
the national informational webinar held August 27, 2013. In addition, a 
consultation/outreach meeting was held on September 9, 2013, with 
tribal representatives from some of the 584 tribes. The EPA 
representatives also met with tribal environmental staff with the 
National Tribal Air Association, by teleconference, on December 19, 
2013. In those teleconferences, the EPA provided background information 
on the GHG emission guidelines to be developed and a summary of issues 
being explored by the agency.
    In addition, the EPA held a series of listening sessions prior to 
development of this proposed action. Tribes participated in a session 
on September 9, 2013 with the state agencies, as well as in a separate 
session with tribes on September 26, 2013.
6. Industry Representatives
    Agency officials have engaged with industry leaders and 
representatives from trade associations in scores of one-on-one and 
national meetings. Many meetings occurred at the EPA headquarters and 
in the EPA's Regional Offices and some were sponsored by stakeholder 
groups. Because the focus of the standard is on the electricity sector, 
many of the meetings with industry have been with utilities and 
industry representatives directly related to the electricity sector. 
The agency has also met with energy industries such as coal and natural 
gas interests, as well as companies that offer new technology to 
prevent or reduce carbon pollution, including companies that have 
expertise in renewable energy and energy efficiency. Other meetings 
have been held with representatives of energy intensive industries, 
such as the iron and steel and aluminum industries to help understand 
the issues related to large industrial users of electricity.
7. Electric Utility Representatives
    Agency officials participated in many meetings with utilities and 
their associations. The meetings focused on the importance of the 
utility industry in reducing carbon emissions from power plants. Power 
plant emissions are central to this rulemaking. The EPA encouraged 
industry representatives to work with state environmental and energy 
officers.
    The electric utility representatives included private utilities or 
investor owned utilities. Public utilities and cooperative utilities 
were also part of in-depth conversations about CAA section 111(d) with 
EPA officials.
    The conversations included meetings with the EPA headquarters and 
Regional offices. State officials were included in many of the 
meetings. Meetings with utility associations and groups of utilities 
were held with key EPA officials. The meetings covered technical, 
policy, and legal topics of interest and utilities expressed a wide 
variety of support and concerns about CAA section 111(d).
8. Electricity Grid Operators
    The EPA had a number of conversations with the Independent System 
Operators and Regional Transmission Organizations (ISOs and RTOs) to 
discuss the rule and issues related to grid operations and reliability. 
EPA staff met with the ISO/RTO Council on several occasions to collect 
their ideas. The EPA Regional Offices also met with the ISOs and RTOs 
in their regions. System operators have offered suggestions in using 
regional approaches to implement CAA section 111(d) while maintaining 
reliable, affordable electricity.
9. Representatives From Non-Governmental Organizations
    Agency officials engaged with representatives of environmental 
justice organizations during the outreach effort, for example, we 
engaged with the National Environmental Justice Advisory Council 
members in September 2013. The NEJAC is composed of stakeholders, 
including environmental justice leaders and other

[[Page 34847]]

leaders from state and local government and the private sector.
    The EPA has also met with a number of environmental groups to 
provide their ideas on how to reduce carbon pollution from existing 
power plants using section 111(d) of the CAA.
    Many environmental organizations discussed the need for reducing 
carbon pollution. Meetings were technical, policy and legal in nature 
and many groups discussed specific state policies that are already in 
place to reduce carbon pollution in the states.
    A number of organizations representing religious groups have 
reached out to the EPA on several occasions to discuss their concerns 
and ideas regarding this rule.
    Public health groups discussed the need for protection of 
children's health from harmful air pollution. Doctors and health care 
providers discussed the link between reducing carbon pollution and air 
pollution and public health. Consumer groups representing advocates for 
low income electricity customers discussed the need for affordable 
electricity. They talked about reducing electricity prices for 
consumers through energy efficiency and low cost carbon reductions.
10. Labor
    EPA senior officials and staff met with a number of labor union 
representatives about reducing carbon pollution using CAA section 
111(d). Those unions included: The United Mine Workers of America; the 
Sheet Metal, Air, Rail and Transportation Union (SMART); the 
International Brotherhood of Boilermakers, Iron Ship Builders, 
Blacksmiths, Forgers and Helpers (IBB); United Association of 
Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry of 
the United States and Canada; the International Brotherhood of 
Electrical Workers (IBEW): And the Utility Workers Union of America. In 
addition, agency leaders met with the Presidents of several unions and 
the President of the American Federation of Labor-Congress of 
Industrial Organizations (AFL-CIO) at the AFL-CIO headquarters.
    EPA officials, when invited, attended meetings sponsored by labor 
unions to give presentations and engage in discussions about reducing 
carbon pollution using CAA section 111(d). These included meetings 
sponsored by the IBB and the IBEW.

B. Key Messages From Stakeholders

    Many stakeholders stated that opportunities exist to reduce the 
carbon emissions from existing power generation through a wide range of 
measures, from measures that are implementable via physical changes at 
the source to those that also are implementable across the broader 
power generation system. Opinions varied about how broader system 
measures could factor into programs to reduce carbon pollution. Some 
stakeholders recommended that system-wide measures be allowed for 
compliance, but not factored into the carbon improvement goals the EPA 
establishes, while others recommended that system-wide measures be 
factored into the goals. Among the arguments and information offered by 
stakeholders who suggested that states be encouraged to incorporate 
system-wide measures into their state plans and that EGU operators be 
encouraged to rely on such measures were examples and discussions of 
the significant extent to which dispatch, end use energy efficiency and 
renewable energy had already proven to be successful strategies for 
reducing EGU CO2 emissions. Some state and industry 
representatives favored goals that they described as based on measures 
implementable only within the facility ``fence line'' (i.e., measures 
implementable only at the source). Many stakeholders stated that the 
EPA should not require the state plans to impose on the affected EGUs 
legal responsibility for the full amount of required CO2 
emissions reductions, and instead, the EPA should authorize the state 
plans to include requirements on entities other than the affected EGUs 
that would have the effect of reducing utilization and, therefore, 
emissions from the affected EGUs.
    Views on the form and stringency of the goal or guidelines varied. 
Some stakeholders preferred a rate-based form of the goal, while others 
preferred a mass-based form. In addition, some stakeholders recommended 
that the EPA let the states have the flexibility to either choose among 
multiple forms of the goals or to set their own goals. With regard to 
the stringency of the goal, some stakeholders recommended that the 
stringency of the goals vary by state, to account for differences in 
state circumstances.
    Many stakeholders recognized the value of allowing states 
flexibility in implementing the goals the EPA establishes. For example, 
states highlighted the importance of the EPA recognizing existing state 
and regional programs that address carbon pollution, including market-
based programs, and allowing credit for prior accomplishments in 
reducing CO2 emissions. Many states and other stakeholders 
noted the importance of the EPA allowing flexibility in compliance 
options such that states could use approaches such as demand-side 
management to attain the goals.
    Many stakeholders recommended that states be allowed to develop 
multi-state programs. It was frequently noted that such regional 
approaches could offer cost-effective carbon pollution solutions.
    There was broad agreement that most states would need more than one 
year to develop and submit their complete plans to the EPA. For some 
states, more time is necessary because of the state legislative 
schedule and/or regulatory process. In some cases, approval of a plan 
through a state's legislative or regulatory process could take one year 
or more after the plan has already been developed. Additional time 
would also allow and encourage multi-state and regional partnerships 
and programs.
    Many stakeholders also supported flexibility in the timing of 
implementation of the state plans and power sector compliance with the 
goals in the state plans. Such flexibility, some stakeholders asserted, 
would accommodate the diverse GHG mitigation potential of states and 
support more cost-effective approaches to achieving CO2 
reductions.
    During the outreach process, some stakeholders raised general 
concerns that the rulemaking could have a negative impact on jobs and 
ratepayers. Some stakeholders also expressed concerns about potential 
adverse effects on electric system reliability. Some stakeholders were 
concerned that meeting the goals could potentially result in stranded 
generation assets. To prevent this from occurring, some stakeholders 
suggested varying the stringency of standards to account for individual 
state circumstances and variation.
    The EPA has given stakeholder input careful consideration during 
the development of this proposal and, as a result, this proposal 
includes features that are intended to be responsive to many 
stakeholder concerns.

C. Key Stakeholder Proposals

    During the EPA's public outreach in advance of this proposal, a 
number of ideas were put forward that are not fully reflected in this 
proposal. We invite public comment on these ideas, some of which are 
outlined below.
1. Model Rule on Interstate Emissions Credit Trading and Price Ceiling
    Some groups thought that the EPA should put forward a model rule 
for an interstate emissions credit trading program that could be easily 
adopted by states who wanted to use such a

[[Page 34848]]

program for its plan. One group suggested the model rule should include 
a provision to allow the state to compensate merchant generators as 
well as retail rate payers. Another group specified that the model rule 
would also include a ceiling-price called an alternative compliance 
payment that would fund state directed clean technology investment. 
Facilities that face costs that exceed the ceiling price could opt to 
pay into the fund as a way of complying.
2. Equivalency Tests
    One group recommended that state programs be allowed to demonstrate 
equivalency using one of three tests: Rate-based equivalency via a 
demonstration that the state program achieves equivalent or better 
carbon intensity for the regulated sector; mass-based equivalency via a 
demonstration that the program achieves equal or greater emission 
reductions relative to what would be achieved by the federal approach; 
or a market price-based equivalency via a demonstration that the 
program reflects a carbon price comparable to or greater than the cost-
effectiveness benchmark used by the EPA in designing the program. The 
EPA is proposing a way to demonstrate equivalency and that is discussed 
in Section VIII of this preamble.
3. Power Plant-Specific Assessment
    Other stakeholders suggested that an ``inside the fence'' plant- or 
unit-specific assessment linked to the availability of control at the 
source such as heat rate improvements should be considered. They 
indicated that once plant-specific goals are established based on on-
site CO2 reduction opportunities, the source should have the 
flexibility to look ``outside the fence'' for the means to achieve the 
goals, including the use of emissions trading, and averaging.
    The EPA invites comment on these suggestions.

D. Consideration of the Range of Existing State Policies and Programs

    Across the nation, many states and regions have shown strong 
leadership in creating and implementing policies and programs that 
reduce GHG emissions from the power sector while achieving other 
economic, environmental, and energy benefits. Some of these activities, 
such as market-based programs and GHG performance standards, directly 
require GHG emission reductions from EGUs. Others reduce GHG emissions 
by reducing utilization of fossil fuel-fired EGUs through, for example, 
renewable portfolio standards (RPS) and energy efficiency resource 
standards (EERS), which alter the mix of energy supply and reduce 
energy demand. States have developed their policies and programs with 
stakeholder input and tailored them to their own circumstances and 
priorities. Their leadership and experiences provided the EPA with 
important information about best practices to build upon in this 
proposed rule. As directed by the Presidential Memorandum, the EPA is, 
with this proposal to reduce power plant carbon pollution, building on 
actions already underway in states and the power sector.
1. Market-Based Emission Limits
    Nine states actively participate in the Regional Greenhouse Gas 
Initiative (RGGI), a market-based CO2 emission reduction 
program addressing EGUs that was established in 2009.\47\ Through RGGI, 
the participating states are implementing coordinated CO2 
emission budget trading programs. In aggregate, these programs 
establish an overall limit on allowable CO2 emissions from 
affected EGUs in the participating states. Participating states issue 
CO2 allowances in an amount up to the number of allowances 
in each state's annual emission budget. At the end of each three-year 
compliance period, affected EGUs must submit CO2 allowances 
equal to their reported CO2 emissions. CO2 
allowances may be traded among both regulated and non-regulated 
parties, creating a market for emission allowances. This market creates 
a price signal for CO2 emissions, which factors into the 
dispatch of affected EGUs. A price signal for CO2 emissions 
also allows sources flexibility to make emission reductions where 
reduction costs are lowest, and encourages innovation in developing 
emission control strategies.
---------------------------------------------------------------------------

    \47\ The nine states include Connecticut, Delaware, Maine, 
Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and 
Vermont.
---------------------------------------------------------------------------

    Approximately 90 percent of CO2 allowances are 
distributed by the RGGI participating states through auction.\48\ From 
2009 through 2012, the nine RGGI states invested auction proceeds of 
more than $700 million in programs that lower costs for energy 
consumers and reduce CO2 emissions.\49\ Through 2012, for 
example, the RGGI states invested approximately $460 million of 
proceeds into energy efficiency programs.\50\ The participating RGGI 
states estimate that those investments are providing benefits to energy 
consumers in the region of more than $1.8 billion in lifetime energy 
savings.\51\
---------------------------------------------------------------------------

    \48\ Regional Greenhouse Gas Initiative 2013 Allowance 
Allocation http://rggi.org/design/overview/allowance-allocation/2013-allocation.
    \49\ Regional Investments of RGGI CO2 Allowance 
Proceeds, 2012 (2014), available at http://www.rggi.org/docs/Documents/2012-Investment-Report.pdf.
    \50\ Of the $707 million in auction proceeds invested by RGGI 
participating states through 2012, 65 percent supported end-use 
energy efficiency programs. See Regional Greenhouse Gas Initiative, 
``Regional Investments of RGGI CO2 Allowance Proceeds, 
2012'' (2014). Available at http://www.rggi.org/docs/Documents/2012-Investment-Report.pdf.
    \51\ Id.
---------------------------------------------------------------------------

    Between 2005, when an agreement to implement RGGI was announced, 
and 2012, power sector CO2 emissions in the RGGI 
participating states fell by more than 40 percent.\52\ RGGI was not the 
primary driver for these reductions but the reductions led RGGI-
participating states to later adjust the CO2 emission limits 
downward.\53\ In January 2014, the participating states lowered the 
overall allowable CO2 emission level in 2014 by 45 percent, 
setting a multi-state CO2 emission limit for affected EGUs 
of 91 million short tons of CO2 in 2014 and 78 million short 
tons of CO2 in 2020, more than 50 percent below 2008 
levels.\54\
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    \52\ Regional Greenhouse Gas Initiative, Report on Emission 
Reduction Efforts of the States Participating in the Regional 
Greenhouse Gas Initiative and Recommendations for Guidelines under 
Section 111(d) of the Clean Air Act (2013).
    \53\ The first three-year control period under RGGI, 
establishing CO2 emission limits for EGUs, began on 
January 1, 2009.
    \54\ RGGI Press Release, January 13, 2014, http://www.rggi.org/docs/PressReleases/PR011314_AuctionNotice23.pdf.
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    Similarly, California established an economy-wide market-based GHG 
emissions trading program under the authority of its 2006 Global 
Warming Solutions Act, which requires the state to reduce its 2020 GHG 
emissions to 1990 levels.\55\ While California's emission trading 
program, like its state emission limit, is multi-sector in scope, the 
state projects that the emissions trading program and related 
complementary measures will reduce power sector GHG emissions to less 
than 80 million metric tons of CO2 equivalent by 2025, a 25 
percent reduction from 2005 power sector emission levels.\56\ Prior to 
the implementation of the emission trading program, California reports 
that it reduced CO2 power sector emissions by 16 percent 
from 2005 to a 2010-2012

[[Page 34849]]

averaging period, a reduction of 16 million metric tons of 
CO2 equivalent.\57\
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    \55\ State of California Global Warming Solutions Act of 2006, 
Assembly Bill 32, Chapter http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered.pdf.
    \56\ Preliminary California Air Resources Board analyses, based 
in part on CARB 2008 to 2012 Emissions for Mandatory GHG reporting 
Summary (2013), cited in Letter to the EPA Administrator, ``States' 
Roadmap on Reducing Carbon Pollution,'' December 16, 2013. Available 
at http://www.georgetownclimate.org/sites/default/files/EPA_Submission_from_States-FinalCompl.pdf.
    \57\ Id.
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2. GHG Performance Standards
    Four states, California, New York, Oregon and Washington, have 
enacted GHG emission standards that impose enforceable emission limits 
on new and/or expanded electric generating units. For example, since 
2012, New York requires new or expanded baseload plants that are 
greater than 25 Megawatts (MW) to meet an emission rate of either 925 
pounds CO2/Megawatt hour (MWh) (based on output) or 120 
pounds of CO2/Million British Thermal Units (MMBtu) (based 
on input). Similarly, non-baseload plants in New York of at least 25 MW 
or larger must meet an emission rate of either 1450 pounds 
CO2/MWh (based on output) or 160 pounds of CO2/
MMBtu (based on input).\58\
---------------------------------------------------------------------------

    \58\ 6 New York Codes, Rules & Regulations. Part 251 (Adopted 
June 28, 2012).
---------------------------------------------------------------------------

    Three states, California, Oregon and Washington, have enacted GHG 
emission performance standards that set an emission rate for 
electricity purchased by electric utilities. In both Oregon and 
Washington, for example, electric utilities may enter into long term 
power purchase agreements for baseload power only if the electric 
generator supplying the power has a CO2 emission rate of 
1,100 pounds of CO2 per MWh or less.\59\
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    \59\ OR SB 101 (2000); Washington Revised Code ch.80.80 (2013); 
Wash SB 6001 (2007).
---------------------------------------------------------------------------

3. Utility Planning Approaches
    Two states, Minnesota and Colorado, have worked collaboratively 
with their investor-owned utilities to develop multi-pollutant emission 
reduction plans on a utility-wide basis. This multi-pollutant, 
collaborative approach enables utilities to determine the least cost 
way to meet long term and comprehensive energy and environmental goals.
    Colorado's Clean Air, Clean Jobs Act of 2010, for example, required 
Colorado investor-owned utilities with coal plants to develop a multi-
pollutant plan to meet existing and reasonably foreseeable federal CAA 
requirements.\60\ The utilities were not required to adopt a specific 
plan set by the state but were, instead, required to work 
collaboratively with the Colorado Department of Public Health and 
Environmental and Colorado Public Utility Commission to develop an 
acceptable plan. Xcel Energy, Colorado's largest investor-owned 
utility, submitted a plan that was approved in 2010. With this plan, 
Xcel Energy is projected to reduce its CO2 emissions from 
generation in Colorado by 28 percent by 2020.\61\
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    \60\ Colorado Clean Air, Clean Jobs Act, HB1365.
    \61\ Xcel Energy, Colorado Clean Air-Clean Jobs Plan, available 
at http://www.xcelenergy.com/Environment/Doing_Our_Part/Clean_Air_Projects/Colorado_Clean_Air_Clean_Jobs_Plan.
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4. Renewable Portfolio Standards
    More than 25 states have mandatory renewable portfolio standards 
that require retail electricity suppliers to supply a minimum 
percentage or amount of their retail electricity load with electricity 
generated from eligible sources of renewable energy.\62\ These 
standards have been established via utility regulatory commissions, 
legislatures and citizen ballots and requirements vary from state to 
state. State RPS typically specify the types of renewable energy, or 
other energy sources, that qualify for use toward achievement of the 
standard, and often allow for the use of qualifying renewable energy 
resources located outside of the state. They reduce utilization of 
fossil fuel-fired EGUs and, thereby, lead to reductions in GHG 
emissions by meeting a portion of the demand for electricity through 
renewable or other energy sources.
---------------------------------------------------------------------------

    \62\ http://www.dsireusa.org/.
---------------------------------------------------------------------------

    In 2007, the Minnesota legislature amended the state's 2001 
renewable energy objective and established a renewable energy standard 
(RES) requiring at least 25 percent of all electricity generated or 
purchased in Minnesota to come from renewable energy by 2025. The 
standard sets requirements and timetables, beginning in 2010, that vary 
based on the provider. For example, in 2011, Xcel Energy had a 
requirement to generate or purchase 15 percent of its total retail 
sales from renewable energy while all other utilities had a target of 7 
percent of total retail sales. According to the latest Minnesota 
Department of Commerce report to the legislature on progress, all 
utilities subject to the standard met it for 2011 and were on track to 
meet their 2012 goals.\63\ The 2012 requirement increased to 18 percent 
of total retail sales for Xcel Energy and 12 percent for all other 
utilities.\64\ In 2013, the Minnesota legislature expanded the RES with 
solar incentives and a specific solar energy standard requiring 
Minnesota utilities to ensure that at least 1.5 percent of their retail 
electricity sales in 2020 come from solar energy.\65\
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    \63\ Report to the Minnesota Legislature: Progress on Compliance 
By Electric Utilities With The Minnesota Renewable Energy Objective 
and the Renewable Energy Standard, Prepared by: The Minnesota 
Department of Commerce, Division of Energy Resources January 14, 
2013; http://mn.gov/commerce/energy/images/2013RESLegReport.pdf.
    \64\ Id.
    \65\ Minnesota Statutes 2013, Section 216B.1691, Subdivision 2f. 
Solar Energy Standard https://www.revisor.mn.gov/statutes/?id=216b.1691.
---------------------------------------------------------------------------

    The Oregon Renewable Portfolio Standard (RPS) is another example of 
a state requirement for renewables. Originally enacted in 2007, it 
requires that all utilities serving Oregon meet a percentage of their 
retail electricity needs with qualified renewable resources. Like in 
Minnesota, the percentage varies across utilities with the three 
largest utilities required to reach five percent from renewable energy 
sources starting in 2011, 15 percent in 2015, 20 percent in 2020, and 
25 percent in 2025. Other electric utilities in the state are required 
to reach levels of five percent or ten percent by 2025, depending on 
their size. According to the latest RPS compliance reports submitted by 
the largest utilities for the state, each had achieved the five percent 
target as of the end of 2012.\66\
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    \66\ Eugene Water Electric Board Oregon Renewable Portfolio 
Standard 2012 Compliance Report and 2013-2030 Implementation Plan, 
June 1, 2013. PacifiCorp's Renewable Portfolio Standard Oregon 
Compliance Report for 2012, May 31, 2013. PGE 2012 Renewable 
Portfolio Standard Compliance Report, June 1, 2013.
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5. Demand-Side Energy Efficiency Programs
    Many electric utilities, third-party administrators, and states 
implement demand-side energy efficiency programs to reduce generation 
from EGUs by reducing electricity use, including peak demand. When 
these programs reduce fossil fuel electricity generation, they also 
reduce CO2 emissions. Demand-side energy efficiency programs 
use a variety of energy efficiency measures to target a variety of end 
uses and are often driven by existing state standards and programs, 
such as policies requiring utilities to obtain ``all cost-effective 
energy efficiency'' through long-term integrated resource planning 
(IRP), renewable portfolio standards (RPS) that include efficiency as a 
qualifying resource, energy efficiency resource standards (EERS), 
public benefit funds, and other demand-side planning requirements.
    The purposes of demand-side energy efficiency programs vary; goals 
include to reduce GHG emissions by reducing fossil-fired generation, 
help states achieve energy savings goals, save energy and money for 
consumers and improve electricity reliability. They are typically 
funded through a small fee or surcharge on customer electricity bills, 
but can also be funded by other sources, such as from RGGI 
CO2 allowance auction proceeds mentioned above.

[[Page 34850]]

    Nationally, total spending on electric ratepayer-funded energy 
efficiency programs was about $5 billion in 2012.\67\ Based on Lawrence 
Berkeley National Laboratory (LBNL) projections, spending is projected 
to reach $8.1 billion in 2025.\68\
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    \67\ Consortium for Energy Efficiency Annual Industry Report: 
2013 State of the Efficiency Program Industry--Budgets, Expenditures 
and Impacts, 2014.
    \68\ Lawrence Berkeley National Laboratory (LBNL) The Future of 
Utility Customer-Funded Energy Efficiency Programs in the United 
States: Projected Spending and Savings to 2025 (http://emp.lbl.gov/sites/all/files/lbnl-5803e.pdf).
---------------------------------------------------------------------------

    Electricity savings from energy efficiency programs are also 
growing. In 2011, electricity savings from these programs totaled 
approximately 22.9 million MWh, a 22 percent increase from the previous 
year.\69\
---------------------------------------------------------------------------

    \69\ American Council for an Energy Efficient Economy (ACEEE) 
2013 State Scorecard http://www.aceee.org/sites/default/files/publications/researchreports/e13k.pdf.
---------------------------------------------------------------------------

    California has been advancing energy efficiency through utility-run 
demand-side energy efficiency programs for decades and considers energy 
efficiency ``the bedrock upon which climate policies are built.'' \70\ 
It requires its investor-owned utilities to meet electricity load 
``through all available energy efficiency and demand reduction 
resources that are cost-effective, reliable and feasible.'' \71\ The 
California Public Utility Commission works with the California Energy 
Commission to determine the amount of cost-effective reduction 
potential and establishes efficiency targets. A recent energy 
efficiency potential study found that, even after years of running 
programs, California can still tap ``tens of thousands of GWh in 
potential savings . . . over the next decade.'' \72\ Investor-owned 
utilities use demand-side energy efficiency programs to achieve their 
targets and currently ``save about 3,000 GW per year, enough savings to 
power about 600,000 households.'' \73\ Between 2010 and 2011, these 
programs are estimated to have reduced CO2 by 3.8 million 
tons.\74\
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    \70\ December 27, 2013 Letter from Mary D. Nichols, Chairman of 
California Air Resources Board, to EPA Administrator Gina McCarthy.
    \71\ Cal Pub. Utility Code Sec.  454.5 (a)(9)(C).
    \72\ Cited in December 27, 2013 Letter from Mary D. Nichols, 
Chairman of California Air Resources Board, to EPA Administrator 
Gina McCarthy.
    \73\ Id.
    \74\ Id.
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    In Vermont, for example, the Vermont Legislature and the Vermont 
Public Service Board (PSB) established the first statewide ``energy 
efficiency utility'' in 1999 to provide energy efficiency services to 
residences and businesses throughout the state.\75\ Vermont law 
requires that the energy efficiency utility budgets be set at a level 
to achieve ``all reasonably available, cost-effective energy 
efficiency'' and then specific energy (kWh) and peak demand (kW) 
savings levels are negotiated every three years.\76\ In 2013, 
Efficiency Vermont, the PSB-appointed energy efficiency utility, 
achieved annual savings of 1.66 percent of the state's electricity 
sales, at a cost of 4.1 cents per kilowatt[hyphen]hour, lower than the 
cost of comparable electric supply in the same year, which was 8.4 
cents per kWh.\77\ Efficiency Vermont projects a net lifetime economic 
value to Vermont of more than $60 million from the 2013 energy 
efficiency investments.\78\
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    \75\ State of Vermont Public Service Board, Energy Efficiency 
Utility Creation and Structure. http://psb.vermont.gov/utilityindustries/eeu/generalinfo/ creationandstructure.
    \76\ Vermont Statute, Title 30: Public Service, 30 V.S.A. Sec.  
209 (d)3(B). http://www.leg.state.vt.us/statutes/fullsection.cfm?Title=30&Chapter=005&Section=00209.
    \77\ Efficiency Vermont Savings Claim Summary 2013, Reported to 
the Vermont Public Service Board and to the Vermont Public Service 
Department, 2014, https://www.efficiencyvermont.com/docs/about_efficiency_vermont/annual_summaries/2013_savingsclaim_summary.pdf.
    \78\ Id.
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6. Energy Efficiency Resource Standards
    More than 20 states have energy efficiency resource standards 
(EERS) that require utilities to save a certain amount of energy each 
year or cumulatively.\79\ They are typically multi-year requirements 
expressed as a percentage of annual retail electricity sales or as 
specific electricity savings amounts over a long term period relative 
to a baseline of retail sales. Over the compliance period, an EERS 
reduces fossil fuel-fired EGU generation through reductions in 
electricity demand, thereby reducing CO2 emissions from the 
power sector.
---------------------------------------------------------------------------

    \79\ State Energy Efficiency Resource Standards: Policy Design, 
Status, and Impacts, DC Steinberg, O. Zinaman, NREL Technical Report 
NREL/TP-6A20-61023, April 2014.
---------------------------------------------------------------------------

    In Arizona, for example, the Arizona Corporation Commission (ACC) 
adopted rules in 2010 requiring all investor-owned utilities to achieve 
22 percent cumulative electricity savings by 2020, making it one of the 
highest standards in the nation.\80\ The rule required utilities to 
achieve 1.25 percent electricity savings in 2011 compared to 
electricity sales in the previous year, ramping up the savings each 
year until 2020 according to a designated timetable.\81\ In 2012, for 
example, investor-owned utilities were required to achieve energy 
savings equivalent to 1.75 percent of the 2011 sales, leading to a 
cumulative savings requirement of 3 percent by the end of 2012 (an 
average of 1.5% annually over the 2 year period).\82\ Utilities can 
meet the energy savings requirements through a variety of means, 
including cost-effective energy efficiency programs, as well as load 
management and demand response programs.\83\ Arizona Public Service 
Company (APS), the largest utility in Arizona, achieved cumulative 
energy savings equivalent to 3.2 percent of retail sales from 2011 to 
2012, exceeding the 3 percent savings target, and reported a net 
benefit to consumers of more than $200 million for the year 2012 
alone.\84\
---------------------------------------------------------------------------

    \80\ Arizona Corporation Commission, Docket RE-OOOOOC-09-0427, 
August 2010. Available at http://images.edocket.azcc.gov/docketpdf/0000116125.pdf.
    \81\ Id.
    \82\ Arizona Corporation Commission, Docket RE-OOOOOC-09-0427, 
August 2010. Available at http://images.edocket.azcc.gov/docketpdf/0000116125.pdf.
    \83\ Id.
    \84\ Arizona Public Service Company 2012 Demand Side Management 
Annual Progress Report, March 1, 2013 Web site, http://www.aps.com/en/ourcompany/aboutus/energyefficiency/Pages/home.aspx.
---------------------------------------------------------------------------

E. Conclusions

    States have taken a leadership role in mitigating GHG emissions and 
have demonstrated the potential for national application of a number of 
approaches. Throughout the development of this proposed rule, the EPA 
considered the states' experiences and lessons learned regarding the 
design and implementation of successful GHG mitigation programs. The 
agency also fully considered input from stakeholders during the 
development of this proposed rulemaking.
    Considering all input from stakeholders, the agency recognizes that 
the most cost-effective approach to reducing GHG emissions from the 
power sector under CAA section 111(d) is to follow the lead of numerous 
states and not only to identify improvements in the efficiency of 
fossil fuel-fired EGUs as a component of the BSER, but also include in 
the BSER determination the EGU-emissions-reduction opportunities that 
states have already demonstrated to be successful in relying on lower- 
and zero-emitting generation and reduced electricity demand.
    CAA section 111(d) sets up a partnership between the EPA and the 
states. In the context of that partnership, the EPA recognizes the 
importance of each state having the flexibility to design a cost-
effective program tailored to its own specific circumstances. The 
agency also recognizes, as many states

[[Page 34851]]

have, the value of regional planning in designing approaches to achieve 
cost-effective GHG reductions. To support state flexibility and 
encourage multi-state coordination in the development of multi-state 
and regional programs and policies, the EPA recognizes that flexibility 
in both the timing of plan submittal and the timing of CO2 
emission reductions will be necessary.

IV. Rule Requirements and Legal Basis

A. Summary of Rule Requirements

    The EPA is proposing emission guidelines for each state to use in 
developing plans to address greenhouse gas emissions from existing 
fossil fuel-fired electric generating units. The emission guidelines 
are based on the EPA's determination of the ``best system of emission 
reduction . . . adequately demonstrated'' (BSER) and include state-
specific goals, general approvability criteria for state plans, 
requirements for state plan components, and requirements for the 
process and timing for state plan submittal and compliance.
    Under CAA section 111(d), the states must establish standards of 
performance that reflect the degree of emission limitation achievable 
through the application of the ``best system of emission reduction'' 
that, taking into account the cost of achieving such reduction and any 
non-air quality health and environmental impact and energy 
requirements, the Administrator determines has been adequately 
demonstrated. Consistent with CAA section 111(d), the EPA is proposing 
state-specific goals that reflect the EPA's calculation of the BSER.
    Under CAA section 111(d), each state must develop, adopt, and then 
submit its plan to the EPA. To do so, the state would determine, and 
include in its plan, an emission performance level that is equivalent 
to the state-specific CO2 goal in the emission guidelines. 
As part of determining this level, the state would decide whether to 
adopt the rate-based form of the goal established by the EPA or 
translate the rate-based goal to a mass-based goal. The state would 
then establish a standard of performance or set of standards of 
performance (known as emission standards under the existing CAA section 
111(d) framework regulations), along with implementing and enforcing 
measures, that will achieve a level of emission performance that equals 
or exceeds the level specified in the state plan.
    The EPA is proposing to determine the BSER as the combination of 
emission rate improvements and limitations on overall emissions at 
affected EGUs that can be accomplished through any combination of one 
or more measures from the following four sets of measures or building 
blocks:
    1. Reducing the carbon intensity of generation at individual 
affected EGUs through heat rate improvements.
    2. Reducing emissions from the most carbon-intensive affected EGUs 
in the amount that results from substituting generation at those EGUs 
with generation from less carbon-intensive affected EGUs (including 
natural gas combined cycle (NGCC) units that are under construction).
    3. Reducing emissions from affected EGUs in the amount that results 
from substituting generation at those EGUs with expanded low- or zero-
carbon generation.
    4. Reducing emissions from affected EGUs in the amount that results 
from the use of demand-side energy efficiency that reduces the amount 
of generation required.
    The EPA has reviewed information about the current and recent 
performance of affected EGUs and states' implementation of programs 
that reduce CO2 emissions from these sources. Based on our 
analysis of that information, the proposed state goals reflect the 
following stringency of application of the measures in each of the 
building blocks: Block 1, improving average heat rate of coal-fired 
steam EGUs by six percent; block 2, displacing coal-fired steam and 
oil/gas-fired steam generation in each state by increasing generation 
from existing NGCC capacity in that state toward a 70 percent target 
utilization rate; block 3, including the projected amounts of 
generation achievable by completing all nuclear units currently under 
construction, avoiding retirement of about six percent of existing 
nuclear capacity, and increasing renewable electric generating capacity 
over time through the use of state-level renewable generation targets 
consistent with renewable generation portfolio standards that have been 
established by states in the same region; and block 4, increasing state 
demand-side energy efficiency efforts to reach 1.5 percent annual 
electricity savings in the 2020-2029 period.
    Based on the EPA's application of the BSER to each state, the EPA 
is proposing to establish, as part of the emission guidelines, state-
specific goals, expressed as average emission rates for fossil fuel-
fired EGUs. Each state's goals comprise the EPA's determination of the 
emission limitation achievable through application of the BSER in that 
state. For each state, the EPA is proposing an interim goal for the 
phase-in period from 2020 to 2029 and the final goal that applies 
beginning in 2030. The proposed goals for each state are listed in 
Section VII, below. The EPA is proposing that measures that a state 
takes after the date of this proposal, and that result in 
CO2 emission reductions during the plan period, would apply 
toward achievement of the state's CO2 goal.
    The EPA is further proposing, as part of the plan guidelines, 
timetables for states to submit their plans. The agency expects to 
finalize this rulemaking by June 2015, and we are proposing to require 
that each state submit its plan to the EPA by June 30, 2016. However, 
if a state needs additional time to submit a complete plan, the state 
must submit an initial plan by June 30, 2016, that documents the 
reasons why more time is needed to submit a complete plan and includes 
commitments to take concrete steps that will ensure that the state will 
submit a complete plan by June 30, 2017, or June 30, 2018, as 
appropriate. If such a state is developing a plan limited in 
geographical scope to the individual state, then the state would have 
until June 30, 2017, to submit a complete plan. A state that is 
developing a plan that includes a multi-state approach would have until 
June 30, 2018, to submit a complete plan.
    The EPA is further proposing, as part of the emission guidelines, 
to allow states the option of translating the EPA-determined goal, 
which will be rate-based, to a mass-based goal. For states 
participating in a multi-state approach, the individual state 
performance goals in the emission guidelines would be replaced with an 
equivalent multi-state performance goal. The EPA is also proposing that 
in their plans, whether single state or multi-state, states may not 
adjust the stringency of the goals set by the EPA.
    Under CAA section 111(d)(1) and the implementing regulations, with 
the state emission performance level in place, the state must adopt a 
state plan that establishes a standard of performance or set of 
standards of performance, along with implementing and enforcing 
measures, that will achieve that emission performance level. The EPA is 
further proposing, as part of the guidelines, to authorize the state to 
submit either of two types of measures to achieve the performance 
level: (1) A set of measures that we refer to as ``portfolio'' 
measures, which include a combination of emission limitations that 
apply directly to the affected sources and other measures that have the 
effect of limiting generation by, and therefore emissions from, the 
affected sources; or (2) solely emission limitations that apply 
directly to the affected sources.

[[Page 34852]]

    The EPA is also proposing, as part of the plan guidelines, that a 
complete state plan include the following twelve components:

 Identification of affected entities
 Description of plan approach and geographic scope
 Identification of state emission performance level
 Demonstration that plan is projected to achieve emission 
performance level
 Identification of emissions standards
 Demonstration that each emissions standard is quantifiable, 
non-duplicative, permanent, verifiable, and enforceable
 Identification of monitoring, reporting, and recordkeeping 
requirements
 Description of state reporting
 Identification of milestones
 Identification of backstop measures
 Certification of hearing on state plan
 Supporting material

    The EPA is also proposing, as part of its emission guidelines, that 
plan approvability be based on four general criteria: (1) Enforceable 
measures that reduce EGU CO2 emissions; (2) projected 
achievement of emission performance equivalent to the goals established 
by the EPA, on a timeline equivalent to that in the emission 
guidelines; (3) quantifiable and verifiable emission reductions; and 
(4) a process for reporting on plan implementation, progress toward 
achieving CO2 goals, and implementation of corrective 
actions, if necessary.
    The EPA is also proposing, as part of its plan guidelines, 
requirements for the process and timing for demonstrating achievement 
of the required emission performance level, including performance and 
emission milestones. The proposed option would require each state to 
achieve its ultimate CO2 emission performance level by 2030 
and, in addition, provide an initial, phase-in compliance period of up 
to 10 years, from 2020 up to 2029, for a state and/or other responsible 
parties to comply with the emission performance level in the state 
plan. A state would need to meet its interim 2020-2029 CO2 
emission performance level on average over the 10-year phase-in 
compliance period, achieve its final CO2 emission 
performance level by 2030, and maintain it thereafter.
    If a state with affected EGUs does not submit a plan or if the EPA 
does not approve a state's plan, then under CAA section 111(d)(2)(A), 
the EPA must establish a plan for that state. A state that has no 
affected EGUs must document this in a formal letter submitted to the 
EPA by June 30, 2016. In the case of a tribe that has one or more 
affected EGUs in its area of Indian country,\85\ the tribe would have 
the opportunity, but not the obligation, to establish a CO2 
emission performance standard and a CAA section 111(d) plan for its 
area of Indian country. If it determines that such a plan is necessary 
or appropriate, the EPA has the responsibility to establish CAA section 
111(d) plans for areas of Indian country where affected sources are 
located unless a tribe on whose lands an affected source (or sources) 
is located seeks and obtains authority from the EPA to establish a plan 
itself, pursuant to the Tribal Authority Rule.
---------------------------------------------------------------------------

    \85\ The EPA is aware of at least four affected EGUs located in 
Indian country: Two on Navajo lands, the Navajo Generating Station 
and the Four Corners Generating Station; one on Ute lands, the 
Bonanza Generating Station; and one on Fort Mojave lands, the South 
Point Energy Center. The affected EGUs at the first three plants are 
coal-fired EGUs. The fourth affected EGU is an NGCC facility.
---------------------------------------------------------------------------

B. Summary of Legal Basis

    This proposed action is consistent with the requirements of CAA 
section 111(d) and the implementing regulations. As an initial matter, 
the EPA reasonably interprets the provisions identifying which air 
pollutants are covered under CAA section 111(d) to authorize the EPA to 
regulate CO2 from fossil fuel-fired EGUs. In addition, the 
EPA recognizes that CAA section 111(d) applies to sources that, if they 
were new sources, would be covered under a CAA section 111(b) rule. The 
EPA intends to complete two CAA section 111(b) rulemakings regulating 
CO2 from new fossil fuel-fired EGUs and from modified and 
reconstructed fossil fuel-fired EGUs before it finalizes this 
rulemaking, and either of those section 111(b) rulemakings will provide 
the requisite predicate for this rulemaking.
    A key step in promulgating requirements under CAA section 111(d) is 
determining the ``best system of emission reduction . . . adequately 
demonstrated'' (BSER). In promulgating the implementing regulations, 
the EPA explicitly stated that it is authorized to determine the BSER; 
\86\ accordingly, in this rulemaking, the EPA is determining the BSER.
---------------------------------------------------------------------------

    \86\ The EPA is not re-opening that interpretation in this 
rulemaking.
---------------------------------------------------------------------------

    The EPA is proposing two alternative BSER for fossil fuel-fired 
EGUs, each of which is based on methods that have already been employed 
for reducing emissions of air pollutants, including, in some cases, 
CO2, from these sources. The first identifies the 
combination of the four building blocks as the BSER. These include 
operational improvements and equipment upgrades that the coal-fired 
steam-generating EGUs in the state may undertake to improve their heat 
rate (building block 1) and increases in, or retention of, zero- or 
low-emitting generation, as well as measures to reduce demand for 
generation, all of which, taken together, displace, or avoid the need 
for, generation from the affected EGUs (building blocks 2, 3, and 4). 
All of these measures are components of a ``system of emission 
reduction'' for the affected EGUs because they either improve the 
carbon intensity of the affected EGUs in generating electricity or, 
because of the integrated nature of the electricity system and the 
fungibility of electricity, they displace or avoid the need for 
generation from those sources and thereby reduce the emissions from 
those sources. Moreover, those measures may be undertaken by the 
affected EGUs themselves and, in the case of building blocks 2, 3, and 
4, they may be required by the states.
    Further, these measures meet the criteria in CAA section 111(a)(1) 
and the caselaw as the ``best'' system of emission reduction because, 
among other things, they achieve the appropriate level of reductions, 
they are of reasonable cost, and they encourage technological 
development that is important to achieving further emission reductions. 
Moreover, the measures in each of the building blocks are ``adequately 
demonstrated'' because they are each well-established in numerous 
states, and many of them have already been relied on to reduce GHGs and 
other air pollutants from fossil fuel-fired EGUs. It should be 
emphasized that these measures are consistent with current trends in 
the electricity sector.
    For the alternative approach for the BSER, the EPA is identifying 
the ``system of emission reduction'' as including, in addition to 
building block 1, the reduction of affected fossil fuel-fired EGUs' 
mass emissions achievable through reductions in generation of specified 
amounts from those EGUs. Under this approach, the measures in building 
blocks 2, 3, and 4 would not be components of the system of emission 
reduction, but instead would serve as bases for quantifying the 
reduction in emissions resulting from the reduction in generation at 
affected EGUs. In light of the available sources of replacement 
generation through the measures in the building blocks, this approach 
would also meet the criteria for being the ``best'' system that is 
``adequately demonstrated'' because of the emission reductions it would

[[Page 34853]]

achieve, its reasonable cost, and its promotion of technological 
development, as well as the fact that the reliability of the 
electricity system would be maintained.
    After determining the BSER, the EPA is authorized under the 
implementing regulations, as an integral component to setting emission 
guidelines, to apply the BSER and determine the resulting emission 
limitation. The EPA is proposing to apply the BSER to the affected EGUs 
on a statewide basis. In this rulemaking, the EPA terms the resulting 
emission limitation the state goal.
    With the promulgation of the emission guidelines, each state must 
develop a plan to achieve an emission performance level that 
corresponds to the state goal. The state plans must establish standards 
of performance for the affected EGUs and include measures that 
implement and enforce those standards. Based on requests from 
stakeholders, the EPA is proposing that states be authorized to submit 
state plans that do not impose legal responsibility on the affected 
EGUs for the entirety of the emission performance level, but instead, 
by adopting what this preamble refers to as a ``portfolio approach,'' 
impose requirements on other affected entities (e.g., renewable energy 
and demand-side energy efficiency measures) that would reduce 
CO2 emissions from the affected EGUs.
    It should be noted that an important aspect of the BSER for 
affected EGUs is that the EPA is proposing to apply it on a statewide 
basis. The statewide approach also underlies the required emission 
performance level, which, as noted, is based on the application of the 
BSER to a state's affected EGUs, and which the suite of measures in the 
state plan, including the emission standards for the affected EGUs, 
must achieve overall. The state has flexibility in assigning the 
emission performance obligations to its affected EGUs, in the form of 
standards of performance--and, for the portfolio approach, in imposing 
requirements on other entities--as long as, again, the required 
emission performance level is met.
    This state-wide approach both harnesses the efficiencies of 
emission reduction opportunities in the interconnected electricity 
system and is fully consistent with the principles of federalism that 
underlie the Clean Air Act generally and CAA section 111(d) 
particularly. That is, this provision achieves the emission performance 
requirements through the vehicle of a state plan, and provides each 
state significant flexibility to take local circumstances and state 
policy goals into account in determining how to reduce emissions from 
its affected sources, as long as the plan meets minimum federal 
requirements. This state-wide approach, and the standards of 
performance for the affected EGUs that the states will establish 
through the state-plan process, are consistent with the applicable CAA 
section 111 provisions.
    A state has discretion in determining the measures in its plans. 
The state may adopt measures that assure the achievement of the 
required emission performance level, and is not limited to the measures 
that the EPA identifies as part of the BSER. By the same token, the 
affected EGUs, to comply with the applicable standards of performance 
in the state plan, may rely on any efficacious means of emission 
reduction, regardless of whether the EPA identifies those measures as 
part of the BSER.
    In this rulemaking, the EPA proposes reasonable deadlines for state 
plan submission and the EPA's action. The proposed deadline for the 
EPA's action on state plan submittals varies from that in the 
implementing regulations, and the EPA is proposing to revise that 
provision in the regulations accordingly. Under CAA section 111(d)(2), 
the state plans must be ``satisfactory'' for the EPA to approve them, 
and in this rulemaking, the EPA is proposing the criteria that the 
state plans must meet under that requirement.
    The EPA discusses its legal interpretation in more detail in other 
parts of this preamble and discusses certain issues in more detail in 
the Legal Memorandum included in the docket for this rulemaking. The 
EPA solicits comment on all aspects of its legal interpretations, 
including the discussion in the Legal Memorandum.

V. Authority To Regulate Carbon Dioxide and EGUs, Affected Sources, 
Treatment of Categories

A. Authority To Regulate Carbon Dioxide

    The EPA has the authority to regulate, under CAA section 111(d), 
CO2 emissions from EGUs, under the Agency's construction of 
the ambiguous provisions in CAA section 111(d)(1)(A)(i) that identify 
the air pollutants subject to CAA section 111(d). The ambiguities stem 
from apparent drafting errors that occurred during enactment of the 
1990 CAA Amendments, which revised section 111(d).
    During the 1990 CAA Amendments, the House of Representatives and 
the Senate each passed an amendment to CAA section 111(d)(1)(A)(i). The 
two amendments differed from each other, and were not reconciled during 
the Conference Committee and, as a result, both were enacted into law. 
As amended by the Senate, the pertinent language of CAA section 
111(d)(1) would exclude the regulation of any pollutant which is 
``included on a list published under [CAA section] 112(b).'' \87\ As 
amended by the House, the pertinent language in CAA section 111(d)(1) 
would exclude the regulation of any pollutant which is ``emitted from a 
source category which is regulated under section 112.'' \88\ The two 
versions conflict with each other and thus are ambiguous. Under these 
circumstances, the EPA may reasonably construe the provision to 
authorize the regulation of GHGs under CAA section 111(d).
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    \87\ Public Law 101-549, Sec.  302(a), 104 Stat. at 2574 (Nov. 
15, 1990).
    \88\ Public Law 101-549, Sec.  108(g), 104 Stat. at 2467 (Nov. 
15, 1990).
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    It should be noted that the U.S. Supreme Court's holding in 
American Electric Power Co. v. Connecticut, 131 S. Ct. 2527, 2537-38 
(2011), that ``the Clean Air Act and the EPA actions it authorizes 
displace any federal common law right to seek abatement of carbon-
dioxide emissions from fossil fuel-fired power plants'' was premised on 
the Court's understanding that CAA section 111, including CAA section 
111(d), applies to carbon dioxide emissions from those sources.
    We discuss this issue in more detail in the Legal Memorandum.

B. Authority To Regulate EGUs

    Before the EPA finalizes this CAA section 111(d) rule, the EPA will 
finalize a CAA section 111(b) rulemaking regulating CO2 
emissions from new EGUs, which will provide the requisite predicate for 
applicability of CAA section 111(d).
    CAA section 111(d)(1) requires the EPA to promulgate regulations 
under which states must submit state plans regulating ``any existing 
source'' of certain pollutants ``to which a standard of performance 
would apply if such existing source were a new source.'' A ``new 
source'' is ``any stationary source, the construction or modification 
of which is commenced after the publication of regulations (or, if 
earlier, proposed regulations) prescribing a standard of performance 
under [CAA section 111] which will be applicable to such source.'' It 
should be noted that these provisions make clear that a ``new source'' 
includes one that undertakes either new construction or a modification. 
It should also be noted

[[Page 34854]]

that the EPA's implementing regulations define ``construction'' to 
include ``reconstruction,'' which the implementing regulations go on to 
define as the replacement of components of an existing facility to an 
extent that (i) the fixed capital cost of the new components exceeds 50 
percent of the fixed capital cost that would be required to construct a 
comparable entirely new facility, and (ii) it is technologically and 
economically feasible to meet the applicable standards.
    Under CAA section 111(d)(1), in order for existing sources to 
become subject to that provision, the EPA must promulgate standards of 
performance under CAA section 111(b) to which, if the existing sources 
were new sources, they would be subject. Those standards of performance 
may include ones for sources that undertake new construction, 
modifications, or reconstructions.
    The EPA is in the process of promulgating two rulemakings under CAA 
section 111(b) for CO2 emissions from affected sources. The 
EPA proposed the first, which applies to affected sources undertaking 
new constructions, by notice dated January 8, 2014, which we refer to 
as the January 2014 Proposal. The EPA is proposing the second, which 
applies to affected sources undertaking modifications or 
reconstructions, concurrently with this CAA section 111(d) proposal. 
The EPA will complete one or both of these CAA section 111(b) 
rulemakings before or concurrently with this CAA section 111(d) 
rulemaking, which will provide the requisite predicate for 
applicability of CAA section 111(d).\89\
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    \89\ In the past, the EPA has issued standards of performance 
under section 111(b) and emission guidelines under section 111(d) 
simultaneously. See ``Standards of Performance for new Stationary 
Sources and Guidelines for Control of Existing Sources: Municipal 
Solid Waste Landfills--Final Rule,'' 61 FR 9905 (March 12, 1996).
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C. Affected Sources

    The EPA is proposing that, for the emission guidelines, an affected 
EGU is any fossil fuel-fired EGU that was in operation or had commenced 
construction as of January 8, 2014, and is therefore an ``existing 
source'' for purposes of CAA section 111, and that in all other 
respects would meet the applicability criteria for coverage under the 
proposed GHG standards for new fossil fuel-fired EGUs (79 FR 1430; 
January 8, 2014).
    The January 8, 2014 proposed GHG standards for new EGUs generally 
define an affected EGU as any boiler, integrated gasification combined 
cycle (IGCC), or combustion turbine (in either simple cycle or combined 
cycle configuration) that (1) is capable of combusting at least 250 
million Btu per hour; (2) combusts fossil fuel for more than 10 percent 
of its total annual heat input (stationary combustion turbines have an 
additional criteria that they combust over 90 percent natural gas); (3) 
sells the greater of 219,000 MWh per year and one-third of its 
potential electrical output to a utility distribution system; and (4) 
was not in operation or under construction as of January 8, 2014 (the 
date the proposed GHG standards of performance for new EGUs were 
published in the Federal Register). The minimum fossil fuel consumption 
condition applies over any consecutive three-year period (or as long as 
the unit has been in operation, if less). The minimum electricity sales 
condition applies on an annual basis for boilers and IGCC facilities 
and over rolling three-year periods for combustion turbines (or as long 
as the unit has been in operation, if less).
    The rationale for this proposal concerning applicability is the 
same as that for the January 8, 2014 proposal, sections V.A-B. See 79 
FR at 1,459/1-1,461/2. We incorporate that discussion by reference 
here.

D. Implications for Tribes and U.S. Territories

    As noted in Section II.D of this preamble, although affected EGUs 
located in Indian country operate as part of the interconnected system 
of electricity production and distribution, affected EGUs located in 
Indian country within a state's borders would not be encompassed within 
the state's CAA section 111(d) plan. The EPA is aware of four 
potentially affected power plants located in Indian country: The South 
Point Energy Center, on Fort Mojave tribal lands within Arizona; the 
Navajo Generating Station, on Navajo tribal lands within Arizona; the 
Four Corners Power Plant, on Navajo tribal lands within New Mexico; and 
the Bonanza Power Plant, on Ute tribal lands within Utah. The South 
Point facility is an NGCC power plant, and the Navajo, Four Corners, 
and Bonanza facilities are coal-fired power plants. The operators and 
co-owners of these four facilities include investor-owned utilities, 
cooperative utilities, public power agencies, and independent power 
producers, most of which also co-own potentially affected EGUs within 
state jurisdictions. We are not aware of any potentially affected EGUs 
that are owned or operated by tribal entities. If it determines that 
such a plan is necessary or appropriate, the EPA has the responsibility 
to establish CAA section 111(d) plans for areas of Indian country where 
affected sources are located unless a tribe on whose lands an affected 
source (or sources) is located seeks and obtains authority from the EPA 
to establish a plan itself, pursuant to the Tribal Authority Rule.\90\ 
The EPA intends to publish a supplemental proposal to establish 
emission performance goals (if it determines that such action is 
necessary or appropriate) covering the four potentially affected power 
plants identified above, as well as any subsequently identified 
similarly situated power plants, and also to proposed goals for U.S. 
territories with affected EGUs. The EPA intends to take final action on 
that proposal by June 2015. If a tribe does seek and obtain the 
necessary authority to establish a plan itself, it is the EPA's 
intention that the tribe would have flexibility to develop a plan 
tailored to its circumstances, in the same manner as a state, to meet 
CO2 emission performance goals that would be established by 
the EPA based on application of the BSER to that area of Indian 
country. The EPA is aware of actions that have been taken or are being 
taken by some sources in tribal areas or territories and will be 
mindful of these actions in considering establishment of a plan.
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    \90\ See 40 CFR 49.1 to 49.11.
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    The EPA invites comment on whether a tribe wishing to develop and 
implement a CAA section 111(d) plan should have the option of including 
the EGUs located in its area of Indian country in a multi-
jurisdictional plan with one or more states (i.e., treating the tribal 
lands as an additional state).
    If the EPA develops one or more CAA section 111(d) federal plans 
for areas of Indian country with affected EGUs, we are likewise 
currently considering doing so on a multi-jurisdictional basis in 
coordination with nearby states developing section 111(d) state plans. 
The EPA solicits comment on such an approach for a federal plan.
    At this time, the EPA is not proposing CO2 emission 
performance goals for areas of Indian country containing potentially 
affected EGUs. We do plan to establish such goals in the future, to be 
addressed through either tribal or federal plans, as discussed above. 
The EPA notes that some present and planned actions being taken to 
reduce criteria pollutants from EGUs in Indian country will result in 
significant CO2 emission reductions relative to emissions in 
the 2012 baseline period used in computing the state CO2

[[Page 34855]]

performance goals in this proposal.\91\ We invite comment on how the 
BSER should be applied to potentially affected EGUs in Indian country. 
We particularly invite comment on data sources for setting renewable 
energy and demand-side energy efficiency targets.
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    \91\ For example, a plan currently being implemented at the Four 
Corners plant to satisfy regional haze requirements calls for 
reduction of NOx emissions to be achieved in part by shutting down a 
portion of the plant's generating capacity, and a similar plan has 
been proposed for the Navajo plant. See 78 FR 62509 (October 22, 
2013).
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    The state-specific goals that the EPA is proposing are based on the 
collection of affected EGUs located within that state. In setting goals 
specific to an area of Indian country, the EPA proposes to base the 
goals on the collection of affected EGUs located within that area of 
Indian country. We request comment on this approach.

E. Combined Categories and Codification in the Code of Federal 
Regulations

    In this rulemaking, the EPA is soliciting comment on combining the 
two existing categories for the affected EGUs into a single category 
for purposes of facilitating emission trading among sources in both 
categories. The EPA is also proposing codifying all of the proposed 
requirements for the affected EGUs in a new subpart UUUU of 40 CFR part 
60.
    As discussed in the January 8, 2014 proposal for the CAA section 
111(b) standards for GHG emissions from EGUs, in 1971 the EPA listed 
fossil fuel-fired steam generating boilers as a new category subject to 
section 111 rulemaking, and in 1979 the EPA listed fossil fuel-fired 
combustion turbines as a new category subject to the CAA section 111 
rulemaking. In the ensuing years, the EPA has promulgated standards of 
performance for the two categories, and codified those standards, at 
various times, in 40 CFR part 60 subparts D, Da, GG, and KKKK. In the 
2014 proposal, the EPA proposed separate standards of performance for 
sources in the two categories and proposed codifying the standards in 
the same Da and KKKK subparts that currently contain the standards of 
performance for conventional pollutants from those sources. In 
addition, the EPA co-proposed combining the two categories into a 
single category solely for purposes of the CO2 emissions 
from new construction of affected EGUs, and codifying the proposed 
requirements in a new 40 CFR part 60 subpart TTTT. The EPA solicited 
comment on whether combining the categories for new sources is 
necessary in order to combine the categories for existing sources.
    In the present rulemaking, the EPA is proposing emission guidelines 
for the two categories and is soliciting comment on combining the two 
categories into a single category for purposes of the CO2 
emissions from existing affected EGUs. The EPA solicits comment on 
whether combining the two categories would offer additional 
flexibility, for example, by facilitating implementation of 
CO2 mitigation measures, such as shifting generation from 
higher to lower-carbon intensity generation among existing sources 
(e.g., shifting from boilers to NGCC units) or facilitating emissions 
trading among sources. Because the two categories are pre-existing and 
the EPA would not be subjecting any additional sources to regulation, 
the combined category would not be considered a new category that the 
EPA must list under CAA section 111(b)(1)(A). As a result, this 
proposal does not list a new category under section 111(a)(1)(A), nor 
does this proposal revise either of the two source categories--steam-
generating boilers and combustion turbines--that the EPA has already 
listed under that provision. Thus, the EPA would not be required to 
make a finding that the combined category causes or contributes 
significantly to air pollution which may reasonably be anticipated to 
endanger public health or welfare.
    In addition, the EPA is proposing to create a new subpart UUUU and 
to include all GHG emission guidelines for the affected sources--
utility boilers and IGCC units as well as natural gas-fired stationary 
combustion turbines--in that newly created subpart. We believe that 
combining the emission guidelines for affected sources into a new 
subpart UUUU is appropriate because the emission guidelines the EPA is 
establishing do not vary by type of source. Accordingly, the EPA is not 
proposing to codify any of the requirements of this rulemaking in 
subparts Da or KKKK.

VI. Building Blocks for Setting State Goals and the Best System of 
Emission Reduction

A. Introduction

    Based on the experiences of states and the industry and the EPA's 
outreach with stakeholders as described above, the EPA has identified 
multiple measures currently in use for achieving CO2 
emission reductions from existing fossil fuel-fired EGUs. For purposes 
of determining the ``best system of emission reduction . . . adequately 
demonstrated'' (BSER) and developing state emission performance goals, 
we have screened the measures and have found that they support two 
alternative formulations for the BSER. We are grouping the measures 
that we are proposing to consider further at this time into four 
categories, which we call ``building blocks.'' We provide an overview 
of these building blocks in Section VI.B and more detailed discussion 
of each block in Section VI.C. In Section VI.D we discuss possible 
combinations of the building blocks, and in Section VI.E, we explain 
why as a legal matter all four building blocks, taken together, support 
the BSER, which in turn serves as the basis for the standards of 
performance that the states must include in their state plans, as CAA 
section 111(d) requires.
    As discussed in Section III of this preamble, we are mindful of 
numerous and varied stakeholder concerns, including the need to achieve 
meaningful CO2 emission reductions at the affected 
facilities and to recognize and take advantage of the progress already 
made by existing programs. Like stakeholders, we are attentive to the 
need to maintain electricity system reliability and to minimize adverse 
impacts on electricity and fuel prices and on assets that have already 
been improved by installation of controls for other kinds of pollution. 
Many of these considerations align with our approach to determining the 
BSER, as discussed more in Section VII, and we consider several of 
these to be key principles in this application. As discussed in 
Sections VII and VIII, we acknowledge and appreciate the advantages of 
allowing and promoting flexibility for states in crafting their 
programs. We recognize the knowledge that states have about their 
specific situations and their ability to evaluate and leverage existing 
and new capacity and programs to ultimately reduce EGU CO2 
emissions.
    Similarly, we recognize and appreciate that states operate with 
differing circumstances and policy preferences. For example, states 
have differing access to specific fuel types, and the variety of types 
of EGUs operating in different states is broad and significant. States 
are part of assorted EGU dispatch systems and vary in the amounts of 
electricity that they import and export. For these reasons, we also 
recognize and appreciate the value in allowing and promoting multi-
state reduction strategies. Some states already participate in a multi-
state program that reduces CO2 emissions, the RGGI, and we 
have noted the success of that program for those states.

[[Page 34856]]

    Another key consideration in determining the BSER, as discussed 
more in the following sections, is the relationship between the timing 
of measures and their effectiveness in limiting emissions. For example, 
actions that can occur in the near term, such as improvements to 
individual EGU heat rates, may fail to achieve the cumulative emission 
reductions that sustained implementation of other actions, such as 
demand-side energy efficiency programs, may achieve over time.

B. Building Blocks for the Best System of Emission Reduction

    This subsection summarizes the EPA's analytic approach to 
determining the best system of emission reduction (BSER) for 
CO2 emissions from existing EGUs. Later subsections discuss 
particular measures and how they form the basis of the BSER.\92\
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    \92\ The EPA is aware of the potential that one or more 
facilities involved in programs mentioned or relied on in this 
proposal may have received some form of assistance under the Energy 
Policy Act of 2005 (EPAct). Section 402 (i) of the EPAct (codified 
at 42 U.S.C. section 15962(i)) states:
    ``No technology, or level of emission reduction, solely by 
reason of the use of the technology, or the achievement of the 
emission reduction, by 1 or more facilities receiving assistance 
under this Act, shall be considered to be--(1) adequately 
demonstrated for purposes of section 111 of the Clean Air Act (42 
U.S.C. 7411)[.]''
    In a February 26, 2014 Notice of Data Availability, the EPA 
proposed to give this provision its natural meaning: the term 
``solely'' modifies all of the provisions, so that any ``adequately 
demonstrated'' finding by the EPA could not be based solely upon 
technology, level of emission reduction, or achievement of the 
emission reduction by a facility (or facilities) receiving 
assistance. The EPA proposes the same interpretation here. The EPA 
further believes that its proposed determination of the ``best 
system of emission reduction . . . adequately demonstrated'' does 
not depend exclusively on technology, level of emission reduction, 
or achievement of emission reduction from facilities receiving EPAct 
assistance, given the myriad number of technologies and emission 
performance on which that proposed determination is based.
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1. Overview of Approach
    In considering the appropriate scope of the proposed BSER, the EPA 
evaluated three basic groupings of strategies for reducing 
CO2 emission from EGUs: (i) Reductions achievable through 
improvements in individual EGUs' emission rates (referred to throughout 
this preamble as ``building block 1''); (ii) EGU CO2 
emissions reductions achievable through re-dispatch from affected steam 
EGUs to affected NGCC units (``building block 2''); and (iii) EGU 
CO2 emissions reductions achievable by meeting demand for 
electricity or electricity services through expanded use of low- or 
zero-carbon generating capacity (``building block 3'') and through 
expanded use of demand-side energy efficiency (``building block 4''). 
While the first grouping plays the same role in each of our two 
formulations of the BSER, the second and third groupings play different 
roles: In the first formulation they constitute components of the BSER, 
and in the second formulation they serve as the basis for why a 
component of that formulation of the BSER--reduced utilization of the 
higher-emitting affected EGUs--is adequately demonstrated.
    As described in the remainder of this section, the EPA concluded 
that while certain strategies within the first grouping clearly should 
be part of the BSER, it was not appropriate to limit consideration of 
the BSER to this first grouping, for several reasons. First, we 
determined that some strategies available in the other two groupings 
can support reduced CO2 emissions from the fossil fuel-fired 
EGUs by significant amounts and at lower costs than some of the 
strategies in the first grouping. Second, we observed that strategies 
in all three groupings were already being pursued by states and sources 
taking advantage of the integrated nature of the electricity system, at 
least in part for the purpose of reducing CO2 emissions. 
Third, we were concerned that if measures from the first grouping that 
improve heat rates at coal-fired steam EGUs were implemented in 
isolation, without additional measures that encourage substitution of 
less carbon-intensive ways of providing electricity services for more 
carbon-intensive generation, the resulting increased efficiency of 
coal-fired steam units would provide incentives to operate those EGUs 
more, leading to smaller overall reductions in CO2 
emissions.\93\ These factors reinforced the appropriateness of our 
considering strategies from all three groupings for purposes of 
determining the BSER.
---------------------------------------------------------------------------

    \93\ Elsewhere in the preamble we refer to the potential for 
efficiency improvements to lead to increased competitiveness and 
therefore increased utilization as a ``rebound effect.''
---------------------------------------------------------------------------

2. CO2 Reductions Achievable Through Improvements in 
Individual EGUs' Emission Rates
    The first grouping of CO2 emission reduction options 
that the EPA evaluated as potential options for the BSER consists of 
measures that can reduce individual EGUs' CO2 emission rates 
(i.e., the amount of CO2 emitted per unit of electricity 
\94\ output). These measures included improving the efficiency with 
which EGUs convert fuel heat input to electricity output (i.e., heat 
rate improvements), applying carbon capture and storage (CCS) 
technology, and substituting lower-carbon fuels such as natural gas for 
higher-carbon fuels such as coal (i.e., natural gas co-firing or 
conversion).
---------------------------------------------------------------------------

    \94\ For simplicity, throughout this preamble we generally refer 
to the energy output produced by EGUs as electricity, recognizing 
that some EGUs produce a portion of their energy output in other 
forms, such as steam for heating or process uses. The discussion 
here applies to both EGUs that produce only electricity and EGUs 
that produce a combination of electricity and other energy output.
---------------------------------------------------------------------------

    Our assessment of heat rate improvements showed that these measures 
would achieve CO2 emission reductions at low costs, although 
compared to other measures, the available reductions were relatively 
limited in quantity.\95\ Specifically, our analysis indicated that 
average CO2 emission reductions of 1.3 to 6.7 percent could 
be achieved by coal-fired steam EGUs through adoption of best 
practices, and that additional average reductions of up to four percent 
could be achieved through equipment upgrades.\96\ Heat rate 
improvements pay for themselves at least in part through reductions in 
fuel costs, generally making this a relatively inexpensive approach for 
reducing CO2 emissions. We estimated that CO2 
reductions of between four and six percent from overall heat rate 
improvements could be achieved on average across the nation's fleet of 
coal-fired steam EGUs for net costs in a range of $6 to $12 per metric 
ton.\97\
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    \95\ The EPA assessed opportunities to achieve CO2 
reductions through heat rate improvements at both coal-fired steam 
EGUs and non-coal-fired fossil fuel-fired EGUs, such as oil/gas-
fired steam EGUs and NGCC units. At this time we are proposing that 
the basis for supporting the BSER should include heat rate 
improvements only at coal-fired steam EGUs, but we are inviting 
comment on including heat rate improvements at other EGU types. See 
Section VI.C.5 for further discussion of our assessment of heat rate 
opportunities for non-coal-fired EGUs.
    \96\ These estimated ranges are averages applicable to the fleet 
of coal-fired steam EGUs as a whole. Potential improvements at 
individual EGUs could be higher or lower.
    \97\ As noted above, in the absence of other kinds of 
CO2 emission reduction measures, the emission reductions 
achievable through heat rate improvements could be offset to some 
extent by increased utilization of EGUs making the improvements (a 
``rebound effect''). See Section VI.C.1 below for further 
discussion.
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    The EPA also examined application of CCS technology at existing 
EGUs. CCS offers the technical potential for CO2 emission 
reductions of over 90 percent, or smaller percentages in partial 
applications. In the recently proposed Carbon Pollution Standards for 
new fossil fuel-fired EGUs (79 FR 1430), we found that partial CCS was 
adequately demonstrated for new fossil fuel-fired steam EGUs and 
integrated gasification

[[Page 34857]]

combined cycle (IGCC) units. We also found that for these new units the 
costs were not unreasonable, either for individual units or on a 
national basis, and we proposed to find that application of partial CCS 
is the BSER. However, application of CCS at existing units would entail 
additional considerations beyond those at issue for new units. 
Specifically, the cost of integrating a retrofit CCS system into an 
existing facility would be expected to be substantial, and some 
existing EGUs might have space limitations and thus might not be able 
to accommodate the expansion needed to install CCS. Further, the 
aggregated costs of applying CCS as a component of the BSER for the 
large number of existing fossil fuel-fired steam EGUs would be 
substantial and would be expected to affect the cost and potentially 
the supply of electricity on a national basis. For these reasons, 
although some individual facilities may find implementation of CCS to 
be a viable CO2 mitigation option in their particular 
circumstances,\98\ the EPA is not proposing and does not expect to 
finalize CCS as a component of the BSER for existing EGUs in this 
rulemaking.\99\ Nevertheless, CCS would be available to states and 
sources as a compliance option.
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    \98\ CCS already has been or is being implemented at some 
existing EGUs, as noted in the discussion of CCS later in the 
preamble.
    \99\ As noted later in this preamble, we are nevertheless 
seeking comment on the extent to which existing EGUs could implement 
CCS in order to improve our understanding.
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    Natural gas co-firing or conversion at coal-fired steam EGUs offers 
greater potential CO2 emission reductions than heat rate 
improvements, but at a higher cost (although less than the cost of 
applying CCS technology). Because natural gas contains less carbon than 
an energy-equivalent quantity of coal, converting a coal-fired steam 
EGU to burn only natural gas would reduce the unit's CO2 
emissions by approximately 40 percent. The CO2 reductions 
are generally proportional to the amount of gas substituted for coal, 
so if an EGU continued to burn mostly coal while co-firing natural gas 
as, for example, 10 percent of the EGU's total heat input, the 
CO2 emission reductions would be approximately four percent. 
The EPA determined that the most significant cost associated with 
natural gas conversion or co-firing is likely to be the incremental 
cost of natural gas relative to the cost of coal. Using Energy 
Information Administration (EIA) fuel price projections, we estimated 
that the CO2 reductions achieved through natural gas 
conversion or co-firing at an average coal-fired steam EGU would have 
costs ranging from approximately $83 to $150 per metric ton.\100\ Thus, 
although there have been past instances where coal-fired steam EGUs 
have been converted to natural gas, and we expect some additional 
future conversions where circumstances at individual EGUs make the 
option particularly attractive, for the industry as a whole we would 
expect that other approaches could reduce CO2 emissions from 
existing EGUs at lower cost. However, gas conversion or co-firing would 
be available to states and sources as a compliance option, and, as 
noted later in the preamble, we are seeking comment on whether this 
option should be considered part of the BSER.
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    \100\ The lower end of the range is for conversion to 100 
percent natural gas, which would allow EGUs to eliminate certain 
fixed operating and maintenance costs associated with coal use but 
not natural gas use. See Section VI.C.5.a below for further 
discussion.
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3. CO2 Emission Reductions Achievable Through Re-Dispatch 
From Steam EGUs to NGCC Units
    The second grouping of CO2 emission reduction options 
evaluated by the EPA in the BSER analysis involves reducing emissions 
by shifting generation among affected EGUs. An obvious alternative to 
substituting natural gas for coal at individual steam EGUs through 
conversion or co-firing is instead to use natural gas to generate 
electricity at a different affected EGU with a better heat rate--
notably a natural gas combined cycle (NGCC) unit--and to substitute 
that electricity for electricity from the coal-fired steam EGU, thus 
resulting in lower emissions from the coal-fired steam EGU and lower 
emissions from the set of affected EGUs overall.\101\ The electricity 
system is physically interconnected or networked and operated on an 
integrated basis across large regions. System operators routinely 
increase or decrease the electricity output of individual EGUs to 
respond to changes in electricity demand, equipment availability, and 
relative operating costs (or bid prices) of individual EGUs while 
observing reliability-related constraints. It has long been common 
industry practice for system operators to choose from among multiple 
EGUs when deciding which EGU to ``dispatch'' to generate the next 
increment of electricity needed to meet demand. Thus, the well-
established practices of the industry support our evaluation of ``re-
dispatch'' of generation from steam EGUs to NGCC units as a potential 
component of the basis for the BSER to reduce CO2 emissions 
from existing EGUs.
---------------------------------------------------------------------------

    \101\ Strategies in this grouping also include shifting 
generation from steam EGUs burning oil or natural gas to more 
efficient NGCC units.
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    NGCC units can produce as much as 46 percent more electricity from 
a given quantity of natural gas than steam EGUs,\102\ making the re-
dispatch approach a significantly less expensive way to reduce 
CO2 emissions than conversion or co-firing of coal-fired 
steam EGUs to burn natural gas. For example, using the same EIA fuel 
cost projections as were used above to estimate the costs of natural 
gas conversion or co-firing, we estimated that the cost of 
CO2 reductions achievable by substituting electricity from 
an existing NGCC unit for electricity from an average coal-fired steam 
EGU would be approximately $30 per metric ton.\103\
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    \102\ This estimate assumes an average heat rate of 10,434 Btu/
kWh for coal fossil fuel-fired steam units between 400 and 600 MW 
and 7,130 Btu/kWh for NGCC units between 400 and 600 MW. See 
NEEDSv.5.13 at http://www.epa.gov/powersectormodeling/BaseCasev513.html.
    \103\ See Section VI.C.2 below for further discussion.
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    Our analysis indicated that the potential CO2 reductions 
available through re-dispatch from steam EGUs to NGCC units are 
substantial. As of 2012, there was approximately 245 GW of NGCC 
capacity in the United States, 196 GW of which was placed in service 
between 2000 and 2012.\104\ In 2012, the average utilization rate of 
U.S. NGCC capacity was 46 percent, well below the utilization rates the 
units are capable of achieving. In 2012 approximately 10 percent of 
NGCC plants operated at annual utilization rates of 70 percent or 
higher, and 19 percent of NGCC units operated at utilization rates of 
at least 70 percent over the summer season. Average reported 
availability generally exceeds 85 percent. We recognize that the 
ability to increase NGCC utilization rates may also be affected by 
infrastructure and system considerations, such as limits on the ability 
of the natural gas industry to produce and deliver the increased 
quantities of natural gas, the ability of steam EGUs to reduce 
generation while remaining ready to supply electricity when needed in 
peak demand hours, and the ability of the electric transmission system 
to accommodate the changed geographic pattern of generation. However, 
these considerations have not limited past rapid increases in NGCC 
generation levels, as indicated by a 20 percent increase in natural gas 
consumption for

[[Page 34858]]

electricity generation from 2011 to 2012.\105\ Further, we have taken 
these considerations into account, and the proposal's compliance 
schedule provides flexibility and time for investment in additional 
natural gas and electric industry infrastructure if needed.
---------------------------------------------------------------------------

    \104\ EIA Form 860, available at http://www.eia.gov/electricity/data/eia860. In comparison, in 2012 there was 336 GW of coal steam 
capacity, of which 22 GW was placed in service between 2000 and 
2012. Id.
    \105\ EIA Form 923, available at http://www.eia.gov/electricity/data/eia923/.
---------------------------------------------------------------------------

    As discussed below in Section VI.C.2, the data and considerations 
cited above support our assessment that an average NGCC utilization 
rate in a range of 65 to 75 percent is a reasonable target for the 
amount of additional NGCC generation that could be substituted for 
higher carbon generation from steam EGUs as part of the BSER.\106\ If 
re-dispatch consistent with a target average NGCC utilization rate of 
70 percent had been achieved in 2012, the combined CO2 
emissions of steam EGUs and NGCCs would have been reduced by 
approximately 13 percent.
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    \106\ Substitution would only occur to the extent that there is 
both NGCC capacity whose generation could be increased and steam 
EGUs whose generation could be decreased.
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    Finally, we also note that mechanisms for encouraging re-dispatch 
as a CO2 reduction measure have already been developed and 
applied in the industry. Under both RGGI and California's Global 
Warming Solutions Act, shifting generation from more carbon-intensive 
EGUs to less carbon-intensive EGUs is a way to facilitate compliance 
with regulatory requirements. In both cases, the industry has 
demonstrated the ability to respond to the regulatory requirements of 
these state programs.
4. CO2 Emission Reductions Achievable Through Other Actions 
Underway in the Industry
    The third grouping of CO2 emission reduction options the 
EPA evaluated in the BSER analysis encompasses other measures already 
used in the industry and not included in the first two groupings. From 
our evaluation of re-dispatch as an option for reducing CO2 
emissions, it was apparent that relevant factors for consideration 
include the integrated nature of the electricity system and the fact 
that particular measures capable of reducing CO2 emissions 
at EGUs were already being used and would continue to be used 
throughout the industry, either for the purpose of compliance with 
CO2 emission reduction requirements or to serve other 
purposes and policy goals. That observation led us to consider what 
other potential actions and options the industry was already using that 
had resulted in or could result in, or support, the reduction of 
CO2 emissions at EGUs. Again, we observed many such 
instances, some taking place incidental to the routine operation of the 
electricity system and others taking place in response to specific 
state initiatives to reduce CO2 emissions from the power 
sector. We concluded that there are two principal types of such 
potential options for measures that support CO2 emission 
reductions at EGUs affected under this proposal: Ongoing development 
and use of low- and zero-carbon generating capacity, and ongoing 
development and application of demand-side energy efficiency measures.
    Low-and zero-carbon generating capacity provides electricity that 
can be substituted for generation from more carbon-intensive EGUs. More 
than half the states already have established some form of state-level 
renewable energy requirements, with targets calling on average for 
almost 20 percent of 2020 generation to be supplied from renewable 
sources. The EPA is unaware of analogous state policies to support 
development of new nuclear units, but 30 states already have nuclear 
EGUs (with five units under construction) and the generation from these 
units is currently helping to avoid CO2 emissions from 
fossil fuel-fired EGUs. Policies that encourage development of 
renewable energy capacity and discourage premature retirement of 
nuclear capacity could be useful elements of CO2 reduction 
strategies and are consistent with current industry behavior. Costs of 
CO2 reductions achievable through these policies have been 
estimated in a range from $10 to $40 per metric ton.\107\
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    \107\ See Section VI.C.3 below for further discussion.
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    Demand-side energy efficiency programs produce electricity-
dependent services with less electricity, and thereby support reduced 
generation from existing fossil fuel-fired EGUs by reducing the demand 
for that generation. Reduced generation results in lower CO2 
emissions. More than 40 states already have established some form of 
demand-side energy efficiency polices, and individual states have 
avoided up to 13 percent of their electricity demand. Again, policies 
that encourage demand-side energy efficiency could be useful elements 
of CO2 reduction strategies and are consistent with current 
industry behavior. Using conservatively high estimates of the costs of 
demand-side energy efficiency, the EPA estimates that the costs of 
CO2 emission reductions achievable consistent with such 
policies would be in a range of $16 to $24 per metric ton.\108\
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    \108\ See Section VI.C.4 below for further discussion.
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5. Summary of Building Blocks for the Best System of Emission Reduction
    Based on the analytic approach summarized above, the EPA has 
identified the following four principal categories--``building 
blocks''--of measures that provide the foundation of our BSER 
determination for CO2 emissions from existing EGUs:
    1. Reducing the carbon intensity of generation at individual 
affected EGUs through heat rate improvements.
    2. Reducing emissions from the most carbon-intensive affected EGUs 
in the amount that results from substituting generation at those EGUs 
with generation from less carbon-intensive affected EGUs (including 
NGCC units under construction).
    3. Reducing emissions from affected EGUs in the amount that results 
from substituting generation at those EGUs with expanded low- or zero-
carbon generation.
    4. Reducing emissions from affected EGUs in the amount that results 
from the use of demand-side energy efficiency that reduces the amount 
of generation required.
    Since they either result in improved operating efficiency or 
support reductions in mass emissions at existing EGUs, each of the four 
building blocks represents a demonstrated basis for reducing 
CO2 emissions from affected EGUs that is already being 
pursued in the power sector. In the next subsection, we discuss each of 
the building blocks at length. Our approach for applying the building 
blocks to each state's circumstances in order to develop state goals is 
described in Section VII of this preamble.

C. Detailed Discussion of Building Blocks and Other Options Considered

    In this subsection we discuss each of the building blocks in turn. 
For each building block, we provide our proposed assessment of the 
technical potential of the building block and the reasonableness of its 
costs within the context of the BSER determination, and we describe how 
we developed the data inputs used in the computations of the proposed 
state goals described in Section VII.C and the alternate goals offered 
for comment in Section VII.E. We also discuss certain measures that we 
are not proposing to consider as part of the best system of emission 
reduction. Additional detail is provided

[[Page 34859]]

in the Greenhouse Gas Abatement Measures TSD.
    It is worth noting that although the discussion below necessarily 
addresses the building blocks individually, states are not required to 
pursue plans involving any given building block or to do so at any 
particular level of stringency. Rather, states have flexibility to 
establish plans to meet their state emission limitations using their 
own preferred combinations of efficacious measures applied to the 
extent determined appropriate by the states. The EPA expects that 
states and affected EGUs are unlikely to limit themselves to the 
measures in any single building block, but instead are likely to pursue 
portfolios of measures from a combination of the actions encompassed in 
the building blocks. In developing the data inputs to be used in 
computing state goals, the EPA has estimated reasonable rather than 
maximum possible implementation levels for each building block in order 
to establish overall state goals that are achievable while allowing 
states to take advantage of the flexibility to pursue some building 
blocks more extensively, and others less extensively, than is reflected 
in the goal computations, according to each state's needs and 
preferences.
1. Building Block 1--Heat Rate Improvements
    The first category of approaches to reducing CO2 
emissions at affected fossil fuel-fired EGUs consists of measures that 
reduce the carbon intensity of generation at individual coal-fired 
steam EGUs \109\ by improving heat rate. Heat rate improvements are 
changes that increase the efficiency with which an EGU converts fuel 
energy to electric energy (and useful thermal energy in the case of 
units that cogenerate steam for process use as well as electricity), 
thereby reducing the amount of fuel needed to produce the same amount 
of electricity and lowering the amount of CO2 produced as a 
byproduct of fuel combustion. Heat rate improvements yield important 
benefits to affected sources by reducing their fuel costs.
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    \109\ A ``steam EGU'' is an EGU that combusts fuel in a boiler 
and uses the combustion heat to create steam which is then used to 
drive a steam turbine that drives a generator to create electricity. 
In contrast, a ``combined cycle EGU'' combusts fuel in a combustion 
turbine that directly drives a generator, and the waste heat is then 
used to create steam which is used to drive a steam turbine that 
drives a generator to create more electricity. Steam EGUs can 
combust a wide variety of fuels including coal and natural gas. 
Combined cycle EGUs are more efficient at converting fuel energy to 
electric energy but are limited to gaseous or liquid fuels, most 
commonly natural gas or distillate oil. Almost all existing coal-
fired EGUs are steam EGUs (the exceptions are integrated 
gasification combined cycle (IGCC) units where coal is processed to 
create a gaseous fuel that is then combusted in a combined cycle 
unit).
---------------------------------------------------------------------------

    The EPA is aware of the potential for ``rebound effects'' from 
improvements in heat rates at individual EGUs. In this context, a 
rebound effect would occur where, because of an improvement in its heat 
rate, an EGU experiences a reduction in variable operating costs that 
makes the EGU more competitive relative to other EGUs and consequently 
raises the EGU's generation output. The increase in the EGU's 
CO2 emissions associated with the increase in generation 
output would offset the reduction in the EGU's CO2 emissions 
caused by the decrease in its heat rate and rate of CO2 
emissions per unit of generation output. The extent of the offset would 
depend on the extent to which the EGU's generation output increased (as 
well as the CO2 emission rates of the EGUs whose generation 
was displaced). The EPA considers the rebound effect to be a potential 
concern if heat rate improvements were the only approaches being 
considered for the BSER, but believes that the effect can be addressed 
by establishing the BSER as a combination of approaches that includes 
not only heat rate improvements but also approaches that will encourage 
reductions in electricity demand or increases in generation from lower- 
or zero-emitting EGUs. The topic of potential rebound effects is 
discussed further in Sections VI.D and VI.E below. For purposes of the 
remainder of this subsection, no rebound effect is assumed.
    Although heat rate improvements have the potential to reduce 
CO2 emissions from all types of affected EGUs, the EPA's 
analysis indicates the potential is significantly greater for coal-
fired steam EGUs than for other EGUs, and for purposes of determining 
the best system of emission reduction at this time, the EPA is 
conservatively proposing to base its estimate of CO2 
emission reductions from heat rate improvements on coal-fired steam 
EGUs only.\110\ The remainder of this subsection focuses on the EPA's 
analysis of potential heat rate improvements from coal-fired steam 
EGUs. Our analysis of potential heat rate improvements from other types 
of affected EGUs is addressed in Section VI.C.5 below.
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    \110\ As noted in Section VI.C.5.d below, we are taking comment 
on including heat rate improvement opportunities at other EGU types 
in the basis for supporting the BSER. Also, for compliance purposes 
states and EGUs would be able to rely on CO2 emission 
reductions achieved through heat rate improvements at other types of 
EGUs.
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a. Ability of Heat Rate Improvements To Reduce CO2 Emissions
    The heat rate of an EGU is the amount of fuel energy input needed 
(Btu, higher heating value basis) to produce 1 kWh of net electrical 
energy output (and useful thermal energy in the case of cogeneration 
units).\111\ The current weighted-average annual heat rate of U.S. 
coal-fired EGUs in the range of 400 to 600 MW is approximately 10,434 
Btu per net kWh.\112\ Because an EGU's CO2 emissions are 
driven primarily by the amount of fuel consumed, at any fossil fuel-
fired EGU there is a strong correlation between potential heat rate 
improvements and potential reductions in carbon-intensity.\113\
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    \111\ Heat rate can also be expressed on a gross basis--i.e., 
fuel input per kWh of gross electricity generated--instead of a net 
basis--i.e., fuel input per kWh of net electricity sent to the grid. 
The difference between gross and net electricity is the amount of 
electricity used at the plant to operate components such as pumps, 
fans, motors, and pollution control devices.
    \112\ See NEEDSv.5.13 at http://www.epa.gov/powersectormodeling/BaseCasev513.html.
    \113\ A small portion of some fossil fuel-fired EGU's 
CO2 emissions may come from sources other than fuel, such 
as limestone or other carbonates used to capture sulfur dioxide 
(SO2) and/or hydrogen chloride (HCl) in a scrubber or dry 
injection system. However, CO2 emissions from these 
reagents will also tend to be reduced by heat rate improvements, 
because reagent usage, and the associated CO2 emissions, 
will decrease when the amount of fuel used decreases.
---------------------------------------------------------------------------

    Several studies have examined the opportunities to employ heat rate 
improvements as a means of reducing CO2 emissions from coal-
fired power plants.\114\ Among these, a 2009 study by the engineering 
firm Sargent & Lundy used bottom-up engineering approaches evaluating 
potential heat rate improvements from specific best practices and 
equipment upgrades, including upgrades to boilers, steam turbines, and 
control systems. Based on this study, the EPA believes that 
implementation of all identified best practices and equipment upgrades 
at a facility could provide total heat rate improvements in a range of 
approximately 4 to 12 percent. (We recognize that individual EGUs would 
only be able to implement the best practices or upgrades that were 
applicable to their specific designs or fuel types and that had not 
already been implemented.)
---------------------------------------------------------------------------

    \114\ See chapter 2 of the GHG Abatement Measures TSD for 
details.
---------------------------------------------------------------------------

    In addition to the Sargent & Lundy study, which looked generically 
at the types of improvements that can be made at specific types of 
EGUs, historical heat rate data also provides a basis for

[[Page 34860]]

discerning the existence and possible magnitude of potential heat rate 
improvements. Many EGUs regularly report to both the EPA and the U.S. 
Department of Energy's Energy Information Administration (EIA) 
CO2 emissions and generation data, from which heat input and 
heat rate data can be computed. We have reviewed these data and have 
identified several ``data apparent'' instances where an EGU's heat rate 
experienced a substantial improvement in a short time--presumably 
because of equipment upgrades installed at that point in time--that was 
then sustained. These heat rate improvements ranged from 3 to 8 
percent. In combination with bottom-up engineering analysis and the 
further, more detailed EPA analysis of hourly data summarized below, 
the individual EGU heat rate histories provide a strong basis for 
considering heat rate improvement as a meaningful potential approach to 
reducing the carbon intensity of generation at individual affected 
fossil fuel-fired EGUs.
b. Amounts of Heat Rate Improvements
    In order to estimate the technical potential of heat rate 
improvement opportunities at existing fossil fuel-fired EGUs suggested 
by the discussion above, the EPA pursued two principal areas of 
analysis. The first area concerned the heat rate improvements that 
could be achieved by reducing heat rate variability at individual coal-
fired EGUs through adoption of best practices for operation and 
maintenance. The second area concerned heat rate improvement 
opportunities that could be achieved through further equipment 
upgrades. Both analyses are summarized below along with our 
conclusions, and are discussed in greater detail in the GHG Abatement 
Measures TSD.
    For the best practices analysis, the EPA worked with the hourly 
data reported to the EPA by affected EGUs subject to the monitoring and 
reporting requirements of 40 CFR Part 75. The reported data include 
hourly heat input and, for most reporting EGUs, hourly gross 
generation, making it possible to compute hourly gross heat rates. We 
used the hourly data to assess variability in the hourly gross heat 
rates of approximately 900 individual coal-fired steam EGUs over the 
period from 2002 to 2012. Specifically, the EPA evaluated the 
consistency with which individual EGUs maintained their hourly heat 
rates over time. We expected that a certain degree of short-term heat 
rate variability was caused by factors beyond operators' control, 
notably variation in hourly ambient temperature and hourly load, and 
preliminary analysis confirmed our expectation. We therefore controlled 
for variation in those factors by grouping the observed hourly heat 
rate data for each EGU into subsets corresponding to ranges of hourly 
ambient temperatures and hourly load levels.\115\ We believe that the 
amount of residual variability within each data subset is an indication 
of the degree of technical potential to improve the consistency with 
which optimal heat rate performance is achieved by adopting operating 
and maintenance best practices. For example, optimal heat rate 
performance could be achieved with greater consistency through 
practices such as turning off unneeded pumps at reduced loads, 
installation of digital control systems, more frequent tuning of 
existing control systems, or earlier like-kind replacement of worn 
existing components. (Upgrades to existing equipment are considered 
below.) By applying best practices to their operating and maintenance 
procedures, owners and operators of EGUs could reduce heat rate 
variability relative to average heat rates and, because the deviations 
generally result in performance worse than the optimal heat rates, 
improve the EGUs' average heat rates. Assuming that between 10 percent 
and 50 percent of the deviation from top decile performance in each 
subset of hourly heat rate observations within defined ranges of 
temperature and load could be eliminated through adoption of best 
practices, the result is a corresponding estimated range of 1.3 percent 
to 6.7 percent technical potential for improvement in the average heat 
rate of the entire fleet of coal-fired EGUs.\116\ Based on this 
analysis, we believe a reasonable estimate for purposes of developing 
state-specific goals is that affected coal-fired steam EGUs on average 
could achieve a four percent improvement in heat rate through adoption 
of best practices to reduce hourly heat rate variability. This estimate 
corresponds to the elimination, on average across the fleet of affected 
EGUs, of 30 percent of the deviation from top-decile performance in the 
hourly heat rate for each EGU not attributable to hourly temperature 
and load variation. We also solicit comment on the use of estimates up 
to six percent, reflecting elimination on average of 50 percent of the 
deviation from top-decile performance.
---------------------------------------------------------------------------

    \115\ Temperature data are from the National Oceanic and 
Atmospheric Administration's Integrated Surface Data, http://www.ncdc.noaa.gov/data-access/land-based-station-data/land-based-datasets/integrated-surface-database-isd. Electrical generation data 
are from the EPA's Air Markets Program Data, http://ampd.epa.gov/ampd/.
    \116\ We examined whether the potential for heat rate 
improvement varied based on EGU characteristics such as capacity, 
boiler type, and location, and found no meaningful differences.
---------------------------------------------------------------------------

    For the equipment upgrade analysis, we evaluated potential 
opportunities to improve heat rates at affected EGUs through specific 
upgrades identified in the 2009 Sargent & Lundy study. In that study, 
Sargent & Lundy estimated ranges of potential heat rate improvement 
achievable through a variety of equipment upgrades. We screened the 
upgrades from the study to identify what we consider to be a reasonable 
subset of equipment upgrades that would generally be beyond the scope 
of investments we would expect to be made for purposes of achieving the 
best-practices heat rate improvements discussed above. Based on the 
average of the study's ranges of potential heat rate improvements from 
the various upgrades in this subset, implementation of the full subset 
of appropriate opportunities at a single EGU could be expected to 
result in an aggregate heat rate improvement of approximately four 
percent (incremental to the improvement achievable from adoption of 
best practices). However, we recognize that this total may overstate 
the average equipment upgrade opportunity across all EGUs because some 
EGUs may have already implemented some of these upgrades. We therefore 
propose to use as a data input for purposes of developing state goals 
an estimate that, on average across the fleet of affected EGUs, only 
half of the full equipment upgrade opportunity just described remains--
i.e., that for the fleet of affected EGUs as a whole, the technical 
potential for heat rate improvements from equipment upgrades 
incremental to the best-practices opportunity is on average two percent 
rather than four percent. We solicit comment on increasing this figure 
up to four percent.
    Some of the measures available to EGUs for reducing their carbon 
intensity affect net heat rates rather than gross heat rates. Various 
EGU components such as pumps, fans, motors, and pollution control 
devices use electricity, a factor that is not accounted for in gross 
heat rates (that is, fuel used per unit of gross energy output) but is 
accounted for in net heat rates (that is, fuel used per unit of net 
energy output sent to the electric grid or used for thermal purposes). 
The electricity used by these components, referred to as auxiliary or 
parasitic load, may represent from 4 to 12 percent of gross generation 
at a coal-fired steam EGU.\117\ The analysis of

[[Page 34861]]

technical potential to reduce heat rate variability discussed above was 
based on gross heat rate data. Like gross heat rate, parasitic load can 
be addressed both through adoption of best practices and through 
equipment upgrades, and some measures undertaken at EGUs may affect 
parasitic load as well as gross heat rate. Because the hourly 
generation data reported to the EPA represent gross generation, we have 
less data available to directly analyze potential net heat rate 
improvements than gross heat rate improvements. We have therefore not 
included any separate estimate of parasitic load reductions achievable 
through best practices in our goal-setting data inputs. However, these 
opportunities would be available as a mechanism for reducing carbon-
intensity at affected EGUs and thus provide more flexibility and 
opportunities for sources to improve their heat rates at reasonable 
costs.\118\
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    \117\ Electric Power Research Institute 2011 Technical Report--
Program on Technology Innovation: Electricity Use in the Electric 
Sector (Opportunities to Enhance Electric Energy Efficiency in the 
Production and Delivery of Electricity).
    \118\ As proposed, the state-specific goals are expressed in the 
form of CO2 emissions per net MWh, and reporting 
requirements for sources would be in the same form, allowing 
parasitic load reductions to contribute to improved measured heat 
rates. If goals and reporting requirements were changed to a gross 
MWh basis in the final rule, accounting for parasitic load 
reductions as a source of CO2 reductions would require 
additional procedures.
---------------------------------------------------------------------------

    The total of the estimated potential heat rate improvements from 
adoption of best practices to reduce heat rate variability and 
implementation of equipment upgrades as discussed above is six percent. 
This total is used as the data input for heat rate improvements in the 
computation of proposed state goals discussed in Section VII.C below. 
Because of the close relationship between an EGU's fuel consumption and 
its CO2 emissions, a six percent heat rate improvement would 
be associated with a reduction in CO2 emissions of 
approximately six percent. We believe that this represents a reasonable 
estimate of the technical potential for CO2 emission 
reductions that would be achievable from affected coal-fired steam 
EGUs, on average, through heat rate improvements as an element of the 
best system of emission reduction.
    For purposes of developing the alternate set of goals on which we 
are taking comment, as described in Section VII.E below, we have used a 
more conservative estimate of a four percent heat rate improvement from 
affected coal-fired EGUs on average. This level of improvement would be 
consistent with those EGUs on average implementing best practices to 
reduce heat rate variability without making further equipment upgrades, 
or would be consistent with those EGUs on average implementing both 
best practices and equipment upgrades, but to a lesser degree than we 
have projected as being achievable for purposes of our proposal. We 
view the four percent estimate as a reasonable minimum estimate of the 
technical potential for heat rate improvement on average across 
affected coal-fired steam EGUs.
c. Costs of Heat Rate Improvements
    By definition, any heat rate improvement made for the purpose of 
reducing CO2 emissions will also reduce the amount of fuel 
the EGU consumes to produce its electricity output. The cost 
attributable to CO2 emission reductions therefore would be 
the net cost to achieve the heat rate improvement after any savings 
from reduced fuel expense. As summarized below, we estimate that, on 
average, the savings in fuel cost associated with a six percent heat 
rate improvement would be sufficient to cover much of the associated 
costs, with the result that the net costs of heat rate improvements 
associated with reducing CO2 emissions from affected EGUs 
are relatively low.
    The EPA's most detailed estimates of the average costs required to 
achieve the full range of heat rate improvements come from the 2009 
Sargent & Lundy study discussed above. Based on the study, the EPA 
estimated that for a range of heat rate improvements from 415 to 1205 
Btus per kWh, corresponding to percentage heat rate improvements of 4 
to 12 percent for a typical coal-fired EGU, the required capital costs 
would range from $40 to $150 per kW. To correspond to the average heat 
rate improvement of six percent that we have estimated to be achievable 
through the combination of best practices and equipment upgrades, we 
have estimated an average cost of $100 per kW, slightly above the 
midpoint of the Sargent & Lundy study's range. At an estimated annual 
capital charge rate of 14.3 percent, the carrying cost of an estimated 
$100 per kW investment would be $14.30 per kW-year. For a coal-fired 
EGU with a heat rate of 10,450 Btu per kWh, a utilization rate of 78 
percent, and a coal price of $2.62 per MMBtu, a six percent heat rate 
improvement would produce fuel cost savings of approximately $11.20 per 
kW-year,\119\ leaving approximately $3.10 per kW-year of carrying cost 
not recovered through fuel cost savings. At an average CO2 
emission rate of 0.976 metric tons per MWh, the same six percent heat 
rate improvement would reduce CO2 emissions by 0.40 metric 
tons per kW-year.\120\ Thus, the average cost of CO2 
reductions from heat rate improvements would be approximately $7.75 per 
metric ton of CO2 ($3.10/0.40). If the average heat rate 
improvement achievable for the $100 per kW investment were only four 
percent, consistent with the heat rate improvement estimate in the 
alternate goals on which we seek comment, the average cost of 
CO2 reductions would be $11.63 per metric ton.\121\ On the 
other hand, if an average heat rate improvement of four percent could 
be achieved for an average investment of $50 per kW, reflecting an 
assumption that the first improvements pursued would be the least 
expensive ones, the average cost of CO2 reductions would 
fall to $5.81 per metric ton.\122\
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    \119\ 10,450 Btu/kWh * 8760 hours/year * 78% utilization * $2.62 
per MMBtu * 6% improvement * 0.000001 MMBtu/Btu = $11.2 per kW-year. 
Data inputs for average coal-fired EGU heat rate, average coal-fired 
EGU utilization, and average coal price are from the IPM 5.13 base 
case for 2020.
    \120\ 8760 hours/year * 78% utilization * 0.976 metric tons/Mwh 
* 6% improvement * 0.001 MW/kW = 0.40 metric tons of CO2 
per kW-year. The estimated average coal-fired EGU CO2 
emission rate per MWh is from the IPM 5.13 base case for 2020.
    \121\ $7.75 per metric ton of CO2 * 6%/4% = $11.63 
per metric ton of CO2.
    \122\ $11.63 per metric ton of CO2 * $50/$100 = $5.81 
per metric ton of CO2.
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    The EPA recognizes that the simplified cost analysis just described 
will represent the costs for some EGUs better than others because of 
differences in EGUs' individual circumstances. We further recognize 
that reductions in the utilization rates of coal-fired EGUs anticipated 
from other components proposed for inclusion in the best system of 
emission reduction would tend to reduce the fuel savings associated 
with heat rate improvements, thereby raising the effective cost of 
achieving the CO2 emission reductions from the heat rate 
improvements. Nevertheless, we still expect that the majority of the 
investment required to capture the technical potential for 
CO2 emission reductions from heat rate improvements would be 
offset by fuel savings, and that the net costs of heat rate 
improvements as an approach to reducing CO2 emissions from 
existing fossil fuel-fired EGUs are reasonable.
    Based on the analyses of technical potential and cost summarized 
above, we propose to find that a six percent reduction in the 
CO2 emission rate of the coal-fired EGUs in a state, on 
average, is a reasonable estimate of the amount of heat rate 
improvement that can be implemented at a reasonable cost.\123\
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    \123\ We note that although we expect that heat rate 
improvements are also available from other fossil fuel-fired EGUs, 
we have conservatively not included CO2 emission rate 
reductions for those EGUs in the state goals. However, as discussed 
in Section VI.C.5.d below, we are requesting comment on this aspect 
of the proposal. Further, states and sources would be free to use 
heat rate improvements at those other units to help reach the state 
goals.

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[[Page 34862]]

    We invite comment on all aspects of our analyses and findings 
related to heat rate improvements, both as summarized here and as 
further discussed in the Greenhouse Gas Abatement Measures TSD. As 
noted earlier, we specifically request comment on increasing the 
estimates of the amounts of heat rate improvement achievable through 
adoption of best practices for operation and maintenance and through 
equipment upgrades up to six percent and four percent, respectively, 
representing a total potential improvement of up to ten percent, 
particularly in light of the reasonable cost of heat rate improvements. 
We also solicit comment on the quantitative impacts on the net heat 
rates of coal-fired steam EGUs of operation at loads less than the 
rated maximum unit loads.
2. Building Block 2--Dispatch Changes Among Affected EGUs
    The second element of the foundation for the EPA's BSER 
determination for reducing CO2 emissions at affected fossil 
fuel-fired EGUs goes to the achievement of reductions in mass emissions 
at certain affected EGUs--in particular, fossil fuel-fired steam EGUs--
and entails an analysis of the extent to which generation at the most 
carbon-intensive affected EGUs--again, in particular, fossil fuel-fired 
steam EGUs--can be replaced with generation at less carbon-intensive 
affected fossil fuel-fired EGUs--in particular, NGCC units that were in 
operation or had commenced construction as of January 8, 2014, and are 
therefore affected units for purposes of this rule.
a. Ability of Re-Dispatch To Reduce CO2 Emissions
    The nation's EGUs are interconnected by transmission grids 
extending over large regions. EGU owners and grid operators, subject to 
various reliability and operational constraints, use the flexibility 
provided by these interconnections to prioritize among available EGUs 
when deciding which units should be called upon (i.e., ``dispatched'') 
to increase or decrease generation in order to meet electricity demand 
at any point in time. Recognizing that increments of generation are to 
some extent interchangeable, dispatch decisions are based on 
electricity demand at a given point in time, the variable costs of 
available generating resources, and system constraints. This system of 
security-constrained economic dispatch assures reliable and affordable 
electricity. Electricity demand varies across geography and time in 
response to numerous conditions, such that EGU owners and grid 
operators are constantly responding to changes in demand and ``re-
dispatching'' to meet demand in the most reliable and cost-effective 
manner possible. Since the enactment and implementation of Title IV of 
the CAA Amendments of 1990, in regions where EGUs are subject to 
market-based programs to limit emissions of pollutants such as 
SO2 and NOX, the costs of emission allowances 
have been factored directly into those EGUs' variable costs, like the 
variable costs of operating pollution control devices, and have thereby 
been accounted for in least-cost economic dispatch decisions by grid 
operators. Similarly, operators of EGUs subject to CO2 
emissions limits in RGGI now include the cost of RGGI CO2 
allowances in those EGUs' variable costs,\124\ creating economic 
incentives to replace generation at higher-emitting EGUs with 
generation from lower-emitting sources to reduce CO2 
emissions at the former through the process of least-cost economic 
dispatch. As an alternate mechanism, permitting authorities can impose 
limits on utilization or CO2 emissions at higher-emitting 
EGUs, in which case grid operators and other market participants would 
use the integrated electricity system to find other ways to meet the 
demand for electricity services, either through demand-side energy 
efficiency or through increased generation from lower-emitting EGUs. In 
either case, whether implemented through economic mechanisms or permit 
limitations, reducing emissions at high carbon-intensity EGUs is 
technically feasible and can reduce overall power sector CO2 
emissions because generation at such EGUs can be replaced by generation 
at less carbon-intensive EGUs.
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    \124\ The PJM market monitor publishes breakdowns of wholesale 
energy prices, including a CO2 emission allowance cost 
component, based on analysis of the prices bid by the ``marginal'' 
EGUs. See Monitoring Analytics, 2013 State of the Market Report for 
PJM at 103-05, tbls. 3-63 & 3-64 (2014), available at http://www.monitoringanalytics.com/reports/pjm_state_of_the_market/2013.shtml.
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    We have also analyzed potential upstream net methane emissions 
impact from natural gas and coal for the impacts analysis. This 
analysis indicated that any net impacts from methane emissions are 
likely to be small compared to the CO2 emissions reduction 
impacts of shifting power generation from coal-fired steam EGUs to NGCC 
units. Further information on our analysis of upstream impacts can be 
found in Appendix 3A of the RIA.
b. Magnitude of Re-Dispatch
    Having identified replacing generation at higher-emitting EGUs with 
generation at lower-emitting EGUs as a technically feasible 
CO2 emissions reduction strategy, we next address the 
quantity of replacement generation that may be relied upon at 
reasonable costs. The U.S. electric generating fleet includes EGUs 
employing a variety of generating technologies. EGUs using technologies 
with relatively low variable costs, such as nuclear units, are for 
economic reasons generally operated at their maximum output whenever 
they are available. Renewable EGUs such as wind and solar units also 
have low variable costs, but in any event are generally operated when 
wind and sun conditions permit rather than at operators' discretion. In 
contrast, fossil fuel-fired EGUs have higher variable costs and are 
also relatively flexible. Fossil fuel-fired EGUs are therefore 
generally the units that operators use to respond to intra-day and 
intra-week changes in demand. Because of these typical characteristics 
of the various EGU types, the primary re-dispatch opportunities among 
existing units available to EGU owners and grid operators generally 
consist of opportunities to shift generation among various fossil fuel-
fired units, in particular between coal-fired EGUs (as well as oil- and 
gas-fired steam EGUs) and NGCC units. In the shortterm--that is, over 
time intervals shorter than the time required to build a new EGU--
fossil fuel-fired units consequently tend to compete more with one 
another than with nuclear and renewable EGUs. The amount of re-dispatch 
from coal-fired EGUs to NGCC units that takes place as a result of this 
competition is highly relevant to overall power sector GHG emissions, 
because a typical NGCC unit produces less than half as much 
CO2 per MWh of electricity generated as a typical coal-fired 
EGU.
    In order to estimate the potential magnitude of the opportunity to 
reduce power sector CO2 emissions through re-dispatch among 
existing EGUs, the EPA first examined information on the design 
capabilities and availability of NGCC units. This examination showed 
that, although most NGCC units have historically been operated in 
intermediate-duty roles for economic reasons, they are technically 
capable of

[[Page 34863]]

operating in base-load roles at much higher annual utilization rates. 
Average annual availability (that is, the percentage of annual hours 
when an EGU is not in a forced or maintenance outage) for NGCC units in 
the U.S. generally exceeds 85 percent, and can exceed 90 percent for 
some groups.\125\
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    \125\ See, e.g., North American Electric Reliability Corp., 
2008-2012 Generating Unit Statistical Brochure--All Units Reporting, 
http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx; Higher 
Availability of Gas Turbine Combined Cycle, Power Engineering (Feb. 
1, 2011), http://www.power-eng.com/articles/print/volume-115/issue-2/features/higher-availability-of-gas-turbine-combined-cycle.html.
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    We also researched historical data to determine the utilization 
rates that NGCC units have already been demonstrated capable of 
sustaining. Over the last several years, EGU owners and grid operators 
have engaged in considerable re-dispatch among various types of fossil 
fuel-fired units relative to historical dispatch patterns, with NGCC 
units increasing generation and many coal-fired EGUs reducing 
generation. In fact, in April 2012, for the first time ever the total 
quantity of electricity generated nationwide from natural gas was 
approximately equal to the total quantity of electricity generated 
nationwide from coal.\126\ These changes in generation patterns have 
been driven largely by changes over time in the relative prices of 
natural gas and coal, in addition to lower overall demand for 
electricity. Although the relative fuel prices vary by location, as do 
the recent patterns of re-dispatch, this trend holds across broad 
regions of the U.S. In the aggregate, the historical data provide ample 
evidence indicating that, on average, existing NGCC units can achieve 
and sustain utilization rates higher than their present utilization 
rates.
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    \126\ Today in Energy, EIA (June 6, 2012) (http://www.eia.gov/todayinenergy/detail.cfm?id=6990).
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    The experience of relatively heavily used NGCC units provides an 
additional indication of the degree of increase in average NGCC unit 
utilization that is technically feasible. According to the historical 
NGCC unit utilization rate data reported to the EPA, in 2012 roughly 10 
percent of existing NGCC units operated at annual utilization rates of 
70 percent or higher.\127\ In effect, these units were being dispatched 
to provide base-load power. In addition to the 10 percent of NGCC units 
that operated at a 70 percent utilization rate on an annual basis, some 
NGCC units operated at high utilization rates for shorter, but still 
sustained, periods of time in response to high cyclical demand. For 
example, on a seasonal basis, a significant number of NGCC units have 
achieved utilization rates between 50 and 80 percent; over the 2012 
winter season (December 2011-February 2012) and summer season (June-
August 2012), about 16 percent and 19 percent of NGCC units, 
respectively, operated at utilization rates of 70 percent or more 
across these entire seasons.\128\ During the spring and fall periods 
when electricity demand levels are typically lower, these units were 
sometimes idled or operated at much lower capacity factors. 
Nonetheless, the data clearly demonstrate that a substantial number of 
existing NGCC units have proven the ability to sustain 70 percent 
utilization rates for extended periods of time. We view this as strong 
evidence that increasing the utilization rates of existing NGCC units 
to 70 percent, not in every individual instance but on average, as part 
of a comprehensive approach to reducing CO2 emissions from 
existing high carbon-intensity EGUs, would be technically feasible.
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    \127\ The corresponding percentages of NGCC units that in 2012 
operated at annual utilization rates of at least 65 percent and at 
least 75 percent were 16 percent and 6 percent, respectively.
    \128\ Air Markets Program Data (at http://ampd.epa.gov/ampd/).
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    For purposes of establishing state goals, historical (2012) 
electric generation data are used to apply each building block and 
develop each state's goal (expressed as an adjusted CO2 
emission rate in lbs per MWh).\129\ In 2012, total electric generation 
from existing NGCC units was 959 TWh.\130\ After the application of 
NGCC re-dispatch toward a 70 percent target utilization rate, the total 
generation from these existing sources is projected to be 1,390 TWh per 
year. Adding in the NGCC units that had commenced construction before 
January 8, 2014 (and are therefore existing sources for purposes of 
this proposal) but were not yet in operation in 2012 increases the 
projected total generation from the full set of existing NGCC units to 
1,443 TWh per year.
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    \129\ See Section VII for further explanation of how goals were 
computed.
    \130\ For covered sources.
---------------------------------------------------------------------------

    Although producing over 1,400 TWh of generation in 2020 from 
existing NGCC units is not actually required, because states may choose 
other abatement measures to reach the state goals, the EPA nevertheless 
believes that producing this quantity of generation from this set of 
NGCC units is feasible. As a reference point, NGCC generation increased 
by approximately 430 TWh (an 80 percent increase) between 2005 and 
2012. The EPA calculates that NGCC generation in 2020 could increase by 
approximately 50 percent from today's levels. This reflects a smaller 
ramp-up rate in NGCC generation than has been observed from 2005 to 
2012. We also expect an increase in NGCC generation of this amount 
would not impair power system reliability. As we note in the TSD on 
Resource Adequacy and Reliability, the level of potential re-dispatch 
can be accommodated within the flexible compliance requirements of the 
rule. Similar conclusions have been reached in recent studies of the 
potential impact of emission reductions from existing power 
plants.\131\
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    \131\ See Greenhouse Gas Emission Reductions From Existing Power 
Plants: Options to Ensure Electric System Reliability (Analysis 
Group, Inc., May 2014). Also see the Resource Adequacy Technical 
Support Document.
---------------------------------------------------------------------------

    The EPA also examined the technical capability of the natural gas 
supply and delivery system to provide increased quantities of natural 
gas and the capability of the electricity transmission system to 
accommodate shifting generation patterns. For several reasons, we 
conclude that these systems would be capable of supporting the degree 
of increased NGCC utilization needed for states to achieve the proposed 
goals. First, the natural gas pipeline system is already supporting 
national average NGCC utilization rates of 60 percent or higher during 
peak hours, which are the hours when constraints on pipelines or 
electricity transmission networks are most likely to arise. NGCC unit 
utilization rates during the range of peak daytime hours from 10 a.m. 
to 9 p.m. are typically 15 to 20 percentage points above their average 
utilization rates (which have recently been in the range of 40 to 50 
percent).\132\ Fleet-wide combined-cycle average monthly utilization 
rates have reached 65 percent,\133\ showing that the pipeline system 
can currently support these rates for an extended period. If the 
current pipeline and transmission systems allow these utilization rates 
to be achieved in peak hours and for extended periods, it is reasonable 
to expect that similar utilization rates should also be possible in 
other hours when constraints are typically less severe, and be reliably 
sustained for other months of the year. The second consideration 
supporting our view that natural gas and electricity system

[[Page 34864]]

infrastructure would be capable of supporting increased NGCC unit 
utilization rates is the flexibility of the emission guidelines. The 
state goals do not require any particular NGCC unit utilization rate to 
be achieved in any hour or year of the initial plan period. Thus, even 
if isolated natural gas or electricity system constraints were to limit 
NGCC unit utilization rates in certain locations in certain hours, this 
would not prevent an increase in NGCC generation overall across a state 
or broader region and across all hours. The third consideration 
supporting a conclusion regarding the adequacy of the infrastructure is 
that pipeline and transmission planners have repeatedly demonstrated 
the ability to methodically relieve bottlenecks and expand 
capacity.\134\ Natural gas pipeline capacity has regularly been added 
in response to increased gas demand and supply, such as the addition of 
large amounts of new NGCC capacity from 2001 to 2003, or the delivery 
to market of unconventional gas supplies since 2008. These pipeline 
capacity increases have added significant deliverability to the natural 
gas pipeline network to meet the potential demands from increased use 
of existing NGCC units. Over a longer time period, much more 
significant pipeline expansion is possible. In previous studies, when 
the pipeline system was expected to face very large demands for natural 
gas use by electric utilities about ten years ago, increases of up to 
30 percent in total deliverability out of the pipeline system were 
judged to be possible by the pipeline industry.\135\ There have been 
notable pipeline capacity expansions over the past five years, and 
substantial additional pipeline expansions are currently under 
construction.\136\ Similarly, the electric transmission system is 
undergoing substantial expansion.\137\ Further, as discussed below in 
Sections VII.D and VIII of this preamble (on state flexibilities and 
state plans, respectively), we believe the flexible nature of the 
proposed goals provides time for infrastructure improvements to occur 
should they prove necessary in some locations.\138\ Combining these 
factors of currently observed average monthly NGCC utilization rates of 
up to 65 percent, the flexibility of the emission guidelines, and the 
availability of time to address any existing infrastructure 
limitations, it is reasonable to conclude that the natural gas pipeline 
system can reliably deliver sufficient natural gas supplies, and the 
electric transmission system can reliably accommodate changed 
generation patterns, to allow NGCC utilization to increase up to an 
average annual utilization rate of 70 percent.
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    \132\ EIA, Average utilization of the nation's natural gas 
combined-cycle power plant fleet is rising, Today in Energy, July 
9,2011, http://www.eia.gov/todayinenergy/detail.cfm?id=1730#; EIA, 
Today in Energy, Jan. 15, 2014, http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent data).
    \133\ EIA, Electric Power Monthly, February, 2014. Table 6.7.A.
    \134\ See, e.g., EIA, Natural Gas Pipeline Additions in 2011, 
Today in Energy; INGAA Foundation, Pipeline and Storage 
Infrastructure Requirements for a 30 Tcf Market (2004 update); INGAA 
Foundation, North American Midstream Infrastructure Through 2035--A 
Secure Energy Future Report (2011).
    \135\ Pipeline and Storage Infrastructure Requirements for a 30 
Tcf Market, INGAA Foundation, 1999 (Updated July, 2004); U.S. gas 
groups confident of 30-tcf market, Oil and Gas Journal, 1999.
    \136\ For example, between 2010 and April 2014, 118 pipeline 
projects with 44,107 MMcf/day of capacity (4,699 miles of pipe) were 
placed in service, and between April 2014 and 2016 an additional 47 
pipeline projects with 20,505 MMcf/day of capacity (1,567 miles of 
pipe) are scheduled for completion. Energy Information 
Administration, http://www.eia.gov/naturalgas/data.cfm.
    \137\ According to the Edison Electric Institute, member 
companies are planning over 170 projects through 2024, with costs 
totaling approximately $60.6 billion (this is only a portion of the 
total transmission investment anticipated). Approxi- mately 75 
percent of the reported projects (over 13,000 line miles) are high 
voltage (345 kV and higher). http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_Project_lowres_bookmarked.pdf.
    \138\ See Section VII.D and Section VIII below for discussion of 
timing flexibility.
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    We recognize that re-dispatch does contemplate an associated 
increase in natural gas production, consistent with the current trends 
in the natural gas industry. The EPA expects the growth in NGCC 
generation assumed in goal-setting to be feasible and consistent with 
domestic natural supplies. Increases in the natural gas resource base 
have led to fundamental changes in the outlook for natural gas. There 
is general agreement that recoverable natural gas resources will be 
substantially higher for the foreseeable future than previously 
anticipated, exerting downward pressure on natural gas prices. 
According to EIA, proven natural gas reserves have doubled between 2000 
and 2012. Domestic production has increased by 32 percent over that 
same timeframe (from 19.2 TCF in 2000 to 25.3 TCF in 2012). EIA's 
Annual Energy Outlook for 2014 projects that production will further 
increase to 29.1 TCF, as a result of increased supplies and favorable 
market conditions. For comparison, NGCC generation growth of 450 TWh 
(calculated in goal setting) would result in increased gas consumption 
of roughly 3.5 TCF for the electricity sector, which is less than the 
projected increase in natural gas production.
    The EPA notes that the assessments described above regarding the 
ability of the electricity and natural gas industries to achieve the 
levels of performance indicated for building block 2 in the state goal 
computations are supported by analysis that has been conducted using 
the Integrated Planning Model (IPM). IPM is a multi-regional, dynamic, 
deterministic linear programming model of the U.S. electric power 
sector that the EPA has used for over two decades to evaluate the 
economic and emission impacts of prospective environmental policies. To 
fulfill its purpose of producing projections related to the electric 
power sector and its related markets--including least-cost capacity 
expansion and electricity dispatch projections--that reflect industry 
conditions in as realistic a manner as possible, IPM incorporates 
representations of constraints related to fuel supply, transmission, 
and unit dispatch. The model includes a detailed representation of the 
natural gas pipeline network and the capability to project economic 
expansion of the network based on pipeline load factors. At the EGU 
level, IPM includes detailed representations of key operational 
limitations such as turn-down constraints, which are designed to 
account for the cycling capabilities of EGUs to ensure that the model 
properly reflects the distinct operating characteristics of peaking, 
cycling, and base load units.
    As described in more detail below, the EPA used IPM to assess the 
costs of requiring increasing levels of re-dispatch from higher- to 
lower-emitting EGUs, and to that end, the EPA developed a series of 
modeling scenarios that explored shifting generation from existing 
coal-fired EGUs to existing NGCC units on a 1:1 basis within defined 
areas.\139\ By the nature of IPM's design, those scenarios necessarily 
also require compliance with the constraints just described (as 
implemented for any specific scenario). IPM was able to arrive at a 
solution for scenarios reflecting average NGCC utilization rates of 65, 
70, and 75 percent, while observing the market, technical, and 
regulatory constraints embedded in the model. Such a result is 
consistent with the EPA's determination that increasing the utilization 
rates of existing NGCC units to 70 percent, not in every individual 
instance but on average, as part of a comprehensive approach to 
reducing CO2 emissions from existing high carbon-intensity 
EGUs, would be technically feasible.
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    \139\ See Chapter 3 of the Regulatory Impact Analysis for more 
detail.
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c. Cost of Re-Dispatch
    Having established the technical feasibility and quantification of 
replacing incremental generation at

[[Page 34865]]

higher-emitting EGUs with generation at NGCC facilities as a 
CO2 emissions reduction strategy, we next turn to the 
question of cost. The cost of the power sector CO2 emission 
reductions that can be achieved through re-dispatch among existing 
fossil fuel-fired EGUs depends on the relative variable costs of 
electricity production at EGUs with different degrees of carbon 
intensity. These variable costs are driven by the EGUs' respective fuel 
costs and by the efficiencies with which they can convert fuel to 
electricity (i.e., their heat rates). Historically, natural gas has had 
a higher cost per unit of energy content (e.g., MMBtu) than coal in 
most locations, but for NGCC units this disadvantage in fuel cost per 
MMBtu relative to coal-fired EGUs is typically offset in significant 
part, and sometimes completely, by a heat rate advantage.
    The EPA has conducted two sets of extensive analyses to help inform 
the development of the state-specific emission goals described in this 
proposal, including analyses of the opportunity to reduce 
CO2 emissions through re-dispatch. The first set was a 
dispatch-only set that provided a framework for understanding the 
broader economic and emissions implications of shifting generation to 
NGCC units from more carbon-intensive EGUs without consideration of 
emission reduction measures reflected in the other building blocks. The 
second set included additional refinements and more closely reflected 
all the characteristics of the proposed goals that were used as the 
basis for assessing the costs and benefits of the overall 
proposal.\140\ Both sets of analyses were conducted using IPM.
---------------------------------------------------------------------------

    \140\ See Regulatory Impact Analysis for more detail.
---------------------------------------------------------------------------

    The first set--the dispatch-only analyses--explored the magnitude 
and cost of potential opportunities to shift generation from existing 
coal-fired EGUs to existing NGCC units within defined areas. The 
purpose of analyzing these scenarios was to understand and demonstrate 
to what extent existing NGCC units could increase their dispatch at 
reasonable costs and without significant impacts on other economic 
variables such as the prices of natural gas and electricity. To 
evaluate how EGU owners and grid operators could respond to a state 
plan's possible requirements, signals, or incentives to re-dispatch 
from more carbon-intensive to less carbon-intensive EGUs, the EPA 
analyzed a series of scenarios in which the fleet of NGCC units 
nationwide was required, on average, to achieve a specified annual 
utilization rate.\141\ Specifically, the scenarios required average 
NGCC unit utilization rates of at least 65, 70, and 75 percent, 
respectively. For each scenario, we identified the set of dispatch 
decisions that would meet electricity demand at the lowest total cost, 
subject to all other specified operating and reliability constraints 
for the scenario, including the specified average NGCC unit utilization 
rate. Further, we allowed re-dispatch to occur exclusively within a 
region's existing fleet.\142\
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    \141\ The utilization rate constraint applied on average to all 
NGCC units nationwide and did not apply to individual NGCC units or 
to the fleets of NGCC units within individual states.
    \142\ To best reflect the integrated nature of the electric 
power sector, the EPA defined six regions for this analysis, the 
borders of which are informed by North American Electric Reliability 
(NERC) regions and Regional Transmission Organizations (RTOs). See 
Chapter 3 of the Regulatory Impact Analysis for more detail.
---------------------------------------------------------------------------

    The costs and economic impacts of the various scenarios were 
evaluated by comparing the total costs and emissions from each scenario 
to the costs and emissions from a business-as-usual scenario. For the 
scenario reflecting a 70 percent NGCC utilization rate, comparison to 
the business-as-usual case indicates that the average cost of the 
CO2 reductions achieved over the 2020-2029 period was $30 
per metric ton of CO2.\143\ We view these estimated costs as 
reasonable and therefore as supporting the use of a 70 percent 
utilization rate target for purposes of quantifying the emission 
reductions achievable at a reasonable cost through the application of 
the BSER.
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    \143\ The analogous costs for the scenarios with 65 and 75 
percent NGCC utilization rates were $21 and $40 per metric ton of 
CO2, respectively. For further detail on cost 
methodology, data inputs, and results, refer to Chapter 3 of the GHG 
Abatement Measures TSD.
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    However, we also note that the costs just described are higher than 
we would expect to actually occur in real-world compliance with this 
proposal's goals. One reason for this is that the 70 percent 
utilization rate in the scenario exaggerates the stringency with which 
building block 2 is actually reflected in each of the state goals: 
While the goal computation procedure uses 70 percent as a target NGCC 
utilization rate for all states, for only 29 states do the goals 
actually reflect reaching that target NGCC utilization, with the result 
that the average NGCC utilization rate reflected in the computed state 
goals is only 64 percent.\144\ Also, at least some states may be able 
to achieve additional emission reductions through other components of 
the BSER, and those other components may be relatively inexpensive. The 
dispatch-only analyses were focused on evaluating the potential impacts 
of re-dispatch in particular, and as a result, they reflect an 
assumption that even in a state where re-dispatch might be relatively 
expensive compared to other available CO2 emission reduction 
measures that are part of the BSER, the state plan would rely on re-
dispatch to the same extent as the plans of other states. In practice, 
under these circumstances, states would have flexibility to choose 
among alternative CO2 reduction strategies that were part of 
the BSER, instead of relying on re-dispatch to the maximum extent.
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    \144\ For further explanation of the state goal computation 
methodology, see Section VII of the preamble and the Goal 
Computation TSD.
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    The EPA also analyzed dispatch-only scenarios where shifting of 
generation among EGUs was limited by state boundaries. In these 
scenarios with less re-dispatch flexibility, the cost of achieving the 
quantity of CO2 reductions corresponding to a nationwide 
average NGCC unit utilization of 70 percent was $33 per metric ton. 
Combining the results of the modeling with the factors likely to be 
present in the real world reinforces the support we expressed above for 
the 70 percent utilization rate. We remain concerned, however, that 
higher NGCC utilization rates could be harder to sustain and could 
exert further upward pressure on prices.
    We invite comment on whether the regional or state scenarios should 
be given greater weight in establishing the appropriate degree of re-
dispatch to incorporate into the state goals for CO2 
emission reductions, and in assessing costs.
    We also conclude from our analyses that the extent of re-dispatch 
estimated in this building block can be achieved without causing 
significant economic impacts. For example, in both of the 70 percent 
NGCC unit utilization rate scenarios--with re-dispatch limited to 
regional and state boundaries, respectively--delivered natural gas 
prices were projected to increase by an average of no more than ten 
percent over the 2020-2029 period, which is well within the range of 
historical natural gas price variability.\145\ Projected wholesale 
electricity price increases over the same period were less than seven 
percent in both cases, which similarly is well within the range of 
historical electric price variability.\146\

[[Page 34866]]

We view these projected impacts as not unreasonable and as supporting 
use of a 70 percent NGCC utilization rate target for purposes of 
quantifying the emission reductions achievable through application of 
the BSER.
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    \145\ According to EIA data, year-to-year changes in natural gas 
prices at Henry Hub averaged 29.9 percent over the period from 2000 
to 2013.  http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm.
    \146\ For example, year-on-year changes in PJM wholesale 
electricity prices averaged 19.5 percent over the period from 2000 
to 2013. Ventyx Velocity Suite, ISO real-time data for all hours. 
Price variability for other eastern ISO regions (NYISO, ISO-NE., and 
Midcontinent ISO) was similar. Id.
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    However, for the same reasons discussed above with respect to 
estimated costs per ton of CO2, in actual implementation we 
again expect that the economic impacts shown in these scenarios, 
including natural gas price impacts, are likely overstated compared to 
the impacts that would actually occur in real-world compliance with 
this rule's proposed goals. Consistent with this expectation, the 
comprehensive analyses used to assess the compliance costs and benefits 
of this proposal, which reflect a more complete representation of the 
additional flexibility available to states, show significantly smaller 
economic impacts. These analyses are discussed in Section X below.
    Based on the analyses summarized above, the EPA proposes that for 
purposes of establishing state goals, a reasonable estimate regarding 
the degree of mass emission reductions achievable at fossil fuel-fired 
steam EGUs can be determined based on the degree to which electricity 
generation could be shifted from more carbon-intensive EGUs to less 
carbon-intensive EGUs within the state at reasonable cost through re-
dispatch. The increment of emission reductions incorporated in this 
component of our proposed BSER determination is commensurate with an 
annual utilization rate for the state's NGCC units of up to 70 percent, 
on average across all the NGCC units in the state.
    For purposes of the alternative set of goals on which we are 
seeking comment, we have used the less stringent target of a 65 percent 
average utilization rate for NGCC units. In 2012, approximately 16 
percent of existing NGCC plants larger than 25 megawatts had 
utilization rates equal to or higher than this level. Also, as noted 
earlier, average NGCC utilization nationwide is already over 60 percent 
in some peak hours. We therefore view 65 percent as a reasonable lower-
bound estimate of an achievable average NGCC utilization rate, and we 
would expect the costs and economic impacts from re-dispatch associated 
with a 65 percent NGCC utilization target to be lower than the costs 
and impacts associated with the 70 percent utilization target. Our cost 
analysis indicated that CO2 emission reductions consistent 
with a 65 percent average NGCC utilization rate could be achieved at a 
cost of $21 per metric ton.
    As discussed above, in addition to analyzing the impacts of using 
the proposed 70 percent target utilization rate for existing NGCC 
units, the EPA has also performed preliminary analysis of the impacts 
of using a target utilization rate for existing NGCC units of 75 
percent. That analysis showed that CO2 emission reductions 
consistent with a 75 percent target utilization rate could be achieved 
at a cost of $40 per metric ton.\147\ We invite comment on whether we 
should consider options for a target utilization rate for existing NGCC 
units greater than the proposed 70 percent target utilization rate.
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    \147\ For further analysis related to the use of a 75 percent 
target utilization rate for NGCC units, see chapter 3 of the GHG 
Abatement Measures TSD.
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    We invite comment on these proposed findings and on all other 
issues raised by the discussion above and the related portions of the 
Greenhouse Gas Abatement Measures TSD.
3. Building Block 3--Using an Expanded Amount of Less Carbon-Intensive 
Generating Capacity
    The third element of the foundation for the EPA's BSER 
determination for reducing CO2 emissions at affected fossil 
fuel-fired EGUs also goes to the achievement of reductions in mass 
emissions, but in this case the reductions would occur at all affected 
EGUs, and entails an analysis of the extent to which generation at the 
affected EGUs can be replaced by using an expanded amount of lower-
carbon generating capacity to produce replacement generation. Below we 
discuss two types of generating capacity that can play this role: 
Renewable generating capacity and new and preserved nuclear capacity.
a. Renewable Generating Capacity
    Renewable electricity (RE) generating technologies are a well-
established part of the U.S. power sector. In 2012, electricity 
generated from renewable technologies, including conventional 
hydropower, represented 12 percent of total U.S. electricity 
generation, up from 9 percent in 2005. More than half the states have 
established renewable portfolio standards (RPS) that require minimum 
proportions of electricity sales to be supplied with generation from 
renewable generating resources.\148\ Production of this renewable 
generation replaces predominantly fossil fuel-fired generation and 
thereby avoids the CO2 emissions from that replaced 
generation. The EPA believes that renewable electricity generation is a 
proven way to assure reductions of CO2 emissions at affected 
EGUs at a reasonable cost.\149\
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    \148\ Database of State Incentives for Renewables & Efficiency 
(DSIRE), http://www.dsireusa.org/summarymaps/index.cfm?ee=0&RE=0.
    \149\ For discussion of how states and sources might use RE in 
state plans, see Section VIII below.
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1. Proposed Quantification of Renewable Energy Generation
    To estimate the CO2 emission reductions from affected 
EGUs achievable based on increases in renewable generation, the EPA has 
developed a ``best practices'' scenario for renewable energy generation 
based on the RPS requirements already established by a majority of 
states. The EPA views the existing RPS requirements as a reasonable 
foundation upon which to develop such a scenario for two principal 
reasons. First, in establishing the requirements, states have already 
had the opportunity to assess those requirements against a range of 
policy objectives including both feasibility and costs. These prior 
state assessments therefore support the feasibility and cost of the 
best practices scenario as well. Second, renewable resource development 
potential varies by region, and the RPS requirements developed by the 
states necessarily reflect consideration of the states' own respective 
regional contexts.\150\
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    \150\ The EPA recognizes that individual RPS policies vary in 
their specification of where qualifying RE generation must occur. 
However, the EPA believes the regional structure of this estimation 
exercise supports a broad interpretation of RPS requirements across 
states within a region as a proxy for reasonable-cost RE generation 
potential within the same region.
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    The EPA has not assumed any specific type of renewable generating 
technology for the best practices scenario. Also, the scenario is not 
an EPA forecast of renewable capacity development and neither 
establishes RPS requirements that any state must meet nor makes any 
determinations regarding allowable RE compliance measures. Rather, it 
represents a level of renewable resource development for individual 
states--with recognition of regional differences--that we view as 
reasonable and consistent with policies that a majority of states have 
already adopted based on their own policy objectives and assessments of 
feasibility and cost.
    As noted above, renewable resource potential varies regionally. 
This geographic pattern is reflected in the existing RPS requirements 
of the various states. Recognizing this pattern, the EPA has grouped 
the states into six regions for purposes of developing the best

[[Page 34867]]

practices scenario.\151\ By comparing each state to a set of neighbors 
rather than to a single national standard, we are able to take regional 
variation into account while still maintaining a level of rigor for the 
scenario's targets. The regional structure is informed by North 
American Electric Reliability Corporation (NERC) regions and Regional 
Transmission Organizations (RTOs), with adjustments to align regional 
borders with state borders and to group Florida and Texas with 
neighboring states.\152\ This structure accounts for similar power 
system characteristics as well as geographic similarities in RE 
potential. The grouping of states into the six regions is shown in 
Table 5 below.
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    \151\ Given their unique locations, Alaska and Hawaii are not 
grouped with other states into these regions. As a conservative 
approach to estimating RE generation potential in Alaska and Hawaii, 
the EPA has developed RE generation targets for each of those states 
based on the lowest values for the six regions evaluated here.
    \152\ The regions are the same as those used in regional 
modeling of this rule; see the Regulatory Impact Analysis for more 
information on the regional modeling.

                         Table 5--Regions for Development of Best Practices RPS Scenario
----------------------------------------------------------------------------------------------------------------
                         Region                                                   States
----------------------------------------------------------------------------------------------------------------
East Central...........................................  Delaware, District of Columbia*, Maryland, New Jersey,
                                                          Ohio, Pennsylvania, Virginia, West Virginia.
North Central..........................................  Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri,
                                                          North Dakota, South Dakota, Wisconsin.
Northeast..............................................  Connecticut, Maine, Massachusetts, New Hampshire, New
                                                          York, Rhode Island, Vermont*.
South Central..........................................  Arkansas, Kansas, Louisiana, Nebraska, Oklahoma, Texas.
Southeast..............................................  Alabama, Florida, Georgia, Kentucky, Mississippi, North
                                                          Carolina, South Carolina, Tennessee.
West...................................................  Arizona, California, Colorado, Idaho, Montana, Nevada,
                                                          New Mexico, Oregon, Utah, Washington, Wyoming.
----------------------------------------------------------------------------------------------------------------
* Because Vermont and the District of Columbia lack affected sources, no goals are being proposed for these
  jurisdictions.

    The best practices scenario for each state consists of increasing 
annual levels of RE generation estimated based on application of an 
annual RE growth factor to the state's historical RE generation, 
subject to a maximum RE generation target. The annual RE growth factors 
and maximum RE generation targets were developed separately for each of 
the six regions. Our procedure for determining these elements is 
described in the Greenhouse Gas Abatement Measures TSD and summarized 
below.
    The EPA first quantified the amount of renewable generation in 2012 
in each state. The EPA then summed these amounts for all states in each 
region to determine a regional starting level of renewable generation 
prior to implementation of the best practices scenario. Hydropower 
generation is excluded from this existing 2012 generation for purposes 
of quantifying BSER-related RE generation potential because building 
the methodology from a baseline that includes large amounts of existing 
hydropower generation could distort regional targets that are later 
applied to states lacking that existing hydropower capacity. The 
exclusion of pre-existing hydropower generation from the baseline of 
this target-setting framework does not prevent states from considering 
incremental hydropower generation from existing facilities (or later-
built facilities) as an option for compliance with state goals.
    Next, the EPA estimated the aggregate target level of RE generation 
in each of the six regions assuming that all states within each region 
can achieve the RE performance represented by an average of RPS 
requirements in states within that region that have adopted such 
requirements. For this purpose, the EPA averaged the existing RPS 
percentage requirements that will be applicable in 2020 and multiplied 
that average percentage by the total 2012 generation for the region. We 
also computed each state's maximum RE generation target in the best 
practices scenario as its own 2012 generation multiplied by that 
average percentage. (For some states that already have RPS requirements 
in place, these amounts are less than their RPS targets for 2030.)
    For each region we then computed the regional growth factor 
necessary to increase regional RE generation from the regional starting 
level to the regional target through investment in new RE capacity, 
assuming that the new investment begins in 2017, the year following the 
initial state plan submission deadline,\153\ and continues through 
2029. This regional growth factor is the growth factor used for each 
state in that region to develop the best practices scenario.
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    \153\ See Section VIII below for further discussion of timing 
requirements for state plan submittals.
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    Finally, we developed the annual RE generation levels for each 
state. To do this, we applied the appropriate regional growth factor to 
that state's initial RE generation level, starting in 2017, but 
stopping at the point when additional growth would cause total RE 
generation for the state to exceed the state's maximum RE generation 
target. For computation of the proposed state goals discussed in 
Section VII.C below, we used the annual amounts for the years 2020 
through 2029. For computation of the alternate state goals discussed in 
Section VII.E below, on which we are seeking comment, we used the 
annual amounts for the years 2020 through 2024.
    Alaska and Hawaii are treated as separate regions. Their RE targets 
are based on the lowest regional RE target among the continental U.S. 
regions and their growth factors are based upon historical growth rates 
in their own RE generation. We invite comment regarding the treatment 
of Alaska and Hawaii as part of this method.
    For details on the regional targets and growth factors applied, 
please refer to Chapter 4 of the GHG Abatement Measures TSD.
    The cumulative RE amounts for each state, represented as 
percentages of total generation, are shown in Table 6.

[[Page 34868]]

                         Table 6--State RE Generation Levels for State Goal Development
                                     [Percentage of annual generation]\154\
----------------------------------------------------------------------------------------------------------------
                                                          Proposed goals                  Alternate goals
                                       2012      ---------------------------------------------------------------
              State                  (percent)    Interim  level   Final  level   Interim  level   Final  level
                                                   *  (percent)      (percent)     *  (percent)      (percent)
----------------------------------------------------------------------------------------------------------------
Alabama.........................               2               6               9               4               5
Alaska..........................               1               2               2               1               1
Arizona.........................               2               3               4               3               3
Arkansas........................               3               5               7               4               5
California......................              15              20              21              20              21
Colorado........................              12              19              21              17              19
Connecticut.....................               2               5               9               4               5
Delaware........................               2               7              12               4               5
Florida.........................               2               6              10               4               6
Georgia.........................               3               8              10               6               7
Hawaii..........................               9              10              10              10              10
Idaho...........................              16              21              21              21              21
Illinois........................               4               7               9               6               7
Indiana.........................               3               5               7               4               5
Iowa............................              25              15              15              15              15
Kansas..........................              12              19              20              19              20
Kentucky........................               0               1               2               1               1
Louisiana.......................               2               5               7               4               4
Maine...........................              28              25              25              25              25
Maryland........................               2              10              16               6               8
Massachusetts...................               5              15              24              11              13
Michigan........................               3               6               7               5               6
Minnesota.......................              18              15              15              15              15
Mississippi.....................               3               8              10               6               8
Missouri........................               1               2               3               2               2
Montana.........................               5               8              10               6               7
Nebraska........................               4               8              11               6               7
Nevada..........................               8              14              18              12              14
New Hampshire...................               7              19              25              15              19
New Jersey......................               2               8              16               5               7
New Mexico......................              11              18              21              16              18
New York........................               4              11              18               8              10
North Carolina..................               2               7              10               5               6
North Dakota....................              15              15              15              15              15
Ohio............................               1               6              11               4               5
Oklahoma........................              11              19              20              18              20
Oregon..........................              12              19              21              17              19
Pennsylvania....................               2               9              16               5               7
Rhode Island....................               1               4               6               3               3
South Carolina..................               2               7              10               5               6
South Dakota....................              24              15              15              15              15
Tennessee.......................               1               3               6               2               3
Texas...........................               8              16              20              13              15
Utah............................               3               5               7               4               5
Virginia........................               3              12              16               9              12
Washington......................               7              12              15              10              11
West Virginia...................               2               8              14               5               6
Wisconsin.......................               5               8              11               7               8
Wyoming.........................               9              15              19              13              14
----------------------------------------------------------------------------------------------------------------

    The EPA notes that for some states, the RE generation targets 
developed using the proposed approach are less than those states' 
reported RE generation amounts for 2012. We invite comment on whether 
the approach for quantifying the RE generation component of each 
state's goal should be modified to include a floor based on reported 
2012 RE generation in that state.
---------------------------------------------------------------------------

    \154\ Vermont and the District of Columbia are excluded from 
this table because we are not proposing goals for those 
jurisdictions.
---------------------------------------------------------------------------

    This approach to quantification of a state's RE generation target 
does not explicitly account for the amount of fossil fuel-fired 
generation in that state. Without such an accounting, the application 
of this approach could yield, for a given state, an increase in RE 
generation that exceeds the state's reported 2012 fossil fuel-fired 
generation.\155\ The EPA invites comment on whether this approach 
should be modified so that the difference between a state's RE 
generation target and its 2012 level of corresponding RE generation 
does not exceed the state's

[[Page 34869]]

reported 2012 fossil fuel-fired generation.\156\
---------------------------------------------------------------------------

    \155\ In this proposed RE approach, this situation only occurs 
with the RE targets quantified for the state of Washington.
    \156\ For example, for the state of Washington the proposed 
approach yields a final RE generation target of 17.7 TWh, 
representing an increase of 9.5 TWh over Washington's reported 2012 
RE generation (excluding hydropower) of 8.2 TWh. By comparison, 
Washington's 2012 reported fossil fuel-fired generation was 9.4 TWh. 
(The 2012 reported RE and fossil fuel-fired generation amounts for 
all states are included in the Goal Computation TSD.) If the 
limitation described in the text were applied to Washington, the 
state's incremental quantified RE generation would be limited to 9.4 
TWh, with the result that the state's final RE generation target 
would be 17.6 TWh instead of 17.7 TWh.
---------------------------------------------------------------------------

    We note that with the exception of hydropower, the RE generation 
levels represent total amounts of RE generation, rather than 
incremental amounts above a particular baseline level. As a result, 
this RE generation can be supplied by any RE capacity regardless of its 
date of installation. This approach is therefore focused on quantifying 
the fulfillment of each state's potential for the deployment of RE as 
part of BSER using a methodology that does not require discriminating 
between RE capacity that was installed before or after any given date. 
Under this approach, states in a given region where a higher proportion 
of total generation has already been achieved from renewable resources 
are assumed to have less opportunity for deployment of additional 
renewable generation as part of the BSER framework informing state 
goals, in comparison to states in that region where the proportion of 
total generation achieved from renewable resources to date has been 
lower. That being said, the assumptions of RE generation used to 
develop the state goals do not impose any specific RE generation 
requirements on any state; they are only used to inform the 
quantification of state goals to which states may respond with whatever 
emission reduction measures are preferred.
    With regard to hydropower, we seek comment regarding whether to 
include 2012 hydropower generation from each state in that state's 
``best practices'' RE quantified under this approach, and whether and 
how the EPA should consider year-to-year variability in hydropower 
generation if such generation is included in the RE targets quantified 
as part of BSER. Chapter 4 of the GHG Abatement Measures TSD presents 
state RE targets both with and without the inclusion of each state's 
2012 hydropower generation.
2. Cost of CO2 Emission Reductions From RE Generation
    The EPA believes that RE generation at the levels represented in 
the best practices scenario can be achieved at reasonable costs. 
According to an EPA analysis based on EIA levelized costs, the cost to 
reduce emissions through RE ranges from $10 to $40 per metric ton of 
CO2.\157\ Analysis of RE development in response to state 
RPS policies also finds historical and projected costs of RPS-driven RE 
deployment to be modest. One comparative analysis that ``synthesize[d] 
and analyze[d] the results and methodologies of 28 distinct state or 
utility-level RPS cost impact analyses'' projected the median change in 
retail electricity price to be $0.0004 per kilowatt-hour (a 0.7 percent 
increase), the median monthly bill impact to be between $0.13 and 
$0.82, and the median CO2 reduction cost to be $3 per metric 
ton.\158\ This finding has been confirmed with more recent RPS cost 
data, including a report that determined 2010-2012 retail electricity 
price impacts due to state RPS policies to be less than two percent, 
with only two states experiencing price impacts of greater than three 
percent.\159\ Additionally, the National Renewable Energy Laboratory 
has projected low incremental costs for a range of scenarios reflecting 
significant increases in RE penetration, including scenarios that 
increase RE penetration to a range of 30 to 40 percent of national 
generation, levels higher than those projected in our best practices 
scenario.\160\
---------------------------------------------------------------------------

    \157\ This analysis is based upon EIA's AEO 2014 Estimated 
Levelized Costs of Electricity for New Generation Sources, available 
at http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
    \158\ Chen et al., ``Weighing the Costs and Benefits of State 
Renewable Portfolio Standards: A Comparative Analysis of State-Level 
Policy Impact Projections,'' Lawrence Berkeley National Laboratory, 
March 2007, available at http://emp.lbl.gov/publications/weighing-costs-and-benefits-state-renewables-portfolio-standards-comparative-analysis-s.
    \159\ Galen Barbose, ``Renewables Portfolio Standards in the 
United States: A Status Update,'' Lawrence Berkeley National Lab, 
November 2013. Also to be published in Heeter et al., ``Estimating 
the Costs and Benefits of Complying with Renewable Portfolio 
Standards: Reviewing Experience to Date'' [review draft title]. 
UNPUBLISHED. National Renewable Energy Laboratory and Lawrence 
Berkeley National Laboratory.
    \160\ NREL, ``Renewable Electricity Futures Study'', NREL/TP-
6A20-52409, 2012, http://www.nrel.gov/analysis/re_futures/.
---------------------------------------------------------------------------

    While RPS requirements will continue to grow over time, the EPA 
does not expect this anticipated expansion to fall outside the 
historical norms of deployment or to create unusual pressure for cost 
increases. Full compliance with current RPS goals through 2035 would 
require approximately 4 to 4.5 GW of new renewable capacity per year. 
Average deployment of RPS-supported renewable capacity from 2007 to 
2012 exceeded 6 GW per year.\161\ In addition, recent improvements in 
RPS compliance rates indicate to the EPA the reasonableness of current 
RPS growth trajectories. Weighted average compliance rates among all 
states have improved in each of the past three reported years (2008-
2011) from 92.1 percent to 95.2 percent despite a 40 percent increase 
in RPS obligations during this period.\162\
---------------------------------------------------------------------------

    \161\ Galen Barbose, ``Renewables Portfolio Standards in the 
United States: A Status Update,'' Lawrence Berkeley National 
Laboratory, November 2013.
    \162\ http://emp.lbl.gov/rps, retrieved March 2014. The RPS 
compliance measure cited is inclusive of credit multipliers and 
banked RECs utilized for compliance, but excludes alternative 
compliance payments, borrowed RECs, deferred obligations, and excess 
compliance. This estimate does not represent official compliance 
statistics, which vary in methodology by state.
---------------------------------------------------------------------------

    We invite comment on this approach to treatment of renewable 
generating capacity as a basis for the best system of emission 
reduction adequately demonstrated and for quantification of state 
goals.
3. Alternative Approach to Quantification of RE Generation
    Additionally, the EPA is soliciting comment on an alternative 
approach to quantification of renewable generation to support the BSER. 
Unlike the proposed RE scenario described above that relies on a 
regional application of state RPS commitments, the alternative 
methodology relies on a state-by-state assessment of RE technical and 
market potential. The alternative approach is based on two sources of 
information: A metric representing the degree to which the technical 
potential of states to develop RE generation has already been realized, 
and IPM modeling of RE deployment at the state level under a scenario 
that reflects a reduced cost of building new renewable generating 
capacity.
    The metric measuring realization of RE technical potential in a 
state compares each state's existing renewable generation by technology 
type with the technical potential for that technology in that state as 
assessed by the National Renewable Energy Laboratory (NREL).\163\ This 
comparison yields, for each state and for each RE technology, a 
proportion of renewable generation technical potential that has been 
achieved and can be represented as an RE development rate. For example, 
if

[[Page 34870]]

a given state has 500 MWh of solar generation in 2012 while NREL 
assesses that state's solar generation technical potential at 5,000 
MWh/year, then that state's solar RE development rate would be ten 
percent. The EPA then considers the range of RE development rates 
across states in order to define a benchmark RE development rate for 
each technology.
---------------------------------------------------------------------------

    \163\ Lopez et al., NREL, ``U.S. Renewable Energy Technical 
Potentials: A GIS-Based Analysis,'' (July 2012).
---------------------------------------------------------------------------

    While a benchmark RE development rate offers a useful metric to 
quantify the proportion of RE generation that would bring all states up 
to a designated proportion of RE generation that has been achieved in 
practice by certain states to date, such a metric does not explicitly 
take into account the cost that would be faced to reach the benchmark 
RE development rate in each state. In order to take this cost into 
account, for this alternative approach the EPA has paired the benchmark 
RE development rates described above with IPM modeling of RE deployment 
at the state level, based on a scenario reflecting a reduced cost of 
building new renewable generating capacity. The cost reduction for new 
RE generating capacity is intended to represent the avoided cost of 
other actions that could be taken instead to reduce CO2 
emissions from the power sector. In the Alternative RE Approach TSD, 
available in the docket, we show the RE deployment levels modeled using 
a cost reduction of up to $30 per MWh, a level that is consistent with 
the cost range of $10 to $40 per metric ton of avoided CO2 
emissions estimated for the proposed RE scenario described above.\164\
---------------------------------------------------------------------------

    \164\ Additional detail regarding this modeling and approach is 
provided in the Alternative RE Approach TSD.
---------------------------------------------------------------------------

    Under this alternative RE approach, the EPA would quantify RE 
generation for each technology in each state as the lesser of (1) that 
technology's benchmark rate multiplied by the technology's in-state 
technical potential, or (2) the IPM-modeled market potential for that 
specific technology. For example, if the benchmark RE development rate 
for solar generation is determined to be 12 percent, and the 
hypothetical state described above has a solar generation technical 
potential of 5,000 MWh/year, then the benchmark RE development level of 
generation for that state would be 600 MWh/year. If the IPM-modeled 
market potential for solar generation in that state is 750 MWh/year, 
then this approach would quantify solar generation for that state as 
the benchmark RE development level (600 MWh/year) because it is the 
lesser amount of those two measures.
    Having quantified an amount of RE generation from each RE 
technology in each state, the EPA would then determine for each state a 
total level of RE generation that equals the sum of the generation 
quantified for each of the assessed RE technologies in that state. If 
the EPA were to adopt this alternative approach for quantifying RE in 
BSER, these total levels of RE generation for each state would be 
incorporated in state goals in place of the RE generation levels 
quantified using the proposed approach described above. Further 
methodological detail and state-level RE targets for this alternative 
approach are provided in the Alternative RE Approach TSD in the docket.
    We invite comment on this alternative approach to quantification of 
RE generation to support the BSER. We note that the three specific 
requests for comment made above with respect to the proposed 
quantification approach--addressing, first, the possibility of a floor 
based on 2012 RE generation, second, the possibility of a limitation 
based on 2012 fossil fuel-fired generation and, third, the treatment of 
hydropower generation--apply to this alternative approach as well.\165\
---------------------------------------------------------------------------

    \165\ The Alternative RE Approach TSD presents the 
quantification of hydropower generation under the alternative 
approach, as well as the resulting state RE targets both with and 
without hydropower generation included.
---------------------------------------------------------------------------

    Finally, the EPA notes that the alternative RE approach described 
above is one of a number of possible methodologies for using technical 
and economic renewable energy potential to quantify RE generation for 
purposes of state goals. The EPA invites comment on other possible 
techno-economic approaches. For example, a conceptual framework for 
another techno-economic approach is provided in the Alternative RE 
Approach TSD.
b. New and Preserved Nuclear Capacity
    Nuclear generating capacity facilitates CO2 emission 
reductions at fossil fuel-fired EGUs by providing carbon-free 
generation that can replace generation at those EGUs. Because of their 
relatively low variable operating costs, nuclear EGUs that are 
available to operate typically are dispatched before fossil fuel-fired 
EGUs. Increasing the amount of nuclear capacity relative to the amount 
that would otherwise be available to operate is therefore a technically 
viable approach to support reducing CO2 emissions from 
affected fossil fuel-fired EGUs.
1. Proposed Quantification of Nuclear Generation
    One way to increase the amount of available nuclear capacity is to 
build new nuclear EGUs. However, in addition to having low variable 
operating costs, nuclear generating capacity is also relatively 
expensive to build compared to other types of generating capacity, and 
little new nuclear capacity has been constructed in the U.S. in recent 
years; instead, most recent generating capacity additions have 
consisted of NGCC or renewable capacity. Nevertheless, five nuclear 
EGUs at three plants are currently under construction: Watts Bar 2 in 
Tennessee, Vogtle 3-4 in Georgia, and Summer 2-3 in South Carolina. The 
EPA believes that since the decisions to construct these units were 
made prior to this proposal, it is reasonable to view the incremental 
cost associated with the CO2 emission reductions available 
from completion of these units as zero for purposes of setting states' 
CO2 reduction goals (although the EPA acknowledges that the 
planning for those units likely included consideration of the 
possibility of future regulation of CO2 emissions from 
EGUs). Completion of these units therefore represents an opportunity to 
reduce CO2 emissions from affected fossil fuel-fired EGUs at 
a very reasonable cost. For this reason, we are proposing that the 
emission reductions achievable at affected sources based on the 
generation provided at the identified nuclear units currently under 
construction should be factored into the state goals for the respective 
states where these new units are located. However, the EPA also 
realizes that reflecting completion of these units in the goals has a 
significant impact on the calculated goals for the states in which 
these units are located. If one or more of the units were not completed 
as projected, that could have a significant impact on the state's 
ability to meet the goal. We therefore take comment on whether it is 
appropriate to reflect completion of these units in the state goals and 
on alternative ways of considering these units when setting state 
goals.
    Another way to increase the amount of available nuclear capacity is 
to preserve existing nuclear EGUs that might otherwise be retired. The 
EPA is aware of six nuclear EGUs at five plants that have retired or 
whose retirements have been announced since 2012: San Onofre Units 2-3 
in California, Crystal River 3 in Florida, Kewaunee in Wisconsin, 
Vermont Yankee in Vermont, and Oyster Creek in New Jersey. While each 
retirement decision

[[Page 34871]]

is based on the unique circumstances of that individual unit, the EPA 
recognizes that a host of factors--increasing fixed operation and 
maintenance costs, relatively low wholesale electricity prices, and 
additional capital investment associated with ensuring plant security 
and emergency preparedness--have altered the outlook for the U.S. 
nuclear fleet in recent years. Reflecting similar concern for these 
challenges, EIA in its most recent Annual Energy Outlook has projected 
an additional 5.7 GW of capacity reductions to the nuclear fleet. EIA 
describes the projected capacity reductions--which are not tied to the 
projected retirement of any specific unit--as necessary to recognize 
the ``continued economic challenges'' faced by the higher-cost nuclear 
units.\166\ Likewise, without making any judgment about the likelihood 
that any individual EGU will retire, we view this 5.7 GW, which 
comprises an approximately six percent share of nuclear capacity, as a 
reasonable proxy for the amount of nuclear capacity at risk of 
retirement.
---------------------------------------------------------------------------

    \166\ Jeffrey Jones and Michael Leff, EIA, ``Implications of 
accelerated power plant retirements,'' (April 2014).
---------------------------------------------------------------------------

2. Cost of CO2 Emission Reductions From Nuclear Generation
    We have determined that, based on available information regarding 
the cost and performance of the nuclear fleet, preserving the operation 
of at-risk nuclear capacity would likely be capable of achieving 
CO2 reductions from affected EGUs at a reasonable cost. For 
example, retaining the estimated six percent of nuclear capacity that 
is at risk for retirement could support avoiding 200 to 300 million 
metric tons of CO2 over an initial compliance phase-in 
period of ten years.\167\ According to a recent report, nuclear units 
may be experiencing up to a $6/MWh shortfall in covering their 
operating costs with electricity sales.\168\ Assuming that such a 
revenue shortfall is representative of the incentive to retire at-risk 
nuclear capacity, one can estimate the value of offsetting the revenue 
loss at these at-risk nuclear units to be approximately $12 to $17 per 
metric ton of CO2. The EPA views this cost as reasonable. We 
therefore propose that the emission reductions supported by retaining 
in operation six percent of each state's historical nuclear capacity 
should be factored into the state goals for the respective states.\169\
---------------------------------------------------------------------------

    \167\ Assuming replacement power for at-risk nuclear capacity is 
sourced from new NGCC capacity at 800 lbs/MWh or the power system at 
1127 lbs CO2/MWh (average 2020 power sector emissions 
intensity as projected in the EPA's IPM Base Case).
    \168\ ``Nuclear * * * The Middle Age Dilemma?'' Eggers, et al., 
Credit Suisse, February 2013.
    \169\ A state's historical nuclear fleet is defined as all units 
in commercial operation as of May 2014 with no current plans to 
retire.
---------------------------------------------------------------------------

    For purposes of goal computation, generation from under-
construction and preserved nuclear capacity is based on an estimated 90 
percent average utilization rate for U.S. nuclear units, consistent 
with long-term average annual utilization rates observed across the 
nuclear fleet. The methodology for taking this generation into account 
for purposes of setting state emission rate goals is described below in 
Section VII on state goals and in the Goal Computation TSD.
    We invite comment on all aspects of the approach discussed above. 
In addition, we specifically request comment on whether we should 
include in the state goals an estimated amount of additional nuclear 
capacity whose construction is sufficiently likely to merit evaluation 
for potential inclusion in the goal-setting computation. If so, how 
should we do so--for example, according to EGU owners' announcements, 
the issuance of permits, projections of new construction by the EPA or 
another government agency, or commercial projections? What specific 
data sources should we consider for those permits or projections?
4. Building Block 4--Demand-Side Energy Efficiency
    The fourth element of the foundation for the EPA's BSER 
determination for reducing CO2 emissions at affected fossil 
fuel-fired EGUs also supports reduced mass emissions at all affected 
EGUs, and entails an analysis of the extent to which generation 
reductions at the affected EGUs can be supported by reducing the demand 
for generation at those EGUs through measures that reduce the overall 
quantity of generation demanded by end-users.\170\
---------------------------------------------------------------------------

    \170\ Electricity end-users and electricity end-use referred to 
throughout this subsection include the residential, commercial and 
industrial sectors.
---------------------------------------------------------------------------

a. Benefits of Demand-Side Energy Efficiency
    Reducing demand for generation at affected EGUs through policies to 
improve demand-side energy efficiency is a proven basis for reducing 
CO2 emissions at those EGUs. Every state has established 
demand-side energy efficiency policies, and many stakeholders 
emphasized the success of these policies in reducing electricity 
consumption by large amounts. For example, data reported to the U.S. 
Energy Information Administration (EIA) show that in 2012 California 
and Minnesota avoided 12.5 percent and 13.1 percent of their 
electricity demand, respectively, through their demand-side efficiency 
programs.\171\ Additionally, multiple studies have found that 
significant improvements in end-use energy efficiency can be realized 
at less cost than the savings from avoided power system costs.\172\ 
Increased investment in demand-side energy efficiency is being 
supported by efforts at the federal, state, and local levels of 
government as well as corporate efforts. Many stakeholders urged the 
inclusion of demand-side energy efficiency policies as compliance 
options under the CAA section 111(d) guidelines.
---------------------------------------------------------------------------

    \171\ Energy Information Administration Form 861, 2012, 
available at http://www.eia.gov/electricity/data/eia861/.
    \172\ See, e.g., Electric Power Research Institute, U.S. Energy 
Efficiency Potential Through 2035 (Final Report, April 2014); Wang, 
Yu and Marilyn A. Brown, Policy Drivers for Improving Electricity 
End-Use Efficiency in the U.S.: An Economic-Engineering Analysis 
(Energy Efficiency, 2014).
---------------------------------------------------------------------------

    By reducing electricity consumption, energy efficiency avoids 
greenhouse gas emissions associated with electricity generation. 
Because fossil fuel-fired EGUs typically have higher variable costs 
than other EGUs (such as nuclear and renewable EGUs), their generation 
is typically the first to be replaced when demand is reduced. 
Consequently, reductions in the utilization of fossil fuel-fired EGUs 
can be supported by reducing electricity consumption and, by the same 
token, reductions in electricity consumption avoid the CO2 
emissions associated with the avoided generation. In this manner, in 
2011, state demand-side energy efficiency programs are estimated to 
have reduced CO2 emissions by 75 million metric tons.\173\ 
And when integrated into a comprehensive approach for addressing 
CO2 emissions, demand-side energy efficiency improvements 
offer even more potential to improve the carbon profile of the 
electricity supply system. For example, if incentives exist to shift 
generation to lower carbon-intensity EGUs, and those EGUs are fully 
utilized, reducing demand can support further reductions in carbon 
intensity. This potential effect reinforces the appropriateness of 
incorporating demand-side efficiency improvements into a comprehensive 
approach to address power sector CO2 emissions. In addition, 
by supporting reductions in fossil fuel usage at EGUs, demand-side

[[Page 34872]]

energy efficiency supports not only reduced CO2 emissions 
and carbon intensity of the power sector, but also reduced criteria 
pollutant emissions, cooling water intake and discharge, and solid 
waste production associated with fossil fuel combustion. By reducing 
electricity usage significantly, energy efficiency also commonly 
reduces the bills of electricity customers.
---------------------------------------------------------------------------

    \173\ Innovation, Electricity, Efficiency (an Institute of the 
Edison Foundation), Summary of Customer-Funded Electric Efficiency 
Savings, Expenditures, and Budgets (2011-2012) (March 2013), 
available at http://www.edisonfoundation.net/iei/ourwork/Pages/issuebriefs.aspx.
---------------------------------------------------------------------------

b. ``Best Practices'' for Demand-Side Energy Efficiency
    To estimate the potential CO2 reductions at affected 
EGUs that could be supported by implementation of demand-side energy 
efficiency policies as a part of state goals, the EPA developed a 
``best practices'' demand-side energy efficiency scenario. This 
scenario provides an estimate of the potential for sources and states 
to implement policies that increase investment in demand-side energy 
efficiency technologies and practices at reasonable costs. It does not 
represent an EPA forecast of business-as-usual impacts of state energy 
efficiency policies or an EPA estimate of the full potential of end-use 
energy efficiency available to the power system, but rather represents 
a feasible policy scenario showing the reductions in fossil fuel-fired 
electricity generation resulting from accelerated use of energy 
efficiency policies in all states consistent with a level of 
performance that has already been achieved or required by policies 
(e.g., energy efficiency resource standards) of the leading states. The 
data and methodology used to develop the best practices scenario are 
summarized below.
    We have not assumed any particular type of demand-side energy 
efficiency policy. States with leading energy efficiency performance 
have employed a variety of strategies that are implemented by a range 
of entities including investor-owned, municipal and cooperative 
electric utilities as well as state agencies and third-party 
administrators. These include energy efficiency programs,\174\ building 
energy codes, state appliance standards (for appliances without federal 
standards), tax credits, and benchmarking requirements for building 
energy use.\175\ Energy efficiency policies are designed to accelerate 
the deployment of demand-side energy efficiency technologies, 
practices, and measures by addressing market barriers and market 
failures that limit their adoption. Some states have adopted energy 
efficiency resource standards \176\ (EERS) to drive investment in 
energy efficiency programs; some have relied on other strategies; most 
states are using multiple policy approaches. Based on historical data 
on energy efficiency program savings and analysis of the requirements 
of existing state energy efficiency policies, twelve leading states 
have either achieved--or have established requirements that will lead 
them to achieve--annual incremental savings rates of at least 1.5 
percent of the electricity demand that would otherwise have 
occurred.\177\ The 1.5 percent savings rate is inclusive of, not 
additional to, existing state energy efficiency requirements. These 
savings levels are realized exclusively through the adoption and 
implementation of energy efficiency programs. The energy savings data 
underpinning these analyses are derived from energy efficiency program 
reports required by state public utility commissions and other entities 
with a similar oversight role.\178\ These state commissions define and 
oversee the analysis and reporting requirements for energy efficiency 
programs as part of their role of overseeing rates for utility 
customers in their states. One typical requirement is the application 
of recognized evaluation, measurement, and validation (EM&V) protocols 
that specify industry-preferred approaches and methodologies for 
estimating savings from efficiency programs.\179\
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    \174\ Energy efficiency programs are driven by a variety of 
state policies including energy efficiency resource standards, 
requirements to acquire all cost-effective energy efficiency, 
integrated resource planning requirements, and demand-side 
management plans and budgets. Funding for energy efficiency programs 
is provided through a variety of mechanisms as well, including per 
kilowatt-hour surcharges and proceeds from forward capacity market 
and emission allowance auctions. The programs are implemented by a 
range of entities including investor-owned, municipal, and 
cooperative electric utilities, state agencies, and designated 
third-party administrators. All end-use sectors (residential, 
commercial, and industrial) are targeted by energy efficiency 
programs and numerous strategies are employed, including targeted 
rebates for high-efficiency appliances; energy audits with 
recommendations for cost-effective, energy-saving upgrades; and 
processes to certify energy efficiency service providers.
    \175\ See the appendix to the State Plan Considerations TSD for 
descriptions of the full array of demand-side energy efficiency 
policies currently employed by states.
    \176\ EERS establish specific, long-term targets for energy 
savings that utilities or non-utility program administrators must 
meet through customer energy efficiency programs. EERS, as well as 
requirements that utilities acquire all cost-effective energy 
efficiency, have been the most impactful state energy efficiency 
strategies in recent years.
    \177\ The historical data used are reported to the Energy 
Information Administration through Form EIA-861. The analysis and 
summary of state energy efficiency policies is from the American 
Council for an Energy-Efficient Economy (ACEEE), State EERS Activity 
Policy Brief (February 24, 2014). See the Greenhouse Gas Abatement 
Measures TSD for more information.
    \178\ E.g., energy efficiency programs operated by municipal and 
cooperative utilities may report their program results to their 
Boards of Directors rather than to a state utility commission.
    \179\ See the EM&V section of the State Plan TSD for more 
information on EE program evaluation.
---------------------------------------------------------------------------

    While EM&V data reflect documented electricity savings from energy 
efficiency programs, they typically do not account for potential 
electricity savings available from additional state-implemented 
policies for which EM&V protocols are less consistently required or 
applied, such as building energy codes. Thus, we consider the 1.5 
percent annual incremental savings \180\ rate to be a reasonable 
estimate of the energy efficiency policy performance that is already 
achieved or required by leading states and that can be achieved at 
reasonable costs by all states given adequate time. If we were to 
capture the potential for additional policies, such as the adoption and 
enforcement of state or local building energy codes, to contribute 
additional reductions in electricity demand beyond those resulting from 
energy efficiency programs, we could reasonably increase the targeted 
annual incremental savings rate beyond 1.5 percent.
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    \180\ This incremental savings rate and all others discussed in 
this subsection represent net, rather than gross, energy savings. 
Gross savings are the changes in energy use (MWh) that result 
directly from program-related actions taken by program participants, 
regardless of why they participated in a program. Net savings refer 
to the changes in energy use that are directly attributable to a 
particular energy efficiency program after accounting for free-
ridership, spillover, and other factors.
---------------------------------------------------------------------------

    For states where EE program experience is more limited, reaching a 
best-practices level of performance requires undertaking a set of 
activities that takes some time to plan, implement, and evaluate. For 
the best practices scenario, we have therefore estimated that each 
state's annual incremental savings rate increases from its 2012 annual 
saving rate \181\ to a rate of 1.5 percent over a period of years 
starting in 2017. (Thus, the goal for each state differs to reflect the 
assumption that in a state already close to a 1.5 percent annual 
incremental savings rate, energy efficiency programs can be expanded to 
reach that rate sooner than in a state that is further from that rate.) 
The pace at which states are estimated to increase their savings rate 
level is 0.2 percent per year. This rate is consistent with past 
performance and future requirements of leading states.\182\ For states 
already at or above the 1.5 percent

[[Page 34873]]

annual incremental savings rate (based on 2012 reported data), we 
estimate that they would realize a 1.5 percent rate in 2017 and 
maintain that rate through 2029. For all states we assume the initial 
savings rate (the lower of their 2012 value or 1.5 percent) is realized 
in 2017 and increases each year by 0.2 percent until the target rate of 
1.5 percent is achieved \183\ and is then maintained at that level 
through 2029. The savings from energy efficiency programs are 
cumulative, meaning that, in simplified terms, a state in which a 
sustained program is implemented with a 1.5 percent annual incremental 
savings rate could expect cumulative annual savings of approximately 
1.5 percent after the first year, 3.0 percent after the second year, 
4.5 percent after the third year, and so on. Savings from the first 
year would drop off at the end of the average life of the energy 
efficiency program portfolio (typically about ten years). Accordingly, 
we have projected the cumulative annual savings for each state that 
would be achieved for the period 2020 to 2029 based on the state's 
reaching and then sustaining the best practices annual incremental 
savings rate through 2029. These values, for each state and for each 
year (2020-2029), are used in the procedure for computing the state 
goals described in Section VII.C below.
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    \181\ 2012 is the most recent year for energy efficiency program 
incremental savings data reported using EIA Form 861.
    \182\ See the Greenhouse Gas Abatement Measures TSD for more 
information.
    \183\ For example, a state with a reported savings rate of 0.5% 
in 2012 is assumed to realize a 2017 savings rate of 0.5% and their 
savings rates for 2018, 2019, 2020, 2021 and 2022 are calculated to 
be 0.7%, 0.9%, 1.1%, 1.3%, and 1.5%, respectively. By this method, 
all states have reached the 1.5% target rate by 2017 at the earliest 
and by 2025 at the latest.
---------------------------------------------------------------------------

    As discussed in Section VII.E below, the EPA is also taking comment 
on a less stringent alternative for setting state goals. Under this 
alternative, the demand-side energy efficiency requirement uses 1.0 
percent (rather than 1.5 percent) annual incremental savings as 
representative of the best-practices level of performance. In addition, 
the pace at which incremental savings levels are increased from their 
historical levels is relaxed slightly to 0.15 percent per year (rather 
than 0.2 percent). The 1.0 percent rate of savings is a level of 
performance that has been achieved--or that established state 
requirements will cause to be achieved--by 20 states.\184\ As is done 
with the more stringent goal-setting approach for energy efficiency, 
the cumulative percentages for each state are derived and multiplied by 
the state's 2012 historical electricity sales as reflected in the EIA 
detailed state data, in this case for the period from 2020 to 2024.
---------------------------------------------------------------------------

    \184\ See the Greenhouse Gas Abatement Measures TSD for more 
information.
---------------------------------------------------------------------------

    The state-specific cumulative annual electricity saving data inputs 
for both the proposed approach and the less stringent alternative are 
discussed in the Greenhouse Gas Abatement Measures TSD and summarized 
in Table 7.

Table 7--Demand-Side Energy Efficiency State Goal Development: Cumulative Annual Electricity Savings (Percentage
                          of Annual Sales) Resulting From Best Practices Scenario \185\
----------------------------------------------------------------------------------------------------------------
                                                   1.5% Savings target scenario    1.0% Savings target scenario
                      State                      ---------------------------------------------------------------
                                                       2020            2029            2020            2024
----------------------------------------------------------------------------------------------------------------
Alabama.........................................             1.4             9.5             1.1             3.9
Alaska..........................................             1.2             9.5             0.9             3.7
Arizona.........................................             5.2            11.4             3.5             6.0
Arkansas........................................             1.5             9.7             1.2             4.1
California......................................             5.0            11.6             3.6             6.1
Colorado........................................             3.9            11.0             3.3             5.9
Connecticut.....................................             4.7            11.9             3.6             6.3
Delaware........................................             1.1             9.5             0.9             3.6
Florida.........................................             2.0            10.0             1.8             4.7
Georgia.........................................             1.8             9.8             1.5             4.4
Hawaii..........................................             1.3             9.5             1.0             3.8
Idaho...........................................             3.8            11.1             3.5             5.9
Illinois........................................             4.4            11.6             3.5             6.2
Indiana.........................................             3.2            11.1             2.9             5.7
Iowa............................................             4.7            11.7             3.6             6.0
Kansas..........................................             1.2             9.5             0.9             3.7
Kentucky........................................             1.9            10.0             1.6             4.6
Louisiana.......................................             1.1             9.3             0.9             3.6
Maine...........................................             5.4            12.1             3.6             6.3
Maryland........................................             4.2            11.5             3.5             6.1
Massachusetts...................................             4.4            11.8             3.6             6.2
Michigan........................................             4.6            11.8             3.6             6.2
Minnesota.......................................             4.8            11.7             3.6             6.2
Mississippi.....................................             1.4             9.6             1.1             3.9
Missouri........................................             1.6             9.9             1.3             4.2
Montana.........................................             3.4            10.9             3.0             5.7
Nebraska........................................             2.2            10.4             1.9             4.9
Nevada..........................................             3.0            10.7             2.7             5.5
New Hampshire...................................             2.8            11.0             2.6             5.5
New Jersey......................................             1.3             9.6             1.0             3.7
New Mexico......................................             3.1            10.6             2.8             5.5
New York........................................             4.4            11.8             3.5             6.2
North Carolina..................................             2.4            10.3             2.1             5.0
North Dakota....................................             1.4             9.7             1.1             4.0
Ohio............................................             4.2            11.6             3.5             6.1
Oklahoma........................................             1.9            10.0             1.6             4.5
Oregon..........................................             4.7            11.4             3.6             6.1
Pennsylvania....................................             4.7            11.7             3.6             6.2

[[Page 34874]]

 
Rhode Island....................................             3.9            11.6             3.4             6.1
South Carolina..................................             2.3            10.2             2.0             4.9
South Dakota....................................             1.6             9.9             1.3             4.2
Tennessee.......................................             2.2            10.3             1.9             4.9
Texas...........................................             1.8             9.9             1.5             4.4
Utah............................................             3.6            11.0             3.2             5.8
Virginia........................................             1.2             9.3             1.0             3.7
Washington......................................             4.2            11.3             3.5             6.0
West Virginia...................................             1.8            10.1             1.5             4.4
Wisconsin.......................................             4.7            11.8             3.6             6.2
Wyoming.........................................             1.6             9.7             1.3             4.2
----------------------------------------------------------------------------------------------------------------

c. Costs of Demand-Side Energy Efficiency
    The EPA expects implementation of demand-side energy efficiency 
policies as reflected in the best practices scenario to be achievable 
at reasonable costs. The EPA finds support for the reasonableness of 
the costs of this building block from two perspectives. First, the 
specific savings levels represented by this building block were 
developed based upon the experience and success of states in developing 
and implementing energy efficiency policies that they undertake 
primarily for the purpose of providing economic benefits to electricity 
consumers in their state. Secondly, even with notably conservative 
assumptions about the costs of achieving the levels of electricity 
savings associated with this building block, the EPA's analysis of the 
power sector indicates that the costs are reasonable.
    The processes by which states develop funding for energy efficiency 
programs typically require the application of cost-effectiveness tests 
to ensure that adopted program portfolios lead to lower costs than the 
use of generation sources that would otherwise be required to meet the 
associated electricity service demands. Indeed, a major reason for the 
widespread presence and rapid growth of demand-side energy efficiency 
programs is the strong evidence of the reasonableness of their costs 
even before the additional benefit of CO2 reductions is 
considered.\186\ Independent studies have found that end-users' needs 
for energy-dependent services (e.g., heating, cooling, lighting, motor 
output, and information and entertainment services) frequently can be 
satisfied at lower cost by improving the efficiency of electricity 
consumption rather than by increasing the supply of electricity.\187\ 
These factors indicate that the cost of CO2 reductions 
achieved through implementation of demand-side energy efficiency at the 
levels reflected in the best practices scenario are likely to be very 
reasonable, typically resulting in reductions in average electricity 
bills across all end-use sectors.\188\ Because demand-side energy 
efficiency costs are incurred at the time of investment, while the cost 
savings (from lower electricity usage) are realized over the life of 
these investments (typically about 10 years), bill reductions are 
greater in later years, but provide substantial payback over the 
investment period.
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    \185\ Vermont and the District of Columbia are excluded from 
this table because we are not proposing goals for those 
jurisdictions.
    \186\ Some states do include a valuation of CO2 
benefits as part of their evaluations of cost effectiveness.
    \187\ E.g., Electric Power Research Institute, U.S. Energy 
Efficiency Potential Through 2035 (Final Report, April 2014); 
Northwest Power and Conservation Council, Sixth Northwest 
Conservation and Electric Power Plan (Feb. 2010), available at 
http://www.nwcouncil.org/energy/powerplan/6/plan/.
    \188\ As described below and in the Goal Computation TSD, in the 
case of a state that is a net importer of electricity, the proposed 
goal computation procedure includes an adjustment to account for the 
possibility that some of the generation and emissions avoided due to 
the state's demand-side energy efficiency programs may occur at EGUs 
in other states. Given the extremely low cost of CO2 
emission reductions achievable through demand-side energy efficiency 
programs, implementation of such programs is likely to reduce 
CO2 emissions at reasonable cost even for a state whose 
own affected EGUs achieve only part of the CO2 emission 
reduction benefit from the state's demand-side energy efficiency 
efforts.
---------------------------------------------------------------------------

    Another approach to evaluating the reasonableness of the costs 
associated with this building block is to compare the demand-side 
energy efficiency costs to the avoided power system costs as 
represented within the EPA's modeling of the power sector. The costs 
associated with the best practices scenario were estimated based upon a 
synthesis of data and analysis of the factors that impact energy 
efficiency program costs as calculated using an engineering-based, 
bottom-up approach that is standard for state and utility analysis of 
these policies. These factors include the average energy efficiency 
program costs per unit of first-year energy savings ($/MWh), the ratio 
of program to participant costs, and the lifetimes of energy efficiency 
measures across the full portfolio of programs. In addition, the EPA 
has included a cost escalation factor to represent the possibility of 
increased costs associated with higher levels of incremental energy 
savings rates and the national scope of the best practices scenario. 
The EPA has taken a conservative approach to each of these factors, 
selecting values that are at the higher-cost end of reasonable ranges 
of estimated values. The combination of these factors is reflected in 
the value the EPA has derived for the levelized cost per MWh of saved 
energy. This value includes both the program costs paid by utilities 
for implementing energy efficiency programs and the amounts that 
program participants pay for their own energy efficiency improvements 
beyond the program costs. These costs are levelized across the measure 
lifetimes of a full portfolio of energy efficiency programs. This 
analysis provides a levelized cost of saved energy (LCOSE) range of 
$85/MWh to $90/MWh ($2011) over the 2020 to 2030 period. This range of 
LCOSE is notably conservative (leading to higher costs) in comparison 
with most utility and state analysis. For example, a 2014 analysis by 
the American Council for an Energy-Efficient Economy (ACEEE) surveyed 
program and participant cost results across seven states and found a 
comparable LCOSE value of $54/MWh (2011$).\189\
---------------------------------------------------------------------------

    \189\ American Council for an Energy-Efficient Economy (ACEEE), 
The Best Value for America's Energy Dollar: A National Review of the 
Cost of Utility Energy Efficiency Programs (Report No. U1402, March 
2014).

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[[Page 34875]]

    To estimate the reductions in power system costs and CO2 
emissions associated with the best-practices level of demand-side 
energy efficiency described above, the EPA analyzed a scenario 
incorporating the resulting reduction in electricity demand and 
compared the results with the business-as-usual scenario. Both analyses 
were conducted using the Integrated Planning Model (IPM) described 
previously. Combining the resulting power system cost reductions with 
the energy efficiency cost estimates associated with the best practices 
scenario, the EPA derived net cost impacts for 2020, 2025, and 2030. 
Dividing these net cost impacts by the associated CO2 
reductions for each year, the EPA found that the average cost of the 
CO2 reductions achieved ranged from $16 to $24 per metric 
ton of CO2. The EPA views these estimated costs as 
reasonable. Together with the history of demonstrated successful state 
implementation of demand-side energy efficiency programs at reasonable 
costs discussed above, this analysis supports the reasonableness of the 
level of demand-side energy efficiency represented by the best 
practices scenario and, by extension, the reasonableness of the 
emission reductions at affected EGUs that can be achieved consistent 
with achievement of that level of demand-side energy efficiency.
    Further details regarding the data and methodology used to evaluate 
the potential for demand-side energy efficiency programs to substitute 
for generation at affected EGUs and thereby facilitate reductions of 
power sector CO2 emissions at reasonable costs are provided 
in the Greenhouse Gas Abatement Measures TSD. We invite comment on all 
aspects of our data and methodology as discussed above and in the TSD, 
as well as on the level of reductions we propose to define as best 
practices suitable for representation consistent with the best system 
of emission reduction and the level reflected in the less stringent 
scenario. We also specifically invite comment on several issues: (1) 
Increasing the annual incremental savings rate to 2.0 percent and the 
pace of improvement to 0.25 percent per year to reflect an estimate of 
the additional electricity savings achievable from state policies not 
reflected in the 1.5 percent rate and the 0.20 percent per year pace of 
improvement, such as building energy codes and state appliance 
standards, (2) alternative approaches and/or data sources (i.e., other 
than EIA Form 861) for determining each state's current level of annual 
incremental electricity savings, and (3) alternative approaches and/or 
data sources for evaluating costs associated with implementation of 
state demand-side energy efficiency policies.
5. Potential Emission Reduction Measures Not Used To Set Proposed Goals
    There are four additional potential measures for reducing, or 
supporting reduced, GHG emissions from EGUs that the EPA does not 
propose to consider part of the best system of emission reduction 
adequately demonstrated for existing EGUs at this time and therefore 
has not used for goal-setting purposes, but that merit discussion here: 
Fuel switching at individual EGUs, carbon capture and storage (CCS), 
using expanded amounts of less carbon-intensive new NGCC capacity to 
provide replacement generation, and heat rate improvements at affected 
EGUs other than coal-fired steam EGUs.
a. Fuel Switching at Individual Units
    One technically feasible approach for reducing CO2 
emissions per MWh of generation from an EGU designed for coal-fired 
generation is to substitute natural gas for some or all of the coal. 
Most existing coal-fired steam EGU boilers can be modified to switch to 
100 percent gas input or to co-fire gas with coal in any desired 
proportion. For certain individual EGUs, switching to or co-firing with 
gas may be an attractive option for reducing CO2 emissions.
    Changing the type of fuel burned at a steam EGU typically requires 
certain plant modifications (e.g., new burners) and may have some 
negative impact on the net efficiencies of the boiler and the overall 
generation process. If the plant lacks existing gas pipeline 
infrastructure capable of delivering the necessary quantities of 
natural gas to the boiler, installation of a new pipeline lateral would 
also be required.
    The capital costs of plant modifications required to switch a coal-
fired EGU completely to natural gas are roughly $100-300/kW, excluding 
pipeline costs. For plants that require additional pipeline capacity, 
the capital cost of constructing new pipeline laterals is approximately 
$1 million per mile of pipeline built. Offsetting these capital costs, 
conversion to 100 percent gas input would typically reduce the EGU's 
fixed operating and maintenance costs by about 33 percent due mainly to 
certain equipment retirements and a reduction in staffing, while non-
fuel variable costs would be reduced by about 25 percent due to reduced 
maintenance and waste disposal costs. However, in most cases, the most 
significant cost change associated with switching from coal to gas in a 
coal-fired boiler is likely to be the difference in fuel cost. Using 
EIA's projections of future coal and natural gas prices, switching a 
steam EGU's fuel from coal to gas typically would more than double the 
EGU's fuel cost per MWh of generation.
    The CO2 reduction potential of natural gas co-firing or 
conversion is due largely to the different carbon intensities of coal 
and natural gas and is directly related to the proportion of gas 
burned. Greater reductions in the CO2 emission rate are 
achieved at higher proportions of gas usage. For example, at ten 
percent gas co-firing, the net emission rate (e.g., pounds of 
CO2 per net MWh of generation) of a typical steam EGU 
previously burning only coal would decrease by approximately four 
percent. At 100 percent gas burn, the net emission rate of a typical 
steam EGU previously burning only coal would decrease by approximately 
40 percent.
    For a typical base-load coal-fired EGU, and reflecting EIA's 
projected future natural gas and coal prices, the average cost of 
CO2 reductions achieved through gas conversion or co-firing 
ranges from $83 per metric ton to $150 per metric ton. The low end of 
the range of CO2 reduction costs represents a 100 percent 
switch to gas, because in instances where a combination of coal and gas 
is burned, the EGU would continue to bear the fixed costs associated 
with equipment needed for coal combustion, raising the cost per ton of 
CO2 reduced.
    The EPA's economic analysis suggests that there are more cost 
effective opportunities for coal-fired utility boilers to reduce their 
CO2 emissions than through natural gas conversion or co-
firing. As a result, the EPA has not proposed at this time to include 
this option in the BSER and has not incorporated implementation of the 
option into the proposed state goals. However, the EPA believes that 
there are a number of factors that warrant further consideration in 
determining whether the option should be included. First, the EPA is 
aware that a number of utilities have reworked some of their coal-fired 
units to allow for some level of natural gas co-firing (and in some 
cases have converted the units to fire entirely on natural gas). 
Second, the EPA is aware of several possible reasons beyond reduction 
of CO2 emissions that may make natural gas co-firing 
economically attractive in some circumstances. One example is that 
natural gas reburn strategies that involve

[[Page 34876]]

co-firing with 10 to 20 percent natural gas can be an effective control 
strategy for NOX emissions and, thus, can offset operational 
(and in some cases, capital) costs associated with other NOX 
controls such as selective catalytic reduction (SCR) or selective non-
catalytic reduction (SNCR). A second example suggested by some vendors 
is that the capability to burn natural gas in a coal-fired boiler can 
improve economics because it allows the boiler to operate more 
effectively at lower loads. A third example, applicable to units that 
run infrequently but may be needed for reliability purposes, is that 
converting to or co-firing with natural gas may be more economically 
attractive than either installing non-CO2 emission controls 
or taking other measures, such as transmission upgrades, that could 
become necessary if the unit were retired. Finally, beyond the reasons 
just described explaining why EGU owners may find natural gas co-firing 
to be cost-effective, there are also potentially significant health co-
benefits associated with burning natural gas instead of coal.
    We solicit comment on whether natural gas co-firing or conversion 
should be part of the BSER. We also request comment regarding whether, 
and, if so, how, we should consider the co-benefits of natural gas co-
firing in making that determination.
b. Carbon Capture and Storage
    Another possible approach for reducing CO2 emissions 
from existing fossil fuel-fired EGUs is through the application of 
carbon capture and storage \190\ technology (CCS). In the recently 
proposed standards of performance for new fossil fuel-fired EGUs (79 FR 
1430), the EPA proposed to find that the best system of emission 
reduction for new fossil fuel-fired boilers and IGCC units is partial 
application of CCS. In that proposal, the EPA found that, for new 
units, partial CCS has been adequately demonstrated, it is technically 
feasible, it can be implemented at costs that are not unreasonable, it 
provides meaningful emission reductions, and its implementation will 
serve to promote further development and deployment of the technology. 
The EPA also noted in the proposal that most of the relatively few new 
boiler and IGCC EGU projects currently under development are already 
planning to implement CCS, and, as a result, the proposed standard 
would not have a significant impact on nationwide energy prices.
---------------------------------------------------------------------------

    \190\ This is also sometimes referred to as ``carbon capture and 
sequestration.''
---------------------------------------------------------------------------

    In contrast, the EPA did not identify full or partial CCS as the 
BSER for new natural gas-fired stationary combustion turbines, noting 
technical challenges to implementation of CCS at NGCC units as compared 
to implementation at new solid fossil fuel-fired sources. The EPA also 
noted that, because virtually all new fossil fuel-fired power projects 
are projected to use NGCC technology, requiring full or partial CCS 
would have a greater impact on the price of electricity than requiring 
CCS at the few projected coal plants, and the larger number of NGCC 
projects would make a CCS requirement difficult to implement in the 
short term.
    Partial CCS has been demonstrated at existing EGUs. It has been 
demonstrated at a pilot-scale at Southern Company's Plant Barry, it is 
being installed for large-scale demonstration at NRG's W.A. Parish 
facility, and it is expected soon to be applied at a commercial scale 
as a retrofit at SaskPower's Boundary Dam plant in Canada. However, the 
EPA expects that the costs of integrating a retrofit CCS system into an 
existing facility would be substantial. For example, some existing 
sources have a limited footprint and may not have the land available to 
add a CCS system. Moreover, there are a large number of existing 
fossil-fired EGUs. Accordingly, the overall costs of requiring CCS 
would be substantial and would affect the nationwide cost and supply of 
electricity on a national basis.
    For the reasons just described, based on the information available 
at this time, the EPA does not propose to find that CCS is a component 
of the best system of emission reduction for CO2 emissions 
from existing fossil fuel-fired EGUs. The EPA does solicit comment on 
all aspects of applying CCS to existing fossil fuel-fired EGUs (in 
either full or partial configurations), but does not expect to finalize 
CCS as a component of the BSER in this rulemaking. It should be noted, 
however, that in light of the fact that several existing fossil-fired 
EGUs are currently being retrofitted with CCS, the implementation of 
partial CCS may be a viable GHG mitigation option at some facilities, 
and as a result, emission reductions achieved through use of the 
technology could be used to help meet the emission performance level 
required under a state plan.
    Additional discussion can be found in the Greenhouse Gas Abatement 
Measures TSD.
c. New NGCC Capacity
    In Section VI.C.2 above, we discussed the opportunity to reduce 
CO2 emissions by replacing generation at high carbon-
intensity affected EGUs with lower-carbon generation from existing NGCC 
units.\191\ From a technical perspective, the same potential would 
exist to replace high-emitting generation with generation from 
additional NGCC capacity that may be built in the future; the analysis 
above regarding the feasibility of policies to increase utilization 
rates of existing NGCC units on average to 70 percent applies equally 
to new NGCC units.\192\ We view the opportunity to reduce 
CO2 emissions at affected EGUs by means of addition and 
operation of new NGCC capacity as clearly feasible.
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    \191\ For purposes of this proposal, NGCC units that have 
commenced construction as of January 8, 2014 are ``existing'' units.
    \192\ Whether and to what extent adding new NGCC capacity is 
likely to lead to CO2 reductions depends on what 
incentives would exist to operate that new capacity in preference to 
operation of more carbon-intensive existing EGUs. Because the 
proposed state goals also reflect the opportunity to reduce 
utilization of high carbon-intensity EGUs by shifting generation to 
less carbon-intensive EGUs, we believe that in the context of a 
comprehensive state plan, the necessary incentives would likely 
exist, in which case adding new NGCC capacity would tend to reduce 
CO2 emissions.
---------------------------------------------------------------------------

    In addition, we note that our compliance modeling for this proposal 
suggests that the construction and operation of new NGCC capacity will 
be undertaken as method of responding to the proposal's requirements.
    However, compared to the opportunity to reduce CO2 
emissions at affected EGUs by means of re-dispatch to existing NGCC 
capacity, the parallel opportunity involving new NGCC capacity would be 
more costly for several reasons. The first reason is the additional 
cost associated with additional usage of natural gas. As noted in the 
discussion of building block 2 above, the EPA analyzed costs associated 
with several different target utilization rates for existing NGCC units 
and that analysis showed higher costs of CO2 reductions at 
higher target NGCC utilization rates.
    The second reason that emission reductions from the use of new NGCC 
capacity would be more costly is that there would be capital investment 
costs. Some amount of new NGCC capacity (beyond the units that were 
already under construction as of January 8, 2014 and are ``existing'' 
units for purposes of this proposal) would likely be built to meet 
perceived electricity market demand or to replace less economic 
capacity regardless of this proposal. The costs of achieving 
CO2 emission reductions through re-dispatch to these new 
NGCC units and through re-dispatch to existing NGCC units would be 
comparable (ignoring consideration

[[Page 34877]]

of the cost impacts just discussed related to increases in overall gas 
usage). However, in the case of any new NGCC units that would not have 
been built if not for this proposal, and that were built in part for 
the purpose of achieving CO2 reductions at affected EGUs, 
some portion of their construction or fixed operating costs would also 
be attributable to the CO2 reduction opportunity, increasing 
to some extent the cost of the CO2 reductions at affected 
EGUs achieved through re-dispatch to those new NGCC units.
    The third reason relates to the costs of pipeline infrastructure 
expansion, and in particular the unevenly distributed nature of those 
costs. While expanded use of existing NGCC capacity to achieve 
CO2 emission reductions can be expected to rely largely on 
existing pipeline infrastructure with incremental capacity expansions, 
use of new NGCC capacity--if required in all states--could require 
substantially greater pipeline infrastructure investments to serve some 
states than others.
    Taken together, the EPA believes the cost considerations just 
described indicate a higher cost for CO2 reductions 
achievable from re-dispatch to new NGCC capacity than from other 
options, at least for states with limited natural gas pipeline 
infrastructure, and we therefore do not propose to include this option 
in state goals.
    While the EPA is not proposing that new NGCC capacity is part of 
the basis supporting the BSER, we recognize that there are a number of 
new NGCC units being proposed and that many modeling efforts suggest 
that development of new NGCC capacity would likely be used as a 
CO2 emission mitigation strategy. Therefore, we invite 
comment on whether we should consider construction and use of new NGCC 
capacity as part of the basis supporting the BSER. Further, we take 
comment on ways to define appropriate state-level goals based on 
consideration of new NGCC capacity.
d. Assessment of Heat Rate Improvement Opportunities at Oil-Fired Steam 
EGUs, Gas-Fired Steam EGUs, NGCC Units, and Simple-Cycle Combustion 
Turbine Units
    The EPA assessed opportunities to improve heat rates at affected 
EGUs other than coal-fired steam units. This assessment, which is 
documented in a Technical Memorandum included as an appendix to the GHG 
Abatement Measures TSD, considers the potential extent of heat rate 
improvements and CO2 reductions that could be reasonably 
available from oil-fired steam EGUs, gas-fired steam EGUs, NGCC units, 
and simple-cycle combustion turbine units. For these non-coal 
technologies, the total additional potential CO2 reductions 
achievable through heat rate improvements appear relatively small 
compared to the potential CO2 reductions achievable through 
heat rate improvements at coal-fired steam EGUs. For this reason, the 
EPA does not propose to include heat rate improvement opportunities at 
these other fossil fuel-fired units as an element of the BSER for 
CO2 emissions from affected EGUs at this time. However, we 
are aware that the proportion of total generation provided from EGUs 
such as oil-fired steam EGUs or gas-fired steam EGUs varies by 
location, and may be relatively large in geographically isolated areas 
such as islands. We therefore invite comment on whether heat rate 
improvements for some of the EGU types discussed above should be 
identified as a basis for supporting the BSER, with particular 
reference to U.S. territories.
    Finally, the EPA expects that for some individual oil/gas-fired 
steam EGUs and NGCC units attractive heat rate improvement 
opportunities will exist. We note that under the proposed flexible 
approach to state plans described later in this preamble, 
CO2 reductions achieved through such opportunities could be 
used to help meet state goals, regardless of whether these measures are 
used as a basis to support the BSER.

D. Potential Combinations of the Building Blocks as Components of the 
Best System of Emission Reduction

    This subsection summarizes the EPA's examination of combinations of 
the building blocks as components of the BSER, comparing the merits of 
a potential BSER that comprises only building blocks 1 and 2 with the 
merits of a BSER that comprises all four building blocks--the preferred 
option in this proposal. (A more detailed discussion of how we 
evaluated each option against the criteria to be considered for the 
BSER follows in Section VI.E.) \193\
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    \193\ For convenience, the discussion in this Section VI.D is 
based on our proposal to identify the BSER as consisting of the 
building blocks themselves. The points made in this discussion are 
also relevant for our alternative proposal to identify the BSER as 
consisting of building block 1 coupled with reduced utilization of 
the affected EGUs in specified amounts.
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1. Reasons for Considering Combinations of Building Blocks
    As previously described, the building blocks can be summarized as 
follows:
    Building block 1: Reducing the carbon intensity of generation at 
individual affected EGUs through heat rate improvements.
    Building block 2: Reducing emissions from the most carbon-intensive 
affected EGUs in the amount that results from substituting generation 
at those EGUs with generation from less carbon-intensive affected EGUs 
(including NGCC units under construction).
    Building block 3: Reducing emissions from affected EGUs in the 
amount that results from substituting generation at those EGUs with 
expanded low- or zero-carbon generation.
    Building block 4: Reducing emissions from affected EGUs in the 
amount that results from the use of demand-side energy efficiency that 
reduces the amount of generation required.
    The EPA initially considered a BSER comprising only strategies 
within building block 1. As described earlier in Section VI.B, the EPA 
concluded that certain strategies within building block 1--specifically 
heat rate improvements at individual coal-fired steam EGUs--should be a 
component of the BSER determination, as they are technically feasible 
and can be implemented at a reasonable cost. However, the EPA further 
concluded that, while heat rate improvements qualify as a system of 
emission reduction, they are not in themselves the BSER as there are 
additional strategies that can be utilized in combination with building 
block 1 that are technically feasible, can be implemented at reasonable 
cost, and result in greater emission reductions than would be achieved 
through building block 1 strategies alone. The EPA is also concerned 
that if the measures that improve heat rates at coal-fired steam EGUs 
in building block 1 are implemented in isolation, without additional 
measures that reduce overall electricity demand or encourage 
substitution of less carbon-intensive generation for more carbon-
intensive generation, the resulting increased efficiency of coal-fired 
steam units would provide incentives to operate those EGUs more, 
leading to smaller overall reductions in CO2 emissions. 
Further, in listening sessions and other outreach meetings, the EPA 
learned that states and other sources were already implementing and 
pursuing strategies in the other building blocks for the purpose, at 
least in part, of reducing CO2 emissions.
2. A Combination of Building Blocks 1 and 2 as the Best System of 
Emission Reduction
    We considered a BSER that comprises strategies from building blocks 
1 and 2.

[[Page 34878]]

In this system, emission reductions at the most carbon-intensive 
individual affected EGUs would occur through a combination of heat rate 
improvements (resulting in a decrease in emission rates) and 
substitution of generation at less carbon-intensive affected EGUs, 
notably existing NGCC units. One reason for considering a BSER 
comprising these two building blocks is that it involves only affected 
EGUs and generation from affected EGUs.
    The EPA believes that the combination of building blocks 1 and 2 
would be a ``system of emission reduction'' capable of achieving 
significant reductions in CO2 emissions from affected EGUs 
at a reasonable cost. As discussed in Section VI.C above, each of the 
two building blocks independently would be capable of achieving 
meaningful CO2 emission reductions at reasonable costs. In 
combination, the need to achieve the level of emission reductions 
achievable through use of building block 2 can mitigate the concern 
that building block 1, implemented alone, would make coal-fired EGUs 
more economically competitive and lead to increased generation that 
would offset the emission reduction benefits of the carbon-intensity 
improvements. While combining the building blocks may also raise the 
cost per ton of emission reductions achieved through heat rate 
improvements (by reducing the quantity of MWh generated from the EGUs 
with improved heat rates and therefore also reducing the aggregate 
emission reductions achieved at those EGUs by the heat rate 
improvements), the costs of heat rate improvements are low enough that 
we believe their cost per ton of emission reduction would remain 
reasonable.
    Nevertheless, the EPA is not proposing that a combination of 
building blocks 1 and 2 is the BSER, because the proposed combination 
of all four building blocks discussed below--in other words, adding to 
the measures in building blocks 1 and 2 the measures in building blocks 
3 and 4, which we and stakeholders have identified as already in use--
is capable of achieving even greater CO2 emission reductions 
from affected EGUs at reasonable costs. The state-specific goals that 
would be computed consistent with a BSER based on the combination of 
only building blocks 1 and 2 (i.e., goals computed using the goal 
computation methodology discussed in Section VII below, except for the 
omission of building blocks 3 and 4) are presented in the Goal 
Computation TSD available in the docket. Further information on the 
EPA's evaluation of this combination is available in the ``Analysis of 
Emission Reductions, Costs, Benefits and Economic Impacts Associated 
with Building Blocks 1 and 2'' available in the docket. We invite 
comment on a potential BSER comprising a combination of building blocks 
1 and 2.
3. A Combination of all Four Building Blocks as the Best System of 
Emission Reduction
    Our proposal for the BSER is a combination of all four building 
blocks. As discussed in Section VI.C above, each of the four building 
blocks is a proven way to support either improvements in emissions 
rates at affected EGUs or reductions in EGU mass emissions; each is in 
widespread use and is independently capable of supporting significant 
CO2 reductions from affected EGUs, either on an emission 
rate or mass-emissions basis, at a reasonable cost consistent with 
ensuring system reliability. As discussed in Section VI.E below, the 
combination of all four building blocks provides the basis for 
satisfying the legal criteria to be considered the BSER. Further, as 
discussed in Section X below, the combination of all four building 
blocks can achieve greater overall CO2 emission reductions 
from affected EGUs, at a lower cost per unit of CO2 
eliminated, than the combination of building blocks 1 and 2.
    In the large and highly integrated electricity system, where 
electricity is fungible and the demand for electricity services can be 
met in many ways (including through demand-side energy efficiency), 
states and the industry have long pursued a wide variety of strategies 
for ensuring that the demand for electricity services is met reliably, 
at reasonable costs, and in a manner consistent with evolving 
constraints, including environmental objectives. These strategies have 
long extended to the measures in all four building blocks. We believe 
the combination of all four building blocks fairly represents the range 
of measures that states and the industry will consider when developing 
state plans and strategies for reducing CO2 emissions from 
affected EGUs while continuing to meet demand for electricity services 
reliably and affordably. Therefore, we believe it is appropriate to 
consider that same combination as the BSER upon which the required 
CO2 standards of performance for affected EGUs should be 
based.

E. Determination of the Best System of Emission Reduction

1. Overview
    In this section, the EPA explains the ``best system of emission 
reduction . . . adequately demonstrated.'' This explanation includes 
what the EPA proposes to determine as the BSER and why. In addition the 
EPA explains how the BSER forms the basis for each state's overall 
emission limitation requirement, which the EPA determines as the state 
goal and the state adopts into its planning process as the emissions 
performance level. The emission performance level, in turn, constitutes 
the minimum degree of stringency for the standards of performance that, 
taken as a whole, the state must establish for its affected EGUs (or, 
if the state adopts the portfolio approach, for the requirements 
imposed on the affected EGUs and other entities). Through this process, 
the BSER informs the minimum stringency of the standards of 
performance, although the state retains flexibility in its allocation 
of emission limitations among its sources. As the EPA explains, central 
to this overall approach is the fact that the EPA applies the BSER on a 
state-wide basis, which is consistent with the interconnected nature of 
the electricity system.
    The EPA is proposing two alternative formulations for the BSER, 
each of which is based on, although in different ways, the four 
building blocks. Under the first approach, emission rate improvements 
and mass emission reductions at affected EGUs facilitated through the 
adoption of the four building blocks themselves meet the criteria for 
the BSER because they will amount to substantial reductions in 
CO2 emissions achieved while maintaining fuel diversity and 
a reliable, affordable electricity supply for the United States. Under 
the second approach, the BSER consists of building block 1 coupled with 
reduced utilization in specified amounts from, in general, higher-
emitting affected EGUs. Under this latter approach, the measures in 
building blocks 2, 3, and 4 serve to justify those amounts and the 
``adequate[ ] demonstrat[ion]'' because they are proven measures that 
are already being pursued by states and the industry, at least in part 
for the purpose of reducing CO2 emissions from affected 
EGUs.
    The remainder of this discussion is organized into the following 
subsections. Subsection 2 contains a summary of relevant considerations 
for the BSER as defined in the statute and further interpreted in court 
decisions. Subsection 3 discusses characteristics of the electricity 
industry relevant to

[[Page 34879]]

interpretation of the BSER for purposes of this proposal, most notably 
the industry's highly interconnected and integrated nature. Subsection 
4 provides a discussion of how the building blocks would satisfy the 
BSER criteria in isolation or support the alternative formulation of 
the BSER as including reduced utilization in specified amounts. 
Subsection 5 evaluates two combinations of building blocks--a 
combination of building blocks 1 and 2, and the proposed combination of 
all four building blocks--against the BSER criteria, and explains why 
we propose that the combination of all four is the BSER. Subsection 6 
addresses additional considerations related to the inclusion of 
building blocks 2, 3, and 4 as parts of the basis supporting the BSER. 
In subsection 7, we describe and seek comment on the alternate 
interpretation that the BSER includes, in addition to building block 1, 
a component consisting of reduced generation from higher-emitting 
affected EGUs, with the measures in the other building blocks serving 
as the basis for quantifying the amounts of generation reductions and 
consequent CO2 emission reductions that can be achieved 
while continuing to meet the demand for electricity services in a 
reliable and affordable manner. In subsection 8, we discuss the 
discretion that the case law gives us in weighing the various criteria 
to determine the BSER. In subsection 9, we discuss how the BSER and the 
state-wide manner in which the EPA applies it form the basis for the 
emission standards that the state includes in the plan, and we explain 
why that approach is consistent with the applicable section 111 
requirements. The final three subsections address the topics of 
combining source categories, severability, and certain other specific 
issues on which we are seeking comment. Additional discussion is 
provided in the Legal Memorandum available in the docket.
2. Statutory and Regulatory Provisions Related to Determination and 
Application of the BSER
    The EPA's explanation for this BSER proposal begins with the 
statutory definition of a ``standard of performance'':

    The term ``standard of performance'' means a standard for 
emissions of air pollutants which reflects the degree of emission 
limitation achievable through the application of the best system of 
emission reduction 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.

42 U.S.C. 7411(a)(1).

    The U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit or 
Court) has handed down case law over a 40-year period that interprets 
this CAA provision, including its component elements.\194\ Under this 
case law, the EPA determines the BSER based on the following key 
considerations, among others:
---------------------------------------------------------------------------

    \194\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. 
Cir. 1973), cert. denied, 416 U.S. 969 (1974); Essex Chemical Corp. 
v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973), cert. denied, 
Appalachian Power Co. v. EPA, 416 U.S. 969 (1974); Sierra Club v. 
Costle, 657 F.2d 298 (D.C. Cir. 1981); Portland Cement Ass'n v. EPA, 
665 F.3d 177 (D.C. Cir. 2011). Although this case law concerns the 
meaning of the definition of ``standard of performance'' for 
purposes of rulemakings that the EPA promulgated under CAA section 
111(b), the same term is used for section 111(d), and as a result, 
this case law is relevant for the present rulemaking under section 
111(d).
---------------------------------------------------------------------------

     The system of emission reduction must be technically 
feasible.
     The EPA must consider the amount of emission reductions 
that the system would generate.
     The costs of the system must be reasonable. The EPA may 
consider costs at the source level, the industry level, and, at least 
in the case of the power sector, the national level in terms of the 
overall costs of electricity and the impact on the national economy 
over time.\195\
---------------------------------------------------------------------------

    \195\ As discussed in the January 2014 Proposal, the D.C. 
Circuit's case law formulates the cost consideration in various 
ways: The costs must not be ``exorbitant[ ]'', Essex Chemical Corp. 
v. Ruckelshaus, 486 F.2d at 433, see Lignite Energy Council v. EPA, 
198 F.3d 930, 933 (D.C. Cir. 1999); ``greater than the industry 
could bear and survive,'' Portland Cement Ass'n v. EPA, 513 F.2d 
506, 508 (D.C. Cir. 1975); or ``excessive'' or ``unreasonable,'' 
Sierra Club v. Costle, 657 F.2d at 343. In the January 2014 
Proposal, the EPA stated that ``these various formulations of the 
cost standard . . . are synonymous,'' and, for convenience, we used 
``reasonableness'' as the formulation. We take the same approach in 
this rulemaking.
---------------------------------------------------------------------------

     The EPA must also consider that CAA section 111 is 
designed to promote the development and implementation of technology, 
including the diffusion of existing technology as the BSER,\196\ the 
development of new technology that may be treated as the BSER,\197\ and 
the development of other emerging technology.\198\
---------------------------------------------------------------------------

    \196\ See 1970 Senate Committee Report No. 91-1196 at 15 (``The 
maximum use of available means of preventing and controlling air 
pollution is essential to the elimination of new pollution 
problems'').
    \197\ See Portland Cement Ass'n v. Ruckelshaus, 486 F.2d at 391 
(the best system of emission reduction must ``look[ ] toward what 
may fairly be projected for the regulated future, rather than the 
state of the art at present'').
    \198\ See Sierra Club v. Costle, 657 F.2d at 351 (upholding a 
standard of performance designed to promote the use of an emerging 
technology).
---------------------------------------------------------------------------

    Another consideration particularly relevant to this rulemaking is 
energy impacts, which, as with costs, the EPA may consider at the 
source level, the industry level, and the national level over time. In 
the context of the electricity industry and this proposal, the EPA 
believes that the scope of energy impacts that may be considered 
encompasses assurance of the continued ability of the industry to meet 
the evolving demand for electricity services in a reliable manner, 
while providing sufficient flexibility to enable affected sources to 
follow state energy plans.
    Importantly, the EPA has discretion to weigh these various 
considerations, may determine that some merit greater weight than 
others, and may vary the weighting depending on the source category.
    It is a well-established principle that states have discretion 
regarding the measures adopted in their state implementation plans 
under CAA section 110 to attain the NAAQS.\199\ The EPA believes that 
the same principle applies in the context of state plans under section 
111(d) as well, such that each state has the discretion to adopt 
emission reduction measures other than the measures found by the EPA to 
comprise the BSER, or to place greater or lesser emphasis than the EPA 
on certain measures, provided that the state's plan achieves the 
required level of emission performance for affected sources.
---------------------------------------------------------------------------

    \199\ See Train v. Natural Res. Def. Council, 421 U.S. 60 
(1975).
---------------------------------------------------------------------------

    The EPA discussed the CAA requirements and Court interpretations of 
the BSER at length in the January 2014 Proposal, 79 FR at 1,462/1-
1,467/3, and incorporates by reference that discussion into this 
rulemaking.
    Over the last forty years, under CAA section 111(d), the agency has 
regulated four pollutants from five source categories (i.e., phosphate 
fertilizer plants (fluorides), sulfuric acid plants (acid mist), 
primary aluminum plants (fluorides), Kraft pulp plants (total reduced 
sulfur), and municipal solid waste landfills (landfill gases)).\200\ In 
addition, the agency has regulated additional pollutants under CAA

[[Page 34880]]

section 111(d) in conjunction with CAA section 129.\201\ However, the 
agency has not previously regulated CO2 or any other 
greenhouse gas under CAA section 111(d) (although because landfill 
gases include methane, the agency's regulation of landfill gases 
reduced emissions of that greenhouse gas). Further, the electricity 
industry differs in important ways from the source categories 
previously regulated under section 111(d) in terms of its large scale, 
its central importance to the economy, and, as discussed below, its 
highly interconnected and integrated nature.
---------------------------------------------------------------------------

    \200\ See ``Phosphate Fertilizer Plants; Final Guideline 
Document Availability,'' 42 FR 12022 (Mar. 1, 1977); ``Standards of 
Performance for New Stationary Sources; Emission Guideline for 
Sulfuric Acid Mist,'' 42 FR 55796 (Oct. 18, 1977); ``Kraft Pulp 
Mills, Notice of Availability of Final Guideline Document,'' 44 FR 
29828 (May 22, 1979); ``Primary Aluminum Plants; Availability of 
Final Guideline Document,'' 45 FR 26294 (Apr. 17, 1980); ``Standards 
of Performance for New Stationary Sources and Guidelines for Control 
of Existing Sources: Municipal Solid Waste Landfills, Final Rule,'' 
61 FR 9905 (Mar. 12, 1996).
    \201\ See, e.g., ``Standards of Performance for New Stationary 
Sources and Emission Guidelines for Existing Sources: Sewage Sludge 
Incineration Units, Final Rule,'' 76 FR 15372 (Mar. 21, 2011).
---------------------------------------------------------------------------

3. The Interconnected Nature of the U.S. Electricity Sector
    The U.S. electricity system is a highly interconnected, integrated 
system in which large numbers of EGUs using diverse fuels and 
generating technologies are operated in a coordinated manner to produce 
fungible electricity services for customers. Because electricity 
storage is costly and has not been widely deployed, the amounts of 
electricity demanded and supplied must be continuously matched, and 
system operators typically have flexibility to choose among multiple 
EGUs when selecting where to obtain the next MWh of generation needed. 
Coordination over short- and long-term time scales is accomplished 
through a variety of institutions including vertically integrated 
utilities, state regulatory agencies, independent system operators and 
regional transmission organizations (ISOs/RTOs), and market mechanisms. 
The electricity sector is both critical to the nation's economy and the 
source of more than 30 percent of U.S. greenhouse gas emissions, 
predominantly in the form of CO2.
    The integrated electricity system allows increased generation from 
less carbon-intensive NGCC units to substitute for generation from more 
carbon-intensive steam EGUs (building block 2), thereby lowering 
CO2 emissions from the group of affected EGUs as a whole. 
The electricity system similarly allows increased generation resulting 
from expansion of the amount of available low- or zero-carbon 
generating capacity connected to the electric grid (building block 3), 
as well as avoided generation resulting from reductions in electricity 
demand (building block 4), to substitute for fossil fuel-fired 
generation, thereby reducing CO2 emissions from affected 
EGUs. Each of these measures already routinely occurs within this 
integrated system for providing electricity and electricity services.
    The integrated nature of the electricity system has long played a 
central role in the industry's continuing efforts to assure reliability 
and to manage costs generally. Specifically in the area of pollution 
control, state governments and the federal government have repeatedly 
taken advantage of the integrated nature of the electricity system when 
designing programs to allow the industry to meet the pollution control 
objectives in a least-cost manner. Examples include several cap-and-
trade programs to reduce national or regional emissions of 
SO2 and NOX: The SO2-related portion 
of the CAA Title IV Acid Rain Program, the Ozone Transport Commission 
(OTC) NOX Budget Program, the NOX SIP Call 
NOX Budget Trading Program, and the Clean Air Interstate 
Rule (CAIR) annual SO2, annual NOX, and ozone-
season NOX trading programs. While the Acid Rain Program was 
created by federal legislation, the OTC NOX Budget Program 
was developed primarily through the joint efforts of a group of 
northeastern states. In the NOX SIP Call and CAIR programs, 
the federal government set emission budgets and developed trading 
programs that states could use as a compliance option.\202\ Each of 
these programs was designed to take advantage of the fact that in an 
integrated electricity system, some EGUs can reduce emissions at lower 
costs than others, and that by allowing the industry to determine 
through market mechanisms which EGUs to control and which to leave 
uncontrolled, and which EGUs to potentially operate more and which to 
potentially operate less, overall compliance costs can be reduced. The 
integrated electricity system plays the important function of allowing 
some EGUs to reduce their generation while ensuring that overall demand 
for electricity services can be reliably met. It is worth noting that 
adoption by affected EGUs of any of the measures in the building blocks 
could be (or could have been) used to facilitate compliance with each 
of the programs just described.\203\
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    \202\ In the Regional Greenhouse Gas Initiative, described in 
more detail below, participating states use emission budgets and a 
trading program to address CO2 emissions from the 
electricity sector.
    \203\ In addition to the already-implemented programs mentioned 
above--the SO2-related portion of the Acid Rain Program, 
the OTC NOX Budget Program, the NOX SIP Call 
NOX Budget Trading Program, and the Clean Air Interstate 
Rule trading programs--use of measures in the building blocks would 
also facilitate compliance with the cap-and-trade programs 
established by the Cross-State Air Pollution Rule (76 FR 48208, Aug. 
8, 2011).
---------------------------------------------------------------------------

    Some states are already relying on the integrated nature of the 
electricity system to establish the policy contexts within which 
affected EGUs will reduce their CO2 emissions.\204\ 
California and Colorado provide two examples of how statewide targets 
(or company-wide targets within a state) can be designed with 
consideration of the wide range of CO2 mitigation options 
and affected EGUs' flexibility to use those options.
---------------------------------------------------------------------------

    \204\ A number of utilities also have climate mitigation plans. 
Examples include National Grid, http://www2.nationalgrid.com/responsibility/how-were-doing/grid-data-centre/climate-change/; 
Exelon, http://www.exeloncorp.com/newsroom/pr_20140423_EXC_Exelon2020.aspx; PG&E, http://www.pge.com/about/environment/pge/climate/; and Austin Energy, http://austinenergy.com/wps/portal/ae/about/environment/austin-climate-protection-plan/!ut/p/a0/04_Sj9CPykssy0xPLMnMz0vMAfGjzOINjCyMPJwNjDzdzY0sDBzdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/.
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    California enacted its Global Warming Solutions Act (also known as 
AB32) in 2006, requiring the state to reduce its GHG emissions to 1990 
levels by 2020 and 80 percent below 1990 levels by 2050.\205\ According 
to California, ``the integrated nature of the power grid means that 
policies which displace the need for fossil generation can often cut 
emissions from covered sources more deeply, and more cost-effectively 
than can engineering changes at the plants alone, though these source-
level control efforts are a vital starting point.'' \206\ California 
therefore relied on a suite of mechanisms to provide fossil fuel-fired 
generation substitutes and incentives for EGUs to reduce their 
emissions, including demand-side energy efficiency programs, renewable 
energy programs, and an economy-wide cap-and-trade program, along with 
other programs.\207\ The California plan has put in place mechanisms 
that through market dynamics affect both companies' longer-term 
planning decisions and their short-term dispatch decisions. The need to 
hold emissions allowances and the reduced demand from demand-side 
energy efficiency programs impact longer-term decisions companies make 
about investment in both existing and new EGUs. The price of emission 
allowances also impacts hourly dispatch decisions; where emission 
allowance requirements are in effect, EGU owners

[[Page 34881]]

routinely recognize the costs of emission allowances as components of 
the variable operating costs that are relied on for these 
decisions.\208\ In this manner, allowance prices constitute market 
signals encouraging reduced use of higher-emitting EGUs and increased 
use of lower-emitting EGUs.
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    \205\ State of California Global Warming Solutions Act of 2006, 
Assembly Bill 32, http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered.pdf.
    \206\ December 27, 2013 Letter from Mary D. Nichols, Chairman of 
California Air Resources Board, to EPA Administrator Gina McCarthy.
    \207\ See Cal. Air Res. Bd., Climate Change Scoping Plan 31-32, 
41-46 (2008), available at http://www.arb.ca.gov/cc/scopingplan/document/adopted_scoping_plan.pdf.
    \208\ The requirement to hold allowances covering their 
CO2 emissions went into effect for EGUs in California on 
January 1, 2013.
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    The Colorado Clean Air, Clean Jobs Act (CACJA), signed into law on 
April 19, 2010, required each investor-owned utility with coal-fired 
EGUs to submit to the state a multi-pollutant plan for meeting current 
and foreseeable EPA standards for emissions of NOX, 
SO2, particulates, mercury, and CO2. Rather than 
fully prescribing specific control technologies, the law provided 
flexibility for each utility to select the best set of measures to 
achieve the emission reductions.\209\ For example, a utility could 
choose to retrofit or repower EGUs, or it could choose to retire 
higher-emitting EGUs and replace them with NGCC units and other low- or 
non-emitting energy plants or with end-use efficiency measures.\210\ 
The Colorado plan generally focused more on impacting companies' 
longer-term planning decisions than on affecting short-term dispatch 
decisions. In response, Colorado utilities have adopted a mix of 
measures including retrofits, natural gas conversions and retirements 
of coal-fired EGUs, as well as construction of new NGCC units.
---------------------------------------------------------------------------

    \209\ The law also set some explicit requirements, such as 
requirements for development of new renewable generating capacity 
and requirements to phase out older coal-fired EGUs.
    \210\ See State of Colorado House Bill 10-1365, available at 
http://www.leg.state.co.us/clics/clics2010a/csl.nsf/fsbillcont/0CA296732C8CEF4D872576E400641B74?Open&file=1365_ren.pdf.
---------------------------------------------------------------------------

    Multi-state mechanisms with analogous impacts on both longer-term 
planning decisions and short-term dispatch decisions have also been put 
in place. For example, nine northeastern and Mid-Atlantic States \211\ 
participate in the Regional Greenhouse Gas Initiative (RGGI), a market-
based emissions budget trading program that sets an aggregate limit on 
CO2 emissions from fossil fuel-fired EGUs in the 
participating states. To comply with the program, each EGU must acquire 
allowances equal to its emissions in each compliance period--through 
purchases or by allocation from the state--and must surrender the 
allowances at the end of the period. The RGGI program offers 
flexibility to regulated parties through provisions for multi-year 
compliance periods, allowance banking, offsets, an auction reserve 
price, and a cost-containment reserve of allowances, and further 
encourages emission allowance market development by authorizing trading 
between regulated and non-regulated parties.\212\ Operating in this 
regime, EGUs could take a variety of compliance actions, including 
replacing generation at higher-emitting EGUs with generation at lower-
emitting EGUs or achieving emissions reductions at EGUs by means of 
end-use energy efficiency programs.
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    \211\ Participating states include Connecticut, Delaware, Maine, 
Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and 
Vermont.
    \212\ See RGGI Web site at http://www.rggi.org/rggi.
---------------------------------------------------------------------------

    An approach to determination of the BSER that recognizes the 
integrated nature of the electricity system is also consistent with the 
way in which the electricity industry already addresses resource 
planning issues. For example, in states where the price of EGUs' 
generation remains subject to regulation, utilities generally prepare 
integrated resource plans setting forth their strategies for meeting 
future demand for electricity services in a cost-effective manner. 
These plans may include measures from building blocks 2, 3, and 4. In 
most states where generation is no longer subject to price regulation, 
regional transmission organizations (RTOs) or independent system 
operators (ISOs) ensure the adequacy of future generation supplies by 
administering auctions for forward capacity. In these auctions, owners 
of existing EGUs (with consideration of building blocks 1 and 2),\213\ 
developers of new EGUs including renewable generating capacity 
(building block 3), and developers of demand-side resources (building 
block 4) all compete to provide potential resources for meeting the 
projected demand for electricity services.
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    \213\ Potential heat rate improvements create opportunities for 
EGU owners to reduce their variable costs, which increase potential 
operating profits from generation and thereby create opportunities 
to lower the prices at which the owners would bid the capacity of 
their EGUs into the auctions.
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    As indicated by the foregoing discussion, in the U.S. electricity 
system the demand for electricity services is met, on both a short-term 
and longer-term basis and in both regulated and deregulated contexts, 
through integrated consideration of a wide variety of possible options, 
coordinated by some combination of utilities, regulators, system 
operators, and market mechanisms. The EPA believes that the BSER for 
CO2 emissions from existing EGUs should reflect this 
integrated character.
    A final, important point regarding the integrated electricity 
system is that the sets of actions that enable the demand for 
electricity services to be continuously met can be undertaken in 
different orders, with changes in some interconnected elements 
eliciting compensating responses from other interconnected elements. 
Thus, the CO2 emissions reductions associated with building 
blocks 2, 3, and 4 can be achieved in either of two ways: (i) First 
instituting measures in building blocks 2, 3, and 4, which, due to the 
interconnected and integrated nature of the grid, would elicit the 
response of reducing generation at some or all affected EGUs, thereby 
lowering those EGUs' emissions; or (ii) first reducing generation and 
therefore emissions from some or all affected EGUs (or planning to make 
those reductions), which due to the interconnected and integrated 
nature of the grid, would elicit the responses identified in building 
blocks 2, 3, and 4 of increasing generation at lower-emitting EGUs or 
reducing the demand for electricity services. (In some cases, the 
change and response could be planned simultaneously.) Each of these 
sets of actions, with the building blocks as the initial change or the 
reduced generation at affected EGUs as the initial change, may be 
considered to be part of a ``system of emission reduction,'' as 
discussed below.
    Further discussion of the ways in which the ``system of emission 
reduction'' for affected EGUs is influenced by the interconnected and 
integrated nature of the electricity system is provided below in the 
context of the EPA's rationale for proposing to base the BSER on the 
combination of all four building blocks. This topic is also discussed 
in the Legal Memorandum available in the docket.
4. Evaluation of Individual Building Blocks Against the BSER Criteria
    In this subsection we explain why (i) the individual building 
blocks meet the criteria to qualify as components of the ``best system 
of emission reduction . . . adequately demonstrated'' and (ii) why, 
under the alternative formulation of the BSER as including reduced 
utilization of higher-emitting affected EGUs in specified amounts, 
building blocks 2, 3, and 4 serve as the basis for those amounts and 
why the reduced utilization is ``adequately demonstrated.''
a. Building Block 1--Heat Rate Improvements
    Building block 1--reducing the carbon intensity of generation at 
individual affected coal-fired steam EGUs through heat rate 
improvements--is a component of the BSER because the measures the 
affected sources may

[[Page 34882]]

undertake to achieve heat rate improvements are technically feasible 
and of reasonable cost, and meet the other requirements to qualify as a 
component of the ``best system of emission reduction . . . adequately 
demonstrated.''
    The EPA's analysis and conclusions regarding the technical 
feasibility, costs, and magnitude of CO2 emission reductions 
achievable through heat rate improvements are discussed in Section 
VI.C.1 above. We consider heat rate improvement to be a common and 
well-established practice within the industry.
    Other BSER criteria also favor building block 1 as a component of 
the BSER. For example, with respect to non-air health and environmental 
impacts, heat rate improvements cause fuel to be used more efficiently, 
reducing the volumes of and therefore the adverse impacts associated 
with disposal of coal combustion solid waste products. With respect to 
technological innovation, building block 1 encourages the spread of 
more advanced technology to EGUs currently using components with older 
designs. The EPA has not specifically evaluated the extent to which 
enhanced maintenance practices leading to heat rate improvements might 
also lead to electricity reliability improvements, but generally 
expects that enhanced maintenance would be more likely to improve than 
to degrade EGU availability, which would tend to improve electricity 
system reliability.
    As noted above, the EPA is concerned about the potential ``rebound 
effect'' associated with building block 1 if applied in isolation. More 
specifically, we noted that in the context of the integrated 
electricity system, absent other incentives to reduce generation and 
CO2 emissions from coal-fired EGUs, heat rate improvements 
and consequent variable cost reductions at those EGUs would cause them 
to become more competitive compared to other EGUs and increase their 
generation, leading to smaller overall reductions in CO2 
emissions (depending on the CO2 emission rates of the 
displaced generating capacity). However, we believe that this concern 
can be readily addressed by ensuring that the BSER also reflects other 
CO2 reduction strategies that encourage increases in 
generation from lower- or zero-carbon EGUs or in demand-side energy 
efficiency, thereby allowing building block 1 to be considered part of 
the BSER for CO2 emissions at affected EGUs.
b. Building Block 2--Re-Dispatch
    Building block 2--reducing CO2 emissions at and 
substituting for generation from the most carbon-intensive affected 
EGUs with generation from less carbon-intensive affected EGUs 
(specifically NGCC units that are currently operating or under 
construction)--is a component of the BSER because the shifts in 
generation that it involves demonstrate that reducing mass 
CO2 emissions at higher-emitting EGUs is technically 
feasible, will not jeopardize system reliability, is of reasonable 
cost, and meets the other requirements for a component of the ``best 
system of emission reduction . . . adequately demonstrated.''
    The EPA's analysis and conclusions regarding the technical 
feasibility, costs, and magnitude of CO2 emission reductions 
achievable at high-emitting EGUs through re-dispatch among affected 
EGUs are discussed in Section VI.C.2 above. We consider re-dispatch 
among the large number of diverse EGUs that are linked to one another 
and to customers by extensive regional transmission grids to be a 
routine and well-established operating practice within the industry 
that is used to facilitate the achievement of a wide variety of 
objectives, including environmental objectives, while meeting the 
demand for electricity services. As discussed above, in the 
interconnected and integrated electricity industry, fossil fuel-fired 
steam EGUs are able to reduce their generation and NGCC units are able 
to increase their generation in a coordinated manner through 
mechanisms--in some cases centralized and in others not--that regularly 
deal with such changes on both a short-term and a longer-term basis.
    Both the achievability of this building block and the 
reasonableness of its costs are supported by the fact that there has 
been a long-term trend in the industry away from coal-fired generation 
and toward NGCC generation for a variety of reasons. As part of their 
CO2 reduction strategies, states can encourage this trend in 
a variety of ways. First, a state could use its permitting authority to 
impose limits on the hours of operation (or emissions) of individual 
steam generating units over a given time period. Second, a state could 
change the relative costs of generation for more carbon-intensive and 
less carbon-intensive generating units by imposing a cost on carbon 
emissions. A state could do so through any of several market-based 
mechanisms. One would be to adopt an allowance-based system. An example 
is the Regional Greenhouse Gas Initiative, an allowance-based system in 
which sources purchase allowances in periodic auctions. Another way 
would be through a tradable emission rate system, under which the state 
would impose an emission rate limit on the steam generating unit that 
the unit could meet only by purchasing the right to average its 
emission rate with a unit with a lower rate, such as an NGCC unit. Most 
broadly, an allowance system would provide the greatest incentive for 
the most carbon-intensive affected sources to reduce emissions as much 
as possible so as to reduce their need to purchase allowances (or to 
allow them to sell un-needed allowances), and the same would be true 
for a tradable emission rate system.
    The emission reductions achievable or supported by the application 
of building block 2 also perform well against other BSER criteria. For 
example, we expect that building block 2 would have positive non-air 
health and environmental impacts. Coal combustion for electricity 
generation produces large volumes of solid wastes that require 
disposal, with some potential for adverse environmental impacts; these 
wastes are not produced by natural gas combustion. The intake and 
discharge of water for cooling at many EGUs also carries some potential 
for adverse environmental impacts; NGCC units generally require less 
cooling water than steam EGUs.\214\ As already noted, with respect to 
energy impacts, the EPA believes that building block 2 (at least at the 
level of stringency proposed for purposes of establishing state goals) 
would not pose risks to reliability. Building block 2 also promotes 
greater use of the advanced NGCC technology installed in the existing 
fleet of NGCC units.
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    \214\ According to a DOE/NETL study, the relative amount of 
water consumption for a new pulverized coal plant is 2.5 times the 
consumption for a new NGCC unit of similar size. ``Cost and 
Performance Baseline for Fossil Energy Plants: Volume 1: Bituminous 
Coal and Natural Gas to Electricity,'' Rev 2a, September 2013, 
National Energy Technology Laboratory Report DOE/NETL-2010/1397.
---------------------------------------------------------------------------

    It should be observed that, by definition of the elements of this 
building block, the shifts in generation taking place under building 
block 2 occur entirely among existing EGUs subject to this 
rulemaking.\215\ Through application of this building block considered 
in isolation, some affected sources--mostly coal-fired steam EGUs--
would reduce their generation and CO2 emissions, while other 
affected sources--NGCC units--would increase their generation and 
CO2 emissions.\216\

[[Page 34883]]

However, because for each MWh of generation, NGCC units produce less 
CO2 emissions than coal-fired steam EGUs, the total quantity 
of CO2 emissions from all affected sources in aggregate 
would decrease. In the context of the integrated electricity system, 
where the operation of affected EGUs of multiple types is routinely 
coordinated to provide a fungible service, and in the context of 
CO2 emissions, where location is a less important factor 
than is the case for other pollutants, the EPA believes that a measure 
that takes advantage of that integration to reduce CO2 
emissions from the overall set of affected EGUs is readily encompassed 
within the meaning of a ``system of emission reduction'' for 
CO2 emissions at affected EGUs even if the measure would 
increase CO2 emissions from a subset of those affected EGUs. 
Indeed, our review of the data and discussions with states reveal that 
some states are already moving in this direction for this purpose 
(while others are moving in the same direction for other purposes). 
Emission trading or averaging approaches can facilitate the 
implementation of such a ``system'' and have already been used in the 
electricity industry to address CO2 as well as other 
pollutants, as discussed above.
---------------------------------------------------------------------------

    \215\ For purposes of this rulemaking, ``existing'' EGUs include 
units under construction as of January 8, 2014, the date of 
publication in the Federal Register of the Carbon Pollution 
Standards for new fossil fuel-fired EGUs.
    \216\ Because building blocks 3 and 4 reduce generation and 
CO2 emissions from all fossil fuel-fired affected EGUs as 
a group, including NGCC units, the increase in generation and 
CO2 emissions from NGCC units under building block 2 is 
mitigated to some extent by including those building blocks in the 
BSER along with building block 2.
---------------------------------------------------------------------------

    Finally, the EPA notes that the alternative interpretation of the 
BSER discussed later is based in part on the re-dispatch measures in 
building block 2. In this alternative, as it relates to building block 
2, reduced generation from the subset of affected EGUs consisting of 
fossil fuel-fired steam EGUs--i.e., the most carbon-intensive subset of 
affected EGUs--is a component of the BSER. The potential to use 
increased generation from less carbon-intensive affected NGCC units 
would serve as a basis for quantifying the amounts of generation 
reductions and CO2 emission reductions at more carbon-
intensive affected EGUs that could be achieved while continuing to meet 
the demand for electricity services in a reliable and affordable 
manner. This alternative is discussed further in Section VI.E.7 below.
c. Building Block 3--Use of Expanded Low- and Zero-Carbon Generating 
Capacity
    Building block 3--reducing CO2 emissions at and 
substituting for generation from affected EGUs by using expanded 
amounts of low- and zero-carbon generating capacity--is a component of 
the BSER because the expansion and use of renewable generating 
capacity, completion and use of nuclear capacity currently under 
construction, and avoidance of nuclear capacity retirements all 
establish the foundation for a determination that mass emission 
reductions from affected EGUs are technically feasible, do not 
jeopardize system reliability, are of reasonable cost, and meet the 
other requirements for a component of the ``best system of emission 
reduction . . . adequately demonstrated.''
    The EPA's analysis and conclusions regarding the technical 
feasibility, costs, and magnitude of the measures in building block 3 
are discussed in Section VI.C.3 above. We consider all of these 
measures to be proven, well-established practices within the industry, 
and development of renewable capacity in particular is consistent with 
recent industry trends. States are already pursuing policies that 
encourage production of greater amounts of renewable energy, such as 
the establishment of targets for procurement of renewable generating 
capacity. Moreover, markets for renewable energy certificates, which 
facilitate investment in renewable energy, are already well-
established. As noted above with re-dispatch, an allowance system or 
tradable emission rate system would provide incentives for sources to 
reduce their emissions as much as possible, including through 
substituting for their generation with generation from renewable 
energy. In addition, owners of existing nuclear units and nuclear units 
currently under construction can take action to complete or preserve 
that capacity, the generation from which likewise can be dispatched in 
a coordinated manner to substitute for fossil fuel-fired generation. As 
discussed above, coordination of these decisions in the integrated 
electricity system can occur through a variety of mechanisms, some 
centralized and some not.
    The renewable capacity measures in building block 3 generally 
perform well against other BSER criteria. For example, incentives for 
expansion of renewable capacity encourage technological innovation in 
improved renewable technologies as well as more extensive deployment of 
current advanced technologies. Generation from wind turbines (the most 
common renewable technology) does not produce solid waste or require 
cooling water, a better environmental outcome than if that amount of 
generation had instead been produced at a typical range of fossil fuel-
fired EGUs. Although the intermittent nature of generation from 
renewable resources such as wind and solar units requires special 
consideration from grid operators, renewable generation has grown 
quickly in recent years, as discussed above, and the EPA has seen no 
evidence that operators will be less able to cope with future growth 
than they have with rapid past growth.
    The EPA believes that the performance of the nuclear measures in 
building block 3 against the other BSER measures is also positive on 
balance. With respect to encouragement of technological innovation, 
incentives for completion of nuclear capacity currently under 
construction encourage deployment of nuclear unit designs that reflect 
advances over earlier designs. The nation's nuclear fleet today 
routinely operates at high average utilization rates, suggesting no 
reason to expect adverse reliability consequences from completion or 
preservation of additional nuclear capacity. The five nuclear units 
currently under construction are all designed to use closed-cycle 
cooling systems with lower cooling water usage than some existing 
fossil fuel-fired EGUs;\217\ existing nuclear units may use amounts of 
cooling water comparable to the amounts used by those fossil fuel-fired 
steam EGUs. The EPA recognizes that nuclear generation poses unique 
waste disposal issues (although it avoids the solid waste issues 
specific to coal-fired generation). However, we do not consider that 
potential disadvantage of nuclear generation relative to fossil fuel-
fired generation as outweighing nuclear generation's other advantages 
as an element of building block 3. For all these reasons, we consider 
building block 3 to be a component of the ``best system of emission 
reduction . . . adequately demonstrated.''
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    \217\ See U.S. NRC, Watts Bar Unit 2 Final Environmental 
Statement, Final Report at 3-3, available at http://pbadupws.nrc.gov/docs/ML1314/ML13144A092.pdf; U.S. NRC, Summer Units 
2-3 Final Environmental Impact Statement, Final Report at 3-14, 
available at http://pbadupws.nrc.gov/docs/ML1109/ML11098A044.pdf; 
U.S. NRC, Vogtle Units 3-4 Final Environmental Impact Statement, 
Final Report at 3-5, available at http://pbadupws.nrc.gov/docs/ML0822/ML082240145.pdf. Relative to the once-through systems at many 
existing power plants, closed-cycle cooling systems withdraw from 
and discharge to external water bodies substantially less overall 
cooling water, although they also consume larger amounts of water 
through evaporation. See Department of Energy/Office of Fossil 
Energy's Power Plant Water Management R&D Program, available at 
http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/PowerPlantWaterMgtR-D-Final-1.pdf.
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    Finally, the EPA notes that the alternative BSER discussed later 
would include a component consisting of reduced generation from 
affected EGUs,

[[Page 34884]]

with the measures in building block 3 serving as a basis for 
quantifying the amount of reduced generation and consequent 
CO2 emission reductions. Because of the availability of 
those measures, the amount of reduced generation can be achieved while 
continuing to meet the demand for electricity services in a reliable 
and affordable manner. This alternative BSER is discussed in Section 
VI.E.7 below.
d. Building Block 4--Increased Demand-Side Energy Efficiency
    Building block 4--reducing CO2 emissions at and reducing 
generation from affected EGUs by promoting demand-side energy 
efficiency that reduces the amount of generation required from affected 
EGUs--is a component of the BSER because the demand-side energy 
efficiency is technically feasible and of reasonable cost, and meets 
the other requirements for a component of the ``best system of emission 
reduction . . . adequately demonstrated.''
    The EPA's analysis and conclusions regarding the technical 
feasibility, costs, and magnitude of building block 4 are discussed in 
Section VI.C.4 above. We consider demand-side energy efficiency 
programs to be proven, well-established practices within the industry 
that are consistent with industry trends. Greater demand-side energy 
efficiency is already a common policy goal among states, and most 
states already authorize or require implementation of demand-side 
energy efficiency programs. Fossil fuel-fired EGUs can reduce their 
generation. Owners of affected EGUs as well as other parties can 
contract for demand-side energy efficiency. As discussed above, 
coordination of these decisions in the integrated electricity system 
can occur through a variety of mechanisms, some centralized and some 
not. For example, an allowance system or tradable emission rate system 
would provide incentives that promote the measures in building block 4 
in the same manner as discussed above for other building blocks.
    Building block 4 is also very attractive under other BSER criteria. 
Demand-side energy efficiency avoids the non-air health and 
environmental effects of the fossil fuel-fired generation for which it 
substitutes. Further, by reducing the overall amount of electricity 
that needs to be transmitted between EGUs and customers, demand-side 
energy efficiency tends to relieve stress on the grid, thereby 
increasing system reliability. Creating incentives for additional 
demand-side energy efficiency is also consistent with the goals of 
encouraging technological innovation in energy efficiency and 
encouraging deployment of current advanced technologies. For all these 
reasons, the measures in building block 4 qualify as a component of the 
``best system of emission reduction . . . adequately demonstrated.''
    The EPA notes that the alternative BSER discussed later would 
include a component consisting of reduced generation from affected 
EGUs, with demand-side energy efficiency serving as a basis for 
quantifying the amounts of generation reductions and consequent 
CO2 emission reductions that can be achieved while 
continuing to meet the demand for electricity services in a reliable 
and affordable manner. This alternate interpretation of the BSER is 
discussed in Section VI.E.7 below.
5. Evaluation of Building Block Combinations Against the BSER Criteria
a. Combination of Building Blocks 1 and 2
    The EPA has considered whether a combination of building blocks 1 
and 2 would be the BSER. As described in Section VI.D above, we believe 
that such a combination is technically feasible and would be a ``system 
of emission reduction'' capable of achieving meaningful reductions in 
CO2 emissions from affected EGUs at a reasonable cost. The 
combination would also satisfy other BSER criteria. Nevertheless, we do 
not propose that this combination should be the BSER because the 
proposed combination of all four building blocks is capable of 
achieving greater reductions in CO2 emissions from affected 
EGUs at a lower cost.
    The EPA believes that both building blocks 1 and 2 individually 
satisfy the BSER criteria identified by the statute and the D.C. 
Circuit, with one possible concern, related to a ``rebound effect,'' 
noted earlier. That concern is the potential for the heat rate 
improvements in building block 1, if implemented in isolation, to make 
coal-fired steam EGUs more competitive compared to other EGUs and cause 
them to increase their generation, creating a ``rebound effect'' that 
would make building block 1 less effective at reducing CO2 
emissions. As discussed above, building blocks 1 and 2 each appear 
attractive or neutral with respect to each of the other BSER criteria.
    With respect to most of the BSER criteria, there is no reason to 
expect that the combination of building blocks 1 and 2 would be 
evaluated differently from the individual building blocks. However, as 
noted earlier, the combination addresses the concern about building 
block 1 regarding a potential rebound effect, and in that important 
respect it performs better than building block 1 considered in 
isolation. The substitution of NGCC generation for generation from 
coal-fired and other steam EGUs ensures that generation from coal-fired 
EGUs, as a group, would not increase as a result of their improved 
variable costs, with the result that the reduction in CO2 
emission rates of coal-fired EGUs brought about by heat rate 
improvements would not be offset by an increase in CO2 
emissions due to increased generation from those EGUs. The combination 
of building blocks would therefore be capable of achieving greater 
reductions in CO2 emissions from affected sources than 
either building block in isolation.
    While achieving substantially greater emission reductions than 
building block 1 alone, by reducing overall generation from coal-fired 
EGUs the combination of building blocks 1 and 2 also has the potential 
to raise the cost of the portion of the overall emission reductions 
achievable through heat rate improvements relative to the cost of those 
reductions if building block 1 were implemented in isolation.\218\ 
However, the EPA believes that the cost of emission reductions achieved 
through heat rate improvements would remain reasonable for two reasons. 
First, as discussed in Section VI.C.1 above, the cost of CO2 
emission reductions achievable through heat rate improvements is quite 
low, and that cost would remain reasonable even if it was substantially 
increased. Second, although under the combination of building blocks 1 
and 2 the volume of coal-fired generation would decrease, that decrease 
is unlikely to be spread uniformly among all coal-fired EGUs. It is 
more likely that some coal-fired EGUs would decrease their generation 
slightly while others would decrease their generation by larger 
percentages or cease operations altogether. We would expect EGU owners 
to take these changes in EGU operating patterns into account when 
considering where to invest in heat rate improvements, with the result 
that there would be a tendency for such investments to be concentrated 
in EGUs whose generation output was expected to decrease the

[[Page 34885]]

least. This enlightened bias in spending on heat rate improvements--
that is, focusing investments on EGUs where such improvements would 
have the largest impacts and produce the highest returns, given 
consideration of projected changes in dispatch patterns--would tend to 
mitigate any deterioration in the cost of CO2 emission 
reductions achievable through heat rate improvements.
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    \218\ If an EGU produces less generation output, then an 
improvement in that EGU's heat rate and rate of CO2 
emissions per unit of generation produces a smaller reduction in 
CO2 emissions. If the investment required to achieve the 
improvement in heat rate and emission rate is the same regardless of 
the EGU's generation output, then the cost per unit of 
CO2 emission reduction will be higher when the EGU's 
generation output is lower.
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    As noted above, the EPA invites comment on a potential BSER 
comprising building blocks 1 and 2, in light of the considerations that 
could support this approach.
b. Combination of All Four Building Blocks
    The EPA's proposed BSER is a combination of all four building 
blocks. For the reasons described below, and similar to each of the 
building blocks, the combination must be considered a ``system of 
emission reduction.'' Moreover, as also discussed below, the 
combination qualifies as the ``best'' system that is ``adequately 
demonstrated.'' The combination is technically feasible; it is capable 
of achieving meaningful reductions in CO2 emissions from 
affected EGUs at a reasonable cost; it satisfies the other BSER 
criteria as well; and its components are well-established. The 
combination of all four building blocks would achieve greater 
CO2 emission reductions at a lower cost than the combination 
of building blocks 1 and 2 described above, and would also perform 
better against other BSER criteria. We therefore propose to find the 
combination of all four building blocks to be the ``best system of 
emission reduction . . . adequately demonstrated'' for reducing CO 
emissions at affected EGUs.\219\
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    \219\ The analysis of the interactions among building blocks 
provided above for the combination of building blocks 1 and 2, 
indicating that the addition of building block 2 would mitigate the 
potential concern about a ``rebound effect'' if building block 1 
were implemented in isolation, applies to the combination of all 
four building blocks as well; in fact, the addition of building 
blocks 3 and 4 would further mitigate that concern. The EPA believes 
that if implemented in combination, each of the four building blocks 
would achieve substantial reductions in CO2 emissions 
from affected EGUs at a reasonable cost.
---------------------------------------------------------------------------

    The assessments of the individual building blocks against the BSER 
criteria would generally apply in the same way to those building blocks 
when implemented as the combination of all four building blocks, with 
the same exceptions as discussed above with respect to the combination 
of building blocks 1 and 2 as well. However, the combination of all 
four building blocks would improve upon the combination of building 
blocks 1 and 2 in several respects. First, because of the potential of 
building blocks 3 and 4 to achieve additional CO2 reductions 
at reasonable costs, the broader combination would achieve greater 
CO2 emission reductions at a lower average cost. Second, by 
encompassing the increased low-and zero-carbon generation in building 
block 3, the broader combination would reduce reliance on fossil fuels 
and improve fuel diversity. Third, by encompassing the increased 
demand-side energy efficiency in building block 4, the broader 
combination would reduce the amount of electricity that would need to 
be delivered over the electric grid, generally reducing pressure on the 
grid and thereby improving electricity system reliability. These 
considerations all support basing the BSER on the combination of all 
four building blocks. They also support basing the BSER, in the 
alternative, on the combination of building block 1 and reduced 
generation in the amounts facilitated by the remaining building blocks.
    As has been discussed in earlier portions of the preamble, the 
costs and energy impacts of each of the four building blocks 
individually are reasonable when viewed either at the individual source 
level or through the lens of the electricity system as a whole, a 
conclusion that holds for the combination of the building blocks as 
well. Moreover, the flexibility available to states and regulated 
entities to rely more extensively in their plans and strategies on 
whichever measures best suit their particular circumstances will 
further improve cost effectiveness. The analysis the EPA performed to 
assess the costs, benefits, and other impacts of the proposed goals 
reflects this compliance flexibility, along with transmission and 
pipeline capabilities and constraints, fuel market and electricity 
dispatch dynamics, and seasonal electricity load requirements. As 
described below in Section X, the results indicate that the proposed 
state goals (discussed in Section VII) are readily achievable with no 
adverse impacts on electricity system reliability, and that impacts on 
retail electricity prices are modest and fall within the range of price 
variability seen historically in response to changes in factors such as 
weather and fuel supply. Further, the costs tend to decline over time 
as states and regulated entities take advantage of the available 
flexibility and expand deployment of more cost-effective measures 
(notably demand-side energy efficiency). The EPA considers this 
analysis strong confirmation of the reasonableness of the costs of the 
measures in the four building blocks in combination as the best system 
of emission reduction.
6. Additional Considerations Related to Inclusion of Building Blocks 2, 
3, and 4 as Part of the Basis Supporting the BSER
    In this section, we discuss additional reasons why the measures in 
building blocks 2, 3, and 4, individually and in combination, meet the 
requirements to be components of the BSER. In particular, we discuss 
why they meet the definition of a ``system of emission reduction,'' and 
we provide additional reasons why they are the ``best'' that is 
``adequately demonstrated.'' The interconnected nature of the electric 
system is an important part of our reasoning.
a. ``System of Emission Reduction''
    For the convenience of the reader, it is useful to reiterate the 
key CAA section 111 requirements: Section 111(d)(1) requires that each 
state's plan ``establish[] standards of performance for any existing 
source'' for certain types of air pollutants; and section 111(a)(1) 
defines a ``standard of performance'' as ``a standard for emissions . . 
. which reflects the degree of emission limitation achievable through 
the application of the best system of emission reduction . . . 
adequately demonstrated.'' These provisions require that, in this 
rulemaking, the affected sources must be subject to emissions 
standards, but the basis for those standards--the ``system of emission 
reduction''--may be any method that reduces the affected sources' 
emissions, as long as that method is a ``system'' that meets the 
criteria for being the ``best'' that is ``adequately demonstrated.''
    As discussed in the Legal Memorandum, the EPA is justified in 
adopting this interpretation under the first step of the framework for 
administrative agencies to construe statutes that the U.S. Supreme 
Court established in Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-844 
(1984) (Chevron), which we refer to as Chevron step 1.
    Specifically, the term ``system,'' which is not defined in the CAA, 
is broad: ``A set of things working together as parts of a mechanism or 
interconnecting network.'' \220\ The

[[Page 34886]]

remaining provisions of the definition of ``standard of performance'' 
do not include any constraints on the ``set of things'' that may 
constitute a ``system of emission reduction.'' Nor does the context in 
which ``standard of performance'' is found--the provisions of section 
111(d)(1)--add constraints on the things that may constitute such a 
system. Rather, it is clear from these CAA provisions that anything 
that reduces the emissions of affected sources may be considered a 
``system of emission reduction'' for those sources. For this reason, 
the measures in building blocks 2, 3, and 4 must be considered 
components of such a system.
---------------------------------------------------------------------------

    \220\ Oxford Dictionary of English (3rd ed.) (published 2010, 
online version 2013), http://www.oxfordreference.com.mutex.gmu.edu/view/10.1093/acref/9780199571123.001.0001/acref-9780199571123.
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    Even if these CAA provisions leave room for interpretation as to 
whether those measures must be considered components of such a system, 
the EPA's interpretation that they do is reasonable. As discussed in 
the Legal Memorandum, the EPA is justified in adopting this 
interpretation under the second step of the Chevron framework, which we 
refer to as Chevron step 2. There are several reasons. In enacting the 
CAA, Congress established ``pollution prevention'' as a ``primary 
goal'' of the Act, and described it as ``the reduction or elimination, 
through any measures, of the amount of pollutants produced or created 
at the source.'' \221\ Building blocks 2, 3, and 4 are pollution 
prevention measures, and, in light of the importance of pollution 
prevention in the CAA, it is reasonable to interpret ``system of 
emission reduction'' in section 111 to incorporate those measures. In 
addition, the breadth of ``system of emission reduction'' is confirmed 
by contrasting it with other provisions in the CAA that prescribe 
specific types of controls as the basis for emission limits.\222\ 
Further support is found in Title IV of the CAA, in which Congress 
established the program that regulates fossil fuel-fired power plants 
to reduce their emissions of SO2 and NOX, the 
precursors to acid deposition. In designing Title IV, Congress 
recognized the integrated nature of the electricity sector and how that 
integration could be harnessed to reduce air pollutant emissions. In 
fact, Congress included provisions to encourage re-dispatch to lower-
emitting sources, renewable energy, and demand-side energy efficiency, 
all of which are measures in those building blocks.\223\ All this 
supports the reasonableness of interpreting ``system of emission 
reduction'' in CAA section 111 to incorporate those measures. It should 
also be noted that a number of commentators in the private sector and 
academia have indicated support for interpreting the term, ``system of 
emission reduction'' to base the CAA section 111(d) standards of 
performance on measures such as re-dispatch, renewable energy, and 
demand-side energy efficiency.\224\ Some stakeholders have as 
well.\225\
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    \221\ CAA Sec.  101(a)(3), (c).
    \222\ For example, as discussed in the Legal Memorandum, CAA 
Sec.  407(b)(2) requires the EPA to base the nitrogen oxides 
(NOX) emission limits for certain types of boilers ``on 
the degree of reduction achievable through the retrofit application 
of the best system of continuous emission reduction . . . ;'' and 
further requires the EPA to revise previously promulgated emission 
limits for certain types of boilers ``to be more stringent if the 
[EPA] determines that more effective low NOX burner 
technology is available.'' (Emphasis added.)
    \223\ CAA Sec.  401(b), 404(f)-(g).
    \224\ See Nordhaus R., Gutherz I., ``Regulation of 
CO2 Emissions from Existing Power Plants Under Sec.  
111(d) of the Clean Air Act: Program Design and Statutory 
Authority,'' Environmental Law Reporter, 44: 10366, 10384 (May 2014) 
(``strong arguments for'' interpreting ``system'' to include 
measures such as the addition of new zero-carbon generating capacity 
and increases in end-user energy efficiency); Sussman R., ``Power 
Plant Regulation Under the Clean Air Act: A Breakthrough Moment for 
U.S. Climate Policy?'' Virginia Environment Law Journal, 32:97, 119 
(2014) (``EPA would seem to have discretion to define `system' to 
include any mix of strategies effective in reducing emissions.''); 
Konschnik K., Peskoe A., ``Efficiency Rules: The Case for End-Use 
Energy Efficiency Programs in the Section 111(d) Rule for Existing 
Power Plants,'' Harvard Law School Environmental Law Program--Policy 
Initiative 4 (March 3, 2014) (EPA is authorized to ``consider[ ] . . 
. the entire [electricity grid] system when setting performance 
standards.''); Monast J., Profeta T., Pearson B., Doyle J., 
``Regulating Greenhouse Gas Emissions From Existing Sources: Section 
111(d) and State Equivalency,'' Environmental Law Reporter, 42: 
10206, 10209 (March 2012) (``Demand-side energy-efficiency programs 
and renewable energy generation may fit within the Sec.  111 
framework, however, because both reduce the utilization of power 
plant. . . . According to this reasoning, emission reductions are 
occurring within the source category, because of changes in 
generation at the power plant.'').
    \225\ Ceronsky M., Carbonell T., ``Section 111(d) of the Clean 
Air Act: The Legal Foundation for Strong, Flexible & Cost-Effective 
Carbon Pollution Standards for Existing Power Plants,'' 
Environmental Defense Fund, at 9 (Oct. 2013), available at http://www.edf.org/sites/default/files/111-clean_air_act-strong_flexible_cost-effective_carbon_pollution_standards_for_existing_power_plants.pdf; Doniger D., ``Questions and Answers on 
the EPA's Legal Authority to Set `System Based' Carbon Pollution 
Standards for Existing Power Plants under Clean Air Act Section 
111(d),'' NRDC [Natural Resources Defense Council] Issue Brief (Oct. 
2013); ``Comments of the Attorneys General of New York, California, 
Massachusetts, Connecticut, Delaware, Maine, Maryland, New Mexico, 
Oregon, Rhode Island, Vermont, Washington, and the District of 
Columbia on the Design of a Program to Reduce Carbon Pollution from 
Existing Power Plants'' (Dec. 16, 2013).
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b. ``Best'' System That Is ``Adequately Demonstrated
    As described earlier with respect to the individual building 
blocks, the measures in each of building blocks 2, 3, and 4 meet the 
criteria for the ``best'' system of emission reduction, and, generally 
for the same reasons, the three in combination do as well.
    In addition, the measures in building blocks 2, 3, and 4, 
individually and in combination, are ``adequately demonstrated.'' As 
discussed earlier, thanks to the integrated nature of the electricity 
system, they have long been relied on to reduce costs in general, 
assure reliability, and implement pre-existing pollution control 
requirements in the least-cost manner. As also noted elsewhere in the 
preamble, and discussed in more detail in the following subsections, 
some utilities, states and regions are already relying on these 
measures for the specific purpose of reducing CO2 emissions 
from EGUs.
(i) Actions by Affected EGUs
    Measures in building blocks 2, 3, and 4 may be undertaken or 
invested in by the affected EGUs themselves, which supports that these 
measures are ``adequately demonstrated.'' More specifically, the EPA 
believes that owners of units operating across a wide range of 
corporate, institutional and market structures (e.g., vertically 
integrated utilities in regulated markets, independent power producers, 
municipal utilities, and rural cooperatives) can take advantage of a 
broad range of reduction opportunities included in the building blocks. 
Because of the proposed lengthy planning period, owners can consider 
longer-term options such as implementing energy efficiency programs or 
replacement of older generating resources with more modern types of 
generation, as well as shorter-term options such as heat rate 
improvements and re-dispatch. Many companies, for example, already 
factor a carbon cost adder into their long-term planning decisions.
    Large vertically integrated utilities generally have options within 
all four building blocks. They tend to have large and, as a general 
matter, at least somewhat diverse generation fleets. For their higher-
emitting units, they have opportunities to use measures that reduce the 
units' CO2 emission rates, such as heat rate improvements, 
co-firing, or fuel switching. While this proposal preserves fuel 
diversity, with over 30 percent of projected 2030 generation coming 
from coal and over 30 percent from natural gas, even companies that 
have traditionally depended upon coal to supply the majority of their 
generation are diversifying their fleets, increasing their

[[Page 34887]]

opportunities for re-dispatch.\226\ Within the 5-to-15-year planning 
horizon established in this proposal to begin in June 2015, most of 
these companies are likely to be investing in new generation and can 
consider options such as increased reliance on new renewable generating 
capacity. They also run energy efficiency programs for their customers.
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    \226\ http://online.wsj.com/article/PR-;CO-20140508-
;915605.html.
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    Municipal utilities and rural cooperatives that own generating 
asset portfolios also have multiple options for reducing CO2 
emissions, particularly generation and transmission cooperatives and 
larger municipal utilities. They can implement unit-specific 
improvements, re-dispatch to lower emitting resources, employ energy 
efficiency and renewable energy strategies, and explore longer-term 
capacity planning strategies. For cooperatives and municipal utilities 
with smaller fleets, re-dispatching among their own units may not 
provide as many opportunities, particularly in the short term. But 
because of the timing flexibility in the guidelines, these owners can 
use both short-term dispatch strategies and longer-term capacity 
planning strategies to reduce GHG emissions, and in many cases 
financing is available at tax-advantaged or subsidized rates. At the 
same time, in formulating their plans, states will be in a position to 
recognize the distinctive attributes of smaller utilities--and, of 
course, may consider participating in integrated multi-state compliance 
strategies to increase the flexibility and cost-saving opportunities 
that would be available to the covered EGUs.
    Some stakeholders have expressed concerns that municipal utilities 
and rural cooperatives can face other challenges as well. According to 
these stakeholders, in deregulated areas, even though these utilities 
may be fully vertically integrated entities, they may not have as much 
flexibility to control dispatch because they are operating in a 
competitive market, where they can be in a position in which they need 
to operate if called upon. Even in this case, the timing flexibility of 
the rule allows them to consider longer-term capacity planning 
strategies. These can include building or contracting for electric 
supply from lower-emitting sources, use of distributed renewable 
technologies, and use of demand-side energy efficiency measures. There 
are a number of municipal utilities and rural cooperatives that are 
already aggressively pursuing such strategies.\227\ Nevertheless, in 
recognition of stakeholders' expressed concerns, we invite comment on 
whether there are special considerations affecting small rural 
cooperative or municipal utilities that might merit adjustments to this 
proposal, and if so, possible adjustments that should be considered.
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    \227\ For examples, see Large Public Power Council, Energy 
Efficiency Working Group, Second Annual Energy Efficiency 
Benchmarking Report (2013); https://www.nreca.coop/nreca-on-the-issues/energy-operations/energy-efficiency/.
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    Independent power producers (IPPs) may also face unique challenges 
but nevertheless have options. Companies with coal-fired EGUs can 
implement efficiency improvements as well as other unit-level 
compliance options such as co-firing or fuel switching. While these 
types of companies do not use the integrated resource planning process 
that many vertically integrated utilities use, they still undertake 
long-term business planning and as a result are in a position to 
consider different long-term strategies related to their generating 
assets. Many IPPs are actively developing renewable generating capacity 
and natural gas-fired generating capacity. IPP owners could also fund 
demand-side energy efficiency programs and document the resulting 
electricity savings.
(ii) Actions by States
    Another reason why the measures in building blocks 2, 3, and 4 are 
``adequately demonstrated'' is that states may adopt them and, in fact, 
many states have already adopted many of them.
    For example, several states have already adopted renewable energy 
(RE) and demand-side energy efficiency (EE) measures in their CAA 
section 110 state implementation plans (SIPs) for attaining and 
maintaining the national ambient air quality standards (NAAQS). The EPA 
has provided initial guidance for states to do so.\228\ Some state air 
agencies did so for their 1997 8-hour ozone NAAQS SIPs that were due in 
2007; for example, Washington, DC, included the purchase of wind power 
and the installation of LED traffic lights \229\; Dallas, Texas 
included efficiency measures from the Texas Emissions Reduction Program 
(TERP) \230\; and Connecticut included projects such as high efficiency 
air conditioners, compact fluorescent lighting, combined heat and power 
(CHP), and solar photovoltaic installations.\231\ Since that time, many 
states have adopted legislative mandates for energy efficiency or 
renewable energy, and states have expressed interest in including EE/RE 
policies and programs in upcoming NAAQS SIPs. The EPA has provided 
additional guidance \232\ and has partnered with the Northeast States 
for Coordinated Air Use Management (NESCAUM) and three states 
(Maryland, Massachusetts, and New York) to identify opportunities for 
including EE/RE in a NAAQS SIP and to provide real-world examples and 
lessons learned through those states' case studies.\233\
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    \228\ See, e.g., Guidance on SIP Credits for Emission Reductions 
from Electric-Sector Energy Efficiency and Renewable Energy Measures 
(Aug. 2004), http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf; Incorporating Emerging and Voluntary Measures in a State 
Implementation Plan (SIP) (Sept. 2004), http://www.epa.gov/ttn/oarpg/t1/memoranda/evm_ievm_g.pdf.
    \229\ DC Region 8-hour ozone SIP at 126, http://www.mwcog.org/uploads/pub-documents/9FhcXg20070525084306.pdf.
    \230\ Dallas/Ft. Worth, Texas 8-hour ozone SIP, http://www.gpo.gov/fdsys/pkg/FR-2008-08-15/pdf/E8-18835.pdf.
    \231\ CT 1997 8-hour ozone SIP Web site, http://www.ct.gov/deep/cwp/view.asp?a=2684&q=385886&depNav_GID=1619 (see Attainment 
Demonstration TSD, Chapter 8 at 31, http://www.ct.gov/deep/lib/deep/air/regulations/proposed_and_reports/section_8.pdf).
    \232\ Roadmap for Incorporating EE/RE Policies and Programs into 
SIPs/TIPs (July 2012), http://epa.gov/airquality/eere/manual.html.
    \233\ States' Perspectives on EPA's Roadmap to Incorporate 
Energy Efficiency/Renewable Energy in NAAQS State Implementation 
Plans: Three Case Studies, Final Report to the U.S. Environmental 
Protection Agency (Dec. 2013), http://www.nescaum.org/documents/nescaum-final-rept-to-epa-ee-in-naaqs-sip-roadmap-case-studies-20140522.pdf.
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    It should be recognized that each state's electric utility sector 
operates under distinctive conditions and circumstances. The EPA's 
proposal ensures that states retain flexibility to craft standards of 
performance that can accommodate characteristics including fuel 
sources, types of EGU owners within a state (e.g., investor-owned, 
municipal, and cooperative utilities, and independent power producers), 
and regulatory structure (e.g., regulated or restructured). States can 
tailor their regulatory mechanisms to recognize differences, for 
example by creating budgets on a company-wide basis or using market-
based mechanisms such as mass-based trading systems, to ensure that 
requirements are achievable.
    The proposal also recognizes that states have different resource 
bases and energy policies in place, and these differences are taken 
into account in the state goal-setting and computation process. For 
instance, while the EPA's BSER assumptions consider re-dispatch to NGCC 
units, they do not consider re-dispatch beyond the NGCC capacity 
already existing in a state. In that way, the proposal does not presume 
that

[[Page 34888]]

states with limited natural gas generation or infrastructure will have 
to develop those resources.
    Furthermore, while the BSER reflects best practices for both 
renewables and energy efficiency, it also recognizes that some states 
have made more progress than others in these areas. The BSER allows 
time for states to ramp up to greater levels of energy efficiency and 
use and development of renewable energy resources, should they choose 
those approaches. With respect to renewable energy, the proposal also 
recognizes that different areas of the country have different resource 
bases and does not presume that a uniform level of penetration of 
renewable generation is appropriate for every state.
    The features provided in this proposal to ensure policy flexibility 
can be used by all states to address their unique circumstances. In a 
regulated state, if a company's compliance strategies included reducing 
generation at higher-emitting EGUs, it would work through its state's 
integrated planning process to ensure that adequate generation was 
available through a combination of all four building blocks. Cost 
recovery, and cost oversight, can be achieved through rate cases before 
state regulators. In a restructured state, even if affected companies 
responded to the guidelines by reducing generation without themselves 
replacing that generation, the electricity markets that have developed 
would react to ensure the availability of replacement generation. Other 
companies would see opportunities to build or ramp up existing lower-
emitting generation, and in some markets that treat demand-side 
resources on par with supply side resources, energy service companies 
would likely see opportunities. Further, state regulators can continue 
to play an important role in restructured states as well, authorizing 
or reviewing both renewable energy procurement and demand-side energy 
efficiency programs. In all types of market structures, large energy 
users might independently see additional energy efficiency 
opportunities or opportunities for self-generation using options such 
as combined heat and power, solar, or power purchase agreements, and 
states can structure their plans to allow the CO2 reductions 
achieved at affected EGUs through such actions to assist in reaching 
compliance. As discussed in earlier portions of this section and 
elsewhere in the preamble, each of the building blocks is already being 
widely implemented, is consistent with industry trends, and consists of 
CO2 reduction methods already widely accepted in the eyes of 
various stakeholders, as was clear from views expressed in our outreach 
process.
    Moreover, there are mechanisms through which states could require 
measures from any of the building blocks in state plans. In fact, the 
state plan formulation process through which CAA section 111(d) is 
implemented reinforces the determination that these measures are 
components of the BSER. For example, states would have authority to 
impose measures such as best practices for operation and maintenance of 
EGUs, dispatch limits, renewable energy resource requirements, and 
demand-side energy efficiency requirements. States also would have 
authority to establish requirements that change the relative costs of 
generation from more carbon-intensive and less carbon-intensive EGUs, 
for example by creating emission allowance systems that cause market 
participants and system operators to take account of CO2 
emission rates as an element of variable operating costs. Such an 
approach can encourage measures from all of the building blocks 
simultaneously. As noted elsewhere in the preamble, many states have 
already pursued one or more of these approaches.\234\
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    \234\ See the discussions of California California Global 
Warming Solutions Act and RGGI above in this section and elsewhere 
in the preamble.
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    It also should be noted that during the public outreach sessions, 
stakeholders generally recommended that state plans be authorized to 
rely on, and that affected sources be authorized to implement, re-
dispatch, renewable energy measures, and demand-side energy efficiency 
measures in order to meet states' and sources' emission reduction 
obligations. The EPA agrees that state plans may include these 
measures, at least under certain circumstances, as discussed in Section 
VIII, and that sources may rely on them to achieve required reductions. 
It is clear that these types of measures are well-accepted by the 
stakeholders as means to reduce emissions from affected sources. The 
fact that state plans and sources would be expected to use these types 
of measures to reduce emissions supports the view that these measures 
are part of a ``system of emission reduction'' for those sources that 
the EPA may evaluate against the appropriate criteria to determine 
whether they comprise the ``best system of emission reduction . . . 
adequately demonstrated.''
(iii) Regional Organizations
    Another reason why the measures in building blocks 2, 3, and 4 are 
``adequately demonstrated'' is that they can be accommodated through 
the existing regional components of the electricity system.
    On the regional level, ISO/RTOs control dispatch and are 
responsible for reliable operation of the bulk power system.\235\ They 
can seek solutions, such as capacity markets and transmission upgrades, 
to preserve resource adequacy and ensure the continued reliable 
operation of the grid. For this proposal, the ISO/RTO Council has 
already submitted a set of recommendations they believe can help 
balance the needs of lower emissions, economic dispatch, and 
reliability, which is discussed in greater detail in Section VIII.F.7 
of this proposal.\236\ For areas of the country that are not covered by 
an ISO/RTO, there are regional groups, such as ColumbiaGrid, Northern 
Tier Transmission Group and WestConnect in the west, and system 
operators such as Southern Company in the southeast, that can provide 
these functions. In shifting to lower-emitting units, grid operators 
across the country factor environmental costs into their economic 
dispatch through a variety of mechanisms, including allowance costs, 
variable costs associated with operating environmental controls, and 
operating limits for high-emitting units.
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    \235\ Across all markets, at the federal level, FERC and NERC 
create and oversee standards for reliability. NERC works with 
electric reliability councils and control areas that comprise all 
types of utilities and system operators to ensure that adequate 
generation is available.
    \236\ http://www.isorto.org/Documents/Report/20140128_IRCProposal-ReliabilitySafetyValve-RegionalComplianceMeasurement_EPA-C02Rule.pdf.
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(iv) Concerns From Stakeholders; Solicitation of Comment
    We note that some stakeholders have argued that CAA section 
111(a)(1) does not authorize the EPA to identify re-dispatch, low- or 
zero-emitting generation, or demand-side energy efficiency measures 
(building blocks 2, 3, and 4) as components of the ``best system of 
emission reduction . . . adequately demonstrated.'' According to these 
stakeholders, as a legal matter, the BSER is limited to measures that 
may be undertaken at the affected units, and not measures that are 
beyond the affected units; the measures in building blocks 2, 3, and 4 
are ``beyond-the-unit'' or ``beyond-the-fenceline'' measures because 
they are implemented outside of the affected units and outside their 
control; and as a result, those measures cannot be considered 
components of the BSER.
    We welcome comment on this issue. As discussed above, we propose 
that the

[[Page 34889]]

provisions of CAA section 111 do not by their terms preclude the BSER 
from including those types of measures. In addition, as noted above, 
under our proposed approach, affected sources may themselves implement 
the measures included in building blocks 2, 3, and 4, so that those 
measures are within their control with the result of their application 
being emissions reductions at affected EGUs. Moreover, under our 
alternative approach, the ``system of emission reduction'' includes 
reductions in utilization at the affected sources themselves.\237\ It 
should also be noted that, as discussed above, the re-dispatch measures 
in building block 2 are limited to affected sources. Thus, the proposed 
approach and alternative described above respond to these stakeholder 
concerns.
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    \237\ Commenters have critiqued this ``at-the-unit'' and 
``beyond-the-unit'' distinction as follows:
    There is an argument that the at-the-unit/beyond-the-unit 
distinction is not a meaningful one. Specifically, it could be 
argued that the distinction between at-the-unit and beyond-the-unit 
measures is largely artificial, because all of the emission 
reductions under consideration--whether from at-the-unit measures 
(e.g., fuel-switching or efficiency upgrades) or from beyond-the-
unit measures--are, in fact, emission reductions at or from electric 
generating units on the interconnected electric grid. For example, 
neither the addition of renewable generation nor the reduction of 
end-user demand directly reduces atmospheric emission of 
CO2; rather these measures permit fossil EGUs to reduce 
their own output and emissions. It can be argued that all of the 
systems of emission reduction here contemplated--whether they 
involve end-use energy efficiency, displacing high-emission 
generation with lower emission generation, fuel-switching, heat-rate 
improvements, etc.--are effectively at-the-unit measures that 
ultimately reduce emissions solely from regulated EGUs. If energy-
efficiency programs, added renewable energy, and redispatch from 
higher emitting facilities to lower emitting facilities are viewed 
as at-the-unit systems of emission reduction, the at-the-unit/
beyond-the-unit distinction arguably becomes irrelevant--at least 
from a legal perspective. Rather, the real issue may come down to 
whether Sec.  111(d) authorizes the EPA to require EGUs to curtail 
their output of electricity as a means of complying with the rule.
    Nordhaus R., Gutherz I., ``Regulation of CO2 
Emissions from Existing Power Plants Under Sec.  111(d) of the Clean 
Air Act: Program Design and Statutory Authority,'' Environmental Law 
Reporter, 44: 10366, 10383 n. 133 (May 2014).
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7. Alternate Approach to the Best System of Emission Reduction
    As an alternative to the approach described above for determining 
the ``best system of emission reduction . . . adequately 
demonstrated,'' the ``system of emission reduction'' may be identified 
as including, in addition to building block 1, the reduction of 
affected fossil fuel-fired EGUs' mass emissions achievable through 
reductions in generation of specified amounts from those EGUs. Under 
this approach, the measures in building blocks 2, 3, and 4 would not be 
components of the system of emission reduction but instead would serve 
as bases for quantifying the reduced generation (and therefore 
emissions) at affected EGUs, and assuring that the amount of reduced 
generation meets the criteria for the ``best'' system that is 
``adequately demonstrated'' because, among other things, the reduced 
generation can be achieved while the demand for electricity services 
can continue to be met in a reliable and affordable manner. 
Specifically, the amount of generation from the increased utilization 
of NGCC units would determine a portion of the amount of the generation 
reduction component of the BSER for affected fossil fuel-fired steam 
EGUs, and the amount of generation from the use of expanded low- and 
zero-carbon generating capacity that could be provided, along with the 
amount of generation from fossil fuel-fired EGUs that could be avoided 
through the promotion of demand-side energy efficiency, would determine 
a portion of the amount of the generation reduction component of the 
BSER for all affected EGUs.
    Reduced generation is encompassed by the terms of the phrase 
``system of emission reduction'' in CAA section 111(a)(1), as a matter 
of Chevron step 1, because, in accordance with the above-discussed 
definition of ``system,'' reduced generation is a ``set of things''--
which include reduced use of generating equipment and therefore reduced 
fuel input--that the affected source may take to reduce its 
CO2 emissions.\238\ If that phrase is not considered clear 
by its terms, then, under Chevron step 2, it may reasonably be 
interpreted to include reduced generation.\239\ As discussed in the 
Legal Memorandum, the legislative history of the 1970 CAA Amendments 
indicates that Congress recognized that emitting sources could comply 
with pollution control requirements by reducing production, including 
retiring.\240\ As also noted in the Legal Memorandum, examples of 
reduced utilization as a means of reducing emissions are found in 
settlement agreements between the EPA and fossil fuel-fired EGUs to 
resolve alleged violations of the CAA new source review (NSR) 
requirements.\241\
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    \238\ For this reason, under a Chevron step 1 interpretation, 
``system of emission reduction'' includes reduced generation.
    \239\ For these reasons, under a Chevron step 2 interpretation, 
``system of emission reduction'' includes reduced generation.
    \240\ See CAA section 110(g) (authorizing temporary emergency 
suspensions of SIP revisions if needed to prevent the closing of a 
source of air pollution), enacted as CAA section 110(f) in the 1970 
CAA Amendments; 116 Cong. Rec. 42384 (Dec. 18, 1970), reprinted in 
Congressional Research Service, A Legislative History of the Clean 
Air Act Amendments of 1970, vol. 1, at 132-33 (1974) (statement of 
Sen. Muskie) (discussing criteria for sources to receive compliance 
date extensions). Sen. Muskie added that the emission standards set 
by the EPA for hazardous air pollutants ``could include emission 
standards which allowed for no measureable emissions,'' id., which 
further suggests that, as a practical matter, the standards could 
result in reduced production.
    \241\ See, e.g., Consent Decree at 18, United States v. Wis. 
Power & Light Co., No. 13-cv-266 (W.D. Wis. filed Apr. 22, 2013), 
available at http://www2.epa.gov/sites/production/files/documents/wisconsinpower-cd.pdf.
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    Reduction of, or limitation on, the amount of generation is already 
a well-established means of reducing emissions of pollutants in the 
electric sector, notwithstanding the fact that as a practical matter, 
some facilities may have to operate, or remain available, to ensure 
system reliability. For example, reduced generation by higher-emitting 
sources is one of the compliance options available to, and used by, 
EGUs to comply with the Clean Air Act acid rain program in CAA title 
IV, as well as the transport rules that we refer to as the 
NOX SIP Call \242\ and the Clean Air Interstate Rule 
(CAIR).\243\ Reduction in generation is also a possible means by which 
an EGU can achieve compliance with its requirements under RGGI.
---------------------------------------------------------------------------

    \242\ 63 FR 57356 (Oct. 27, 1998).
    \243\ 70 FR 25162 (May 12, 2005).
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    Reduced generation in specified amounts is part of the ``best'' 
system of emission reduction that is ``adequately demonstrated.'' 
Reduced generation is technically feasible because of a source's 
ability to limit its own operations. In addition, the amounts of 
generation and emission reductions may be determined with precision 
through the application of building block 2, 3, and 4 measures for 
increased generation from low- or zero-emitting sources and increased 
demand-side energy efficiency, which, in turn, ensure the reliability 
of the electricity grid and the affordability of electricity to 
businesses and consumers.
    Because of the availability of the measures in building blocks 2, 
3, and 4, the proposed levels of reduced generation are of reasonable 
cost for the affected source category and the nationwide electricity 
system, do not jeopardize reliability, result in an important amount of 
emission reductions, are consistent with current trends in the 
electricity sector, and promote the development and implementation of 
technology that is important for continued emissions reductions. All 
these results come about because the operation of the electrical

[[Page 34890]]

grid through integrated generation, transmission, and distribution 
networks creates fungibility for electricity and electricity services, 
which allows decreases in generation at affected fossil fuel-fired 
steam EGUs to be replaced by increases in generation at affected NGCC 
units (building block 2) and allows decreases in generation at all 
affected EGUs to be replaced by increased generation at low- or zero-
carbon EGUs (building block 3) or by decreased demand (building block 
4). Further, this fungibility increases over longer timeframes with the 
opportunity to invest in infrastructure improvements, and as noted 
elsewhere, this proposal provides an extended state plan and source 
compliance horizon. These characteristics of the integrated electricity 
system assure that reduced generation in specified amounts meets the 
criteria to qualify as part of the ``best'' system of emission 
reduction.
    Reduced generation in those amounts is also ``adequately 
demonstrated.'' As noted above, the measures in building blocks 2, 3, 
and 4 are already in widespread use in the industry. At the levels 
proposed, they have the technical capability to substitute for reduced 
generation at some or all affected EGUs at reasonable cost. The NGCC 
capacity necessary to accomplish the levels of generation reduction 
proposed for building block 2 is already in operation or under 
construction. Moreover, it is reasonable to expect that the incremental 
resources reflected in building blocks 3 and 4 will develop at the 
levels requisite to ensure an adequate and reliable supply of 
electricity at the same time that affected EGUs may choose or be 
required to reduce their CO2 emissions by means of reducing 
their utilization. There are several reasons for this. First, the 
affected sources themselves could invest in new renewable energy 
resources and demand-side energy efficiency, as discussed above.\244\ 
Second, the states, as part of their plans, have mechanisms available 
to put these substitutes in place: They could establish requirements or 
incentives that would result in new renewable energy and demand-side 
energy efficiency programs, as also discussed above.\245\ Third, as 
also discussed above, regional entities in the electricity system can 
accommodate these substitutes.
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    \244\ It should be noted that in light of the low current and 
projected near term prices for natural gas, market forces may lead 
investors to choose to build new NGCC units, rather than new 
renewable resources. This result would not call into question the 
technical feasibility of a BSER that included reductions in fossil 
fuel-fired generation by the amount of a specified amount of new 
renewable resources. This is because under these circumstances, the 
fossil fuel-fired generators could still reduce their generation 
without causing reliability or other problems in the electric power 
system.
    \245\ The nuclear generating capacity reflected in building 
block 3 is already in operation or under construction.
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    Most broadly, with respect to the measures in building blocks 2, 3, 
and 4, provided there is sufficient lead time for planning, mechanisms 
are in place in both regulated and deregulated electricity markets to 
assure that substitute generation will become available and/or steps to 
reduce demand will be taken to compensate for reduced generation by 
affected EGUs. These mechanisms are based on, among other things, the 
integrated nature of the electricity system coupled with the 
availability of capacity in existing NGCC units, the growing 
institutional capacity of entities that develop renewable energy and 
demand-side energy efficiency resources, and the ability of system 
operators and state regulators to incentivize further development of 
those resources.
    The EPA solicits comment on whether measures in addition to those 
in building blocks 2, 3, and 4 could support the showing that reduced 
utilization is ``adequately demonstrated,'' including additional NGCC 
capacity that may be built in the future, as discussed in Section 
VI.C.5.c above.
8. The EPA's Discretion in Applying the Criteria for the Best System of 
Emission Reduction
    As discussed above, each of the approaches to determining the 
``best system of emission reduction . . . adequately demonstrated'' 
entails applying the criteria described in the D.C. Circuit case law 
for evaluating the BSER. It should be emphasized that under the case 
law, the EPA has significant discretion in weighing the different 
criteria, and may weigh them differently in different rulemakings.
    For the present proposal, the EPA is heavily weighting three 
criteria in particular: The amount of emission reductions, the cost of 
achieving those reductions, and the promotion of technology 
implementation--while also noting that the proposed BSER determination 
readily meets the other criteria as well. The EPA considers it 
especially important in this rulemaking, while ensuring that 
electricity system reliability is preserved and that costs are not 
unreasonable, to achieve a significant amount of emissions reductions 
in response to the urgency and the magnitude of the need to mitigate 
climate change. The EPA discusses this above in the sections concerning 
the scientific background for this rulemaking. The EPA also considers 
it especially important for the present proposal that the overall costs 
of achieving the emission reductions should be reasonable. Costs can be 
minimized through the flexibility to choose from a broad range of 
CO2 emission reduction measures, as is provided in the 
portion of this proposal addressing state plans, and a similarly broad 
range of emission reduction measures, represented by the four building 
blocks discussed above, should serve as the basis supporting the BSER. 
Finally, the EPA also considers it especially important for the present 
proposal to promote technological innovation and development of, in 
particular, the measures in building blocks 3 and 4 (to reiterate, low- 
or zero-carbon electricity generation and demand-side energy 
efficiency, respectively). Promoting innovation in, and market 
penetration of, these technologies and practices is critical to making 
the substantial reductions in emissions that will be required during 
the next few decades to reduce the risks to public health and welfare 
and our economic well-being of dangerous climate change.
    In addition, in this rulemaking, the EPA is determining the BSER in 
a manner that is consistent with, and that provides further impetus 
for, current trends in the nation's electricity system that offer 
promise to reduce the carbon intensity of the system over the near- and 
long-term, while maintaining reliability and affordability. This 
approach is consistent with the case law, which authorizes the EPA to 
determine BSER by ``balanc[ing] long-term national and regional 
impacts,'' and by ``using a long-term lens with a broad focus on future 
costs, environmental and energy effects of different technological 
systems. . . .'' \246\
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    \246\ Sierra Club v. Costle, 657 F.2d 298, 331 (D.C. Cir. 1981).
---------------------------------------------------------------------------

9. State-Wide Application of the BSER; Appropriateness of Standards of 
Performance
    An important aspect of the BSER for affected EGUs is that the EPA 
is proposing to apply it on a statewide basis. The statewide approach 
also underlies the required emission performance level, which is based 
on the application of the BSER to a state's affected EGUs, and which 
the suite of measures in the state plan, including the emission 
standards for the affected

[[Page 34891]]

EGUs, must achieve overall. The state has flexibility in assigning the 
emission performance obligations to its affected EGUs, in the form of 
standards of performance--and, for the portfolio approach, in imposing 
requirements on other entities--as long as, again, the required 
emission performance level is met.
    This state-wide approach both harnesses the efficiencies of 
emission reduction opportunities in the interconnected electricity 
system and is fully consistent with the principles of federalism that 
underlie the Clean Air Act generally and CAA section 111(d) 
particularly. That is, this provision achieves the emission performance 
requirements through the vehicle of a state plan, and provides each 
state significant flexibility to take local circumstances and state 
policy goals into account in determining how to reduce emissions from 
its affected sources, as long as the plan meets minimum federal 
requirements.
    In this subsection, we describe how this approach, and the 
standards of performance for the affected EGUs that the states will 
establish through the process we describe, are consistent with the CAA 
section 111(d)(1) and (a)(1) provisions.
    For convenience, we set out the requirements of CAA section 
111(d)(1) and (a)(1) here: Under CAA section 111(d)(1), the state must 
adopt a plan that ``establishes standards of performance for any 
existing source.'' Under CAA section 111(a)(1), a ``standard of 
performance'' is a ``standard for emissions . . . which reflects the 
degree of emission limitation achievable through the application of the 
best system of emission reduction . . . adequately demonstrated.'' The 
EPA proposes to interpret these provisions as set forth in this sub-
section.
    The first step is for the EPA to determine the ``best system of 
emission reduction . . . adequately demonstrated.'' As discussed at 
length elsewhere, the EPA is proposing two alternative BSER. The first 
is the measures in building blocks 1 through 4 combined. This includes 
operational improvements and equipment upgrades that the coal-fired 
steam EGUs in the state may undertake to improve their heat rate by, on 
average, six percent and increases in, or retention of, zero- or low-
emitting generation, as well as measures to reduce demand for 
generation, all of which, taken together, displace, or avoid the need 
for, generation from the affected EGUs. This BSER is a set of measures 
that impacts affected EGUs as a group. The alternative approach to BSER 
is building block 1 combined with reduced utilization from the affected 
EGUs in the state as a group, in the amounts that can be replaced by an 
increase in, or retention of, zero- or low-emitting generation, as well 
as reduced demand for generation.
    After determining the BSER, the EPA then applies the BSER to each 
state's affected EGUs, on a state-wide basis. Building block 1 is 
applied to the coal-fired steam EGUs on a statewide basis; building 
block 2 is applied to increase the generation of the NGCC units in the 
state up to certain amounts, and decrease the amount of generation from 
steam EGUs accordingly; and the measures in building blocks 3 and 4 are 
applied to reduce, or avoid, generation from all affected EGUs on a 
state-wide basis. Under the alternative formulation of the BSER, the 
total amount of reduced generation from the affected EGUs in the state, 
associated with the measures in building blocks 2, 3, and 4, is 
determined on the basis of each state's affected EGUs as a group.
    This statewide approach to applying the BSER is consistent with the 
CAA section 111(a)(1) definition of ``standard of performance,'' which, 
as quoted above, refers to ``the application of the [BSER],'' for the 
purpose of determining ``the degree of emission limitation 
achievable,'' but does not otherwise constrain how the BSER is to be 
applied.
    As a result, the EPA may apply the BSER to all of the affected EGUs 
in the state as a group. Similarly, the implementing regulations give 
the EPA broad discretion to identify the group of sources to which the 
BSER is applied. The regulations provide that the EPA ``will specify 
different emission guidelines or compliance times or both for different 
sizes, types, and classes of designated facilities when costs of 
control, physical limitations, geographical location, or similar 
factors make subcategorization appropriate.'' Applying the BSER to the 
affected EGUs in each state as a group is appropriate, and therefore is 
consistent with these regulations.
    As part of applying the BSER, the EPA, to return to provisions of 
CAA section 111(a)(1), calculates the ``emission limitation achievable 
through the application of the [BSER].'' In this rulemaking, we refer 
to this amount as the state goal. As noted, the EPA expresses the state 
goal in the emission guidelines as an emission rate.
    The state must develop a state plan that achieves the state goal, 
either in the form of an emission rate, as specified for the state in 
the emission guidelines, or a translated mass-based version of the 
rate-based goal. We refer to the state goal, in the form used by the 
state as the foundation of its plan, as the required emission 
performance level.
    As part of its state plan, the state must establish ``standards of 
performance'' for its affected EGUs. To do so, the state may consider 
the measures the EPA identified as part of the BSER or other measures 
that reduce emissions from the affected EGUs. Moreover, the state has 
the flexibility to establish emission standards in the degree of 
stringency that the state considers appropriate. The primary limitation 
on the state's flexibility is that the emission standards applied to 
all of the state's affected EGUs--and, in the case of states that adopt 
the portfolio approach, the requirements imposed on other affected 
entities--taken as a whole, must be demonstrated to achieve the 
required emission performance level. In addition, the state may make 
the emission standards for any of its affected EGUs sufficiently 
stringent, so that the standards and any requirements imposed on other 
affected entities (if relevant), taken as a whole, achieve a level of 
emission performance that is better than the required emission 
performance level. See CAA section 116, 40 CFR 60.24(g).
    Under these circumstances--that the emission standards that the 
state establishes for its affected EGUs and any other requirements for 
the other affected entities, as relevant, taken together, are at least 
as stringent as necessary to achieve the required emission performance 
level for the state's affected EGUs--each emission standard that the 
state adopts for each of its affected EGUs will meet the definition of 
a ``standard of performance'' under CAA section 111(a)(1). 
Specifically, the ``standard of performance'' for each source will 
constitute, to return to the provisions of CAA section 111(a)(1), ``a 
standard for emissions which reflects [that is, embodies, or 
represents] \247\ the degree [that is, the portion] of emission 
limitation achievable through the application of the [BSER]'' [that is, 
as noted above, the required emission performance level for all 
affected sources in a state]. That ``degree'' or portion of the 
required emission performance level is, in effect, the portion of the 
state's obligation to limit its affected sources' emissions that the 
state has assigned to each particular affected source. An emission 
standard

[[Page 34892]]

meets this definition of the term ``standard of performance'' 
regardless of whether it is part of a plan that adopts the portfolio 
approach (in which case, the standard will reflect a relatively smaller 
part of the emission performance level) or one that imposes the plan's 
emission limitation obligations entirely on the affected EGUs (in which 
case, the standard will reflect a relatively larger part of the 
emission performance level).
---------------------------------------------------------------------------

    \247\ See Oxford Dictionary of English (3rd ed. 2010 (online 
version 2013)) (defining ``reflect'' as, among other things, 
``embody or represent (something) in a faithful or appropriate 
way'').
---------------------------------------------------------------------------

    These proposed interpretations of the provisions of CAA sections 
111(d)(1) and (a)(1) are fully consistent with the EPA's overall 
approach in this rulemaking to determining and applying the BSER and 
identifying the appropriate level of emission performance for the 
affected EGUs. As noted, this approach entails applying the BSER on a 
state-wide basis and, based on the BSER, identifying the emission 
performance level for each state's affected EGUs that each state must 
achieve, so that each state may then assign the emission limitation 
obligations among its sources. As noted, this approach is fully 
consistent with the interconnected nature of the electricity system and 
with the principles of federalism that underlie CAA section 111(d).
    It should be emphasized that each state has many options for 
assigning the emission limitation obligations among its affected 
sources. For example, the state could impose emission standards that 
are consistent with the BSER. Under these circumstances, the state may 
assign to different affected sources emission standards with different 
levels of stringency because the state will have determined that those 
standards are consistent with the nature of each source's participation 
in the state's electricity system. In addition, the state could 
authorize emission trading as part of the emission standards for 
affected sources. Under these circumstances, if an affected source's 
emission level was higher than the standard the state established for 
it, the source could achieve the standard by purchasing additional 
emission rights through the trading program.
    Finally, it should be noted that states retain authority under CAA 
section 116 and 40 CFR 60.24(g) to impose standards of performance 
that, cumulatively, are more stringent than the emission performance 
level.\248\
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    \248\ The EPA's approach may also be characterized as (i) 
determining the BSER for the affected EGUs, (ii) establishing as the 
emission guideline the standard for emissions that the affected EGUs 
in the state can achieve on average through the application of the 
BSER, and (iii) as part of the emission guideline, authorizing each 
state to establish as the applicable standard for each affected EGU, 
the standard that the state considers appropriate and that when 
totaled with the standards established for the other EGUs (and as 
may be adjusted to account for the portfolio approach, if that 
approach is adopted by the state) is at least as stringent as the 
average standard in the emission guideline. As noted in the 
accompanying text, a state has many ways to establish standards that 
meet the CAA requirements, including, for example, following the 
BSER or authorizing emission rate averaging or trading.
---------------------------------------------------------------------------

10. Combined Categories
    As discussed above, the EPA is soliciting comment on combining the 
category of steam EGUs and the category of combustion turbines (which 
include NGCC units) into a single category for fossil fuel-fired EGUs, 
for purposes of promulgating emission guidelines for CO2 
emissions. The EPA solicits comment on whether combining the categories 
is, as a legal matter, a prerequisite for (i) identifying as a 
component of the BSER re-dispatch between sources in the two categories 
(i.e., re-dispatch between steam EGUs and NGCC units), or (ii) 
facilitating averaging or trading systems that include sources in both 
categories, which states may wish to adopt.
11. Severability
    We consider our proposed findings of the BSER with respect to the 
various building blocks to be severable, such that in the event a court 
were to invalidate our finding with respect to any particular building 
block, we would find that the BSER consists of the remaining building 
blocks. The state goals that would result from any combination of the 
building blocks can be computed from data included in the Goal 
Computation TSD and its appendices using the methodology described in 
the preamble and that TSD.
12. Solicitation of Comment
    We invite comment on all aspects of our proposed interpretation and 
alternate interpretation of the BSER for CO2 emissions from 
existing fossil fuel-fired EGUs, both as identified above and as 
further discussed in the Legal Memorandum in the docket.\249\ In 
particular, we invite comment on our analysis of the four building 
blocks as components of the BSER, whether any other potential measures 
should be considered, our analysis of the combinations of building 
blocks 1 and 2 and of all four building blocks, and the legal, 
technical, and economic bases of our conclusions. With regard to 
comments received during the stakeholder meetings, some commenters 
noted that trading programs like RGGI have been successful at reducing 
GHGs, and other commenters provided specific BSER proposals based on 
trading and/or emissions averaging approaches. We specifically request 
comment on whether any of these approaches should be considered as the 
BSER. We also specifically invite comment on the question, raised by 
some stakeholders, as to whether if measures may be relied on in the 
state plan to achieve emissions reductions, they cannot be excluded 
from the scope of the BSER solely because they involve actions by 
entities or at locations other than affected sources.
---------------------------------------------------------------------------

    \249\ However, as noted, we are not soliciting comment on issues 
that were resolved by the implementing regulations.
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VII. State Goals

A. Overview

    In this section, the EPA sets out proposed state-specific 
CO2 emission performance goals to guide states in 
development of their state plans. The proposed goals reflect the EPA's 
quantification of each state's average emission rate from affected EGUs 
that could be achieved by 2030 and sustained thereafter, with interim 
goals that would apply over a 2020-2029 phase-in period, through 
reasonable implementation, considering the unique circumstances of each 
individual state, of the best system of emission reduction adequately 
demonstrated (based on all four building blocks) described above. In 
addition, we are taking comment on a second set of state-specific goals 
that would reflect less stringent application of the same BSER, in this 
case by 2025, with interim goals that would apply over a 2020-2024 
phase-in period. As promulgated in the final rule following 
consideration of comments received, the interim and final goals will be 
binding emission guidelines for state plans.
    The proposed goals are expressed in the form of state-specific, 
adjusted \250\ output-weighted-average CO2 emission rates 
for affected EGUs. However, states are authorized to translate the form 
of the goal to a mass-based form, as long as the translated goal 
achieves the same degree of emission limitation.\251\
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    \250\ As described below, the emission rate goals include 
adjustments to incorporate the potential effects of emission 
reduction measures that address power sector CO2 
emissions primarily by reducing the amount of electricity produced 
at a state's affected EGUs (associated with, for example, increasing 
the amount of new low- or zero-carbon generating capacity or 
increasing demand-side energy efficiency) rather than by reducing 
their CO2 emission rates per unit of energy output 
produced.
    \251\ A method for translating from a rate-based goal to a mass-
based goal is discussed in the Projecting CO2 Emission 
Performance in State Plans TSD.
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    The EPA is also proposing that measures taken by a state or its 
sources

[[Page 34893]]

after the date of this proposal, or programs already in place, and 
which result in CO2 emission reductions at affected EGUs 
during the 2020-2030 period, would apply toward achievement of the 
state's CO2 goal. Thus, states with currently existing 
programs and policies, and states that put in place new programs and 
policies early, will be better positioned to achieve the goals.
    The EPA is proposing to finalize the goal for each state as 
proposed, and adjusted as may be appropriate based on comments. A state 
may demonstrate during the comment period that application of one of 
the building blocks to that state would not be expected to produce the 
level of emission reduction quantified by the EPA because 
implementation of the building block at the levels envisioned by the 
EPA was technically infeasible, or because the costs of doing so were 
significantly higher than projected by the EPA. While the EPA would 
consider this in setting final state goals, the EPA would also consider 
(and would expect commenters to address) whether a similar overall 
state goal could still be achieved through more aggressive 
implementation of one or more of the measures encompassed in the other 
building blocks or through other, comparable measures. For example, if 
a state demonstrates during the public comment period that the state's 
coal-fired steam EGUs could only achieve an average four percent heat 
rate improvement, instead of the six percent that the EPA is proposing 
to determine is achievable from application of building block 1, the 
EPA would not adjust the state's goal to reflect that change unless the 
state also demonstrates that it could not get additional reductions 
from application of building blocks 2, 3 or 4, or in related, 
comparable measures.
    Each of the building blocks establishes a reasonable level of 
reductions, but not necessarily the maximum amount that could be 
achieved if that building block, and no other, were the basis 
supporting the BSER. Together the building blocks establish a 
reasonable overall level of reductions and effort that the EPA 
considers appropriate at this time. This amount of emission reductions 
is significant and will require effort and adjustments throughout the 
electricity sector. In light of the overall effort to achieve the state 
goals based on a combination of all four building blocks at the levels 
specified, the EPA is not proposing a higher level of reductions at 
this time, even though the measures in the building blocks could be 
implemented more stringently to achieve greater emission reductions.
    Because the building blocks each establish a reasonable level of 
emission reduction rather than the maximum possible level of reduction, 
the EPA expects that, for any particular state, even if the application 
of the measures in one building block to that state would not produce 
the level of emission reductions reflected in the EPA's quantification 
for that state, the state will be able to reasonably implement measures 
in other of the building blocks more stringently, so that the state 
would still be able to achieve the proposed goal. Accordingly, the EPA 
proposes that even if a state demonstrates during the comment period 
that application of a building block to that state would not result in 
the level of emission reductions reflected in the EPA's quantification 
for that state, then the state should also explain why the application 
of the other building blocks would not result in greater emission 
reductions than are reflected in the EPA's quantification for that 
state. In light of the fact that the building blocks are based on a 
reasonable level of stringency and not the most stringent possible 
level, the EPA expects that such offsetting emission reductions at the 
state's affected EGUs from the application of other building blocks 
will be available, so that the EPA will be able to finalize the state 
goals as proposed. For example, a state's inability to meet the level 
of emission reductions anticipated through use of one building block 
may free up resources that the state could then devote to more 
stringent implementation of another building block. This approach would 
mean that overall, the same nationwide level of emission reductions as 
proposed would be achieved. The EPA invites comment on this aspect of 
the proposal.
    At this time, the EPA is not proposing CO2 emission 
performance goals for either Indian country or U.S. territories. The 
EPA does plan to establish CO2 emission goals for both 
Indian country and territories in the future. The EPA plans to conduct 
additional outreach before setting these goals.
    Issues related to the establishment of CO2 goals and CAA 
section 111(d) plans for Indian country are discussed in Section V.D of 
this preamble. As noted in that discussion, the EPA is aware of four 
potentially affected power plants located in Indian country: The South 
Point Energy Center, on Fort Mojave tribal lands within Arizona; the 
Navajo Generating Station, on Navajo tribal lands within Arizona; the 
Four Corners Power Plant, on Navajo tribal lands within New Mexico; and 
the Bonanza Power Plant, on Ute tribal lands within Utah.\252\ Data for 
these four power plants have been excluded from the data used to 
compute the proposed state goals for Arizona, New Mexico, and Utah 
discussed below.
---------------------------------------------------------------------------

    \252\ The South Point facility is an NGCC power plant, and the 
Navajo, Four Corners, and Bonanza facilities are coal-fired power 
plants.
---------------------------------------------------------------------------

    With respect to territories, the EPA is currently aware of 
potentially affected EGUs in Puerto Rico, the U.S. Virgin Islands, and 
Guam. The EPA requests comment on how the BSER would apply to these 
territories, as well as to American Samoa or the Northern Mariana 
Islands if potentially affected EGUs are subsequently identified in 
those territories. In particular, the EPA solicits comment on 
appropriate alternatives for territories that do not have access to 
natural gas.\253\ Because the data sources we have used for purposes of 
establishing renewable energy and demand-side energy efficiency targets 
for states do not cover all the territories, we also solicit comment on 
ways to determine appropriate renewable energy and demand-side energy 
efficiency targets using other data sources.
---------------------------------------------------------------------------

    \253\ As noted in Section VI.C.5.d above, we are requesting 
comment on whether heat rate improvements for non-coal fossil fuel-
fired EGUs should be part of the basis supporting the BSER, with 
particular reference to the situation of geographically isolated 
jurisdictions such as the U.S. territories.
---------------------------------------------------------------------------

    The remainder of this section addresses five sets of topics. First, 
we discuss several issues related to the form of the goals. Second, we 
describe the proposed state goals and the computation procedure. Third, 
we discuss several types of state flexibility with respect to the 
goals. Fourth, we describe the alternate set of goals offered for 
comment and certain other approaches we considered. Finally, we discuss 
the proposal's compatibility with the need to ensure a reliable, 
affordable supply of electricity.
    Some of the topics addressed in this section are addressed in 
greater detail in supplemental documents available in the docket for 
this rulemaking, including the Goal Computation TSD and the Greenhouse 
Gas Abatement Measures TSD. Specific topics addressed in the various 
TSDs are noted throughout the discussion below.

B. Form of Goals

    The proposed goals are presented in the form of adjusted output-
weighted-average CO2 emission rates that the affected fossil 
fuel-fired EGUs located in each state could achieve, on average, 
through application of the measures

[[Page 34894]]

comprising the BSER (or alternative control methods). Several aspects 
of this proposed form of goal are worth noting at the outset: The use 
of an emission rate-based form (e.g., the quantity of CO2 
per MWh of electricity generated), with the opportunity for the state 
to adopt a mass-based form (e.g., a cap on the tonnage of 
CO2 emissions); the use of output-weighted-average emission 
rates for all affected EGUs in a state rather than nationally uniform 
emission rates for all affected EGUs of particular types; the use of 
adjustments to accommodate measures that reduce CO2 
emissions by reducing the quantity of fossil fuel-fired generation 
rather than by reducing the CO2 emission rate per MWh 
generated by affected sources; the use of emission rates expressed in 
terms of net rather than gross energy output; and the adjustability of 
the goals based on the severability of the underlying building blocks.
    First, the EPA proposes to use an emission rate-based form for the 
state-specific goals included in the guidelines, and to give each state 
the opportunity to translate its rate-based goal to an equivalent mass-
based form for state plan purposes. Each of the two forms of goals 
presents advantages, and states have expressed support for having the 
flexibility to use either form. Defining emission performance levels in 
a rate-based form provides flexibility to accommodate changes in the 
overall quantities of electricity generated in response to increases in 
electricity demand. Defining emission performance levels in a mass-
based form provides relative certainty as to the absolute emission 
levels that would be achieved as well as relative simplicity in 
accommodating and accounting for the emission impacts of a wide variety 
of emission reduction strategies. In light of these respective 
advantages, we propose to set an emission rate-based form of goal, and 
to allow any state to translate the rate-based goal to an equivalent 
mass-based emission performance level for state plan purposes. This 
approach allows each state to maximize the advantages it considers 
optimal and is consistent with the state flexibility principle that is 
central to the EPA's development of this program.
    The second aspect noted above concerns the proposed choice of 
state-specific output-weighted-average emission rates for all affected 
EGUs in each state rather than nationally uniform emission rates for 
particular types of affected EGUs. Here, the EPA's main consideration 
has been to ensure that the proposed goals reflect opportunities to 
manage CO2 emissions by shifting generation among different 
types of affected EGUs. Specifically, because CO2 emission 
rates differ widely across the fleet of affected EGUs, and because 
transmission interconnections typically provide system operators with 
choices as to which EGU should be called upon to produce the next MWh 
of generation needed to meet demand, opportunities exist to manage 
utilization of high carbon-intensity EGUs based on the availability of 
less carbon-intensive generating capacity. For states and generators, 
this means that CO2 emission reductions can be achieved by 
shifting generation from EGUs with higher CO2 emission 
rates, such as coal-fired EGUs, to EGUs with lower CO2 
emission rates, such as NGCC units. Our analysis indicates that 
shifting generation among EGUs offers opportunities to achieve large 
amounts of CO2 emission reductions at reasonable costs. 
These opportunities can be reflected in a goal established in the form 
of an output-weighted-average emission rate for multiple affected EGU 
types. Our approach is also consistent with the fact that the 
proportions of different EGU types and hence the magnitudes of the 
generation-shifting opportunities vary across states, and that CAA 
section 111(d) calls for standards of performance to be established in 
state plans rather than on a nationwide basis.
    The third aspect noted above regarding the proposed form of the 
goals concerns the adjustments made to the output-weighted-average 
emission rates in order to accommodate reduced utilization of affected 
EGUs associated with measures such as increases in low- and zero-carbon 
generating capacity and demand-side energy efficiency. We recognize 
that these measures support reduced overall CO2 mass 
emissions from affected EGUs through reductions in the quantity of 
generation from affected EGUs, and not necessarily through reductions 
in the weighted-average CO2 emission rates of affected EGUs. 
Accordingly, we have constructed the emission rate goals in a manner 
that is intended to account for these generation quantity-reducing 
measures by making adjustments to the values used in the emission rate 
computations. The specific adjustments are summarized below in the 
context of the goal computation methodology and are described in 
greater detail in the Goal Computation TSD. As described below in 
Section VIII on state plans, we are proposing that a state choosing a 
rate-based form of goal would be able to make analogous adjustments 
when assessing monitored emission performance so that measures that 
support avoided generation at affected EGUs could be used to help the 
state meet the rate-based emission performance level reflected in its 
plan. We note that adjustments of this nature are not necessary when a 
plan's emission performance level is based on the mass of 
CO2 emissions \254\ rather than on CO2 emission 
rates, because the emission-reducing effects of reduced generation at 
affected EGUs are evident in the EGUs' reported CO2 mass 
emissions.
---------------------------------------------------------------------------

    \254\ We also recognize that even under a mass-based approach, 
adjustments may be appropriate in some circumstances to address 
interstate effects, such as when measures undertaken pursuant to one 
state's plan are expected to be associated with decreases in fossil 
fuel-fired generation and CO2 emissions in another state. 
These issues are discussed below in Section VIII on state plans.
---------------------------------------------------------------------------

    The fourth aspect noted above concerns the proposed expression of 
the goals in terms of net energy output \255\--that is, energy output 
encompassing net MWh of generation measured at the point of delivery to 
the transmission grid rather than gross MWh of generation measured at 
the EGU's generator.\256\ The difference between net and gross 
generation is the electricity used at a plant to operate auxiliary 
equipment such as fans, pumps, motors, and pollution control devices. 
Because improvements in the efficiency of these devices represent 
opportunities to reduce carbon intensity at existing affected EGUs that 
would not be captured in measurements of emissions per gross MWh, we 
are proposing goals expressed in terms of net generation. Nearly all 
EGUs already have in place the equipment necessary to determine and 
report hourly net generation, and we believe that the proposed 
reporting requirement would therefore not be burdensome. However, we 
also recognize that at present EGUs report gross rather than net load 
\257\ to us under 40 CFR Part 75, and that the proposed GHG standards 
of performance for new EGUs are expressed in terms of gross generation 
(although we sought comment on the use of net generation instead). We 
therefore specifically seek comment on whether the goals and reporting 
requirements for existing EGUs should be expressed in terms of

[[Page 34895]]

gross generation instead of net generation for consistency with 
existing reporting requirements and with the proposed requirements 
under the GHG standards of performance for new EGUs.
---------------------------------------------------------------------------

    \255\ As discussed below in Section VIII on state plans, we are 
similarly proposing that states choosing a rate-based form of 
emission performance level for their plans should establish a 
requirement for affected EGUs to report hourly net energy output.
    \256\ For some EGUs, total net or gross energy output also 
includes useful thermal output, in addition to either net or gross 
electric energy output.
    \257\ Some EGUs report gross steam output instead of gross 
electrical load.
---------------------------------------------------------------------------

    The final aspect noted above has to do with the severability of the 
four building blocks, discussed in Section VI above, upon which the 
goals are based. Because the building blocks can be implemented 
independently of one another and the goals are the sum of the emission 
reductions from all of the building blocks, if any of the building 
blocks is found to be an invalid basis for the ``best system of 
emission reduction . . . adequately demonstrated,'' the goals would be 
adjusted to reflect the emissions reductions from the remaining 
building blocks. As noted above, the state goals that would result from 
any combination of the building blocks can be computed from data 
included in the Goal Computation TSD and its appendices using the 
methodology described below and in that TSD.
    We invite comment on all aspects of the proposed form of the goals.

C. Proposed Goals and Computation Procedure

    The EPA has developed proposed goals for state plans reflecting 
application of the BSER, based on all four building blocks described 
earlier, to pertinent data for each state. The goals are intended to 
represent CO2 emission rates achievable by 2030 after a 
2020-2029 phase-in period on an output-weighted-average basis 
collectively by all of a state's affected EGUs, with certain 
computation adjustments described below to reflect the potential to 
achieve mass emission reductions by avoiding fossil fuel-fired 
generation. For each state, in addition to the final goal, the EPA has 
developed an interim goal that would apply during the 2020-2029 period 
on a cumulative or average basis as the state progresses toward the 
final goal. The proposed goals are set forth in Table 8 below, followed 
by a description of the computation methodology. (The issue of how 
states could demonstrate emission performance consistent with the 
interim and final goals is addressed in Section VIII on state plans.)

                   Table 8--Proposed State \258\ Goals
  [Adjusted output-weighted-average pounds of CO2 per net MWh from all
                    affected fossil fuel-fired EGUs]
------------------------------------------------------------------------
                                                       Interim    Final
                        State                           goal      goal
------------------------------------------------------------------------
Alabama.............................................     1,147     1,059
Alaska..............................................     1,097     1,003
Arizona *...........................................       735       702
Arkansas............................................       968       910
California..........................................       556       537
Colorado............................................     1,159     1,108
Connecticut.........................................       597       540
Delaware............................................       913       841
Florida.............................................       794       740
Georgia.............................................       891       834
Hawaii..............................................     1,378     1,306
Idaho...............................................       244       228
Illinois............................................     1,366     1,271
Indiana.............................................     1,607     1,531
Iowa................................................     1,341     1,301
Kansas..............................................     1,578     1,499
Kentucky............................................     1,844     1,763
Louisiana...........................................       948       883
Maine...............................................       393       378
Maryland............................................     1,347     1,187
Massachusetts.......................................       655       576
Michigan............................................     1,227     1,161
Minnesota...........................................       911       873
Mississippi.........................................       732       692
Missouri............................................     1,621     1,544
Montana.............................................     1,882     1,771
Nebraska............................................     1,596     1,479
Nevada..............................................       697       647
New Hampshire.......................................       546       486
New Jersey..........................................       647       531
New Mexico *........................................     1,107     1,048
New York............................................       635       549
North Carolina......................................     1,077       992
North Dakota........................................     1,817     1,783
Ohio................................................     1,452     1,338
Oklahoma............................................       931       895
Oregon..............................................       407       372
Pennsylvania........................................     1,179     1,052
Rhode Island........................................       822       782
South Carolina......................................       840       772
South Dakota........................................       800       741
Tennessee...........................................     1,254     1,163
Texas...............................................       853       791
Utah *..............................................     1,378     1,322
Virginia............................................       884       810
Washington..........................................       264       215
West Virginia.......................................     1,748     1,620
Wisconsin...........................................     1,281     1,203
Wyoming.............................................     1,808     1,714
------------------------------------------------------------------------
* Excludes EGUs located in Indian country within the state.

     
---------------------------------------------------------------------------

    \258\ The EPA has not developed goals for Vermont and the 
District of Columbia because current information indicates those 
jurisdictions have no affected EGUs. Also, as noted above, the EPA 
is not proposing goals for Indian country or U.S. territories at 
this time.
---------------------------------------------------------------------------

    The proposed goals are expressed as adjusted output-weighted-
average emission rates for all affected EGUs in a state. As discussed 
earlier in this section, a goal expressed as an unadjusted output-
weighted-average emission rate would fail to account for mass emission 
reductions from reductions in the total quantity of fossil fuel-fired 
generation associated with state plan measures that increase low- or 
zero-carbon generating capacity or demand-side energy efficiency. 
Accordingly, under the proposed goals, the emission rate computation 
includes an adjustment designed to reflect those mass emission 
reductions. The adjustment is made by estimating the annual net 
generation associated with an achievable amount of qualifying new low-
carbon and zero-carbon generating capacity, as well as the annual 
avoided generation associated with an achievable portfolio of demand-
side energy efficiency measures, and adding those MWh amounts to the 
energy output from affected units that would have been used in an 
unadjusted output-weighted-average emission rate computation.\259\ 
Mathematically, this adjustment has the effect of spreading the 
measured CO2 emissions from the state's affected EGUs over a 
larger quantity of energy output, thus resulting in an adjusted 
emission rate lower than the unadjusted emission rate. (As discussed 
below in Section VIII on state plans, we are proposing that a state 
could make analogous adjustments to compliance measurement approaches 
under its state plan, thereby enabling the state to adopt an emission 
rate-based form of emission performance level while still being able to 
rely on low- or zero-carbon capacity deployment programs and demand-
side energy efficiency as components of its plan.)
---------------------------------------------------------------------------

    \259\ In the case of new capacity that is not zero-carbon, an 
adjustment would also be required to the emissions value used in 
computing the weighted-average emission rate. This procedure is 
discussed further in the Goal Computation TSD.
---------------------------------------------------------------------------

    The methodology used to compute each state's proposed goal is 
summarized on a step-by-step basis below. The methodology is described 
in more detail in the Goal Computation TSD, which includes a numerical 
example illustrating the full procedure. The development of the data 
inputs used in the computation procedure is discussed in Section VI 
above and in the Greenhouse Gas Abatement Measures TSD.
    Step 1 (compilation of baseline data). On a state-by-state basis, 
we obtained total annual quantities of CO2 emissions, net 
generation (MWh), and capacity (MW) from reported 2012 data for all 
affected EGUs.\260\ For each state,

[[Page 34896]]

we aggregated the 2012 data for all coal-fired steam EGUs as one group, 
all oil- and gas-fired steam EGUs as a second group, and all NGCC units 
as a third group. We aggregated the 2012 data for all remaining 
affected EGUs (i.e., integrated gasification combined-cycle (IGCC) 
units and any simple-cycle combustion turbines satisfying relevant 
thresholds for qualification as affected EGUs) as a fourth, ``other'' 
group.\261\ To these totals for affected EGUs operating in 2012, we 
added estimates for other EGUs not yet in operation in 2012 that are 
affected EGUs for purposes of this emission guideline.\262\ Capacity 
and emission rate data inputs for the post-2012 affected EGUs were 
obtained from the NEEDS database maintained by the EPA for use with the 
Integrated Planning Model (IPM). Generation data inputs for the post-
2012 affected EGUs were estimated based on the average 2012 utilization 
rates for recently constructed EGUs of the same types; for example, we 
estimated in this step that the post-2012 NGCC units would operate at a 
55 percent utilization rate on average.
---------------------------------------------------------------------------

    \260\ EGUs whose capacity, fossil fuel combustion, or 
electricity sales were insufficient to qualify them as affected EGUs 
were not included in the goal computations. Most simple cycle 
combustion turbines were excluded on this basis. See the 
applicability criteria described in Section V.B. above.
    \261\ The emission and generation totals for the ``other'' group 
also reflect the portion of affected cogeneration units' total 
CO2 emissions and total energy output corresponding to 
those units' useful thermal output.
    \262\ Assuming it meets other applicability criteria, an EGU 
would be affected if it had commenced construction by January 8, 
2014 (the data of Federal Register publication of the proposed GHG 
NSPS for new EGUs).
---------------------------------------------------------------------------

    Step 2 (application of building block 1). The total CO2 
emissions amount for the coal-fired steam EGU group in each state from 
Step 1 was reduced by six percent, reflecting our assessment of the 
average opportunity to reduce CO2 emission rates across the 
existing fleet of coal-fired steam EGUs through heat rate improvements 
that is technically achievable at a reasonable cost.
    Step 3 (application of building block 2). If the generation data 
for the NGCC group in a state developed in Step 1 showed average annual 
utilization below 70 percent of those units' maximum possible output, 
and the generation data developed in Step 1 also included generation 
from the coal-fired steam or oil/gas-fired steam EGU groups in that 
state, the generation and emissions figures for the NGCC group were 
increased, and the generation and emissions figures for the coal-fired 
and oil/gas-fired steam EGU groups from Step 2 were proportionately 
\263\ decreased, to reflect an estimated potential increase in 
utilization of the NGCC group to a maximum of 70 percent. In this step, 
the total (across all four groups) of the state's fossil fuel-fired 
generation was maintained at the amount computed in Step 1, but to the 
extent that in the analysis a portion of the total fossil generation 
was shifted from the coal-fired and oil/gas-fired steam EGU groups, 
which have higher CO2 emission rates, to the NGCC group, 
which has a lower CO2 emission rate, the total (across all 
four groups) of the state's CO2 emissions was reduced.\264\
---------------------------------------------------------------------------

    \263\ For example, if the data developed in Step 1 showed equal 
quantities of MWh generated by the coal-fired steam EGU group and 
the oil/gas-fired steam EGU group, then any overall reduction in the 
MWh generated by these two groups due to a commensurate increase in 
the MWh generated by the less carbon-intensive NGCC group would be 
split equally between the coal-fired steam group and the oil/gas-
fired steam group.
    \264\ We did not estimate any change in utilization, generation, 
or emissions for the state's ``other'' group of IGCC units and 
simple-cycle combustion turbines in Step 3.
---------------------------------------------------------------------------

    Step 4 (application of building block 3). We estimated the total 
quantities of generation from renewable generating capacity and from 
under-construction or preserved nuclear capacity for each state using 
the approaches described in Section VI.C.3 above. Separate estimates of 
renewable generation were computed for each year of the plan period for 
each state based on the state's 2012 renewable generation and a 
regional growth factor. Nuclear generation was estimated as the amount 
of under-construction and preserved nuclear capacity for each state 
operated at a utilization rate of 90 percent, consistent with recent 
industry-wide average utilization rates for nuclear units.
    Step 5 (application of building block 4). We estimated the total 
MWh amount by which generation from each state's affected EGUs would be 
cumulatively reduced in each year of the plan period associated with 
implementation in that state of demand-side energy efficiency programs 
resulting in annual incremental reductions in the state's electricity 
usage (relative to usage absent those programs) of 1.5 percent each 
year, as described in Section VI.C.4 above. Separate estimates were 
developed for each year to reflect the fact that energy efficiency 
programs that are implemented on an ongoing basis would be expected to 
produce larger cumulative impacts on total annual electricity usage 
over time. For states that are net importers of electricity, the 
estimated reduction in the generation by the state's affected EGUs was 
scaled down to reflect an expectation that a portion of the generation 
avoided by the demand-side energy efficiency would occur at EGUs in 
other states.
    Step 6 (computation of annual rates). We computed adjusted output-
weighted-average CO2 emission rates for each state by 
dividing (1) the total CO2 emissions for the coal-fired 
steam EGU, oil- and gas-fired steam EGU, NGCC unit, and ``other'' 
affected fossil EGU groups from Step 3 above by (2) the total of (a) 
the total net energy output (expressed in MWh) for the four groups from 
Step 1 above plus (b) the estimated annual net generation from 
renewable and nuclear generating capacity from Step 4 above plus (c) 
the estimated cumulative annual MWh amount saved through demand-side 
energy efficiency from Step 5 above.\265\ We performed these 
computations separately for each year from 2020 to 2029, using the 
respective cumulative annual MWh savings figures developed in Steps 4 
and 5.
---------------------------------------------------------------------------

    \265\ Expressed as a formula, the equation for the annual rate 
computation is:
    [(Coal gen. x Coal emission rate) + (OG gen. x OG emission rate) 
+ (NGCC gen. x NGCC emission rate) + ``Other'' emissions]/[Coal gen. 
+ OG gen. + NGCC gen. + ``Other'' gen. + Nuclear gen. + RE gen. + EE 
gen.]
    This formula and its elements are further explained in the Goal 
Computation TSD, as well as in the text above.
---------------------------------------------------------------------------

    Step 7 (computation of interim and final goals). The final 2030 
goal for each state is the annual rate computed for 2029 for the state 
from Step 6 above. We computed the 2020-2029 interim goal for each 
state as the simple average of the annual rates computed for each of 
the years from 2020 to 2029 for the state from Step 6 above.
    It bears emphasis that the procedure described above is proposed to 
be used only to determine state goals, and the particular data inputs 
used in the procedure are not intended to represent specific 
requirements that would apply to any individual EGU or to the 
collection of EGUs in any state. The specific requirements applicable 
to individual EGUs, to the EGUs in a given state collectively, or to 
other affected entities in the state, would be based on the standards 
of performance established through that state's plan. The details of 
how states could attain emission performance levels consistent with the 
goals through different state plan approaches that recognize emission 
reductions achieved through all the building blocks are discussed 
further in Section VIII on state plans.
    We invite comment on all aspects of the goal computation procedure. 
(Note that we also invite comment on certain specific alternate data 
inputs to the procedure in Section VI.C above.) We also specifically 
invite comment on the state-specific historical data to which

[[Page 34897]]

the building blocks are applied in order to compute the state goals, as 
well as the state-specific data used to develop the state-specific data 
inputs for building blocks 3 and 4. These data are contained in the 
Goal Computation TSD and the Greenhouse Gas Abatement Measures TSD.
    With respect to building block 2, we specifically request comment 
on the following alternate procedure: In Step 3, to the extent that 
generation from a state's NGCC group was increased consistent with the 
NGCC utilization rate target, in order to maximize the resulting 
emission reductions, we would decrease generation from the state's 
coal-fired steam group first, and then decrease generation from the 
state's oil/gas-fired steam group (instead of decreasing generation 
from the coal-fired steam and oil/gas-fired steam groups 
proportionately).
    With respect to building block 4, we specifically invite comment on 
the alternative in Step 5 of scaling up the estimated reduction in the 
generation by affected EGUs in net electricity-exporting states to 
reflect an expectation that a portion of the generation avoided in 
conjunction with the demand-side energy efficiency efforts of other, 
net electricity-importing states would occur at those EGUs, analogous 
to the proposed adjustment for net electricity-importing states 
described in Step 5. We also request comment on the alternative of 
making no adjustment in Step 5 for either net electricity-importing or 
net electricity-exporting states. These alternatives are discussed in 
the Goal Computation TSD.
    We also request comment on whether CO2 emission 
reductions associated with other measures not currently included in any 
of the four proposed building blocks should be included in the state 
goals.

D. State Flexibilities

    As promulgated in the final rule following consideration of 
comment, the state-specific goals will be binding emission guidelines. 
States' ability to achieve emission performance levels consistent with 
the binding goals is enhanced by several distinct types of flexibility: 
(i) Choices as to the measures employed, including the timing of their 
implementation; (ii) the ability to translate from a rate-based form of 
goal to a mass-based form of goal; and (iii) the opportunity to pursue 
multi-state plan approaches.
    First, a core flexibility provided under CAA section 111(d) is that 
while states are required to establish standards of performance that 
reflect the degree of emission limitation from application of the 
control measures that the EPA identifies as the BSER, they need not 
mandate the particular control measures the EPA identifies as the basis 
for its BSER determination. In developing the building block data 
inputs applied to each state's historical data to develop the goals, 
the EPA targeted reasonably achievable rather than maximum performance 
levels. The overall goals therefore represent reasonably achievable 
emission performance levels that provide states with flexibility to 
pursue some building blocks more extensively and others less 
extensively than the degree reflected in the EPA's data inputs while 
meeting the overall goals. States can also choose to include in their 
plans other measures that reduce CO2 emissions at affected 
EGUs but that are not included in the building blocks.
    Further, by allowing states to demonstrate emission performance by 
affected EGUs on an average basis over a multi-year interim plan period 
of as long as ten years, the EPA's proposed approach increases states' 
flexibility to choose among alternative potential plan measures. For 
example, by taking advantage of the multi-year flexibility, a state 
could choose to rely more heavily in its plan on measures whose 
effectiveness tends to grow over time, such as demand-side energy 
efficiency programs. This flexibility could also help states address 
concerns about stranded assets, for example, by enabling states to 
defer imposition of requirements on EGUs that may be scheduled to 
retire after 2020 but before 2029.
    The second type of flexibility noted above is that while the EPA is 
proposing to establish goals in an emission rate-based form, we are 
also proposing to provide states with the flexibility to translate the 
rate-based goals to mass-based goals in order to accommodate states' 
potential interest in having emission performance requirements measured 
in absolute tons. For example, the northeastern and Mid-Atlantic states 
that currently participate in the mass-based Regional Greenhouse Gas 
Initiative (RGGI) may choose to develop state plans (or a multi-state 
plan, as noted below) establishing mass-based emission performance 
levels designed to be met at least in part through standards of 
performance based on RGGI's existing market-based CO2 
emission budget trading program. Because the use of mass-based plans 
can simplify the process of accounting for the CO2 reduction 
impacts of a variety of measures, the EPA believes the flexibility to 
adopt mass-based emission performance levels can facilitate plan 
development and could be attractive to states that do not already 
participate in mass-based emission reduction programs as well.
    Third, the EPA's approach allows states to submit multi-state 
plans. The EPA expects this flexibility to reduce the cost of achieving 
the state goals and therefore expects it to be attractive to states. 
For example, the RGGI-participating states could choose to submit a 
multi-state mass-based plan that demonstrates emission performance by 
affected EGUs on a multi-state basis. Additional states may also choose 
to join a multi-state plan. The mechanics of translating rate-based 
goals into mass-based goals and considerations related to multi-state 
plans are discussed below in Section VIII on state plans.
    Some stakeholders have suggested that states themselves should be 
allowed to quantify the level of emission reduction resulting from the 
application of BSER or, if the EPA establishes goals, the states should 
be allowed to adjust the goals or to treat the goals established by the 
EPA as advisory rather than binding. Consistent with the existing 
implementing regulations for CAA section 111(d) at 40 CFR part 60, this 
quantification is the EPA's role.\266\ As discussed in the Legal 
Memorandum, CAA section 111(d) directs the EPA to ``prescribe 
regulations which shall establish a procedure similar to that provided 
by [CAA section 110] under which each State shall submit'' a section 
111(d) state plan. As noted in Section II.D of this preamble, the EPA 
promulgated implementing regulations in 1975, and has revised parts of 
them since. The regulations set out a multi-step process for the 
development and approval of state plans, and assign responsibility for 
the various steps in the process to the EPA or the states. The 
regulations provide that the EPA is to promulgate an ``emission 
guideline that reflects the application of the best system of emission 
reduction (considering the cost of such reduction) that has been 
adequately demonstrated for'' affected sources.\267\ In this manner, 
the regulations make clear that the EPA determines the BSER. In this 
rulemaking, as discussed above, the EPA identifies the BSER. In 
addition, in this rulemaking, the EPA applies the BSER to each state, 
and then, for each state, calculates the average emission rate that, in 
the words of the regulations just quoted, ``reflects the application of

[[Page 34898]]

the [BSER].'' That average emission rate is the state goal.
---------------------------------------------------------------------------

    \266\ 40 CFR 60.22(b)(5). We do not propose to re-open that 
portion of the implementing regulations in this rulemaking.
    \267\ Id.
---------------------------------------------------------------------------

    By the same token, because the state goals are an integral part of 
the emission guidelines that the framework regulations authorize the 
EPA to establish, the goals are binding, and the states, in their CAA 
section 111(d) plans, must meet those goals and may not make them less 
stringent. This matter, too, is resolved by the implementing 
regulations.\268\ To reiterate, the proposed state goals represent the 
level of performance that is achievable through application of the BSER 
to the pertinent data for each individual state. States have the 
opportunity to comment on the proposed BSER, the proposed methodology 
for computing state goals based on application of the BSER, and the 
state-specific data that is proposed for use in the computations. We 
expect that the states will have an adequate opportunity to comment on 
the state goals during the comment period. Once the final goals have 
been promulgated, and adjusted as may be appropriate based on comments 
to address any factual errors in the analysis, the states will be able 
to meet them because they will represent the application of BSER to the 
states' affected sources. In addition, states have several types of 
flexibilities in developing their state plans: They have flexibility 
regarding the selection of the measures upon which they choose to rely 
and a 10-year time period over which to reach full implementation of 
these measures, and they can use rate-based or mass-based approaches. 
In addition, as we have noted, multi-state coordination offers states 
an opportunity to achieve additional emission reductions and reduce 
implementation costs. These flexibilities, discussed further in Section 
VIII of this preamble, ensure that states will be able to achieve their 
final CO2 emission performance goals and that no special 
provision for state adjustment of goals outside the normal notice-and-
comment rulemaking process is warranted.\269\
---------------------------------------------------------------------------

    \268\ Id. We do not propose to re-open that portion of the 
implementing regulations in this rulemaking.
    \269\ In the event that a state becomes concerned about its 
ability to meet the goal that the EPA promulgates for it, the state 
may submit to the EPA a petition for reconsideration, if that 
petition is based on relevant information not available during the 
comment period. See CAA section 307(d)(7)(B).
---------------------------------------------------------------------------

E. Alternate Goals Offered for Comment and Other Approaches Considered

    In addition to the proposed state-specific emission rate-based 
goals described above, the EPA has developed for public comment an 
alternate set of goals reflecting less stringent application of the 
building blocks and a shorter implementation period. The alternate 
final goals represent emission performance that would be achievable by 
2025, after a 2020-2024 phase-in period, with interim goals that would 
apply during the 2020-2024 period on a cumulative or average basis as 
states progress toward the final goals.
    Because the time period for implementation relates directly to the 
emission reductions that are achievable and therefore what measures, 
and at what level of stringency, constitute the BSER, the alternate 
goals reflect several differences in data inputs from the proposed 
goals. Specifically, a value of four percent (instead of six percent) 
was used for the potential improvement in carbon intensity of coal-
fired EGUs in Step 2; a value of 65 percent (instead of 70 percent) was 
used for the potential annual utilization rate of NGCC units in Step 3; 
and a value of one percent (instead of 1.5 percent) was used for the 
annual incremental electricity savings achievable through a portfolio 
of demand-side energy efficiency programs in Step 5. (No change was 
made to the data inputs regarding less carbon-intensive generating 
capacity in Step 4.) As noted above, the alternate goals also reflect a 
shortening of the proposed phase-in period from ten years (2020-2029) 
to five years (2020-2024) to reflect an expectation that less stringent 
goals could be achieved in less time. Steps 5, 6, and 7 of the goal 
computation procedure therefore were performed for the span of years 
from 2020 to 2024 rather than for the span from 2020 to 2029. The 
alternate goals are set forth in Table 9 below.

                  Table 9--Alternate State \270\ Goals
  [Adjusted output-weighted-average pounds of CO2 per net MWh from all
                    affected fossil fuel-fired EGUs]
------------------------------------------------------------------------
                                                       Interim    Final
                        State                           goal      goal
------------------------------------------------------------------------
Alabama.............................................     1,270     1,237
Alaska..............................................     1,170     1,131
Arizona *...........................................       779       763
Arkansas............................................     1,083     1,058
California..........................................       582       571
Colorado............................................     1,265     1,227
Connecticut.........................................       651       627
Delaware............................................     1,007       983
Florida.............................................       907       884
Georgia.............................................       997       964
Hawaii..............................................     1,446     1,417
Idaho...............................................       261       254
Illinois............................................     1,501     1,457
Indiana.............................................     1,715     1,683
Iowa................................................     1,436     1,417
Kansas..............................................     1,678     1,625
Kentucky............................................     1,951     1,918
Louisiana...........................................     1,052     1,025
Maine...............................................       418       410
Maryland............................................     1,518     1,440
Massachusetts.......................................       715       683
Michigan............................................     1,349     1,319
Minnesota...........................................     1,018       999
Mississippi.........................................       765       743
Missouri............................................     1,726     1,694
Montana.............................................     2,007     1,960
Nebraska............................................     1,721     1,671
Nevada..............................................       734       713
New Hampshire.......................................       598       557
New Jersey..........................................       722       676
New Mexico *........................................     1,214     1,176
New York............................................       736       697
North Carolina......................................     1,199     1,156
North Dakota........................................     1,882     1,870
Ohio................................................     1,588     1,545
Oklahoma............................................     1,019       986
Oregon..............................................       450       420
Pennsylvania........................................     1,316     1,270
Rhode Island........................................       855       840
South Carolina......................................       930       897
South Dakota........................................       888       861
Tennessee...........................................     1,363     1,326
Texas...............................................       957       924
Utah *..............................................     1,478     1,453
Virginia............................................     1,016       962
Washington..........................................       312       284
West Virginia.......................................     1,858     1,817
Wisconsin...........................................     1,417     1,380
Wyoming.............................................     1,907     1,869
------------------------------------------------------------------------
* Excludes EGUs located in Indian country in the state.

     
---------------------------------------------------------------------------

    \270\ See footnote accompanying Table 8 above.
---------------------------------------------------------------------------

    The EPA recognizes that its approach to the alternate goals, 
comprising less stringent requirements in each of the building blocks 
to be achieved over a shorter compliance horizon, follows the logic of 
including time as one of the functions of the BSER determination. At 
the same time, we also recognize that the components of the alternate 
goals may reflect an overly conservative approach. Specifically, the 
alternate goals as set forth above may underestimate the extent to 
which the key elements of the four building blocks--achieving heat rate 
improvements at EGUs, switching generation to NGCC facilities, 
fostering the penetration of renewable resources or improving year-to-
year end-use energy efficiency--can be achieved rapidly while 
preserving reliability and remaining reasonable in cost. Accordingly, 
we request comment on the alternate goals, particularly with respect to 
whether any one or all of the building blocks in the alternate goals

[[Page 34899]]

can be applied at a greater level of stringency: Can the heat rate 
improvement value be set at a level above four percent, even six 
percent? Can NGCC capacity be dispatched at a utilization rate above 65 
percent? Can annual incremental electricity savings be achieved at a 
rate higher than one percent?
    It is worth noting that the EPA projects that the alternate goals 
will achieve emission reductions equal to 23 percent below 2005 level 
in 2025. The EPA's analysis shows that under the proposed goals 
described in Section VII.C above, power sector emissions will be 29 
percent below 2005 levels in 2025, suggesting that the kinds of changes 
contemplated in the four building blocks, even as early as 2025, will 
be yielding reductions far greater than the 23 percent projected for 
the alternate goals as set forth above in this subsection.
    The EPA has considered other approaches to setting goals. In 
particular, given the interconnected nature of the power sector and the 
importance of opportunities for shifting generation among EGUs, we 
considered whether goals should be set on a multi-state basis 
reflecting the scope of existing regional transmission control areas. 
We also considered whether goals should be set on a state-specific 
basis, but regional rather than state-specific evaluations should be 
used to assess the estimated opportunities to reduce utilization of the 
most carbon-intensive EGUs by shifting generation to less carbon-
intensive EGUs. A potential advantage of using regional evaluations is 
the ability to recognize additional emission reduction opportunities 
that would be available at reasonable costs based on a more complete 
representation of the capabilities of existing infrastructure to 
accommodate shifts in generation among EGUs in multiple states. We 
request comment on whether, and if so how, the EPA should incorporate 
greater consideration of multi-state approaches into the goal-setting 
process, and on the issue of whether, and if so how, the potential cost 
savings associated with multi-state approaches should be considered in 
assessing the reasonableness of the costs of state-specific goals.

F. Reliable Affordable Electricity

    Many stakeholders raised concerns that this regulation could affect 
the reliability of the electric power system. The EPA agrees that 
reliability must be maintained and in designing this proposed 
rulemaking has paid careful attention to this issue. The EPA has met on 
several occasions with staff and managers from the Department of Energy 
and the Federal Energy Regulatory Commission to discuss our approach to 
the rule and its potential impact on the power system. EPA staff and 
managers have also had numerous discussions with state public utility 
commissioners and their staffs to get their suggestions and advice 
concerning this rule, including how to address reliability concerns.
    In addition, the EPA met with independent system operators several 
times to discuss any potential impact of this rule on grid reliability. 
The ISO/RTO Council, a national organization of electric grid 
operators, offered analytic support to help states design programs that 
do not compromise the regional bulk power system. They also offered to 
help states develop regional approaches which may reduce costs and 
strengthen the reliability of the electricity grid. Specifically, the 
ISO/RTO Council has suggested that ISOs and RTOs could provide analytic 
support to help states develop and implement their plans. The ISOs and 
RTOs have the capability to model the system-wide effects of individual 
state plans. Providing assistance in this way, they felt, would allow 
states with borders that fall within an ISO or RTO footprint to assess 
the system-wide impacts of potential state plan approaches. In 
addition, as the state implements its plan, ISO/RTO analytic support 
would allow the state to monitor the effects of its plan on the 
regional electricity system. ISO/RTO analytic capability could help 
states assure that their plans are consistent with region-wide system 
reliability. The ISO/RTO Council suggested that the EPA ask states to 
consult with the applicable ISO/RTO in developing their state plans. 
The EPA agrees with this suggestion and encourages states with borders 
that fall within one or more ISO or RTO footprints to consult with the 
relevant ISOs/RTOs.
    The EPA has met with the U.S. Department of Agriculture as well to 
discuss how we can address the concerns of small, relatively isolated 
power generators in rural America and especially the electric 
cooperatives. Many of these entities have special challenges, as they 
may have small, older carbon-intensive assets and might have particular 
challenges meeting carbon requirements.
    With all of this in mind, the EPA in determining the BSER looked 
specifically at the reasonableness of the costs of control options in 
part to ensure that the options would not have a negative effect on 
system reliability. The BSER, including each of the building blocks, 
was determined to be feasible at reasonable costs over the timeframe 
proposed here. Further, under the Clean Air Act the states are given 
the flexibility to design state plans that include any measure or 
combination of measures to achieve the required emission limitations. 
States are not required to use each of the measures that the EPA 
determines constitute the BSER or use those measures to the same degree 
or extent that the EPA determines is feasible at a reasonable cost. 
Thus, each state has the flexibility to choose the most cost-effective 
measures given that state's energy profile and economy, as long as the 
state achieves the reductions necessary to meet its goal. Many market-
based approaches which states may choose reduce the costs of 
compliance. They can allow certain units that are seldom used to remain 
in operation if they are needed for reliability purposes. Multi-state 
approaches also reduce costs and stress on the grid and so can help to 
reduce any concern about electricity reliability.
    States may choose measures that would ease pressures on system 
reliability. This is true for many demand-side management approaches, 
including programs to encourage end-use energy efficiency, distributed 
generation, and combined heat and power, which actually reduce demand 
for centrally generated power and thus relieve pressure on the grid.
    The EPA is proposing a 10-year period over which to achieve the 
full required CO2 reductions, and we would expect this to 
further relieve any pressure on grid reliability. This relatively long 
planning and implementation period provides states with substantial 
flexibility regarding methods and timing of achieving emission 
reductions.
    The EPA's supporting analysis for this rule includes an examination 
of the effects of the rule on regional resource adequacy.\271\ The 
EPA's analysis looked at the types of changes in the generation fleet 
that were projected to occur through retirements, additional generation 
and energy efficiency. The analysis did not raise concerns over 
regional resource adequacy. The EPA further examined how the policy 
options impacted the flows and transfers of electricity that occur to 
meet reserve margins. None of the interregional changes in the policy 
cases suggested that there would be increases in flows that would raise 
significant concerns about grid congestion or grid management. 
Moreover, the time

[[Page 34900]]

horizon for compliance with this rule will permit environmental and 
reliability planners to coordinate these changes and address potential 
concerns before they arise.
---------------------------------------------------------------------------

    \271\ See the Resource Adequacy and Reliability Analysis TSD, 
available in the docket.
---------------------------------------------------------------------------

    The EPA concludes that the proposed rule will not raise significant 
concerns over regional resource adequacy or raise the potential for 
interregional grid problems. The EPA believes that any remaining local 
issues can be managed through standard reliability planning processes. 
The flexibility inherent in the rule is responsive to the CAA's 
recognition that state plans for emission reduction can, and must, be 
consistent with a vibrant and growing economy and reliable, affordable 
electricity to support that economy. The EPA welcomes comments and 
suggestions on this issue.

VIII. State Plans

A. Overview

    After the EPA establishes the state-specific rate-based 
CO2 goals in the emission guidelines, as described in 
Section VII above, each state must then develop, adopt, and submit its 
state plan under CAA section 111(d). To do so, the state must first 
determine the emission performance level it will include in its plan, 
which entails deciding whether it will adopt the rate-based 
CO2 goal set by the EPA or translate the rate-based goal to 
a mass-based goal.
    The state must then establish an emission standard or set of 
emission standards, and, perhaps other measures, along with 
implementing and enforcing measures, that will achieve a level of 
emission performance that is equal to or better than the level 
specified in the state plan.
    The state must then adopt the state plan through certain 
procedures, which include a state hearing. Within the time period 
specified in the emission guidelines (from as early as June 30, 2016 to 
as late as June 30, 2018, depending on the state's circumstances), the 
state must submit its complete state plan to the EPA. The EPA then must 
determine whether to approve or disapprove the plan. If a state does 
not submit a plan, or if the EPA does not approve a state's plan, then 
the EPA must establish a plan for the state.
    As discussed in Section V.D of this preamble, in the case of a 
tribe that has one or more affected EGUs located in its area of Indian 
country, if the EPA determines that a CAA section 111(d) plan is 
necessary or appropriate, the EPA has the responsibility to establish a 
CAA section 111(d) plan for that area of Indian country where affected 
sources are located unless the tribe on whose lands an affected source 
(or sources) is located seeks and obtains authority from the EPA to 
establish a plan itself, pursuant to the Tribal Authority Rule.\272\ 
The agency is soliciting comment on aspects of such CAA section 111(d) 
plans, as described in Section V.D of this preamble.
---------------------------------------------------------------------------

    \272\ See 40 CFR 49.1 to 49.11.
---------------------------------------------------------------------------

    This section is organized into six parts. First, we discuss the 
types of plans that we propose states could submit. Second, we address 
timing for plan implementation and achievement of state emission 
performance goals for affected EGUs. Third, we discuss the proposed 
state plan approvability criteria. Fourth, we summarize the proposed 
components of an approvable state plan. Fifth, we address the proposed 
process and timing for submittal of state plans. Sixth, we identify 
several key considerations for states in developing and implementing 
plans, including: Affected entities with obligations under a plan; 
treatment of existing state programs; incorporation of renewable energy 
(RE) and demand-side energy efficiency (EE) programs in certain plans; 
quantification, monitoring, and verification of RE and demand-side EE 
measures; reporting and recordkeeping for affected entities; treatment 
of interstate effects; and projection of emission performance. Finally, 
we discuss a number of additional factors that could help states meet 
their CO2 emission performance goals, and we note certain 
resources that are available to facilitate plan development and 
implementation. Additional discussion of some of the topics covered in 
this section can be found in the State Plan Considerations TSD and 
Projecting EGU CO2 Emission Performance in State Plans TSD, 
both of which are in the rulemaking docket.

B. Approach

    In this action, the EPA is proposing emission guidelines in the 
form of state-specific CO2 emission performance goals. In 
addition, the EPA is proposing guidelines for states to follow in 
developing plans to establish and implement CO2 emission 
standards for affected EGUs. The proposed plan guidelines include four 
general plan approvability criteria, twelve required components for a 
state plan to be approvable, the process and timing for state plan 
submittal and review, and the process and timing for demonstrating 
achievement of the CO2 goals. These are described below.
    The EPA recognizes that each state has different state policy 
considerations--including varying emission reduction opportunities and 
existing state programs and measures--and that the characteristics of 
the electricity system in each state (e.g., utility regulatory 
structure, generation mix, electricity demand) also differ. The agency 
also anticipates--and supports--states' commitments to a wide range of 
policy preferences that could encompass those of states like Kentucky, 
West Virginia and Wyoming seeking to continue to feature significant 
reliance on coal-based generation; states like Minnesota, Colorado, 
California and the nine RGGI states seeking to build on actions and 
policies they have already undertaken; and states like Washington and 
Oregon seeking to integrate sustainable forestry and renewable energy 
strategies. The proposed plan guidelines provide states with options 
for establishing emission standards in a manner that accommodates a 
diverse range of state approaches. Each state will have significant 
flexibility to determine how to best achieve its CO2 goals 
in light of its specific circumstances, including addressing concerns 
particular to the state, such as employment transition issues, as it 
designs and implements its plan over multiple years. As an example, the 
RGGI states' implementation of their mass-based emission budget trading 
program raises proceeds through allowance auctions and uses those 
proceeds to advance programs promoting and expanding end-use energy 
efficiency. States could address analogous priorities, such as 
employment transition, through a similar mechanism.
    The proposed plan guidelines would also allow states to collaborate 
and to develop plans that provide for demonstration of emission 
performance on a multi-state basis, in recognition of the fact that 
electricity is transmitted across state lines, and that state measures 
may impact, and may be explicitly designed to reduce, regional EGU 
CO2 emissions. The EPA also recognizes that multi-state 
collaboration would likely offer lower-cost approaches to achieving 
CO2 emission reductions. With this in mind, we are proposing 
to provide states with additional time to submit complete plans if they 
do so as part of a multi-state plan, and we solicit comment on other 
potential mechanisms for fostering multi-state collaboration.
1. State Plan Approaches
a. Overview
    Although state CAA section 111(d) plans must assure that the 
emission performance level is achieved through

[[Page 34901]]

reductions at the affected sources, we believe that different types of 
state plans could be constructed that make use of the diversity of 
measures available to achieve CO2 emission reductions. Based 
on the EPA's outreach efforts, it is clear that states are considering 
different types of plans.
    Three important issues in the design of state plans include: (1) 
Whether the plan should require the affected EGUs to be subject to 
emission limits that assure that the emission performance level is 
achieved, or instead, whether the plan could rely on measures, such as 
renewable energy (RE) or demand-side energy-efficiency (EE), to assure 
the achievement of part of the emission performance level; (2) whether 
the responsibility for all of the measures other than emission limits 
should fall on the affected EGUs, or, instead, could fall on entities 
other than affected EGUs; and (3) whether the fact that requiring all 
measures relied on to achieve the emission performance level to be 
included in the state plan renders those measures federally 
enforceable. These issues and the EPA's proposed approach are addressed 
in detail in the sections that follow.
    The EPA is proposing that all measures relied on to achieve the 
emission performance level be included in the state plan, and that 
inclusion in the state plan renders those measures federally 
enforceable.
    In light of current state programs, and of stakeholder expressions 
of concerns over the above-noted issues, including legal enforcement 
considerations, with respect to those programs, the EPA is proposing to 
authorize states either to submit plans that hold the affected EGUs 
fully and solely responsible for achieving the emission performance 
level, or to submit plans that rely in part on measures imposed on 
entities other than affected EGUs to achieve at least part of that 
level, as well as on measures imposed on affected EGUs to achieve the 
balance of that level. The EPA requests comment on this proposed 
approach, as opposed to the approach under which state plans simply 
would be required to hold the affected EGUs fully and solely 
responsible for achieving the emission performance level.
    In addition, the EPA is soliciting comment on several other types 
of state plans that may assure the requisite level of emission 
performance without rendering certain types of measures federally 
enforceable and that limit the obligations of the affected EGUs.
b. Portfolio Approach
    In assessing the types of state plans to authorize, the EPA 
reviewed existing state programs that reduce CO2 emissions 
from fossil fuel-fired power plants. Existing state programs are 
particularly informative for this purpose in light of the fact that CAA 
section 111(d) gives states the primary responsibility for designing 
their own state plans for submission to the EPA. Many of these existing 
state programs, as summarized above, include measures such as renewable 
energy (RE) and demand-side energy efficiency (EE) programs, which 
impose responsibilities on a range of entities, including state 
agencies, for assuring implementation of actions that result in reduced 
utilization of, and therefore reduced emissions from, fossil fuel-fired 
EGUs, and do not impose legal responsibilities for those emission 
reductions on the EGUs themselves.
    In addition, during the EPA's extensive outreach efforts, many 
stakeholders expressed concern over the extent of responsibility that 
fossil fuel-fired EGUs would be required to bear for the required 
emission reductions, in particular, those associated with RE and 
demand-side EE measures. These stakeholders recommended that the EPA 
authorize states to achieve emission reductions from RE and demand-side 
EE measures by imposing requirements on entities other than fossil 
fuel-fired EGUs, and without imposing legal responsibility for these 
emission reductions on those EGUs.
    Accordingly, the EPA is proposing to authorize a state plan to 
adopt what we refer to as a ``portfolio approach,'' in which the plan 
would include emission limits for affected EGUs along with other 
enforceable measures, such as RE and demand-side EE measures, that 
reduce CO2 emissions from affected EGUs. Under this 
approach, it would be all of the measures combined that would be 
designed to achieve the required emission performance level for 
affected EGUs as expressed in the state goal. Under this approach, the 
emission limits enforceable against the affected EGUs would not, on 
their own, assure, or be required to assure, achievement of the 
emission performance level. Rather, the state plan would include 
measures enforceable against other entities that support reduced 
generation by, and therefore CO2 emission reductions from, 
the affected EGUs. As noted, these other measures would be federally 
enforceable because they would be included in the state plan. A 
portfolio approach could be used for state plans that establish the 
emission performance level on either an emission rate basis or a mass 
emissions basis.
    In addition, a portfolio approach could either be what we refer to 
as ``utility-driven'' or ``state-driven,'' depending on the utility 
regulatory structure in a state. Under a utility-driven approach, a 
state plan may include, for example, measures implemented consistent 
with a utility integrated resource plan, including both measures that 
directly apply to affected EGUs (e.g., repowering or retirement of one 
or more EGUs) as well as RE and demand-side EE measures that avoid EGU 
CO2 emissions.\273\ Under a state-driven approach, the 
measures in a state plan would include emission standards for affected 
EGUs, as well as requirements that apply to entities other than 
affected EGUs, for example, renewable portfolio standards (RPS) or end-
use energy efficiency resource standards (EERS), both of which often 
apply to electric distribution utilities.\274\
---------------------------------------------------------------------------

    \273\ In the case of a utility-driven portfolio approach, the 
vertically integrated electric utility implementing portfolio 
measures is also the owner and operator of affected EGUs.
    \274\ A state-driven portfolio approach is more likely in states 
that have instituted electricity sector restructuring, where 
electric utilities have typically been required by states to divest 
electric generating assets.
---------------------------------------------------------------------------

c. Obligations on Affected EGUs
    The EPA is proposing to authorize state plans to adopt the 
portfolio approach and is proposing to interpret the CAA as allowing 
that approach, as described in more detail below. CAA section 111(d)(1) 
would certainly allow state plans to require the affected EGUs to be 
the sole entities legally responsible for achieving the emission 
performance level. The EPA is also soliciting comment on whether it can 
reasonably interpret CAA section 111(d)(1) to allow states to adopt 
plans that require EGUs and other entities to be legally responsible 
for actions required under the plan that will, in aggregate, achieve 
the emission performance level.
    We note that some existing state programs, such as RGGI in the 
northeastern states, do impose the ultimate responsibility on fossil 
fuel-fired EGUs to achieve the required emission reductions, but are 
also designed to work either concurrently, or in an integrated fashion, 
with RE and demand-side EE programs that reduce the cost of meeting 
those emission limitations. These existing programs offer a possible 
precedent for another type of CAA section 111(d) state plan. Such a 
plan approach could rely on CO2 emission standards 
enforceable against affected EGUs--whether in the form of

[[Page 34902]]

emission rate or mass limits--to ensure achievement of the required 
emission performance level, but also include enforceable or 
complementary RE and demand-side EE measures that lower cost and 
otherwise facilitate EGU emission reductions. Depending on the type of 
plan, these RE and demand-side EE measures could either be enforceable 
components of the plan (that is, the states could require affected EGUs 
or other affected entities to invest in RE or in demand-side EE 
programs) or be complementary to the plan. In this manner, RE and 
demand-side EE measures could be a major component of a state's overall 
strategy for reducing EGU CO2 emissions at a reasonable 
cost.
    It should be noted that state plan approaches that impose legal 
responsibility on the affected EGUs to achieve the full level of 
required emission performance could incorporate RE and demand-side EE 
measures regardless of whether the emission standards that those plans 
apply to the affected EGUs take the form of an emission rate or a mass 
limit. Plans with rate-based emission limits could incorporate 
enforceable RE and demand-side EE measures by adjusting an EGU's 
CO2 emission rate when demonstrating compliance through 
either an administrative adjustment by the state or use of a tradable 
credit approach. (These actions would need to be enforceable components 
of a state plan to facilitate EGU compliance with emission rate limits 
and ensure that actions are properly quantified, monitored, and 
verified.) A state plan that imposes a mass limit on affected EGUs that 
is sufficiently stringent to achieve the emission performance level 
would not need to include RE or demand-side EE measures as an 
enforceable component of the plan to assure the achievement of that 
performance level. The mass limit itself would suffice. However, the 
state may wish to implement RE and demand-side EE measures as a 
complement to the plan to support achievement of the mass limit at 
lesser cost.
d. Federal Enforceability
    Another concern expressed by some stakeholders is that including RE 
and demand-side EE measures in state plans would render those measures 
federally enforceable and thereby extend federal presence into areas 
that, to date, largely have been the exclusive preserve of the state 
and, in particular, state public utility commissions and the electric 
utility companies they regulate. These stakeholders suggest that states 
could rely on RE and demand-side EE programs as complementary measures 
to reduce costs for, and otherwise facilitate, EGU emission limits 
without including those measures in the CAA section 111(d) state plan. 
Under this suggested approach, the EGU emission limits would be 
federally enforceable, but RE and demand-side EE measures would serve 
as complementary measures and would not be enforceable under federal 
law; instead, they would remain enforceable under state law. According 
to stakeholders, those types of state programs, particularly because 
they are well-established, can be expected to achieve their intended 
results. Thus, they suggest that the states could conclude that those 
RE and demand-side EE measures would be beneficial in assuring the 
achievement of the required emission performance level by the affected 
EGUs specified in the CAA section 111(d) state plan, even without 
including those measures in the plan.
e. Plans With State Commitments
    As another vehicle for approving CAA section 111(d) plans for 
states that wish to rely on state RE and demand-side EE programs but do 
not wish to include those programs in their state plans, the EPA 
requests comment on what we refer to as a ``state commitment 
approach.'' This approach differs from the proposed portfolio approach, 
described above, in one major way: Under the state commitment approach, 
the state requirements for entities other than affected EGUs would not 
be components of the state plan and therefore would not be federally 
enforceable. Instead, the state plan would include an enforceable 
commitment by the state itself to implement state-enforceable (but not 
federally enforceable) measures that would achieve a specified portion 
of the required emission performance level on behalf of affected EGUs. 
The agency requests comment on the appropriateness of this approach. 
The agency also requests comment on the policy ramifications of the 
following: Under this approach, the state programs upon which the state 
bases its commitment may, in turn, rely on compliance by third parties, 
and if those state programs fail to achieve the expected emission 
reductions, the state could be subject to challenges--including by 
citizen groups--for violating CAA requirements and, as a result, could 
be held liable for CAA penalties.
    We also solicit comment on a variation of this state commitment 
plan approach that is also designed to address stakeholder concerns, 
noted above, about imposing sole legal responsibility on affected EGUs 
for achieving the emission performance level. With this variation, the 
state plan would in effect shift a portion of that responsibility to 
the state, in the following manner: The state plan would impose the 
full responsibility for achieving the emission performance level on the 
affected EGUs, but the state would credit the EGUs with the amount of 
emission reductions expected to be achieved from, for example, RE or 
demand-side EE measures. The state would then assume responsibility for 
that credited amount of emission reductions in the same manner as the 
state commitment plan approach discussed above. We solicit comment on 
whether, if the EPA were to conclude that CAA section 111(d) requires 
state plans to include standards of performance applicable to affected 
EGUs that achieve the emission performance level, this type of state 
plan would meet that requirement while also assuring those EGUs an 
important measure of support.
f. Legal Issues
    The EPA is proposing to interpret the relevant provisions in CAA 
section 111 to authorize state plans that achieve emissions reductions 
from affected EGUs by means of the portfolio approach. CAA section 
111(d)(1) requires each state to submit a plan that ``(A) establishes 
standards of performance for any existing source [for certain air 
pollutants] . . . and (B) provides for the implementation and 
enforcement of such standards of performance.'' CAA section 111(a)(1) 
defines a ``standard of performance'' as ``a standard for emissions of 
air pollutants which reflects the degree of emission limitation 
achievable through the application of the best system of emission 
reduction . . . adequately demonstrated.''
    These provisions make clear that emission limits that are 
enforceable against affected EGUs appropriately belong in state plans 
because they clearly are ``standards of performance.'' However, the 
terms of CAA section 111(d)(1) do not explicitly address whether, in 
addition to emission limits on affected EGUs, state plans may include 
other measures for achieving the emission performance level. Nor do 
they address whether entities other than affected EGUs may be subject 
to requirements that contribute to reducing EGU emissions. Under the 
U.S. Supreme Court's 1984 decision in Chevron U.S.A. Inc. v. NRDC, 
where the statute leaves a gap, the agency has discretion to fashion an 
interpretation

[[Page 34903]]

that is a reasonable construction of the statute.\275\
---------------------------------------------------------------------------

    \275\ Chevron U.S.A., Inc. v. NRDC, 467 U.S. 837, 842-44 (1984).
---------------------------------------------------------------------------

    The EPA is proposing to interpret the phrases ``standards of 
performance for any existing source'' and ``the implementation and 
enforcement of such standards of performance'' to encompass and allow 
the various components of the portfolio approach. To the extent that a 
portfolio approach contains measures that are not standards of 
performance or do not implement or enforce such standards, the EPA is 
proposing to interpret CAA section 111 as allowing state CAA section 
111(d) plans to include measures that are neither standards of 
performance nor measures that implement or enforce those standards, 
provided that the measures reduce CO2 emissions from 
affected sources. These measures would also be federally enforceable if 
included in an approved plan.
    The EPA's proposed interpretation is based, in part, on CAA section 
111(d)'s requirement that states set performance standards ``for'' 
affected sources. Although ``for'' could be read as meaning that the 
standards must apply to affected sources, ``for'' is also reasonably 
interpreted to have a more capacious meaning: Standards (such as EE and 
RE standards) are reasonably considered to be ``for'' affected sources 
if they would have an effect on affected sources by, for example, 
causing reductions in affected EGUs' CO2 emissions by 
decreasing the amount of generation needed from affected EGUs. Under 
this interpretation, and depending on the specific provisions in the 
state plan, renewable energy and demand-side energy efficiency 
requirements would be ``for'' fossil fuel-fired EGUs where such 
standards result in reduced CO2 emissions from fossil fuel-
fired EGUs, even if the standards do not apply directly to fossil fuel-
fired EGUs.
    The EPA also requests comment on another approach: Whether 
``standards of performance for [affected sources]'' is reasonably read 
to include the emission performance level (i.e., the state goal) on 
grounds that the level is ``a standard for emissions'' because it is in 
the nature of a requirement that concerns emissions and it is ``for'' 
the affected sources because it helps determine their obligations under 
the plan.
    Moreover, where the specific measures in the portfolio approach are 
not themselves a ``standard of performance,'' state plans may include 
measures that implement or enforce a standard of performance. For 
example, if the state's plan achieves the emission performance level 
through rate-based emission limits applicable to the affected sources, 
coupled with a crediting mechanism for RE and demand-side EE measures, 
we propose that RE and demand-side EE measures may be included in the 
plan as ``implement[ing]'' measures because they facilitate the 
sources' compliance with their standards of performance. We solicit 
comment on the extent to which measures such as RE and demand-side EE 
may be considered ``implement[ing]'' measures in state plans if they 
are not directly tied to emission reductions that affected sources are 
required to make through emission limits, and if they are requirements 
on entities other than the affected sources. In addition, the EPA 
proposes to interpret CAA section 111(d)(1) to allow state plans to 
include components of the portfolio approach that are measures that 
would reduce emissions from affected sources, even if those measures 
are neither ``standards of performance for existing sources'' nor 
measures ``for the implementation and enforcement of such standards of 
performance.'' There is no specific language in CAA section 111(d) or 
elsewhere in the Act that prohibits states from including measures 
other than performance standards and implementation and enforcement 
measures, provided that they reduce emissions from affected EGUs.
    This interpretation is consistent with the principle of cooperative 
federalism, which is one of the foundational principles of the Clean 
Air Act and which supports providing flexibility to states to meet 
environmental goals (provided minimum CAA statutory requirements are 
met). This general principle, especially when combined with the 
statutory directive that CAA section 111(d) regulations shall establish 
procedures ``similar to that provided by section 110,'' supports an 
interpretation of CAA section 111(d) that allows states sufficient 
flexibility in meeting the state goal set under CAA section 111(d) to 
include in their CAA section 111(d) plans other measures (i.e., 
measures that are neither performance standards nor measures that 
enforce or implement performance standards). The EPA solicits comment 
on all aspects of its proposed interpretation that states have this 
flexibility in selecting measures for their state plans under CAA 
section 111(d).
    An alternative interpretation of CAA section 111(d)(1) would 
suggest that the responsibility to achieve the state's required 
emission performance level must be assigned solely to affected EGUs. As 
described elsewhere in this preamble, there are a number of state-level 
CO2 programs that take this approach while still taking 
advantage of low-cost reductions from RE and demand-side EE through the 
use of complementary measures. This alternative interpretation would be 
based on, for example: A determination that CAA section 111(d)(1) must 
be read as precluding a state plan from including measures that are 
neither standards of performance nor measures for the implementation or 
enforcement of such standards; an interpretation that the state's 
obligation to set performance standards ``for'' existing sources means 
that the standards must apply to affected EGUs and not to other 
entities; and an interpretation that measures ``for the implementation 
and enforcement of such performance standards'' do not include measures 
that are not intended or designed to assist affected EGUs in meeting 
the performance standards. The EPA requests comment on whether it must 
adopt this alternative interpretation. If so, the EPA also takes 
comment on whether there is a way, nonetheless, to allow states to rely 
on the portfolio approach to some extent and/or for some period of 
time.
    We request comment on all of the interpretations discussed in this 
section generally, and on all legal issues under CAA section 111(d)(1) 
with respect to what measures can be included in a state plan and what 
entities must be legally responsible for meeting those measures.
g. Ongoing Applicability of CAA Section 111(d) State Plan
    The EPA is proposing that an existing source that becomes subject 
to requirements under CAA section 111(d) will continue to be subject to 
those requirements even after it undertakes a modification or 
reconstruction. Under this interpretation, a modified or reconstructed 
source would be subject to both (1) the CAA section 111(d) requirements 
that it had previously been subject to and (2) the modified source or 
reconstructed source standard being promulgated under CAA section 
111(b) simultaneously with this rulemaking. It should be noted that 
this proposal applies to any existing source subject to any CAA section 
111(d) plan, and not only existing sources subject to the CAA section 
111(d) plans promulgated under this rulemaking.
    As noted above, a ``new source'' is defined under CAA section 
111(a)(2) as ``any stationary source, the construction or modification 
of which is commenced after,'' in general, a proposed or final CAA 
section 111(b) rule becomes applicable to that source; and under

[[Page 34904]]

section 111(a)(6), an ``existing source'' is defined as ``any 
stationary source other than a new source.'' Under these definitions, 
an ``existing source'' that commences construction of a modification or 
reconstruction after the EPA has proposed or finalized a CAA section 
111(b) standard of performance applicable to it, becomes a ``new 
source.'' However, CAA section 111(d) is silent on whether requirements 
imposed under a CAA section 111(d) plan continue for a source that 
ceases to be an existing source because it modifies or reconstructs. 
Specifically, CAA section 111(d)(1) provides that ``each State shall 
submit to the Administrator a state plan which (A) ``establishes 
standards of performance for any existing source'' but does not say 
whether, once the EPA has approved a state plan that establishes a 
standard of performance for a given source, that standard is lifted if 
the source ceases to be an existing source. Similarly, no other 
provisions of CAA section 111 address whether the imposition of a CAA 
section 111(b) standard on a modified or reconstructed source ends the 
source's obligation to meet any applicable CAA section 111(d) 
requirements.
    Because CAA section 111(d) does not address whether an existing 
source that is subject to a CAA section 111(d) program remains subject 
to that program even after it modifies or reconstructs, the EPA has 
authority to provide a reasonable interpretation, under the Supreme 
Court's decision in Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-844 
(1984). The EPA's interpretation is that under these circumstances, the 
source remains subject to the CAA section 111(d) plan, for two reasons. 
The first is to assure the integrity of the CAA section 111(d) plan. 
The EPA believes that many states will develop integrated plans that 
include all of their EGUs, such as rate- or mass-based trading 
programs. Uncertainty about whether units would remain in the program 
could be very disruptive to the operation of the program. The second 
reason is to avoid creating incentives for sources to seek to avoid 
their obligations under a CAA section 111(d) plan by undertaking 
modifications. The EPA is concerned that owners or operators of units 
might have incentives to modify purely because of potential 
discrepancies in the stringency of the two programs, which would 
undermine the emission reduction goals of CAA section 111(d).
    The EPA invites comments on this interpretation of CAA section 
111(d)(1), including whether this interpretation is supported by the 
statutory text and whether this interpretation is sensible policy and 
will further the goals of the statute. It should be noted that this 
interpretation is severable from the rest of this rulemaking, so that 
if the EPA revises this interpretation in the final rule or if the EPA 
adopts this interpretation in the final rule but it is invalidated by a 
Court, there would be no effect on the rest of this rulemaking.
2. Timing for Implementation and Achievement of Goals
    This section describes proposed state plan requirements related to 
the timing of achieving emission performance goals, including 
performance demonstrations, performance periods, and interim progress 
milestones.
    As previously discussed, the goals are derived from application of 
four ``building blocks.'' The EPA has based the application of some of 
these measures to reduce CO2 emissions, particularly blocks 
3 (expansion of cleaner generating capacity) and 4 (increasing demand-
side energy efficiency), on forward-looking, longer-term assumptions. 
For example, the EPA expects technologies to reduce carbon emissions to 
more fully develop over time and acknowledges the cumulative effects of 
implementation of EE programs and addition of RE generating capacity 
over time. Therefore, the EPA is not proposing to require each state to 
meet its full, final goal immediately, but rather to meet it by 2030. 
The EPA realizes, however, that states can achieve emission reductions 
from those and other measures in the short-term. Therefore, the EPA is 
proposing that states begin meeting interim goals, beginning in 2020. 
The EPA also believes that timing flexibility in implementing measures 
provides significant benefits that allow states to develop plans that 
will help states achieve a number of goals, including: Reducing cost, 
addressing reliability concerns, and addressing concerns about stranded 
assets. Therefore, the EPA is also proposing to allow states 
flexibility to define the trajectory of emission performance between 
2020 and 2029, as long as the interim emission performance level is met 
on a 10-year average or cumulative basis and the 2030 emission 
performance level is achieved.
    Section VIII.B.1.a of this preamble provides an overview of the 
proposals for state plan performance demonstrations and timing of 
emission reductions. Subsequent subsections include proposals for the 
start date for the interim goal performance period, the duration of the 
performance periods for the final and interim goals, interim progress 
milestone requirements, consequences if actual emission performance 
does not meet the state goal, and out-year requirements for states to 
maintain CO2 emission performance levels over time 
consistent with the final goal. In Section VIII.B.2.f of this preamble, 
the agency also requests comment on alternative requirements aimed at 
continued emission performance improvement after 2029. In Section 
VIII.B.2.g of this preamble, the EPA proposes flexibility for states to 
change from mass-based to rate-based goals in different performance 
periods and, in Section VIII.B.2.h, we solicit comment on planning 
requirements that match the option of alternative, less stringent state 
goals.
a. Performance Demonstrations and Timing of Emission Reductions
    As described previously, the agency is proposing final state-
specific goals (specified in Table 8) that represent emission rates to 
be achieved by 2030, as well as interim goals, to be achieved on 
average over the 10-year period from 2020-2029. The agency is also 
proposing that emission performance levels consistent with the final 
state-specific goals be maintained after 2030.
    This relatively long planning and implementation period provides 
states with substantial flexibility regarding methods and timing of 
achieving emission reductions. States may wish to make adjustments to 
their implementation approaches along the way, or as conditions change 
may need to make adjustments to ensure that their plans achieve the 
goals as intended. As a result, the agency envisions that the EPA, 
states, and affected entities will have an ongoing relationship in the 
course of implementing this program.
    The EPA proposes that a state plan must demonstrate projected 
achievement of the emission performance levels in the plan, and these 
emission performance levels must be equivalent to or better than the 
interim and final goals established by the EPA. Specifically, the state 
plan must demonstrate that the projected emission performance of 
affected EGUs in the state will be equivalent to or better than the 
applicable interim goal during the 2020-2029 period, and equivalent to 
or better than the applicable final goal during the year 2030. The 
state plan must identify requirements that continue to apply after 2030 
and are likely to maintain continued emission performance by affected 
EGUs that meets the final goal; however, quantitative projections of 
emission performance by affected EGUs

[[Page 34905]]

beyond 2030 would not be required by this rule under the proposed 
approach. Instead, the EPA proposes that the state plan would be 
considered to provide for maintenance of emission performance 
consistent with the final goal if the plan measures used to demonstrate 
achievement of the final goal by 2030 will continue in force and not 
sunset.
    In addition to demonstrating that projected plan performance will 
meet the interim and final state goals, the EPA proposes that state 
plans must contain requirements for tracking actual plan performance 
during implementation. For plans that do not include enforceable 
requirements for affected EGUs that ensure achievement of the full 
level of required emission performance and interim progress, the state 
plans would be required to include periodic program implementation 
milestones and emission performance checks, and include corrective 
measures to be implemented if mid-course corrections are necessary. The 
state plan would provide for continued tracking of emission performance 
after 2030, and for corrective measures if the emission performance of 
affected EGUs in the state did not continue to meet the 2030 final goal 
during any three-year performance period.
    The rationale for this approach is that it would ensure that states 
design their plans in a way that considers both the interim and final 
goals. If only the interim goal were considered, a state plan might not 
be sufficient to achieve the final goal.\276\
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    \276\ The 2020-2029 interim goal is expressed as a 10-year 
average emission rate to provide states with flexibility in 
designing their plans. Due to the potential for continued end-use 
energy efficiency improvements, the 2029 four-building-block BSER-
based level is a more stringent level than the 2020-2029 average 
four-building-block BSER-based level. The purpose of the final goal 
is to ensure that each state ultimately achieves the emission 
performance level for affected EGUs that is achievable by 2029. 
Without the final goal, it is possible that a state could achieve 
the 2020-2029 interim goal but not achieve the 2030 final goal.
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    The agency requests comment on a second option in which, in 
addition to submitting a plan demonstrating emission performance 
through 2030, states would be required to make a second submittal in 
2025 showing whether their plan measures would maintain the final-goal 
level of emission performance over time (as further described below). 
If not, the state submittal would be required to strengthen or add to 
measures in the state plan to the extent necessary to maintain that 
level of performance over time.
    The EPA also requests comment on whether 2025, or an earlier or 
later year, would be the optimal year for a second plan submittal under 
the second option.
b. Start Date for Performance Period for Interim Goal
    A performance period is a period for which the state plan must 
demonstrate that the required emission performance level will be met. 
The EPA proposes a start date of January 1, 2020, for the interim goal 
plan performance period.\277\ This date would be the beginning of the 
10-year period for which a state must demonstrate that the projected 
emission performance level of affected EGUs in the state, on average, 
will be equivalent to or better than the applicable interim goal. The 
agency generally requests comment on the appropriate start date and 
rationale.
---------------------------------------------------------------------------

    \277\ The start date for a plan performance period must match 
the start date of the corresponding state emission performance goal. 
If a start date other than January 2020 were selected, the EPA would 
recompute the state goals consistent with the selected start date.
---------------------------------------------------------------------------

    In considering the start date, it is relevant to consider the due 
dates for state plan submittals and the amount of time available for 
program implementation by the start date. January 2020 is 3.5 years 
from the proposed June 2016 deadline for initial plan submittals, 2.5 
years from the proposed June 2017 extended deadline for complete plans 
from states not participating in a multi-state plan, and 1.5 years from 
the proposed June 2018 extended deadline for complete plans from states 
participating in a multi-state plan. The EPA suggests that affected 
entities may have greater lead time for compliance than might be 
implied by the plan submittal dates referenced above. Affected entities 
will have knowledge of state requirements as they are adopted, and the 
state must adopt rules and requirements in advance of submitting its 
complete plan to the EPA. Also, as explained in detail in subsection c, 
states may choose a different emission performance improvement 
trajectory from that which the EPA assumes for purposes of calculating 
state goals, achieving lesser levels of performance in early years and 
more in later years, provided, of course, that the interim 10-year 
average requirement is met.
    The EPA proposes that a 2020 start date for the interim goal plan 
performance period is achievable in light of the following additional 
considerations. First, existing state programs will play a role in 
helping to achieve this rule's proposed emission performance levels. 
Second, in advance of this proposal, many states already were 
contemplating design of strategies that would achieve CO2 
emission reductions equivalent to those that could be required by CAA 
section 111(d) emission guidelines. Third, for inclusion in the 
building blocks, the EPA considered only those emission abatement 
measures that are technically feasible and broadly applicable, and can 
provide reductions in CO2 emissions from affected EGUs at 
reasonable cost.
    For example, the EPA expects that many EGUs will meet their 
requirements in part by implementing heat rate improvements, and those 
actions may be undertaken promptly. The plant operations and 
maintenance (O&M) and engineering solutions used to improve heat rates 
at existing EGUs have long been commercially available and have been 
implemented at EGUs for many years. Further, the relatively modest 
capital costs (average $100/kW) and significant fuel savings associated 
with a suite of heat rate improvement (HRI) methods result in this 
measure being a low-cost approach to reducing CO2 emissions 
from existing EGUs. HRI ``best practices'' (e.g., installation of 
modern control systems, operator training, smart soot blowing) are the 
least-cost HRI methods and can be applied quickly, without lengthy EGU 
outages. The somewhat more costly HRI ``upgrades'' (e.g., steam turbine 
upgrade, boiler draft fan/driver upgrade) may require modest EGU 
outages to implement, but have also been applied on numerous EGUs to 
improve or maintain performance. Drawing on the power sector's 
extensive experience with HRI methods, and the many existing supply 
chains already supporting these methods, the EPA expects that it would 
be feasible to implement HRI projects (i.e., building block 1) by 2020.
    Dispatch changes, which are largely driven by the variable cost of 
operating a given EGU, occur on an hourly basis in the power sector. 
The average availability factor for NGCCs in the U.S. generally exceeds 
85 percent, and can exceed 90 percent for selected groups.\278\ In 
addition, the existing natural gas pipeline and electricity 
transmission networks are already connected to every existing NGCC 
facility, and can support aggregate operation of the NGCC fleet at 70 
percent (or above) at the state level, or can be reasonably expected to 
do so in the time frame for compliance with this rule. Therefore, 
building block 2, which represents shifting of generation from steam 
fossil EGUs to existing NGCCs, is a viable method for providing 
CO2

[[Page 34906]]

emission reductions at existing EGUs by the 2020 compliance start date.
---------------------------------------------------------------------------

    \278\ Source: NERC, 2008-2012 Generating Unit Statistical 
Brochure.
---------------------------------------------------------------------------

    Building Block 3 is based on shifting generation from affected 
fossil units to new renewable energy generating capacity, which is 
added over time, and new or preserved nuclear capacity, all of which is 
expected to be in place by 2020 (see the GHG Abatement Measures TSD for 
more information).
    Finally, there is considerable experience with the states and the 
power sector in designing and implementing demand-side energy 
efficiency improvement strategies and programs. It is also well 
accepted that such improvements can achieve reductions in 
CO2 emissions from existing EGUs at a reasonable cost. 
Building block 4 represents a feasible pathway for reducing utilization 
of carbon-emitting EGUs by implementing improvements in demand-side 
energy efficiency. This building block is based on a ``best practices'' 
scenario where all states achieve a level of performance--matching a 
level achieved or committed to by twelve leading states--of 1.5 percent 
annual incremental electricity savings as a percentage of retail sales. 
For the best practices scenario, all states achieve this level of 
performance no later than 2025, with leading states reaching this level 
sooner. Each state's current level of performance is taken into 
account, with states achieving lower levels of performance being 
allowed more time to reach the best practice level.
c. Duration of Performance Periods for Final and Interim Goals
    The EPA recognizes that a state's circumstances and choice of 
emission reduction strategies may affect the timing of CO2 
emission performance improvement within a multi-year planning period. 
States can be expected to select various combinations of measures and 
those measures may vary in the time needed to reach full 
implementation. The agency recognizes that certain emission reduction 
measures and programs (e.g., heat rate improvements) are generally 
easier to implement in the near term, while others (e.g., renewable 
portfolio standards, demand-side energy efficiency programs) may 
require several years to implement because of the time necessary to 
establish the proper infrastructure if a state does not already have 
such programs in place. Though some states have already implemented 
such programs that are achieving results, other states may have to 
establish them for the first time. New single and multi-state programs, 
as well as existing single and multi-state programs that are adding or 
revising measures, may need time for implementation to achieve the 
required level of emission performance.
    As described in Section VII of the preamble, the EPA is proposing 
state-specific CO2 emission performance goals in a multi-
year format to provide states with flexibility for the timing of 
programs and measures that improve EGU emission performance, while 
ensuring an overall level of performance consistent with application of 
the BSER. Specifically, the agency is proposing the state-specific 
goals (shown in Table 8) which represent emission rates to be achieved 
by 2030 (final goal) and emission rates to be achieved on average over 
the 2020-2029 period (the interim goal).
    The EPA proposes the following as the preferred option for the 
final and interim goal performance periods. As further explained below, 
this option reflects three main objectives: (1) Provide states with 
timing flexibility during the interim goal period to accommodate 
differences in state adoption processes and types of state programs, 
(2) ensure that state plans are designed to achieve the final goal no 
later than 2030, and (3) provide flexibility for year-to-year variation 
in actual emission performance that may occur as the electricity system 
responds to economic fluctuations.
    Interim goal--Projected plan performance demonstration: To be 
approvable, a state plan must demonstrate that the emission performance 
of affected EGUs will meet the interim emission performance level on 
average over the 2020-2029 period.
    Interim goal--Actual plan performance check: In 2030, the emission 
performance of affected EGUs during the period 2020-2029 must be 
compared against the interim goal. (In addition, as described 
separately below, interim emission performance checks will occur during 
this 10-year period.)
    Final goal--Projected plan performance demonstration: To be 
approvable, a state plan must demonstrate that the emission performance 
of affected EGUs will meet the final emission performance level no 
later than 2030, on a single-year basis.
    Final goal--Actual plan performance check: Starting at the end of 
2032, emission performance of affected EGUs must be compared against 
the final goal on a three-year rolling average basis (i.e., 2030-32, 
2031-33, 2032-2034, etc.).
    This proposed approach provides a 10-year performance period for 
the interim performance level. The 10-year period allows states 
flexibility for timing of program implementation as the state ramps up 
its programs to achieve the final performance level. Using the single 
year 2030 as the projected year for achievement of the final goal 
ensures that state plans are designed to achieve the final goal no 
later than 2030; providing a multi-year time frame for projected plan 
performance would inappropriately delay the requirement for a final-
goal level of performance that the EPA's analysis shows is achievable 
at the end of the 10-year interim ramp-up period. Using 2030 also 
avoids overlap with the interim goal performance period. The rolling 
three-year performance periods for measuring actual plan performance 
against the final goal performance level are proposed in light of year-
to-year variability in economic and other factors, such as weather, 
that influence power system operation and affect EGU CO2 
emissions. The choice of 2030-2032 avoids overlap with the 2020-2029 
interim goal performance period.
    For a rate-based plan, 2020-2029 emission performance is an average 
CO2 emission rate for affected EGUs representing cumulative 
CO2 emissions for affected EGUs over the course of the 10-
year performance period divided by cumulative MWh energy output \279\ 
from affected EGUs over the 10-year performance period, with rate 
adjustments for qualifying measures, such as end-use energy efficiency 
and renewable energy measures, as described in Section VIII.F.3. For a 
mass-based plan, 2020-2029 emission performance is total tons of 
CO2 emitted by affected EGUs over the 10-year performance 
period.
---------------------------------------------------------------------------

    \279\ For EGUs that produce both electric energy output and 
other useful energy output, there would also be a credit for non-
electric output, expressed in MWh.
---------------------------------------------------------------------------

    The agency invites comment on this and other approaches to 
specifying performance periods for state plans.
d. Program Implementation Milestones and Tracking of Emission 
Performance
    The EPA recognizes the importance of ensuring that, during the 
proposed 10-year performance period (2020-2029) for the interim goal, a 
state is making steady progress toward achieving the required level of 
emission performance. The EPA is proposing that certain types of state 
plans be required to have program implementation milestones to ensure 
interim progress, as well as periodic checks on overall emission 
performance leading to corrective measures if necessary.
    Some types of plans are ``self-correcting'' in that they inherently

[[Page 34907]]

would assure interim performance and full achievement of the state 
plan's required level of emission performance through requirements that 
are enforceable against affected EGUs. One example is a state plan with 
a rate-based emission performance level that requires affected EGUs 
collectively to meet an emission rate consistent with the state's 
required emission performance level, and allows EGUs to comply through 
an emission rate averaging system. Another example is a plan that 
includes measures or actions (e.g., emission limits that apply to 
affected EGUs and ensure full plan performance) that take effect 
automatically if the plan's required emission performance level is not 
met, in accordance with a specified milestone. The EPA requests comment 
on whether there are other types of state plans that should be 
considered ``self-correcting.''
    The EPA proposes that self-correcting plans need not contain 
interim milestones consisting of program implementation steps, because 
these state plans inherently require both interim progress and 
achievement of the full level of required emission performance in a 
manner that is federally enforceable against affected EGUs. Annual 
reporting of emission performance by the state, however, is required 
for all types of plans.
    For plans that are not self-correcting, the EPA proposes that the 
state plan must identify periodic program implementation milestones 
(e.g., start of an end-use energy efficiency program, retirement of an 
affected EGU, or increase in portfolio requirements under a renewable 
portfolio standard) that are appropriate to the programs and measures 
included in the plan. If, during plan implementation, a state were to 
miss program implementation milestones in its plan, it would need to 
report the delay to the EPA, explain the cause, and describe the steps 
the state will take to accelerate subsequent implementation to achieve 
the planned improvements in emission performance. Depending on the 
severity of delay and the explanation, the EPA could ultimately 
evaluate actions under CAA authorities to ensure timely program 
implementation.
    In addition, we propose that the state and the EPA would track 
state plan emission performance on an ongoing basis, with states 
reporting performance data to the EPA annually by July 1. During the 
interim performance period, beginning in 2022, the state would be 
required each year to include a comparison of emission performance 
achieved to performance projected in the state plan. Each comparison 
would cover the preceding two-year period. The EPA may also approve 
regular, periodic emission comparison checks with a different frequency 
or comparison period to reflect the design of a state's programs (e.g., 
compliance periods for EGUs under an emission limit).
    A report and corrective measures would be required if an interim 
emission check showed that actual emission performance of affected 
entities was not within 10 percent of the performance projected in the 
state plan (i.e., for a rate-based plan, if the average emission rate 
of affected EGUs were 10 percent higher than plan projections, or for a 
mass-based plan, if collective emissions of affected EGUs were 10 
percent higher than plan projections). In that event, the state would 
be required in its submission to explain reasons for the deviation 
(e.g., energy efficiency program not working as effectively as 
expected, prolonged extreme weather that had been unanticipated in 
electricity demand projections) and specify the corrective measures 
that will be taken to ensure that the required level of emission 
performance in the plan will be met. The state also would be required 
to implement those corrective measures as expeditiously as practical.
    The agency proposes that states be given a choice regarding when to 
adopt into regulation the corrective measures that the state plan 
identifies for implementation in the event that state plan performance 
is deficient. First, the state could adopt corrective measures into 
regulation prior to plan submittal in a manner that enables the state 
to implement the measures administratively, without further legislation 
or rulemaking, if a performance deficiency occurs during plan 
implementation. This would expedite implementation of corrective 
measures once a deficiency is discovered. Second, the state could elect 
to wait to adopt into regulation the corrective measures identified in 
the plan until after a plan performance deficiency is discovered. The 
EPA proposes this choice in recognition of the fact that it may be 
challenging for states to fully adopt corrective measures in advance to 
address the possibility that their plan will not perform as projected. 
However, if a state makes the latter choice, the EPA proposes that the 
state must report the reasons for deficient performance and must 
implement corrective measures if actual emission performance was 
inferior to projected performance by eight percent or more (rather than 
10 percent or more). The reason for the lower percentage trigger is to 
identify a gradually developing deficiency in plan performance earlier 
in time. Legislative and/or regulatory action to adopt corrective 
measures after a deficiency is discovered will take significant time. 
State processes to activate corrective measures should be triggered 
earlier if corrective measures are not adopted in regulation and ready 
to implement.
    The EPA alternatively requests comment on whether states should be 
required to create legal authority and/or adopt regulations providing 
for corrective measures in developing the state plan. The agency 
requests comment generally on the conditions that should trigger 
corrective measure requirements. The agency also solicits comment on 
whether actual emission performance inferior to projected performance 
by ten percent (for plans with corrective measures adopted into 
regulation prior to complete plan submittal) is the appropriate trigger 
for requiring a state to report the reasons for deficient performance 
and to implement corrective measures. We are also soliciting comment on 
the range of five percent to fifteen percent. For plans without 
corrective measures adopted into regulation prior to complete plan 
submittal, the agency solicits comment on whether the proposed eight 
percent emission performance deviation trigger is appropriate. We also 
solicit comment on the range of five percent to ten percent.
    The EPA proposes that the state will be required to compare actual 
emission performance achieved during the entire 10-year interim 
performance period (i.e., 2020-2029) against the interim goal. As noted 
above, beginning after 2032, the EPA proposes that the state be 
required to compare actual emission performance achieved against the 
final goal on a rolling three-year average basis (e.g., 2030-32, 2031-
33, etc.). The EPA also requests comment on the milestone approach and 
emission performance checks outlined above in the context of the 
alternative 5-year performance period and the planning approach for 
alternative state goals, which is described below.
e. Consequences if Actual Emission Performance Does Not Meet State Goal
    There are scenarios under which an approved state plan might fail 
to achieve a level of emission performance by affected EGUs that meets 
the state goal. Under some types of plans, a possible scenario is that 
despite successful plan implementation, emissions under the plan turn 
out to be higher than projected at the time of plan

[[Page 34908]]

approval because actual economic conditions vary from economic 
assumptions used when projecting emission performance. State officials 
have raised the possibility that achieved emission performance might 
not meet projected performance if, for example, planned retirements of 
EGUs were postponed because severe weather produced greater-than-
expected electricity generation needs. In addition, emissions could 
theoretically exceed projections because affected entities under a 
state plan did not fulfill their responsibilities, or because the state 
did not fulfill its responsibilities.
    The EPA believes that the emission guidelines should specify the 
consequences in the event that actual emission performance under a 
state plan does not meet the applicable interim goal in 2020-2029, or 
does not meet the applicable final goal in 2030-2032 or later, because 
CAA section 111(d) is not specific on this point. The agency requests 
comment on how the consequences should vary depending on the reasons 
for a deficiency in performance.
    Specifically, the agency requests comment on whether consequences 
should include the triggering of corrective measures in the state plan, 
or plan revisions to adjust requirements or add new measures. The 
agency also requests comment on whether corrective measures, in 
addition to ensuring future achievement of the state goal, should be 
required to achieve additional emission reductions to offset any 
emission performance deficiency that occurred during a performance 
period for the interim or final goal. This concept has been applied, 
for example, in the Acid Rain Program under Title IV of the CAA; a 
source that has sulfur dioxide emissions exceeding the emission 
allowances that it holds at the end of the period for demonstrating 
compliance is required subsequently to obtain additional emission 
reductions to offset its excess emissions.\280\ The agency also 
requests comment on the process for invoking requirements for 
implementation of corrective measures in response to a state plan 
performance deficiency.
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    \280\ CAA section 411(b).
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    The EPA further requests comment on whether the agency should 
promulgate a mechanism under CAA section 111(d) similar to the SIP call 
mechanism in CAA section 110. Under this approach, after the agency 
makes a finding of the plan's failure to achieve the state goal during 
a performance period, the EPA would require the state to cure the 
deficiency with a new plan within a specified period of time (e.g., 18 
months). If the state still lacked an approved plan by the end of that 
time period, the EPA would have the authority to promulgate a federal 
plan under CAA section 111(d)(2)(A).
f. Out-Year Requirements: Maintaining or Improving the Level of 
Emission Performance Required by the Final Goal
    The agency is determining state goals for affected EGU emission 
performance based on application of the BSER during specified time 
periods. This raises the question of whether affected EGU emission 
performance should only be maintained--or instead should be further 
improved--once the final goal is met in 2030. This involves questions 
of goal-setting as well as questions about state planning. In this 
section, the EPA proposes that a state must maintain the required level 
of performance, and requests comment on the alternative of requiring 
continued improvement.
    The EPA believes that Congress either intended the emission 
performance improvements required under CAA section 111(d) to be 
permanent or, through silence, authorized the EPA to reasonably require 
permanence. Other CAA section 111(d) emission guidelines set emission 
limits to be met permanently. Therefore, the EPA is proposing that the 
level of emission performance for affected EGUs represented by the 
final goal should continue to be maintained in the years after 2030. 
The EPA is proposing a mechanism for implementing this objective, and 
is taking comment on an alternative option.
    As noted above, the EPA proposes that the state plan must 
demonstrate that plan measures are projected to achieve the final 
emission performance level by 2030. In addition, the state plan must 
identify requirements that continue to apply after 2030 and are likely 
to maintain affected EGU emission performance meeting the final goal; 
however, quantitative projections of emission performance beyond 2030 
would not be required under the proposed option. Instead, the EPA 
proposes that the state plan would be considered to provide for 
maintenance of emission performance consistent with the final goal if 
the plan measures used to demonstrate projected achievement of the 
final goal by 2030 will continue in force and not sunset.\281\ After 
implementation, the state would be required to compare actual plan 
performance against the final goal on a rolling three-year average 
basis starting in 2030, and to implement corrective measures if 
necessary.
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    \281\ This is straightforward for plans with EGU emission limits 
that ensure the full level of performance required. For renewable 
energy programs, the agency suggests that the state could continue 
to require the renewable portfolio percentage level that was relied 
upon to demonstrate projected achievement of the final goal 
performance level in 2030. For plans that rely in part on end-use 
energy efficiency programs and measures, the EPA requests comment on 
what a state would need to require in its plan to show that 
performance will be maintained after 2030. End-use energy efficiency 
programs and measures often involve an annual energy savings 
requirement or goal, and some types require additional monetary 
expenditures each year to meet those savings requirements or goals.
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    The EPA also requests comment on an alternative approach to a 
state's pre-implementation demonstration that the final-goal level of 
performance will be maintained after 2030. Under this alternative, the 
state plan would be required to include projections demonstrating that 
emission performance would continue to meet the final goal for up to 10 
years beyond 2030. This approach could be implemented through a second 
round of state plan analysis and submittals in 2025 to make the 
demonstration and strengthen or add measures if necessary. The EPA 
generally requests comment on appropriate requirements to maintain the 
emission performance of affected EGUs in years after 2030.
    The EPA also requests comment on whether we should establish BSER-
based state emission performance goals for affected EGUs that extend 
further into the future (e.g., beyond the proposed planning period), 
and if so, what those levels of improved performance should be. Under 
this alternative, the EPA would apply its goal-setting methodology 
based on application of the BSER in 2030 and beyond to a specified time 
period and final date. The agency requests comment on the appropriate 
time period(s) and final year for the EPA's calculation of state goals 
that reflect application of the BSER under this approach.
    The EPA notes that CAA section 111(b)(1)(B) calls for the EPA, at 
least every eight years, to review and, if appropriate, revise federal 
standards of performance for new sources. This requirement provides for 
regular updating of performance standards as technical advances provide 
technologies that are cleaner or less costly. The agency requests 
comment on the implications of this concept, if any, for CAA section 
111(d).
g. State Flexibility To Choose Mass-Based and Rate-Based Goals After 
2029
    The EPA proposes that states have flexibility to choose between a 
rate-

[[Page 34909]]

based and mass-based performance level for each performance period. For 
example, if a state plan used a mass-based performance level for the 
2020-2029 period, the state plan may still use a rate-based performance 
level for final goal performance periods, or vice versa.
    A state that adopted a mass-based performance level for 2020-2029 
would have two options for addressing any perceived need for emissions 
flexibility in light of anticipated electricity demand growth after 
2029. The state either could adopt a rate-based performance level 
consistent with the final goal, or could adopt a mass-based performance 
level based on a translation of the rate-based final goal to a mass-
based goal.
h. Planning Approach for Alternative State Goals
    In Section VII, the EPA requests comment on alternative, five-year 
state emission performance goals for affected EGUs shown in Table 9. 
The alternative goals represent emission rates achievable on average 
during the 2020-2024 period, as well as emission rates to be achieved 
and maintained after 2024. These alternative goals are less stringent 
than the proposed goals in Table 8.
    To accompany the alternative goals, the EPA requests comment on 
another approach for state plan performance periods. This approach 
would require state plans to demonstrate that the required interim 
emission performance level will be met on average by affected EGUs 
during the five-year 2020-2024 interim period, and that the alternative 
final goal be met no later than 2025. After plan implementation, actual 
emission performance would be compared with the alternative final goal 
on a three-year rolling average basis, starting with 2025-2027, in 
light of year-to-year variability in economic and other factors, such 
as weather, that influence power system operation and affect EGU 
CO2 emissions.
    In connection with the alternative state goals, for the years after 
2027, the EPA requests comment on the same ``out-year'' issues and 
concepts for maintaining or improving emission performance over time 
that are described above in Section VIII.B.2.f. The EPA requests 
comment on whether a state plan should provide for emission performance 
after 2025 solely through post-implementation emission checks that do 
not require a second plan submittal, or whether a state should also be 
required to make a second submittal prior to 2025 to demonstrate that 
its programs and measures are sufficient to maintain performance 
meeting the final goal for at least 10 years. In addition, the agency 
requests comment on the appropriate date for any second state plan 
submittal designed to maintain emission performance after the 2025 
performance level is achieved.

C. Criteria for Approving State Plans

    The EPA is proposing to require the twelve plan components 
discussed in Section VIII.D of this preamble. We will evaluate the 
sufficiency of each plan based on the plan addressing those components 
and on four general criteria for a state plan to be approvable. The EPA 
proposes to use the combination of these twelve plan components and 
four general criteria to determine whether a state's plan is 
``satisfactory'' under CAA section 111(d)(2)(A). First, a state plan 
must contain enforceable measures that reduce EGU CO2 
emissions. Second, these enforceable measures must be projected to 
achieve emission performance equivalent to or better than the 
applicable state-specific CO2 goal on a timeline equivalent 
to that in the emission guidelines.\282\ Third, EGU CO2 
emission performance under the state plan must be quantifiable and 
verifiable. Fourth, the state plan must include a process for state 
reporting of plan implementation (at the level of the affected entity), 
CO2 emission performance outcomes, and implementation of 
corrective measures, if necessary. The EPA requests comments on all 
aspects of these general criteria and the twelve specific plan 
components described below.
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    \282\ Flexibilities provided to states in meeting this general 
approvability criterion are discussed below in Section VIII.C.2., 
emission performance.
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    The agency also notes that a CAA section 111(d) state plan is not a 
CAA section 110 state implementation plan (SIP). Although there are 
similarities in the two programs, approvability criteria for CAA 
section 111(d) plans need not be identical to approvability criteria 
for SIPs.
1. Enforceable Measures
    In developing its plan, a state must ensure that the plan is 
enforceable and in conformance with the CAA. We are seeking comment on 
the appropriateness of existing EPA guidance on enforceability in the 
context of state plans under CAA section 111(d), considering the types 
of affected entities that might be included in a state plan.\283\ This 
guidance serves as the foundation for the types of emission limits that 
the EPA has found can be enforced as a practical matter and sets forth 
the general principle that a requirement that is enforceable as a 
practical matter is one that is quantifiable, verifiable, 
straightforward, and calculated over as short a term as reasonable.
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    \283\ Enforceability guidance includes:(1) September 23, 1987 
memorandum and accompanying implementing guidance, ``Review of State 
Implementation Plans and Revisions for Enforceability and Legal 
Sufficiency,'' (2) August 5, 2004 ``Guidance on SIP Credits for 
Emission Reductions from Electric-Sector Energy Efficiency and 
Renewable Energy Measures,'' and (3) July 2012 ``Roadmap for 
Incorporating Energy Efficiency/Renewable Energy Policies and 
Programs into State and Tribal Implementation Plans, Appendix F.''
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    As discussed in section VIII.F.1, the EPA is seeking comment on 
whether the agency should provide guidance on enforceability 
considerations related to requirements in a state plan for entities 
other than affected EGUs (and if so, which types of entities). Also, as 
discussed in section VIII.F.4, the EPA intends to develop guidance for 
evaluation, monitoring, and verification (EM&V) of renewable energy and 
demand-side energy efficiency programs and measures incorporated in 
state plans.
    A state plan must include enforceable CO2 emission 
limits (either rate-based or mass-based) that apply to affected EGUs. 
As noted above, the EPA is proposing that a state plan may take a 
portfolio approach, which would include enforceable CO2 
emission limits that apply to affected EGUs as well as other 
enforceable measures, such as RE and demand-side EE measures, that 
avoid EGU CO2 emissions and are implemented by the state or 
by another entity assigned responsibility by the state. As noted above, 
we are proposing that state plans are not required to impose emission 
limits on affected EGUs that in themselves fully achieve the emission 
performance level. However, we are seeking comment on whether, for 
state plans where emission limits applicable to affected EGUs alone 
would not assure full achievement of the required level of emission 
performance, the state plan must include additional measures that would 
apply if any of the other portfolio of measures in the plan are not 
fully implemented, or if they are, but the plan fails to achieve the 
required level of emission performance.\284\
---------------------------------------------------------------------------

    \284\ This could include, for example, an expansion of the scope 
or an increase in stringency of the current measures in the plan, a 
second set of measures that avoid EGU CO2 emissions, or 
emissions limits that apply to affected EGUs.
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    The EPA recognizes that a portfolio approach may result in 
enforceable state plan obligations accruing to a diverse range of 
affected entities beyond affected EGUs, and that there may be 
challenges to practically enforcing against some such entities in the 
event of noncompliance. We request comment

[[Page 34910]]

on all aspects associated with enforceability of a state plan and how 
to ensure compliance. We are also seeking comment on enforceability 
considerations under different state plan approaches, which is 
addressed below in VIII.F.1.
2. Emission Performance
    The second criterion for approvability is that the projected 
CO2 emission performance by affected EGUs (taking into 
account the impacts of plan measures that are associated with reducing 
utilization from affected EGUs) must be equivalent to, or better than, 
the required CO2 emission performance level in the state 
plan. State plans that are projected to achieve an average 
CO2 emission rate (expressed in lb CO2/MWh) or 
tonnage CO2 emission outcome by all affected EGUs equal to, 
or lower than, the required level of CO2 emission 
performance in the plan would meet this approvability criterion.
    We are proposing that states may demonstrate such emission 
performance by affected EGUs either on an individual state basis or 
jointly on a multi-state basis.
    All of the emission reduction measures included in the agency's 
determination of the BSER reduce CO2 emissions from affected 
EGUs. As a result, the EPA is not proposing that out-of-sector GHG 
offsets could be applied to demonstrate CO2 emission 
performance by affected EGUs in a state plan.
    However, emission limits for affected EGUs that are included in 
state plans could still include provisions that provide the ability to 
use GHG offsets for compliance with the emission limits, provided those 
emission limits would achieve the required level of emission 
performance for affected EGUs. We note that inclusion of such 
provisions would create a degree of uncertainty about the level of 
emission performance that would be achieved by affected EGUs when 
complying with the emission limit (as potentially would other 
flexibility mechanisms included in an emission limit). As a result, 
such emission limits would not be considered ``self-correcting'' as 
discussed above at Section VIII.B.2.d.
    All existing state emission budget trading programs addressing GHG 
emissions include out-of-sector, project-based emission offsets, which 
may be used to cover a portion of the compliance obligation of affected 
sources. Other states may want to take a similar approach, for example, 
to incentivize GHG emission reductions from land use and agricultural 
waste management. How to address GHG offsets included in EGU emission 
limits when projecting emission performance under a state plan is 
addressed in the Projecting EGU CO2 Emission Performance in 
State Plans TSD.
    The ISO/RTO Council, an organization of electric grid operators, 
has suggested that ISOs and RTOs could play a facilitative role in 
developing and implementing region-wide, multi-state plans, or 
coordinated individual state plans. Existing ISOs and RTOs could 
provide a structure for achieving efficiencies by coordinating the 
state plan approaches applied throughout a grid region. Just as the 
ISO/RTO regions today share the benefits and costs of efficient EGU 
dispatch across state boundaries, there are significant efficiencies 
that could be captured by coordinating individual state plans or 
implementing multi-state plans within a grid region. Under one variant 
of this approach, states would implement a multi-state plan and jointly 
demonstrate CO2 emission performance by affected EGUs across 
the entire ISO/RTO footprint. States with borders that cross the 
boundary of one or more ISO or RTO footprints would need to include 
multiple plan components that address affected EGUs in each respective 
ISO or RTO. The EPA is seeking comment on this idea. States that are 
outside the footprint of an ISO or RTO may benefit from consulting with 
other relevant planning authorities when preparing state plans. We are 
also requesting comment on this idea.
3. Quantifiable and Verifiable Emission Performance
    The third criterion for approvability is that a state plan specify 
how the effects of each state plan measure will be quantified and 
verified. The EPA proposes that all plans must specify how 
CO2 emissions from affected EGUs are monitored and reported. 
The EPA is proposing that both mass-based and rate-based plans must 
include CO2 emission monitoring, reporting, and 
recordkeeping requirements for affected EGUs, as specified in the 
emission guidelines. A rate-based plan must also include monitoring, 
reporting, and recordkeeping requirements for useful energy output from 
affected EGUs (electricity and useful thermal output), as specified in 
the emission guidelines. With one exception, these proposed 
requirements are consistent with those in the proposed EGU Carbon 
Pollution Standards for New Power Plants. See 79 FR 1430-1519 (January 
8, 2014). The exception is that we are proposing that useful energy 
output be measured in terms of net output rather than gross output, as 
discussed below.
    For state plans that include other measures that avoid EGU 
CO2 emissions, such as RE and demand-side EE measures, the 
state will also need to include quantification, monitoring, and 
verification provisions in its plan for these measures, which may vary 
depending on the types of requirements included in the specific plan, 
as specified in the emission guidelines. This may include, for example, 
quantification, monitoring, and verification of RE generation and 
demand-side EE energy savings under a rate-based approach.\285\
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    \285\ Considerations for quantification, monitoring, and 
verification of RE and demand-side EE measures are addressed in 
Section VII.F.4 of this preamble and in the State Plan 
Considerations TSD.
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4. Reporting and Corrective Actions
    The fourth criterion for approval is that a state plan must (i) 
specify a process for annual reporting to the EPA of overall plan 
performance and implementation (including compliance of affected 
entities with applicable emission standards) during the plan 
performance periods, and (ii) include a process and schedule for 
implementing corrective measures if reporting shows that the plan is 
not achieving the projected level of emission performance. We solicit 
comment on whether the latter process should include the adoption of 
new plan measures and subsequent resubmission of the plan to the EPA 
for review and approval, or whether the process should specify the 
implementation of measures that are already included in the approved 
plan in the event that the projected level of performance is not being 
achieved. We also solicit comment on the point at which such a process 
and schedule would be triggered, such as at the end of a multi-year 
plan performance period if emission performance is not met, or at 
specified interim stages within a multi-year plan performance period. 
For plans with self-correcting mechanisms, the agency is not proposing 
that requirements for corrective measures be included in the plan. All 
of these considerations are addressed in more detail above in Section 
VIII.B.2.
    The agency is also proposing that a state plan specify appropriate 
periodic reporting requirements for each affected entity in a state 
plan that will be reported at least annually, electronically, and 
disclosed on a state database accessible by the public and the EPA. The 
EPA is requesting comment on the appropriate scope of these reporting 
requirements and whether the reports should also be directly submitted 
by the affected

[[Page 34911]]

entities to the EPA, as well as to the state.

D. State Plan Components

    The EPA is proposing that an approvable plan must meet the 
approvability criteria described above and include the twelve state 
plan components summarized below, consistent with additional specific 
requirements explained elsewhere in this notice. Plans must comply with 
the EPA framework regulations at 40 CFR 60.23-60.29, except as 
specified otherwise by these emission guidelines. These requirements 
apply both to individual state plans and multi-state plans.
    For states wishing to participate in a multi-state plan, the EPA is 
proposing that only one multi-state plan would be submitted on behalf 
of all participating states. The joint submittal would be signed by 
authorized officials for each of the states participating in the multi-
state plan and would have the same legal effect as an individual 
submittal for each participating state. The joint submittal would 
adequately address plan components that apply jointly for all 
participating states and for each individual state in the multi-state 
plan, including necessary state legal authority to implement the plan, 
such as state regulations and statutes. Because the multi-state plan 
functions as a single plan, each of the required plan components 
described below (e.g., plan performance levels, program implementation 
milestones, emission performance checks, and reporting) would be 
designed and implemented by the participating states on a multi-state 
basis.
    We are also seeking comment on two additional options for multi-
state plan submittals. These options could potentially provide states 
with flexibility in addressing contingencies where one or more states 
submit plan components that are not approvable. In such instances, 
these options would simplify EPA approval of remaining common or 
individual portions of a multi-state plan. These options might also 
address contingencies during plan development where a state fails to 
finalize its participation in a multi-state plan, with minimal 
disruption to the submittals of the remaining participating states.
    First, the EPA is seeking comment on whether states participating 
in a multi-state plan should also be given the option of providing a 
single submittal--signed by authorized officials from each 
participating state -- that addresses common plan elements. Individual 
participating states would also be required to provide individual 
submittals that provide state-specific elements of the multi-state 
plan. Both the common multi-state submittal and each individual 
participating state submittal would be required to address all twelve 
plan components described below (even if only through cross reference 
to either the common submittal or individual submittals, as 
appropriate). Under this approach, the combined common submittal and 
each of the individual participating state submittals would constitute 
the multi-state plan submitted for EPA review.
    Second, the EPA is seeking comment on an approach where all states 
participating in a multi-state plan separately make individual 
submittals that address all elements of the multi-state plan. These 
submittals would need to be materially consistent for all common plan 
elements that apply to all participating states, and would also address 
individual state-specific aspects of the multi-state plan. Each 
individual state plan submittal would need to address all twelve plan 
components.
    The EPA proposes that each plan must have the following twelve 
components, except as indicated otherwise for self-correcting plans:
1. Identification of Affected Entities (Affected EGUs and Other 
Responsible Parties)
    A state plan must list the individual affected EGUs in the state 
that are subject to the plan and provide an inventory of CO2 
emissions from those units (for the most recent calendar year prior to 
plan submission for which data are available), and identify any other 
affected entities in a state plan with responsibilities for 
implementation and enforceable obligations under the plan.
2. Description of Plan Approach and Geographic Scope
    The state plan must describe its approach and geographic scope, 
including whether the state will achieve its required level of 
CO2 emission performance on an individual state basis or 
jointly through a multi-state demonstration.
3. Identification of State Emission Performance Level
    The state plan must identify the state's proposed emission 
performance level, which will either be the rate-based CO2 
emission goal identified for the state in the emission guidelines or a 
translation of the rate-based goal to a mass-based goal.
    A state plan must identify the rate-based or mass-based level of 
emission performance that must be met through the plan, (expressed in 
numeric values, including the units of measurement for the level of 
performance, such as pounds of CO2 per net MWh of useful 
energy output or tons of CO2). As noted, in the emission 
guidelines, the EPA will establish the state goal in the form of a 
CO2 emission rate, and the state may, for its emission 
performance level, either adopt that rate or translate it into a mass-
based goal. If the plan adopts a mass-based goal, the plan must include 
a description of the analytic process, tools, methods, and assumptions 
used to translate from the rate-based goal to the mass-based goal.
    The EPA is proposing that multiple states could jointly demonstrate 
emission performance by affected EGUs. For these multi-state 
approaches, states would demonstrate emission performance by affected 
EGUs in aggregate with partner states. For states participating in a 
multi-state approach, the individual state performance goals in the 
emission guidelines would be replaced with an equivalent multi-state 
performance goal. For example, states taking a rate-based approach 
would demonstrate that all affected EGUs subject to the multi-state 
plan achieve a weighted average CO2 emission rate that is 
consistent, in aggregate, with an aggregation of the state-specific 
rate-based CO2 emission performance goals established in the 
emission guidelines that apply to each of the participating states. If 
states were taking a mass-based approach, participating states would 
demonstrate that all affected EGUs subject to the multi-state plan emit 
a total tonnage of CO2 emissions consistent with a 
translated multi-state mass-based goal. This multi-state mass-based 
goal would be based on translation of an aggregation of the state-
specific rate-based CO2 emission performance goals 
established in the emission guidelines that apply to each of the 
participating states.
    The EPA is seeking comment on two options for calculating a 
weighted average, rate-based CO2 emission performance goal 
for multiple states. Under the first option, the weighted average 
emission rate goal for a group of participating states is computed 
using each state's emission rate goal from the emission guidelines and 
the quantity of electricity generation by affected EGUs in each of 
those states during the 2012 base year that the EPA used in calculating 
the state-specific goals. Different levels would be computed for the 
interim and final goals. This approach is consistent with the method 
used to calculate the state-specific, rate-based emission performance 
goals. However, it does not address the fact

[[Page 34912]]

that the weighted average emission rate performance goal for multiple 
states may be influenced significantly by the weighting of electricity 
generation from affected EGUs in different states. This mix of 
generation among affected EGUs in different states could differ 
significantly during the plan performance periods from that during the 
2012 base year.
    Under the second option, the weighted average emission rate goal 
for a group of participating states is computed using each state-
specific emission rate goal and the quantity of projected electricity 
generation by affected EGUs in each state. The calculation would be 
performed for the 2020 through 2029 period to produce a multi-state 
interim goal, and for 2030 to produce a multi-state final goal. This 
projection of electricity generation by affected EGUs would be for a 
reference case that does not include application of either the state-
specific rate-based emission performance goals for the participating 
states or the requirements, programs, and measures included in the 
multi-state plan. This approach addresses the fact that the mix of 
generation among affected EGUs in different states could differ 
significantly during the plan performance periods from that during the 
2012 base year. As a result, it would base the weighted average goal in 
part on the anticipated business-as-usual mix of generation by affected 
EGUs across the multiple states during the plan performance period. 
However, this approach could also significantly alter the weighted 
average performance goal based on projected retirements of affected 
EGUs in one or more states.
    Under both options, the rate-based multi-state goal could be 
translated to a mass-based goal. These options, and the procedure for 
translation to a mass-based goal, are discussed in more detail in the 
Projecting EGU CO2 Emission Performance in State Plans TSD.
    We are requesting comment on whether, to assist states that seek to 
translate the rate-based goal into a mass-based goal, the EPA should 
provide a presumptive translation of rate-based goals to mass-based 
goals for all states, for those who request it, and/or for multi-state 
regions. As another alternative, the EPA could provide guidance for 
states to use in translating a rate-based goal to a mass-based goal for 
individual states and for multi-state regions. This could include 
information about acceptable analytical methods and tools, as well as 
default input assumptions for key parameters that will likely influence 
projections, such as electricity load forecasts and projected fossil 
fuel prices. Under this approach, the EPA might also provide a 
coordinating function in addressing the assumptions applied by multiple 
states within a grid region, acknowledging that assumptions about state 
programs across a broader grid region that are included in an analysis 
scenario may influence projections of CO2 emissions by 
affected EGUs in one or more particular states in the grid region. The 
agency is seeking comment on the process for establishing mass-based 
emission goals, including the options summarized above for the EPA's 
and states' roles in the translation process.
    Technical considerations involved in translating from rate-based 
goals to mass-based goals are discussed in detail in the Projecting EGU 
CO2 Emission Performance in State Plans TSD. The TSD 
includes a discussion of possible acceptable analytical methods, tools, 
and key assumption inputs that will influence projections. The agency 
invites comment on these technical considerations.
4. Demonstration That the Plan Is Projected To Achieve the State's 
Emission Performance Level
    A state plan must demonstrate that the actions taken pursuant to 
the plan are, when taken together, projected to achieve emission 
performance by affected entities that, on average, will meet the 
state's required emission performance level for affected EGUs during 
the initial 2020-2029 plan performance period, and will meet the 
required final emission performance level in 2030. This demonstration 
will include a detailed description of the analytic process, tools, and 
assumptions used to project future CO2 emission performance 
by affected EGUs under the plan and the results of the analysis. 
Considerations related to projecting the emission performance of 
affected EGUs under a state plan are discussed in section VIII.F.7 and 
in the Projecting EGU CO2 Emission Performance in State 
Plans TSD.
5. Milestones
    As described in greater detail in Section VIII.B.2.d., state plans 
must include periodic programmatic milestones to show progress in 
program implementation if the plan is not self-correcting (i.e., does 
not inherently require both interim progress and the full level of 
required emission performance in a manner that is federally enforceable 
against affected EGUs). These programmatic milestones with specific 
dates for achievement should be appropriate to the programs and 
measures included in the plan.
    In addition, the state plan demonstration will indicate the plan's 
intended trajectory of emission performance improvement. As described 
in Section VIII.B.2.d., each year during the interim performance 
period, beginning in 2022 the state must compare the collective 
emission performance achieved by affected entities in the state during 
the previous two-year period with performance projected in the state 
plan. If actual emission performance is not within 10 percent of 
original projections, the state must submit a report by the July 1 
following the end of the two-year period (submitted as part of the 
state's annual report on plan performance described below in section 
VIII.D.10) to explain reasons for the deviation and specify the 
corrective actions that will be taken to ensure that the required level 
of emission performance in the plan will be met.
6. Corrective Measures
    For a plan that does not include self-correcting mechanisms, the 
plan must also specify corrective measures that will be implemented if 
the state's progress in achieving its level of performance for affected 
EGUs falls short of what is projected under the plan, as well as a 
process and schedule for implementing any such measures. The agency 
requests comment on the amount of emission rate improvement or emission 
reduction that the corrective measures included in the plan must be 
designed to achieve (e.g., measures sufficient to address a 10 percent 
performance deficiency). The agency also seeks comment on whether the 
emission guidelines should establish a deadline for implementation of 
corrective measures (e.g., two years from the July 1 deadline described 
above for reporting the deficiency as part of the state's annual report 
on plan performance). Corrective measure provisions are discussed in 
more detail above in section VIII.B.2.d and in section VIII.B.2.f.
7. Identification of Emission Standards and Any Other Measures
    A state plan must identify the affected entities to which each 
emission standard applies (e.g., individual affected EGUs, groups of 
affected EGUs, all the state's affected EGUs in aggregate, other 
affected entities that are not EGUs), as well as any implementing and 
enforcing measures for such standards, and describe each emission 
standard and the process for demonstrating compliance with it pursuant 
to state regulations or another legal instrument, including the 
schedule

[[Page 34913]]

for compliance for each affected entity. In its proposed Carbon 
Pollution Standards (79 FR 1430-1519, January 8, 2014), the EPA 
proposed that the appropriate averaging time for an emission standard 
for new EGUs be no longer than 12 months. Similarly, the EPA proposes 
here that an appropriate averaging time for any rate-based emission 
standard for affected EGUs and/or other affected entities subject to a 
state plan is no longer than 12 months within a plan performance period 
and no longer than three years for a mass-based standard. We also 
solicit comment on longer and shorter averaging times for emission 
standards included in a state plan.
8. Demonstration That Each Emission Standard Is Quantifiable, Non-
Duplicative, Permanent, Verifiable, and Enforceable
    In developing its CAA section 111(d) plan, a state must ensure that 
its plan is enforceable and in conformance with the CAA. As discussed 
in section VIII.C.1, we are seeking comment on the appropriateness of 
existing EPA guidance on enforceability in the context of state plans 
under CAA section 111(d), considering the types of affected entities 
that might be included in a state plan.\286\ This guidance serves as 
the foundation for the types of monitoring, reporting, and limits that 
the EPA has found can be, as a practical matter, enforced, and set 
forth the general principle that a requirement that is enforceable as a 
practical matter is one that is quantifiable, verifiable, 
straightforward and is calculated over as short a term as reasonable.
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    \286\ EPA guidance on enforceability includes: (1) September 23, 
1987 memorandum and accompanying implementing guidance, ``Review of 
State Implementation Plans and Revisions for Enforceability and 
Legal Sufficiency,'' (2) August 5, 2004 ``Guidance on SIP Credits 
for Emission Reductions from Electric-Sector Energy Efficiency and 
Renewable Energy Measures,'' and (3) July 2012 ``Roadmap for 
Incorporating Energy Efficiency/Renewable Energy Policies and 
Programs into State and Tribal Implementation Plans, Appendix F.''
---------------------------------------------------------------------------

    As discussed in section VIII.F.1, the EPA is seeking comment on 
whether the agency should provide guidance on enforceability 
considerations related to requirements in a state plan for entities 
other than affected EGUs (and if so, which types of entities). Also, as 
discussed in section VIII.F.4, the EPA intends to develop guidance for 
evaluation, monitoring, and verification (EM&V) of renewable energy and 
demand-side energy efficiency programs and measures incorporated in 
state plans.
    For each emission standard, a plan must describe how it is 
quantifiable, non-duplicative, permanent, verifiable, and enforceable 
with respect to an affected entity. An emission standard is 
quantifiable if it can be reliably measured, using technically sound 
methods, in a manner that can be replicated. These issues are discussed 
further in Section VIII.F.4 and in the State Plan Considerations TSD.
    An emission standard is non-duplicative with respect to an affected 
entity if it is not already incorporated in another state plan, except 
in instances where incorporated in another state as part of a multi-
state plan. An example of a duplicative emission standard would occur 
where recognition of avoided CO2 emissions from, for 
example, a wind farm, could be applied in more than one state's CAA 
section 111(d) plan, except in the case of a multi-state plan where 
recognition is assigned among states or emission performance is 
demonstrated jointly for all affected EGUs subject to the multi-state 
plan. This does not mean that measures in an emission standard cannot 
also be used for other purposes. For example, if a state wished to take 
credit for CO2 emissions avoided due to electric generation 
from a new wind farm, those avoided emissions could be considered non-
duplicative and included for purposes of CAA section 111(d), even if 
electric generation from that wind farm was also being used to generate 
renewable energy certificates (RECs) to comply with the state's RPS 
requirements. It also does not mean that a single affected entity could 
not be subject to similar emission standards in different state plans. 
For example, an affected entity might be an electric distribution 
utility that has a service territory that crosses state lines. This 
entity might be subject to a separate state demand-side EE requirement 
for electricity supplied in each of the states where it serves 
electricity customers. In this instance, the same company could be an 
affected entity subject to a different state demand-side EE requirement 
in each state plan, without these emission standards in each plan being 
considered duplicative. The EPA solicits comment on whether an emission 
reduction becomes duplicative (and therefore cannot be used for 
demonstrating performance in a plan) if it is used as part of another 
state's demonstration of emission performance under its CAA section 
111(d) plan.
    An emission standard is permanent if the standard must be met for 
each applicable compliance year or period, or replaced by another 
emission standard in a plan revision, or the state demonstrates in a 
plan revision that the emission standard is no longer necessary for the 
state to meet its required emission performance level for affected 
EGUs.
    An emission standard is verifiable if adequate monitoring, 
recordkeeping and reporting requirements are in place to enable the 
state and the Administrator to independently evaluate, measure, and 
verify compliance with it. This is discussed further in Section 
VIII.F.4 and in the State Plan Considerations TSD. An emission standard 
is enforceable if: (1) It represents a technically accurate limitation 
or requirement and the time period for the limitation or requirement is 
specified, (2) compliance requirements are clearly defined, (3) the 
affected entities responsible for compliance and liable for violations 
can be identified, (4) each compliance activity or measure is 
practically enforceable in accordance with EPA guidance on practical 
enforceability (as discussed in Section VIII.F.1 of this preamble), and 
the Administrator and the state maintain the ability to enforce against 
violations and secure appropriate corrective actions pursuant to CAA 
sections 113(a)-(h).
9. Identification of Monitoring, Reporting, and Recordkeeping 
Requirements
    The state plan must describe the CO2 emission 
monitoring, reporting, and recordkeeping requirements for affected 
EGUs, including requirements for monitoring and reporting of useful 
energy output if a state plan is taking a rate-based approach. The EPA 
is proposing that each plan include monitoring, reporting, and 
recordkeeping requirements for CO2 emissions and useful 
energy output (if applicable) that are materially consistent with the 
requirements specified in the emission guidelines. State plans with a 
rate-based form of the emission performance level must require affected 
EGUs to report hourly net energy output (including net MWh generation, 
and where applicable, useful thermal output) to the EPA on an annual 
basis.
    Most affected EGUs already monitor CO2 emissions under 
40 CFR Part 75 and report the data using the EPA's Emission Collection 
and Monitoring Plan System (ECMPS), which would generally satisfy 
CO2 emission reporting requirements under the proposed 
guidelines. However, we are seeking comment on two possible adjustments 
to the Part 75 Relative Accuracy Test Audit (RATA) requirements for 
steam EGU stack gas flow monitors that can affect reported 
CO2 emissions. The first possible adjustment would be to 
require use of the most accurate RATA

[[Page 34914]]

reference method for specific stack configurations, while the second 
possible adjustment would be to require a computation adjustment when 
an EGU changes RATA reference methods. The rationale for these possible 
adjustments is described further in the Part 75 Monitoring and 
Reporting Considerations TSD available in the docket.
    We are also proposing monitoring and reporting protocols for net 
energy output under 40 CFR Part 75 that would allow the ECMPS to be 
used for purposes of meeting the net energy output reporting 
requirement. Affected facilities with multiple generators (e.g., 
combined cycle facilities) would be required to report the electric 
output from all generators. The proposed protocols include a default 
apportionment procedure for multi-EGU facilities under which the net 
generation of each EGU at the facility would be determined as the net 
generation of the facility multiplied by the ratio of the EGU's gross 
generation to the sum of the gross generation for all EGUs at the 
facility. (In the case of EGUs producing both electric energy output 
and useful thermal output, the apportionment procedure would include a 
thermal-to-electric energy conversion calculation as provided in the 
proposed EGU GHG NSPS regulations.\287\) We solicit comment on whether 
EGUs producing both electric energy output and useful thermal output 
should be required to report both electric and useful thermal output. 
In addition, the proposed protocols would allow facilities to use 
alternative apportionment procedures with EPA approval. We invite 
comment on the proposal for reporting of net rather than gross energy 
output and on the proposed protocols. Specifically, we are seeking 
comment on: Any existing protocols for reporting net output (FERC, 
NERC, etc.); electricity meter specifications; electricity meter 
quality assurance testing and reporting procedures; apportionment 
procedures for parasitic load at multi-unit facilities; treatment of 
externally provided electricity; and monitoring and quality assurance 
testing and reporting procedures for non-electric energy output at CHP 
units. (Options regarding these topics are discussed in the TSD 
mentioned above.) Also, consistent with the requests for comment in the 
proposed CAA section 111(b) GHG NSPS regulations for modified and 
reconstructed sources, we invite comment here on a range of two-thirds 
to 100 percent credit for useful thermal output in the final rule, or 
other alternatives to better align incentives with avoided emissions.
---------------------------------------------------------------------------

    \287\ 70 FR 1429-1519; January 8, 2014.
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    A state plan that contains other emission standards, in addition to 
emission limits applicable to affected EGUs, must include additional 
reporting and recordkeeping requirements related to these other 
measures. These reporting and recordkeeping requirements will consist 
of the data necessary for each affected entity to demonstrate 
compliance with its obligations. This could include, for example, 
reporting of MWh electricity savings achieved by an electric 
distribution utility under an end-use energy efficiency resource 
standard and utility compliance with requirements of the standard. 
These requirements might also include comparable reporting by an 
electric distribution utility of renewable energy certificates (RECs) 
held, or renewable energy purchased or generated, under a renewable 
energy portfolio standard, and compliance with the standard. This is 
discussed further in Section VIII.F.5 and the State Plan Considerations 
TSD.
    The EPA is proposing that state plans must include a record 
retention requirement of ten years, and we request comment on this 
proposed timeframe.
10. Description of State Reporting
    A state plan must provide that the state will submit reports to the 
EPA detailing plan implementation and progress, including the actions 
taken by the state, affected EGUs, and any other affected entities 
under the plan; the status of compliance by affected EGUs and any other 
affected entities with their obligations under the plan; current 
aggregate and individual CO2 emission performance by 
affected EGUs during the reporting year and prior reporting years; and 
any additional measures applied under the plan during the reporting 
period. The state plan must describe the process, timing, and content 
for these reports. The EPA is proposing that an annual report is due no 
later than the July 1 following the end of the reporting year.
    While some of the proposed reporting requirements such as reporting 
of EGU emissions (which can be done through existing reporting 
mechanisms) would not place additional burdens on states, others may 
require assembling information that is being reported under state 
programs into a single report. For example, in the case of a rate-based 
state plan that calls for adjusting the actual emission rate of the 
state's affected EGUs based on emissions avoided through renewable 
energy or end-use energy efficiency programs, the requirement for 
comparing actual plan performance against projected plan performance 
requires the state to incorporate information on results achieved by 
those programs each year. This emission performance comparison serves 
as the basis for showing either that a state plan is on track or that 
corrective measures are needed. Another reporting element is a list of 
facilities and their compliance status. The EPA is requesting comment 
on the appropriate frequency of reporting of the different proposed 
reporting elements, considering both the goals of minimizing 
unnecessary burdens on states and ensuring program effectiveness. In 
particular, the agency requests comment on whether full reports 
containing all of the report elements should only be required every two 
years.
    In addition, the EPA is soliciting comment on whether these reports 
should be submitted electronically, to streamline transmission.
11. Certification of State Plan Hearing
    A state plan must provide certification that a hearing on the state 
plan was held, a list of witnesses and their organizational 
affiliations, if any, appearing at the hearing, and a brief written 
summary of each presentation or written submission pursuant to the 
requirements of the EPA framework regulations at 40 CFR 60.23-60.29.
12. Supporting Material
    The state must provide supporting material and technical 
documentation related to applicable components of the plan. In its 
plan, a state must adequately demonstrate that it has the legal 
authority for each implementation and enforcement component that it has 
included in its plan as part of a federally enforceable emission 
standard. A state can make such a demonstration by providing supporting 
material related to the state's legal authority used to implement and 
enforce each component of the plan, such as statutes, regulations, 
public utility commission orders, and any other applicable legal 
instruments.
    A state plan must also provide analytical materials used in 
translating a rate-based goal to a mass-based goal (if a translation is 
included), analytical materials used in projecting emission performance 
that will be achieved through the plan, relevant implementation 
materials, and any additional technical requirements and guidance the 
state proposes to use to implement elements of the plan.

[[Page 34915]]

E. Process for State Plan Submittal and Review

1. Overview
    Under the framework regulations, state plans would be due nine 
months after finalization of the emission guidelines. 40 CFR 
60.23(a)(1). The President in his June 25, 2013 Memorandum specified 
that states should submit plans by June 30, 2016, which would provide 
states thirteen months. During the outreach process, many states 
expressed concern that this was not sufficient time to prepare and 
submit a state plan to the EPA. States commented that additional time 
was needed to accommodate, among other things, state legislative and 
rulemaking schedules, coordination among states involved in multi-state 
plans, coordination with third parties, and the complex technical work 
needed to develop a state plan. The EPA recognizes that state 
administrative procedures can be lengthy, some states may need new 
legislative authority, and states planning to join in a multi-state 
plan will likely need more than thirteen months to get necessary 
elements in place. Balanced against that concern, however, is the 
urgency of addressing carbon emissions and the fact that there are 
certain steps we believe states can take within thirteen months to set 
themselves on a clear path to adoption of a complete plan. Therefore, 
the EPA is proposing a plan submittal process with a submittal date of 
June 30, 2016 (thirteen months after the expected finalization date of 
the emission guidelines), which provides additional time to submit a 
complete plan to the EPA after June 30, 2016, when justified. Part of 
that justification would include the state's demonstration of having 
taken meaningful steps during the first thirteen months toward 
submitting a complete plan. This approach involves the option that we 
refer to as an initial submittal, followed by submittal of a complete 
state plan no later than either June 30, 2017 for single-state plans or 
June 30, 2018 for multi-state plans.
    In addition, for states wishing to participate in a multi-state 
plan, the EPA is proposing that only one multi-state plan would be 
submitted on behalf of all participating states, provided it is signed 
by authorized officials for each of the states participating in the 
multi-state plan and contains the necessary regulations, laws, etc. for 
each state in the multi-state plan. In this instance, the joint 
submittal would have the same legal effect as an individual submittal 
for each participating state.
2. State Plan Submittal and Timing
    The EPA framework regulations (40 CFR 60.23) require that state 
plans be submitted to the EPA within nine months of promulgation of the 
emission guidelines, unless the EPA specifies otherwise.\288\ In view 
of the potential that these plans may require states to develop new 
regulatory or statutory authority, we are proposing that each state 
must submit a plan to the EPA by June 30, 2016, which is more than one 
year after the expected finalization date of the emission guidelines. 
The state may submit a complete plan, or if justified, an initial plan 
that documents the state's progress in preparing a complete plan. To 
qualify for an extension of the June 30, 2016 deadline for submitting a 
complete plan, the state must submit an initial plan that demonstrates 
the state is on track to develop a complete plan and that includes 
meaningful steps that clearly commit the state to complete an 
approvable plan.
---------------------------------------------------------------------------

    \288\ 40 CFR 60.23(a)(1).
---------------------------------------------------------------------------

    The EPA proposes that approvable justifications for seeking an 
extension beyond 2016 for submitting a complete plan include: A state's 
required schedule for legislative approval and administrative 
rulemaking, the need for multi-state coordination in the development of 
an individual state plan, or the process and coordination necessary to 
develop a multi-state plan. The EPA is requesting comment on other 
circumstances for which an extension of time would be appropriate. We 
are also seeking comment on whether some justifications for extension 
should not be permissible.
    If a state submits an initial state plan by June 30, 2016, and it 
meets the minimum requirements for an initial state plan, as specified 
in the plan guidelines, then the deadline extension for submitting a 
complete plan that the state requested will be deemed granted. If the 
EPA determines that the initial plan does not meet the guidelines, the 
EPA will notify the state by letter, within 60 days, that the agency 
cannot approve the state's initial plan as submitted. The EPA believes 
this approach is authorized by, and consistent with, section 60.27(a) 
of the implementing regulations.
    If the EPA approves a two-year extension to June 30, 2018, for a 
state developing a multi-state plan, the state would be required to 
provide one update, on June 30, 2017, on its progress toward milestones 
and schedules in the initial plan for developing and submitting a 
complete plan. We are requesting comment on this approach and the 
timing and frequency of updates that the state must provide.
3. Components of an Initial State Plan Submittal and Approvability 
Criteria
    As noted, if a state is unable to prepare and submit a complete 
plan by June 30, 2016, the state must make an initial submittal by that 
date. To be approved, the EPA proposes that the initial plan must 
address all components of a complete plan, including identifying which 
components are not complete. For incomplete components, an approvable 
initial submittal must contain a comprehensive roadmap outlining the 
path to completion, including milestones and dates. We recognize that 
certain options that states may choose involve more analytic effort to 
precisely demonstrate sources of emission reductions than other 
options.
    The EPA is proposing that the state must provide an opportunity for 
public comment on a substantial draft of its initial submittal. The EPA 
proposes that this public comment opportunity will not be governed by 
the procedural requirements of the framework regulations that apply to 
the state's adoption of a complete plan, such as the requirement that 
the state hold a public hearing. 40 CFR 60.23(c)-(f). An initial plan 
might not include any legally enforceable provisions that the state 
would have adopted through its administrative or legislative processes, 
which generally provide for public input. Therefore, to ensure that the 
public has an opportunity to understand and inform the initial plan, 
the EPA is proposing that prior to submittal on June 30, 2016 the state 
must have provided a reasonable opportunity for public comment on a 
substantial draft of the initial submittal, with notice to the EPA of 
that comment period. The EPA can use this comment opportunity to advise 
the state whether it is on track to submit an approvable initial plan. 
When the state submits its initial plan, it must provide the EPA with a 
response to any significant comments it received on issues relating to 
the approvability of the initial plan so that the EPA can fully assess 
whether it is approvable.
    To be approvable, the initial plan must include the following 
information:
     A description of the plan approach and progress to date in 
developing a complete plan.
     Initial quantification of the level of emission 
performance that will be achieved through the plan.
     A commitment to maintain existing measures that limit or 
avoid CO2 emissions (e.g., renewable energy

[[Page 34916]]

standards, unit-specific limits on operation or fuel utilization), at 
least until the complete plan is approved.
     A comprehensive roadmap for completing the plan, including 
process, analytical methods, and schedule (with milestones) specifying 
when all necessary plan components will be complete (e.g., 
demonstration of projected plan performance; implementing legislation, 
regulations and agreements; any necessary approvals).
     Identification of existing programs, if any, the state 
intends to rely on to meet its emission performance level.
     Identification of executed agreements with other states 
(e.g., memorandum of understanding (MOU)), if a multi-state approach is 
being pursued.
     A commitment to submit a complete plan by no later than 
the applicable required date and explanation of actions the state will 
take to show progress in addressing incomplete plan components.
     A description of all steps the state has already taken in 
furtherance of actions needed to finalize a complete plan (e.g., copies 
of draft or proposed regulations, draft or introduced legislation, or 
draft implementation materials).
     Evidence of an opportunity for public comment and a 
response to any significant comments received on issues relating to the 
approvability of the initial plan.
    The EPA is soliciting comment on whether there are other elements 
that a state must include in its initial submittal to qualify for a 
date extension. Specifically, the EPA requests comment on whether the 
guidelines should require a state to have taken significant, concrete 
steps toward adopting a complete plan for the initial plan to be 
approvable. For example, while it may be difficult for a state to 
complete its administrative or legislative process within thirteen 
months, it may be reasonable to require that a state must document that 
it has at least proposed any necessary regulations and introduced any 
necessary legislation within the first thirteen months to qualify for 
additional time to submit a complete plan.
    For states participating in a multi-state program, the initial 
submittal should include executed agreements among the participating 
states and a road map for both design of the multi-state program and 
its implementation at the state level. The RGGI provides an example of 
such an approach. The RGGI participating states signed a Memorandum of 
Understanding (MOU) in December 20, 2005, in which the states 
``express[ed] their mutual understandings and commitments''.\289\ The 
MOU included a detailed outline of the multi-state emission budget 
trading program, which served as a guide for drafting a model rule. The 
MOU also included commitments by the participating states to draft and 
finalize the model rule by specified dates, and a commitment to seek to 
establish in statute and/or regulation a program materially consistent 
with the model rule in each state by a specified date.\290\ The MOU 
also included a commitment to launch the program by January 1, 2009 in 
all states and specified a process for establishing a non-profit 
organization to assist the states in administering the regional aspects 
of the program. In addition, prior to execution of the MOU, the RGGI 
states committed, through letters from the Governors of participating 
states, to engage in the development of a market-based program to 
reduce CO2 emissions from power plants. This was followed by 
publication of an action plan for tasks leading up to agreement on the 
basic structure of the program, which was ultimately formalized in the 
MOU.
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    \289\ Regional Greenhouse Gas Initiative Memorandum of 
Understanding, available at http://rggi.org/design/history/mou. Two 
states subsequently signed the original MOU in early 2007 and a 
third joined the program later that year through an amendment of the 
MOU; one of the original states withdrew from the MOU in late 2011.
    \290\ The model rule specified elements that needed to be 
consistent across states for the program to function, as well as 
areas where state rules could differ (e.g., the method used for 
allocating CO2 allowances). For more information, see 
Regional Greenhouse Gas Initiative Model Rule, available at http://rggi.org/docs/ProgramReview/_FinalProgramReviewMaterials/Model_Rule_FINAL.pdf.
---------------------------------------------------------------------------

4. Process for EPA Review of State Plans
    Following the June 30, 2016, deadline for state plan submittals, 
the EPA will review plan submittals for approvability. For a state that 
submits an initial state plan by June 30, 2016, and requests an 
extension of the deadline for the submission of a complete state plan, 
the EPA will determine if the initial plan submittal meets the minimum 
requirements for an initial state plan. If it meets the minimum 
requirements for an initial state plan, as specified in the emission 
guidelines, the state's request for a deadline extension to submit a 
complete plan will be deemed granted, and the complete plan must be 
submitted to the EPA by no later than June 30, 2017 or June 30, 2018 as 
appropriate.
    After receipt of a complete plan submittal, the EPA proposes that 
the agency will review the plan and, within twelve months, approve or 
disapprove the plan through a notice-and-comment rulemaking process, 
similar to that used for approving state implementation plan submittals 
under section 110 of the CAA. The framework regulations currently 
provide for the EPA to act on a complete plan within four months. 40 
CFR 60.27(b). The EPA proposes that for plans under these guidelines, 
the agency will act on a complete plan within twelve months to provide 
adequate time for rulemaking procedures.
    Currently, the EPA's framework regulations do not explicitly 
provide for the EPA to use the different forms of approval actions 
Congress introduced into the SIP program in the 1990 Clean Air Act 
Amendments. The EPA is taking comment on whether, for complete state 
plans under these guidelines, the agency may use two approval 
mechanisms provided for in CAA sections 110(k)(3) and (4), 42 U.S.C. 
7410(k)(3) and (4). CAA section 111(d)(1) provides that the EPA shall 
establish ``a procedure similar to that provided by section 7410 of 
this title [section 110 of the Act].'' The EPA is considering whether 
to update the procedures for acting on complete state plans under the 
guideline to reflect the enhancements Congress included in CAA section 
110 for agency actions on state implementation plans.
    The first mechanism is a partial approval/partial disapproval. 
Where a CAA section 111(d) plan includes severable provisions, some of 
which are approvable and some of which are not, the EPA is taking 
comment on whether the agency should interpret the CAA as providing the 
flexibility to approve those elements that meet the requirements of 
this guideline, while disapproving those elements that do not. Any plan 
that is partially approved and partially disapproved would not fully 
discharge the state's obligation to submit a fully approvable plan, but 
the partial approval would make federally enforceable those elements of 
the state's plan that comply with these guidelines.
    The second mechanism is a conditional approval. Where a CAA section 
111(d) plan is substantially approvable and requires only minor 
amendments to fully meet the requirements of these guidelines, the EPA 
is taking comment on whether the agency should interpret the CAA as 
providing the flexibility to approve that plan on the condition that 
the state commits to curing the minor deficiencies within one year. Any 
such conditional approval would be treated as a disapproval if the 
state fails to comply with its commitment. During the year following 
the conditional approval while the state works to cure

[[Page 34917]]

the deficiency identified in the condition, the state's plan would be 
federally enforceable.
    The EPA has seen that these mechanisms have proven useful when 
reviewing and acting on state implementation plan submittals under CAA 
section 110. They allow the state, the EPA, and citizens to enforce 
good elements of plans or plans that are substantially complete while 
the state and the EPA work together to put in place a fully approvable 
plan. The agency notes that complete plan submittals under these 
guidelines, like SIPs that implement air quality standards, also may 
contain multiple program elements.
5. Failure To Submit a Complete Plan
    If a state fails to submit a complete plan by the applicable 
deadline, the EPA will notify the state by letter of its failure to 
submit. The EPA will publish a Federal Register notice informing the 
public of any such notifications. When appropriate, the agency may 
batch the publication of such notices periodically to simplify 
publication.
6. Modification of an Approved State Plan
    During the course of implementation of an approved state plan, a 
state may wish to update or alter one or more of the enforceable 
measures in the state plan, or replace certain existing measures with 
new measures. The EPA proposes that the state may revise its state plan 
provided that the revision does not result in reducing the required 
emission performance for affected EGUs specified in the original 
approved plan. In other words, no ``backsliding'' on overall plan 
emission performance through a plan modification would be allowed.
    If the state wishes to revise enforceable measures in its approved 
state plan, the EPA proposes that the state must submit the revised 
enforceable measures to the EPA and demonstrate that the revised set of 
enforceable measures in the modified plan will result in emission 
performance at affected EGUs that is equivalent to or better than the 
level of emission performance required by the original state plan. In 
the case of minor changes to enforceable measures, this showing may be 
a simple explanation of why the changes will not alter the emission 
performance of affected EGUs under the state plan, or will clearly 
improve the emission performance of affected EGUs under the state plan. 
In the case of more substantive changes to enforceable measures, or 
substitution of a new measure for an old measure, new projections of 
emission performance under the modified plan would be needed to 
demonstrate that the modified plan will meet the required level of 
emission performance for affected EGUs specified in the original 
approved plan. The EPA requests comment on whether, for such new 
projections of emission performance, the projection methods, tools, and 
assumptions used should match those used for the projection in the 
original demonstration of plan performance, or should be updated to 
reflect the latest data and assumptions, such as assumptions for 
current and future economic conditions and technology cost and 
performance.
7. Plan Templates and Electronic Submittal
    The EPA is seeking comment on the creation of a template for 
initial and complete state plan submittals. A plan template would 
provide a framework that includes all of the necessary components for 
an initial and complete submittal that could be populated by states. 
This could assist states in compiling their plan submittals and 
streamline EPA review by assuring greater consistency in the format and 
organization of submittals. This would provide greater certainty for 
states about what they need to include in a submittal and allow the EPA 
to provide a quicker response to states about the completeness and 
approvability of submittals. We are further seeking comment on whether 
a template may be more appropriate for initial plan submittals than 
complete plans. Initial plan submittals are likely to be more similar 
across states, compared to complete plans, which may include a diverse 
range of components, depending on the state plan approach.
    The EPA is also seeking comment on whether it should provide for, 
or require, electronic submittal of initial and complete plans. It is 
the EPA's experience that the electronic submittal of information 
increases the ease and efficiency of data submittal and data 
accessibility. We note that a number of states have requested an 
electronic submittal process for state implementation plans (SIPs) 
under CAA section 110, and the EPA has implemented a pilot program with 
a number of states for electronic submittal of such plans. The 
Electronic State Implementation Plan Submission Pilot (eSIPS) includes 
an EPA-state workgroup that has developed and will evaluate an 
electronic submission process. This pilot will use the EPA's Central 
Data Exchange (CDX) electronic submission system. We are seeking 
comment on the suitability of such an approach for submittal of state 
plans under CAA section 111(d).

F. State Plan Considerations

    The EPA is proposing to give states broad discretion to develop 
plans that best suit their circumstances and policy objectives. In 
developing its plan, a state will need to make a number of decisions 
that will require careful consideration, in order to ensure that its 
plan both meets the state's policy objectives and is approvable by the 
EPA. In this section, we identify several key decision points and 
factors that states should consider when developing their plans.
    The EPA has also prepared a TSD, titled ``State Plan 
Considerations,'' that provides further information on these topics. 
The agency is seeking comment on the contents of this TSD and all 
aspects of the state plan decision points and factors below.
1. Affected Entities Other Than Affected EGUs
    A state will need to identify each affected entity responsible for 
meeting compliance obligations under its plan and the means by which 
compliance with each plan requirement will be met, as well as 
demonstrate that it has the legal authority to subject such entities to 
the federally enforceable requirements specified in its state plan. We 
are proposing that affected entities in an approvable state plan may 
include: An owner or operator of an affected EGU, other affected 
entities with responsibilities assigned by a state (e.g., an entity 
that is regulated by the state, such as an electric distribution 
utility, or a private or public third-party entity), and a state 
agency, authority or entity. We are seeking comment on other 
appropriate examples of affected entities beyond the affected EGUs.
    While the EPA seeks to provide states with broad discretion to 
develop plans that best suit their circumstances and policy objectives, 
a plan that assigns responsibility to affected entities other than 
affected EGUs may be more challenging to implement and enforce than a 
plan with requirements assigned only to affected EGUs.
    Furthermore, it may be more challenging for a state to demonstrate 
that it has sufficient legal authority to subject such affected 
entities other than affected EGUs to the federally enforceable 
requirements specified in its state plan. We seek comment on whether 
the EPA should provide guidance on enforceability considerations 
related to requirements in a state plan for affected entities other 
than EGUs (and if so, which such entities). The State Plan 
Considerations

[[Page 34918]]

TSD provides illustrative examples of possible entities and legal 
mechanisms.
2. Treatment of Existing State Programs
a. Framing Considerations
    Many state officials and stakeholders have said that the EPA should 
avoid structuring the CAA section 111(d) emission guidelines in a way 
that would disadvantage states that already have adopted programs that 
reduce CO2 emissions from EGUs. The EPA agrees with that 
policy principle.
    There is much less agreement among states and stakeholders on the 
specifics of how existing state programs should be treated in a 
demonstration that a proposed state plan will achieve the required 
level of emission performance.
    The EPA, starting from recent historical data, has identified the 
affected EGU emission performance improvements and resulting average 
emission performance levels for affected EGUs that are achievable, 
considering cost, in each state over the 2020-2029 period, with 
achievement of the final CO2 emission performance level by 
2030.
    As explained in Section VII above, the EPA's proposed state-
specific goals reflect actions that many states have already taken to 
reduce or avoid EGU CO2 emissions. CO2 emission 
reductions due to shifts to lower CO2-emitting power 
generation are also represented in the 2012 base period that was used 
to assess certain building blocks that are applied in calculating a 
state emission performance goal.\291\
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    \291\ For example, in such instances a significant shift to NGCC 
generation prior to 2012 may result in a lower potential for further 
re-dispatch to these units, as witnessed in the 2012 base period 
data. This would influence the calculated rate-based emission goal 
for the state, reducing the percentage improvement required relative 
to the base period CO2 emission rate.
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    The agency recognizes that states that have already shifted toward 
lower carbon-intensity generation or ramped up demand-side EE programs 
are better positioned to meet state-specific goals. For example, states 
where significant shifts in generation to NGCC units have already 
occurred would be closer to the generation mix reflected in the state 
goals than states where NGCC capacity is not yet being operated to the 
same degree. Likewise, states with relatively well-established demand-
side EE programs would be able to build on those programs more quickly 
than states with less established programs, and would be closer to, or 
in some cases already achieving, the level of demand-side energy 
efficiency reflected in the state goals.
b. Proposed Approach for Treatment of Existing State Programs and 
Measures in an Approvable State Plan
    The EPA is proposing that existing state programs, requirements, 
and measures,\292\ may qualify for use in demonstrating that a state 
plan will achieve the required level of emission performance, provided 
they meet the approvability requirements in the emission guidelines 
(summarized above in Section VIII.C) and relevant requirements for plan 
components in the emission guidelines (described above in Section 
VIII.D). Several options for treatment of existing state programs and 
measures are described below.
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    \292\ An ``existing measure'' refers to a state or utility 
requirement, program, or measure that is currently ``on the books.'' 
For the purposes of this discussion, this may include a legal 
requirement that includes current and future obligations or current 
programs and measures that are in place and are anticipated to be 
continued or expanded in the future in accordance with established 
plans. Existing measures may have past, current, and future impacts 
on EGU CO2 emissions.
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    Specifically, the EPA is proposing that, for an existing state 
requirement, program, or measure, a state may apply toward its required 
emission performance level the emission reductions that existing state 
programs and measures achieve during a plan performance period as a 
result of actions taken after the date of this proposal.\293\ This 
proposed approach would recognize beneficial emission impacts from 
existing state programs and measures during a plan performance period. 
It would do so in a way that may be generally compatible with the 
forward-looking methodology that the EPA used to propose state emission 
performance goals based on the BSER. By making actions taken after 
proposal eligible to help meet a state's required emission performance 
level, this approach would support early beneficial emission-reducing 
actions. This option would ensure that actions taken after proposal of 
the emission guidelines and prior to 2020 as a result of requirements 
in a state plan, could be recognized as contributing toward meeting a 
state's required emission performance level for affected EGUs.
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    \293\ We are also proposing that this proposed limitation would 
not apply to existing renewable energy requirements, programs and 
measures because existing renewable energy generation prior to the 
date of proposal of the emission guidelines was factored into the 
state-specific CO2 goals as part of building block 3.
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    In general, the agency has identified two broad options for 
treatment of existing state programs and measures. As noted above, the 
EPA proposes that emission reductions that existing state requirements, 
programs and measures achieve during a plan performance period as a 
result of actions taken after a specified date may be recognized in 
determining emission performance under a state plan. While proposing 
that the ``specified date'' would be the date of proposal of these 
emission guidelines, the EPA also requests comment on the following 
alternatives: The start date of the initial plan performance period, 
the date of promulgation of the emission guidelines, the end date of 
the base period for the EPA's BSER-based goals analysis (e.g., the 
beginning of 2013 for blocks 1-3 and beginning of 2017 for block 4, 
end-use energy efficiency), the end of 2005, or another date.
    For this option, we are seeking comment on the point in time after 
which such actions should be able to qualify for use during a plan 
performance period, considering the method used to set state goals. 
Whether this option is consistent in practice with the EPA's 
application of the BSER may depend on the date or dates that are 
applied for qualifying actions under existing state programs, 
requirements, and measures. For example, implementation of measures 
subsequent to the proposal or promulgation of the emission guidelines 
may be consistent with a forward-looking goal-setting approach, as 
these actions may be necessary to meet a required level of emission 
performance during the plan performance period or will put a state in a 
better position to meet the required level of performance. An example 
is the EPA's treatment of end-use energy efficiency potential in state 
goal-setting, where the energy savings achievable during the initial 
plan performance period are premised in part on a ramping up of end-use 
energy efficiency programs and cumulative energy savings prior to the 
beginning of the plan performance period. Earlier dates may also be 
consistent with a forward-looking goal-setting approach, if the goal-
setting approach is premised in part on actions that could be taken 
prior to the initial plan performance period. However, inconsistency 
issues may arise if the selected date is not adequately synchronized 
with the goal-setting method. The EPA requests comment on whether there 
is a rational basis for choosing a date that predates the base period 
from which the EPA used historical data to derive state goals. The 
agency generally requests comment on the appropriate date to select 
under this option.
    The EPA also solicits comment on a second broad option. This option 
would recognize emission reductions that existing state requirements, 
programs

[[Page 34919]]

and measures achieved starting from a specified date prior to the 
initial plan performance period, as well as emission reductions 
achieved during a plan performance period. The specified date could be, 
for example: The date of promulgation of the emission guidelines; the 
date of proposal of the emission guidelines; the end date of the base 
period for the EPA's BSER-based goals analysis (e.g., the beginning of 
2013 for blocks 1-3 and the beginning of 2017 for block 4, end-use 
energy efficiency); the end of 2005; or another date.
    The EPA requests comment on this option--that emission reduction 
effects that occur prior to the beginning of the initial plan 
performance period could be applied toward meeting the required level 
of emission performance in a state plan. This approach would enable a 
state to count emission improvements achieved by state programs prior 
to 2020 toward its interim goal, allowing the state to begin 
demonstrating emission performance earlier and follow a more gradual 
emission improvement trajectory during the interim performance period 
of 2020-2029. This approach would in effect allow higher emissions 
during the 2020-2029 period than would occur under the proposed 
approach (i.e., requiring less emission performance improvement during 
that period). The rationale for this approach would be that higher 
emissions in 2020-2029 would be offset by pre-2020 emission reductions 
not required by the CAA section 111(d) program. However, total 
emissions to the atmosphere would likely be greater under this 
approach, unless the pre-2020 emission reductions that can be counted 
toward the state goal are limited to reductions that would not have 
occurred in the absence of the CAA section 111(d) program. To the 
extent that states are able to both adopt and implement new 
requirements earlier than 2020 (e.g., by 2018 or 2019), this approach 
could provide an incentive for earlier emission reductions. The agency 
requests comment on whether pre-2020 implementation of new requirements 
would be practical for states. The agency generally requests comment on 
this approach, including the conditions that should apply to pre-2020 
emission reductions that would count toward the state goal.
    The agency also requests comment on the alternative dates listed 
above in connection with this option. We also request comment on 
whether this option is inconsistent with the forward-looking method 
that the EPA has proposed for establishing state goals based on the 
application of the BSER.
    The agency is seeking comment on whether some variation of this 
approach could be justified as consistent with the EPA's proposed goal-
setting approach, as well as the general concept of the BSER and its 
application in establishing state goals. In particular, we are seeking 
comment on whether the emission effects of actions that are taken after 
proposal or promulgation of the emission guidelines or the approval of 
a state plan, but which occur prior to the beginning of the initial 
state plan performance period, could be applied toward meeting the 
required level of emission performance in a state plan.
c. Application of Options Under Rate-Based and Mass-Based Plan 
Approaches
    Under a rate-based approach, the options described above would 
address the eligibility date for qualifying demand-side EE measures 
that, through MWh savings, avoid CO2 emissions from affected 
EGUs. Measures installed after the eligibility date could generate MWh 
savings during a plan performance period, and related avoided 
CO2 emissions, that could be applied toward meeting a 
required rate-based emission performance level. Under the proposed 
option, the eligibility date would be the date of these proposed 
emission guidelines. For example, under this approach, new demand-side 
EE measures installed in 2015 or later to meet an existing, on-the-
books energy efficiency resource standard (EERS) would be a qualifying 
measure. However, only MWh savings beginning in 2020 and related 
avoided CO2 emissions could be applied toward meeting a 
required rate-based emission performance level.
    Under a mass-based approach, the options described above would be 
applied when establishing a reference case scenario projection that is 
used to translate a rate-based goal to a mass-based goal. For example, 
demand-side EE measures after a respective eligibility date would not 
be included in the scenario that is used to project CO2 
emissions from affected EGUs when establishing a translated mass-based 
emission goal. This could be achieved by not including the incremental 
requirements of an end-use EERS requirement in a reference case 
projection, beginning at a specified date. These considerations are 
addressed in more detail in Section VIII.F.7. below and in the 
Projecting CO2 Emission Performance in State Plans TSD.
3. Incorporating RE and Demand-Side EE Measures Under a Rate-Based 
Approach
    We are proposing that RE and demand-side EE measures may be 
incorporated into a rate-based approach through an adjustment or 
tradable credit system applied to an EGU's reported CO2 
emission rate.\294\ Under such a process, measures that avoid EGU 
CO2 emissions from affected EGUs, such as quantified and 
verified end-use energy savings and renewable energy generation, could 
be credited toward a demonstrated CO2 emission rate for EGU 
compliance purposes or used by the state to administratively adjust the 
average CO2 emission rate of affected EGUs when 
demonstrating achievement of the required rate-based emission 
performance level in a state plan.
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    \294\ We are also proposing that RE and demand-side EE measures 
could be used under a mass-based portfolio approach in an approvable 
state plan. However, the focus of this section is limited to 
application of such measures under a rate-based approach.
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    Under this approach, affected EGUs \295\ could comply with a 
CO2 emission rate limit in part through the use of credits 
for actions that avoid CO2 emissions from affected EGUs. If 
a state is implementing a portfolio approach, then the state could 
administratively adjust the average CO2 emission rate of 
affected EGUs through a similar process, provided that the 
CO2-avoiding measures are enforceable elements of the state 
plan.
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    \295\ This could include an individual affected EGU or group of 
affected EGUs if a rate-based averaging or trading approach is used.
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    We are seeking comment on different approaches for providing such 
crediting or administrative adjustment of EGU CO2 emission 
rates, which are elaborated further in the State Plan Considerations 
TSD.
    Credits or adjustment might represent avoided MWh of electric 
generation or avoided tons of CO2 emissions. The approach 
chosen could have significant implications for the amount of adjustment 
or credit provided for RE and demand-side EE measures. If adjustment or 
credits represent avoided MWh, they would be added to the denominator 
when determining an adjusted lb CO2/MWh emission rate. If 
adjustment or credits represent avoided CO2 emissions, they 
would be subtracted from the numerator when determining an adjusted lb 
CO2/MWh emission rate.
    A MWh crediting or adjustment approach implicitly assumes that the 
avoided CO2 emissions come directly from the particular 
affected EGU (or group of EGUs) to which the credits are

[[Page 34920]]

applied. It assumes, in effect, that an additional emission-free MWh is 
being generated by that respective EGU, and that the RE or demand-side 
EE measure reduces CO2 emissions from that individual EGU or 
group of EGUs.\296\ In practice, the average or marginal CO2 
emission rate in the power pool or identified region--representing the 
avoided CO2 emissions from the generating sources being 
displaced by a MWh of energy savings or a MWh of renewable energy 
generation--could differ significantly from the calculated avoided 
CO2 emissions derived by adjusting the MWh output of an 
affected EGU.
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    \296\ As a result, the assumed avoided CO2 emissions 
from an individual MWh of energy savings or MWh of generation from 
renewable energy will differ based on the reported CO2 
emission rate of the individual EGU to which the MWh is applied as 
an adjustment to its MWh output.
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    An alternative approach is to provide an adjustment based on the 
estimated CO2 emissions that are avoided from the power pool 
or identified region as a result of RE and demand-side EE measures. 
This approach implicitly assumes that the avoided CO2 
emissions come from the electric power pool or other identified region 
as a whole, rather than an individual EGU. The avoided CO2 
emissions are determined based on the MWh saved or generated, 
multiplied by a CO2 emission rate for the power pool or 
region. This CO2 emission rate could be based on the average 
or marginal emission rate in the power pool or region, or could be 
based on the emission rate that represents the required rate-based 
emission performance level in the plan. We invite comment on each of 
these possible approaches.
    In addition, because some of the CO2 emissions avoided 
through RE and demand-side EE measures may be from non-affected EGUs, 
we are seeking comment on how this might be addressed in a state plan, 
whether when adjusting or crediting CO2 emission rates of 
affected EGUs based on the effects of RE and demand-side EE measures or 
otherwise. How these dynamics might be addressed, both in projections 
of plan performance and in actual demonstration of performance achieved 
under a plan, is further discussed in the State Plan Considerations 
TSD.
4. Quantification, Monitoring, and Verification of RE and Demand-Side 
EE Measures
    A key consideration for state plans is the process and requirements 
under a state plan for quantifying, monitoring, and verifying the 
effect of RE and demand-side EE measures that result in electricity 
generation or electricity savings.
    The EPA is proposing that a state plan that includes enforceable RE 
and demand-side EE measures must include an evaluation, measurement, 
and verification (EM&V) plan that explains how the effect of these 
measures will be determined in the course of plan implementation. An 
EM&V plan will specify the analytic methods, assumptions, and data 
sources that the state will employ during the state plan performance 
periods to determine the energy savings and energy generation related 
to RE and demand-side EE measures. An EM&V plan would be subject to EPA 
approval as part of a state plan. As discussed below, the EPA intends 
to develop guidance on acceptable EM&V methods that could be 
incorporated in an approvable EM&V plan that is included as part of an 
approvable state plan.
    Utilities and states have conducted ongoing EM&V of demand-side EE 
and RE measures and programs for several decades. Current practice with 
EM&V for RE and demand-side EE programs in the U.S. is primarily 
defined by state public utility commission (PUC) requirements for 
customer-funded energy efficiency and renewable energy programs, as 
well as related compliance and reporting requirements for EERS and 
renewable portfolio standards (RPS).
    The level of PUC oversight of demand-side EE programs varies from 
state to state, but this oversight process has generated the majority 
of the industry guidance and protocols for documenting energy savings 
from EE programs. Typically, impact evaluation reports are responsive 
to requirements established by PUCs and submitted (usually annually) 
for PUC review, approval, and use in resource planning and performance 
assessment. These PUC requirements generally rely upon a well-defined 
set of industry-standard practices and procedures. In states with the 
most experience implementing and overseeing demand-side EE programs, 
this typically includes: Use of one or more industry-standard EM&V 
protocols or guidelines; use of ``deemed savings values,'' \297\ where 
appropriate, for well-understood demand-side EE measures; consideration 
of local factors, such as climate, building type, and occupancy; 
involvement of stakeholders and solicitation of expert advice regarding 
EM&V processes and resulting energy savings impacts; conduct of EM&V 
activities (e.g., direct equipment measurements, application of deemed 
savings, and reporting of impacts) on a regular basis; and provision of 
interim and annual reporting of achieved energy savings.
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    \297\ Deemed savings are measure-specific stipulated values 
based on historical and verified data. Unlike other EM&V approaches, 
deemed savings approaches involve limited or no measurement 
activities, and are therefore a common and relatively low-cost 
strategy for documenting energy savings.
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    Despite this well-defined and generally accepted set of industry 
practices, many states with energy efficiency programs use different 
input values and assumptions in applying these practices (e.g., net 
versus gross savings,\298\ run-time of equipment, measure lifetime). 
This can result in significant differences in claimed energy savings 
values for similar energy efficiency measures between states and 
utilities, even when the same measure type is installed under otherwise 
identical circumstances. In response to a growing awareness of this 
lack of cross-state comparability, policy makers, regulatory agencies, 
and other stakeholders are increasingly advocating for the use of 
common evaluation approaches across jurisdictions. A number of states 
and utilities in different regions of the country are already working 
to develop such common approaches.
---------------------------------------------------------------------------

    \298\ Gross savings are the change in energy use (MWh) and 
demand (MW) that results directly from program-related actions taken 
by program participants, regardless of why they participated in a 
program. Net savings refer to the change in energy use and demand 
that is directly attributable to a particular energy efficiency 
program.
---------------------------------------------------------------------------

    For RE measures and programs, EM&V employed by states and utilities 
commonly relies upon a set of standard practices and procedures, such 
as the use of revenue-quality meters for quantifying RE generation. As 
a result, existing state and utility requirements and processes for 
quantification, monitoring, and verification of RE programs and 
measures generally provide a solid foundation for minimum requirements 
or guidance established by the EPA for state plans.
    For both RE and demand-side EE measures included in state plans, 
additional information and reporting may be necessary to accurately 
quantify the avoided CO2 emissions associated with these 
measures, such as information on the location and the hourly, daily, or 
seasonal basis of renewable energy generation or energy savings.
    Current state and utility EM&V approaches for RE and demand-side EE 
programs and mandates are discussed in more detail in the State Plan

[[Page 34921]]

Considerations TSD. We are seeking comment on the suitability of these 
approaches in the context of an approvable state plan, and on whether 
harmonization of state approaches, or supplemental actions and 
procedures, should be required in an approvable state plan. In 
particular, we intend to establish guidance for acceptable 
quantification, monitoring, and verification of RE and demand-side EE 
measures for an approvable EM&V plan, and are seeking comment on 
critical features of such guidance, including scope, applicability, and 
minimum criteria.\299\ We are also seeking comment on the appropriate 
basis for and technical resources used to establish such guidance, 
including consideration of existing state and utility protocols, as 
well as existing international, national, and regional consensus 
standards or protocols.\300\ The EPA's goal in developing such guidance 
is to assure that it is consistent with industry-standard EM&V 
approaches for both RE and demand-side EE measures and programs, 
leverages the EM&V resources and infrastructure already in place in 
many states, and strikes a reasonable balance between EM&V costs, 
rigor, and the value of resulting information, while considering the 
specific use of such information in assessing avoided CO2 
emissions from affected EGUs.
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    \299\ Section V.A.4 of the State Plan Considerations TSD 
includes a detailed description of these EM&V parameters.
    \300\ A list of these protocols is provided in Section V.A.3.1 
of the State Plan Considerations TSD.
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    In developing guidance, the agency does not intend to limit the 
types of RE and demand-side EE measures and programs that can be 
included in a state plan, provided that supporting EM&V is rigorous, 
complete, and consistent with the EPA's guidance. This approach 
recognizes differences among RE and demand-side EE programs and 
measures with respect to implementation history and experience, 
existence of applicable EM&V protocols and methods, and the nature and 
type of program oversight (e.g., whether or not a program is subject to 
PUC oversight). The EPA is requesting comment on the merits of this 
approach, including whether such guidance should identify types of RE 
and demand-side EE measures and programs for which evaluation of 
results is relatively straightforward and which are appropriate for 
inclusion in a state plan. Such approaches might be subject to 
streamlined review of EM&V protocols included in an approvable state 
plan, provided that such protocols are applied in accordance with 
industry best practices. For example, many utilities have implemented a 
similar core set of RE and demand-side EE measures and programs for 
utility customers. For these types of measures and programs, a 
substantial base of experience has been established nationally for the 
evaluation of measure and program outcomes. Other types of measures and 
programs, such as those that seek to alter consumer and building 
occupant behavior might pose quantification and verification 
challenges. Still other types of measures, such as state energy-
efficient appliance standards and building codes, have not typically 
been subject to similar evaluation of energy savings results. These 
types of approaches might have substantial impacts, and the EPA does 
not want to discourage their implementation in state plans, but they 
might require development of appropriate quantification, monitoring, 
and verification protocols. The EPA and its federal partners intend to 
discuss the development of appropriate EM&V protocols for such measures 
with states in the coming years.
    As an alternative to the EPA's proposed approach of allowing a 
broad range of RE and demand-side EE measures and programs to be 
included in state plans, provided that supporting EM&V documentation 
meets applicable minimum requirements, the EPA is requesting comment on 
whether guidance should limit consideration to certain well-established 
programs, such as those characterized in Section V.A.4.2.1 of the State 
Plan Considerations TSD.
5. Reporting and Recordkeeping for Affected Entities Implementing RE 
and Demand-Side EE Measures
    If a state plan incorporates RE and demand-side EE measures under a 
rate-based approach or implements a mass-based portfolio approach with 
such measures, reporting and recordkeeping requirements for an 
approvable plan would differ from those applicable to an affected EGU. 
For example, these requirements may include compliance reporting by an 
electric distribution utility subject to an EERS or RPS. They may also 
include reporting by a vertically integrated utility implementing an 
approved integrated resource plan. In the latter instance, the utility 
might also be the owner and operator of affected EGUs, but additional 
reporting of quantified effects of RE and demand-side EE measures under 
the utility plan would be necessary to demonstrate emission performance 
under the state plan. In other instances, a state agency or entity or a 
private or public third-party entity might be implementing programs and 
measures that support the deployment of end-use energy efficiency and 
clean energy technologies that are incorporated into a state plan. In 
each of these instances, reporting of program compliance or program 
outcomes is a necessary part of an approvable plan to demonstrate 
emission performance under the plan.
    Examples of potential reporting obligations for affected entities 
implementing RE and demand-side EE measures in an approvable state plan 
are provided in the State Plan Considerations TSD. We are seeking 
comment on the examples and suitability of potential approaches 
described in the TSD and any other appropriate reporting and 
recordkeeping requirements for affected entities beyond affected EGUs.
6. Treatment of Interstate Effects
    The electricity system and wholesale electricity markets are 
interstate in nature. EGUs in one state provide electricity to 
customers in neighboring states. Power companies often own EGUs in more 
than one state and manage them as a system. EGUs are dispatched both 
within and across state borders.
    Similarly, programs and measures in a state plan, such as RE and 
demand-side EE measures, may affect the performance of the 
interconnected electricity system beyond a state border. In addition, 
many state programs allow for actions in neighboring states to meet the 
in-state requirement or explicitly address CO2 emissions in 
neighboring states. For example, many state renewable portfolio 
standards allow for generation by qualifying renewable energy sources 
in other states to count toward meeting the state portfolio 
requirement. Some states also apply CO2 emission 
requirements related to the generation of power purchased by regulated 
utilities, including power imported from out of state.
    The EPA recognizes the complexity of accounting for interstate 
effects associated with measures in a state plan in a consistent 
manner, to allow states to take into account the CO2 
emission reductions resulting from these programs while minimizing the 
likelihood of double counting. We also realize that interstate effects 
on CO2 emissions from affected EGUs could be attributed in 
different manners in the context of an approvable state plan. The EPA 
is seeking comment on the options summarized below, as well as 
alternatives. These options and alternatives, and how they might apply 
to both projections of plan performance

[[Page 34922]]

and reporting of achieved plan performance, are addressed in the State 
Plan Considerations TSD.
    The EPA is proposing that, for demand-side EE measures, consistent 
with the approach that the EPA used in determining the BSER, a state 
could take into account in its plan only those CO2 emission 
reductions occurring (or projected to occur) in the state that result 
from demand-side EE measures implemented in the state. The agency is 
also proposing that, for states that participate in multi-state plans, 
the participating states would have the flexibility to distribute the 
CO2 emission reductions among states in the multi-state 
area, as long as the total CO2 emission reductions claimed 
are equal to the total of each state's in-state emissions reductions 
that result from demand-side EE measures implemented in those states. 
We are also proposing that states could jointly demonstrate 
CO2 emission performance by affected EGUs through a multi-
state plan in a contiguous electric grid region, in which case 
attribution of emission reductions from demand-side EE measures would 
not be necessary. We also request comment on whether a state should be 
able to take credit for emission reductions out of state due to in-
state EE measures if the state can demonstrate that the reductions will 
not be double-counted when the relevant states report on their achieved 
plan performance, and what such a demonstration should entail. We 
request comment on these and other approaches for taking into account 
CO2 emission reductions from demand-side EE measures in 
state plans.
    The EPA is proposing that, for renewable energy measures, 
consistent with existing state RPS policies, a state could take into 
account all of the CO2 emission reductions from renewable 
energy measures implemented by the state, whether they occur in the 
state or in other states. This proposed approach for RE acknowledges 
the existence of renewable energy certificates (REC) that allow for 
interstate trading of RE attributes and the fact that a given state's 
RPS requirements often allow for the use of qualifying RE located in 
another state to be used to comply with that state's RPS.
    The EPA is also seeking comment on how to avoid double counting 
emission reductions using this proposed approach. The agency is also 
proposing that states participating in multi-state plans could 
distribute the CO2 emission reductions among states in the 
multi-state area, as long as the total CO2 emission 
reductions claimed are equal to the total of each state's in-state 
emission reductions from RE measures. We also request comment on the 
option of allowing a state to take into account only those 
CO2 emission reductions occurring in its state. We are also 
proposing that states could jointly demonstrate CO2 emission 
performance by affected EGUs through a multi-state plan in a contiguous 
electric grid region, in which case attribution among states of 
emission reductions from renewable energy measures would not be 
necessary. We also request comment on whether a state should be able to 
take credit for emission reductions out of state due to renewable 
energy measures if the state can demonstrate that the reductions will 
not be double-counted when the relevant states report on their achieved 
plan performance, and on what such a demonstration should entail. We 
request comment on these and other approaches for taking into account 
CO2 emission reductions from renewable energy measures.
7. Projecting Emission Performance
    As proposed, an approvable state plan will include a projection of 
CO2 emission performance by affected EGUs under the plan. In 
addition, a state plan that is using a mass-based goal in determining 
the required level of emission performance under the plan will include 
a translation of the rate-based emission goal in the emission 
guidelines to a mass-based goal. This translation will involve a 
projection of CO2 emissions from affected EGUs during the 
initial 2020-2029 plan performance period and in 2030, under a scenario 
that assumes the rate-based goal in the emission guidelines is met.
    The EPA is striving to find a balance between providing state 
implementation flexibility and ensuring that the emission performance 
required by CAA section 111(d) is properly defined in state plans and 
that plan performance projections have technical integrity. Each state 
plan must include a projection of CO2 emission performance 
from affected EGUs during the multi-year plan period that will result 
from implementation of the plan. Depending on the type of plan 
approach, this will include either a projection of the average 
CO2 emission rate achieved by affected EGUs or total 
CO2 emissions from affected EGUs.
    The credibility of state plans under CAA section 111(d) will depend 
in large part on ensuring credible and consistent emission performance 
projections in state plans. Therefore, the use of appropriate methods, 
tools and assumptions for such projections is critical.
    Considerations for projecting emission performance under a state 
plan will differ depending on the type of plan. This includes 
differences in how inputs to projections are derived; how projections 
are conducted, including tools, methods and assumptions; and how 
aspects of a plan are represented in these projections.
    In general, any material component of a state requirement or 
program included in a state plan that could affect emission performance 
by affected EGUs should be accurately represented in emission 
projections included in the state plan.
    For example, mass-based emission budget trading programs include a 
number of compliance flexibility mechanisms that might impact emission 
performance achieved by affected EGUs subject to these programs. These 
include multi-year compliance periods; the ability to bank allowances 
issued in a previous compliance period for use in a subsequent 
compliance period; the use of out-of-sector project-based emission 
offsets; and cost-containment allowance reserves that make additional 
allowances available to the market if pre-established allowance price 
thresholds are achieved. As a result, annual emissions from affected 
sources subject to an emission budget trading program often differ from 
the established annual emission budget for affected sources. In 
addition, these programs may be multi-sector in nature, regulating 
emissions for source categories in addition to EGUs. As a result, 
emission projections in state plans will need to accurately account for 
and represent these compliance flexibilities, as well as the scope of 
affected sources if they are broader than EGUs affected under CAA 
section 111(d). Similarly, other types of state programs, such as RPS, 
may include flexibility mechanisms or other provisions, such as 
alternative compliance payment mechanisms, banking, and limits on total 
ratepayer impact, that affect the ultimate amount of electricity 
generation required under the portfolio standard. These considerations 
for different types of state programs are discussed in more detail in 
the Projecting EGU CO2 Emission Performance in State Plans 
TSD.
    In general, as with projections used to determine a mass-based 
goal, projections of emission performance under a state plan could be 
conducted using historical data and parameters for estimating the 
future impact of individual state programs and measures. Alternatively, 
a projection could include modeling, such as use of a capacity planning 
and dispatch

[[Page 34923]]

model.\301\ This latter approach would be able to capture dynamic 
interactions within the electricity sector, based on system operation 
and market forces, including interactions among state programs and 
measures and the dynamics of market-based measures.
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    \301\ In many cases, this approach will also require the 
development of parameters for estimating the future effect of 
individual state programs and measures, for use as input assumptions 
for modeling.
---------------------------------------------------------------------------

    These considerations, and considerations for projecting emission 
performance under different types of state plan approaches, are 
discussed in detail in the Projecting EGU CO2 Emission 
Performance in State Plans TSD.
    We are seeking comment on the considerations discussed in this TSD, 
including options presented for how projections might be conducted in 
an approvable state plan, and how different types of state plan 
approaches are represented in these projections. We are seeking further 
comment on whether the EPA should develop guidance that describes 
acceptable projection approaches, tools, and methods for use in an 
approvable plan, as well as providing technical resources for 
conducting projections.
    The ISO/RTO Council, an organization of electric grid operators, 
has suggested that ISOs and RTOs could provide analytic support to help 
states develop and implement their plans. The ISOs and RTOs have the 
capability to model the system-wide effects of individual state plans. 
Providing assistance in this way, they felt, would allow states with 
borders that fall within an ISO or RTO footprint to assess the system-
wide impacts of potential state plan approaches. In addition, as the 
state implements its plan, ISO/RTO analytic support would allow the 
state to monitor the effects of its plan on the regional electricity 
system. ISO/RTO analytic capability could help states assure that their 
plans are consistent with region-wide system reliability. The ISO/RTO 
Council suggested that the EPA ask states to consult with the 
applicable ISO/RTO in developing their state plans. The EPA agrees with 
this suggestion and encourages states with borders that fall within one 
or more ISO or RTO footprints to consult with the relevant ISOs/RTOs.
8. Potential Emission Reduction Measures Not Used To Set Proposed Goals
    States may include measures in their plans beyond those that the 
EPA included in its determination of the BSER. In general, any measures 
that meet the proposed criteria for approvable state plans could be 
employed in a state plan. Beyond that, under a mass-based approach, any 
measure that reduces affected EGU emissions--even if not included in 
the state plan--will, if implemented during a plan performance period, 
help to achieve actual emissions performance that meets the required 
level.
    Beyond the types of state plan measures already discussed in this 
section of the preamble, the agency has identified a number of other 
measures that could also lead to CO2 emission reductions 
from EGUs. These include, for example, electricity transmission and 
distribution efficiency improvements, retrofitting affected EGUs with 
partial CCS, the use of biomass-derived fuels at affected EGUs, and use 
of new NGCC units. Although the emission reduction methods discussed in 
this section are not proposed to be part of the BSER, the agency 
anticipates that some states may be interested in using these 
approaches in their state plans. The agency solicits comment on whether 
these measures are appropriate to include in a state plan to achieve 
CO2 emission reductions from affected EGUs. In addition to 
the specific requests for comment related to specific technologies 
below, we also request comment on other measures that would be 
appropriate. In addition, we request comment on whether the EPA should 
provide specific guidance on inclusion of these measures in a state 
plan.
    In addition, technological advances and innovations in energy and 
pollution control technologies will continue over time. The agency is 
aware that as new technologies become available or as costs of a 
technology drop because of technical advances, states may wish to 
include measures in their state plans that make use of those 
technologies.
    To be more specific, there are multiple potential measures that can 
be taken at an EGU beyond heat rate improvements that will reduce 
CO2 emissions. Some examples are: Including co-firing of 
less CO2 intensive fuels such as natural gas, retrofit of 
partial CCS and use of integrated renewable technology (i.e. meeting 
some of the steam load in a steam turbine from a fossil unit and part 
of the steam load from a concentrating solar installation), and 
improving heat rates of oil- and gas-fired generating units. Co-firing 
of natural gas and the use of CCS could be incorporated into a state 
plan demonstration of emission performance as a reduction in the 
emission rate at an affected EGU in exactly the same way that heat rate 
reductions could be quantified. In the case of an integrated renewable 
and fossil unit, reductions could either be quantified as a reduction 
in rate, or the renewable component could be quantified in the same way 
other renewable reductions are quantified in the state plan.
    In addition to the nuclear generation taken into account in the 
state goals analysis, any additional new nuclear generating units or 
uprating of existing nuclear units, relative to a baseline of capacity 
as of the date of proposal of the emission guidelines, could be a 
component of state plans. This baseline would be consistent with the 
proposed approach for treatment of existing state programs. The agency 
requests comment on alternative nuclear capacity baselines, including 
whether the date for recognizing additional non-BSER nuclear capacity 
should be the end of the base year used in the BSER analysis of 
potential nuclear capacity (i.e., 2012). In general, when considering 
nuclear generation in a state plan, states may wish to consider the 
impacts that different types of policies may have on different types of 
zero-emitting generation. Under a capped approach which does not 
provide any ``crediting'' for zero-emitting generation, the impact on 
all zero-emitting units should be the same. In a rate based approach 
that credited zero or low-emitting generation, the crediting mechanism 
used could result in different economic impacts on different types of 
zero- or low-emitting generation.
    Another way that a state plan could reduce utilization and 
emissions from affected existing EGUs would be through construction of 
new NGCC--that is, NGCC on which construction commences after the date 
of proposal or finalization of CAA section 111(b) standards applicable 
to that source. (The agency's CAA section 111(d) proposal does not 
include new NGCC as a component of the BSER, but requests comment on 
that question in Section VI of this preamble.) Under a mass-based plan 
where an emission limit on affected EGUs would assure achievement of 
the required level of emission performance in the state plan, any 
emission reductions at affected EGUs resulting from substitution of new 
NGCC generation for higher-emitting generation by existing affected 
EGUs would automatically be reflected in mass emission reductions from 
affected EGUs. A state would not need to include enforceable provisions 
for new NGCC in its plan, under such an approach. However, under a 
mass-based portfolio approach, enforceable measures in a state plan 
might include

[[Page 34924]]

construction of new NGCC to replace one or more affected EGUs, perhaps 
as part of a utility IRP and related PUC orders. Again, the effects of 
new NGCC generation would be realized in reduced mass emissions from 
affected EGUs.
    The agency requests comment on how emissions changes under a rate-
based plan resulting from substitution of generation by new NGCC for 
generation by affected EGUs should be calculated toward a required 
emission performance level for affected EGUs. Specifically, considering 
the legal structure of CAA section 111(d), should the calculation 
consider only the emission reductions at affected EGUs, or should the 
calculation also consider the new emissions added by the new NGCC unit, 
which is not an affected unit under section 111(d)? Should the 
emissions from a new NGCC included as an enforceable measure in a mass-
based state plan (e.g., in a plan using a portfolio approach) also be 
considered?
    Similar to zero-emitting generation, states may also want to 
consider whether the policy design they choose sends similar or 
different price signals to new and existing NGCC. For instance, under a 
mass based program, if new NGCCs were not included, their costs would 
be less than the cost of an existing NGCC unit.
    In respect to new fossil fuel-fired EGUs, the agency also requests 
comment on the concept of providing credit toward a state's required 
CAA section 111(d) performance level for emission performance at new 
CAA section 111(b) affected units that, through application of CCS, is 
superior to the proposed standards of performance for new EGUs. Because 
the EPA proposed to find that the BSER for new fossil fuel-fired 
boilers and IGCC units is only a partial application of CCS, we 
recognize that there is the potential for such units, if constructed, 
to obtain additional emission reductions by increasing the level of CCS 
and outperforming the proposed performance standards. In some cases 
these incremental emission reductions may represent a cost effective 
abatement option for states and would provide an incentive for the 
deployment and advancement of CCS. We invite comment on whether 
incremental emission reductions from new fossil fuel-fired boilers and 
IGCC units with CCS, based on exceeding the CAA section 111(b) 
performance standards for such units, should be allowed as a compliance 
option to help meet the emission performance level required under a CAA 
section 111(d) state plan.
    Similarly, while the EPA did not propose to establish standards of 
performance for new NGCC units based on CCS under CAA section 111(b), 
we recognize that if a new NGCC unit were to be constructed with a CCS 
system, it could achieve a lower CO2 emission rate than 
required by the proposed standards of performance for new NGCC units. 
We invite comment on whether incremental emission reductions from new 
NGCC units that outperform the performance standards for such units 
under CAA section 111(b) based on the use of CCS should be allowed as a 
compliance option to help meet the emission performance level required 
under a CAA section 111(d) state plan.
    Building block 4 focuses on improving end-use energy efficiency. 
Another way to reduce the utilization of, and CO2 emissions 
from, affected EGUs is through electricity transmission and 
distribution upgrades that reduce electricity losses during the 
delivery of electricity to end users. Just as end-use energy efficiency 
can reduce mass emissions from affected EGUs, so can transmission 
upgrades.
    In addition, electricity storage technologies have the potential to 
enhance emission performance by reducing the need for fossil fuel-fired 
EGUs to provide generation during periods when intermittent wind and 
solar generation are unavailable due to natural conditions. States may 
wish to consider this possibility as they consider options for design 
of their plans.
    The agency requests comment on whether industrial combined heat and 
power approaches warrant consideration as a potential way to avoid 
affected EGU emissions, and whether the answer depends on circumstances 
that depend on the type of CHP in question.
    Many of the decisions that states will make while developing 
compliance approaches are fundamentally state decisions that will have 
impacts on issues important to the state, including cost to consumers 
and broader energy policy goals, but will not impact overall emission 
performance. Some decisions, however, may impact emission performance 
and exemplify the kinds of decisions and approaches states may be 
interested in pursuing. In light of the broad latitude that the EPA is 
seeking to afford the states, including latitude to adopt measures such 
as those discussed in this subsection, the EPA intends to make 
additional technical resources available and consider developing 
guidance for states, should they need such support in exploring and 
adopting these options. The EPA, in addition, requests comment on 
whether there are still other areas beyond those discussed above for 
which it would be useful for the EPA to provide guidance.
    Through President Obama's Climate Action Plan, the Administration 
is working to identify new approaches to protect and restore our 
forests, as well as other critical landscapes including grasslands and 
wetlands, in the face of a changing climate. Sustainable forestry and 
agriculture can improve resiliency to climate change, be part of a 
national strategy to reduce dependence on fossil fuels, and contribute 
to climate change mitigation by acting as a ``sink'' for carbon. The 
plant growth associated with producing many of the biomass-derived 
fuels can, to varying degrees for different biomass feedstocks, 
sequester carbon from the atmosphere. For example, America's forests 
currently play a critical role in addressing carbon pollution, removing 
nearly 12 percent of total U.S. greenhouse gas emissions each year. As 
a result, broadly speaking, burning biomass-derived fuels for energy 
recovery can yield climate benefits as compared to burning conventional 
fossil fuels.
    Many states have recognized the importance of forests and other 
lands for climate resilience and mitigation and have developed a 
variety of different sustainable forestry policies, renewable energy 
incentives and standards and greenhouse gas accounting procedures. 
Because of the positive attributes of certain biomass-derived fuels, 
the EPA also recognizes that biomass-derived fuels can play an 
important role in CO2 emission reduction strategies. We 
anticipate that states likely will consider biomass-derived fuels in 
energy production as a way to mitigate the CO2 emissions 
attributed to the energy sector and include them as part of their plans 
to meet the emission reduction requirements of this rule, and we think 
it is important to define a clear path for states to do so.
    To better understand the impacts of using different types of 
biomass-derived fuels, the EPA is assessing the use of biomass 
feedstocks for energy recovery by stationary sources and has developed 
a draft accounting framework that the EPA's Science Advisory Board 
(SAB) has reviewed. The draft framework concluded that while biomass 
and other biogenic feedstocks have the potential to reduce the overall 
level of CO2 emissions resulting from electricity 
generation, the contribution of biomass-derived fuels to atmospheric 
CO2 is sensitive to the type of biomass feedstock used, and 
the way in which the feedstock is grown, processed, and ultimately 
combusted as a fuel for energy production. The SAB in its review 
similarly found that there are

[[Page 34925]]

circumstances in which biomass is grown, harvested and combusted in a 
carbon neutral fashion but commented that additional considerations are 
warranted.
    The EPA is in the process of revising the draft framework and 
considering next steps, taking into account both the comments provided 
by the SAB and feedback from stakeholders. The EPA's biogenic 
CO2 accounting framework is expected to provide important 
information regarding the scientific basis for assessing these biomass-
derived fuels and their net atmospheric contribution of CO2 
related to the growth, harvest and use of these fuels. This information 
should assist both states and the EPA in assessing the impact of the 
use of biomass fuels in reaching emission reduction goals in the energy 
sector under state plans to comply with the requirements in the 
emission guidelines.
9. Consideration of a Facility's ``Remaining Useful Life'' in Applying 
Standards of Performance
    In this section, the EPA discusses the relevance to this rule of 
the EPA regulations implementing the CAA section 111(d)(1) provision 
``permit[ing] the State in applying a standard of performance to any 
particular source under a [111(d)] plan . . . to take into 
consideration, among other factors, the remaining useful life of the 
existing source to which such standard applies.''
    For the reasons discussed below, the EPA is proposing that, in this 
case, the flexibility provided in the state plan development process 
adequately allows for consideration of the remaining useful life of the 
affected facilities and other source-specific factors and, therefore, 
that separate application of the remaining useful life provision by 
states in the course of developing and implementing their CAA section 
111(d) plans is unnecessary. The agency is requesting comment on its 
analysis below of the implications of the EPA's existing regulations 
interpreting ``useful life'' and ``other factors'' for purposes of this 
rulemaking.\302\ The agency also requests comment on whether it would 
be desirable to include in regulatory text any aspects of this preamble 
discussion about how the provisions in the existing implementing 
regulations concerning source-specific factors relate to this emission 
guideline.
---------------------------------------------------------------------------

    \302\ The agency is not reopening or considering changes to this 
provision of the implementing regulations.
---------------------------------------------------------------------------

    This section addresses the legal background concerning facility-
specific considerations and the implications for implementation of 
these emission guidelines, including state emissions performance goals.
a. Legal Background
    The EPA's 1975 implementing regulations \303\ address remaining 
useful life and other facility-specific factors that might affect 
requirements for an existing source under section 111(d). Those 
regulations provide that for a pollutant such as GHGs, which have been 
found to endanger public health, standards of performance in state 
plans must be as stringent as the EPA's emission guidelines. Deviation 
from the standard might be appropriate where the state demonstrates 
with respect to a specific facility (or class of facilities):
---------------------------------------------------------------------------

    \303\ 40 CFR 60.24(f).
---------------------------------------------------------------------------

    (1) Unreasonable cost of control resulting from plant age, 
location, or basic process design;
    (2) Physical impossibility of installing necessary control 
equipment; or
    (3) Other factors specific to the facility (or class of facilities) 
that make application of a less stringent standard or final compliance 
time significantly more reasonable.
    The reference to ``[u]nreasonable cost of control resulting from 
plant age'' implements the statutory provision on remaining useful 
life. The language concerning plant location, basic process design, 
physical impossibility of installing controls, and ``other factors'' 
addresses facility-specific issues other than remaining useful life 
that the EPA determined that in some circumstances can affect the 
reasonableness of a control measure for a particular existing source.
    This regulatory provision provides the EPA's default structure for 
implementing the remaining useful life provision of CAA section 111(d). 
The opening clause, however, which provides that this provision is 
applicable ``unless otherwise specified in the applicable subpart'' 
makes clear that this structure may not be appropriate in each case and 
that the EPA has discretion to alter the extent to which states may 
authorize relaxations to standards of performance that would otherwise 
apply to a particular source or source category, if appropriate under 
the circumstances of the specific source category and proposed 
guidelines.
b. Implications for Implementation of These Emission Guidelines
    In general, the EPA notes that the implementing regulation 
provisions for remaining useful life and other facility-specific 
factors are relevant for emission guidelines in which the EPA specifies 
a presumptive standard of performance that must be fully and directly 
implemented by each individual existing source within a specified 
source category. Such guidelines are much more like a CAA section 
111(b) standard in their form. For example, the EPA emission guidelines 
for sulfuric acid plants, phosphate fertilizer plants, primary aluminum 
plants, and Kraft pulp plants specify emission limits for sources.\304\ 
In the case of such emission guidelines, some individual sources, by 
virtue of their age or other unique circumstances, may warrant special 
accommodation.
---------------------------------------------------------------------------

    \304\ See ``Phosphate Fertilizer Plants; Final Guideline 
Document Availability,'' 42 FR 12,022 (Mar. 1, 1977); ``Standards of 
Performance for New Stationary Sources; Emission Guideline for 
Sulfuric Acid Mist,'' 42 FR 55,796 (Oct. 18, 1977); ``Kraft Pulp 
Mills, Notice of Availability of Final Guideline Document,'' 44 FR 
29,828 (May 22, 1979); ``Primary Aluminum Plants; Availability of 
Final Guideline Document,'' 45 FR 26,294 (Apr. 17, 1980); 
``Standards of Performance for New Stationary Sources and Guidelines 
for Control of Existing Sources: Municipal Solid Waste Landfills, 
Final Rule,'' 61 FR 9905 (Mar. 12, 1996).
---------------------------------------------------------------------------

    In these proposed guidelines for state plans to limit 
CO2 from affected EGUs, the agency does not take that 
approach. Instead, the EPA is proposing to establish state emission 
performance goals for the collective group of affected EGUs in a state, 
leaving to each state the design of the specific requirements that fall 
on each affected EGU. Due to the inherent flexibility in the EPA's 
approach to establishing the state-specific goals, and the flexibility 
provided to states in developing approvable CAA section 111(d) plans to 
achieve those goals, the EPA's guidelines contain no emission standards 
that the state must apply directly to a specific EGU; therefore, no 
relief for individual facilities would be needed.
    Rather, because of the flexibility for states to design their own 
standards, the states have the ability to address the issues involved 
with ``remaining useful life'' and ``other factors'' in the initial 
design of those standards, which would occur within the framework of 
the CAA section 111(d) plan development process. States are free to 
specify requirements for individual EGUs that are appropriate 
considering remaining useful life and other facility-specific factors.
    Therefore, to the extent that a performance standard that a state 
may wish to adopt for affected EGUs raises facility-specific issues, 
the state is free to make adjustments to a particular facility's 
requirements on facility-specific grounds, so long as any such 
adjustments are reflected (along with

[[Page 34926]]

any necessary compensating emission reductions), as part of the state's 
CAA section 111(d) plan submission. The agency requests comment on its 
interpretation.
c. Relationship to State Emission Performance Goals and Timing of 
Achievement
    The EPA also believes that, because of the way the state-specific 
goals have been developed in these proposed guidelines, remaining 
useful life and other facility-specific considerations should not 
affect the determination of a state's rate-based or mass-based emission 
performance goal or the state's obligation to develop and submit an 
approvable CAA section 111(d) plan that achieves that goal by the 
applicable deadline.
    Under the proposed guideline, states would have the flexibility to 
adopt a state plan that relies on emission-reducing requirements that 
do not require affected EGUs with a short remaining useful life to make 
major capital expenditures \305\ or incur unreasonable costs. Indeed, 
the EPA's proposal would provide states with broad flexibility 
regarding ways to improve emission performance through utilizing the 
emissions reduction methods represented by the four ``building 
blocks.''
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    \305\ The agency requests comment on whether there are 
circumstances other than a major capital investment that could lead 
to a prospective state plan imposing unreasonable costs considering 
a facility's remaining useful life. Where annual costs predominate 
and/or capital costs do not constitute a major expense, the EPA 
believes that the remaining useful life of an affected EGU will not 
significantly affect its annualized cost of control and therefore 
should not be a factor in determining control requirements for the 
EGU.
---------------------------------------------------------------------------

    We also note that a state is not required to achieve the same level 
of emission reductions with respect to any one building block as 
assumed in the EPA's BSER analysis. If a state prefers not to attempt 
to achieve the level of performance estimated by the EPA for a 
particular building block, it can compensate through over-achievement 
in another one, or employ other compliance approaches not factored into 
the state-specific goal at all. The EPA has estimated reasonable rather 
than maximum possible implementation levels for each building block in 
order to establish overall state goals that are achievable/while 
allowing states to take advantage of the flexibility to pursue some 
building blocks more aggressively, and others less aggressively, than 
is reflected in the goal computations, according to each state's needs 
and preferences.
    Of the four building blocks considered by the EPA in developing 
state goals, only the first block, heat rate improvements, involves 
capital investments at the affected EGUs which, if mandated by a state 
rule, might give rise to remaining useful life considerations at a 
particular facility. The other building blocks--re-dispatch among 
affected sources, addition of new generating capacity, and improvement 
in end-use energy efficiency--do not generally involve capital 
investments by the owner/operator at an affected EGU.
    In the case of heat rate improvements at affected EGUs, states can 
choose whether to require a greater or lesser degree of heat rate 
improvement than the 6 percent improvement assumed in the EPA's 
proposed BSER determination, either because of the remaining useful 
life of one or more EGUs, other source-specific factors that the state 
deemed appropriate to consider, or any other relevant reasons. The 
agency also notes that any capital expenditures would be much smaller 
than capital expenditures required for example, for purchase and 
installation of scrubbers to remove sulfur dioxide; a fleet-wide 
average cost for heat rate improvements at coal-fired generating units 
is $100/kW, compared with a typical SO2 scrubber cost of 
$500/kw (costs vary with unit size).\306\ In addition, the proposed 
guideline allows states to regulate affected EGUs through flexible 
regulatory approaches that do not require affected EGUs to incur large 
capital costs (e.g., averaging and trading programs). Under the EPA's 
proposed approach--establishing state goals and providing states with 
flexibility in plan design--states have flexibility to make exactly the 
kind of judgments necessary to avoid requirements that would result in 
stranded assets.
---------------------------------------------------------------------------

    \306\ Heat rate improvement methods and related capital costs 
are discussed in the GHG Abatement Measures TSD; SO2 
scrubber capital costs are from the documentation for the EPA's IPM 
Base Case v5.13, Chapter 5, Table 5-3, available at http://www.epa.gov/powersectormodeling/BaseCasev513.html
---------------------------------------------------------------------------

    Remaining useful life and other factors, because of their facility-
specific nature, are potentially relevant in determining requirements 
that are directly applicable to affected EGUs. For all of the reasons 
above, the agency believes that the issue of remaining useful life will 
arise infrequently in the development of state plans to limit 
CO2 emissions from affected existing EGUs. Even if relief is 
due a particular facility, the state has an available toolbox of 
emission reduction methods that it can use to develop a section 111(d) 
plan that meets its emissions performance goal on time. The EPA 
therefore proposes that the remaining useful life of affected EGUs, and 
the other facility-specific factors identified in the existing 
implementing regulations, should not be considered as a basis for 
adjusting a state emission performance goal or for relieving a state of 
its obligation to develop and submit an approvable plan that achieves 
that goal on time. The agency solicits comment on this position.
10. Design, Equipment, Work Practice, or Operational standards
    In this section, we discuss whether state plans may include design, 
equipment, work practice, or operational standards.
    CAA section 111(h)(1) authorizes the Administrator to promulgate 
``a design, equipment, work practice, or operational standard, or 
combination thereof,'' if in his or her judgment, ``it is not feasible 
to prescribe or enforce a standard of performance.'' CAA section 
111(h)(2) provides the circumstances under which prescribing or 
enforcing a standard of performance is ``not feasible'': generally, 
when the pollutant cannot be emitted through a conveyance designed to 
emit or capture the pollutant, or when there is no practicable 
measurement methodology for the particular class of sources. Other 
provisions in section 111(h) further provide that a design, equipment, 
work practice, or operational standard (i) must ``be promulgated in the 
form of a standard of performance whenever it becomes feasible'' to do 
so,\307\ and (ii) must ``be treated as a standard of performance'' for 
purposes of, in general, the CAA.\308\
---------------------------------------------------------------------------

    \307\ CAA section 111(h)(4).
    \308\ CAA section 111(h)(5).
---------------------------------------------------------------------------

    As noted above, CAA section 111(d) requires that state plans 
``establish[] standards of performance'' as well as ``provide[] for the 
implementation and enforcement of such standards of performance.'' CAA 
section 111(d) is silent as to whether (i) states may include design, 
equipment, work practice, or operational standards, or (ii) they may 
include those types of standards, but only under the limited 
circumstances described in section 111(h) (i.e., when it is ``not 
feasible'' to prescribe or enforce a standard of performance). 
Similarly, section 111(h) applies by its terms when the Administrator 
is authorized to prescribe standards of performance (which would 
include rulemaking under CAA section 111(b)), but is silent as to 
whether it

[[Page 34927]]

applies to state plans under CAA section 111(d).\309\
---------------------------------------------------------------------------

    \309\ It should be noted that section 111(b)(5), which concerns 
controls promulgated by the Administrator for new and modified 
sources, does refer to section 111(h).
---------------------------------------------------------------------------

    We invite consideration of the proper interpretation of CAA 
sections 111(d) and (h), under either Chevron step 1 or step 2, 
specifically: (i) Do the provisions of section 111(d) preclude state 
plans from including ``design, equipment, work practice, or operational 
standard[s]'' unless those things can be considered ``standards of 
performance'' or as providing for the implementation and enforcement of 
such standards? As a related matter, do the references to ``standard[s] 
of performance'' in CAA section 111(h) indicate that design, equipment, 
work practice, or operational standards cannot be considered 
``standards of performance?'' (ii) Alternatively, are state plans 
authorized to include those design, equipment, work practice, or 
operational standards, but only under the limited circumstances 
described in CAA section 111(h) relating to infeasibility? (iii) As 
another alternative, are state plans authorized to include design, 
equipment, work practice, or operational standards under all 
circumstances, so that the limits of CAA section 111(h) do not apply? 
Finally, to the extent there is legal uncertainty over whether, and 
under what circumstances, state plans may include those standards, 
should the EPA authorize state plans to include them, on the 
understanding that if the Court invalidates the EPA's interpretation, 
states would be required to revise their plans accordingly without 
further rulemaking from the EPA?
11. Emissions Averaging and Trading
    In this section, we discuss why CAA section 111(d) plans may 
include standards of performance that authorize emissions averaging and 
trading.
    CAA section 111(d) authorizes state plans to include ``standards of 
performance'' and measures that implement and enforce those standards 
of performance. CAA section 111(a)(1) defines a ``standard of 
performance'' as ``a standard for emissions of air pollutants which 
reflects the degree of emission limitation achievable through the 
application of the best system of emission reduction . . . adequately 
demonstrated.'' CAA section 302 contains a set of definitions that 
apply ``[w]hen used in [the Clean Air Act],'' including subsection (l), 
which provides a separate definition of ``standard of performance'' as 
``a requirement of continuous emission reduction. . .''
    The EPA proposes that the definition of ``standard of performance'' 
is broad enough to incorporate emissions averaging and trading 
provisions, including both emission rate programs, in which sources may 
average or trade those rates, and mass emission limit programs, in 
which sources may buy and sell mass emission allowances (and, under 
certain circumstances, offsets).\310\ The term ``standard'' in the 
phrase ``standard for emissions of air pollutants'' is not defined in 
the CAA. As the Supreme Court noted in a CAA case, a ``standard'' is 
simply ``that which `is established by authority, custom, or general 
consent, as a model or example; criterion; test.' '' \311\ A tradable 
emission rate or a tradable mass limit is a ``standard for emissions of 
air pollutants'' because it establishes an emissions limit for a 
source's air pollutants, and as a result, qualifies as a ``criterion'' 
or ``test'' for those air pollutants.
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    \310\ Typically, in a mass emission limit trading program, 
sources are required to obtain an allowance for each measure (e.g., 
ton) of air pollutant they emit. The acid rain program under Title 
IV of the CAA is an example of this type of trading program.
    \311\ Engine Mfrs. Ass'n v. South Coast Air Quality Mgmt. Dist., 
541 U.S. 246, 252-53 (2004) (quoting Webster's Second International 
Dictionary, at 2455 (1945))
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    Moreover, although there may be doubt that the definition of 
``standard of performance'' in CAA section 302(l) applies to CAA 
section 111(d) in light of the fact that the definition of the same 
term in CAA section 111(a)(1) is more specific, even if the CAA section 
302(l) definition does apply, an averaging or trading requirement 
qualifies as a ``continuous emission reduction'' because, in the case 
of a tradable emission rate, the rate is applicable at all times, and, 
in the case of a tradable mass limit, the source is always under the 
obligation that its emissions be covered by allowances.
    It should be noted that the EPA has promulgated two other CAA 
section 111(d) rulemakings that authorized state plans to include 
emissions averaging or trading.\312\
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    \312\ See ``Standards of Performance for New and Existing 
Stationary Sources: Electric Utility Steam Generating Units, Final 
Rule,'' 70 FR 28,606 (May 18, 2005) [also known as the Clean Air 
Mercury Rule, or ``CAMR''], vacated on other grounds by New Jersey 
v. EPA, 517 F.3d 574 (D.C. Cir. 2008), cert denied sub nom. Util. 
Air Reg. Grp. v. New Jersey, 555 U.S. 1169 (2009); ``Standards of 
Performance for New Stationary Sources and Emission Guidelines for 
Existing Sources; Municipal Waste Combustors,'' 60 FR 65,387 (Dec. 
19, 1995) (trading rules codified in 40 CFR 60.33b(d)(1)-(2)).
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G. Additional Factors That Can Help State Meet Their CO2 
Emission Performance Goals

    A resource available from the EPA for states pursuing market-based 
approaches is the EPA's data and experience in support of state trading 
programs and emissions data collection. For states needing technical 
assistance with data or operation of market-based programs, existing 
EPA data systems are a resource that have been used to collect 
emissions data, track allowances and transfers, and determine 
compliance for state programs. For example, New Hampshire was part of 
the Ozone Transport Commission (OTC) trading program but was not 
included in the NOx SIP Call. Because the state wanted its sources to 
continue to participate in a state trading program, the EPA operated 
the emissions trading program for New Hampshire sources, from 
allocating allowances to compliance determination.
    Additionally, as noted elsewhere in this preamble, more than 25 
states have mandatory renewable portfolio standards, and other states 
have voluntary renewable programs and goals. There is considerable 
diversity among the states in the scope and coverage of these 
standards, in particular in how renewable resources are defined. At the 
federal level, the EPA has considered the greenhouse gas implications 
related to biomass use at stationary sources through several actions, 
including a call for information from stakeholders and the development 
and review of the ``Accounting Framework for Biogenic CO2 
Emissions from Stationary Sources,'' issued in September 2011. That 
study was reviewed by the EPA's Science Advisory Board in 2011 and 2012 
and the agency continues to assess the framework and consider the 
latest scientific analyses and technical input received from 
stakeholders. The EPA expects that the framework, when finalized, will 
be a resource that could help inform states in the development of their 
CAA section 111(d) plans.

H. Resources for States To Consider in Developing Their Plans

    As part of the stakeholder outreach process, the EPA asked states 
what the agency could do to facilitate state plan development and 
implementation. Some states indicated that they wanted the EPA to 
create resources to assist with state plan development, especially 
resources related to accounting for end-use energy efficiency and 
renewable energy (EE/RE) in state plans. They requested clear 
methodologies for

[[Page 34928]]

measuring EE/RE policies and programs, so that these could be included 
as part of their compliance strategies. Stakeholders said that these 
tools and metrics should build upon the EPA's ``Roadmap for 
Incorporating Energy Efficiency/Renewable Energy Policies and Programs 
into State and Tribal Implementation Plans,''\313\ as well as the State 
Energy Efficiency Action Network's ``Energy Efficiency Program Impact 
Evaluation Guide.''\314\ The EPA also heard that states would like 
examples of effective state policies and programs.
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    \313\ http://epa.gov/airquality/eere/.
    \314\ http://www1.eere.energy.gov/seeaction/index.html.
---------------------------------------------------------------------------

    As a result of this feedback, in consultation with U.S. Department 
of Energy and other federal agencies, the EPA has developed a toolbox 
of decision support resources and is making that available at a 
dedicated Web site: http://www2.epa.gov/ www2.epa.gov/cleanpowerplantoolbox. Current resources on the site focus on 
approaches states and other entities have already taken that reduce 
CO2 emissions from the electric utility sector.
    For the final rulemaking, the EPA plans to organize resources on 
the Web site around the following two categories: State plan guidance 
and state plan decision support. The state plan guidance section will 
serve as a central repository for the final emission guidelines, 
regulatory impact analysis, technical support documents, and other 
supporting materials. The state plan decision support section will 
include information to help states evaluate different approaches and 
measures they might consider as they initiate plan development. This 
section will include, for example, a summary of existing state climate 
and EE/RE policies and programs,\315\ National Action Plan for Energy 
Efficiency (Action Plan),\316\ information on electric utility actions 
that reduce CO2, and tools and information to assist with 
translating energy savings into emission reductions.
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    \315\ Appendix, State Plan Considerations TSD.
    \316\ http://www.epa.gov/cleanenergy/energy-programs/suca/resources.html.
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    We note that our inclusion of a measure in the toolbox does not 
mean that a state plan must include that measure. In fact, inclusion of 
measures provided at the Web site does not necessarily imply the 
approvability of an approach or method for use in a state plan. States 
will need to demonstrate that any measure included in a state plan 
meets all relevant approvability criteria and adequately addresses 
elements of the plan components discussed in Section VIII of this 
preamble.
    The EPA solicits comment on this approach and the information 
currently included, and planned for inclusion, in the Decision Support 
Toolbox.

IX. Implications for Other EPA Programs and Rules

A. Implications for New Source Review Program

    The new source review (NSR) program is a preconstruction permitting 
program that requires major stationary sources of air pollution to 
obtain permits prior to beginning construction. The requirements of the 
NSR program apply both to new construction and to modifications of 
existing major sources. Generally, a source triggers these permitting 
requirements as a result of a modification when it undertakes a 
physical or operational change that results in a significant emission 
increase and a net emissions increase. NSR regulations define what 
constitutes a significant net emissions increase, and the concept is 
pollutant-specific. For GHG emissions, the PSD applicability analysis 
is described in the Prevention of Significant Deterioration and Title V 
Greenhouse Gas Tailoring Rule (FR 75 31514, June 3, 2010). As a general 
matter, a modifying major stationary source would trigger PSD 
permitting requirements for GHGs if it emits GHGs in excess of 100,000 
tons per year (tpy) of carbon dioxide equivalents (CO2e), 
and it undergoes a change or change in the method of operation 
(modification) resulting in an emissions increase of 75,000 tpy 
CO2e as well as an increase on a mass basis. Once it has 
been determined that a change triggers the requirements of the NSR 
program, the source must obtain a permit prior to making the change. 
The pollutant(s) at issue and the air quality designation of the area 
where the facility is located or proposed to be built determine the 
specific permitting requirements.
    As part of its CAA section 111(d) plan, a state may impose 
requirements that require an affected EGU to undertake a physical or 
operational change to improve the unit's efficiency that results in an 
increase in the unit's dispatch and an increase in the unit's annual 
emissions. If the emissions increase associated with the unit's changes 
exceeds the thresholds in the NSR regulations discussed above for one 
or more regulated NSR pollutants, including the netting analysis, the 
changes would trigger NSR.
    While there may be instances in which an NSR permit would be 
required, we expect those situations to be few. As previously discussed 
in this preamble, states have considerable flexibility in selecting 
varied measures as they develop their plans to meet the goals of the 
emissions guidelines. One of these flexibilities is the ability of the 
state to establish the standards of performance in their CAA section 
111(d) plans in such a way so that their affected sources, in complying 
with those standards, in fact would not have emissions increases that 
trigger NSR. To achieve this, the state would need to conduct an 
analysis consistent with the NSR regulatory requirements that supports 
its determination that as long as affected sources comply with the 
standards of performance in their CAA section 111(d) plan, the source's 
emissions would not increase in a way that trigger NSR requirements.
    For example, a state could decide to adjust its demand side 
measures or increase reliance on renewable energy as a way of reducing 
the future emissions of an affected source initially predicted (without 
such alterations) to increase its emissions as a result of a CAA 
section 111(d) plan requirement. In other words, a state plan's 
incorporation of expanded use of cleaner generation or demand-side 
measures could yield the result that units that would otherwise be 
projected to trigger NSR through a physical change that might result in 
increased dispatch would not, in fact, increase their emissions, due to 
reduced demand for their operation. The state could also, as part of 
its CAA section 111(d) plan, develop conditions for a source expected 
to trigger NSR that would limit the unit's ability to move up in the 
dispatch enough to result in a significant net emissions increase that 
would trigger NSR (effectively establishing a synthetic minor limit). 
\317\
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    \317\ Certain stationary sources that emit or have the potential 
to emit a pollutant at a level that is equal to or greater than 
specified thresholds are subject to major source requirements. See, 
e.g., CAA Sec. Sec.  165(a)(1), 169(1), 501(2), 502(a). A synthetic 
minor limitation is a legally and practicably enforceable 
restriction that has the effect of limiting emissions below the 
relevant level and that a source voluntarily obtains to avoid major 
stationary source requirements, such as the PSD or title V 
permitting programs. See, e.g., 40 CFR 52.21(b)(4), 51.166(b)(4), 
70.2 (definition of ``potential to emit'').
---------------------------------------------------------------------------

    We request comment on whether, with adequate record support, the 
state plan could include a provision, based on underlying analysis, 
stating that an affected source that complies with its applicable 
standard would be treated as not increasing its emissions, and if so, 
whether such a provision would mean that, as a matter of law, the 
source's actions to comply with its standard

[[Page 34929]]

would not subject the source to NSR. We also seek comment on the level 
of analysis that would be required to support a state's determination 
that sources will not trigger NSR when complying with the standards of 
performance included in the state's CAA section 111(d) plan and the 
type of plan requirements, if any, that would need to be included in 
the state's plan.
    As a result of such flexibility and anticipated state involvement, 
we expect that a limited number of affected sources would trigger NSR 
when states implement their plans.

B. Implications for Title V Program

    The preamble to the re-proposed EGU NSPS (70 FR 1429-1519; January 
8, 2014) explained that regulating GHGs for the first time under 
section 111 of the CAA would make GHGs ``regulated air pollutants'' for 
the first time under the operating permit regulations of 40 CFR parts 
70 and 71. This would result in GHGs becoming ``fee pollutants'' in 
certain state part 70 permit programs and in the EPA's part 71 permit 
program, thus requiring the collection of fees for GHG emissions in 
these programs. Where title V fees would be required for GHGs, they 
would typically be charged at the same rate ($ per ton of pollutant) as 
all other fee pollutants. This would likely result in excessive and 
unnecessary fees being charged to subject sources. To avoid this 
situation, we proposed to exempt GHGs from the fee rates in effect for 
other fee pollutants, while proposing an alternative fee that would be 
much lower than the fee charged to other fee pollutants, yet sufficient 
to cover the costs of addressing GHGs in operating permits.
    This title V fee issue is a one-time occurrence resulting from the 
promulgation of the first CAA section 111 standard to regulate GHGs 
(the EGU NSPS for new sources) and is not an issue for any other 
subsequent CAA section 111 regulations, so there is no need to address 
any title V fee issues in this proposal. Thus, we are not re-visiting 
these title V fee issues in this proposal, and we are not proposing any 
additional revisions to any title V regulations as part of this action.
    The title V regulations require each permit to include emission 
limitations and standards, including operational requirements and 
limitations that assure compliance with all applicable requirements. 
Requirements resulting from this rule that are imposed on affected EGUs 
or any other potentially affected entities that have title V operating 
permits are applicable requirements under the title V regulations and 
would need to be incorporated into the source's title V permit in 
accordance with the schedule established in the title V regulations. 
For example, if the permit has a remaining life of three years or more, 
a permit reopening to incorporate the newly applicable requirement 
shall be completed no later than 18 months after promulgation of the 
applicable requirement. If the permit has a remaining life of less than 
three years, the newly applicable requirement must be incorporated at 
permit renewal.

C. Interactions With Other EPA Rules

    Existing fossil fuel-fired EGUs, such as those covered in this 
proposal, are or will be potentially impacted by several other recently 
finalized or proposed EPA rules.\318\ On February 16, 2012, the EPA 
issued the mercury and air toxics standards (MATS) rule (77 FR 9304) to 
reduce emissions of toxic air pollutants from new and existing coal- 
and oil-fired EGUs. The MATS rule will reduce emissions of heavy 
metals, including mercury (Hg), arsenic (As), chromium (Cr), and nickel 
(Ni); and acid gases, including hydrochloric acid (HCl) and 
hydrofluoric acid (HF). These toxic air pollutants, also known as 
hazardous air pollutants or air toxics, are known or suspected of 
causing damage to the nervous system, cancer, and other serious health 
effects. The MATS rule will also reduce SO2 and fine 
particle pollution, which will reduce particle concentrations in the 
air and prevent thousands of premature deaths and tens of thousands of 
heart attacks, bronchitis cases and asthma episodes.
---------------------------------------------------------------------------

    \318\ We discuss other rulemakings solely for background 
purposes. The effort to coordinate rulemakings is not a defense to a 
violation of the CAA. Sources cannot defer compliance with existing 
requirements because of other upcoming regulations.
---------------------------------------------------------------------------

    The EPA is closely monitoring MATS compliance and finds that the 
industry is making substantial progress. Plant owners are moving 
proactively to install controls that will achieve the MATS performance 
standards. Certain units, especially those that operate infrequently, 
may be considered not worth investing in given today's electricity 
market, and those are closing.
    Existing sources subject to the MATS rule are given until April 16, 
2015 to comply with the rule's requirements. The final MATS rule 
provided a foundation on which states and other permitting authorities 
could rely in granting an additional, fourth year for compliance 
provided for by the CAA. States report that these fourth year 
extensions are being granted. In addition, the EPA issued an 
enforcement policy that provides a clear pathway for reliability-
critical units to receive an administrative order that includes a 
compliance schedule of up to an additional year, if it is needed to 
ensure electricity reliability.
    On May 19, 2014, the EPA issued a final rule under section 316(b) 
of the Clean Water Act (33 U.S.C. 1326(b)) (referred to hereinafter as 
the 316(b) rule).\319\ This rule establishes new standards to reduce 
injury and death of fish and other aquatic life caused by cooling water 
intake structures at existing power plants and manufacturing 
facilities.\320\ The 316(b) rule subjects existing power plants and 
manufacturing facilities that withdraw in excess of 2 million gallons 
per day (MGD) of cooling water, and use at least 25 percent of that 
water for cooling purposes, to a national standard designed to reduce 
the number of fish destroyed through impingement and a national 
standard for establishing entrainment reduction requirements. All 
facilities subject to the rule must submit information on their 
operations for use by the permit authority in determining 316(b) permit 
conditions. Certain plants that withdraw very large volumes of water 
will also be required to conduct additional studies for use by the 
permit authority in determining the site-specific entrainment reduction 
measures for such facilities. The rule provides significant flexibility 
for compliance with the impingement standards and, as a result, is not 
projected to impose a substantial cost burden on affected facilities. 
With respect to entrainment, the rule calls upon the permitting 
authority to in establishing appropriate entrainment reduction 
measures, taking into account, among other factors, compliance costs, 
facility reliability and grid reliability. Existing sources subject to 
the 316(b) rule are required to comply with the impingement 
requirements as soon as practicable after the entrainment requirements 
are determined. They must comply with applicable site-specific 
entrainment reduction controls based on the schedule of requirements 
established by the permitting authority.
---------------------------------------------------------------------------

    \319\ The pre-publication version of the final rule is available 
at: http://water.epa.gov/lawsregs/lawsguidance/cwa/316b/#final.
    \320\ CWA section 316(b) provides that standards applicable to 
point sources under sections 301 and 306 of the Act must require 
that the location, design, construction and capacity of cooling 
water intake structures reflect the best technology available for 
minimizing adverse environmental impacts.
---------------------------------------------------------------------------

    The EPA is also reviewing public comments and working to finalize 
two proposed rules which will also impact

[[Page 34930]]

existing fossil fuel-fired EGUs: The steam electric effluent limitation 
guidelines (SE ELG) rule and the coal combustion residuals (CCR) rule. 
These proposed rules are summarized below.
    On June 7, 2013 (78 FR 34432), the EPA proposed the SE ELG rule to 
strengthen the controls on discharges from certain steam electric power 
plants by revising technology-based effluent limitations guidelines and 
standards for the steam electric power generating point source 
category. The current regulations, which were last updated in 1982, do 
not adequately address the toxic pollutants discharged from the 
electric power industry, nor have they kept pace with process changes 
that have occurred over the last three decades. Existing steam electric 
power plants currently contribute 50-60 percent of all toxic pollutants 
discharged to surface waters by all industrial categories regulated in 
the United States under the CWA. Furthermore, power plant discharges to 
surface waters are expected to increase as pollutants are increasingly 
captured by air pollution controls and transferred to wastewater 
discharges. This proposed regulation, which includes new requirements 
for both existing and new generating units, would reduce the amount of 
toxic metals and other pollutants discharged to surface waters from 
power plants.
    On June 21, 2010 (75 FR 35128), the EPA proposed the CCR rule, 
which co-proposed two approaches to regulating the disposal of coal 
combustion residuals (CCRs) generated by electric utilities and 
independent power producers. CCRs are residues from the combustion of 
coal in steam electric power plants and include materials such as coal 
ash (fly ash and bottom ash) and flue gas desulfurization (FGD) wastes. 
Under one proposed approach, the EPA would list these residuals as 
``special wastes,'' when destined for disposal in landfills or surface 
impoundments, and would apply the existing regulatory requirements 
established under Subtitle C of RCRA to such wastes. Under the second 
proposed approach, the EPA would establish new regulations applicable 
specifically to CCRs under subtitle D of RCRA, the section of the 
statute applicable to solid (i.e., non-hazardous) wastes. Under both 
approaches, CCRs that are beneficially used would remain exempt under 
the Bevill exclusion.\321\ While the EPA still is evaluating all the 
available information and comments, and while a final risk assessment 
for the CCR rule has not yet been completed, reliance on data and 
analyses discussed in the preamble to the recent SE ELG proposal might 
have the potential to lower the CCR rule risk assessment results by as 
much as an order of magnitude. If this proves to be the case, the EPA's 
current thinking is that the revised risks, coupled with the ELG 
requirements that the agency might promulgate, and the increased 
federal oversight such requirements could achieve, could provide strong 
support for a conclusion that regulation of CCR disposal under RCRA 
Subtitle D would be adequate.\322\ The EPA is under a court-ordered 
deadline to complete the CCR rulemaking by December 19, 2014.
---------------------------------------------------------------------------

    \321\ Beneficial use involves the reuse of CCRs in a product to 
replace virgin raw materials that would otherwise be obtained 
through extraction. The EPA encourages the beneficial use of CCRs in 
an appropriate and protective manner, because this practice can 
produce environmental, economic, and performance benefits. The 
Agency recently evaluated the environmental impacts associated with 
encapsulated beneficial uses of fly ash used as a direct substitute 
for Portland cement in concrete, and FGD gypsum used as a 
replacement for mined gypsum in wallboard. The EPA concluded that 
the beneficial use of CCRs in concrete and wallboard is appropriate 
because the environmental releases of constituents of potential 
concern (COPC) during use by the consumer are comparable to or lower 
than those from analogous non-CCR products, or are at or below 
relevant regulatory and health-based benchmarks for human and 
ecological receptors. See U.S. Environmental Protection Agency, Coal 
Combustion Residual Beneficial Use Evaluation: Fly Ash Concrete and 
FGD Gypsum Wallboard (2014).
    \322\ U.S. EPA. September 2013. Regulatory Impact Analysis for 
the Proposed Standards of Performance for Greenhouse Gas Emissions 
for New Stationary Sources: Electric Utility Generating Units. EPA-
452/R-13-003. Available at http://www2.epa.gov/sites/production/files/2013-09/documents/20130920proposalria.pdf.
---------------------------------------------------------------------------

    The EPA recognizes the importance of assuring that each of the 
rules described above can achieve its intended environmental objectives 
in a commonsense, cost-effective manner, consistent with underlying 
statutory requirements, and while assuring a reliable power system. 
Executive Order (EO) 13563, ``Improving Regulation and Regulatory 
Review,'' issued on January 18, 2011, states that ``[i]n 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.'' Within the EPA, we are paying careful attention to the 
interrelatedness and potential impacts on the industry, reliability and 
cost that these various rulemakings can have.
    As discussed in Sections VII and VIII of this preamble, the EPA is 
proposing to give states broad flexibility in developing approvable 
plans under CAA section 111(d), including the ability to adopt rate-
based or mass-based emission performance goals, and to rely on a wide 
variety of CO2 emission reduction measures. The EPA is also 
proposing to give states considerable flexibility with respect to the 
timeframes for plan development and implementation, with up to two or 
three years permitted for final plans to be submitted after the 
proposed GHG emission guidelines are finalized, and up to fifteen years 
for all emission reduction measures to be fully implemented. In light 
of these flexibilities, we believe that states will have ample 
opportunity, when developing and implementing their CAA section 111(d) 
plans, to coordinate their response to this requirement with source and 
state responses to any obligations that may be applicable to affected 
EGUs as a result of the MATS, 316(b), SE ELG and CCR rules--all of 
which are or will be final rules before this rulemaking is finalized--
and to do so in a manner that will help reduce cost and ensure 
reliability, while also ensuring that all applicable environmental 
requirements are met.\323\
---------------------------------------------------------------------------

    \323\ It should be noted that regulatory obligations imposed 
upon states and sources operate independently under different 
statutes and sections of statutes; the EPA expects that states and 
sources will take advantage of available flexibilities as 
appropriate, but will comply with all relevant legal requirements.
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    The EPA is also endeavoring to enable EGUs to comply with 
applicable obligations under other power sector rules as efficiently as 
possible (e.g., by facilitating their ability to coordinate planning 
and investment decisions with respect to those rules) and, where 
possible, implement integrated compliance strategies. For example, in 
the proposed SE ELG rule, the EPA describes its current thinking on how 
it might effectively harmonize the potential requirements of that rule 
with the requirements of the final CCR rule, to the extent that both 
rules may regulate or affect the disposal of coal combustion wastes to 
and from surface impoundments at power plants.\324\ The EPA's goal in 
exploring how it might harmonize the SE ELG and CCR rules is to 
minimize the overall complexity of the two regulatory structures and 
avoid creating unnecessary burdens.\325\
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    \324\ See: Federal Register Vol. 78, No. 110; June 7, 2013. Page 
34441.
    \325\ In considering how to coordinate the potential 
requirements between the SE ELG and CCR rules, the EPA stated that 
it is guided by the following policy considerations: First and 
foremost, the EPA intends to ensure that its statutory 
responsibilities to restore and maintain water quality under the CWA 
and to protect human health and the environment under RCRA are 
fulfilled. At the same time, the EPA would seek to minimize the 
potential for overlapping requirements to avoid imposing any 
unnecessary burdens on regulated entities and to facilitate 
implementation and minimize the overall complexity of the regulatory 
structure under which facilities must operate. Based on these 
considerations, the EPA stated that it is exploring two primary 
means of integrating the two rules: (1) Through coordinating the 
design of any final substantive CCR regulatory requirements, and (2) 
through coordination of the timing and implementation of final rule 
requirements to provide facilities with a reasonable timeline for 
implementation that allows for coordinated planning and protects 
electricity reliability for consumers.

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[[Page 34931]]

    In addition to the power sector rules discussed above, the 
development of SIPs for criteria pollutants (PM2.5, ozone 
and SO2) and regional haze may also have implications for 
existing fossil-fired EGUs.
    On June 6, 2013, the EPA proposed an implementation rule for the 
2008 ozone National Ambient Air Quality Standards (NAAQS), to provide 
rules and guidance to states on the development of approvable state 
implementation plans (SIPs), including SIPs under CAA section 110 
(infrastructure SIPs) and section 182 (ozone nonattainment SIPs). This 
rule addresses the statutory requirements for areas that the EPA has 
designated as nonattainment for the 2008 ozone standard. The agency is 
currently working to finalize that rule. The EPA is also working on a 
proposed transport rule that would identify the obligations of upwind 
states that contribute to those downwind state ozone nonattainment 
areas. This rule is scheduled for proposal in 2014 and to be finalized 
by 2015.
    The EPA is developing a proposed implementation rule to provide 
guidance to states on the development of SIPs for the 2012 
PM2.5 NAAQS.
    The SO2 NAAQS was revised in June 2010 to protect public 
health from the short-term effects of SO2 exposure. In July 
2013, the EPA designated 29 areas in 16 states as nonattainment for the 
SO2 NAAQS. The EPA based these nonattainment designations on 
the most recent set of certified air quality monitoring data as well as 
an assessment of nearby emission sources and weather patterns that 
contribute to the monitored levels. The EPA intends to address the 
designations for all other areas in separate actions in the future 
\326\. The EPA has proposed the data requirements rule for the 1-hour 
SO2 NAAQS to require states to characterize air quality more 
extensively using ambient monitoring or air quality modeling 
approaches.
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    \326\ The EPA has developed a comprehensive implementation 
strategy for these future actions that focuses resources on 
identifying and addressing unhealthy levels of SO2 in 
areas where people are most likely to be exposed to violations of 
the standard. The strategy is available at: http://www.epa.gov/airquality/sulfurdioxide/implement.html.
---------------------------------------------------------------------------

    The EPA requires SIP updates every 10 years for regional haze, as 
required by the EPA's Regional Haze Rule which was promulgated in 1999. 
The next 10-year SIP revision for regional haze, covering the time 
period through 2028, is due from each state by July 2018. Each SIP must 
provide for reasonable progress towards visibility improvement in 
protected scenic areas.
    The development of these SIPs may, where applicable, have 
significant implications for existing fossil fuel-fired EGUs, as well 
as for the states that are responsible for developing them. The 
timeframes for submittal of SIPs for the various programs and the 
timeframes we are proposing for submittal of the CAA section 111(d) 
state plans will allow considerable time for coordination by states in 
the development of their respective plans. The EPA is willing to work 
with states to assist them in coordinating their efforts across these 
planning processes. The EPA believes that CAA section 111(d) efforts 
and actions will tend to contribute to overall air quality improvements 
and thus should be complementary to criteria pollutant and regional 
haze SIP efforts.
    In light of the broad flexibilities we are proposing in this 
action, we believe that states will have ample opportunity to design 
CAA section 111(d) plans that use innovative, cost-effective regulatory 
strategies and that spark investment and innovation across a wide 
variety of clean energy technologies. We also believe that the broad 
flexibilities we are proposing in this action will enable states and 
affected EGUs to build on their longstanding, successful records of 
complying with multiple CAA, CWA, and other environmental requirements, 
while assuring an adequate, affordable, and reliable supply of 
electricity.

X. Impacts of the Proposed Action \327\
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    \327\ The impacts presented in this section of the preamble 
represent an illustrative implementation of the guidelines. As 
states implement the proposed guidelines, they have sufficient 
flexibility to adopt different state-level or regional approaches 
that may yield different costs, benefits, and environmental impacts. 
For example, states may use the flexibilities described in these 
guidelines to find approaches that are more cost effective for their 
particular state or choose approaches that shift the balance of co-
benefits and impacts to match broader state priorities.
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A. What are the air impacts?

    The EPA anticipates significant emission reductions under the 
proposed guidelines for the power sector. CO2 emissions are 
projected to be reduced when compared to 2005 emissions, by 26 percent 
to 27 percent in 2020 and about 30 percent in 2030 under Option 1. 
Option 2 reflects reductions of about 23 percent in 2020 and 23 percent 
to 24 percent in 2025 when compared to CO2 emissions in 
2005. The guidelines are projected to result in substantial co-benefits 
through reductions of SO2, PM2.5 and NOx that 
will have direct public health benefits by lowering ambient levels of 
these pollutants and ozone. Tables 10 and 11 show expected 
CO2 and other air pollutant emission reductions in the base 
case, with the proposed Option 1 for 2020, 2025, and 2030 and 
regulatory alternative Option 2, for 2020 and 2025.

               Table 10--Summary of CO2 and Other Air Pollutant Emission Reductions with Option 1
----------------------------------------------------------------------------------------------------------------
                                                                                                       PM2.5
                                                   CO2 (million   SO2 (thousands  NOX (thousands   (thousands of
                                                   metric tons)      of tons)        of tons)          tons)
----------------------------------------------------------------------------------------------------------------
2020 Regional Compliance Approach:
----------------------------------------------------------------------------------------------------------------
    Base Case Proposed..........................           2,161           1,476           1,559             212
Guidelines:                                                1,790           1,184           1,213             156
    Emission Reductions.........................             371             292             345              56
----------------------------------------------------------------------------------------------------------------
2025 Regional Compliance Approach:
----------------------------------------------------------------------------------------------------------------
    Base Case Proposed..........................           2,231           1,515           1,587             209
 Guidelines:                                               1,730           1,120           1,166             150

[[Page 34932]]

 
    Emission Reductions.........................             501             395             421              59
----------------------------------------------------------------------------------------------------------------
2030 Regional Compliance Approach:
----------------------------------------------------------------------------------------------------------------
    Base Case Proposed..........................           2,256           1,530           1,537             198
Guidelines:                                                1,711           1,106           1,131             144
    Emission Reductions.........................             545             424             407              54
----------------------------------------------------------------------------------------------------------------
2020 State Compliance Approach:
----------------------------------------------------------------------------------------------------------------
    Base Case Proposed..........................           2,161           1,476           1,559             212
Guidelines:                                                1,777           1,140           1,191             154
    Emission Reductions.........................             383             335             367              58
----------------------------------------------------------------------------------------------------------------
2025 State Compliance Approach:
----------------------------------------------------------------------------------------------------------------
    Base Case Proposed..........................           2,231           1,515           1,587             209
Guidelines:                                                1,724           1,090           1,151             145
    Emission Reductions.........................             506             425             436              63
----------------------------------------------------------------------------------------------------------------
2030 State Compliance Approach:
----------------------------------------------------------------------------------------------------------------
    Base Case Proposed..........................           2,256           1,530           1,537             198
Guidelines:                                                1,701           1,059           1,109             142
    Emission Reductions.........................             555             471             428              56
----------------------------------------------------------------------------------------------------------------
Source: Integrated Planning Model, 2014.

                  Table 11--Summary of CO2 and Air Pollutant Emission Reductions with Option 2
----------------------------------------------------------------------------------------------------------------
                                                                                                       PM2.5
                                                   CO2 (million   SO2 (thousands  NOX (thousands   (thousands of
                                                   metric tons)      of tons)        of tons)          tons)
----------------------------------------------------------------------------------------------------------------
2020 Regional Compliance Approach:
----------------------------------------------------------------------------------------------------------------
    Base Case...................................           2,161           1,476           1,559             212
    Option 2....................................           1,878           1,231           1,290             166
    Emission Reductions.........................             283             244             268              46
----------------------------------------------------------------------------------------------------------------
2025 Regional Compliance Approach:
----------------------------------------------------------------------------------------------------------------
    Base Case...................................           2,231           1,515           1,587             209
    Option 2....................................           1,862           1,218           1,279             165
    Emission Reductions.........................             368             297             309              44
----------------------------------------------------------------------------------------------------------------
2020 State Compliance Approach:
----------------------------------------------------------------------------------------------------------------
    Base Case...................................           2,161           1,476           1,559             212
    Option 2....................................           1,866           1,208           1,277             163
    Emission Reductions.........................             295             267             281              49
----------------------------------------------------------------------------------------------------------------
2025 State Compliance Approach:
----------------------------------------------------------------------------------------------------------------
    Base Case...................................           2,231           1,515           1,587             209
    Option 2....................................           1,855           1,188           1,271             161
    Emission Reductions.........................             376             327             317              48
----------------------------------------------------------------------------------------------------------------
Source: Integrated Planning Model, 2014.

    The reductions in these tables do not account for reductions in 
hazardous air pollutants (HAPs) that may occur as a result of this 
rule. For instance, the fine particulate reductions presented above do 
not reflect all of the reductions in many heavy metal particulates.

B. Comparison of Building Block Approaches

    Though the EPA has determined that the 4-building block approach is 
the BSER, we did analyze the impacts of both a combination of building 
blocks 1 and 2 and the combination of all four building blocks. The 
analysis indicates that the combined strategies of heat rate 
improvements (building block 1) and re-dispatch (building block 2) 
would result in overall CO2 emission reductions of 
approximately 22 percent in 2020 (compared to 2005 emissions and

[[Page 34933]]

assuming state-level compliance). This compares to expected 
CO2 emission reductions of approximately 27 percent for the 
four-block BSER approach discussed below. The EPA analysis also 
estimates 24-32 GW of additional coal-fired EGU retirements in 2020 
(compared to 46-49 GW for the four-block approach) and an additional 3-
5 GW of oil/gas steam EGUs (compared to 16 GW for the four-block 
approach). For both the two-block and the four-block approach, a 
decrease in coal production and price is predicted in 2020. The 
decrease in production is predicted at 20-23 percent for the two-block 
approach, compared to a decrease of 25-27 percent for the four-block 
approach. A 12 percent decrease in coal prices is predicted for the 
two-block approach; while the four-block approach results in a 16 to 18 
percent decrease. Under both approaches, the shifting in generation 
from higher-emitting steam EGUs to lower-emitting NGCC units results in 
an increase in natural gas production and price. The two-block approach 
results in a production increase of 19-22 percent and a price increase 
of 10-11 percent. The four-block approach results in a production 
increase of 12-14 percent and a price increase of 9-12 percent. Both 
the two-block and the four-block approaches result in construction of 
additional NGCC capacity by 2020, with 11-18 GW of new NGCC for the 
two-block approach and 20-22 GW of new NGCC capacity for the four-block 
approach. However, while the two-block approach results in 5-17 GW of 
new NGCC capacity in 2030, the four-block approach results in 32-35 GW 
less NGCC capacity in 2030 relative to the base case (due to increased 
use of renewable energy sources and decreased demand from 
implementation of demand side energy efficiency measures). Also, 
significantly, the two-block approach results in less than 500 MW of 
new renewable energy capacity; while the four-block option results in 
approximately 12 GW of new renewable generating capacity.
    The EPA projects that the annual incremental compliance cost for 
the building block 1 and 2 approach is estimated to be $3.2 to $4.4 
billion in 2020 and $6.8 to $9.8 billion (2011$) in 2030, excluding the 
costs associated with monitoring, reporting, and recordkeeping (MRR). 
This compares to costs excluding MRR of $5.4 to $7.4 billion in 2020 
and $7.3 to $8.8 billion in 2030 for the proposed Option 1 (2011$) as 
discussed in Section X.E of this preamble.
    The total combined climate benefits and health co-benefits for the 
building block 1 and 2 approach are estimated to be $21 to $40 billion 
in 2020 and $32 to $63 billion in 2030 (2011$ at a 3-percent discount 
rate [model average]). The net benefits are estimated to be $18 to $36 
billion in 2020 and $25 to $53 billion in 2030 (2011$ at a 3-percent 
discount rate [model average]). For the purposes of this summary, we 
list the climate benefits associated with the marginal value of the 
model average at 3% discount rate, however we emphasize the importance 
and value of considering the full range of SCC values. These building 
block 1 and 2 benefit estimates compare to combined climate benefits 
and health co-benefits of $33 to $57 billion in 2020 and $55 to $93 
billion in 2030 (2011$ at a 3-percent discount rate [model average]) 
for the proposed Option 1. Net benefits are estimated to be $27 to $50 
billion in 2020 and $48 to $84 billion in 2030 (2011$ at a 3-percent 
discount rate [model average]) as discussed in Section X.G. and XI.A of 
this preamble.\328\
---------------------------------------------------------------------------

    \328\ Note that the health co-benefits and net benefits for the 
proposed Option 1 include PM co-benefits associated with directly 
emitted PM2.5. In contrast, the building block 1 and 2 
analysis does not include co-benefits related to directly emitted 
PM2.5.
---------------------------------------------------------------------------

C. Endangered Species Act

    Consistent with the requirements of section 7(a)(2) of the 
Endangered Species Act (ESA), the EPA has also considered the effects 
of this proposed rule and has reviewed applicable ESA regulations, case 
law, and guidance to determine what, if any, impact there may be to 
listed endangered or threatened species or designated critical habitat. 
Section 7(a)(2) of the ESA requires federal agencies, in consultation 
with the U.S. Fish and Wildlife Service (FWS) and/or the National 
Marine Fisheries Service, to ensure that actions they authorize, fund, 
or carry out are not likely to jeopardize the continued existence of 
federally listed endangered or threatened species or result in the 
destruction or adverse modification of designated critical habitat of 
such species. 16 U.S.C. 1536(a)(2). Under relevant implementing 
regulations, section 7(a)(2) applies only to actions where there is 
discretionary federal involvement or control. 50 CFR 402.03. Further, 
under the regulations consultation is required only for actions that 
``may affect'' listed species or designated critical habitat. 50 CFR 
Sec.  402.14. Consultation is not required where the action has no 
effect on such species or habitat. Under this standard, it is the 
federal agency taking the action that evaluates the action and 
determines whether consultation is required. See 51 FR 19926, 19949 
(June 3, 1986). Effects of an action include both the direct and 
indirect effects that will be added to the environmental baseline. 50 
CFR 402.02. Indirect effects are those that are caused by the action, 
later in time, and are reasonably certain to occur. Id. To trigger a 
consultation requirement, there must thus be a causal connection 
between the federal action, the effect in question, and the listed 
species, and the effect must be reasonably certain to occur.
    The EPA has considered the effects of this proposed rule and has 
reviewed applicable ESA regulations, case law, and guidance to 
determine what, if any, impact there may be to listed species or 
designated critical habitat for purposes of section 7(a)(2) 
consultation. The EPA notes that the projected environmental effects of 
this proposal are positive: reductions in overall GHG emissions, and 
reductions in PM and ozone-precursor emissions (SOX and 
NOX). With respect to the projected GHG emission reductions, 
the EPA does not believe that such reductions trigger ESA consultation 
requirements under section 7(a)(2). In reaching this conclusion, the 
EPA is mindful of significant legal and technical analysis undertaken 
by FWS and the U.S. Department of the Interior in the context of 
listing the polar bear as a threatened species under the ESA. In that 
context, in 2008, FWS and DOI expressed the view that the best 
scientific data available were insufficient to draw a causal connection 
between GHG emissions and effects on the species in its habitat.\329\ 
The DOI Solicitor concluded that where the effect at issue is climate 
change, proposed actions involving GHG emissions cannot pass the ``may 
affect'' test of the section 7 regulations and thus are not subject to 
ESA consultation. The EPA has also previously considered issues 
relating to GHG emissions in connection with the requirements of ESA 
section 7(a)(2). Although the GHG emission reductions projected for 
this proposal are large (the highest estimate is reductions of 555 MMT 
of CO2 in 2030--see Table 10 above), the EPA evaluated 
larger reductions in assessing this same issue in the context of the 
light duty vehicle GHG emission standards for model years 2012-2016 and 
2017-2025. There the agency projected emission reductions roughly 
double and four times those projected

[[Page 34934]]

here over the lifetimes of the model years in question \330\ and, based 
on air quality modeling of potential environmental effects, concluded 
that ``EPA knows of no modeling tool which can link these small, time-
attenuated changes in global metrics to particular effects on listed 
species in particular areas. Extrapolating from global metric to local 
effect with such small numbers, and accounting for further links in a 
causative chain, remain beyond current modeling capabilities.'' EPA, 
Light Duty Vehicle Greenhouse Gas Standards and Corporate Average Fuel 
Economy Standards, Response to Comment Document for Joint Rulemaking at 
4-102 (Docket EPA-OAR-HQ-2009-4782). The EPA reached this conclusion 
after evaluating issues relating to potential improvements relevant to 
both temperature and oceanographic pH outputs. The EPA's ultimate 
finding was that ``any potential for a specific impact on listed 
species in their habitats associated with these very small changes in 
average global temperature and ocean pH is too remote to trigger the 
threshold for ESA section 7 (a)(2).'' Id. The EPA believes that the 
same conclusions apply to the present proposal, given that the 
projected CO2 emission reductions are less than those 
projected for either of the light duty vehicle rules. See, e.g., Ground 
Zero Center for Non-Violent Action v. U.S. Dept. of Navy, 383 F. 3d 
1082, 1091-92 (9th Cir. 2004) (where the likelihood of jeopardy to a 
species from a federal action is extremely remote, ESA does not require 
consultation).
---------------------------------------------------------------------------

    \329\ See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum 
from David Longly Bernhardt, Solicitor, U.S. Department of the 
Interior re: ``Guidance on the Applicability of the Endangered 
Species Act's Consultation Requirements to Proposed Actions 
Involving the Emission of Greenhouse Gases'' (Oct. 3, 2008).
    \330\ See 75 FR at 25438 Table I.C 2-4 (May 7, 2010); 77 FR at 
62894 Table III-68 (Oct. 15, 2012).
---------------------------------------------------------------------------

    With regard to non-GHG air emissions, the EPA is also projecting 
substantial reductions of SOX and NOX as a 
collateral consequence of this proposal. However, CAA section 111(d)(1) 
standards cannot directly control emissions of criteria pollutants. 
Consequently, CAA section 111(d) provides no discretion to adjust the 
standard based on potential impacts to endangered species of reduced 
criteria pollutant emissions. Section 7(a)(2) consultation thus is not 
required with respect to the projected reductions of criteria pollutant 
emissions. See 50 CFR 402.03; see also, National Lime Ass'n v. EPA, 233 
F. 3d 625, 638-39 (D.C. Cir. 2000) (although CAA section 112(b)(2) 
prohibits the EPA from listing criteria pollutants as hazardous air 
pollutants, the EPA may use PM as a surrogate for metal hazardous air 
pollutants and reductions in PM do not constitute impermissible 
regulation of a criteria pollutant).
    Moreover, there are substantial questions as to whether any 
potential for relevant effects results from any element of the proposed 
rule or would result instead from the separate actions of States 
establishing standards of performance for existing sources and 
implementing and enforcing those standards. Cf. American Trucking 
Assn's v. EPA, 175 F. 3d 1027, 1043-45 (D.C. Cir. 1999), rev'd on 
different grounds sub nom., Whitman v. American Trucking Assn's, 531 
U.S. 457 (2000) (National Ambient Air Quality Standards have no 
economic impact, for purposes of Regulatory Flexibility Act, because 
impacts result from the actions of States through their development, 
implementation and enforcement of state implementation plans). Thus, 
for example, although questions may exist whether actions such as 
increased utilization of solar or wind power could have effects on 
listed species, the EPA believes that such effects (if any) would 
result from decisions and actions by states in developing, implementing 
and enforcing their plans. The precise steps States choose to take in 
that regard cannot be determined or ordered by this federal action, and 
they are not sufficiently certain to be attributable to this proposed 
rule for ESA purposes. Consequently, for this additional reason, the 
EPA does not believe that this proposed rule (if enacted) would have 
effects on listed species that would trigger the section 7 (a)(2) 
consultation requirement.

D. What are the energy impacts?

    The proposed guidelines have important energy market implications. 
Under Option 1, average nationwide retail electricity prices are 
projected to increase by roughly 6 to 7 percent in 2020 relative to the 
base case, and by roughly 3 percent in 2030 (contiguous U.S.). Average 
monthly electricity bills are anticipated to increase by roughly 3 
percent in 2020, but decline by approximately 9 percent by 2030. This 
is a result of the increasing penetration of demand-side programs that 
more than offset increased prices to end users by their expected 
savings from reduced electricity use.
    The average delivered coal price to the power sector is projected 
to decrease by 16 to 17 percent in 2020 and roughly 18 percent in 2030, 
relative to the base case for Option 1. The EPA also projects that 
electric power sector-delivered natural gas prices will increase by 9 
to 12 percent in 2020, with negligible changes in 2030. Natural gas use 
for electricity generation will increase by as much as 1.2 trillion 
cubic feet (TCF) in 2020 relative to the base case, and then begin to 
decline over time.
    These figures reflect the EPA's illustrative modeling that presumes 
policies that lead to dispatch changes in 2020 and growing use of 
energy efficiency and renewable electricity generation out to 2029. If 
states make different policy choices, impacts could be different. For 
instance, if states implement renewable and/or energy efficiency 
policies on a more aggressive time-frame, impacts on natural gas and 
electricity prices would likely be less. Implementation of other 
measures not included in the EPA's BSER calculation or compliance 
modeling, such as nuclear uprates, transmission system improvements, 
use of energy storage technologies or retrofit CCS, could also mitigate 
gas price and/or electricity price impacts.
    The EPA projects coal production for use by the power sector, a 
large component of total coal production, will decline by roughly 25 to 
27 percent in 2020 from base case levels. The use of coal by the power 
sector will decrease roughly 30 to 32 percent in 2030. Renewable energy 
capacity is anticipated to increase by roughly 12 GW in 2020 and by 9 
GW in 2030 under Option 1. Energy market impacts from the guidelines 
are discussed more extensively in the RIA found in the docket for this 
rulemaking.

E. What are the compliance costs?

    The compliance costs of this proposed action are represented in 
this analysis as the change in electric power generation costs between 
the base case and the proposed rule in which states pursue a distinct 
set of strategies beyond the strategies taken in the base case to meet 
the terms of the EGU GHG emission guidelines, and include cost 
estimates for demand-side energy efficiency. The compliance 
assumptions--and, therefore, the projected compliance costs--set forth 
in this analysis are illustrative in nature and do not represent the 
full suite of compliance flexibilities states may ultimately pursue. 
These illustrative compliance scenarios are designed to reflect, to the 
extent possible, the scope and the nature of the proposed guidelines. 
However, there is considerable uncertainty with regards to the precise 
measures that states will adopt to meet the proposed requirements, 
because there are considerable flexibilities afforded to the states in 
developing their state plans.
    The EPA projects that the annual incremental compliance cost of 
Option 1 is estimated to be between $5.5 and $7.5 billion in 2020 and 
between $7.3

[[Page 34935]]

and $8.8 billion (2011$) in 2030, including the costs associated with 
monitoring, reporting, and recordkeeping (MRR). The incremental 
compliance cost of Option 2 is estimated to be between $4.3 and $5.5 
billion in 2020, including MRR costs. In 2025, the estimated compliance 
cost of Option 2 is estimated to be between $4.5 and $5.5 billion (with 
the assumed levels of end-use energy efficiency). These important 
dynamics are discussed in more detail in the RIA in the rulemaking 
docket. The annualized incremental cost is the projected additional 
cost of complying with the guidelines in the year analyzed, and 
includes the amortized cost of capital investment, needed new capacity, 
shifts between or amongst various fuels, deployment of energy 
efficiency programs, and other actions associated with compliance. MRR 
costs are estimated to be $68.3 million (2011$) in 2020 and $8.9 
million in 2025 and 2030 for Option 1 and $68.3 million in 2020 and 
$8.9 million in 2025 for Option 2. More detailed cost estimates are 
available in the RIA included in the rulemaking docket.

F. What are the economic and employment impacts?

    The proposed standards are projected to result in certain changes 
to power system operation as a result of the application of state 
emission rate goals. Overall, we project dispatch changes, changes to 
fossil fuel and retail electricity prices, and some additional coal 
retirements. Average electric power sector-delivered natural gas prices 
are projected to increase by roughly 9 to 12 percent in 2020 in Option 
1, with negligible changes by 2030. Under Option 2, electric power 
sector natural gas prices are projected to increase by roughly 8 
percent in 2020, on an average nationwide basis, and increase by 1 
percent or less in 2025. The average delivered coal price to the power 
sector is projected to decrease by 16 to 17 percent in 2020 under 
Option 1, and decrease by roughly 14 percent under Option 2, on a 
nationwide average basis. Retail electricity prices are projected to 
increase 6 to 7 percent under Option 1 and increase by roughly 4 
percent under Option 2, both in 2020 and on an average basis across the 
contiguous U.S. By 2030 under Option 1, electricity prices are 
projected to increase by about 3 percent. Under Option 1, the EPA 
projects 46 to 50 GW of additional coal-fired generation may be 
uneconomic to maintain and may be removed from operation by 2030. The 
EPA projects that under Option 2, 30 to 33 GW of additional coal-fired 
generation may be uneconomic to maintain and may be removed from 
operation by 2025.
    It is important to note that the EPA's modeling does not 
necessarily account for all of the factors that may influence business 
decisions regarding future coal fired capacity. By 2025, the average 
age of the coal-fired fleet will be 49 years old and twenty percent of 
the fleet will be more than 60 years old. Many power companies already 
factor a carbon price into their long term capacity planning that would 
further influence business decisions to replace these aging assets with 
modern, and significantly cleaner generation.
    The compliance modeling done to support the proposal assumes that 
overall electric demand will decrease significantly, as states ramp up 
programs that result in lower overall demand. End-use energy efficiency 
levels increase such that they achieve about an 11 percent reduction on 
overall electricity demand levels in 2030 for Option 1, and a reduction 
in overall electricity demand of approximately 6 percent reduction in 
2025 for Option 2. In response, there are anticipated to be notable 
changes to costs, prices, and electricity generation in the power 
sector as more end-use efficiency is realized.
    Changes in price or demand for electricity, natural gas, coal, can 
impact markets for goods and services produced by sectors that use 
these energy inputs in the production process or supply those sectors. 
Changes in cost of production may result in changes in price, changes 
in quantity produced, and changes in profitability of firms affected. 
The EPA recognizes that these guidelines provide significant 
flexibilities and states implementing the guidelines may choose to 
mitigate impacts to some markets outside the EGU sector. Similarly, 
demand for new generation or energy efficiency can result in shifts in 
production and profitability for firms that supply those goods and 
services, and the guidelines provide flexibility for states that may 
want to enhance demand for goods and services from those sectors.
    Executive Order 13563 directs federal agencies to consider the 
effect of regulations on job creation and employment. According to the 
Executive Order, ``our regulatory system must protect public health, 
welfare, safety, and our environment while promoting economic growth, 
innovation, competitiveness, and job creation. It must be based on the 
best available science.'' (Executive Order 13563, 2011) Although 
standard benefit-cost analyses have not typically included a separate 
analysis of regulation-induced employment impacts, we typically conduct 
employment analyses. During periods of sustained high unemployment, 
employment impacts are of particular concern and questions may arise 
about their existence and magnitude.
    States have the responsibility and flexibility to implement 
policies and practices for compliance with Proposed Electric Generating 
Unit Greenhouse Gas Existing Source Guidelines. Quantifying the 
associated employment impacts is complicated by the wide range of 
approaches that States may use. As such, the EPA's employment analysis 
includes projected employment impacts associated with illustrative 
compliance scenarios for these guidelines for the electric power 
industry, coal and natural gas production, and demand-side energy 
efficiency activities. These projections are derived, in part, from a 
detailed model of the electricity production sector used for this 
regulatory analysis, and U.S government data on employment and labor 
productivity. In the electricity, coal, and natural gas sectors, the 
EPA estimates that these guidelines could have an employment impact of 
roughly 25,900 to 28,000 job-years increase in 2020 for Option 1, state 
to regional compliance approach, respectively. For Option 2, the state 
and regional compliance approach estimates are 26,700 to 29,800 job-
years increase in 2020. Demand-side energy efficiency employment 
impacts are approximately an increase of 78,800 jobs in 2020 for Option 
1 and of 57,000 jobs for Option 2. By its nature, energy efficiency 
reduces overall demand for electric power. The EPA recognizes as more 
efficiency is built into the U.S. power system over time, lower fuel 
requirements may lead to fewer jobs in the coal and natural gas 
extraction sectors, as well as in EGU construction and operation than 
would otherwise have been expected. The EPA also recognizes the fact 
that, in many cases, employment gains and losses that might be 
attributable to this rule would be expected to affect different sets of 
people. Moreover, workers who lose jobs in these sectors may find 
employment elsewhere just as workers employed in new jobs in these 
sectors may have been previously employed elsewhere. Therefore, the 
employment estimates reported in these sectors may include workers 
previously employed elsewhere. This analysis also does not capture 
potential economy-wide impacts due to changes in prices (of fuel, 
electricity, labor, etc.). For these reasons, the numbers reported here

[[Page 34936]]

should not be interpreted as a net national employment impact.

G. What are the benefits of the proposed goals?

    Implementing the proposed standards will generate benefits by 
reducing emissions of CO2 as well as criteria pollutants and 
their precursors, including SO2, NOX and directly 
emitted particles. SO2 and NOX are precursors to 
PM2.5 (particles smaller than 2.5 microns), and 
NOX is a precursor to ozone. The estimated benefits 
associated with these emission reductions are beyond those achieved by 
previous EPA rulemakings including the Mercury and Air Toxics Standards 
rule. The health and welfare benefits from reducing air pollution are 
considered co-benefits for these standards. For this rulemaking, we 
were only able to quantify the climate benefits from reduced emissions 
of CO2 and the health co-benefits associated with reduced 
exposure to PM2.5 and ozone. In summary, we estimate the 
total combined climate benefits and health co-benefits for Option 1 to 
be $33 billion to $54 billion in 2020 and $55 billion to $89 billion in 
2030 assuming a regional compliance approach (2011 dollars at a 3-
percent discount rate [model average]). If states comply using a state-
specific compliance approach, these climate and health co-benefits 
estimates are estimated to be $35 to $57 billion in 2020 and $57 to $93 
billion in 2030 (2011 dollars at a 3-percent discount rate [model 
average]). We also estimate the total combined climate benefits and 
health co-benefits for Option 2 to be $26 billion to $44 billion in 
2020 and $36 billion to $59 billion in 2025 (regional compliance 
approach, 2011 dollars at a 3-percent discount rate [model average]). 
Assuming a state compliance approach, the total combined climate 
benefits and health co-benefits for Option 2 are estimated to be $27 
billion to $45 billion in 2020 and $36 billion to $60 billion in 2025 
(2011 dollars at a 3-percent discount rate [model average]). A summary 
of the emission reductions and monetized benefits estimated for this 
rule at all discount rates and additional analysis years is provided in 
Tables 12 through 17 of this preamble.

              Table 12--Summary of the Monetized Global Climate Benefits for the Proposed Option 1
                                         [Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                                                                  Monetized climate benefits
                                                                             -----------------------------------
                  2020                        Discount rate (statistic)           Regional
                                                                                 compliance     State compliance
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million metric tons)...  ...................................               371               383
                                         5 percent (average SCC)............              $4.7              $4.9
                                         3 percent (average SCC)............               $17               $18
                                         2.5 percent (average SCC)..........               $25               $26
                                         3 percent (95th percentile SCC)....               $51               $52
----------------------------------------------------------------------------------------------------------------
2025
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million metric tons)...  ...................................               501               506
                                         5 percent (average SCC)............              $7.5              $7.6
                                         3 percent (average SCC)............               $25               $25
                                         2.5 percent (average SCC)..........               $37               $37
                                         3 percent (95th percentile SCC)....               $76               $77
----------------------------------------------------------------------------------------------------------------
2030
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million metric tons)...  ...................................               545               555
                                         5 percent (average SCC)............              $9.3              $9.5
                                         3 percent (average SCC)............               $30               $31
                                         2.5 percent (average SCC)..........               $44               $44
                                         3 percent (95th percentile SCC)....               $92               $94
----------------------------------------------------------------------------------------------------------------
\a\ Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the
  table and do not account for changes in non-CO2 GHG emissions. These estimates are based on the global social
  cost of carbon (SCC) estimates for the analysis years (2020, 2025, and 2030) and are rounded to two
  significant figures.

                   Table 13--Summary of the Monetized Global Climate Benefits for the Option 2
                                         [Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                                                                  Monetized climate benefits
                                                                             -----------------------------------
                  2020                        Discount rate (statistic)           Regional            State
                                                                                 compliance        compliance
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million metric tons)...  ...................................               283               295
                                         5 percent (average SCC)............              $3.6              $3.8
                                         3 percent (average SCC)............               $13               $14
                                         2.5 percent (average SCC)..........               $19               $20
                                         3 percent (95th percentile SCC)....               $39               $40
----------------------------------------------------------------------------------------------------------------
2025
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million metric tons)...  ...................................               368               376
                                         5 percent (average SCC)............              $5.5              $5.6
                                         3 percent (average SCC)............               $18               $19

[[Page 34937]]

 
                                         2.5 percent (average SCC)..........               $27               $28
                                         3 percent (95th percentile SCC)....               $56               $57
----------------------------------------------------------------------------------------------------------------
\a\ Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the
  table and do not account for changes in non-CO2 GHG emissions. These estimates are based on the global SCC
  estimates for the analysis years (2020, 2025, and 2030) and are rounded to two significant figures.

  Table 14--Summary of the Monetized Health Co-Benefits for the Proposed Standards Option 1 Regional Compliance
                                              Approach in the U.S.
                                         [Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                                                National
                                                                emission      Monetized health  Monetized health
                         Pollutant                             reductions      co- benefits (3   co- benefits (7
                                                              (thousands of        percent           percent
                                                               short tons)        discount)         discount)
----------------------------------------------------------------------------------------------------------------
                                   Option 1 Regional Compliance Approach 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
    SO2...................................................               292        $12 to $26        $11 to $24
    Directly emitted PM2.5 (Elemental Carbon and Organic                   6     $0.75 to $1.7     $0.67 to $1.5
     Carbon)..............................................
    Directly emitted PM2.5 (crustal)......................                44     $0.77 to $1.7     $0.69 to $1.6
    NOX...................................................               345      $2.2 to $5.0      $2.0 to $4.5
Ozone precursor: \c\                                        ................  ................  ................
    NOX (ozone season only)...............................               146     $0.63 to $2.7     $0.63 to $2.7
----------------------------------------------------------------------------------------------------------------
Total Monetized Health Co-benefits..........................................        $16 to $37        $15 to $34
Total Monetized Health Co-benefits combined with Monetized Climate Benefits         $33 to $54        $32 to $51
 \d\........................................................................
----------------------------------------------------------------------------------------------------------------
                                   Option 1 Regional Compliance Approach 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors \b\                                        ................  ................  ................
    SO2...................................................               395        $17 to $38        $15 to $35
    Directly emitted PM2.5 (Elemental Carbon and Organic                   6     $0.85 to $1.9     $0.76 to $1.7
     Carbon)..............................................
    Directly emitted PM2.5 (crustal)......................                46     $0.78 to $1.8     $0.70 to $1.6
    NOX...................................................               421      $3.0 to $6.8      $2.7 to $6.1
Ozone precursor: \c\                                        ................  ................  ................
NOX (ozone season only)...................................               180      $1.0 to $4.3      $1.0 to $4.3
----------------------------------------------------------------------------------------------------------------
Total Monetized Health Co-benefits..........................................        $23 to $53        $21 to $48
----------------------------------------------------------------------------------------------------------------
Total Monetized Health Co-benefits combined with Monetized Climate Benefits         $48 to $78        $46 to $74
 \d\........................................................................
----------------------------------------------------------------------------------------------------------------
                                   Option 1 Regional Compliance Approach 2030
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
    SO2...................................................               424        $20 to $44        $18 to $40
    Directly emitted PM2.5 (Elemental Carbon and Organic                   5     $0.84 to $1.9     $0.76 to $1.7
     Carbon)..............................................
    Directly emitted PM2.5 (crustal)......................                42     $0.77 to $1.7     $0.70 to $1.6
    NOX...................................................               407      $3.0 to $6.7      $2.7 to $6.1
Ozone precursor: \c\
NOX(ozone season only)....................................               176      $1.1 to $4.5      $1.1 to $4.5
----------------------------------------------------------------------------------------------------------------
    Total Monetized Health Co-benefits......................................        $25 to $59        $23 to $54
    Total Monetized Health Co-benefits combined with Monetized Climate              $55 to $89        $53 to $84
     Benefits \d\...........................................................
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for the analysis years (2020, 2025, 2030) and are rounded to two significant figures, so
  estimates may not sum. It is important to note that the monetized co-benefits do not include reduced health
  effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air
  pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
  through reductions of PM2.5 precursors, such as SO2, NOX and directly emitted PM2.5. PM co-benefits are shown
  as a range reflecting the use of two concentration-response functions, with the lower end of the range based
  on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012).
  These models assume that all fine particles, regardless of their chemical composition, are equally potent in
  causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of
  effect estimates by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
  through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
  of several different concentration-response functions, with the lower end of the range based on a function
  from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
  occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
  at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase
  over time. For the purposes of this table, we show the benefits associated with the model average at 3%
  discount rate, however we emphasize the importance and value of considering the full range of SCC values. We
  provide combined climate and health estimates based on additional discount rates in the RIA.

[[Page 34938]]

  Table 15--Summary of the Monetized Health Co-Benefits in the U.S. for the Proposed Guidelines Option 1 State
                                               Compliance Approach
                                         [Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                             National
                                             emission        Monetized health co-        Monetized health co-
                Pollutant                   reductions        benefits (3 percent         benefits (7 percent
                                           (thousands of           discount)                   discount)
                                            short tons)
----------------------------------------------------------------------------------------------------------------
                                   Option 1 State Compliance Approach in 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \ b\
SO2.....................................             335  $13 to $29................  $11 to $26
Directly emitted PM2.5 (Elemental Carbon               6  $0.76 to $1.7.............  $0.69 to $1.6
 and Organic Carbon).
Directly emitted PM2.5 (crustal)........              45  $0.79 to $1.8.............  $0.71 to $1.6
NOX.....................................             367  $2.2 to $4.9..............  $2.0 to $4.4
Ozone precursor: \c\
NOX (ozone season only).................             157  $0.64 to $2.7.............  $0.64 to $2.7
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits..................  $17 to $40................  $15 to $36
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits combined with      $35 to $57................  $33 to $54
     Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
                                   Option 1 State Compliance Approach in 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
SO2.....................................             425  $18 to $40................  $16 to $36
Directly emitted PM2.5 (Elemental Carbon               6  $0.90 to $2.0.............  $0.81 to $1.8
 and Organic Carbon).
Directly emitted PM2.5 (crustal)........              49  $0.83 to $1.9.............  $0.75 to $1.7
NOX.....................................             436  $2.9 to $6.5..............  $2.6 to $5.8
Ozone precursor: \c\
NOX (ozone season only).................             190  $1.0 to $4.4..............  $1.0 to $4.4
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits..................  $23 to $54................  $21 to $49
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits combined with      $49 to $80................  $46 to $75
     Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
                                   Option 1 State Compliance Approach in 2030
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
SO2.....................................             471  $21 to $47................  $19 to $43
Directly emitted PM2.5 (Elemental Carbon               6  $0.87 to $2.0.............  $0.78 to $1.8
 and Organic Carbon).
Directly emitted PM2.5 (crustal)........              44  $0.80 to $1.8.............  $0.72 to $1.6
NOX.....................................             428  $2.9 to $6.6..............  $2.6 to $6.0
Ozone precursor: \c\
NOX (ozone season only).................             187  $1.1 to $4.6..............  $1.1 to $4.6
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits..................  $27 to $62................  $24 to $57
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits combined with      $57 to $93................  $55 to $87
     Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for the analysis years (2020, 2025, 2030) and are rounded to two significant figures, so
  estimates may not sum. It is important to note that the monetized co-benefits do not include reduced health
  effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air
  pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
  through reductions of PM2.5 precursors, such as SO2, NOX and directly emitted PM2.5. PM co-benefits are shown
  as a range reflecting the use of two concentration-response functions, with the lower end of the range based
  on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012).
  These models assume that all fine particles, regardless of their chemical composition, are equally potent in
  causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of
  effect estimates by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
  through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
  of several different concentration-response functions, with the lower end of the range based on a function
  from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
  occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
  at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase
  over time. For the purposes of this table, we show the benefits associated with the model average at 3%
  discount rate, however we emphasize the importance and value of considering the full range of SCC values. We
  provide combined climate and health estimates based on additional discount rates in the RIA.

 Table 16--Summary of the Monetized Health Co-Benefits in the U.S. for the Option 2 Regional Compliance Approach
                                         [Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                             National
                                             emission        Monetized health co-        Monetized health co-
                Pollutant                   reductions        benefits (3 percent         benefits (7 percent
                                           (thousands of           discount)                   discount)
                                            short tons)
----------------------------------------------------------------------------------------------------------------
                                   Option 2 Regional Compliance Approach 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
SO2.....................................             244  $9.8 to $22...............  $8.9 to $20
Directly emitted PM2.5 (Elemental Carbon               5  $0.61 to $1.4.............  $0.55 to $1.2
 and Organic Carbon).
Directly emitted PM2.5 (crustal)........              36  $0.63 to $1.4.............  $0.57 to $1.3
NOX.....................................             268  $1.7 to $3.9..............  $1.6 to $3.5
Ozone precursor: \c\

[[Page 34939]]

 
NOX (ozone season only).................             111  $0.47 to $2.0.............  $0.47 to $2.0
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits..................  $13 to $31................  $12 to $28
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits combined with      $26 to $44................  $25 to $41
     Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
                                  Option 2 Regional Compliance Approach in 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
SO2.....................................             297  $13 to $29................  $12 to $26
Directly emitted PM2.5 (Elemental Carbon               4  $0.64 to $1.4.............  $0.58 to $1.3
 and Organic Carbon).
Directly emitted PM2.5 (crustal)........              34  $0.59 to $1.3.............  $0.53 to $1.2
NOX.....................................             309  $2.2 to $5.0..............  $2.0 to $4.5
Ozone precursor: \c\
NOX (ozone season only).................             129  $0.73 to $3.1.............  $0.73 to $3.1
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits..................  $17 to $40................  $16 to $36
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits combined with      $36 to $59................  $34 to $55
     Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for the analysis years (2020, 2025) and are rounded to two significant figures, so
  estimates may not sum. It is important to note that the monetized co-benefits do not include reduced health
  effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air
  pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
  through reductions of PM2.5 precursors, such as SO2, NOX and directly emitted PM2.5. PM co-benefits are shown
  as a range reflecting the use of two concentration-response functions, with the lower end of the range based
  on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012).
  These models assume that all fine particles, regardless of their chemical composition, are equally potent in
  causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of
  effect estimates by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
  through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
  of several different concentration-response functions, with the lower end of the range based on a function
  from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
  occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
  at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase
  over time. For the purposes of this table, we show the benefits associated with the model average at 3%
  discount rate, however we emphasize the importance and value of considering the full range of SCC values. We
  provide combined climate and health estimates based on additional discount rates in the RIA.

    Table 17--Summary of the Monetized Health Co-Benefits in the U.S. for Option 2 State Compliance Approach
                                         [Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                             National
                                             emission        Monetized health co-        Monetized health co-
                Pollutant                   reductions        benefits (3 percent         benefits (7 percent
                                           (thousands of           discount)                   discount)
                                            short tons)
----------------------------------------------------------------------------------------------------------------
                                   Option 2 State Compliance Approach in 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors:\b\
SO2.....................................             267  $10 to $23................  $9.1 to $21
Directly emitted PM2.5 (Elemental Carbon               5  $0.64 to $1.5.............  $0.58 to $1.3
 and Organic Carbon).
Directly emitted PM2.5 (crustal)........              38  $0.66 to $1.5.............  $0.60 to $1.4
NOX.....................................             281  $1.7 to $3.8..............  $1.5 to $3.4
Ozone precursor:\c\
NOX (ozone season only).................             119  $0.48 to $2.1.............  $0.48 to $2.1
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits..................  $14 to $32................  $12 to $29
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits combined with      $27 to $45................  $26 to $42
     Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
                                   Option 2 State Compliance Approach in 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors:\ b\
SO2.....................................             327  $14 to $30................  $12 to $27
Directly emitted PM2.5 (Elemental Carbon               5  $0.69 to $1.6.............  $0.63 to $1.4
 and Organic Carbon).
Directly emitted PM2.5 (crustal)........              38  $0.64 to $1.4.............  $0.58 to $1.3
NOX.....................................             317  $2.1 to $4.7..............  $1.9 to $4.2
Ozone precursor:\c\

[[Page 34940]]

 
NOX (ozone season only).................             136  $0.72 to $3.1.............  $0.72 to $3.1
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits..................  $18 to $41................  $16 to $16
                                         -----------------------------------------------------------------------
    Total Monetized Health Co-benefits combined with      $36 to $60................  $35 to $56
     Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for the analysis years (2020, 2025) and are rounded to two significant figures, so
  estimates may not sum. It is important to note that the monetized co-benefits do not include reduced health
  effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air
  pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
  through reductions of PM2.5 precursors, such as SO2, NOX and directly emitted PM2.5. PM co-benefits are shown
  as a range reflecting the use of two concentration-response functions, with the lower end of the range based
  on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012).
  These models assume that all fine particles, regardless of their chemical composition, are equally potent in
  causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of
  effect estimates by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
  through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
  of several different concentration-response functions, with the lower end of the range based on a function
  from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
  occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
  at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase
  over time. For the purposes of this table, we show the benefits associated with the model average at 3%
  discount rate; however, we emphasize the importance and value of considering the full range of SCC values. We
  provide combined climate and health estimates based on additional discount rates in the RIA.

    The EPA has used the social cost of carbon (SCC) estimates 
presented in the 2013 Technical Support Document: Technical Update of 
the Social Cost of Carbon for Regulatory Impact Analysis Under 
Executive Order 12866 (2013 SCC TSD) to analyze CO2 climate 
impacts of this rulemaking.\331\ We refer to these estimates, which 
were developed by the U.S. government, as ``SCC estimates.'' The U.S. 
government first published the SCC estimates in 2010 following an 
interagency process that included the EPA and other executive branch 
entities; the process used three integrated assessment models (IAM) to 
develop SCC estimates and selected four global values for use in 
regulatory analyses. The U.S. government recently updated these 
estimates using new versions of each integrated assessment model and 
published them in 2013. The 2013 update did not revisit the 2010 
modeling decisions (e.g., with regard to the discount rate, reference 
case socioeconomic and emission scenarios or equilibrium climate 
sensitivity). Rather, improvements in the way damages are modeled are 
confined to those that have been incorporated into the latest versions 
of the models by the developers themselves and published in the peer-
reviewed literature. The 2010 SCC Technical Support Document (2010 SCC 
TSD) provides a complete discussion of the methods used to develop 
these estimates and the 2013 SCC TSD presents and discusses the updated 
estimates.\332\
---------------------------------------------------------------------------

    \331\ Docket ID EPA-HQ-OAR-2013-0495, Technical Support 
Document: Technical Update of the Social Cost of Carbon for 
Regulatory Impact Analysis Under Executive Order 12866, Interagency 
Working Group on Social Cost of Carbon, with participation by 
Council of Economic Advisers, Council on Environmental Quality, 
Department of Agriculture, Department of Commerce, Department of 
Energy, Department of Transportation, Environmental Protection 
Agency, National Economic Council, Office of Energy and Climate 
Change, Office of Management and Budget, Office of Science and 
Technology Policy, and Department of Treasury (May 2013, Revised 
November 2013). Available at: http://www.whitehouse.gov/sites/default/files/omb/assets/inforeg/technical-update-social-cost-of-carbon-for-regulator-impact-analysis.pdf.
    \332\ Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support 
Document: Social Cost of Carbon for Regulatory Impact Analysis Under 
Executive Order 12866, Interagency Working Group on Social Cost of 
Carbon, with participation by the Council of Economic Advisers, 
Council on Environmental Quality, Department of Agriculture, 
Department of Commerce, Department of Energy, Department of 
Transportation, Environmental Protection Agency, National Economic 
Council, Office of Energy and Climate Change, Office of Management 
and Budget, Office of Science and Technology Policy, and Department 
of Treasury (February 2010). Also available at: http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf>.
---------------------------------------------------------------------------

    The EPA and other agencies have sought public comment on the SCC 
estimates as part of various rulemakings. In addition, OMB's Office of 
Information and Regulatory Affairs recently sought public comment on 
the approach used to develop the estimates. The comment period ended on 
February 26, 2014, and OMB is reviewing the comments received.
    The four SCC estimates, updated in 2013, are as follows: $13, $46, 
$68, and $137 per metric ton of CO2 emissions in the year 
2020 (2011 dollars).\333\ The first three values are based on the 
average SCC from the three IAMs, at discount rates of 5, 3, and 2.5 
percent, respectively. SCCs at several discount rates are included 
because the literature shows that the SCC is quite sensitive to 
assumptions about the discount rate, and because no consensus exists on 
the appropriate rate to use in an intergenerational context (where 
costs and benefits are incurred by different generations). The fourth 
value is the 95th percentile of the SCC from all three models at a 3 
percent discount rate. It is included to represent higher-than-expected 
impacts from temperature change further out in the tails of the SCC 
distribution (representing less likely, but potentially catastrophic, 
outcomes).
---------------------------------------------------------------------------

    \333\ The 2010 and 2013 TSDs present SCC in $2007. The estimates 
were adjusted to 2011$ using the GDP Implicit Price Deflator. Also 
available at: http://www.gpo.gov/fdsys/pkg/ECONI-2013-02/pdf/ECONI-2013-02-Pg3.pdf.
---------------------------------------------------------------------------

    The 2010 SCC TSD noted a number of limitations to the SCC analysis, 
including the incomplete way in which the integrated assessment models 
capture catastrophic and non-catastrophic impacts, their incomplete 
treatment of adaptation and

[[Page 34941]]

technological change, uncertainty in the extrapolation of damages to 
high temperatures, and assumptions regarding risk aversion. Current 
integrated assessment models do not assign value to all of the 
important physical, ecological, and economic impacts of climate change 
recognized in the climate change literature for various reasons, 
including the inherent difficulties in valuing non-market impacts and 
the fact that the science incorporated into these models understandably 
lags behind the most recent research. Nonetheless, these estimates and 
the discussion of their limitations represent the best available 
information about the social benefits of CO2 emission 
reductions to inform the benefit-cost analysis. Model developers 
continually update the models to incorporate recent research. The new 
versions of the models used to estimate the values presented in this 
rulemaking offer some improvements in these areas identified above, 
although further work is warranted. Accordingly, the EPA and other 
parties continue to conduct research on modeling and valuation of 
climate impacts with the goal of improving these estimates. Additional 
details are provided in the SCC TSDs.
    The health co-benefits estimates represent the total monetized 
human health benefits for populations exposed to reduced 
PM2.5 and ozone resulting from emission reductions under 
illustrative compliance options for the proposed standards. Unlike the 
global SCC estimates, the air pollution health co-benefits are 
estimated for the contiguous U.S. only. We used a ``benefit-per-ton'' 
approach to estimate the benefits of this rulemaking. To create the 
PM2.5 benefit-per-ton estimates, this approach uses a model 
to convert emissions of PM2.5 precursors into changes in 
ambient PM2.5 levels and another model to estimate the 
changes in human health effects associated with that change in air 
quality, which are then divided by the emissions in specific sectors. 
We derived national average benefit-per-ton estimates for the EGU 
sector using the approach published in Fann et al. (2012),\334\ and 
updated those estimates to reflect the studies and population data in 
the 2012 PM NAAQS RIA. We further separated the national estimates into 
regional estimates to provide greater spatial resolution.\335\ In 
addition, we generated regional benefit-per-ton estimates for changes 
in ozone exposure. The ozone estimates used the ozone information from 
the sector modeling for the EGU sector described in Fann et al. (2012) 
and the health impact assumptions used in the Ozone NAAQS 
RIAs.336 337 To calculate the co-benefits for the proposed 
standards, we multiplied the regional benefit-per-ton estimates for the 
EGU sector by the corresponding emission reductions.\338\ All benefit-
per-ton estimates reflect the geographic distribution of the modeled 
emissions, which may not exactly match the emission reductions in this 
rulemaking, and thus they may not reflect the local variability in 
population density, meteorology, exposure, baseline health incidence 
rates, or other local factors for any specific location. More 
information regarding the derivation of the benefit-per-ton estimates 
is available in the RIA.
---------------------------------------------------------------------------

    \334\ Fann, N., K.R. Baker and C.M. Fulcher. 2012. 
``Characterizing the PM2.5-related health benefits of 
emission reductions for 17 industrial, area and mobile emission 
sectors across the U.S.'' Environment International 49 41-151.
    \335\ U.S. Environmental Protection Agency (U.S. EPA). 2012. 
Regulatory Impact Analysis for the Final Revisions to the National 
Ambient Air Quality Standards for Particulate Matter. Research 
Triangle Park, NC: Office of Air Quality Planning and Standards, 
Health and Environmental Impacts Division. (EPA document number EPA-
452/R-12-003, December). Available at: <http://www.epa.gov/pm/2012/finalria.pdf>.
    \336\ U.S. Environmental Protection Agency (U.S. EPA). 2008b. 
Final Ozone NAAQS Regulatory Impact Analysis. Research Triangle 
Park, NC: Office of Air Quality Planning and Standards, Health and 
Environmental Impacts Division, Air Benefit and Cost Group Research. 
(EPA document number EPA-452/R-08-003, March). Available at: <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>.
    \337\ U.S. Environmental Protection Agency (U.S. EPA). 2010. 
Section 3: Re-analysis of the Benefits of Attaining Alternative 
Ozone Standards to Incorporate Current Methods. Available at <http://www.epa.gov/ttnecas1/regdata/RIAs/s3-supplemental_analysis-updated_benefits11-5.09.pdf>.
    \338\ U.S. Environmental Protection Agency. 2013. Technical 
support document: Estimating the benefit per ton of reducing PM2.5 
precursors from 17 sectors. Research Triangle Park, NC: Office of 
Air and Radiation, Office of Air Quality Planning and Standards, 
January. Available at: <http://www.epa.gov/airquality/benmap/models/Source_Apportionment_BPT_TSD_1_31_13.pdf>.
---------------------------------------------------------------------------

    These models assume that all fine particles, regardless of their 
chemical composition, are equally potent in causing premature mortality 
because the scientific evidence is not yet sufficient to allow 
differentiation of effect estimates by particle type. Even though we 
assume that all fine particles have equivalent health effects, the 
benefit-per-ton estimates vary between precursors depending on the 
location and magnitude of their impact on PM2.5 levels, 
which drive population exposure.
    It is important to note that the magnitude of the PM2.5 
and ozone co-benefits is largely driven by the concentration response 
functions for premature mortality and the value of a statistical life 
used to value reductions in premature mortality. For PM2.5, 
we cite two key empirical studies, one based on the American Cancer 
Society cohort study \339\ and the extended Six Cities cohort 
study.\340\ We present the PM2.5 co-benefits results as a 
range based on the concentration-response functions from these two 
epidemiology studies, but this range does not capture the full range of 
uncertainty inherent in the co-benefits estimates. In the RIA for this 
rule, which is available in the docket, we also include 
PM2.5 co-benefits estimates derived from expert judgments 
(Roman et al., 2008) \341\ as a characterization of uncertainty 
regarding the PM2.5-mortality relationship. For the ozone 
co-benefits, we present the results as a range reflecting the use of 
several different concentration-response functions for mortality, with 
the lower end of the range based on a function from Bell et al. (2004) 
\342\ and the upper end based on a function from Levy et al. 
(2005).\343\ Similar to PM2.5, the range of ozone co-
benefits does not capture the full range of inherent uncertainty.
---------------------------------------------------------------------------

    \339\ Krewski D.; M. Jerrett; R.T. Burnett; R. Ma; E. Hughes; Y. 
Shi, et al. 2009. Extended Follow-up and Spatial Analysis of the 
American Cancer Society Study Linking Particulate Air Pollution and 
Mortality. Health Effects Institute. (HEI Research Report number 
140). Boston, MA: Health Effects Institute.
    \340\ Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. 
``Chronic Exposure to Fine Particles and Mortality: An Extended 
Follow-Up of the Harvard Six Cities Study from 1974 to 2009.'' 
Environmental Health Perspective, 120(7), July, pp. 965-970.
    \341\ Roman, H., et al. 2008. ``Expert Judgment Assessment of 
the Mortality Impact of Changes in Ambient Fine Particulate Matter 
in the U.S.'' Environmental Science & Technology, Vol. 42, No. 7, 
February, pp. 2268-2274.
    \342\ Bell, M.L., et al. 2004. ``Ozone and Short-Term Mortality 
in 95 U.S. Urban Communities, 1987-2000.'' Journal of the American 
Medical Association, 292(19), pp. 2372-8.
    \343\ Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. 
``Ozone exposure and mortality: an empiric bayes metaregression 
analysis.'' Epidemiology. 16(4): p. 458-68.
---------------------------------------------------------------------------

    In this analysis, the EPA assumes that the health impact function 
for fine particles is without a threshold. This is based on the 
conclusions of EPA's Integrated Science Assessment for Particulate 
Matter,\344\ which evaluated the substantial body of published 
scientific literature, reflecting thousands of epidemiology, 
toxicology, and clinical studies that documents the association between 
elevated PM2.5

[[Page 34942]]

concentrations and adverse health effects, including increased 
premature mortality. This assessment, which was twice reviewed by the 
EPA's independent Science Advisory Board, concluded that the scientific 
literature consistently finds that a no-threshold model most adequately 
portrays the PM-mortality concentration-response relationship.
---------------------------------------------------------------------------

    \344\ U.S. Environmental Protection Agency. 2009. Integrated 
Science Assessment for Particulate Matter (Final Report). Research 
Triangle Park, NC: National Center for Environmental Assessment, RTP 
Division. (EPA document number EPA-600-R-08-139F, December). 
Available at: <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
---------------------------------------------------------------------------

    In general, we are more confident in the magnitude of the risks we 
estimate from simulated PM2.5 concentrations that coincide 
with the bulk of the observed PM concentrations in the epidemiological 
studies that are used to estimate the benefits. Likewise, we are less 
confident in the risk we estimate from simulated PM2.5 
concentrations that fall below the bulk of the observed data in these 
studies.
    For this analysis, policy-specific air quality data are not 
available,\345\ and thus, we are unable to estimate the percentage of 
premature mortality associated with this specific rule's emission 
reductions at each PM2.5 level. As a surrogate measure of 
mortality impacts, we provide the percentage of the population exposed 
above the lowest measured PM2.5 level (LML) in each of the 
studies from which we obtained concentration-response functions for 
PM2.5 mortality, using the estimates of PM2.5 
from the source apportionment modeling used to calculate the benefit-
per-ton estimates for the EGU sector. Using the Krewski et al. (2009) 
study, 93 percent of the population is exposed to annual mean 
PM2.5 levels at or above the LML of 5.8 micrograms per cubic 
meter ([mu]g/m\3\). Using the Lepeule et al. (2012) study, 67 percent 
of the population is exposed above the LML of 8 [mu]g/m\3\. It is 
important to note that baseline exposure is only one parameter in the 
health impact function, along with baseline incidence rates, 
population, and change in air quality. Therefore, caution is warranted 
when interpreting the LML assessment for this rule because these 
results are not consistent with results from rules that had air quality 
modeling.
---------------------------------------------------------------------------

    \345\ In addition, site-specific emission reductions will depend 
upon how states implement the guidelines.
---------------------------------------------------------------------------

    Every benefit analysis examining the potential effects of a change 
in environmental protection requirements is limited, to some extent, by 
data gaps, model capabilities (such as geographic coverage) and 
uncertainties in the underlying scientific and economic studies used to 
configure the benefit and cost models. Despite these uncertainties, we 
believe the air quality co-benefit analysis for this rule provides a 
reasonable indication of the expected health benefits of the air 
pollution emission reductions for the illustrative compliance options 
for the proposed standards under a set of reasonable assumptions. This 
analysis does not include the type of detailed uncertainty assessment 
found in the 2012 PM2.5 National Ambient Air Quality 
Standard (NAAQS) RIA (U.S. EPA, 2012) because we lack the necessary air 
quality input and monitoring data to conduct a complete benefits 
assessment. In addition, using a benefit-per-ton approach adds another 
important source of uncertainty to the benefits estimates. The 2012 
PM2.5 NAAQS benefits analysis provides an indication of the 
sensitivity of our results to various assumptions.
    We note that the monetized co-benefits estimates shown here do not 
include several important benefit categories, including exposure to 
SO2, NOX, and hazardous air pollutants (e.g., 
mercury and hydrogen chloride), as well as ecosystem effects and 
visibility impairment. Although we do not have sufficient information 
or modeling available to provide monetized estimates for this rule, we 
include a qualitative assessment of these unquantified benefits in the 
RIA for these proposed amendments.
    For more information on the benefits analysis, please refer to the 
RIA for this rule, which is available in the rulemaking docket.

XI. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review, and Executive 
Order 13563, Improving Regulation and Regulatory Review

    Under Section 3(f)(1) of Executive Order 12866 (58 FR 51735, 
October 4, 1993), this action is an ``economically significant 
regulatory action'' because it is likely to have an annual effect on 
the economy of $100 million or more or adversely affect in a material 
way the economy, a sector of the economy, productivity, competition, 
jobs, the environment, public health or safety, or state, local, or 
tribal governments or communities. The $100 million threshold can be 
triggered by either costs or benefits, or a combination of them. 
Accordingly, the EPA submitted this action to OMB for review under 
Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011), and 
any changes made in response to OMB recommendations have been 
documented in the docket for this action.
    The EPA also prepared an analysis of the potential costs and 
benefits associated with this action. This analysis is contained in the 
RIA for this proposed rule. A copy of the analysis is available in the 
docket for this action.
    Consistent with EO 12866 and EO 13563, the EPA estimated the costs 
and benefits for illustrative compliance approaches of implementing the 
proposed guidelines. This proposal sets goals to reduce CO2 
emissions from the electric power industry. Actions taken to comply 
with the proposed guidelines will also reduce the emissions of directly 
emitted PM2.5, sulfur dioxide (SO2) and nitrogen 
oxides (NOX). The benefits associated with these PM, 
SO2 and NOX reductions are referred to as co-
benefits, as these reductions are not the primary objective of this 
rule.
    The EPA has used the social cost of carbon estimates presented in 
the 2013 Technical Support Document: Technical Update of the Social 
Cost of Carbon for Regulatory Impact Analysis Under Executive Order 
12866 (2013 SCC TSD) to analyze CO2 climate impacts of this 
rulemaking. We refer to these estimates, which were developed by the 
U.S. government, as ``SCC estimates.'' The SCC is an estimate of the 
monetary value of impacts associated with a marginal change in 
CO2 emissions in a given year. The four SCC estimates are 
associated with different discount rates (model average at 2.5 percent 
discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), 
and each increases over time. In this summary, the EPA provides the 
estimate of climate benefits associated with the SCC value deemed to be 
central in the SCC TSD: The model average at 3% discount rate. For the 
regional compliance approach, the EPA estimates that in 2020 this 
Option 1 proposal will yield monetized climate benefits (in 2011$) of 
approximately $17 billion (3 percent model average). The air pollution 
health co-benefits in 2020 are estimated to be $16 billion to $37 
billion (2011$) for a 3 percent discount rate and $15 billion to $34 
billion (2011$) for a 7 percent discount rate. The annual, illustrative 
compliance costs estimated by IPM and inclusive of demand side energy 
efficiency program and participant costs and MRR costs, are 
approximately $5.5 billion (2011$) in 2020. The quantified net benefits 
(the difference between monetized benefits and costs) in 2020 are 
estimated to be $28 billion to $49 billion assuming a regional 
compliance approach (2011$) using a 3 percent discount rate (model 
average). This range of net benefits is estimated to be $27 billion to 
$50 billion assuming a state compliance approach (2011$)

[[Page 34943]]

using a 3 percent discount rate (model average). Table 18 shows the 
climate benefits, health co-benefits, cost and net benefits for Option 
1 in 2020 for state and regional compliance approaches. Table 19 shows 
similar estimates for 2030.
    For Option 1 in 2030 assuming a regional compliance approach, the 
EPA estimates this proposal will yield monetized climate benefits (in 
2011$) of approximately $30 billion (3 percent, model average). The air 
pollution health co-benefits in 2030 are estimated to be $25 billion to 
$59 billion (2011$) for a 3 percent discount rate and $23 billion to 
$54 billion (2011$) for a 7 percent discount rate. The annual 
illustrative compliance costs estimated using IPM, inclusive of a 
demand-side energy efficiency program and participant costs and MRR 
costs, are approximately $7.3 billion (2011$) in 2030. The quantified 
net benefits (the difference between monetized benefits and costs) in 
2030 are estimated to be $48 billion to $82 billion (2011$) using a 3 
percent discount rate (model average). The EPA estimates that this 
proposal will yield monetized climate benefits (in 2011$) of 
approximately $31 billion (3 percent, model average) for Option 1 state 
compliance approach in 2030. The air pollution health co-benefits in 
2030 are estimated to be $27 billion to $62 billion (2011$) for a 3 
percent discount rate and $24 billion to $56 billion (2011$) for a 7 
percent discount rate. The annual illustrative compliance costs 
estimated using IPM, inclusive of demand side energy efficiency program 
and participant costs and MRR costs, are approximately $8.8 billion 
(2011$) in 2030. The quantified net benefits (the difference between 
monetized benefits and costs) in 2030 are estimated to be $49 billion 
to $84 billion (2011$) using a 3 percent discount rate (model average) 
assuming a state compliance approach. Based upon the foregoing 
discussion, it remains clear that the benefits of the proposal Option 1 
are substantial and far exceed the costs.

  Table 18--Summary of the Monetized Benefits, Compliance Costs and Net
               Benefits for Proposed Option 1 in 2020 \a\
                           [Billions of 2011$]
------------------------------------------------------------------------
                               3% Discount rate      7% Discount rate
------------------------------------------------------------------------
                  Option 1 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $17.
                              ------------------------------------------
Air pollution health co-       $16 to $37......  $15 to $34
 benefits \c\.
Total Compliance Costs \d\...  $5.5............  $5.5
Net Monetized Benefits \e\...  $28 to $49......  $26 to $45
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.3 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
                   Option 1 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $18.
                              ------------------------------------------
Air pollution health co-       $17 to $40......  $15 to $36
 benefits \c\.
Total Compliance Costs \d\...  $7.5............  $7.5
Net Monetized Benefits \e\...  $27 to $50......  $26 to $46
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.5 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2020, and are rounded to two significant
  figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SCC than to the other estimates because CO2 emissions are long-lived
  and subsequent damages occur over many years. The benefit estimates in
  this table are based on the average SCC estimated for a 3 percent
  discount rate; however, we emphasize the importance and value of
  considering the full range of SCC values. As shown in the RIA, climate
  benefits are also estimated using the other three SCC estimates (model
  average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
  percentile at 3 percent). The SCC estimates are year-specific and
  increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
  PM2.5 and ozone associated with emission reductions of directly
  emitted PM2.5, SO2 and NOX. The range reflects the use of
  concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 90
  percent of total monetized co-benefits from PM2.5 and ozone. These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to allow differentiation
  of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the proposed option
  and a discount rate of approximately 5 percent. This estimate includes
  monitoring, recordkeeping, and reporting costs and demand side energy
  efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global social cost of carbon at a 3 percent discount rate
  (model average). The RIA includes combined climate and health
  estimates based on these additional discount rates.

 Table 19--Summary of the Monetized Benefits, Compliance Costs, and Net
               Benefits for Proposed Option 1 in 2030 \a\
                           [Billions of 2011$]
------------------------------------------------------------------------
                               3% Discount rate      7% Discount rate
------------------------------------------------------------------------
                  Option 1 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $30.
------------------------------------------------------------------------
Air pollution health co-       $25 to $59......  $23 to $54
 benefits \c\.
Total Compliance Costs \d\...  $7.3............  $7.3
Net Monetized Benefits \e\...  $48 to $82......  $46 to $77
------------------------------------------------------------------------

[[Page 34944]]

 
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.7 tons of Hg and 580 tons of HCl.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
                   Option 1 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $31.
                              ------------------------------------------
Air pollution health co-       $27 to $62......  $24 to $56
 benefits \c\.
Total Compliance Costs \d\...  $8.8............  $8.8
Net Monetized Benefits \e\...  $49 to $84......  $46 to $79
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               2.1 tons of Hg and 590 tons of HCl.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2030, and are rounded to two significant
  figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SCC than to the other estimates because CO2 emissions are long-lived
  and subsequent damages occur over many years. The benefit estimates in
  this table are based on the average SCC estimated for a 3 percent
  discount rate; however, we emphasize the importance and value of
  considering the full range of SCC values. As shown in the RIA, climate
  benefits are also estimated using the other three SCC estimates (model
  average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
  percentile at 3 percent). The SCC estimates are year-specific and
  increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
  PM2.5 and ozone associated with emission reductions of directly
  emitted PM2.5, SO2 and NOX. The range reflects the use of
  concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 90
  percent of total monetized co-benefits from PM2.5 and ozone. These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to allow differentiation
  of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the proposed option
  and a discount rate of approximately 5 percent. This estimate includes
  monitoring, recordkeeping, and reporting costs and demand side energy
  efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global social cost of carbon at a 3 percent discount rate
  (model average). The RIA includes combined climate and health
  estimates based on these additional discount rates.

    The estimated costs and benefits for the regulatory alternative--
Option 2 regional and state compliance approaches are shown in Tables 
20 and 21. As these tables reflect, net benefits in 2020 are estimated 
to be $22 to $40 billion (3 percent discount rate) and $21 to $37 
billion (7 percent discount rate) for Option 2 assuming regional 
compliance. These Option 2 net benefit estimates become $22 to $40 
billion (3 percent discount rate) and $20 to $37 billion (7 percent 
discount rate) with the state compliance approach. In 2025, net 
benefits are estimated to be $31 billion to $54 billion (3 percent 
discount rate) and $29 billion to $50 billion (7 percent discount rate) 
assuming a regional compliance approach and $31 billion to $55 billion 
(3 percent discount rate) and $29 billion to $51 billion (7 percent 
discount rate) assuming a state compliance approach.
    The EPA could not monetize important benefits of proposed Option 1 
and regulatory alternative Option 2. Unquantified benefits include 
climate benefits from reducing emissions of non-CO2 
greenhouse gases and co-benefits from reducing exposure to 
SO2, NOX, and hazardous air pollutants (e.g., 
mercury and hydrogen chloride), as well as ecosystem effects and 
visibility impairment.

 Table 20--Summary of the Monetized Benefits, Compliance Costs, and Net
                Benefits for Proposed Option 2 in 2020 a
                           [Billions of 2011$]
------------------------------------------------------------------------
                               3% Discount rate      7% Discount rate
------------------------------------------------------------------------
                  Option 2 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $13.
                              ------------------------------------------
Air pollution health co-       $13 to $31......  $12 to $28
 benefits \c\.
Total Compliance Costs \d\...  $4.3............  $4.3
Net Monetized Benefits \e\...  $22 to $40......  $21 to $37
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               0.9 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------

[[Page 34945]]

 
                   Option 2 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $14.
------------------------------------------------------------------------
Air pollution health co-       $14 to $32......  $12 to $29
 benefits \c\.
Total Compliance Costs \d\...  $5.5............  $5.5
Net Monetized Benefits \e\...  $22 to $40......  $20 to $37
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.2 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2020, and are rounded to two significant
  figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SCC than to the other estimates because CO2 emissions are long-lived
  and subsequent damages occur over many years. The benefit estimates in
  this table are based on the average SCC estimated for a 3 percent
  discount rate; however, we emphasize the importance and value of
  considering the full range of SCC values. As shown in the RIA, climate
  benefits are also estimated using the other three SCC estimates (model
  average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
  percentile at 3 percent). The SCC estimates are year-specific and
  increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
  PM2.5 and ozone associated with emission reductions of directly
  emitted PM2.5, SO2 and NOX. The range reflects the use of
  concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 90
  percent of total monetized co-benefits from PM2.5 and ozone. These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to allow differentiation
  of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the proposed option
  and a discount rate of approximately 5 percent. This estimate includes
  monitoring, recordkeeping and reporting costs and demand side energy
  efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global social cost of carbon at a 3 percent discount rate
  (model average). The RIA includes combined climate and health
  estimates based on these additional discount rates.

 Table 21--Summary of the Monetized Benefits, Compliance Costs, and Net
                Benefits for Proposed Option 2 in 2025 a
                           [Billions of 2011$]
------------------------------------------------------------------------
                               3% Discount rate      7% Discount rate
------------------------------------------------------------------------
                  Option 2 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $18.
                              ------------------------------------------
Air pollution health co-       $17 to $40......  $16 to $36
 benefits \c\.
Total Compliance Costs \d\...  $4.5............  $4.5
Net Monetized Benefits \e\...  $31 to $54......  $29 to $50
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.3 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
                   Option 2 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $19.
                              ------------------------------------------
Air pollution health co-       $18 to $41......  $16 to $37
 benefits \c\.
Total Compliance Costs \d\...  $5.5............  $5.5
Net Monetized Benefits \e\...  $31 to $55......  $29 to $51
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.7 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2025, and are rounded to two significant
  figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SCC than to the other estimates because CO2 emissions are long-lived
  and subsequent damages occur over many years. The benefit estimates in
  this table are based on the average SCC estimated for a 3 percent
  discount rate; however, we emphasize the importance and value of
  considering the full range of SCC values. As shown in the RIA, climate
  benefits are also estimated using the other three SCC estimates (model
  average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
  percentile at 3 percent). The SCC estimates are year-specific and
  increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
  PM2.5 and ozone associated with emission reductions of directly
  emitted PM2.5, SO2 and NOX. The range reflects the use of
  concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 90
  percent of total monetized co-benefits from PM2.5 and ozone. These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to allow differentiation
  of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the proposed option
  and a discount rate of approximately 5 percent. This estimate includes
  monitoring, recordkeeping and reporting costs and demand side energy
  efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global social cost of carbon at a 3 percent discount rate
  (model average). The RIA includes combined climate and health
  estimates based on these additional discount rates.

    The analysis done in support of this proposal shows that the 
emission reductions, benefits, and costs for the illustrative 
compliance approaches for the proposed Option 1 (and regulatory 
alternative Option 2) are larger if states choose to comply on an 
individual basis, compared to the illustrative regional compliance 
approach. The regional approach allows for more flexibility across 
states, which results in slightly fewer emission reductions and

[[Page 34946]]

lower overall costs. Net benefits (the difference between benefits and 
costs) are roughly equivalent under the regional and state compliance 
approaches.
    In evaluating the impacts of the proposed guidelines, we analyzed a 
number of uncertainties, for example evaluating different potential 
spatial approaches to state compliance (i.e., state and regional) and 
in the estimated benefits of reducing carbon dioxide and other air 
pollutants. For a further discussion of key evaluations of uncertainty 
in the regulatory analyses for this proposed rulemaking, see the RIA 
included in the docket.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 
Information Collection Request (ICR) document prepared by the EPA has 
been assigned the EPA ICR number 2503.01.
    The information collection requirements are based on the 
recordkeeping and reporting burden associated with developing, 
implementing, and enforcing a state plan to limit CO2 
emissions from existing sources in the power sector. These 
recordkeeping and reporting requirements are specifically authorized by 
CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA 
pursuant to the recordkeeping and reporting requirements for which a 
claim of confidentiality is made is safeguarded according to agency 
policies set forth in 40 CFR part 2, subpart B.
    The annual burden for this collection of information for the states 
(averaged over the first 3 years following promulgation of this 
proposed action) is estimated to be a range of 316,217 hours at a total 
annual labor cost of $22,381,044, to 633,001 hours at a total annual 
labor cost of $44,802,243. The lower bound estimate reflects the 
assumption that some states already have energy efficiency and 
renewable energy programs in place. The higher bound estimate reflects 
the assumption that no states have energy efficiency and renewable 
energy programs in place. The total annual burden for the federal 
government (averaged over the first 3 years following promulgation of 
this proposed action) is estimated to be 53,300 hours at a total annual 
labor cost of $2,958,005. Burden means the total time, effort, or 
financial resources expended by persons to generate, maintain, retain, 
or disclose or provide information to or for a federal agency. This 
includes the time needed to review instructions; develop, acquire, 
install, and utilize technology and systems for the purposes of 
collecting, validating, and verifying information, processing and 
maintaining information, and disclosing and providing information; 
adjust the existing ways to comply with any previously applicable 
instructions and requirements; train personnel to be able to respond to 
a collection of information; search data sources; complete and review 
the collection of information; and transmit or otherwise disclose the 
information.
    An agency may not conduct or sponsor, and a person is not required 
to respond to a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
    To comment on the agency's need for this information, the accuracy 
of the provided burden estimates, and any suggested methods for 
minimizing respondent burden, the EPA has established a public docket 
for this rule, which includes this ICR, under Docket ID Number EPA-HQ-
OAR-2013-0602. Submit any comments related to the ICR to the EPA and to 
OMB. See the ADDRESSES section at the beginning of this notice for 
where to submit comments to the EPA. Send comments to OMB at the Office 
of Information and Regulatory Affairs, Office of Management and Budget, 
725 17th Street, NW., Washington, DC 20503, Attention: Desk Office for 
the EPA. Since OMB is required to make a decision concerning the ICR 
between 30 and 60 days after June 18, 2014, a comment to OMB is best 
assured of having its full effect if OMB receives it by July 18, 2014. 
The final rule will respond to any OMB or public comments on the 
information collection requirements contained in this proposal.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this rule on small 
entities, small entity is defined as:
    (1) A small business that is defined by the SBA's regulations at 13 
CFR 121.201 (for the electric power generation industry, the small 
business size standard is an ultimate parent entity with less than 750 
employees. The NAICS codes for the affected industry are in Table 22 
below);
    (2) A small governmental jurisdiction that is a government of a 
city, county, town, school district or special district with a 
population of less than 50,000; and
    (3) A small organization that is any not-for-profit enterprise 
which is independently owned and operated and is not dominant in its 
field.

                            Table 22--Potentially Regulated Categories and Entities a
----------------------------------------------------------------------------------------------------------------
                                   NAICS
            Category                Code               Examples of potentially regulated entities \a\
----------------------------------------------------------------------------------------------------------------
Industry.......................     221112  Fossil fuel electric power generating units.
State/Local Government.........   221112 b  Fossil fuel electric power generating units owned by municipalities.
----------------------------------------------------------------------------------------------------------------
\a\ Include NAICS categories for source categories that own and operate electric power generating units
  (includes boilers and stationary combined cycle combustion turbines).
\b\ State or local government-owned and operated establishments are classified according to the activity in
  which they are engaged.

    After considering the economic impacts of this proposed rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities.
    The proposed rule will not impose any requirements on small 
entities. Specifically, emission guidelines

[[Page 34947]]

established under CAA section 111(d) do not impose any requirements on 
regulated entities and, thus, will not have a significant economic 
impact upon a substantial number of small entities. After emission 
guidelines are promulgated, states establish standards on existing 
sources, and it is those state requirements that could potentially 
impact small entities. Our analysis here is consistent with the 
analysis of the analogous situation arising when the EPA establishes 
NAAQS, which do not impose any requirements on regulated entities. As 
here, any impact of a NAAQS on small entities would only arise when 
states take subsequent action to maintain and/or achieve the NAAQS 
through their state implementation plans. See American Trucking Assoc. 
v. EPA, 175 F.3d 1029, 1043-45 (D.C. Cir. 1999) (NAAQS do not have 
significant impacts upon small entities because NAAQS themselves impose 
no regulations upon small entities).
    Nevertheless, the EPA is aware that there is substantial interest 
in the proposed rule among small entities (municipal and rural electric 
cooperatives). As detailed in Section III.A of this preamble, the EPA 
has conducted an unprecedented amount of stakeholder outreach on 
setting emission guidelines for existing EGUs. While formulating the 
provisions of the proposed rule, the EPA considered the input provided 
over the course of the stakeholder outreach. Section III.B of this 
preamble describes the key messages from stakeholders. In addition, as 
described in the RFA section of the preamble to the proposed standards 
of performance for GHG emissions from new EGUs (79 FR 1499-1500, 
January 8, 2014), the EPA conducted outreach to representatives of 
small entities while formulating the provisions of the proposed 
standards. Although only new EGUs would be affected by those proposed 
standards, the outreach regarded planned actions for new and existing 
sources. We invite comments on all aspects of the proposal and its 
impacts, including potential impacts on small entities.

D. Unfunded Mandates Reform Act

    This proposed action does not contain a federal mandate that may 
result in expenditures of $100 million or more for state, local, and 
tribal governments, in the aggregate, or the private sector in any one 
year. Specifically, the emission guidelines proposed under CAA section 
111(d) do not impose any direct compliance requirements on regulated 
entities, apart from the requirement for states to develop state plans. 
The burden for states to develop state plans in the 3-year period 
following promulgation of the rule was estimated and is listed in 
Section IX B., above, but this burden is estimated to be below $100 
million in any one year. Thus, this proposed rule is not subject to the 
requirements of section 202 or section 205 of the Unfunded Mandates 
Reform Act (UMRA).
    This proposed rule is also not subject to the requirements of 
section 203 of UMRA because it contains no regulatory requirements that 
might significantly or uniquely affect small governments.
    In light of the interest among governmental entities, the EPA 
initiated consultations with governmental entities while formulating 
the provisions of the proposed standards for new EGUs. Although only 
new EGUs would be affected by those proposed standards, the outreach 
regarded planned actions for new and existing sources. As described in 
the UMRA discussion in the preamble to the proposed standards of 
performance for GHG emissions from new EGUs (79 FR 1500-1501, January 
8, 2014), the EPA consulted with the following 10 national 
organizations representing state and local elected officials: (1) 
National Governors Association; (2) National Conference of State 
Legislatures, (3) Council of State Governments, (4) National League of 
Cities, (5) U.S. Conference of Mayors, (6) National Association of 
Counties, (7) International City/County Management Association, 8) 
National Association of Towns and Townships, (9) County Executives of 
America, and 10) Environmental Council of States. On February 26, 2014, 
the EPA re-engaged with those governmental entities to provide a pre-
proposal update on the emission guidelines for existing EGUs and 
emission standards for modified and reconstructed EGUs.
    While formulating the provisions of these proposed emission 
guidelines, the EPA also considered the input provided over the course 
of the extensive stakeholder outreach conducted by the EPA (see 
Sections III.A. and III.B. of this preamble).

E. Executive Order 13132, Federalism

    Under Executive Order 13132, the EPA may not issue an action that 
has federalism implications, that imposes substantial direct compliance 
costs, and that is not required by statute, unless the federal 
government provides the funds necessary to pay the direct compliance 
costs incurred by state and local governments, or the EPA consults with 
state and local officials early in the process of developing the 
proposed action.
    The EPA has concluded that this action may have federalism 
implications, because it may impose substantial direct compliance costs 
on state or local governments, and the federal government will not 
provide the funds necessary to pay those costs. As discussed in the 
Supporting Statement found in the docket for this rulemaking, the 
development of state plans will entail many hours of staff time to 
develop and coordinate programs for compliance with the proposed rule, 
as well as time to work with state legislatures as appropriate, and 
develop a plan submittal.
    The EPA consulted with state and local officials early in the 
process of developing the proposed action to permit them to have 
meaningful and timely input into its development. As described in the 
Federalism discussion in the preamble to the proposed standards of 
performance for GHG emissions from new EGUs (79 FR 1501, January 8, 
2014), the EPA consulted with state and local officials in the process 
of developing the proposed standards for newly constructed EGUs. This 
outreach regarded planned actions for new, reconstructed, modified and 
existing sources. The EPA invited the following 10 national 
organizations representing state and local elected officials to a 
meeting on April 12, 2011, in Washington DC: (1) National Governors 
Association; (2) National Conference of State Legislatures, (3) Council 
of State Governments, (4) National League of Cities, (5) U.S. 
Conference of Mayors, (6) National Association of Counties, (7) 
International City/County Management Association, (8) National 
Association of Towns and Townships, (9) County Executives of America, 
and (10) Environmental Council of States. These 10 organizations 
representing elected state and local officials have been identified by 
the EPA as the ``Big 10'' organizations appropriate to contact for 
purpose of consultation with elected officials. On February 26, 2014, 
the EPA re-engaged with those governmental entities to provide a pre-
proposal update on the emission guidelines for existing EGUs and 
emission standards for modified and reconstructed EGUs. In addition, 
extensive stakeholder outreach conducted by the EPA allowed state 
leaders, including governors, environmental commissioners, energy 
officers, public utility commissioners, and air directors, 
opportunities to engage with EPA officials and provide input regarding 
reducing carbon pollution from power plants.
    A detailed Federalism Summary Impact Statement (FSIS) describing 
the

[[Page 34948]]

most pressing issues raised in pre-proposal and post-proposal comments 
will be forthcoming with the final rule, as required by section 6(b) of 
Executive Order 13132. In the spirit of Executive Order 13132, and 
consistent with the EPA's policy to promote communications between the 
EPA and state and local governments, the EPA specifically solicits 
comment on this proposed action from State and local officials.

F. Executive Order 13175, Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). It would not 
impose substantial direct compliance costs on tribal governments that 
have affected EGUs located in their area of Indian country. Tribes are 
not required to, but may, develop or adopt CAA programs. Tribes are not 
required to develop plans to implement the guidelines under CAA section 
111(d) for affected EGUs. To the extent that a tribal government seeks 
and attains treatment in a manner similar to a state (TAS) status for 
that purpose and is delegated authority for air quality planning 
purposes, these proposed emission guidelines would require that 
planning requirements be met and emission management implementation 
plans be executed by the tribes. The EPA is aware of three coal-fired 
EGUs and one natural gas-fired EGU located in Indian country but is not 
aware of any affected EGUs that are owned or operated by tribal 
entities. The EPA notes that this proposal does not directly impose 
specific requirements on EGU sources, including those located in Indian 
country, such as the three coal-fired EGUs and one natural gas-fired 
EGU, but provides guidance to any tribe with delegated authority to 
address CO2 emissions from EGU sources found subject to 
section 111(d) of the CAA. Thus, Executive Order 13175 does not apply 
to this action.
    The EPA conducted outreach to tribal environmental staff and 
offered consultation with tribal officials in developing this action. 
Because the EPA is aware of tribal interest in this proposed rule, 
prior to the April 13, 2012 proposal (77 FR 22392-22441), the EPA 
offered consultation with tribal officials early in the process of 
developing the proposed regulation to permit them to have meaningful 
and timely input into its development. The EPA's consultation regarded 
planned actions for new and existing sources. In addition, on April 15, 
2014, prior to proposal, the EPA met with Navajo Energy Development 
Group officials. For this proposed action for existing EGUs, a tribe 
that has one or more affected EGUs located in its area of Indian 
country \346\ would have the opportunity, but not the obligation, to 
establish a CO2 performance standard and a CAA section 
111(d) plan for its area of Indian country.
---------------------------------------------------------------------------

    \346\ The EPA is aware of at least four affected EGUs located in 
Indian country: Two on Navajo lands, the Navajo Generating Station 
and the Four Corners Generating Station; one on Ute lands, the 
Bonanza Generating Station; and one on Fort Mojave lands, the South 
Point Energy Center. The affected EGUs at the first three plants are 
coal-fired EGUs. The fourth affected EGU is an NGCC facility.
---------------------------------------------------------------------------

    Consultation letters were sent to 584 tribal leaders. The letters 
provided information regarding the EPA's development of both the NSPS 
and emission guidelines for fossil fuel-fired EGUs and offered 
consultation. No tribes have requested consultation. Tribes were 
invited to participate in the national informational webinar held 
August 27, 2013. In addition, a consultation/outreach meeting was held 
on September 9, 2013, with tribal representatives from some of the 584 
tribes. The EPA also met with tribal environmental staff via National 
Tribal Air Association teleconferences on July 25, 2013, and December 
19, 2013. In those teleconferences, the EPA provided background 
information on the GHG emission guidelines to be developed and a 
summary of issues being explored by the agency. Tribes have expressed 
varied points of view. Some tribes raised concerns about the impacts of 
the regulations on EGUs and the subsequent impact on jobs and revenue 
for their tribes. Other tribes expressed concern about the impact the 
regulations would have on the cost of water to their communities as a 
result of increased costs to the EGU that provide energy to transport 
the water to the tribes. Other tribes raised concerns about the impacts 
of climate change on their communities, resources, life ways and 
hunting and treaty rights. The tribes were also interested in the scope 
of the guidelines being considered by the agency (e.g., over what time 
period, relationship to state and multi-state plans) and how tribes 
will participate in these planning activities. In addition, the EPA 
held a series of listening sessions prior to development of this 
proposed action. In 2013, tribes participated in a session with the 
state agencies, as well as a separate session with tribes.
    During the public comment period for this proposal, the EPA will 
hold meetings with tribal environmental staff to inform them of the 
content of this proposal, as well as offer further consultation with 
tribal elected officials where it is appropriate. We specifically 
solicit comment from tribal officials on this proposed rule.

G. Executive Order 13045, Protection of Children From Environmental 
Health Risks and Safety Risks

    The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as 
applying to those regulatory actions that concern health or safety 
risks, such that the analysis required under section 5-501 of the Order 
has the potential to influence the regulation. This action is not 
subject to EO 13045 because it does not involve decisions on 
environmental health or safety risks that may disproportionately affect 
children. The EPA believes that the CO2 emission reductions 
resulting from implementation of the proposed guidelines, as well as 
substantial ozone and PM2.5 emission reductions as a co-
benefit, would further improve children's health.

H. Executive Order 13211, Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    Executive Order 13211 (66 FR 28355; May 22, 2001) requires the EPA 
to prepare and submit a Statement of Energy Effects to the 
Administrator of the Office of Information and Regulatory Affairs, OMB, 
for actions identified as ``significant energy actions.'' This action, 
which is a significant regulatory action under EO 12866, is likely to 
have a significant effect on the supply, distribution, or use of 
energy. We have prepared a Statement of Energy Effects for this action 
as follows. We estimate a 4 to 7 percent increase in retail electricity 
prices, on average, across the contiguous U.S. in 2020, and a 16 to 22 
percent reduction in coal-fired electricity generation as a result of 
this rule. The EPA projects that electric power sector delivered 
natural gas prices will increase by about 8 to 12 percent in 2020. For 
more information on the estimated energy effects, please refer to the 
economic impact analysis for this proposal. The analysis is available 
in the RIA, which is in the public docket.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the 
EPA to use Voluntary Census Standards (VCS) in its regulatory and 
procurement activities unless to do so would be inconsistent with 
applicable law or

[[Page 34949]]

otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, business practices) developed or adopted by one or more 
voluntary consensus bodies. The NTTAA directs the EPA to provide 
Congress, through annual reports to OMB, with explanations when an 
agency does not use available and applicable VCS. This proposed 
rulemaking does not involve technical standards.
    The EPA welcomes comments on this aspect of the proposed rulemaking 
and specifically invites the public to identify potentially-applicable 
VCS and to explain why such standards should be used in this action.

J. Executive Order 12898: Federal Actions to Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies and activities on minority populations and low-income 
populations in the U.S.
    Section II.A of this preamble summarizes the public health and 
welfare impacts from GHG emissions that were detailed in the 2009 
Endangerment Finding under CAA section 202(a)(1).\347\ As part of the 
Endangerment Finding, the Administrator considered climate change risks 
to minority or low-income populations, finding that certain parts of 
the population may be especially vulnerable based on their 
circumstances. These include the poor, the elderly, the very young, 
those already in poor health, the disabled, those living alone, and/or 
indigenous populations dependent on one or a few resources. The 
Administrator placed weight on the fact that certain groups, including 
children, the elderly, and the poor, are most vulnerable to climate-
related health effects.
---------------------------------------------------------------------------

    \347\ ``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) (``Endangerment Finding'').
---------------------------------------------------------------------------

    Strong scientific evidence that the potential impacts of climate 
change raise environmental justice issues is found in the major 
assessment reports by the U.S. Global Change Research Program (USGCRP), 
the Intergovernmental Panel on Climate Change (IPCC), and the National 
Research Council (NRC) of the National Academies, summarized in the 
record for the Endangerment Finding. Their conclusions include that 
poor communities can be especially vulnerable to climate change impacts 
because they tend to have more limited adaptive capacities and are more 
dependent on climate-sensitive resources such as local water and food 
supplies. In addition, Native American tribal communities possess 
unique vulnerabilities to climate change, particularly those on 
established reservations that are restricted to reservation boundaries 
and therefore have limited relocation options. Tribal communities whose 
health, economic well-being, and cultural traditions depend upon the 
natural environment will likely be affected by the degradation of 
ecosystem goods and services associated with climate change. Southwest 
native cultures are especially vulnerable to water quality and 
availability impacts. Native Alaskan communities are likely to 
experience disruptive impacts, including shifts in the range or 
abundance of wild species crucial to their livelihoods and well-being. 
The most recent assessments continue to strengthen scientific 
understanding of climate change risks to minority and low-income 
populations.
    This proposed rule would limit GHG emissions by establishing 
CO2 emission guidelines for existing fossil fuel-fired EGUs. 
In addition to reducing CO2 emissions, implementing the 
proposed rule would reduce other emissions from EGUs that become 
dispatched less frequently due to their relatively low energy 
efficiency. These emission reductions will include SO2 and 
NOx, which form ambient PM2.5 and ozone in the atmosphere, 
and hazardous air pollutants (HAP), such as mercury and hydrochloric 
acid. In the final rule revising the annual PM2.5 
NAAQS,\348\ the EPA identified persons with lower socioeconomic status 
as an at-risk population for experiencing adverse health effects 
related to PM exposures. Persons with lower socioeconomic status have 
been generally found to have a higher prevalence of pre-existing 
diseases, limited access to medical treatment, and increased 
nutritional deficiencies, which can increase this population's risk to 
PM-related and ozone-related effects.\349\ Therefore, in areas where 
this rulemaking reduces exposure to PM2.5, ozone, and 
methylmercury, persons with low socioeconomic status would also 
benefit. The RIA for this rulemaking, included in the docket for this 
rulemaking, provides additional information regarding the health and 
ecosystem effects associated with these emission reductions.
---------------------------------------------------------------------------

    \348\ ``National Ambient Air Quality Standards for Particulate 
Matter, Final Rule,'' 78 FR 3086 (Jan. 15, 2013).
    \349\ U.S. Environmental Protection Agency (U.S. EPA). 2009. 
Integrated Science Assessment for Particulate Matter (Final Report). 
EPA-600-R-08-139F. National Center for Environmental Assessment--RTP 
Division. December. Available on the Internet at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
---------------------------------------------------------------------------

    While there will be many locations with improved air quality for 
PM2.5, ozone, and HAP, there may also be EGUs whose 
emissions of one or more of these pollutants or their precursors 
increase as a result of the proposed emission guidelines for existing 
fossil fuel-fired EGUs. This may occur at EGUs that become dispatched 
more intensively than in the past because they become more energy 
efficient. The EPA has considered the potential for such increases and 
the environmental justice implications of such increases.
    As we noted in the NSR discussion in this preamble, as part of a 
state's CAA section 111(d) plan, the state may require an affected EGU 
to undertake a physical or operational changes to improve the unit's 
efficiency that result in an increase in the unit's dispatch and an 
increase in the unit's annual emissions of GHGs and/or other regulated 
pollutants. A state can take steps to avoid increased utilization of 
particular EGUs and thus avoid any significant increases in emissions 
including emissions of other regulated pollutants whose environmental 
effects would be more localized around the affected EGU. To the extent 
that states take this path, there would be no new environmental justice 
concerns in the areas near such EGUs. For any EGUs that make 
modifications that do trigger NSR permitting, the applicable local, 
state, or federal permitting program will ensure that there are no new 
NAAQS violations and that no existing NAAQS violations are made worse. 
For those EGUs in a permitting situation for which the EPA is the 
permit reviewing authority, the EPA will consider environmental justice 
issues as required by Executive Order 12898.
    In addition to some EGUs possibly being required by a state to make 
modifications for increased energy efficiency, another effect of the 
proposed CO2 emission guidelines for existing fossil fuel-
fired EGUs would be

[[Page 34950]]

increased utilization of other, unmodified EGUs with relatively low GHG 
emissions per unit of electrical output, in particular high efficiency 
gas-fired EGUs. Because such EGUs would not have been modified 
physically nor changed their method of operation, they would not be 
subject to review in the NSR permitting program. Such plants would have 
more hours in the year in which they operate and emit pollutants, 
including pollutants whose environmental effects if any would be 
localized rather than global as is the case with GHG emissions. Changes 
in utilization already occur now as demands for and sources of 
electrical energy evolve, but the proposed CO2 emission 
guidelines for existing fossil fuel-fired EGUs can be expected to cause 
more such changes. Because gas-fired EGUs emit essentially no mercury, 
increased utilization would not increase methylmercury concentrations 
in their vicinities. Increased utilization generally would not cause 
higher peak concentrations of PM2.5, NOx, or ozone around 
such EGUs than is already occurring because peak hourly or daily 
emissions generally would not change, but increased utilization may 
make periods of relatively high concentrations more frequent. It should 
be noted that the gas-fired sources that are likely to become 
dispatched more frequently than at present have very low emissions of 
primary particulate matter, SO2 and HAP per unit of 
electrical output, such that local (or regional) air quality for these 
pollutants is likely to be affected very little. For natural gas-fired 
EGUS, the EPA found that regulation of HAP emissions ``is not 
appropriate or necessary because the impacts due to HAP emissions from 
such units are negligible based on the results of the study documented 
in the utility RTC.'' \350\ In studies done by DOE/NETL comparing cost 
and performance of coal- and NG-fired generation, they assumed 
SO2, PM (and Hg) emissions to be ``negligible.'' Their 
studies predict NOx emissions from a NGCC unit to be approximately 10 
times lower than a subcritical or supercritical coal-fired boiler. Many 
are also very well controlled for emission of NOx through the 
application of after combustion controls such as selective catalytic 
reduction, although not all gas-fired sources are so equipped. 
Depending on the specificity of the state CAA section 111(d) plan, the 
state may be able to predict which EGUs and communities may be in this 
type of situation and to address any concerns about localized 
NO2 concentrations in the design of the CAA section 111(d) 
program, or separately from the CAA section 111(d) program but before 
its implementation. In any case, existing tracking systems will allow 
states and the EPA to be aware of the EGUs whose utilization has 
increased most significantly, and thus to be able to prioritize our 
efforts to assess whether air quality has changed in the communities in 
the vicinity of such EGUs. There are multiple mechanisms in the CAA to 
address situations in which air quality has degraded significantly. In 
conclusion, this proposed rule would result in regional and national 
pollutant reductions; however, there likely would also be some 
locations with more times during the year of relatively higher 
concentrations of pollutants with potential for effects on localized 
communities than would be experienced in the absence of the proposed 
rule. The EPA cannot exactly predict how emissions from specific EGUs 
would change as an outcome of the proposed rule due to the state-led 
implementation. Therefore, the EPA has concluded that it is not 
practicable to determine whether there would be disproportionately high 
and adverse human health or environmental effects on minority, low 
income, or indigenous populations from this proposed rule.
---------------------------------------------------------------------------

    \350\ 65 FR 79831.
---------------------------------------------------------------------------

    In order to provide opportunities for meaningful involvement early 
on in the rule making process, the EPA has hosted webinars and 
conference calls on August 27, 2013, and September 9, 2013, on the 
proposed rule specifically for environmental justice communities and 
has taken all comments and suggestions into consideration in the design 
of the emission guidelines.
    The public is invited to submit comments or identify peer-reviewed 
studies and data that assess effects of exposure to the pollutants 
addressed by this proposal.

XII. Statutory Authority

    The statutory authority for this action is provided by sections 
111, 301, 302, and 307(d)(1)(V) of the CAA, as amended (42 U.S.C. 7411, 
7601, 7602, 7607(d)(1)(V)). This action is also subject to section 
307(d) of the CAA (42 U.S.C. 7607(d)).

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Intergovernmental relations, Reporting and 
recordkeeping requirements.

    Dated: June 2, 2014.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part 
60 of the Code of the Federal Regulations is proposed to be amended as 
follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for Part 60 continues to read as follows:

    Authority: 42 U.S.C. 7401 et seq.

0
2. Section 60.27 is amended by revising paragraph (b) to read as 
follows:

Sec.  60.27  Actions by the Administrator.

* * * * *
    (b) After receipt of a plan or plan revision, the Administrator 
will propose the plan or revision for approval or disapproval. The 
Administrator will, within four months after the date required for 
submission of a plan or plan revision, approve or disapprove such plan 
or revision or each portion thereof, except as provided in Sec.  
60.5715.
* * * * *
0
3. Add subpart UUUU to read as follows:

Subpart UUUU: Emission Guidelines for Greenhouse Gas Emissions and 
Compliance Times for Electric Utility Generating Units

Sec.

Introduction

60.5700 What is the purpose of this subpart?
60.5705 What pollutants are regulated by this subpart?
60.5710 Am I affected by this subpart?
60.5715 What is the review and approval process for my state plan?
60.5720 What if I do not submit a plan or my plan is not approvable?
60.5725 In lieu of a state plan submittal, are there other 
acceptable option(s) for a state to meet its section 111(d) 
obligations?
60.5730 Is there an approval process for a negative declaration 
letter?
60.5735 What authorities will not be delegated to state, local, or 
tribal agencies?

State Plan

60.5740 What must I include in my state plan?
60.5745 Can I work with other states to develop a multi-state plan?
60.5750 Can I include existing requirements, programs, and measures 
in my state plan?
60.5755 What are the timing requirements for submitting my state 
plan?
60.5760 What must I include in an initial submittal in lieu of a 
complete state plan?

[[Page 34951]]

60.5765 What are the state rate-based CO2 emission 
performance goals?
60.5770 What is the procedure for converting my state rate-based 
CO2 emission performance goal to a mass-based 
CO2 emissions performance goal?
60.5775 What schedules, performance periods, and compliance periods 
must I include in my state plan?
60.5780 What emission standards and enforcing measures must I 
include in my plan?
60.5785 What is the procedure for revising my state plan?

Applicability of State Plans to Affected EGUs

60.5790 Does this subpart directly affect EGU owners and operators 
in my state?
60.5795 What affected EGUs must I address in my state plan?
60.5800 What affected EGUs are exempt from my state plan?
60.5805 What applicable monitoring, recordkeeping, and reporting 
requirements do I need to include in my state plan for affected 
EGUs?

Recordkeeping and Reporting Requirements

60.5810 What are my state recordkeeping requirements?
60.5815 What are my state reporting requirements?

Definitions

60.5820 What definitions apply to this subpart?
Table 1 to Subpart UUUU of Part 60--State Rate-based CO2 
Emission Performance Goals (Pounds of CO2 Per Net MWh)

Introduction

Sec.  60.5700  What is the purpose of this subpart?

    This subpart establishes emission guidelines and approval criteria 
for state plans that establish emission standards limiting the control 
of greenhouse gas emissions from an affected steam generating unit, 
integrated gasification combined cycle (IGCC), or stationary combustion 
turbine. An affected steam generating unit, IGCC, or stationary 
combustion turbine shall, for the purposes of this subpart, be referred 
to as an affected EGU. These emission guidelines are developed in 
accordance with sections 111(d) of the Clean Air Act and subpart B of 
this part. To the extent any requirement of this subpart is 
inconsistent with the requirements of subparts A or B of this part, the 
requirements of this subpart will apply.

Sec.  60.5705  What pollutants are regulated by this subpart?

    (a) The pollutants regulated by this subpart are greenhouse gases.
    (b) The greenhouse gas regulated by this subpart is carbon dioxide 
(CO2).

Sec.  60.5710  Am I affected by this subpart?

    If you are the Administrator of an air quality program in a state 
with one or more affected EGUs that commenced construction on or before 
January 8, 2014, you must submit a state plan to the U.S. Environmental 
Protection Agency (EPA) that implements the emission guidelines 
contained in this subpart. You must submit a negative declaration 
letter in place of the state plan if there are no affected EGUs for 
which construction commenced on or before January 8, 2014 in your 
state.

Sec.  60.5715  What is the review and approval process for my state 
plan?

    The EPA will review your state plan according to Sec.  60.27 except 
that under Sec.  60.27(b) the Administrator will have twelve months 
after the date required for submission of a plan or plan revision to 
approve or disapprove such plan or revision or each portion thereof. If 
you submit a request for extension under Sec.  60.5760(a) in lieu of a 
complete state plan the EPA will follow the procedure in Sec.  
60.5760(b).

Sec.  60.5720  What if I do not submit a plan or my plan is not 
approvable?

    If you do not submit an approvable state plan the EPA will develop 
a Federal plan for your state according to Sec.  60.27 to implement the 
emission guidelines contained in this subpart. Owners and operators of 
affected entities not covered by an approved state plan must comply 
with a Federal plan implemented by the EPA for the state. The Federal 
plan is an interim action and will be automatically withdrawn when your 
state plan is approved.

Sec.  60.5725  In lieu of a state plan submittal, are there other 
acceptable option(s) for a state to meet its section 111(d) 
obligations?

    A state may meet its CAA section 111(d) obligations only by 
submitting a complete state plan or a negative declaration letter (if 
applicable).

Sec.  60.5730  Is there an approval process for a negative declaration 
letter?

    No. The EPA has no formal review process for negative declaration 
letters. Once your negative declaration letter has been received, the 
EPA will place a copy in the public docket and publish a notice in the 
Federal Register. If, at a later date, an affected EGU for which 
construction commenced on or before January 8, 2014 is found in your 
state, a Federal plan implementing the emission guidelines contained in 
this subpart would automatically apply to that affected EGU until your 
state plan is approved.

Sec.  60.5735  What authorities will not be delegated to state, local, 
or tribal agencies?

    The authorities that will not be delegated to State, local, or 
tribal agencies are specified in paragraph (a) of this section.
    (a) Approval of alternatives, not already approved by this subpart, 
to the emissions performance goals in Table 1 to this subpart 
established under Sec.  60.5755.
    (b) [Reserved]

State Plan

Sec.  60.5740  What must I include in my state plan?

    (a) You must include the elements described in paragraphs (a)(1) 
through (11) of this section in your state plan.
    (1) Identification of affected entities, including an inventory of 
CO2 emissions from affected EGUs during the most recent 
calendar year prior to the submission of the plan for which data is 
available.
    (2) A description of plan approach and the geographic scope of a 
plan (state or multi-state), including, if relevant, identification of 
multi-state plan participants and geographic boundaries related to plan 
elements.
    (3) Identification of the state emission performance level for 
affected entities that will be achieved through implementation of the 
plan.
    (i) The plan must specify the average emissions performance that 
the plan will achieve for the following periods:
    (A) The 10 year interim plan performance period of 2020 through 
2029.
    (B) The single projection year of 2030.
    (ii) The identified emission performance level for each plan 
performance period in paragraph (a)(3)(i) of this section must be 
equivalent to or better than the levels of the rate-based 
CO2 emission performance goals in Table 1 of this Subpart 
for affected entities in your state. The emission performance levels 
may be in either a rate-based form or a mass based form which is 
calculated according to Sec.  60.5770. The CO2 emission 
performance level specified must include either of the following as 
applicable:
    (A) For a rate-based CO2 emission performance level, the 
identified level must represent the CO2 emissions rate, in 
pounds of CO2 per MWh of net energy output that will be 
achieved by affected entities.
    (B) For a mass-based CO2 emission performance level, the 
identified level of performance must represent the total tons of 
CO2 that will be emitted by affected entities during each 
plan performance period.

[[Page 34952]]

    (iii) For the interim plan performance period you must identify the 
emission performance levels anticipated under the plan during each year 
2020 through 2029.
    (4) A demonstration that the plan is projected to achieve each of 
the state's emission performance levels for affected entities according 
to paragraph (a)(3) of this section.
    (5) Identification of emission standards for each affected entity, 
compliance periods for each emission standard, and demonstration that 
the emission standards are, when taken together, sufficiently 
protective to meet the state emissions performance level.
    (6) A demonstration that each emission standard is quantifiable, 
non-duplicative, permanent, verifiable, and enforceable with respect to 
an affected entity.
    (7) If your state plan does not require achievement of the full 
level of required emission performance, and the identified interim 
increments of performance in paragraph (a)(3)(iii) of this section, 
through emission limits on EGUs, the plan must specify the following:
    (i) Program implementation milestones (e.g., start of an end-use 
energy efficiency program, retirement of an affected EGU, or increase 
in portfolio requirements under a renewable portfolio standard) and 
milestone dates that are appropriate to the requirements, programs, and 
measures included in the plan.
    (ii) Corrective measures that will be implemented in the event that 
the comparison required by Sec.  60.5815(b) of projected versus actual 
emissions performance of affected entities shows that actual emissions 
performance is greater than 10 percent in excess to projected plan 
performance for the period described in Sec.  60.5775(c)(1), and a 
process and schedule for implementing such corrective measures.
    (8) Identification of applicable monitoring, reporting, and 
recordkeeping requirements for each affected entity. If applicable, 
these requirements must be consistent with the requirements specified 
in Sec.  60.5810.
    (9) Description of the process, contents, and schedule for annual 
state reporting to the EPA about plan implementation and progress 
including information required under Sec.  60.5815.
    (10) Certification that the hearing on the state plan was held, a 
list of witnesses and their organizational affiliations, if any, 
appearing at the hearing, and a brief written summary of each 
presentation or written submission.
    (11) Supporting material including:
    (i) Materials demonstrating the state's legal authority to carry 
out each component of its plan, including emissions standards;
    (ii) Materials supporting the projected emissions performance level 
that will be achieved by affected entities under the plan, according to 
paragraph (a)(4) of this section;
    (iii) Materials supporting the projected mass-based emission 
performance goal, calculated pursuant to Sec.  60.5770, if applicable; 
and
    (iv) Materials necessary to support evaluation of the plan by the 
EPA.
    (b) You must follow the requirements of subpart B of this part 
(Adoption and Submittal of state plans for Designated Facilities) and 
demonstrate that they were met in your state plan.

Sec.  60.5745  Can I work with other states to develop a multi-state 
plan?

    A multi-state plan may be submitted, provided it is signed by 
authorized officials for each of the states participating in the multi-
state plan. In this instance, the joint submittal will have the same 
legal effect as an individual submittal for each participating state. A 
multi-state plan will include all the required elements for a single-
state plan specified in Sec.  60.5740(a). A multi-state plan, if 
submitted by a state, must:
    (a) Demonstrate CO2 emission performance jointly for all 
affected entities in all states participating in the multi-state plan, 
as follows:
    (1) For states demonstrating performance based on the 
CO2 emission rate, the level of performance identified in 
the multi-state plan pursuant to Sec.  60.5740(a)(3) will be a weighted 
(by net energy output) average lb CO2/MWh emission rate to 
be achieved by all affected EGUs in the multi-state area during the 
plan performance period; or
    (2) For states demonstrating performance based on mass 
CO2 emissions, the level of performance identified in the 
multi-state plan pursuant to 60.5740(a)(3) will be total CO2 
emissions by all affected EGUs in the multi-state area during the plan 
performance period.
    (b) Assign among states, according to a formula in the multi-state 
plan, avoided CO2 emissions resulting from emission 
standards contained in the plan, from affected entities in states 
participating in the multi-state plan.

Sec.  60.5750  Can I include existing requirements, programs, and 
measures in my state plan?

    (a) Yes, you may include existing requirements, programs and 
measures in your plan according to paragraphs (b) through (d) of this 
section.
    (b) Existing state programs, requirements, and measures, may 
qualify for use in demonstrating that a state plan achieves the 
required level of emission performance specified in a plan, according 
to Sec.  60.5740(a)(3).
    (c) Existing state programs, requirements, and measures, may 
qualify for use in projecting that a state plan will achieve the 
required level of emission performance specified in a plan, according 
to Sec.  60.5740(a)(4).
    (d) Emission impacts of existing programs, requirements, and 
measures that occur during a plan performance period may be recognized 
in meeting or projecting CO2 emission performance by 
affected EGUs according to Sec.  60.5740(a)(3) and (4), as long as they 
meet the following requirements:
    (1) Actions taken pursuant to an existing state program, 
requirement, or measure, such as compliance with a regulatory 
obligation or initiation of an action related to a program or measure, 
must occur after June 18, 2014; and
    (2) The existing state program, requirement, or measure, and any 
related actions taken pursuant to such program, requirement, or 
measure, meet the applicable requirements pursuant to Sec.  60.5740(a) 
and Sec.  60.5780.

Sec.  60.5755  What are the timing requirements for submitting my state 
plan?

    (a) You must submit your state plan with the information in Sec.  
60.5740 by June 30, 2016 unless you are submitting a request for 
extension according to paragraphs (b) or (c) of this section.
    (b) For a state seeking a one year extension for a complete plan 
submittal you must include the information in Sec.  60.5760(a) in a 
submittal by June 30, 2016 to receive an extension to submit your 
complete state plan by June 30, 2017.
    (c) For states in a multi-state plan seeking a two year extension 
for a complete plan submittal you must include the information in Sec.  
60.5760(a) in a submittal by June 30, 2016 to receive an extension to 
submit your complete multi-state plan by June 30, 2018.

Sec.  60.5760  What must I include in an initial submittal in lieu of a 
complete state plan?

    (a) You must include the following required elements in an initial 
submittal in lieu of a complete state plan:
    (1) A description of the plan approach and progress made to date in 
developing each of the plan elements in Sec.  60.5740;
    (2) An initial projection of the level of emission performance that 
will be achieved under the complete plan;
    (3) A commitment by the state to maintain existing state programs 
and

[[Page 34953]]

measures that limit or avoid CO2 emissions from affected 
entities (e.g., renewable energy standards, unit-specific limits on 
operation or fuel utilization), which must at a minimum apply during 
the interim period prior to state submission and EPA approval of a 
complete plan, and must continue to apply in lieu of a complete plan if 
one is ultimately not submitted and approved;
    (4) Justification of why additional time is needed to submit a 
complete plan;
    (5) A comprehensive roadmap for completing the plan, including 
process, analytical methods and schedule (including milestones) 
specifying when all necessary plan components will be complete (e.g., 
projection of emission performance; implementing legislation, 
regulations and agreements; necessary approvals);
    (6) Identification of existing and future programs, requirements, 
and measures the state intends to include in the plan;
    (7) If a multi-state plan is being developed, an executed 
agreement(s) with other states (e.g., MOU) participating in the 
development of the multistate plan; and
    (8) A commitment to submit a complete plan by June 30, 2017, for a 
single-state plan, or June 30, 2018, for a multi-state plan, and 
actions the state will take to show progress in addressing incomplete 
plan components prior to submittal of the complete plan.
    (9) A description of all steps the state has already taken in 
furtherance of actions needed to finalize a complete plan.
    (10) Evidence of an opportunity for public comment and a response 
to any significant comments received on issues relating to the 
approvability of the initial plan.
    (b) You must submit either a complete state plan or an initial 
submittal by June 30, 2016. Where an initial submittal is submitted in 
lieu of a complete state plan the due date of a complete state plan 
will be June 30, 2017, for a single-state plan, or June 30, 2018, for a 
multi-state plan unless a state is notified within 60 days of the EPA 
receiving the initial submittal in paragraph (a) of this section that 
the EPA finds the initial submittal does not meet the requirements 
listed in paragraph (a) of this section.

Sec.  60.5765  What are the state rate-based CO2 emissions 
performance goals?

    (a) The annual average state rate-based CO2 emission 
performance goals for the interim performance periods of 2020 through 
2029, and the final 2030 and thereafter period are respectively listed 
in Table 1 of this Subpart. The state rate-based CO2 
emission performance goal may be converted to a mass-based emission 
performance goal according to Sec.  60.5770.
    (b)[Reserved]

Sec.  60.5770  What is the procedure for converting my state rate-based 
CO2 emission performance goal to a mass-based CO2 
emissions performance goal?

    (a) If the plan adopts a mass-based goal according to Sec.  
60.5740(a)(3), the plan must identify the mass-based goal, in tons of 
CO2 emitted by affected EGUs over the plan performance 
period, and include a description of the analytic process, tools, 
methods, and assumptions used to convert from the rate-based goal for 
the state identified in Table 1 of this Subpart to an equivalent mass-
based goal. The conversion process must include following requirements:
    (1) The process, tools, methods, and assumptions used in the 
conversion of the rate-based goal must be included in your state plan 
according to Sec.  60.5740(a)(11).
    (2) The material supporting the conversion of the rate-based goal, 
including results, data, and descriptions, must be include in a state 
plan according to Sec.  60.5740(a)(11).
    (3) The conversion must represent the tons of CO2 
emissions that are projected to be emitted by affected EGUs, in the 
absence of emission standards contained in the plan, if the affected 
EGUs were to perform at an average lb CO2/MWh rate equal to 
the rate-based goal for the state identified in Table 1 of this 
Subpart.
    (b) [Reserved]

Sec.  60.5775  What schedules, performance periods, and compliance 
periods must I include in my state plan?

    (a) Your state plan must include a schedule of compliance for each 
affected entity regulated under the plan.
    (b) Your state plan must include compliance periods, as defined in 
section Sec.  60.5820, for each affected entity regulated under the 
plan.
    (c) For the interim performance period of 2020-2029 your state must 
meet the requirements in paragraphs (c)(1) and (2) of this section.
    (1) Your state plan must include increments of emissions 
performance (either rate based or mass based with respect to the 
interim level of performance set in the state plan) within the interim 
performance period for every 2-rolling calendar years starting January 
1, 2020 and ending in 2028 (i.e. 2020-2021, 2021-2022, 2022-2023, 
etc.), unless other periods that ensure regular progress in the interim 
period are approved by the Administrator.
    (2) At the end of 2029 your state must meet the interim emissions 
performance level specified in Sec.  60.5740(a)(3) as averaged over the 
plan performance period 2020-2029.
    (d) During the final performance period, 2030 and thereafter, your 
state must meet the final emission performance level specified in Sec.  
60.5740(a)(3) on a 3-calendar year rolling average starting January 1, 
2030 (i.e., 2030-2032, 2031-2033, 2032-2034, etc.).
    (e) You must include the provisions of your state plan which 
demonstrate progress and compliance with the requirements in this Sec.  
60.5775 and Sec.  60.5740 in your state's annual report required in 
Sec.  60.5815.

Sec.  60.5780  What emission standards and enforcing measures must I 
include in my plan?

    (a) Your state plan shall include emission standard(s) that are 
quantifiable, verifiable, non-duplicative, permanent, and enforceable 
with respect to each affected entity. The plan shall include the 
methods by which each emission standard meets each of the following 
requirements in paragraphs (b) through (f) of this section.
    (b) An emission standard is quantifiable with respect to an 
affected entity if it can be reliably measured, in a manner that can be 
replicated.
    (c) An emission standard is verifiable with respect to an affected 
entity if adequate monitoring, recordkeeping and reporting requirements 
are in place to enable the state and the Administrator to independently 
evaluate, measure, and verify compliance with the emission standard.
    (d) An emission standard is non-duplicative with respect to an 
affected entity if it is not already incorporated as an emission 
standard in another state plan unless incorporated in multi-state plan.
    (e) An emission standard is permanent with respect to an affected 
entity if the emission standard must be met for each compliance period, 
or unless it is replaced by another emission standard in an approved 
plan revision, or the state demonstrates in an approved plan revision 
that the emission reductions from the emission standard are no longer 
necessary for the state to meet its state level of performance.
    (f) An emission standard is enforceable against an affected entity 
if:
    (1) A technically accurate limitation or requirement and the time 
period for

[[Page 34954]]

the limitation or requirement is specified;
    (2) Compliance requirements are clearly defined;
    (3) The affected entities responsible for compliance and liable for 
violations can be identified;
    (4) Each compliance activity or measure is enforceable as a 
practical matter; and
    (5) The Administrator and the state maintain the ability to enforce 
violations and secure appropriate corrective actions pursuant to 
sections 113(a) through (h) of the Act.

Sec.  60.5785  What is the procedure for revising my state plan?

    State plans can only be revised with approval by the Administrator. 
If one (or more) of the elements of the state plan set in Sec.  60.5740 
require revision with respect to reaching the emission performance goal 
set in Sec.  60.5765 a request may be submitted to the Administrator 
indicating the proposed corrections to the state plan to ensure the 
emission performance goal is met.

Applicability of State Plans to Affected EGUs

Sec.  60.5790  Does this subpart directly affect EGU owners and 
operators in my state?

    (a) This subpart does not directly affect EGU owners and operators 
in your state. However, EGU owners and operators must comply with the 
state plan that a state develops to implement the emission guidelines 
contained in this subpart.
    (b) If a state does not submit an approvable plan or initial 
submittal to implement and enforce the emission guidelines contained in 
this subpart by June 30, 2016, the EPA will implement and enforce a 
Federal plan, as provided in Sec.  60.5740, to ensure that each 
affected EGU within the state that commenced construction on or before 
January 8, 2014 reaches compliance with all the provisions of this 
subpart.

Sec.  60.5795  What affected EGUs must I address in my state plan?

    (a) The EGUs that must be addressed by your state plan are any 
affected steam generating unit, IGCC, or stationary combustion turbine 
that commences construction on or before January 8, 2014.
    (b) An affected EGU is a steam generating unit, integrated 
gasification combined cycle (IGCC), or stationary combustion turbine 
that meets the relevant applicability conditions specified in paragraph 
(b)(1) or (2) of this section.
    (1) A steam generating unit or IGCC that has a base load rating 
greater than 73 MW (250 MMBtu/h) heat input of fossil fuel (either 
alone or in combination with any other fuel) and was constructed for 
the purpose of supplying one-third or more of its potential electric 
output and more than 219,000 MWh net-electric output to a utility 
distribution system on an annual basis.
    (2) A stationary combustion turbine that has a base load rating 
greater than 73 MW (250 MMBtu/h), was constructed for the purpose of 
supplying, and supplies, one-third or more of its potential electric 
output and more than 219,000 MWh net-electrical output to a utility 
distribution system on a 3-year rolling average basis, combusts fossil 
fuel for more than 10.0 percent of the heat input during a 3-year 
rolling average basis and combusts over 90% natural gas on a heat input 
basis on a 3-year rolling average basis.

Sec.  60.5800  What affected EGUs are exempt from my state plan?

    Affected EGUs that are exempt from your state plan include: those 
that are subject to subpart TTTT as a result of commencing construction 
or reconstruction after the subpart TTTT applicability date; and those 
subject to subpart TTTT as a result of commencing modification or 
reconstruction prior becoming subject to an applicable state plan.

Sec.  60.5805  What applicable monitoring, recordkeeping, and reporting 
requirements do I need to include in my state plan for affected EGUs?

    (a) A state plan must include monitoring that is no less stringent 
that what is described in (a)(1) through (6) of this section.
    (1) If an affected EGU is required to meet a rate based emission 
standard they must prepare a monitoring plan in accordance with the 
applicable provisions in Sec.  75.53(g) and (h) of this chapter.
    (2) An affected EGU must measure the hourly CO2 mass 
emissions from each affected unit using the procedures in paragraphs 
(a)(2)(i) through (v) of this section, except as provided in paragraph 
(a)(3) of this section.
    (i) An affected EGU must install, certify, operate, maintain, and 
calibrate a CO2 continuous emissions monitoring system 
(CEMS) to directly measure and record CO2 concentrations in 
the affected EGU exhaust gases emitted to the atmosphere and an exhaust 
gas flow rate monitoring system according to Sec.  75.10(a)(3)(i) of 
this chapter. If an affected EGU measures CO2 concentration 
on a dry basis, they must also install, certify, operate, maintain, and 
calibrate a continuous moisture monitoring system, according to Sec.  
75.11(b) of this chapter.
    (ii) For each monitoring system an affected EGU uses to determine 
the CO2 mass emissions, they must meet the applicable 
certification and quality assurance procedures in Sec.  75.20 of this 
chapter and Appendices B and D to part 75 of this chapter.
    (iii) An affected EGU must use a laser device to measure the 
dimensions of each exhaust gas stack or duct at the flow monitor and 
the reference method sampling locations prior to the initial setup 
(characterization) of the flow monitor. For circular stacks, an 
affected EGU must measure the diameter at three or more distinct 
locations and average the results. For rectangular stacks or ducts, an 
affected EGU must measure each dimension (i.e., depth and width) at 
three or more distinct locations and average the results. If the flow 
rate monitor or reference method sampling site is relocated, an 
affected EGU must repeat these measurements at the new location.
    (iv) An affected EGU must use only unadjusted exhaust gas 
volumetric flow rates to determine the hourly CO2 mass 
emissions from the affected facility; an affected EGU must not apply 
the bias adjustment factors described in section 7.6.5 of Appendix A to 
part 75 of this chapter to the exhaust gas flow rate data.
    (v) If an affected EGU chooses to use Method 2 in Appendix A-1 to 
this part to perform the required relative accuracy test audits (RATAs) 
of the part 75 flow rate monitoring system, they must use a calibrated 
Type-S pitot tube or pitot tube assembly. An affected EGU must not use 
the default Type-S pitot tube coefficient.
    (3) If an affected EGU exclusively combusts liquid fuel and/or 
gaseous fuel as an alternative to complying with paragraph (b) of this 
section, they may determine the hourly CO2 mass emissions by 
using Equation G-4 in Appendix G to part 75 of this chapter according 
to the requirements in paragraphs (a)(3)(i) and (ii) of this section.
    (i) An affected EGU must implement the applicable procedures in 
appendix D to part 75 of this chapter to determine hourly unit heat 
input rates (MMBtu/h), based on hourly measurements of fuel flow rate 
and periodic determinations of the gross calorific value (GCV) of each 
fuel combusted.
    (ii) An affected EGU may determine site-specific carbon-based F-
factors (Fc) using Equation F-7b in section 3.3.6 of 
appendix F to part 75 of this chapter, and may use these Fc 
values in the

[[Page 34955]]

emissions calculations instead of using the default Fc 
values in the Equation G-4 nomenclature.
    (4) An affected EGU must install, calibrate, maintain, and operate 
a sufficient number of watt meters to continuously measure and record 
on an hourly basis net electric output. Measurements must be performed 
using 0.2 accuracy class electricity metering instrumentation and 
calibration procedures as specified under ANSI Standards No. C12.20. 
Further, an affected EGU that is a combined heat and power facility 
must install, calibrate, maintain and operate equipment to continuously 
measure and record on an hourly basis useful thermal output and, if 
applicable, mechanical output, which are used with net electric output 
to determine net energy output.
    (5) In accordance with Sec.  60.13(g), if two or more affected EGUs 
that implement the continuous emissions monitoring provisions in 
paragraph (a)(2) of this section share a common exhaust gas stack and 
are subject to the same emissions standard, they may monitor the hourly 
CO2 mass emissions at the common stack in lieu of monitoring 
each EGU separately. If an affected EGU chooses this option, the hourly 
net electric output for the common stack must be the sum of the hourly 
net electric output of the individual affected facility and you must 
express the operating time as ``stack operating hours'' (as defined in 
Sec.  72.2 of this chapter).
    (6) In accordance with Sec.  60.13(g), if the exhaust gases from an 
affected EGU that implements the continuous emissions monitoring 
provisions in paragraph (a)(2) of this section are emitted to the 
atmosphere through multiple stacks (or if the exhaust gases are routed 
to a common stack through multiple ducts and you elect to monitor in 
the ducts), they must monitor the hourly CO2 mass emissions 
and the ``stack operating time'' (as defined in Sec.  72.2 of this 
chapter) at each stack or duct separately. In this case, an affected 
EGU must determine compliance with an applicable emissions standard by 
summing the CO2 mass emissions measured at the individual 
stacks or ducts and dividing by the net energy output for the affected 
EGU.
    (b) An affected EGU must maintain records for at least 10 years 
following the date of each occurrence, measurement, maintenance, 
corrective action, report, or record.
    (1) An affected EGU must maintain each record on site for at least 
2 years after the date of each occurrence, measurement, maintenance, 
corrective action, report, or record, according to Sec.  60.7. An 
affected EGU may maintain the records off site and electronically for 
the remaining year(s).
    (c) An affected EGU must include in a report required by the state 
plan covering each compliance period all hourly CO2 
emissions and all hourly net electric output and all hourly net energy 
output measurements for a CHP facility calculated from data monitored 
according to paragraph (a) of this section.

Recordkeeping and Reporting Requirements

Sec.  60.5810  What are my state recordkeeping requirements?

    (a) States must keep records of all plan components, plan 
requirements, supporting documentation, and the status of meeting the 
plan requirements defined in the state plan on an annual basis during 
the interim plan performance period from 2020-2029. After 2029 states 
must keep records of all information that is used to support any 
continued effort to meet the final emissions performance goal.
    (b) States must keep records of all data submitted by each affected 
entity that is used to determine compliance with each affected entity's 
emissions standard.
    (c) If a state has a requirement for hourly CO2 
emissions and net generation information to be used to calculate 
compliance with an annual emissions standard for affected EGUs, any 
information that is submitted to the EPA electronically pursuant to 
requirements in Part 75 would meet the recordkeeping requirement of 
this section and a state would not need to keep records of information 
that would be in duplicate of paragraph (b) of this section.
    (d) A state must keep records at minimum for 20 years.

Sec.  60.5815  What are my state reporting requirements?

    (a) You must submit an annual report covering each calendar year no 
later than July 1 of the following year, starting July 1 2021. The 
annual report must include the following:
    (1) The level of emissions performance achieved by all affected 
entities and identification of whether affected entities are on 
schedule to meet the applicable level of emissions performance for 
affected entities during the plan performance period and compliance 
periods, as specified in the plan.
    (2) The level of emissions performance achieved by all affected 
EGUs during the reporting period, and prior reporting periods, 
expressed as average CO2 emissions rate or total mass 
CO2 emissions, consistent with the plan approach, and 
identification of whether affected EGUs are on schedule to meet the 
applicable level of emissions performance for affected EGUs during the 
plan performance period, as specified in the plan.
    (3) A list of affected entities and their compliance status with 
the applicable emissions standards specified in the state plan.
    (4) A list of all affected EGUs and their reported CO2 
emissions performance for each compliance period during the reporting 
period, and prior reporting periods.
    (5) All other required information, as specified in your state plan 
according to Sec.  60.5740(a)(9).
    (6) All information required by Sec.  60.5775(e).
    (b) For each two-year period in Sec.  60.5775(c)(1), you must 
compare the average CO2 emission performance achieved by 
affected entities in the state versus the CO2 emission 
performance projected in the state plan. If actual emission performance 
is greater than 10 percent in excess to projected plan performance for 
a two-year comparison period, you must explain the reasons for the 
deviation and specify the corrective actions that will be taken to 
ensure that the required interim and final levels of emission 
performance in the plan will be met. The information required in this 
paragraph must be included in the annual report required by paragraph 
(a) of this section.
    (c) You must include in your 2029 annual report (which is 
subsequently due by July 1, 2030) the calculation of average emissions 
over the 2020-2029 interim performance period used to determine 
compliance with your interim emission performance level. The calculated 
value must be in units consistent with your interim emission 
performance level.
    (d) You must include in each report, starting with the 2032 annual 
report (which is subsequently due by July 1, 2033), a 3-calendar year 
rolling average used to determine compliance with the final emission 
performance level. The calculated value must be in units consistent 
with your final emission performance level.

Definitions

Sec.  60.5820  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein will have the 
meaning given them in the Clean Air Act and in subparts A (General 
Provisions) and B of this part.

[[Page 34956]]

    Affected electric generating unit or Affected EGU means a steam 
generating unit, an IGCC facility, or a stationary combustion turbine 
that meets the applicability conditions in section Sec.  60.5795.
    Affected Entity shall mean any of the following: An affected EGU, 
or another entity with obligations under this subpart for the purpose 
of meeting the emissions performance goal requirements in these 
emission guidelines.
    Base load rating means the maximum amount of heat input (fuel) that 
a steam generating unit can combust on a steady state basis, as 
determined by the physical design and characteristics of the steam 
generating unit at ISO conditions. For a stationary combustion turbine, 
base load rating means 100 percent of the design heat input capacity of 
the simple cycle portion of the stationary combustion turbine at ISO 
conditions (heat input from duct burners is not included).
    CO2 emissions performance goal means the rate-based CO2 
emissions performance goal specified for a state in Table 1 of this 
subpart, or a translated mass-based form of that goal.
    Coal means all solid fuels classified as anthracite, bituminous, 
subbituminous, or lignite by the American Society of Testing and 
Materials in ASTM D388 (incorporated by reference, see Sec.  60.17), 
coal refuse, and petroleum coke. Synthetic fuels derived from coal for 
the purpose of creating useful heat, including but not limited to 
solvent-refined coal, gasified coal (not meeting the definition of 
natural gas), coal-oil mixtures, and coal-water mixtures are included 
in this definition for the purposes of this subpart.
    Combined cycle facility means an electric generating unit that uses 
a stationary combustion turbine from which the heat from the turbine 
exhaust gases is recovered by a heat recovery steam generating unit to 
generate additional electricity.
    Combined heat and power facility or CHP facility, (also known as 
``cogeneration'') means an electric generating unit that that use a 
steam-generating unit or stationary combustion turbine to 
simultaneously produce both electric (or mechanical) and useful thermal 
output from the same primary energy source.
    Compliance period means the period of time, set forth by a state in 
its state plan, during which each affected entity must demonstrate 
compliance with an applicable emissions standard, and shall be no 
greater than a three year period for a mass-based plan, and shall be no 
greater than a one year period for a rate-based plan.
    Emission performance level in a state plan means the level of 
emissions performance for affected entities specified in a state plan, 
according to Sec.  60.5740.
    Emission standard means in addition to the definition in Sec.  
60.21, any requirement applicable to any affected entity other than an 
affected source that has the effect of reducing utilization of one or 
more affected sources, thereby avoiding emissions from such sources, 
including, for example, renewable energy and demand-side energy 
efficiency measures requirements.
    Excess emissions means a specified averaging period over which the 
CO2 emissions rate is higher than an applicable emissions 
standard or an averaging period during which an affected EGU is not in 
compliance with any other emission limitation specified in an emission 
standard.
    Existing state program, requirement, or measure means, in the 
context of a state plan, a regulation, requirement, program, or measure 
administered by a state, utility, or other entity that is currently 
established. This may include a regulation or other legal requirement 
that includes past, current, and future obligations, or current 
programs and measures that are in place and are anticipated to be 
continued or expanded in the future, in accordance with established 
plans. An existing state program, requirement, or measure may have 
past, current, and future impacts on EGU CO2 emissions.
    Fossil fuel means natural gas, petroleum, coal, and any form of 
solid, liquid, or gaseous fuel derived from such material for the 
purpose of creating useful heat.
    Gaseous fuel means any fuel that is present as a gas at ISO 
conditions and includes, but is not limited to, natural gas, refinery 
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
    Heat recovery steam generating unit (HRSG) means a unit in which 
hot exhaust gases from the combustion turbine engine are routed in 
order to extract heat from the gases and generate useful output. Heat 
recovery steam generating units can be used with or without duct 
burners.
    Integrated gasification combined cycle facility or IGCC facility 
means a combined cycle facility that is designed to burn fuels 
containing 50 percent (by heat input) or more solid-derived fuel not 
meeting the definition of natural gas plus any integrated equipment 
that provides electricity or useful thermal output to either the 
affected facility or auxiliary equipment. The Administrator may waive 
the 50 percent solid-derived fuel requirement during periods of the 
gasification system construction, startup and commissioning, shutdown, 
or repair. No solid fuel is directly burned in the unit during 
operation.
    ISO conditions means 288 Kelvin (15[deg] C), 60 percent relative 
humidity and 101.3 kilopascals pressure.
    Liquid fuel means any fuel that is present as a liquid at ISO 
conditions and includes, but is not limited to, distillate oil and 
residual oil.
    Mechanical output means the useful mechanical energy that is not 
used to operate the affected facility, generate electricity and/or 
thermal output, or to enhance the performance of the affected facility. 
Mechanical energy measured in horsepower hour should be converted into 
MWh by multiplying it by 745.7 then dividing by 1,000,000.
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane, 
ethane, or propane), composed of at least 70 percent methane by volume 
or that has a gross calorific value between 35 and 41 megajoules (MJ) 
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic 
foot), that maintains a gaseous state under ISO conditions. In 
addition, natural gas contains 20.0 grains or less of total sulfur per 
100 standard cubic feet. Finally, natural gas does not include the 
following gaseous fuels: Landfill gas, digester gas, refinery gas, sour 
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, 
or any gaseous fuel produced in a process which might result in highly 
variable sulfur content or heating value.
    Net-electric output means the amount of gross generation the 
generator(s) produce (including, but not limited to, output from steam 
turbine(s), combustion turbine(s), and gas expander(s)), as measured at 
the generator terminals, less the electricity used to operate the plant 
(i.e., auxiliary loads); such uses include fuel handling equipment, 
pumps, fans, pollution control equipment, other electricity needs, and 
transformer losses as measured at the transmission side of the step up 
transformer (e.g., the point of sale).
    Net energy output means:
    (1) The net electric or mechanical output from the affected 
facility, plus 75 percent of the useful thermal output measured 
relative to SATP conditions that is not used to generate additional 
electric or mechanical output or to enhance the performance of the unit 
(e.g., steam delivered to an industrial process for a heating 
application).
    (2) For combined heat and power facilities where at least 20.0 
percent of

[[Page 34957]]

the total gross energy output consists of electric or direct mechanical 
output and 20.0 percent of the total gross energy output consists of 
useful thermal output on a rolling 3 year basis, the net electric or 
mechanical output from the affected facility divided by 0.95, plus 75 
percent of the useful thermal output measured relative to SATP 
conditions that is not used to generate additional electric or 
mechanical output or to enhance the performance of the unit (e.g., 
steam delivered to an industrial process for a heating application).
    Petroleum means crude oil or a fuel derived from crude oil, 
including, but not limited to, distillate and residual oil.
    Solid fuel means any fuel that has a definite shape and volume, has 
no tendency to flow or disperse under moderate stress, and is not 
liquid or gaseous at ISO conditions. This includes, but is not limited 
to, coal, biomass, and pulverized solid fuels.
    Standard ambient temperature and pressure (SATP) conditions means 
298.15 Kelvin (25[deg] C, 77 [deg]F)) and 100.0 kilopascals (14.504 
psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 
50 Btu/lb.
    Stationary combustion turbine means all equipment, including but 
not limited to the turbine engine, the fuel, air, lubrication and 
exhaust gas systems, control systems (except emissions control 
equipment), heat recovery system, fuel compressor, heater, and/or pump, 
post-combustion emissions control technology, and any ancillary 
components and sub-components comprising any simple cycle stationary 
combustion turbine, any combined cycle combustion turbine, and any 
combined heat and power combustion turbine based system plus any 
integrated equipment that provides electricity or useful thermal output 
to the combustion turbine engine, heat recovery system or auxiliary 
equipment. Stationary means that the combustion turbine is not self-
propelled or intended to be propelled while performing its function. It 
may, however, be mounted on a vehicle for portability. If a stationary 
combustion turbine burns any solid fuel directly it is considered a 
steam generating unit.
    Steam generating unit means any furnace, boiler, or other device 
used for combusting fuel and producing steam (nuclear steam generators 
are not included) plus any integrated equipment that provides 
electricity or useful thermal output to the affected facility or 
auxiliary equipment.
    Useful thermal output means the thermal energy made available for 
use in any industrial or commercial process, or used in any heating or 
cooling application, i.e., total thermal energy made available for 
processes and applications other than electric generation, mechanical 
output at the affected facility, or to directly enhance the performance 
of the affected facility (e.g., economizer output is not useful thermal 
output, but thermal energy used to reduce fuel moisture is considered 
useful thermal output). Useful thermal output for affected facilities 
with no condensate return (or other thermal energy input to the 
affected facility) or where measuring the energy in the condensate (or 
other thermal energy input to the affected facility) would not 
meaningfully impact the emission rate calculation is measured against 
the energy in the thermal output at SATP conditions. Affected 
facilities with meaningful energy in the condensate return (or other 
thermal energy input to the affected facility) must measure the energy 
in the condensate and subtract that energy relative to SATP conditions 
from the measured thermal output.

    Table 1 to Subpart UUUU of Part 60--State Rate-Based CO2 Emission
                            Performance Goals
                       [Pounds of CO2 per net MWh]
------------------------------------------------------------------------
                State                   Interim goal       Final goal
------------------------------------------------------------------------
Alabama.............................             1,147             1,059
Alaska..............................             1,097             1,003
Arizona.............................               735               702
Arkansas............................               968               910
California..........................               556               537
Colorado............................             1,159             1,108
Connecticut.........................               597               540
Delaware............................               913               841
Florida.............................               794               740
Georgia.............................               891               834
Hawaii..............................             1,378             1,306
Idaho...............................               244               228
Illinois............................             1,366             1,271
Indiana.............................             1,607             1,531
Iowa................................             1,341             1,301
Kansas..............................             1,578             1,499
Kentucky............................             1,844             1,763
Louisiana...........................               948               883
Maine...............................               393               378
Maryland............................             1,347             1,187
Massachusetts.......................               655               576
Michigan............................             1,227             1,161
Minnesota...........................               911               873
Mississippi.........................               732               692
Missouri............................             1,621             1,544
Montana.............................             1,882             1,771
Nebraska............................             1,596             1,479
Nevada..............................               697               647
New Hampshire.......................               546               486
New Jersey..........................               647               531
New Mexico..........................             1,107             1,048
New York............................               635               549
North Carolina......................             1,077               992
North Dakota........................             1,817             1,783

[[Page 34958]]

 
Ohio................................             1,452             1,338
Oklahoma............................               931               895
Oregon..............................               407               372
Pennsylvania........................             1,179             1,052
Rhode Island........................               822               782
South Carolina......................               840               772
South Dakota........................               800               741
Tennessee...........................             1,254             1,163
Texas...............................               853               791
Utah................................             1,378             1,322
Virginia............................               884               810
Washington..........................               264               215
West Virginia.......................             1,748             1,620
Wisconsin...........................             1,281             1,203
Wyoming.............................             1,808             1,714
------------------------------------------------------------------------

[FR Doc. 2014-13726 Filed 6-17-14; 8:45 am]
BILLING CODE 6560-50-P