[Federal Register Volume 80, Number 205 (Friday, October 23, 2015)]
[Rules and Regulations]
[Pages 64661-64964]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-22842]



[[Page 64661]]

Vol. 80

Friday,

No. 205

October 23, 2015

Part III





Environmental Protection Agency





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40 CFR Part 60





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

Federal Register / Vol. 80 , No. 205 / Friday, October 23, 2015 / 
Rules and Regulations

[[Page 64662]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2013-0602; FRL-9930-65-OAR]
RIN 2060-AR33


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: In this action, the Environmental Protection Agency (EPA) is 
establishing final emission guidelines for states to follow in 
developing plans to reduce greenhouse gas (GHG) emissions from existing 
fossil fuel-fired electric generating units (EGUs). Specifically, the 
EPA is establishing: Carbon dioxide (CO2) emission 
performance rates representing the best system of emission reduction 
(BSER) for two subcategories of existing fossil fuel-fired EGUs--fossil 
fuel-fired electric utility steam generating units and stationary 
combustion turbines; state-specific CO2 goals reflecting the 
CO2 emission performance rates; and guidelines for the 
development, submittal and implementation of state plans that establish 
emission standards or other measures to implement the CO2 
emission performance rates, which may be accomplished by meeting the 
state goals. This final rule will continue progress already underway in 
the U.S. to reduce CO2 emissions from the utility power 
sector.

DATES: This final rule is effective on December 22, 2015.

ADDRESSES: Docket. The EPA has established a docket for this action 
under Docket No. EPA-HQ-OAR-2013-0602. 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., confidential 
business information (CBI) or other information for which disclosure is 
restricted by statute). Certain other material, such as copyrighted 
material, will be publicly available only in hard copy. Publicly 
available docket materials are available either electronically in 
http://www.regulations.gov or in hard copy at the EPA Docket Center, 
EPA WJC West Building, 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. For additional information 
about the EPA's public docket, visit the EPA Docket Center homepage at 
http://www2.epa.gov/dockets.
    World Wide Web. In addition to being available in the docket, an 
electronic copy of this final rule will be available on the World Wide 
Web (WWW). Following signature, a copy of this final rule will be 
posted at the following address: http://www.epa.gov/cleanpowerplan/. A 
number of documents relevant to this rulemaking, including technical 
support documents (TSDs), a legal memorandum, and the regulatory impact 
analysis (RIA), are also available at http://www.epa.gov/cleanpowerplan/. These and other related documents are also available 
for inspection and copying in the EPA docket for this rulemaking.

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: [email protected] or Mr. Colin Boswell, 
Measurements Policy Group (D243-05), Sector Policies and Programs 
Division, U.S. EPA, Research Triangle Park, NC 27711; telephone number 
(919) 541-2034, facsimile number (919) 541-4991; email address: 
[email protected].

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 and 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)
CEIP Clean Energy Incentive Program
CEMS Continuous Emissions Monitoring System
CHP Combined Heat and Power
CO2 Carbon Dioxide
DOE U.S. Department of Energy
ECMPS Emission Collection and Monitoring Plan System
EE Energy Efficiency
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
FERC Federal Energy Regulatory Commission
ERC Emission Rate Credit
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
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
OMB Office of Management and Budget
PM Particulate Matter
PM2.5 Fine Particulate Matter
PRA Paperwork Reduction Act
PUC Public Utilities Commission
RE Renewable Energy
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 Organization
SBA Small Business Administration
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

    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 Final Rule

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II. Background
    A. Climate Change Impacts From GHG Emissions
    B. GHG Emissions From Fossil Fuel-Fired EGUs
    C. The Utility Power Sector
    D. Challenges in Controlling Carbon Dioxide Emissions
    E. Clean Air Act Regulations for Power Plants
    F. Congressional Awareness of Climate Change
    G. International Agreements and Actions
    H. Legislative and Regulatory Background for CAA Section 111
    I. Statutory and Regulatory Requirements
    J. Clean Power Plan Proposal and Supplemental Proposal
    K. Stakeholder Outreach and Consultations
    L. Comments on the Proposal
III. Rule Requirements and Legal Basis
    A. Summary of Rule Requirements
    B. Summary of Legal Basis
IV. Authority for This Rulemaking, Definition of Affected Sources, 
and Treatment of Categories
    A. EPA's Authority Under CAA Section 111(d)
    B. CAA Section 112 Exclusion to CAA Section 111(d) Authority
    C. Authority To Regulate EGUs
    D. Definition of Affected Sources
    E. Combined Categories and Codification in the Code of Federal 
Regulations
V. The Best System of Emission Reduction and Associated Building 
Blocks
    A. The Best System of Emission Reduction (BSER)
    B. Legal Discussion of Certain Aspects of the BSER
    C. Building Block 1--Efficiency Improvements at Affected Coal-
Fired Steam EGUs
    D. Building Block 2--Generation Shifts Among Affected EGUs
    E. Building Block 3--Renewable Generating Capacity
VI. Subcategory-Specific CO2 Emission Performance Rates
    A. Overview
    B. Emission Performance Rate Requirements
    C. Form of the Emission Performance Rates
    D. Emission Performance Rate-Setting Equation and Computation 
Procedure
VII. Statewide CO2 Goals
    A. Overview
    B. Reconstituting Statewide Rate-Based CO2 Emission 
Performance Goals From the Subcategory-Specific Emission Performance 
Rates
    C. Quantifying Mass-Based CO2 Emission Performance 
Goals From the Statewide Rate-Based CO2 Emission 
Performance Goals
    D. Addressing Potential Leakage in Determining the Equivalence 
of Statewide CO2 Emission Performance Goals
    E. State Plan Adjustments of State Goals
    F. Geographically Isolated States and Territories With Affected 
EGUs
VIII. State Plans
    A. Overview
    B. Timeline for State Plan Performance and Provisions To 
Encourage Early Action
    C. State Plan Approaches
    D. State Plan Components and Approvability Criteria
    E. State Plan Submittal and Approval Process and Timing
    F. State Plan Performance Demonstrations
    G. Additional Considerations for State Plans
    H. Resources for States to Consider in Developing Plans
    I. Considerations for CO2 Emission Reduction Measures 
That Occur at Affected EGUs
    J. Additional Considerations and Requirements for Mass-Based 
State Plans
    K. Additional Considerations and Requirements for Rate-Based 
State Plans
    L. Treatment of Interstate Effects
IX. Community and Environmental Justice Considerations
    A. Proximity Analysis
    B. Community Engagement in State Plan Development
    C. Providing Communities With Access to Additional Resources
    D. Federal Programs and Resources Available to Communities
    E. Multi-Pollutant Planning and Co-Pollutants
    F. Assessing Impacts of State Plan Implementation
    G. EPA Continued Engagement
X. Interactions With Other EPA Programs and Rules
    A. Implications for the NSR Program
    B. Implications for the Title V Program
    C. Interactions With Other EPA Rules
XI. Impacts of This Action
    A. What are the air impacts?
    B. Endangered Species Act
    C. What are the energy impacts?
    D. What are the compliance costs?
    E. What are the economic and employment impacts?
    F. What are the benefits of the proposed action?
XII. 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 (PRA)
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    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 (NTTAA)
    J. Executive Order 12898, Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act (CRA)
XIII. Statutory Authority

I. General Information

A. Executive Summary

1. Introduction
    This final rule is a significant step forward in reducing 
greenhouse gas (GHG) emissions in the U.S. In this action, the EPA is 
establishing for the first time GHG emission guidelines for existing 
power plants. These final emission guidelines, which rely in large part 
on already clearly emerging growth in clean energy innovation, 
development and deployment, will lead to significant carbon dioxide 
(CO2) emission reductions from the utility power sector that 
will help protect human health and the environment from the impacts of 
climate change. This rule establishes, at the same time, the foundation 
for longer term GHG emission reduction strategies necessary to address 
climate change and, in so doing, confirms the international leadership 
of the U.S. in the global effort to address climate change. In this 
final rule, we have taken care to ensure that achievement of the 
required emission reductions will not compromise the reliability of our 
electric system, or the affordability of electricity for consumers. 
This final rule is the result of unprecedented outreach and engagement 
with states, tribes, utilities, and other stakeholders, with 
stakeholders providing more than 4.3 million comments on the proposed 
rule. In this final rule, we have addressed the comments and concerns 
of states and other stakeholders while staying consistent with the law. 
As a result, we have followed through on our commitment to issue a plan 
that is fair, flexible and relies on the accelerating transition to 
cleaner power generation that is already well underway in the utility 
power sector.
    Under the authority of Clean Air Act (CAA) section 111(d), the EPA 
is establishing CO2 emission guidelines for existing fossil 
fuel-fired electric generating units (EGUs)--the Clean Power Plan. 
These final guidelines, when fully implemented, will achieve 
significant reductions in CO2 emissions by 2030, while 
offering states and utilities substantial flexibility and latitude in 
achieving these reductions. In this final rule, the EPA is establishing 
a CO2 emission performance rate for each of two 
subcategories of fossil fuel-fired EGUs--fossil fuel-fired electric 
steam generating units and stationary combustion turbines--that 
expresses the ``best system of emissions reduction . . . adequately 
demonstrated'' (BSER)

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for CO2 from the power sector.\1\ The EPA is also 
establishing state-specific rate-based and mass-based goals that 
reflect the subcategory-specific CO2 emission performance 
rates and each state's mix of affected EGUs. The guidelines also 
provide for the development, submittal and implementation of state 
plans that implement the BSER--again, expressed as CO2 
emission performance rates--either directly by means of source-specific 
emission standards or other requirements, or through measures that 
achieve equivalent CO2 reductions from the same group of 
EGUs.
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    \1\ Under CAA section 111(d), pursuant to 40 CFR 60.22(b)(5), 
states must establish, in their state plans, emission standards 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 (i.e., the BSER). 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 emission standard or 
standards that reflect that amount of emission reduction.
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    States with one or more affected EGUs will be required to develop 
and implement plans that set emission standards for affected EGUs. The 
CAA section 111(d) emission guidelines that the EPA is promulgating in 
this action apply to only the 48 contiguous states and any Indian tribe 
that has been approved by the EPA pursuant to 40 CFR 49.9 as eligible 
to develop and implement a CAA section 111(d) plan.\2\ Because Vermont 
and the District of Columbia do not have affected EGUs, they will not 
be required to submit a state plan. Because the EPA does not possess 
all of the information or analytical tools needed to quantify the BSER 
for the two non-contiguous states with otherwise affected EGUs (Alaska 
and Hawaii) and the two U.S. territories with otherwise affected EGUs 
(Guam and Puerto Rico), these emission guidelines do not apply to those 
areas, and those areas will not be required to submit state plans on 
the schedule required by this final action.
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    \2\ In the case of a tribe that has one or more affected EGUs in 
its area of Indian country, the tribe has the opportunity, but not 
the obligation, to establish a CO2 emission standard for 
each affected EGU located in its area of Indian country and a CAA 
section 111(d) plan for its area of Indian country. If the tribe 
chooses to establish its own plan, it must seek and obtain authority 
from the EPA to do so pursuant to 40 CFR 49.9. If it chooses not to 
seek this authority, the EPA has the responsibility to determine 
whether it is necessary or appropriate, in order to protect air 
quality, to establish a CAA section 111(d) plan for an area of 
Indian country where affected EGUs are located.
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    The emission standards in a state's plan may incorporate the 
subcategory-specific CO2 emission performance rates set by 
the EPA or, in the alternative, may be set at levels that ensure that 
the state's affected EGUs, individually, in aggregate, or in 
combination with other measures undertaken by the state achieve the 
equivalent of the interim and final CO2 emission performance 
rates between 2022 and 2029 and by 2030, respectively. State plans must 
also: (1) Ensure that the period for emission reductions from the 
affected EGUs begin no later than 2022, (2) show how goals for the 
interim and final periods will be met, (3) ensure that, during the 
period from 2022 to 2029, affected EGUs in the state collectively meet 
the equivalent of the interim subcategory-specific CO2 
emission performance rates, and (4) provide for periodic state-level 
demonstrations prior to and during the 2022-2029 period that will 
ensure required CO2 emission reductions are being 
accomplished and no increases in emissions relative to each state's 
planned emission reduction trajectory are occurring. A Clean Energy 
Incentive Program (CEIP) will provide opportunities for investments in 
renewable energy (RE) and demand-side energy efficiency (EE) that 
deliver results in 2020 and/or 2021. The plans must be submitted to the 
EPA in 2016, though an extension to 2018 is available to allow for the 
completion of stakeholder and administrative processes.
    The EPA is promulgating: (1) Subcategory-specific CO2 
emission performance rates, (2) state rate-based goals, and (3) state 
mass-based CO2 goals that represent the equivalent of each 
state's rate-based goal. This will facilitate states' choices in 
developing their plans, particularly for those seeking to adopt mass-
based allowance trading programs or other statewide policy measures as 
well as, or instead of, source-specific requirements. The EPA received 
significant comment to the effect that mass-based allowance trading was 
not only highly familiar to states and EGUs, but that it could be more 
readily applied than rate-based trading for achieving emission 
reductions in ways that optimize affordability and electric system 
reliability.
    In this summary, we discuss the purpose of this rule, the major 
provisions of the final rule, the context for the rulemaking, key 
changes from the proposal, the estimated CO2 emission 
reductions, and the costs and benefits expected to result from full 
implementation of this final action. Greater detail is provided in the 
body of this preamble, the RIA, the response to comments (RTC) 
documents, and various TSDs and memoranda addressing specific topics.
2. Purpose of This Rule
    The purpose of this rule is to protect human health and the 
environment by reducing CO2 emissions from fossil fuel-fired 
power plants in the U.S. These plants are by far the largest domestic 
stationary source of emissions of CO2, the most prevalent of 
the group of air pollutant GHGs that the EPA has determined endangers 
public health and welfare through its contribution to climate change. 
This rule establishes for the first time emission guidelines for 
existing power plants. These guidelines will lead to significant 
reductions in CO2 emissions, result in cleaner generation 
from the existing power plant fleet, and support continued investments 
by the industry in cleaner power generation to ensure reliable, 
affordable electricity now and into the future.
    Concurrent with this action, the EPA is also issuing a final rule 
that establishes CO2 emission standards of performance for 
new, modified, and reconstructed power plants. Together, these rules 
will reduce CO2 emissions by a substantial amount while 
ensuring that the utility power sector in the U.S. can continue to 
supply reliable and affordable electricity to all Americans using a 
diverse fuel supply. As with past EPA rules addressing air pollution 
from the utility power sector, these guidelines have been designed with 
a clear recognition of the unique features of this sector. 
Specifically, the agency recognizes that utilities provide an essential 
public service and are regulated and managed in ways unlike any other 
industrial activity. In providing assurances that the emission 
reductions required by this rule can be achieved without compromising 
continued reliable, affordable electricity, this final rule fully 
accounts for the critical service utilities provide.
    As with past rules under CAA section 111, this rule relies on 
proven technologies and measures to set achievable emission performance 
rates that will lead to cost-effective pollutant emission reductions, 
in this case CO2 emission reductions at power plants, across 
the country. In fact, the emission guidelines reflect strategies, 
technologies and approaches already in widespread use by power 
companies and states. The vast preponderance of the input we received 
from stakeholders is supportive of this conclusion.
    States will play a key role in ensuring that emission reductions 
are achieved at a reasonable cost. The experience of

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states in this regard is especially important because CAA section 
111(d) relies on the well-established state-EPA partnership to 
accomplish the required CO2 emission reductions. States will 
have the flexibility to choose from a range of plan approaches and 
measures, including numerous measures beyond those considered in 
setting the CO2 emission performance rates, and this final 
rule allows and encourages states to adopt the most effective set of 
solutions for their circumstances, taking account of cost and other 
considerations. This rulemaking, which will be implemented through the 
state-EPA partnership, is a significant step that will reduce air 
pollution, in this case GHG emissions, in the U.S. At the same time, 
the final rule greatly facilitates flexibility for EGUs by establishing 
a basis for states to set trading-based emission standards and 
compliance strategies. The rule establishes this basis by including 
both uniform emission performance rates for the two subcategories of 
sources and also state-specific rate- and mass-based goals.
    This final rule is a significant step forward in implementing the 
President's Climate Action Plan.\3\ To address the far-reaching harmful 
consequences and real economic costs of climate change, the President's 
Climate Action Plan details a broad array of actions to reduce GHG 
emissions that contribute to climate change and its harmful impacts on 
public health and the environment. Climate change is already occurring 
in this country, affecting the health, economic well-being and quality 
of life of Americans across the country, and especially those in the 
most vulnerable communities. This CAA section 111(d) rulemaking to 
reduce GHG emissions from existing power plants, and the concurrent CAA 
section 111(b) rulemaking to reduce GHG emissions from new, modified, 
and reconstructed power plants, implement one of the strategies of the 
Climate Action Plan.
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    \3\ The President's Climate Action Plan, June 2013. http://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf.
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    Nationwide, by 2030, this final CAA section 111(d) existing source 
rule will achieve CO2 emission reductions from the utility 
power sector of approximately 32 percent from CO2 emission 
levels in 2005.
    The EPA projects that these reductions, along with reductions in 
other air pollutants resulting directly from this rule, will result in 
net climate and health benefits of $25 billion to $45 billion in 2030. 
At the same time, coal and natural gas will remain the two leading 
sources of electricity generation in the U.S., with coal providing 
about 27 percent of the projected generation and natural gas providing 
about 33 percent of the projected generation.
3. Summary of Major Provisions
    a. Overview. The fundamental goal of this rule is to reduce harmful 
emissions of CO2 from fossil fuel-fired EGUs in accordance 
with the requirements of the CAA. The June 2014 proposal for this rule 
was designed to meet this overarching goal while accommodating two 
important objectives. The first was to establish guidelines that 
reflect both the unique interconnected and interdependent manner in 
which the power system operates and the actions, strategies, and 
policies states and utilities have already been undertaking that are 
resulting in CO2 emission reductions. The second objective 
was to provide states and utilities with broad flexibility and choice 
in meeting those requirements in order to minimize costs to ratepayers 
and to ensure the reliability of electricity supply. In this final 
rule, the EPA has focused on changes that, in addition to being 
responsive to the critical concerns and priorities of stakeholders, 
more fully accomplish these objectives.
    While our consideration of public input and additional information 
has led to notable revisions from the emission guidelines we proposed 
in June 2014, the proposed guidelines remain the foundation of this 
final rule. These final guidelines build on the progress already 
underway to reduce the carbon intensity of power generation in the 
U.S., especially through the lowest carbon-intensive technologies, 
while reflecting the unique interconnected and interdependent system 
within which EGUs operate. Thus, the BSER, as determined in these 
guidelines, incorporates a range of CO2-reducing actions, 
while at the same time adhering to the fundamental approach the EPA has 
relied on for decades in implementing section 111 of the CAA. 
Specifically, in making its BSER determination, the EPA examined not 
only actions, technologies and measures already in use by EGUs and 
states, but also deliberately incorporated in its identification of the 
BSER the unique way in which affected EGUs actually operate in 
providing electricity services. This latter feature of the BSER mirrors 
Congress' approach to regulating air pollution in this sector, as 
exemplified by Title IV of the CAA. There, Congress established a 
pollution reduction program specifically for fossil fuel-fired EGUs and 
designed the sulfur dioxide (SO2) portion of that program 
with express recognition of the utility power sector's ability to shift 
generation among various EGUs, which enabled pollution reduction by 
increasing reliance on RE and even on demand-side EE. The result of our 
following Congress' recognition of the interdependent operation of EGUs 
within an interconnected grid is the incorporation in the BSER of 
measures, such as shifting generation to lower-emitting NGCC units and 
increased use of RE, that rely on the current interdependent operation 
of EGUs. As we noted in the proposal and note here as well, the EPA 
undertook an unprecedented and sustained process of engagement with the 
public and stakeholders. It is, in many ways, as a direct result of 
public discussion and input that the EPA came to recognize the 
substantial extent to which the BSER needed to account for the unique 
interconnected and interdependent operations of EGUs if it was to meet 
the criteria on which the EPA has long relied in making BSER 
determinations.
    Equally important, these guidelines offer states and owners and 
operators of EGUs broad flexibility and latitude in complying with 
their obligations. Because affordability and electricity system 
reliability are of paramount importance, the rule provides states and 
utilities with time for planning and investment, which is instrumental 
to ensuring both manageable costs and system reliability, as well as to 
facilitating clean energy innovation. The final rule continues to 
express the CO2 emission reduction requirements in terms of 
state goals, as well as in terms of emission performance rates for the 
two subcategories of affected EGUs, reflecting the particular mix of 
power generation in each state, and it continues to provide until 2030, 
fifteen years from the date of this final rule, for states and sources 
to achieve the CO2 reductions. Numerous commenters, 
including most sources, states and energy agencies, indicated that this 
was a reasonable timeframe. The final guidelines also continue to 
provide an option where programs beyond those directly limiting power 
plant emission rates can be used for compliance (i.e., policies, 
programs and other measures). The final rule also continues to allow, 
but not require, multi-state approaches. Finally, EPA took care to 
ensure that states could craft their own emissions reduction 
trajectories in meeting the interim goals included in this final rule.
    b. Opportunities for states. As stated above, the final 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

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emissions. States, in their CAA section 111(d) plans, will be able to 
rely on, and extend, programs they may already have created to address 
emissions of air pollutants, and in particular CO2, from the 
utility power sector or to address the sector from an overall 
perspective. Those states committed to Integrated Resource Planning 
(IRP) will be able to establish their CO2 reduction plans 
within that framework, while states with a more deregulated power 
sector system will be able to develop CO2 reduction plans 
within that specific framework. Each state will have the opportunity to 
take advantage of a wide variety of strategies for reducing 
CO2 emissions from affected EGUs, including demand-side EE 
programs and mass-based trading, which some suggested in their 
comments. 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 (USDA), among others, are 
committed to sharing expertise with interested states as they develop 
and implement their plans.
    States will be able to address the economic interests of their 
utilities and ratepayers by using the flexibilities in this final 
action to reduce costs to consumers, minimize stranded assets, and spur 
private investments in RE and EE technologies and businesses. They may 
also, 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 final rule gives states the 
flexibility to implement a broad range of approaches that recognize 
that the utility power sector is made up of a diverse range of 
companies of various sizes that own and operate fossil fuel-fired EGUs, 
including vertically integrated companies in regulated markets, 
independent power producers, rural cooperatives and municipally-owned 
utilities, some of which are likely to have more direct access than 
others to certain types of GHG emission reduction opportunities, but 
all of which have a wide range of opportunities to achieve reductions 
or acquire clean generation.
    Again, with features that facilitate mass-based and/or interstate 
trading, the final guidelines also empower affected EGUs to pursue a 
broad range of choices for compliance and for integrating compliance 
action with the full range of their investments and operations.
    c. Main elements. This final rule comprises three main elements: 
(1) Two subcategory-specific CO2 emission performance rates 
resulting from application of the BSER to the two subcategories of 
affected EGUs; (2) state-specific CO2 goals, expressed as 
both emission rates and as mass, that reflect the subcategory-specific 
CO2 emission performance rates and each state's mix of 
affected EGUs the two performance rates; and (3) guidelines for the 
development, submittal and implementation of state plans that implement 
those BSER emission performance rates either through emission standards 
for affected EGUs, or through measures that achieve the equivalent, in 
aggregate, of those rates as defined and expressed in the form of the 
state goals.
    In this final action, the EPA is setting emission performance 
rates, phased in over the period from 2022 through 2030, for two 
subcategories of affected fossil fuel-fired EGUs--fossil fuel-fired 
electric utility steam-generating units and stationary combustion 
turbines. These rates, applied to each state's particular mix of fossil 
fuel-fired EGUs, generate the state's carbon intensity goal for 2030 
(and interim rates for the period 2022-2029). Each state will determine 
whether to apply these to each affected EGU or to take an alternative 
approach and meet either an equivalent statewide rate-based goal or 
statewide mass-based goal. The EPA does not prescribe how a state must 
meet the emission guidelines, but, if a state chooses to take the path 
of meeting a state goal, these final guidelines identify the methods 
that a state can or, in some cases, must use to demonstrate that the 
combination of measures and standards that the state adopts meets its 
state-level CO2 goals. While the EPA accomplishes the phase-
in of the interim goal by way of annual emission performance rates, 
states and EGUs may meet their respective emission reduction 
obligations ``on average'' over that period following whatever emission 
reduction trajectory they determine to pursue over that period.
    CAA section 111(d) creates a partnership between the EPA and the 
states under which the EPA establishes emission guidelines and the 
states take the lead on implementing them by establishing emission 
standards or creating plans that are consistent with the EPA emission 
guidelines. The EPA recognizes that each state has differing policy 
considerations--including varying regional 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 and generation mix) also differ. Therefore, as in 
the proposal, each state will have the latitude to design a program to 
meet source-category specific emission performance rates or the 
equivalent statewide rate- or mass-based goal in a manner that reflects 
its particular circumstances and energy and environmental policy 
objectives. Each state can do so on its own, or a state can collaborate 
with other states and/or tribal governments on multi-state plans, or 
states can include in their plans the trading tools that EGUs can use 
to realize additional opportunities for cost savings while continuing 
to operate across the interstate system through which electricity is 
produced. A state would also have the option of adopting the model 
rules for either a rate- or a mass-based program that the EPA is 
proposing concurrently with this action.\4\
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    \4\ The EPA's proposed CAA section 111(d) federal plan and model 
rules for existing fossil fuel-fired EGUs are being published 
concurrently with this final rule.
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    To facilitate the state planning process, this final rule 
establishes guidelines for the development, submittal, and 
implementation of state plans. The final rule describes the components 
of a state plan, the additional latitude states have in developing 
strategies to meet the emission guidelines, and the options they have 
in the timing of submittal of their plans. This final rule also gives 
states considerable flexibility with respect to the timeframes for plan 
development and implementation, as well as the choice of emission 
reduction measures. The final rule provides up to fifteen years for 
full implementation of all emission reduction measures, with 
incremental steps for planning and then for demonstration of 
CO2 reductions that will ensure that progress is being made 
in achieving CO2 emission reductions. States will be able to 
choose from a wide range of emission reduction measures, including 
measures that are not part of the BSER, as discussed in detail in 
section VIII.G of this preamble.
    d. Determining the BSER. In issuing this final 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 numerous 
subsequent CAA section 111 rulemakings. These requirements call on the 
EPA to develop emission guidelines that reflect the EPA's determination 
of the ``best system of emission reduction . . . adequately 
demonstrated'' for states to follow in

[[Page 64667]]

formulating plans to establish emission standards to implement the 
BSER.
    As the EPA has done in making BSER determinations in previous CAA 
section 111 rulemakings, for this final BSER determination, 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).\5\
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    \5\ 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), provide an example, as the guidelines 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.
---------------------------------------------------------------------------

    In so doing, as has always been the case, our considerations were 
not limited solely to specific technologies or equipment in 
hypothetical operation; rather, our analysis encompassed the full range 
of operational practices, limitations, constraints and opportunities 
that bear upon EGUs' emission performance, and which reflect the unique 
interconnected and interdependent operations of EGUs and the overall 
electricity grid.
    In this final action, the agency has determined that the BSER 
comprises the first three of the four proposed ``building blocks,'' 
with certain refinements to the three building blocks.
    The three building blocks are:

    1. Improving heat rate at affected coal-fired steam EGUs.
    2. Substituting increased generation from lower-emitting 
existing natural gas combined cycle units for generation from 
higher-emitting affected steam generating units.
    3. Substituting increased generation from new zero-emitting 
renewable energy generating capacity for generation from affected 
fossil fuel-fired generating units.

    These three building blocks are approaches that are available to 
all affected EGUs, either through direct investment or operational 
shifts or through emissions trading where states, which must establish 
emission standards for affected EGUs, do so by incorporating emissions 
trading.\6\ At the same time, and as we noted in the proposal, there 
are numerous other measures available to reduce CO2 
emissions from affected EGUs, and our determination of the BSER does 
not necessitate the use of the three building blocks to their maximum 
extent, or even at all. The building blocks and the BSER determination 
are described in detail in section V of this preamble.
---------------------------------------------------------------------------

    \6\ The EPA notes that, in quantifying the emission reductions 
that are achievable through application of the BSER, some building 
blocks will apply to some, but not all, affected EGUs. Specifically, 
building block 1 will apply to affected coal-fired steam EGUs, 
building block 2 will apply to all affected steam EGUs (both coal-
fired and oil/gas-fired), and building block 3 will apply to all 
affected EGUs.
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    e. CO2 state-level goals and subcategory-specific emission 
performance rates.
    (1) Final CO2 goals and emission performance rates.
    In this action, the EPA is establishing CO2 emission 
performance rates for two subcategories of affected EGUs--fossil fuel-
fired electric utility steam generating units and stationary combustion 
turbines. For fossil fuel-fired steam generating units, we are 
finalizing an emission performance rate of 1,305 lb CO2/MWh. 
For stationary combustion turbines, we are finalizing an emission 
performance rate of 771 lb CO2/MWh. As we did at proposal, 
for each state, we are also promulgating rate-based CO2 
goals that are the weighted aggregate of the emission performance rates 
for the state's EGUs. To ensure that states and sources can choose 
additional alternatives in meeting their obligations, the EPA is also 
promulgating each state's goal expressed as a CO2 mass goal. 
The inclusion of mass-based goals, along with information provided in 
the proposed federal plan and model rules that are being issued 
concurrently with this rule, paves the way for states to implement 
mass-based trading, as some states have requested, reflecting their 
view that mass-based trading provides significant advantages over rate-
based trading.
    Affected EGUs, individually, in aggregate, or in combination with 
other measures undertaken by the state, must achieve the equivalent of 
the CO2 emission performance rates, expressed via the state-
specific rate- and mass-based goals, by 2030.
    (2) Interim CO2 emission performance rates and state-specific 
goals.
    The best system of emission reduction includes both the measures 
for reducing CO2 emissions and the timeframe over which they 
can be implemented. In this final action, the EPA is establishing an 8-
year interim period, beginning in 2022 instead of 2020, over which to 
achieve the full required reductions to meet the CO2 
performance rates, a commencement date more than six years from October 
23, 2015, the date of this rulemaking. This 8-year interim period from 
2022 through 2029 is separated into three steps, 2022-2024, 2025-2027, 
and 2028-2029, each associated with its own interim CO2 
emission performance rates. The interim steps are presented both in 
terms of emission performance rates for the two subcategories of 
affected EGUs and in terms of state goals, expressed both as a rate and 
as a mass. A state may adopt emission standards for its sources that 
are identical to these interim emission performance rates or, 
alternatively, adapt these steps to accommodate the timing of expected 
reductions, as long as the state's interim goal is met over the 8-year 
period.
    f. State plans.\7\
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    \7\ The CAA section 111(d) emission guidelines apply to the 50 
states, the District of Columbia, U.S. territories, and any Indian 
tribe that has been approved by the EPA pursuant to 40 CFR 49.9 as 
eligible to develop and implement a CAA section 111(d) plan. In this 
preamble, in instances where these governments are not specifically 
listed, the term ``state'' is used to represent them. Because 
Vermont and the District of Columbia do not have affected EGUs, they 
will not be required to submit a state plan. Because the EPA does 
not possess all of the information or analytical tools needed to 
quantify the BSER for the two non-contiguous states with affected 
EGUs (Alaska and Hawaii) and the two U.S. territories with affected 
EGUs (Guam and Puerto Rico), we are not finalizing emission 
performance rates in those areas at this time, and those areas will 
not be required to submit state plans until we do.
---------------------------------------------------------------------------

    In this action, the EPA is establishing final guidelines for states 
to follow in developing, submitting and implementing their plans. In 
developing plans, states will need to choose the type of plan they will 
develop. They will also need to include required plan components in 
their plan submittals, meet plan submittal deadlines, achieve the 
required CO2 emission reductions over time, and provide for 
monitoring and periodic reporting of progress. As with the BSER 
determination, stakeholder comments have provided both data and 
recommendations to which these final guidelines are responsive.
    (1) Plan approaches.
    To comply with these emission guidelines, a state will have to 
ensure, through its plan, that the emission standards it establishes 
for its sources individually, in aggregate, or in combination with 
other measures undertaken by the state, represent the equivalent of the 
subcategory-specific CO2 emission performance rates. This 
final rule includes several options for state plans, as discussed in 
the proposal and in many of the comments we received.
    First, in the final rule, states may establish emission standards 
for their affected EGUs that mirror the uniform emission performance 
rates for the two subcategories of sources included in this final rule. 
They may also pursue alternative approaches that adopt emission 
standards that meet the

[[Page 64668]]

uniform emission performance rates, or emission standards that meet 
either the rate-based goal promulgated for the state or the alternative 
mass-based goal promulgated for the state. It is for the purpose of 
providing states with these choices that the EPA is providing state-
specific rate-based and mass-based goals equivalent to the emission 
performance rates that the EPA is establishing for the two 
subcategories of fossil fuel-fired EGUs. A detailed explanation of 
rate- and mass-based goals is provided in section VII of this preamble 
and in a TSD.\8\ In developing its plan, each state and eligible tribe 
electing to submit a plan will need to choose whether its plan will 
result in the achievement of the CO2 emission performance 
rates, statewide rate-based goals, or statewide mass-based goals by the 
affected EGUs.
---------------------------------------------------------------------------

    \8\ The CO2 Emission Performance Rate and Goal 
Computation TSD for the CPP Final Rule, available in the docket for 
this rulemaking.
---------------------------------------------------------------------------

    The second major set of options provided in the final rule includes 
the types of measures states may rely on through the state plans. A 
state will be able to choose to establish emission standards for its 
affected EGUs sufficient to meet the requisite performance rates or 
state goal, thus placing all of the requirements directly on its 
affected EGUs, which we refer to as the ``emission standards 
approach.'' Alternatively, a state can adopt a ``state measures 
approach,'' which would result in the affected EGUs meeting the 
statewide mass-based goal by allowing a state to rely upon state-
enforceable measures on entities other than affected EGUs, in 
conjunction with any federally enforceable emission standards the state 
chooses to impose on affected EGUs. With a state measures approach, the 
plan must also include a contingent backstop of federally enforceable 
emission standards for affected EGUs that fully meet the emission 
guidelines and that would be triggered if the plan failed to achieve 
the required emission reductions on schedule. A state would have the 
option of basing its backstop emission standards on the model rule, 
which focuses on the use of emissions trading as the core mechanism and 
which the EPA is proposing today. A state that adopts a state measures 
approach must use its mass CO2 emission goal as the metric 
for demonstrating plan performance.
    The final rule requires that the state plan submittal include a 
timeline with all of the programmatic plan milestone steps the state 
will take between the time of the state plan submittal and the year 
2022 to ensure that the plan is effective as of 2022. States must 
submit a report to the EPA in 2021 that demonstrates that the state has 
met the programmatic plan milestone steps that the state indicated it 
would take during the period from the submittal of the final plan 
through the end of 2020, and that the state is on track to implement 
the approved state plan as of January 1, 2022.
    The plan must also include a process for reporting on plan 
implementation, progress toward achieving CO2 emission 
reductions, and implementation of corrective actions, in the event that 
the state fails to achieve required emission levels in a timely 
fashion. Beginning January 1, 2025, and then January 1, 2028, January 
1, 2030, and then every two calendar years thereafter, the state will 
be required to compare emission levels achieved by affected EGUs in the 
state with the emission levels projected in the state plan and report 
the results of that comparison to the EPA by July 1 of those calendar 
years.
    Existing state programs can be aligned with the various state plan 
options further described in Section VIII. A state plan that uses one 
of the finalized model rules, which the EPA is proposing concurrently 
with this action, could be presumptively approvable if the state plan 
meets all applicable requirements.\9\ 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.
---------------------------------------------------------------------------

    \9\ The EPA would take action on such a state plan through 
independent notice and comment rulemaking.
---------------------------------------------------------------------------

    State plan approaches and plan guidelines are explained further in 
section VIII of this preamble.
    (2) State plan components and approvability criteria.
    The EPA's implementing regulations provide certain basic elements 
required for state plans submitted pursuant to CAA section 111(d).\10\ 
In the proposal, the EPA identified certain additional elements that 
should be contained in state plans. In this final action, in response 
to comments, the EPA is making several revisions to the components 
required in a state plan submittal and is also incorporating the 
approvability criteria into the final list of components required in a 
state plan submittal. In addition, we have organized the state plan 
components to reflect: (1) Components required for all state plan 
submittals; (2) additional components required for the emission 
standards approach; and (3) additional components required for the 
state measures approach.
---------------------------------------------------------------------------

    \10\ 40 CFR 60.23.
---------------------------------------------------------------------------

    All state plans must include the following components:

     Description of the plan
     Applicability of state plans to affected EGUs
     Demonstration that the plan submittal is projected to 
achieve the state's CO2 emission performance rates or 
state CO2 goal \11\
---------------------------------------------------------------------------

    \11\ A state that chooses to set emission standards that are 
identical to the emission performance rates for both the interim 
period and in 2030 and beyond need not identify interim state goals 
nor include a separate demonstration that its plan will achieve the 
state goals.
---------------------------------------------------------------------------

     Monitoring, reporting and recordkeeping requirements 
for affected EGUs
     State recordkeeping and reporting requirements
     Public participation and certification of hearing on 
state plan
     Supporting documentation

    Also, in submitting state plans, states must provide documentation 
demonstrating that they have considered electric system reliability in 
developing their plans.
    Further, in this final rule, the EPA is requiring states to 
demonstrate how they are meaningfully engaging all stakeholders, 
including workers and low-income communities, communities of color, and 
indigenous populations living near power plants and otherwise 
potentially affected by the state's plan. In their plan submittals, 
states must describe their engagement with their stakeholders, 
including their most vulnerable communities. The participation of these 
communities, along with that of ratepayers and the public, can be 
expected to help states ensure that state plans maintain the 
affordability of electricity for all and preserve and expand jobs and 
job opportunities as they move forward to develop and implement their 
plans.
    State plan submittals using the emission standards approach must 
also include:

     Identification of each affected EGU; identification of 
federally enforceable emission standards for the affected EGUs; and 
monitoring, recordkeeping and reporting requirements.
     Demonstrations that each emission standard will result 
in reductions that are quantifiable, non-duplicative, permanent, 
verifiable, and enforceable.

    State plan submittals using the state measures approach must also 
include:

     Identification of each affected EGU; identification of 
federally enforceable emission standards for affected EGUs (if 
applicable); identification of backstop of

[[Page 64669]]

federally enforceable emission standards; and monitoring, 
recordkeeping and reporting requirements.
     Identification of each state measure and demonstration 
that each state measure will result in reductions that are 
quantifiable, non-duplicative, permanent, verifiable, and 
enforceable.

    In addition to these requirements, each state plan must follow the 
EPA implementing regulations at 40 CFR 60.23.
    (3) Timing and process for state plan submittal and review.
    Because of the compelling need for actions to begin the steps 
necessary to reduce GHG emissions from EGUs, the EPA proposed that 
states submit their plans within 13 months of the date of this final 
rule and that reductions begin in 2020. In light of the comments 
received and in order to provide maximum flexibility to states while 
still taking timely action to reduce CO2 emissions, in this 
final rule the EPA is allowing for a 2-year extension until September 
6, 2018, for both individual and multi-state plans, to provide a total 
of 3 years for states to submit a final plan if an extension is 
received. Specifically, the final rule requires each state to submit a 
final plan by September 6, 2016. Since 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, a robust public participation process, coordination with 
third parties, coordination among states involved in multi-state plans, 
and consultation with reliability entities, the EPA is allowing an 
optional two-phased submittal process for state plans. If a state needs 
additional time to submit a final plan, then the state may request an 
extension by submitting an initial submittal by September 6, 2016. For 
the extension to be granted, the initial submittal must address three 
required components sufficiently to demonstrate that a state is able to 
undertake steps and processes necessary to timely submit a final plan 
by the extended date of September 6, 2018. These components are: An 
identification of final plan approach or approaches under 
consideration, including a description of progress made to date; an 
appropriate explanation for why the state needs additional time to 
submit a final plan beyond September 6, 2016; and a demonstration of 
how they have been engaging with the public, including vulnerable 
communities, and a description of how they intend to meaningfully 
engage with community stakeholders during the additional time (if an 
extension is granted) for development of the final plan, as described 
in section VIII.E of this preamble. As further described in section 
VIII.B of this preamble, the EPA is establishing a CEIP in order to 
promote early action. States' participation in the CEIP is optional. In 
order for a state to participate in the program, it must include in its 
initial submittal, if applicable, a non-binding statement of intent to 
participate in the CEIP; if a state is submitting a final plan by 
September 6, 2016, it must include such a statement of intent as part 
of its supporting documentation for the plan.
    If the initial submittal includes those components and if the EPA 
does not notify the state that the initial submittal does not contain 
the required components, then, within 90 days of the submittal, the 
extension of time to submit a final plan will be deemed granted. A 
state will then have until no later than September 6, 2018, to submit a 
final plan. The EPA will also be working with states during the period 
after they make their initial submittals and provide states with any 
necessary information and assistance during the 90-day period. Further, 
states participating in a multi-state plan may submit a single joint 
plan on behalf of all of the participating states.
    States and tribes that do not have any affected EGUs in their 
jurisdictional boundaries may provide emission rate credits (ERCs) to 
adjust CO2 emissions, provided they are connected to the 
contiguous U.S. grid and meet other requirements for eligibility. There 
are certain limitations and restrictions for generating ERCs, and 
these, as well as associated requirements, are explained in section 
VIII of this preamble.
    Following submission of final plans, the EPA will review plan 
submittals for approvability. Given a similar timeline accorded under 
section 110 of the CAA, and the diverse approaches states may take to 
meet the CO2 emission performance rates or equivalent 
statewide goals in the emission guidelines, the EPA is extending the 
period for EPA review and approval or disapproval of plans from the 
four-month period provided in the EPA implementing regulations to a 
twelve-month period. This timeline will provide adequate time for the 
EPA to review plans and follow notice-and-comment rulemaking procedures 
to ensure an opportunity for public comment. The EPA, especially 
through our regional offices, will be available to work with states as 
they develop their plans, in order to make review of submitted plans 
more straightforward and to minimize the chances of unexpected issues 
that could slow down approval of state plans.
    (4) Timing for implementing the CO2 emission guidelines.
    The EPA recognizes that the measures states and utilities have been 
and will be taking to reduce CO2 emissions from existing 
EGUs can take time to implement. We also recognize that investments in 
low-carbon intensity and RE and in EE strategies are currently underway 
and in various stages of planning and implementation widely across the 
country. We carefully reviewed information submitted to us regarding 
the feasible timing of various measures and identifying concerns that 
the required CO2 emission reductions could not be achieved 
as early as 2020 without compromising electric system reliability, 
imposing unnecessary costs on ratepayers, and requiring investments in 
more carbon-intensive generation, while diverting investment in cleaner 
technologies. The record is compelling. To respond to these concerns 
and to reflect the period of time required for state plan development 
and submittal by states, review and approval by the EPA, and 
implementation of approved plans by states and affected EGUs, the EPA 
is determining in this final rule that affected EGUs will be required 
to begin to make reductions by 2022, instead of 2020, as proposed, and 
meet the final CO2 emission performance rates or equivalent 
statewide goals by no later than 2030. The EPA is establishing an 8-
year interim period that begins in 2022 and goes through 2029, and 
which is separated into three steps, 2022-2024, 2025-2027, and 2028-
2029, each associated with its own interim goal. Affected EGUs must 
meet each of the interim period step 1, 2, and 3 CO2 
emission performance rates, or, following the emissions reduction 
trajectory designed by the state itself, must meet the equivalent 
statewide interim period goals, on average, that a state may establish 
over the 8-year period from 2022-2029. The CAA section 111(d) plan must 
include those specific requirements. Affected EGUs must also achieve 
the final CO2 performance rates or the equivalent statewide 
goal by 2030 and maintain that level subsequently. This approach 
reflects adjustments to the timeframe over which reductions must be 
achieved that mirror the determination of the final BSER, which 
incorporates the phasing in of the BSER measures in keeping with the 
achievability of those measures. The agency believes that this approach 
to timing is reasonable and appropriate, is consistent with many of the 
comments we received, and will

[[Page 64670]]

best support the optimization of overall CO2 reductions, 
ratepayer affordability and electricity system reliability.
    The EPA recognizes that successfully achieving reductions by 2022 
will be facilitated by actions and investments that yield 
CO2 emission reductions prior to 2022. The final guidelines 
include provisions to encourage early actions. States will be able to 
take advantage of the impacts of early investments that occur prior to 
the beginning of a plan performance period. Under a mass-based plan, 
those impacts will be reflected in reductions in the reported 
CO2 emissions of affected EGUs during the plan performance 
period. Under a rate-based plan, states may recognize early actions 
implemented after 2012 by crediting MWh of electricity generation and 
savings that are achieved by those measures during the interim and 
final plan performance periods. This provision is discussed in section 
VIII.K of the preamble.
    In addition, to encourage early investments in RE and demand-side 
EE, the EPA is establishing the CEIP. Through this program, detailed in 
section VIII.B of this preamble, states will have the opportunity to 
award allowances and ERCs to qualified providers that make early 
investments in RE, as well as in demand-side EE programs implemented in 
low-income communities. Those states that take advantage of this option 
will be eligible to receive from the EPA matching allowances or ERCs, 
up to a total for all states that represents the equivalent of 300 
million short tons of CO2 emissions.
    The EPA will address design and implementation details of the CEIP 
in a subsequent action. Prior to doing so, the EPA will engage with 
states, utilities and other stakeholders to gather information 
regarding their interests and priorities with regard to implementation 
of the CEIP.
    The CEIP can play an important role in supporting one of the 
critical policy benefits of this rule. The incentives and market signal 
generated by the CEIP can help sustain the momentum toward greater RE 
investment in the period between now and 2022 so as to offset any 
dampening effects that might be created by setting the period for 
mandatory reductions to begin in 2022, two years later than at 
proposal.
    (5) Community and environmental justice considerations.
    Climate change is an environmental justice issue. Low-income 
communities and communities of color already overburdened by pollution 
are disproportionately affected by climate change and are less 
resilient than others to adapt to or recover from climate-change 
impacts. While this rule will provide broad benefits to communities 
across the nation by reducing GHG emissions, it will be particularly 
beneficial to populations that are disproportionately vulnerable to the 
impacts of climate change and air pollution.
    Conventional pollutants emitted by power plants, such as 
particulate matter (PM), SO2, hazardous air pollutants 
(HAP), and nitrogen oxides (NOx), will also be reduced as 
the plants reduce their carbon emissions. These pollutants can have 
significant adverse local and regional health impacts. The EPA analyzed 
the communities in closest proximity to power plants and found that 
they include a higher percentage of communities of color and low-income 
communities than national averages. We thus expect an important co-
benefit of this rule to be a reduction in the adverse health impacts of 
air pollution on these low-income communities and communities of color. 
We refer to these communities generally as ``vulnerable'' or 
``overburdened,'' to denote those communities least resilient to the 
impacts of climate change and central to environmental justice 
considerations.
    While pollution will be cut from power plants overall, there may be 
some relatively small number of coal-fired plants whose operation and 
corresponding emissions increase as energy providers balance energy 
production across their fleets to comply with state plans. In addition, 
a number of the highest-efficiency natural gas-fired units are also 
expected to increase operations, but they have correspondingly low 
carbon emissions and are also characterized by low emissions of the 
conventional pollutants that contribute to adverse health effects in 
nearby communities and regionally. The EPA strongly encourages states 
to evaluate the effects of their plans on vulnerable communities and to 
take the steps necessary to ensure that all communities benefit from 
the implementation of this rule. In order to identify whether state 
plans are causing any adverse impacts on overburdened communities, 
mindful that substantial overall reductions, nevertheless, may be 
accompanied by potential localized increases, the EPA intends to 
perform an assessment of the implementation of this rule to determine 
whether it and other air quality rules are leading to improved air 
quality in all areas or whether there are localized impacts that need 
to be addressed.
    Effective engagement between states and affected communities is 
critical to the development of state plans. The EPA encourages states 
to identify communities that may be currently experiencing adverse, 
disproportionate impacts of climate change and air pollution, how state 
plan designs may affect them, and how to most effectively reach out to 
them. This final rule requires that states include in their initial 
submittals a description of how they engaged with vulnerable 
communities as they developed their initial submittals, as well as the 
means by which they intend to involve communities and other 
stakeholders as they develop their final plans. The EPA will provide 
training and other resources for states and communities to facilitate 
meaningful engagement.
    In addition to the benefits for vulnerable communities from 
reducing climate change impacts and effects of conventional pollutant 
emissions, this rule will also help communities by moving the utility 
industry toward cleaner generation and greater EE. The federal 
government is committed to ensuring that all communities share in these 
benefits.
    The EPA also encourages states to consider how they may incorporate 
approaches already used by other states to help low-income communities 
share in the investments in infrastructure, job creation, and other 
benefits that RE and demand-side EE programs provide, have access to 
financial assistance programs, and minimize any adverse impacts that 
their plans could have on communities. To help support states in taking 
concrete actions that provide economic development, job and electricity 
bill-cutting benefits to low-income communities directly, the EPA has 
designed the CEIP specifically to target the incentives it creates on 
investments that benefit low-income communities.
    Community and environmental justice considerations are discussed 
further in section IX of this preamble.
    (6) Addressing employment concerns.
    In addition, the EPA encourages states in designing their state 
plans to consider the effects of their plans on employment and overall 
economic development to assure that the opportunities for economic 
growth and jobs that the plans offer are realized. To the extent 
possible, states should try to assure that communities that can be 
expected to experience job losses can also take advantage of the 
opportunities for job growth or otherwise transition to healthy, 
sustainable economic growth. The President has proposed the POWER+ Plan 
to help communities impacted by power sector transition. The POWER+ 
plan invests in workers and jobs, addresses important legacy costs in 
coal country, and drives

[[Page 64671]]

development of coal technology.\12\ Implementation of one key part of 
the POWER+ Plan, the Partnerships for Opportunity and Workforce and 
Economic Revitalization (POWER) initiative, has already begun. The 
POWER initiative specifically targets economic and workforce 
development assistance to communities affected by ongoing changes in 
the coal industry and the utility power sector.\13\
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    \12\ https://www.whitehouse.gov/the-press-office/2015/03/27/fact-sheet-partnerships-opportunity-and-workforce-and-economic-revitaliz.
    \13\ http://www.eda.gov/power/.
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    (7) Electric system reliability.
    In no small part thanks to the comments we received and our 
extensive consultation with key agencies responsible for reliability, 
including FERC and DOE, among others, along with EPA's longstanding 
principles in setting emission standards for the utility power sector, 
these guidelines reflect the paramount importance of ensuring electric 
system reliability. The input we received on this issue focused heavily 
on the extent of the reductions required at the beginning of the 
interim period, proposed as 2020. We are addressing these concerns in 
large part by moving the beginning of the period for mandatory 
reductions under the program from 2020 to 2022 and significantly 
adjusting the interim goals so that they provide a less abrupt initial 
reduction expectation. This, in turn, will provide states and utilities 
with a great deal more latitude in determining their emission reduction 
trajectories over the interim period. As a result, there will be more 
time for planning, consultation and decision making in the formulation 
of state plans and in EGUs' choice of compliance strategies, all within 
the existing extensive structure of energy planning at the state and 
regional levels. These adjustments in the interim goals are supported 
by the information in the record concerning the time needed to develop 
and implement reductions under the BSER. In addition, the various forms 
of flexibility retained and enhanced in this final rule, including 
opportunities for trading within and between states, and other multi-
state compliance approaches, will further support electric system 
reliability.
    The final guidelines address electric system reliability in several 
additional important ways. Numerous commenters urged us to include, as 
part of the plan development or approval process, input from review by 
energy regulatory agencies and reliability entities. In the final rule, 
we are requiring that each state demonstrate in its final state plan 
submittal that it has considered reliability issues in developing its 
plan. Second, we recognize that issues may arise during the 
implementation of the guidelines that may warrant adjustments to a 
state's plan in order to maintain electric system reliability. The 
final guidelines make clear that states have the ability to propose 
amendments to approved plans in the event that unanticipated and 
significant electric system reliability challenges arise and compel 
affected EGUs to generate at levels that conflict with their compliance 
obligations under those plans.
    As a final element of reliability assurance, the rule also provides 
for a reliability safety valve for individual sources where there is a 
conflict between the requirements the state plan imposes on a specific 
affected EGU and the maintenance of electric system reliability in the 
face of an extraordinary and unanticipated event that presents 
substantial reliability concerns.
    We anticipate that these situations will be extremely rare because 
the states have the flexibility to craft requirements for their EGUs 
that will provide long averaging periods and/or compliance mechanisms, 
such as trading, whose inherent flexibility will make it unlikely that 
an individual unit will find itself in this kind of situation. As one 
example, under compliance regimes that allow individual EGUs to 
establish compliance through the acquisition and holding of allowances 
or ERCs equal to their emissions, an EGU's need to continue to 
operate--and emit--for the purposes of ensuring system reliability will 
not put the EGU into non-compliance, provided, of course, it obtains 
the needed allowances or credits in a timely fashion. We, nevertheless, 
agree with many commenters that it is prudent to provide an electric 
system reliability safety valve as a precaution.
    Finally, the EPA, DOE and FERC have agreed to coordinate their 
efforts, at the federal level, to help ensure continued reliable 
electricity generation and transmission during the implementation of 
the final rule. The three agencies have set out a memorandum that 
reflects their joint understanding of how they will work together to 
monitor implementation, share information, and to resolve any 
difficulties that may be encountered.
    As a result of the many features of this final rule that provide 
states and affected EGUs with meaningful time and decision making 
latitude, we believe that the comprehensive safeguards already in place 
in the U.S. to ensure electric system reliability will continue to 
operate effectively as affected EGUs reduce their CO2 
emissions under this program.
    (8) Outreach and resources for stakeholders.
    To provide states, U.S. territories, tribes, utilities, 
communities, and other interested stakeholders with understanding about 
the rule requirements, and to provide efficiencies where possible and 
reduce the cost and administrative burden, the EPA will continue to 
work with states, tribes, territories, and stakeholders to provide 
information and address questions about the final rule. Outreach will 
include opportunities for states and tribes to participate in 
briefings, teleconferences, and meetings about the final rule. The 
EPA's ten regional offices will continue to be the entry point for 
states, tribes and territories to ask technical and policy questions. 
The agency will host (or partner with appropriate groups to co-host) a 
number of webinars about various components of the final rule; these 
webinars are planned for the first two months after the final rule is 
issued. The EPA will also offer consultations with tribal governments. 
The EPA will continue outreach throughout the plan development and 
submittal process. The EPA will use information from this outreach 
process to inform the training and other tools that will be of most use 
to the state, tribes, and territories that are implementing the final 
rule.
    The EPA has worked with communities, states, tribes and relevant 
associations to develop an extensive training plan that will continue 
in the months after the Clean Power Plan is finalized. The EPA has 
assembled resources from a variety of sources to create a comprehensive 
training curriculum for those implementing this rule. Recorded 
presentations from the EPA, DOE and other federal entities will be 
available for communities, states, and others involved in composing and 
participating in the development of state plans. This curriculum is 
available online at EPA's Air Pollution Training Institute.
    The EPA also expects to issue guidance on specific topics. As 
guidance documents, tools, templates and other resources become 
available, the EPA, in consultation with DOE and other federal 
agencies, will continue to make these resources available via a 
dedicated Web site.\14\
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    \14\ www.epa.gov/cleanpowerplantoolbox.
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    We intend to continue to work actively with states and tribes, as 
appropriate, to provide information and technical support that will be 
helpful to

[[Page 64672]]

them in developing and implementing their plans. The EPA will engage in 
formal consultations with tribal governments and provide training 
tailored to the needs of tribes and tribal governments.
    Additional detail on aspects of the final rule is included in 
several technical support documents (TSDs) and memoranda that are 
available in the rulemaking docket.
4. Key Changes From Proposal
    a. Overview and highlights. As noted earlier in this overview, the 
June 2014 proposal for the rule was designed to meet the fundamental 
goal of reducing harmful emissions of CO2 from fossil fuel-
fired EGUs in a manner consistent with the CAA requirements, while 
accommodating two important objectives. The first objective was to 
establish guidelines that reflect both the manner in which the power 
system operates and the actions and measures already underway across 
states and the utility power sector that are resulting in 
CO2 emission reductions. The second objective was to provide 
states and utilities maximum flexibility, control and choice in meeting 
their compliance obligations. In this final rule, the EPA has focused 
on changes that, in addition to being responsive to the critical 
concerns and priorities of stakeholders, more fully accomplish these 
two crucial objectives.
    To achieve these objectives, the June 2014 proposal featured 
several important elements: The building block approach for the BSER; 
state-specific, rather than source-specific, goals; a 10-year interim 
goal that could be met ``on average'' over the 10-year period between 
2020 and 2029; and a ``portfolio'' option for state plans. These 
features were intended either to capture, in the emission guidelines, 
emission reduction measures already in widespread use or to maximize 
the range of choices that states and utilities could select in order to 
achieve their emission limitations at low cost while ensuring electric 
system reliability. In this final rule, we are retaining the key design 
elements of the proposal and making certain adjustments to respond to a 
variety of very constructive comments on ways that will implement the 
CAA section 111(d) requirements efficiently and effectively.
    The building block approach is a key feature of the proposal that 
we are retaining in the final rule, but have refined to include only 
the first three building blocks and to reflect implementation of the 
measures encompassed in the building blocks on a broad regional grid-
level. In the proposal, we expressed the emission limitation 
requirements reflecting the BSER in terms of the state goals in order 
to provide states with maximum flexibility and latitude. We viewed this 
as an important feature because each state has its own energy profile 
and state-specific policies and needs relative to the production and 
use of electricity. In the final rule, we extend that flexibility 
significantly in direct response to comments from states and utilities. 
The final rule establishes source-level emission performance rates for 
the source subcategories, while retaining state-level rate- and mass-
based goals. One of the key messages conveyed by state and utility 
commenters was that the final rule should make it easier for states to 
adopt mass-based programs and for utilities accustomed to operating 
across broad multi-state grids to be able to avail themselves of more 
``ready-made'' emissions trading regimes. The inclusion of both of 
these new features--mass-based state goals in addition to rate-based 
goals, and source-level emission performance rates for the two 
subcategories of sources--is intended to make it easier for states and 
utilities to achieve these outcomes. In fact, these additions, together 
with the model rules and federal plan being proposed concurrently with 
this rule, should demonstrate the relative ease with which states can 
adopt mass-based trading programs, including interstate mass-based 
programs that lend themselves to the kind of interstate compliance 
strategies so well suited for integration with the current interstate 
operations of the overall utility grid.
    Many stakeholders conveyed to the EPA that the proposal's interim 
goals for the 2020-2029 period were designed in a way that defeated the 
EPA's objective of allowing states and utilities to shape their 
emission reduction trajectories. They pointed out that, in many cases, 
the timing and stringency of the states' interim goals could require 
actions that could result in high costs, threaten electric system 
reliability or hinder the deployment of renewable technology. In 
response, the EPA has revised the interim goals in two critical ways. 
First, the period for mandatory reductions begin in 2022 rather than 
2020; second, in keeping with the BSER, emission reduction requirements 
are phased in more gradually over the interim period. These changes 
will allow states and utilities to delineate their own emission 
reduction trajectories so as to minimize costs and foster broader 
deployment of RE technologies. The value of these changes is 
demonstrated by our analysis of the final rule, which shows lower 
program costs, especially in the early years of the interim period, and 
greater RE deployment, relative to the analysis of the proposed rule. 
At the same time, this re-design of the interim goals, together with 
refinements we have made to state plan requirements and the inclusion 
of a reliability safety valve, provide states, utilities and other 
entities with the ability to continue to guarantee system reliability.
    b. Outreach, engagement and comment record. This final rule is the 
product of one of the most extensive and long-running public engagement 
processes the EPA has ever conducted, starting in the summer of 2013, 
prior to proposal, and continuing through December 2014, when the 
public comment period ended, and continuing beyond that with 
consultations and meetings with stakeholders. The result of this 
extensive consultation was millions of comments from stakeholders, 
which we have carefully considered over the past several months. The 
EPA gained crucial insights from the more than 4 million comments that 
the agency received on the proposal and associated documents leading to 
this final rulemaking. Comments were provided by stakeholders that 
include state environmental and energy officials, tribal officials, 
public utility commissioners, system operators, owners and operators of 
every type of power generating facility, other industry 
representatives, labor leaders, public health leaders, public interest 
advocates, community and faith leaders, and members of the public.
    The insights gained from public comments contributed to the 
development of final emission guidelines that build on the proposal and 
the alternatives on which we sought comment. The modifications 
incorporated in the final guidelines are directly responsive to the 
comments we received from the many and diverse stakeholders. The 
improved guidelines reflect information and ideas that states and 
utilities provided to us about both the best approach to establishing 
CO2 emission reduction requirements for EGUs and the most 
effective ways to create true flexibility for states and utilities in 
meeting these requirements. These final rules also reflect the results 
of EPA's robust consultation with federal, state and regional energy 
agencies and authorities, to ensure that the actions sources will take 
to reduce GHG emissions will not compromise electric system reliability 
or affordability of the U.S. electricity supply. Input and assistance 
from FERC

[[Page 64673]]

and DOE have been particularly important in shaping some provisions in 
these final guidelines. At the same time, input from faith-based, 
community-based and environmental justice organizations, who provided 
thoughtful comments about the potential impacts of this rule on 
pollution levels in overburdened communities and economic impacts, 
including utility rates in low-income communities, is also reflected in 
this rule. The final rule also reflects our response to concerns raised 
by labor leaders regarding the potential effects on workers and 
communities of the transition away from higher-emitting power 
generation to lower- and zero-emitting power generation.
    c. Key changes. The most significant changes in these final 
guidelines are: (1) The period for mandatory emission reductions 
beginning in 2022 instead of 2020 and a gradual application of the BSER 
over the 2022-2029 interim period, such that a state has substantial 
latitude in selecting its own emission reduction trajectory or ``glide 
path'' over that period, (2) a revised BSER determination that focuses 
on narrower generation options that do not include demand-side EE 
measures and that includes refinements to the building blocks, more 
complete incorporation in the BSER of the realities of electricity 
operations over the three regional interconnections, and up-to-date 
information about the cost and availability of clean generation 
options, (3) establishment of source-specific CO2 emission 
performance rates that are uniform across the two fossil fuel-fired 
subcategories covered in these guidelines, as well as rate- and mass-
based state goals, to facilitate emission trading, including interstate 
trading and, in particular, mass-based trading, (4) a variation on the 
proposal's ``portfolio'' option for state plans--called here the 
``state measures'' approach--that continues to provide states 
flexibility while ensuring that all state plans have federally 
enforceable measures as a backstop, (5) additional, more flexible 
options for states and utilities to adopt multi-state compliance 
strategies, (6) an extension of up to two years available to all states 
for submittal of their final compliance plans following making initial 
submittals in 2016, (7) provisions to encourage actions that achieve 
early reductions, including a Clean Energy Incentive Program (CEIP), 
(8) a combination of provisions expressly designed to ensure electric 
system reliability, (9) the addition of employment considerations for 
states in plan development, and (10) the expansion of considerations 
and programs for low-income and vulnerable communities.
    We provide summary explanations in the following paragraphs and 
more detailed explanations of all of these changes in later sections of 
this preamble and associated documents.
    (1) Mandatory reduction period beginning in 2022 and a gradual 
glide path.
    The proposal's mandatory emission reduction period beginning in 
2020 and the trajectory of emission reduction requirements in the 
interim period were both the subjects of significant comment. Earlier 
this year, FERC conducted a series of technical conferences comprising 
one national session and three regional sessions. The information 
provided by workshop participants echoed much of the material that had 
been submitted to the comment record for this rulemaking. On May 15, 
2015, the FERC Commissioners, drawing upon information highlighted at 
the technical conferences, transmitted to the EPA some suggestions for 
the final rule. In addition, via comments, states, utilities, and 
reliability entities asked us to ensure adequate time for them to 
implement strategies to achieve CO2 reductions. They 
expressed concern that, in the proposal, at least some states would be 
required to reduce emissions in 2020 to levels that would require 
abrupt shifts in generation in ways that raised concerns about impacts 
to electric system reliability and ratepayer bills, as well as about 
stranded assets. To many commenters, the proposal's requirement for 
CO2 emission reductions beginning in 2020, together with the 
stringency of the interim CO2 goal, posed significant 
reliability implications, in particular. In this final rule, the agency 
is addressing these concerns, in part, by adjusting the compliance 
timeframe from a 10-year interim period that begins in 2020 to an 8-
year interim period that begins in 2022, and by refining the approach 
for meeting interim CO2 emission performance rates to be a 
gradual glide path separated into three steps, 2022-2024, 2025-2027, 
and 2028-2029, that is also achievable ``on average'' over the 8-year 
interim period. In response to the concerns of commenters that the 
proposal's 10-year interim target failed to afford sufficient 
flexibility, the final guidelines' approach will provide states with 
realistic options for customizing their emission reduction 
trajectories. Of equal importance, the approach provides more time for 
planning, consultation and decision making in the formulation of state 
plans and in EGUs' choices of compliance strategies. Both FERC's May 
15, 2015 letter and the comment record, as well as other information 
sources, made it clear that providing sufficient time for planning and 
implementation was essential to ensuring electric system reliability.
    The final guidelines' approach to the interim emission performance 
rates is the result of the application of the measures constituting the 
BSER in a more gradual way, reflecting stakeholder comments and 
information about the appropriate period of time over which those 
measures can be deployed consistent with the BSER factors of cost and 
feasibility. In addition to facilitating reliable system operations, 
these changes provide states and utilities with the latitude to 
consider a broader range of options to achieve the required reductions 
while addressing concerns about ratepayer impacts and stranded assets.
    (2) Revised BSER determination.
    Commenters urged the EPA to confine its BSER determination to 
actions that involve what they characterized as more ``traditional'' 
generation. While some stakeholders recognized demand-side EE as being 
an integral part of the electricity system, with many of the 
characteristics of more traditional generating resources, other 
stakeholders did not. As explained in section V.B.3.c.(8) below, our 
traditional interpretation and implementation of CAA section 111 has 
allowed regulated entities to produce as much of a particular good as 
they desire, provided that they do so through an appropriately clean 
(or low-emitting) process. While building blocks 1, 2, and 3 fall 
squarely within this paradigm, the proposed building block 4 does not. 
In view of this, since the BSER must serve as the foundation of the 
emission guidelines, the EPA has not included demand-side EE as part of 
the final BSER determination. Thus, neither the final guidelines' BSER 
determination nor the emission performance rates for the two 
subcategories of affected EGUs take into account demand-side EE. 
However, many commenters also urged the EPA to allow states and sources 
to rely on demand-side EE as an element of their compliance strategies, 
as demand-side EE is treated as functionally interchangeable with other 
forms of generation for planning and operational purposes, as EE 
measures are in widespread use across the country and provide energy 
savings that reduce emissions, lower electric bills, and lead to 
positive investments and job creation. We agree, and the final 
guidelines provide ample latitude for states and utilities to rely on 
demand-side EE in

[[Page 64674]]

meeting emission reduction requirements.
    In response to stakeholder comments on the first three building 
blocks and considerable data in the record, the EPA has made 
refinements to the building blocks, and these are reflected in the 
final BSER. Refinements include adoption of a modified approach to 
quantification of the RE component, exclusion of the proposed nuclear 
generation components, and adoption of a consistent regionalized 
approach to quantification of all three building blocks. 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 practically and at 
reasonable cost. Therefore, the final BSER also reflects adjustments to 
the stringency of the building blocks, after consideration of more and 
less stringent levels, and refinements to the timeframe over which 
reductions must be achieved. Sections V.C through V.E of this preamble 
provide further information on the refinements made to the building 
blocks and the rationale for doing so.
    Commenters pointed out--and practical experience confirms--what is 
widely known: That the utility power sector operates over regional 
interconnections that are not constrained by state borders. Across a 
variety of issues raised in the proposal, many commenters urged that 
the EPA take that reality into account in developing this final rule. 
Consequently, the BSER determination itself (as well as a number of new 
compliance features included in this final rule) and the resulting 
subcategory-specific emission performance rates take into account the 
grid-level operations of the source category.
    The final guidelines' BSER determination also takes into account 
recent reductions in the cost of clean energy technology, as well as 
projections of continuing cost reductions, and continuing increases in 
RE deployment. We also updated the underlying analysis with the most 
recent Energy Information Administration (EIA) projections that show 
lower growth in electricity demand between 2020 and 2030 than 
previously projected. In keeping with these recent EIA projections, we 
expect the final guidelines will be more conducive to compliance, 
consistent with a strategy that allows for the cleanest power 
generation and greater CO2 reductions in 2030 than the 
proposal. With a date of 2022, instead of 2020, as proposed, for the 
mandatory CO2 emission reduction period to begin, the final 
guidelines reflect that the additional time aligns with the adoption of 
lower-cost clean technology and, thus, its incorporation in the BSER at 
higher levels. At the same time, the 2022-2029 interim period will more 
easily allow for companies to take advantage of improved clean energy 
technologies as potential least cost options.
    (3) Uniform emission performance rates.
    Some stakeholders commented that the proposal's approach of 
expressing the BSER in terms of state-specific goals deviated from the 
requirements of CAA section 111 and from previous new source 
performance standards (NSPS). The effect, they stated, was that the 
proposal created de facto emission standards for all affected EGUs but 
that these de facto standards varied widely depending on the state in 
which a given EGU happened to be located. Instead, these and other 
commenters stated, section 111 requires that EPA establish the BSER 
specifically for affected sources, rather than by means of merely 
setting state-specific goals, and that these standards be uniform. 
Still other commenters observed that the effect of the approach taken 
in the proposal of applying the BSER to each state's fleet was to put a 
greater burden of reductions on lower-emitting or less carbon-intensive 
states and a lesser emission reduction burden on sources and states 
that were higher-emitting or more carbon-intensive. This, they argued, 
was both inequitable and at odds with the way in which NSPS have been 
applied in the past, where the higher-emitting sources have made the 
greater and more cost-effective reductions, while lower-emitting 
sources, whose reduction opportunities tend to be less cost-effective, 
have been required to make fewer reductions to meet the applicable 
standard.
    At the same time, state and utility commenters expressed concern 
that relying on state-specific goals and state-by-state planning could 
introduce complexity into the otherwise seamless integrated operation 
of affected EGUs across the multi-state grids on which system 
operators, states and utilities currently rely and intend to continue 
to rely. Accordingly, they recommended that the final guidelines 
facilitate emissions trading, in particular interstate trading, which 
would enable EGU operators to integrate compliance with CO2 
emissions limitations with facility and grid-level operations. These 
sets of comments intersected at the point at which they focused on the 
fact that it is at the source level at which the standard is set for 
NSPS and at the source level at which compliance must be achieved.
    The EPA carefully considered these comments and while we believe 
that the approach we took at proposal was well-founded and reflected a 
number of important considerations, we have concluded that there is a 
way to address these concerns while expanding upon the advantages 
offered by the proposal. Accordingly, the final guidelines establish 
uniform rates for the two subcategories of sources--an approach that is 
valuable for creating greater equity between and among utilities and 
states with widely varying emission levels and for expanding the 
flexibility of the program, especially in ways that have been 
identified as important to utilities and states. Specifically, the 
final guidelines express the BSER by means of performance-based 
CO2 emission rates that are uniform across each of two 
subcategories--fossil fuel-fired electric steam generating units and 
stationary combustion turbines--for the affected EGUs covered by the 
guidelines. The rates are determined, in part, by applying the 
methodology identified in the Notice of Data Availability (NODA) 
published on October 30, 2014, which was based on the proposal's 
building block approach. The final guidelines also maintain the 
approach adopted in the proposal of establishing state-level goals; in 
the final rule, those goals are equal to the weighted aggregate of the 
two emission performance rates as applied to the EGUs in each state.
    This approach rectifies what would have been an inefficient, 
unintended outcome of putting the greater reduction burden on lower-
emitting sources and states while exempting higher-emitting sources and 
states. Expressing the BSER by means of these rates also augments the 
range of options for both states and EGUs for securing needed 
flexibility. Inclusion of state goals creates latitude for states as to 
how they will meet the guidelines. States also may meet the guideline 
requirements by adopting the CO2 emission performance rates 
as emission standards that apply to the affected EGUs in their 
jurisdiction. Such an approach would lend itself to the ready 
establishment of intra-state and interstate trading, with the uniform 
rate-based standards of performance established for each EGU as the 
basis for such trading. At the same time, as at proposal, each state 
also has the option of complying with these guidelines by adopting a 
plan that takes a different approach to setting standards of 
performance for its EGUs and/or by applying complementary or 
alternative

[[Page 64675]]

measures to meet the state goal set by these guidelines--as either a 
rate or a mass total.
    During the outreach process and through comments, a number of state 
officials and other stakeholders expressed concern that the EPA's 
approach at proposal necessitated or represented a significant 
intrusion into state-level energy policy-making, drawing the EPA well 
beyond the bounds of its CAA authority and expertise. In fact, these 
final guidelines are entirely respectful of the EPA's responsibility 
and authority to regulate sources of air pollution. Instead, by 
establishing and operating through uniform performance rates for the 
two subcategories of sources that can be applied by states at the 
individual source level and that can readily be implemented through 
emission standards that incorporate emissions trading, these final 
guidelines align with the approach Congress and the EPA have 
consistently taken to regulating emissions from this and other 
industrial sectors, namely setting source-level, source category-wide 
standards that individual sources can meet through a variety of 
technologies and measures.
    We emphasize, at the same time, that while the final guidelines 
express the BSER by means of source-level CO2 emission 
performance rates, as well as state-level goals, as at proposal, each 
state will have a goal reflecting its particular mix of sources, and 
the final guidelines retain the flexibility inherent in the proposal's 
state-specific goals approach (and, as discussed in section VIII of 
this preamble, enhanced in various ways). Thus, in keeping with the 
proposal's flexibility, states may choose to adopt either the emission 
performance rates as emission standards for their sources, set 
different but, in the aggregate, equivalent rates, or fulfill their 
obligations by meeting their respective individual state goals.
    (4) State plan approaches.
    Commenters expressed support for the objectives served by the 
``portfolio'' option in the state plan approaches included at proposal, 
but many raised concerns about its legality, with respect, in 
particular, to the CAA's enforceability requirements. Some of these 
commenters identified a ``state commitment approach'' with backstop 
measures as a variation of the ``portfolio'' approach that would retain 
the benefits of the ``portfolio'' approach while resolving legal and 
enforceability concerns. In this final rule, in response to stakeholder 
comments on the portfolio approach and alternative approaches, the EPA 
is finalizing two approaches: A source-based ``emission standards'' 
approach, and a ``state measures'' approach. Through the latter, states 
may adopt a set of policies and programs, which would not be federally 
enforceable, except that any standards imposed on affected EGUs would 
be federally enforceable. In addition, states would be required to 
include federally enforceable backstop measures applicable to each 
affected EGU in the event that the measures included in the state plan 
failed to achieve the state plan's emissions reduction trajectory. 
Under these guidelines, states can implement the BSER through standards 
of performance incorporating the uniform performance rates or 
alternative but in the aggregate equivalent rates, or they can adopt 
plans that achieve in aggregate the equivalent of the subcategory-
specific CO2 emission performance rates by relying on other 
measures undertaken by the state that complement source-specific 
requirements or, save for the contingent backstop requirement, supplant 
them entirely. This revision provides consistency in the treatment of 
sources while still providing maximum flexibility for states to design 
their plans around reduction approaches that best suit their policy 
objectives.
    (5) Emission trading programs.
    Many state and utility commenters supported the use of mass-based 
and rate-based emission trading programs in state plans, including 
interstate emission trading programs, and either pointed out obstacles 
to establishing such programs or suggested approaches that would 
enhance states' and utilities' ability to create and participate in 
such programs.
    Through a combination of features retained from the proposal and 
changes made to the proposal, these final guidelines provide states and 
utilities with a panoply of tools that greatly facilitate their putting 
in place and participating in emissions trading programs. These 
include: (1) Expressing BSER in uniform emission performance rates that 
states may rely on in setting emission standards for affected EGUs such 
that EGUs operating under such standards readily qualify to trade with 
affected EGUs in states that adopt the same approach, (2) promulgating 
state mass goals so that states can move quickly to establish mass-
based programs such that their affected EGUs readily qualify to trade 
with affected EGUs in states that adopt the same approach, and (3) 
providing EPA resources and capacity to create a tracking system to 
support state emissions trading programs.
    (6) Extension of plan submittal date.
    Stakeholders, particularly states, provided compelling information 
establishing that it could take longer than the agency initially 
anticipated for the states to develop and submit their required plans. 
While the approach at proposal reflected the EPA's conclusion that it 
was essential to the environmental and economic purposes of this 
rulemaking that utilities and states establish the path towards 
emissions reductions as early as possible, we recognize commenters' 
concerns. To strike the proper balance, the EPA has developed a revised 
state plan submittal schedule. For states that cannot submit a final 
plan by September 6, 2016, the EPA is requiring those states to make an 
initial submittal by that date to assure that states begin to address 
the urgent needs for reductions quickly, and is providing until 
September 6, 2018, for states to submit a final plan, if an extension 
until that date is justified, to address the concern that a submitting 
state needs more time to develop comprehensive plans that reflect the 
full range of the state's and its stakeholders' interests.
    (7) Provisions to encourage early action.
    Many commenters supported providing incentives for states and 
utilities to deploy CO2-reducing investments, such as RE and 
demand-side EE measures, as early as possible. We also received 
comments from stakeholders regarding the disproportionate burdens that 
some communities already bear, and stating that all communities should 
have equal access to the benefits of clean and affordable energy. The 
EPA recognizes the validity and importance of these perspectives, and 
as a result has determined to provide a program--called the CEIP--in 
which states may choose to participate.
    The CEIP is designed to incentivize investment in certain RE and 
demand-side EE projects that commence construction, in the case of RE, 
or commence construction, in the case of demand-side EE, following the 
submission of a final state plan to the EPA, or after September 6, 
2018, for states that choose not to submit a final state plan by that 
date, and that generate MWh (RE) or reduce end-use energy demand (EE) 
during 2020 and/or 2021. State participation in the program is 
optional.
    Under the CEIP, a state may set aside allowances from the 
CO2 emission budget it establishes for the interim plan 
performance period or may generate early action ERCs (ERCs are 
discussed in more detail in section VIII.K.2), and allocate these 
allowances or ERCs to

[[Page 64676]]

eligible projects for the MWh those projects generate or the end-use 
energy savings they achieve in 2020 and/or 2021. For each early action 
allowance or ERC a state allocates to such projects, the EPA will 
provide the state with an appropriate number of matching allowances or 
ERCs for the state to allocate to the project. The EPA will match 
state-issued early action ERCs and allowances up to an amount that 
represents the equivalent of 300 million short tons of CO2 
emissions.
    For a state to be eligible for a matching award of allowances or 
ERCs from the EPA, it must demonstrate that it will award allowances or 
ERCs only to ``eligible'' projects. These are projects that:
     Are located in or benefit a state that has submitted a 
final state plan that includes requirements establishing its 
participation in the CEIP;
     Are implemented following the submission of a final state 
plan to the EPA, or after September 6, 2018, for a state that chooses 
not to submit a complete state plan by that date;
     For RE: Generate metered MWh from any type of wind or 
solar resources;
     For EE: Result in quantified and verified electricity 
savings (MWh) through demand-side EE implemented in low-income 
communities; and
     Generate or save MWh in 2020 and/or 2021.
    The following provisions outline how a state may award early action 
ERCs and allowances to eligible projects, and how the EPA will provide 
matching ERCs or allowances to states.
     For RE projects that generate metered MWh from any type of 
wind or solar resources: For every two MWh generated, the project will 
receive one early action ERC (or the equivalent number of allowances) 
from the state, and the EPA will provide one matching ERC (or the 
equivalent number of allowances) to the state to award to the project.
     For EE projects implemented in low-income communities: For 
every two MWh in end-use demand savings achieved, the project will 
receive two early action ERCs (or the equivalent number of allowances) 
from the state, and the EPA will provide two matching ERCs (or the 
equivalent number of allowances) to the state to award to the project.
    Early action allowances or ERCs awarded by the state, and matching 
allowances or ERCs awarded by the EPA pursuant to the CEIP, may be used 
for compliance by an affected EGU with its emission standards and are 
fully transferrable prior to such use.
    The EPA discusses the CEIP in the proposed federal plan rule and 
will address design and implementation details of the CEIP in a 
subsequent action. Prior to doing so, the EPA will engage with states, 
utilities and other stakeholders to gather information regarding their 
interests and priorities with regard to implementation of the CEIP.
    (8) Provisions for electric system reliability.
    A number of commenters stressed the importance of final guidelines 
that addressed the need to ensure that EGUs could meet their emission 
reduction requirements without being compelled to take actions that 
would undermine electric system reliability. As noted above, the EPA 
has consulted extensively with federal, regional and state energy 
agencies, utilities and many others about reliability concerns and ways 
to address them. The final guidelines support electric system 
reliability in a number of ways, some inherent in the improvements made 
in the program's design and some through specific provisions we have 
included in the final rule. Most important are the two key changes we 
made to the interim goal: Establishing 2022, instead of 2020, as the 
period for mandatory emission reductions begin and phasing in, over the 
8-year period, emission performance rates such that the level of 
stringency of the emission performance rates in 2022-2024 is 
significantly less than that for the years 2028 and 2029. Since states 
and utilities need only to meet their interim goal ``on average'' over 
the 8-year period, these changes provide them with a great deal of 
latitude in determining for themselves their emission reduction 
trajectory--and they have additional time to do so. As a result, the 
final guidelines provide the ingredients that commenters, reliability 
entities and expert agencies told the EPA were essential to ensuring 
electric system reliability: Time and flexibility sufficient to allow 
for planning, implementation and the integration of actions needed to 
address reliability while achieving the required emissions reductions.
    In addition, the final guidelines add a requirement, based on 
substantial input from experts in the energy field, for states to 
demonstrate that they have considered electric system reliability in 
developing their state plans. The final rule also offers additional 
opportunities that support electric system reliability, including 
opportunities for trading within and between states. The final 
guidelines also make clear that states can adjust their plans in the 
event that reliability challenges arise that need to be remedied by 
amending the state plan. In addition, the final rule includes a 
reliability safety valve to address situations where, because of an 
unanticipated catastrophic event, there is a conflict between the 
requirements imposed on an affected unit and the maintenance of 
reliability.
    (9) Approaches for addressing employment concerns.
    Some commenters brought to our attention the concerns of workers, 
their families and communities, particularly in coal-producing regions 
and states, that the ongoing shift toward lower-carbon electricity 
generation that the final rule reflects will cause harm to communities 
that are dependent on coal. Others had concerns about whether new jobs 
created as a result of actions taken pursuant to the final rule will 
allow for overall economic development. In the final rule, the EPA 
encourages states, in designing their state plans, to consider the 
effects of their plans on employment and overall economic development 
to assure that the opportunities for economic growth and jobs that the 
plans offer are manifest. We also identify federal programs, including 
the multi-agency Partnerships for Opportunity and Workforce and 
Economic Revitalization (POWER) Initiative.\15\ The POWER Initiative is 
competitively awarding planning assistance and implementation grants 
with funding from the Department of Commerce, Department of Labor 
(DOL), Small Business Administration, and the Appalachian Regional 
Commission,\16\ whose mission is to assist communities affected by 
changes in the coal industry and the utility power sector.
---------------------------------------------------------------------------

    \15\ http://www.eda.gov/power/.
    \16\ https://www.whitehouse.gov/the-press-office/2015/03/27/fact-sheet-partnerships-opportunity-and-workforce-and-economic-revitaliz.
---------------------------------------------------------------------------

    (10) Community and environmental justice considerations.
    Many community leaders, environmental justice advocates, faith-
based organizations and others commented that the benefits of this rule 
must be shared broadly across society and that undue burdens should not 
be imposed on low-income ratepayers. We agree. The federal government 
is taking significant steps to help low-income families and individuals 
gain access to RE and demand-side EE through new initiatives involving, 
for example, increasing solar energy systems in federally subsidized 
homes and supporting solar systems for others with low incomes. The 
final rule ensures that bill-lowering measures such as demand-side EE 
continue to be a major

[[Page 64677]]

compliance option. The CEIP will encourage early investment in these 
types of projects as well. In addition to carbon reduction benefits, we 
expect significant near- and long-term public health benefits in 
communities as conventional air pollutants are reduced along with GHGs. 
However, some stakeholders expressed concerns about the possibility of 
localized increases in emissions from some power plants as the utility 
industry complies with state plans, in particular in communities 
already disproportionately affected by air pollution. This rule sets 
expectations for states to engage with vulnerable communities as they 
develop their plans, so that impacts on these communities are 
considered as plans are designed. The EPA also encourages states to 
engage with workers in the utility power and related sectors, as well 
as their worker representatives, so that impacts on their communities 
may be considered. The EPA commits, once implementation is under way, 
to assess the impacts of this rule. Likewise, we encourage states to 
evaluate the effects of their plans to ensure that there are no 
disproportionate adverse impacts on their communities.
5. Additional Context for This Final Rule
    a. Climate change impacts. This final rule is an important step in 
an essential series of long-term actions that are achieving and must 
continue to achieve the GHG emission reductions needed to address the 
serious threat of climate change, and constitutes a major commitment--
and international leadership-by-doing--on the part of the U.S., one of 
the world's largest GHG emitters. GHG pollution threatens the American 
public by leading to 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\17\ and 82 
percent of U.S. GHG emissions.\18\ The May 2014 report of the National 
Climate Assessment \19\ 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, with resulting damage and disruption to human well-
being, infrastructure, ecosystems, and agriculture, and projects 
continued increases in impacts across a wide range of communities, 
sectors, and ecosystems. New scientific assessments since 2009, when 
the EPA determined that GHGs pose a threat to human health and the 
environment (the ``Endangerment Finding''), highlight the urgency of 
addressing the rising concentration of CO2 in the 
atmosphere. Certain groups, including children, the elderly, and the 
poor, are most vulnerable to climate-related effects. Recent studies 
also find that certain communities, including low-income communities 
and some communities of color (more specifically, populations defined 
jointly by ethnic/racial characteristics and geographic location), are 
disproportionately affected by certain climate change related impacts--
including heat waves, degraded air quality, and extreme weather 
events--which are associated with increased deaths, illnesses, and 
economic challenges. Studies also find that climate change poses 
particular threats to the health, well-being, and ways of life of 
indigenous peoples in the U.S.
---------------------------------------------------------------------------

    \17\ 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.
    \18\ From Table ES-2 ``Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2013'', Report EPA 430-R-15-004, United 
States Environmental Protection Agency, April 15, 2015. Available at 
http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
    \19\ 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/.
---------------------------------------------------------------------------

    b. The utility power sector. One of the strategies of the 
President's Climate Action Plan is to reduce CO2 emissions 
from power plants.\20\ 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. and among fossil 
fuel-fired EGUs, coal-fired units are by far the largest emitters of 
GHGs. To accomplish the goal of reducing CO2 emissions from 
power plants, President Obama issued a Presidential Memorandum \21\ 
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 new, modified, 
reconstructed and existing power plants, and in doing so to build on 
state leadership in moving toward a cleaner power sector. In this 
action and the concurrent CAA section 111(b) rule, the EPA is 
finalizing regulations to reduce GHG emissions from fossil fuel-fired 
EGUs. This CAA section 111(d) action builds on actions states and 
utilities are already taking to move toward cleaner generation of 
electric power.
---------------------------------------------------------------------------

    \20\ The President's Climate Action Plan, June 2013. http://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf.
    \21\ 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.
---------------------------------------------------------------------------

    The utility power sector is unlike other industrial sectors. In 
other sectors, sources effectively operate independently and on a 
local-site scale, with control of their physical operations resting in 
the hands of their respective owners and operators. Pollution control 
standards, which focus on each source in a non-utility industrial 
source category, have reflected the standalone character of individual 
source investment decision-making and operations.
    In stark contrast, the utility power sector comprises a unique 
system of electricity resources, including the EGUs affected under 
these guidelines, that operate in a complex and interconnected grid 
where electricity generally flows freely (e.g., portions of the system 
cannot be easily isolated through the use of switches or valves as can 
be done in other networked systems like trains and pipeline systems). 
That grid is physically interconnected and operated on an integrated 
basis across large regions. In this interconnected system, system 
operators, whose decisions, protocols, and actions, to a significant 
extent, dictate the operations of individual EGUs and large ensembles 
of EGUs, must reliably balance supply and demand using available 
generation and demand-side resources, including EE, demand response and 
a wide range of low- and zero-emitting sources. These resources are 
managed to meet the system needs in a reliable and efficient manner. 
Each aspect of this interconnected system is highly regulated and 
coordinated, with supply and demand constantly being balanced to meet 
system needs. Each step of the process from the electric generator to 
the end user is highly regulated by multiple entities working in 
coordination and considering overall system reliability. For example, 
in an independent system operator (ISO) or regional transmission 
organization (RTO) with a centralized, organized capacity market, 
electric generators are paid to be available to run when needed, must 
bid into energy markets, must respond to dispatch instructions, and 
must have permission to schedule maintenance. The ISO/RTO dispatches 
resources in a way that maintains electric system reliability.
    The approach we take in the final guidelines--both in the way we 
defined the BSER and established the resulting emission performance 
rates, and in the ranges of options we created for states

[[Page 64678]]

and affected EGUs--is consistent with, and in some ways mirrors, the 
interconnected, interdependent and highly regulated nature of the 
utility power sector, the daily operation of affected EGUs within this 
framework, and the critical role of utilities in providing reliable, 
affordable electricity at all times and in all places within this 
complex, regulated system. Thus, not only do these guidelines put a 
premium on providing as much flexibility and latitude as possible for 
states and utilities, they also recognize that a given EGU's operations 
are determined by the availability and use of other generation 
resources to which it is physically connected and by the collective 
operating regime that integrates that individual EGU's activity with 
other resources across the grid.
    In this integrated system, numerous entities have both the 
capability and the responsibility to maintain a reliable electric 
system. FERC, DOE, state public utility commissions, ISOs, RTOs, other 
planning authorities, and the North American Electric Reliability 
Corporation (NERC), all contribute to ensuring the reliability of the 
electric system in the U.S. Critical to this function are dispatch 
tools, applied primarily by RTOs, ISOs, and balancing authorities, that 
operate such that actions taken or costs incurred at one source 
directly affect or cause actions to occur at other sources. Generation, 
outages, and transmission changes in one part of the synchronous grid 
can affect the entire interconnected grid.\22\ The interconnection is 
such that ``[i]f a generator is lost in New York City, its effect is 
felt in Georgia, Florida, Minneapolis, St. Louis, and New Orleans.'' 
\23\ The U.S. Supreme Court has explicitly recognized the 
interconnected nature of the electricity grid.\24\
---------------------------------------------------------------------------

    \22\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 159 (2d ed. 2010).
    \23\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 160 (2d ed. 2010).
    \24\ Federal Power Comm'n v. Florida Power & Light Co., 404 U.S. 
453, at 460 (1972) (quoting a Federal Power Commission hearing 
examiner, `` `If a housewife in Atlanta on the Georgia system turns 
on a light, every generator on Florida's system almost instantly is 
caused to produce some quantity of additional electric energy which 
serves to maintain the balance in the interconnected system between 
generation and load.' '') (citation omitted). See also New York v. 
FERC, 535 U.S. 1, at 7-8 (2002) (stating that ``any electricity that 
enters the grid immediately becomes a part of a vast pool of energy 
that is constantly moving in interstate commerce.'') (citation 
omitted). In Federal Power Comm'n v. Southern California Edison Co., 
376 U.S. 205 (1964), the Supreme Court found that a sale for resale 
of electricity from Southern California Edison to the City of 
Colton, which took place solely in California, was under Federal 
Power Commission jurisdiction because some of the electricity that 
Southern California Edison marketed came from out of state. The 
Supreme Court stated that, `` `federal jurisdiction was to follow 
the flow of electric energy, an engineering and scientific, rather 
than a legalistic or governmental, test.' '' Id. at 210, quoting 
Connecticut Light & Power Co. v. Federal Power Commission, 324 U.S. 
515, 529 (1945) (emphasis omitted).
---------------------------------------------------------------------------

    The uniqueness of the utility power sector inevitably affects the 
way in which environmental regulations are designed. When the EPA 
promulgates environmental regulations that affect the utility power 
sector, as we have done numerous times over the past four decades, we 
do so with the awareness of the importance of the efficient and 
continuous, uninterrupted operation of the interconnected electricity 
system in which EGUs participate. We also keep in mind the unique 
product that this interconnected system provides--electricity 
services--and the critical role of this sector to the U.S. economy and 
to the fundamental well-being of all Americans.
    In the context of environmental regulation, Congress, the EPA and 
the states all have recognized--as we do in these final guidelines--
that electricity production takes place, at least to some extent, 
interchangeably between and among multiple generation facilities and 
different types of generation. This is evidenced in the enactment or 
promulgation of pollution reduction programs, such as Title IV of the 
CAA, the NOX state implementation plan (SIP) Call, the 
Cross-State Air Pollution Rule (CSAPR), and the Regional Greenhouse Gas 
Initiative (RGGI). As these actions show, both Congress and the EPA 
have consistently tailored legislation and regulations affecting the 
utility power sector to its unique characteristics. For example, in 
Title IV of the Clean Air Act Amendments of 1990, Congress established 
a pollution reduction program specifically for fossil fuel-fired EGUs 
and designed the SO2 portion of that program with express 
recognition of the sector's ability to shift generation among various 
EGUs, which enabled pollution reduction by increasing reliance on 
natural gas-fired units and RE. Similarly, in the NOX SIP 
Call, the Clean Air Interstate Rule (CAIR), and CSAPR, the EPA 
established pollution reduction programs focused on fossil fuel-fired 
EGUs and designed those programs with express recognition of the 
sector's ability to shift generation among various EGUs. In this 
action, we continue that approach. Both the subcategory-specific 
emission performance rates, and the pathways offered to achieve them, 
reflect and are tailored to the unique characteristics of the utility 
power sector.
    The way that power is produced, distributed and used in the U.S. is 
already changing as a result of advancements in innovative power sector 
technologies and in the availability and cost of low-carbon fuel, RE 
and demand-side EE technologies, as well as economic conditions. These 
changes are taking place at a time when the average age of the coal-
fired generating fleet is approaching that at which utilities and 
states undertake significant new investments to address aging assets. 
In 2025, the average age of the coal-fired generating fleet is 
projected to be 49 years old, and 20 percent of those units would be 
more than 60 years old if they remain 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 for and investing in the next generation of power production, 
simply because of the need to take account of the age of current assets 
and infrastructure. Historically, the industry has invested about $100 
billion a year in capital improvements. These guidelines will help 
ensure that, as those necessary investments are being made, they are 
integrated with the need to address GHG pollution from the sector.
    At the same time, owners/operators of affected EGUs are already 
pursuing the types of measures contemplated in this rule. Out of 404 
entities identified as owners or operators of affected EGUs, 
representing ownership of 82 percent of the total capacity of the 
affected EGUs, 178 already own RE generating capacity in addition to 
fossil fuel-fired generating capacity. In fact, these entities already 
own aggregate amounts of RE generating capacity equal to 25 percent of 
the aggregate amounts of their affected EGU capacity.\25\ In addition, 
funding for utility EE programs has been growing rapidly, increasing 
from $1.6 billion in 2006 to $6.3 billion in 2013.
---------------------------------------------------------------------------

    \25\ SNL Energy. Data used with permission. Accessed on June 9, 
2015.
---------------------------------------------------------------------------

    The final guidelines are based on, and reinforce, the actions 
already being taken by states and utilities to upgrade aging 
electricity infrastructure with 21st century technologies. The 
guidelines will ensure that these trends continue in ways that are 
consistent with the long-term planning and investment processes already 
used in the utility power sector. This final rule provides flexibility 
for states to build upon their progress, and the progress of cities and 
towns, in addressing GHGs, and minimizes

[[Page 64679]]

additional requirements for existing programs where possible. It also 
allows states to pursue policies to reduce carbon pollution that: (1) 
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) tailor plans to meet their respective energy, 
environmental and economic needs and goals, and those of their local 
communities. Thus, the final guidelines will achieve meaningful 
CO2 emission reductions while maintaining the reliability 
and affordability of electricity in the U.S.
6. Projected National-Level Emission Reductions
    Under the final guidelines, the EPA projects annual CO2 
reductions of 22 to 23 percent below 2005 levels in 2020, 28 to 29 
percent below 2005 levels in 2025, and 32 percent below 2005 levels in 
2030. These guidelines will also result in important reductions in 
emissions of criteria air pollutants, including SO2, 
NOX, and directly-emitted fine particulate matter 
(PM2.5). A thorough discussion of the EPA's analysis is 
presented in Section XI.A of this preamble and in Chapter 3 of the 
Regulatory Impact Analysis (RIA) included in the docket for this 
rulemaking.
7. Costs and Benefits
    Actions taken to comply with the final guidelines will reduce 
emissions of CO2 and other air pollutants, including 
SO2, NOX, and directly emitted PM2.5 
from the utility power sector. 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 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 EE.
    Because of the range of choices available to states and the lack of 
a priori knowledge about the specific choices states will make in 
response to the final goals, the RIA for this final action presents two 
scenarios designed to achieve these goals, which we term the ``rate-
based'' illustrative plan approach and the ``mass-based'' illustrative 
plan approach.
    In summary, we estimate the total combined climate benefits and 
health co-benefits for the rate-based approach to be $3.5 to $4.6 
billion in 2020, $18 to $28 billion in 2025, and $34 to $54 billion in 
2030 (3 percent discount rate, 2011$). Total combined climate benefits 
and health co-benefits for the mass-based approach are estimated to be 
$5.3 to $8.1 billion in 2020, $19 to $29 billion in 2025, and $32 to 
$48 billion in 2030 (3 percent discount rate, 2011$). A summary of the 
emission reductions and monetized benefits estimated for this rule at 
all discount rates is provided in Tables 15 through 22 of this 
preamble.
    The annual compliance costs are estimated using the Integrated 
Planning Model (IPM) and include demand-side EE program and participant 
costs as well as monitoring, reporting and recordkeeping costs. In 
2020, total compliance costs of the final guidelines are approximately 
$2.5 billion (2011$) under the rate-based approach and $1.4 billion 
(2011$) under the mass-based approach. In 2025, total compliance costs 
of the final guidelines are approximately $1.0 billion (2011$) under 
the rate-based approach and $3.0 billion (2011$) under the mass-based 
approach. In 2030, total compliance costs of the final guidelines are 
approximately $8.4 billion (2011$) under the rate-based approach and 
$5.1 billion (2011$) under the mass-based approach.
    The quantified net benefits (the difference between monetized 
benefits and compliance costs) in 2020 are estimated to range from $1.0 
billion to $2.1 billion (2011$) using a 3 percent discount rate (model 
average) under the rate-based approach and from $3.9 billion to $6.7 
billion (2011$) using a 3 percent discount rate (model average) under 
the mass-based approach. In 2025, the quantified net benefits (the 
difference between monetized benefits and compliance costs) in 2025 are 
estimated to range from $17 billion to $27 billion (2011$) using a 3 
percent discount rate (model average) under the rate-based approach and 
from $16 billion to $26 billion (2011$) using a 3 percent discount rate 
(model average) under the mass-based approach. In 2030, the quantified 
net benefits (the difference between monetized benefits and compliance 
costs) in 2030 are estimated to range from $26 billion to $45 billion 
(2011$) using a 3 percent discount rate (model average) under the rate-
based approach and from $26 billion to $43 billion (2011$) using a 3 
percent discount rate (model average) under the mass-based approach.

[[Page 64680]]



  Table 1--Summary of the Monetized Benefits, Compliance Costs, and Net
 Benefits for the Final Guidelines in 2020, 2025, and 2030 \a\ Under the
                  Rate-Based Illustrative Plan Approach
                           [Billions of 2011$]
------------------------------------------------------------------------
                        Rate-based approach, 2020
-------------------------------------------------------------------------
                                 3% Discount rate     7% Discount rate
------------------------------------------------------------------------
Climate benefits b............                    $2.8
------------------------------------------------------------------------
Air pollution health co-        $0.70 to $1.8....  $0.64 to $1.7.
 benefits c.
Total Compliance Costs d......  $2.5.............  $2.5.
Net Monetized Benefits e......  $1.0 to $2.1.....  $1.0 to $2.0.
                               -----------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
                        Rate-based approach, 2025
------------------------------------------------------------------------
Climate benefits b............                     $10
------------------------------------------------------------------------
Air pollution health co-        $7.4 to $18......  $6.7 to $16.
 benefits c.
Total Compliance Costs d......  $1.0.............  $1.0.
Net Monetized Benefits e......  $17 to $27.......  $16 to $25.
------------------------------------------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
                        Rate-based approach, 2030
------------------------------------------------------------------------
Climate benefits b............  $20
------------------------------------------------------------------------
Air pollution health co-        $14 to $34.......  $13 to $31.
 benefits c.
Total Compliance Costs d......  $8.4.............  $8.4.
Net Monetized Benefits e......  $26 to $45.......  $25 to $43.
------------------------------------------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
\a\ All 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
  SC-CO2 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 SC-CO2 values. As shown in the RIA,
  climate benefits are also estimated using the other three SC-CO2
  estimates (model average at 2.5 percent discount rate, 3 percent, and
  5 percent; 95th percentile at 3 percent). The SC-CO2 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 98
  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 final guidelines
  and a discount rate of approximately 5%. This estimate includes
  monitoring, recordkeeping, and reporting costs and demand-side EE
  program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global SC-CO2 at a 3 percent discount rate (model average).
  The RIA includes combined climate and health estimates based on
  additional discount rates.


[[Page 64681]]


  Table 2--Summary of the Monetized Benefits, Compliance Costs, and Net
  Benefits for the Final Guidelines in 2020, 2025 and 2030 a Under the
                  Mass-Based Illustrative Plan Approach
                           [Billions of 2011$]
------------------------------------------------------------------------
                        Mass-based approach, 2020
-------------------------------------------------------------------------
                                 3% Discount rate     7% Discount rate
------------------------------------------------------------------------
Climate benefits b............                    $3.3
------------------------------------------------------------------------
Air pollution health co-        $2.0 to $4.8.....  $1.8 to $4.4.
 benefits c.
Total Compliance Costs d......  $1.4.............  $1.4.
Net Monetized Benefits e......  $3.9 to $6.7.....  $3.7 to $6.3.
------------------------------------------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
                        Mass-based approach, 2025
------------------------------------------------------------------------
      Climate benefits b                           $12
------------------------------------------------------------------------
Air pollution health co-        $7.1 to $17......  $6.5 to $16.
 benefits c.
Total Compliance Costs d......  $3.0.............  $3.0.
Net Monetized Benefits e......  $16 to $26.......  $15 to $24.
------------------------------------------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
                        Mass-based approach, 2030
------------------------------------------------------------------------
Climate benefits b............                     $20
------------------------------------------------------------------------
Air pollution health co-        $12 to $28.......  $11 to $26.
 benefits c.
Total Compliance Costs d......  $5.1.............  $5.1.
Net Monetized Benefits e......  $26 to $43.......  $25 to $40.
------------------------------------------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
a All 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
  SC-CO2 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 SC-CO2 estimated for
  a 3 percent discount rate, however we emphasize the importance and
  value of considering the full range of SC-CO2 values. As shown in the
  RIA, climate benefits are also estimated using the other three SC-CO2
  estimates (model average at 2.5 percent discount rate, 3 percent, and
  5 percent; 95th percentile at 3 percent). The SC-CO2 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 98 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 final guidelines
  and a discount rate of approximately 5 percent. This estimate includes
  monitoring, recordkeeping, and reporting costs and demand-side EE
  program and participant costs.
e The estimates of net benefits in this summary table are calculated
  using the global SC-CO2 at a 3 percent discount rate (model average).
  The RIA includes combined climate and health estimates based on
  additional discount rates.


[[Page 64682]]

    There are additional important benefits that the EPA could not 
monetize. Due to current data and modeling limitations, our estimates 
of the benefits from reducing CO2 emissions do not include 
important impacts like ocean acidification or potential tipping points 
in natural or managed ecosystems. The unquantified benefits also 
include climate benefits from reducing emissions of non-CO2 
GHGs (e.g., nitrous oxide and methane) \26\ and co-benefits from 
reducing direct exposure to SO2, NOX, and HAP 
(e.g., mercury and hydrogen chloride), as well as from reducing 
ecosystem effects and visibility impairment.
---------------------------------------------------------------------------

    \26\ Although CO2 is the predominant greenhouse gas 
released by the power sector, electricity generating units also emit 
small amounts of nitrous oxide and methane. For more detail about 
power sector emissions, see RIA Chapter 2 and the U.S. Greenhouse 
Gas Reporting Program's power sector summary, http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.html.
---------------------------------------------------------------------------

    We project employment gains and losses relative to base case for 
different types of labor, including construction, plant operation and 
maintenance, coal and natural gas production, and demand-side EE. In 
2030, we project a net decrease in job-years of about 31,000 under the 
rate-based approach and 34,000 under the mass-based approach \27\ for 
construction, plant operation and maintenance, and coal and natural gas 
and a gain of 52,000 to 83,000 jobs in the demand-side EE sector under 
either approach. Actual employment impacts will depend upon measures 
taken by states in their state plans and the specific actions sources 
take to comply.
---------------------------------------------------------------------------

    \27\ 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 2025 may 
represent 20 full-time jobs or 40 half-time jobs.
---------------------------------------------------------------------------

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

B. Organization and Approach for This Rule

    This final rule establishes the EPA's emission guidelines for 
states to follow in developing plans to reduce CO2 emissions 
from the utility power sector. Section II of this preamble provides 
background information on climate change impacts from GHG emissions, 
GHG emissions from fossil fuel-fired EGUs, the utility power sector, 
the CAA section 111(d) requirements, EPA actions prior to this final 
action, outreach and consultations, and the number and extent of 
comments received. In section III of the preamble, we present a summary 
of the rule requirements and the legal basis for these. Section IV 
explains the EPA authority to regulate CO2 and EGUs, 
identifies affected EGUs, and describes the proposed treatment of 
source categories. Section V describes the agency's determination of 
the BSER using three building blocks and our key considerations in 
making the determination. Section VI provides the subcategory-specific 
emission performance rates, and section VII provides equivalent 
statewide rate-based and mass-based goals. Section VIII then describes 
state plan approaches and the requirements, and flexibilities, for 
state plans, followed by section IX, in which considerations for 
communities are described. Interactions between this final rule and 
other EPA programs and rules are discussed in section X. Impacts of the 
proposed action are then described in section XI, followed by a 
discussion of statutory and executive order reviews in section XII and 
the statutory authority for this action in section XIII.
    We note that this rulemaking is being promulgated concurrently with 
two related actions in this issue of the Federal Register: The final 
NSPS for CO2 emissions from newly constructed, modified, and 
reconstructed EGUs, which is being promulgated under CAA section 
111(b), and the proposed federal plan and model rules. These 
rulemakings have their own rulemaking dockets.

II. Background

    In this section, we discuss climate change impacts from GHG 
emissions, both on public health and public welfare. We also present 
information about GHG emissions from fossil fuel-fired EGUs, the 
challenges associated with controlling carbon dioxide emissions, the 
uniqueness of the utility power sector, and recent and continuing 
trends and transitions in the utility power sector. In addition, we 
briefly describe CAA regulations for power plants, provide highlights 
of Congressional awareness of climate change and international 
agreements and actions, and summarize statutory and regulatory 
requirements relevant to this rulemaking. In addition, we provide 
background information on the EPA's June 18, 2014 Clean Power Plan 
proposal, the November 4, 2014 supplemental proposal, and other actions 
associated with this rulemaking,\28\ followed by information on 
stakeholder outreach and consultations and the comments that the EPA 
received prior to issuing this final rulemaking.
---------------------------------------------------------------------------

    \28\ The EPA also published in the Federal Register a notice of 
data availability (79 FR 64543; November 8, 2014) and a notice on 
the translation of emission rate-based CO2 goals to mass-
based equivalents (79 FR 67406; November 13, 2014).
---------------------------------------------------------------------------

A. Climate Change Impacts From GHG Emissions

    According to the National Research Council, ``Emissions of 
CO2 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 CO2 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 reduction choices made today matter in determining impacts 
experienced not just over the next few decades, but in the coming 
centuries and millennia.'' \29\
---------------------------------------------------------------------------

    \29\ National Research Council, Climate Stabilization Targets, 
p.3.
---------------------------------------------------------------------------

    In 2009, based on a large body of robust and compelling scientific 
evidence, the EPA Administrator issued the Endangerment Finding under 
CAA section 202(a)(1).\30\ In the Endangerment Finding, the 
Administrator found that the current, elevated concentrations of GHGs 
in the atmosphere--already at levels unprecedented in human history--
may reasonably be anticipated to endanger public health and welfare of 
current and future generations in the U.S. We summarize these adverse 
effects on public health and welfare briefly here.
---------------------------------------------------------------------------

    \30\ ``Endangerment and Cause or Contribute Findings for 
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR 
66496 (Dec. 15, 2009) (``Endangerment Finding'').
---------------------------------------------------------------------------

1. Public Health Impacts Detailed in the 2009 Endangerment Finding
    Climate change caused by human emissions of GHGs threatens the 
health of Americans in multiple ways. By raising average temperatures, 
climate change 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 U.S. Compared to a future 
without climate change, climate change is expected to increase ozone 
pollution over broad areas of the U.S., especially on the highest ozone 
days and in the largest metropolitan areas with the worst ozone 
problems, and thereby increase the risk of morbidity and mortality. 
Climate change is also

[[Page 64683]]

expected to cause more intense hurricanes and more frequent and intense 
storms and heavy precipitation, with impacts on other areas of public 
health, such as the potential for increased deaths, injuries, 
infectious and waterborne diseases, and stress-related disorders. 
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 impacts touch nearly every aspect of public welfare. 
Among the multiple threats caused by human emissions of GHGs, 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 a multitude of increased risks, 
particularly from rising sea level and increases in the severity of 
storms. These communities face storm and flooding damage to property, 
or even loss of land due to inundation, erosion, wetland submergence 
and habitat loss.
    Impacts of climate change on public welfare also include threats to 
social and ecosystem services. Climate change is expected to result in 
an increase in peak electricity demand. Extreme weather from climate 
change threatens energy, transportation, and water resource 
infrastructure. Climate change may also exacerbate ongoing 
environmental pressures in certain settlements, particularly in Alaskan 
indigenous communities, and 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 and Observations
    Since the administrative record concerning the Endangerment Finding 
closed following the EPA's 2010 Reconsideration Denial, the climate has 
continued to change, with new records being set for a number of climate 
indicators such as global average surface temperatures, Arctic sea ice 
retreat, CO2 concentrations, and sea level rise. 
Additionally, a number of major scientific assessments have been 
released that improve understanding of the climate system and 
strengthen the case that GHGs endanger public health and welfare both 
for current and future generations. These assessments, from the 
Intergovernmental Panel on Climate Change (IPCC), the U.S. Global 
Change Research Program (USGCRP), and the National Research Council 
(NRC), include: 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 National Climate Assessment, Climate Change Impacts in the United 
States (NCA3), 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 carefully reviewed these recent assessments in keeping 
with the same approach outlined in Section VIII.A of the 2009 
Endangerment Finding, which was to rely primarily upon the major 
assessments by the USGCRP, the IPCC, and the NRC of the National 
Academies to provide the technical and scientific information to inform 
the Administrator's judgment regarding the question of whether GHGs 
endanger public health and welfare. 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.
    The findings of the recent scientific assessments confirm and 
strengthen the conclusion that GHGs endanger public health, now and in 
the future. The NCA3 indicates that human health in the U.S. will be 
impacted by ``increased extreme weather events, wildfire, decreased air 
quality, threats to mental health, and illnesses transmitted by food, 
water, and disease-carriers such as mosquitoes and ticks.'' The most 
recent assessments now have greater confidence that climate change will 
influence production of pollen that exacerbates asthma and other 
allergic respiratory diseases such as allergic rhinitis, as well as 
effects on conjunctivitis and dermatitis. Both the NCA3 and the IPCC 
AR5 found that increasing temperature has lengthened the allergenic 
pollen season for ragweed, and that increased CO2 by itself 
can elevate production of plant-based allergens.
    The NCA3 also finds that climate change, in addition to chronic 
stresses such as extreme poverty, is negatively affecting indigenous 
peoples' health in the U.S. through impacts such as reduced access to 
traditional foods, decreased water quality, and increasing exposure to 
health and safety hazards. The IPCC AR5 finds that climate change-
induced warming in the Arctic and resultant changes in environment 
(e.g., permafrost thaw, effects on traditional food sources) have 
significant impacts, observed now and projected, on the health and 
well-being of Arctic residents, especially indigenous peoples. Small, 
remote, predominantly-indigenous communities are especially vulnerable 
given their ``strong dependence on the environment for food, culture, 
and way of life; their political and economic marginalization; existing 
social, health, and poverty disparities; as well as their frequent 
close proximity to exposed locations along ocean, lake, or river 
shorelines.'' \31\ In addition, increasing temperatures and loss of 
Arctic sea ice increases the risk of drowning for those engaged in 
traditional hunting and fishing.
---------------------------------------------------------------------------

    \31\ IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 
Vulnerability. Part B: Regional Aspects. Contribution of Working 
Group II to the Fifth Assessment Report of the Intergovernmental 
Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. 
Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. 
Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. 
MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge 
University Press, Cambridge, p. 1581. https://www.ipcc.ch/report/ar5/wg2/.
---------------------------------------------------------------------------

    The NCA3 concludes that children's unique physiology and developing 
bodies contribute to making them particularly vulnerable to climate 
change. Impacts on children are expected from heat waves, air 
pollution, infectious and waterborne illnesses, and mental health 
effects resulting from extreme weather events. The IPCC AR5 indicates 
that children are among those especially susceptible to most allergic 
diseases, as well as health effects

[[Page 64684]]

associated with heat waves, storms, and floods. The IPCC finds that 
additional health concerns may arise in low income households, 
especially those with children, if climate change reduces food 
availability and increases prices, leading to food insecurity within 
households.
    Both the NCA3 and IPCC AR5 conclude that climate change will 
increase health risks facing the elderly. Older people are at much 
higher risk of mortality during extreme heat events. Pre-existing 
health conditions also make older adults susceptible to cardiac and 
respiratory impacts of air pollution and to more severe consequences 
from infectious and waterborne diseases. Limited mobility among older 
adults can also increase health risks associated with extreme weather 
and floods.
    The new assessments also confirm and strengthen the conclusion that 
GHGs endanger public welfare, and emphasize the urgency of reducing GHG 
emissions due to their projections that show GHG concentrations 
climbing to ever-increasing levels in the absence of mitigation. The 
NRC assessment Understanding Earth's Deep Past projected that, without 
a reduction in emissions, CO2 concentrations by the end of 
the century would increase to levels that the Earth has not experienced 
for more than 30 million years.\32\ In fact, that assessment stated 
that ``the magnitude and rate of the present GHG 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.'' \33\ 
Because of these unprecedented changes, several assessments state that 
we may be approaching critical, poorly understood thresholds. As stated 
in the assessment, ``As Earth continues to warm, it may be approaching 
a critical climate threshold beyond which rapid and potentially 
permanent--at least on a human timescale--changes not anticipated by 
climate models tuned to modern conditions may occur.'' The NRC Abrupt 
Impacts report analyzed abrupt climate change in the physical climate 
system and abrupt impacts of ongoing changes that, when thresholds are 
crossed, can cause abrupt impacts for society and ecosystems. The 
report considered destabilization of the West Antarctic Ice Sheet 
(which could cause 3-4 m of potential sea level rise) as an abrupt 
climate impact with unknown but probably low probability of occurring 
this century. The report categorized a decrease in ocean oxygen content 
(with attendant threats to aerobic marine life); increase in intensity, 
frequency, and duration of heat waves; and increase in frequency and 
intensity of extreme precipitation events (droughts, floods, 
hurricanes, and major storms) as climate impacts with moderate risk of 
an abrupt change within this century. The NRC Abrupt Impacts report 
also analyzed the threat of rapid state changes in ecosystems and 
species extinctions as examples of an irreversible impact that is 
expected to be exacerbated by climate change. Species at most risk 
include those whose migration potential is limited, whether because 
they live on mountaintops or fragmented habitats with barriers to 
movement, or because climatic conditions are changing more rapidly than 
the species can move or adapt. While the NRC determined that it is not 
presently possible to place exact probabilities on the added 
contribution of climate change to extinction, they did find that there 
was substantial risk that impacts from climate change could, within a 
few decades, drop the populations in many species below sustainable 
levels thereby committing the species to extinction. Species within 
tropical and subtropical rainforests such as the Amazon and species 
living in coral reef ecosystems were identified by the NRC as being 
particularly vulnerable to extinction over the next 30 to 80 years, as 
were species in high latitude and high elevation regions. Moreover, due 
to the time lags inherent in the Earth's climate, the NRC Climate 
Stabilization Targets assessment notes that the full warming from any 
given concentration of CO2 reached will not be fully 
realized for several centuries, underscoring that emission activities 
today carry with them climate commitments far into the future.
---------------------------------------------------------------------------

    \32\ National Research Council, Understanding Earth's Deep Past, 
p. 1.
    \33\ Id., p.138.
---------------------------------------------------------------------------

    Future temperature changes will depend on what emission path the 
world follows. In its high emission scenario, the IPCC AR5 projects 
that global temperatures by the end of the century will likely be 2.6 
[deg]C to 4.8 [deg]C (4.7 to 8.6[emsp14][deg]F) warmer than today. 
Temperatures on land and in northern latitudes will likely warm even 
faster than the global average. However, according to the NCA3, 
significant reductions in emissions would lead to noticeably less 
future warming beyond mid-century, and therefore less impact to public 
health and welfare.
    While rainfall may only see small globally and annually averaged 
changes, there are expected to be substantial shifts in where and when 
that precipitation falls. According to the NCA3, regions closer to the 
poles will see more precipitation, while the dry subtropics are 
expected to expand (colloquially, this has been summarized as wet areas 
getting wetter and dry regions getting drier). In particular, the NCA3 
notes that the western U.S., and especially the Southwest, is expected 
to become drier. This projection is consistent with the recent observed 
drought trend in the West. At the time of publication of the NCA, even 
before the last 2 years of extreme drought in California, tree ring 
data was already indicating that the region might be experiencing its 
driest period in 800 years. Similarly, the NCA3 projects that heavy 
downpours are expected to increase in many regions, with precipitation 
events in general becoming less frequent but more intense. This trend 
has already been observed in regions such as the Midwest, Northeast, 
and upper Great Plains. Meanwhile, the NRC Climate Stabilization 
Targets assessment found that the area burned by wildfire is expected 
to grow by 2 to 4 times for 1 [deg]C (1.8[emsp14][deg]F) of warming. 
For 3 [deg]C of warming, the assessment found that 9 out of 10 summers 
would be warmer than all but the 5 percent of warmest summers today, 
leading to increased frequency, duration, and intensity of heat waves. 
Extrapolations by the NCA also indicate that Arctic sea ice in summer 
may essentially disappear by mid-century. Retreating snow and ice, and 
emissions of carbon dioxide and methane released from thawing 
permafrost, will also amplify future warming.
    Since the 2009 Endangerment Finding, the USGCRP NCA3, and multiple 
NRC assessments have projected future rates of sea level rise that are 
40 percent larger to more than twice as large as the previous estimates 
from the 2007 IPCC 4th Assessment Report due in part to improved 
understanding of the future rate of melt of the Antarctic and Greenland 
Ice sheets. The NRC Sea Level Rise assessment projects a global sea 
level rise of 0.5 to 1.4 meters (1.6 to 4.6 feet) by 2100, the NRC 
National Security Implications assessment suggests that ``the 
Department of the Navy should expect roughly 0.4 to 2 meters [1.3 to 
6.6 feet] global average sea-level rise by 2100,'' \34\ and the NRC 
Climate Stabilization Targets assessment states that an increase of 3 
[deg]C will lead to a sea level rise of 0.5 to 1 meter (1.6 to 3.3 
feet) by 2100. These assessments continue to recognize that there is

[[Page 64685]]

uncertainty inherent in accounting for ice sheet processes. 
Additionally, local sea level rise can differ from the global total 
depending on various factors: The east coast of the U.S. in particular 
is expected to see higher rates of sea level rise than the global 
average. For comparison, the NCA3 states that ``five million Americans 
and hundreds of billions of dollars of property are located in areas 
that are less than four feet above the local high-tide level,'' and the 
NCA3 finds that ``[c]oastal infrastructure, including roads, rail 
lines, energy infrastructure, airports, port facilities, and military 
bases, are increasingly at risk from sea level rise and damaging storm 
surges.'' \35\ Also, because of the inertia of the oceans, sea level 
rise will continue for centuries after GHG concentrations have 
stabilized (though more slowly than it would have otherwise). 
Additionally, there is a threshold temperature above which the 
Greenland ice sheet will be committed to inevitable melting: According 
to the NCA, some recent research has suggested that even present day 
CO2 levels could be sufficient to exceed that threshold.
---------------------------------------------------------------------------

    \34\ NRC, 2011: National Security Implications of Climate Change 
for U.S. Naval Forces. The National Academies Press, p. 28.
    \35\ Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. 
Yohe, Eds., 2014: Climate Change Impacts in the United States: The 
Third National Climate Assessment. U.S. Global Change Research 
Program, p. 9.
---------------------------------------------------------------------------

    In general, climate change impacts are expected to be unevenly 
distributed across different regions of the U.S. and have a greater 
impact on certain populations, such as indigenous peoples and the poor. 
The NCA3 finds climate change impacts such as the rapid pace of 
temperature rise, coastal erosion and inundation related to sea level 
rise and storms, ice and snow melt, and permafrost thaw are affecting 
indigenous people in the U.S. Particularly in Alaska, critical 
infrastructure and traditional livelihoods are threatened by climate 
change and, ``[i]n parts of Alaska, Louisiana, the Pacific Islands, and 
other coastal locations, climate change impacts (through erosion and 
inundation) are so severe that some communities are already relocating 
from historical homelands to which their traditions and cultural 
identities are tied.'' \36\ The IPCC AR5 notes, ``Climate-related 
hazards exacerbate other stressors, often with negative outcomes for 
livelihoods, especially for people living in poverty (high confidence). 
Climate-related hazards affect poor people's lives directly through 
impacts on livelihoods, reductions in crop yields, or destruction of 
homes and indirectly through, for example, increased food prices and 
food insecurity.'' \37\
---------------------------------------------------------------------------

    \36\ Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. 
Yohe, Eds., 2014: Climate Change Impacts in the United States: The 
Third National Climate Assessment. U.S. Global Change Research 
Program, p. 17.
    \37\ IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of 
Working Group II to the Fifth Assessment Report of the 
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, 
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, 
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 
Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 
Cambridge University Press, p. 796. https://www.ipcc.ch/report/ar5/wg2/.
---------------------------------------------------------------------------

    Carbon dioxide in particular has unique impacts on ocean 
ecosystems. The NRC Climate Stabilization Targets assessment found that 
coral bleaching will increase due both to warming and ocean 
acidification. Ocean surface waters have already become 30 percent more 
acidic over the past 250 years due to absorption of CO2 from 
the atmosphere. According to the NCA3, this acidification will reduce 
the ability of organisms such as corals, krill, oysters, clams, and 
crabs to survive, grow, and reproduce. The NRC Understanding Earth's 
Deep Past assessment notes four of the five major coral reef crises of 
the past 500 million years were caused by acidification and warming 
that followed GHG increases of similar magnitude to the emissions 
increases expected over the next hundred years. The NRC Abrupt Impacts 
assessment specifically highlighted similarities between the 
projections for future acidification and warming and the extinction at 
the end of the Permian which resulted in the loss of an estimated 90 
percent of known species. Similarly, the NRC Ocean Acidification 
assessment finds that ``[t]he chemistry of the ocean is changing at an 
unprecedented rate and magnitude due to anthropogenic carbon dioxide 
emissions; the rate of change exceeds any known to have occurred for at 
least the past hundreds of thousands of years.'' \38\ The assessment 
notes that the full range of consequences is still unknown, but the 
risks ``threaten coral reefs, fisheries, protected species, and other 
natural resources of value to society.'' \39\
---------------------------------------------------------------------------

    \38\ NRC, 2010: Ocean Acidification: A National Strategy to Meet 
the Challenges of a Changing Ocean. The National Academies Press, p. 
5.
    \39\ Ibid.
---------------------------------------------------------------------------

    Events outside the U.S., as also pointed out in the 2009 
Endangerment Finding, will also have relevant consequences. The NRC 
Climate and Social Stress assessment concluded that it is prudent to 
expect that some climate events ``will produce consequences that exceed 
the capacity of the affected societies or global systems to manage and 
that have global security implications serious enough to compel 
international response.'' The NRC National Security Implications 
assessment recommends preparing for increased needs for humanitarian 
aid; responding to the effects of climate change in geopolitical 
hotspots, including possible mass migrations; and addressing changing 
security needs in the Arctic as sea ice retreats.
    In addition to future impacts, the NCA3 emphasizes that climate 
change driven by human emissions of GHGs is already happening now and 
it is happening in the U.S. According to the IPCC AR5 and the NCA3, 
there are a number of climate-related changes that have been observed 
recently, and these changes are projected to accelerate in the future. 
The planet warmed about 0.85 [deg]C (1.5 [deg]F) from 1880 to 2012. It 
is extremely likely (>95 percent probability) that human influence was 
the dominant cause of the observed warming since the mid-20th century, 
and likely (>66 percent probability) that human influence has more than 
doubled the probability of occurrence of heat waves in some locations. 
In the Northern Hemisphere, the last 30 years were likely the warmest 
30 year period of the last 1400 years. U.S. average temperatures have 
similarly increased by 1.3 to 1.9 degrees F since 1895, with most of 
that increase occurring since 1970. Global sea levels rose 0.19 m (7.5 
inches) from 1901 to 2010. Contributing to this rise was the warming of 
the oceans and melting of land ice. It is likely that 275 gigatons per 
year of ice melted from land glaciers (not including ice sheets) since 
1993, and that the rate of loss of ice from the Greenland and Antarctic 
ice sheets increased substantially in recent years, to 215 gigatons per 
year and 147 gigatons per year respectively since 2002. For context, 
360 gigatons of ice melt is sufficient to cause global sea levels to 
rise 1 mm. Annual mean Arctic sea ice has been declining at 3.5 to 4.1 
percent per decade, and Northern Hemisphere snow cover extent has 
decreased at about 1.6 percent per decade for March and 11.7 percent 
per decade for June. Permafrost temperatures have increased in most 
regions since the 1980s, by up to 3 [deg]C (5.4 [deg]F) in parts of 
Northern Alaska. Winter storm frequency and intensity have both 
increased in the Northern Hemisphere. The NCA3 states that the 
increases in the severity or frequency of some types of extreme weather 
and climate events in recent decades can affect energy production

[[Page 64686]]

and delivery, causing supply disruptions, and compromise other 
essential infrastructure such as water and transportation systems.
    In addition to the changes documented in the assessment literature, 
there have been other climate milestones of note. In 2009, the year of 
the Endangerment Finding, the average concentration of CO2 
as measured on top of Mauna Loa was 387 parts per million, far above 
preindustrial concentrations of about 280 parts per million.\40\ The 
average concentration in 2013, the last full year before this rule was 
proposed, was 396 parts per million. The average concentration in 2014 
was 399 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.\41\ Arctic sea ice 
has continued to decline, with September of 2012 marking a new record 
low in terms of Arctic sea ice extent, 40 percent below the 1979-2000 
median. Sea level has continued to rise at a rate of 3.2 mm per year 
(1.3 inches/decade) since satellite observations started in 1993, more 
than twice the average rate of rise in the 20th century prior to 
1993.\42\ And 2014 was the warmest year globally in the modern global 
surface temperature record, going back to 1880; this now means 19 of 
the 20 warmest years have occurred in the past 20 years, and except for 
1998, the ten warmest years on record have occurred since 2002.\43\ The 
first months of 2015 have also been some of the warmest on record.
---------------------------------------------------------------------------

    \40\ ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt.
    \41\ http://www.esrl.noaa.gov/gmd/ccgg/trends/.
    \42\ Blunden, J., and D. S. Arndt, Eds., 2014: State of the 
Climate in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238.
    \43\ http://www.ncdc.noaa.gov/sotc/global/2014/13.
---------------------------------------------------------------------------

    These assessments and observed changes make it clear that reducing 
emissions of GHGs across the globe is necessary in order to avoid the 
worst impacts of climate change, and underscore the urgency of reducing 
emissions now. The NRC Committee on America's Climate Choices listed a 
number of reasons ``why it is imprudent to delay actions that at least 
begin the process of substantially reducing emissions.'' \44\ For 
example:
---------------------------------------------------------------------------

    \44\ NRC, 2011: America's Climate Choices, The National 
Academies Press.
---------------------------------------------------------------------------

     The faster emissions are reduced, the lower the risks 
posed by climate change. Delays in reducing emissions could commit the 
planet to a wide range of adverse impacts, especially if the 
sensitivity of the climate to GHGs is on the higher end of the 
estimated range.
     Waiting for unacceptable impacts to occur before taking 
action is imprudent because the effects of GHG emissions do not fully 
manifest themselves for decades and, once manifest, many of these 
changes will persist for hundreds or even thousands of years.
     In the committee's judgment, the risks associated with 
doing business as usual are a much greater concern than the risks 
associated with engaging in strong response efforts.
4. Observed and Projected U.S. Regional Changes
    The NCA3 assessed the climate impacts in 8 regions of the U.S., 
noting that changes in physical climate parameters such as 
temperatures, precipitation, and sea ice retreat were already having 
impacts on forests, water supplies, ecosystems, flooding, heat waves, 
and air quality. Moreover, the NCA3 found that future warming is 
projected to be much larger than recent observed variations in 
temperature, with precipitation likely to increase in the northern 
states, decrease in the southern states, and with the heaviest 
precipitation events projected to increase everywhere.
    In the Northeast, temperatures increased almost 2[emsp14][deg]F 
from 1895 to 2011, precipitation increased by about 5 inches (10 
percent), and sea level rise of about a foot has led to an increase in 
coastal flooding. The 70 percent increase in the amount of rainfall 
falling in the 1 percent of the most intense events is a larger 
increase in extreme precipitation than experienced in any other U.S. 
region.
    In the future, if emissions continue increasing, the Northeast is 
expected to experience 4.5 to 10[emsp14][deg]F of warming by the 2080s. 
This will lead to more heat waves, coastal and river flooding, and 
intense precipitation events. The southern portion of the region is 
projected to see 60 additional days per year above 90[emsp14][deg]F by 
mid-century. Sea levels in the Northeast are expected to increase 
faster than the global average because of subsidence, and changing 
ocean currents may further increase the rate of sea level rise. 
Specific vulnerabilities highlighted by the NCA include large urban 
populations particularly vulnerable to climate-related heat waves and 
poor air quality episodes, prevalence of climate sensitive vector-borne 
diseases like Lyme and West Nile Virus, usage of combined sewer systems 
that may lead to untreated water being released into local water bodies 
after climate-related heavy precipitation events, and 1.6 million 
people living within the 100-year coastal flood zone who are expected 
to experience more frequent floods due to sea level rise and tropical-
storm induced storm-surge. The NCA also highlighted infrastructure 
vulnerable to inundation in coastal metropolitan areas, potential 
agricultural impacts from increased rain in the spring delaying 
planting or damaging crops or increased heat in the summer leading to 
decreased yields and increased water demand, and shifts in ecosystems 
leading to declines in iconic species in some regions, such as cod and 
lobster south of Cape Cod.
    In the Southeast, average annual temperature during the last 
century cycled between warm and cool periods. A warm peak occurred 
during the 1930s and 1940s followed by a cool period and temperatures 
then increased again from 1970 to the present by an average of 
2[emsp14][deg]F. There have been increasing numbers of days above 
95[emsp14][deg]F and nights above 75[emsp14][deg]F, and decreasing 
numbers of extremely cold days since 1970. Daily and five-day rainfall 
intensities have also increased, and summers have been either 
increasingly dry or extremely wet. Louisiana has already lost 1,880 
square miles of land in the last 80 years due to sea level rise and 
other contributing factors.
    The Southeast is exceptionally vulnerable to sea level rise, 
extreme heat events, hurricanes, and decreased water availability. 
Major consequences of further warming include significant increases in 
the number of hot days (95[emsp14][deg]F or above) and decreases in 
freezing events, as well as exacerbated ground-level ozone in urban 
areas. Although projected warming for some parts of the region by the 
year 2100 are generally smaller than for other regions of the U.S., 
projected warming for interior states of the region are larger than 
coastal regions by 1[emsp14][deg]F to 2[emsp14][deg]F. Projections 
further suggest that globally there will be fewer tropical storms, but 
that they will be more intense, with more Category 4 and 5 storms. The 
NCA identified New Orleans, Miami, Tampa, Charleston, and Virginia 
Beach as being specific cities that are at risk due to sea level rise, 
with homes and infrastructure increasingly prone to flooding. 
Additional impacts of sea level rise are expected for coastal highways, 
wetlands, fresh water supplies, and energy infrastructure.
    In the Northwest, temperatures increased by about 1.3 [deg]F 
between 1895 and 2011. A small average increase in precipitation was 
observed over this time period. However, warming temperatures have 
caused increased rainfall relative to snowfall, which has

[[Page 64687]]

altered water availability from snowpack across parts of the region. 
Snowpack in the Northwest is an important freshwater source for the 
region. More precipitation falling as rain instead of snow has reduced 
the snowpack, and warmer springs have corresponded to earlier snowpack 
melting and reduced streamflows during summer months. Drier conditions 
have increased the extent of wildfires in the region.
    Average annual temperatures are projected to increase by 3.3 [deg]F 
to 9.7 [deg]F by the end of the century (depending on future global GHG 
emissions), with the greatest warming expected during the summer. 
Continued increases in global GHG emissions are projected to result in 
up to a 30 percent decrease in summer precipitation. Earlier snowpack 
melt and lower summer stream flows are expected by the end of the 
century and will affect drinking water supplies, agriculture, 
ecosystems, and hydropower production. Warmer waters are expected to 
increase disease and mortality in important fish species, including 
Chinook and sockeye salmon. Ocean acidification also threatens species 
such as oysters, with the Northwest coastal waters already being some 
of the most acidified worldwide due to coastal upwelling and other 
local factors. Forest pests are expected to spread and wildfires burn 
larger areas. Other high-elevation ecosystems are projected to be lost 
because they can no longer survive the climatic conditions. Low lying 
coastal areas, including the cities of Seattle and Olympia, will 
experience heightened risks of sea level rise, erosion, seawater 
inundation and damage to infrastructure and coastal ecosystems.
    In Alaska, temperatures have changed faster than anywhere else in 
the U.S. Annual temperatures increased by about 3[emsp14][deg]F in the 
past 60 years. Warming in the winter has been even greater, rising by 
an average of 6[emsp14][deg]F. Arctic sea ice is thinning and shrinking 
in area, with the summer minimum ice extent now covering only half the 
area it did when satellite records began in 1979. Glaciers in Alaska 
are melting at some of the fastest rates on Earth. Permafrost soils are 
also warming and beginning to thaw. Drier conditions have contributed 
to more large wildfires in the last 10 years than in any previous 
decade since the 1940s, when recordkeeping began. Climate change 
impacts are harming the health, safety and livelihoods of Native 
Alaskan communities.
    By the end of this century, continued increases in GHG emissions 
are expected to increase temperatures by 10 to 12 [deg]F in the 
northernmost parts of Alaska, by 8 to 10 [deg]F in the interior, and by 
6 to 8 [deg]F across the rest of the state. These increases will 
exacerbate ongoing arctic sea ice loss, glacial melt, permafrost thaw 
and increased wildfire, and threaten humans, ecosystems, and 
infrastructure. Precipitation is expected to increase to varying 
degrees across the state, however warmer air temperatures and a longer 
growing season are expected to result in drier conditions. Native 
Alaskans are expected to experience declines in economically, 
nutritionally, and culturally important wildlife and plant species. 
Health threats will also increase, including loss of clean water, 
saltwater intrusion, sewage contamination from thawing permafrost, and 
northward extension of diseases. Wildfires will increasingly pose 
threats to human health as a result of smoke and direct contact. Areas 
underlain by ice-rich permafrost across the state are likely to 
experience ground subsidence and extensive damage to infrastructure as 
the permafrost thaws. Important ecosystems will continue to be 
affected. Surface waters and wetlands that are drying provide breeding 
habitat for millions of waterfowl and shorebirds that winter in the 
lower 48 states. Warmer ocean temperatures, acidification, and 
declining sea ice will contribute to changes in the location and 
availability of commercially and culturally important marine fish.
    In the Southwest, temperatures are now about 2[emsp14][deg]F higher 
than the past century, and are already the warmest that region has 
experienced in at least 600 years. The NCA notes that there is evidence 
that climate-change induced warming on top of recent drought has 
influenced tree mortality, wildfire frequency and area, and forest 
insect outbreaks. Sea levels have risen about 7 or 8 inches in this 
region, contributing to inundation of Highway 101 and backup of 
seawater into sewage systems in the San Francisco area.
    Projections indicate that the Southwest will warm an additional 5.5 
to 9.5[emsp14][deg]F over the next century if emissions continue to 
increase. Winter snowpack in the Southwest is projected to decline 
(consistent with the record lows from this past winter), reducing the 
reliability of surface water supplies for cities, agriculture, cooling 
for power plants, and ecosystems. Sea level rise along the California 
coast will worsen coastal erosion, increase flooding risk for coastal 
highways, bridges, and low-lying airports, pose a threat to groundwater 
supplies in coastal cities such as Los Angeles, and increase 
vulnerability to floods for hundreds of thousands of residents in 
coastal areas. Climate change will also have impacts on the high-value 
specialty crops grown in the region as a drier climate will increase 
demands for irrigation, more frequent heat waves will reduce yields, 
and decreased winter chills may impair fruit and nut production for 
trees in California. Increased drought, higher temperatures, and bark 
beetle outbreaks are likely to contribute to continued increases in 
wildfires. The highly urbanized population of the Southwest is 
vulnerable to heat waves and water supply disruptions, which can be 
exacerbated in cases where high use of air conditioning triggers energy 
system failures.
    The rate of warming in the Midwest has markedly accelerated over 
the past few decades. Temperatures rose by more than 1.5[emsp14][deg]F 
from 1900 to 2010, but between 1980 and 2010 the rate of warming was 
three times faster than from 1900 through 2010.
    Precipitation generally increased over the last century, with much 
of the increase driven by intensification of the heaviest rainfalls. 
Several types of extreme weather events in the Midwest (e.g., heat 
waves and flooding) have already increased in frequency and/or 
intensity due to climate change.
    In the future, if emissions continue increasing, the Midwest is 
expected to experience 5.6 to 8.5 [deg]F of warming by the 2080s, 
leading to more heat waves. Though projections of changes in total 
precipitation vary across the regions, more precipitation is expected 
to fall in the form of heavy downpours across the entire region, 
leading to an increase in flooding. Specific vulnerabilities 
highlighted by the NCA include long-term decreases in agricultural 
productivity, changes in the composition of the region's forests, 
increased public health threats from heat waves and degraded air and 
water quality, negative impacts on transportation and other 
infrastructure associated with extreme rainfall events and flooding, 
and risks to the Great Lakes including shifts in invasive species, 
increases in harmful algal blooms, and declining beach health.
    High temperatures (more than 100 [deg]F in the Southern Plains and 
more than 95 [deg]F in the Northern Plains) are projected to occur much 
more frequently by mid-century. Increases in extreme heat will increase 
heat stress for residents, energy demand for air conditioning, and 
water losses. North Dakota's increase in annual temperatures over the 
past 130 years is the fastest in the contiguous U.S., mainly driven by 
warming winters. Specific vulnerabilities highlighted by the NCA 
include increased demand for water and energy, changes to crop growth 
cycles and

[[Page 64688]]

agricultural practices, and negative impacts on local plant and animal 
species from habitat fragmentation, wildfires, and changes in the 
timing of flowering or pest patterns. Communities that are already the 
most vulnerable to weather and climate extremes will be stressed even 
further by more frequent extreme events occurring within an already 
highly variable climate system.
    In Hawaii, other Pacific islands, and the Caribbean, rising air and 
ocean temperatures, shifting rainfall patterns, changing frequencies 
and intensities of storms and drought, decreasing baseflow in streams, 
rising sea levels, and changing ocean chemistry will affect ecosystems 
on land and in the oceans, as well as local communities, livelihoods, 
and cultures. Low islands are particularly at risk.
    Rising sea levels, coupled with high water levels caused by 
tropical and extra-tropical storms, will incrementally increase coastal 
flooding and erosion, damaging coastal ecosystems, infrastructure, and 
agriculture, and negatively affecting tourism. Ocean temperatures in 
the Pacific region exhibit strong year-to-year and decadal 
fluctuations, but since the 1950s, they have exhibited a warming trend, 
with temperatures from the surface to a depth of 660 feet rising by as 
much as 3.6 [deg]F. As a result of current sea level rise, the 
coastline of Puerto Rico around Rinc[oacute]n is being eroded at a rate 
of 3.3 feet per year. Freshwater supplies are already constrained and 
will become more limited on many islands. Saltwater intrusion 
associated with sea level rise will reduce the quantity and quality of 
freshwater in coastal aquifers, especially on low islands. In areas 
where precipitation does not increase, freshwater supplies will be 
adversely affected as air temperature rises.
    Warmer oceans are leading to increased coral bleaching events and 
disease outbreaks in coral reefs, as well as changed distribution 
patterns of tuna fisheries. Ocean acidification will reduce coral 
growth and health. Warming and acidification, combined with existing 
stresses, will strongly affect coral reef fish communities. For Hawaii 
and the Pacific islands, future sea surface temperatures are projected 
to increase 2.3 [deg]F by 2055 and 4.7 [deg]F by 2090 under a scenario 
that assumes continued increases in emissions. Ocean acidification is 
also taking place in the region, which adds to ecosystem stress from 
increasing temperatures. Ocean acidity has increased by about 30 
percent since the pre-industrial era and is projected to further 
increase by 37 percent to 50 percent from present levels by 2100.
    The NCA also discussed impacts that occur along the coasts and in 
the oceans adjacent to many regions, and noted that other impacts occur 
across regions and landscapes in ways that do not follow political 
boundaries.

B. GHG Emissions From Fossil Fuel-Fired EGUs \45\
---------------------------------------------------------------------------

    \45\ The emission data presented in this section of the preamble 
(Section II.B) are in metric tons, in keeping with reporting 
requirements for the GHGRP and the U.S. GHG Inventory. Note that the 
mass-based state goals presented in section VII of this preamble, 
and discussed elsewhere in this preamble, are presented in short 
tons.
---------------------------------------------------------------------------

    Fossil fuel-fired electric utility generating units (EGUs) are by 
far the largest emitters of GHGs among stationary sources in the U.S., 
primarily in the form of CO2, and among fossil fuel-fired 
EGUs, coal-fired units are by far the largest emitters. This section 
describes the amounts of these emissions and places these amounts in 
the context of the U.S. Inventory of Greenhouse Gas Emissions and Sinks 
\46\ (the U.S. GHG Inventory).
---------------------------------------------------------------------------

    \46\ ``Inventory of U.S. Greenhouse Gas Emissions and Sinks: 
1990--2013'', Report EPA 430-R-15-004, United States Environmental 
Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
---------------------------------------------------------------------------

    The EPA implements a separate program under 40 CFR part 98 called 
the Greenhouse Gas Reporting Program \47\ (GHGRP) that requires 
emitting facilities over threshold amounts of GHGs to report their 
emissions to the EPA annually. Using data from the GHGRP, this section 
also places emissions from fossil fuel-fired EGUs in the context of the 
total emissions reported to the GHGRP from facilities in the other 
largest-emitting industries.
---------------------------------------------------------------------------

    \47\ U.S. EPA Greenhouse Gas Reporting Program Dataset, see 
http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html.
---------------------------------------------------------------------------

    The EPA prepares the official 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 \48\ 
of GHGs, including CO2 emissions, for the years 1990, 2005 
and 2013.
---------------------------------------------------------------------------

    \48\ Sinks are a physical unit or process that stores GHGs, such 
as forests or underground or deep sea reservoirs of carbon dioxide.
    \49\ From Table ES-4 of ``Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2013'', Report EPA 430-R-15-004, U.S. 
Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
    \50\ The energy sector includes all greenhouse gases resulting 
from stationary and mobile energy activities, including fuel 
combustion and fugitive fuel emissions.

                                 Table 3--U.S. GHG Emissions and Sinks by Sector
                       [Million metric tons carbon dioxide equivalent (MMT CO2 Eq.)] \49\
----------------------------------------------------------------------------------------------------------------
                             Sector                                    1990            2005            2013
----------------------------------------------------------------------------------------------------------------
Energy \50\.....................................................         5,290.5         6,273.6         5,636.6
Industrial Processes and Product Use............................           342.1           367.4           359.1
Agriculture.....................................................           448.7           494.5           515.7
Land Use, Land-Use Change and Forestry..........................            13.8            25.5            23.3
Waste...........................................................           206.0           189.2           138.3
                                                                 -----------------------------------------------
    Total Emissions.............................................         6,301.1         7,350.2         6,673.0
Land Use, Land-Use Change and Forestry (Sinks)..................         (775.8)         (911.9)         (881.7)
                                                                 -----------------------------------------------
Net Emissions (Sources and Sinks)...............................         5,525.2         6,438.3         5,791.2
----------------------------------------------------------------------------------------------------------------

    Total fossil energy-related CO2 emissions (including 
both stationary and mobile sources) are the largest contributor to 
total U.S. GHG emissions, representing 77.3 percent of total 2013 GHG 
emissions.\51\ In 2013, fossil fuel

[[Page 64689]]

combustion by the utility power sector--entities that burn fossil fuel 
and whose primary business is the generation of electricity--accounted 
for 38.3 percent of all energy-related CO2 emissions.\52\ 
Table 4 below presents total CO2 emissions from fossil fuel-
fired EGUs, for years 1990, 2005 and 2013.
---------------------------------------------------------------------------

    \51\ From Table ES-2 ``Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2013'', Report EPA 430-R-15-004, United 
States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
    \52\ From Table 3-1 ``Inventory of U.S. Greenhouse Gas Emissions 
and Sinks: 1990-2013'', Report EPA 430-R-15-004, United States 
Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.

           Table 4--U.S. GHG Emissions From Generation of Electricity From Combustion of Fossil Fuels
                                                 [MMT CO2] \53\
----------------------------------------------------------------------------------------------------------------
                          GHG emissions                                1990            2005            2013
----------------------------------------------------------------------------------------------------------------
Total CO2 from fossil fuel-fired EGUs...........................         1,820.8         2,400.9         2,039.8
    --from coal.................................................         1,547.6         1,983.8         1,575.0
    --from natural gas..........................................           175.3           318.8           441.9
    --from petroleum............................................            97.5            97.9            22.4
----------------------------------------------------------------------------------------------------------------

    In addition to preparing the official U.S. GHG Inventory to present 
comprehensive total U.S. GHG emissions and comply with commitments 
under the UNFCCC, the EPA collects detailed GHG emissions data from the 
largest emitting facilities in the U.S. through its Greenhouse Gas 
Reporting Program (GHGRP). Data collected by the GHGRP from large 
stationary sources in the industrial sector show that the utility power 
sector emits far greater CO2 emissions than any other 
industrial sector. Table 5 below presents total GHG emissions in 2013 
for the largest emitting industrial sectors as reported to the GHGRP. 
As shown in Table 4 and Table 5, respectively, CO2 emissions 
from fossil fuel-fired EGUs are nearly three times as large as the 
total reported GHG emissions from the next ten largest emitting 
industrial sectors in the GHGRP database combined.
---------------------------------------------------------------------------

    \53\ From Table 3-5 ``Inventory of U.S. Greenhouse Gas Emissions 
and Sinks: 1990-2013'', Report EPA 430-R-15-004, United States 
Environmental Protection Agency, April 15 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.

   Table 5--Direct GHG Emissions Reported to GHGRP by Largest Emitting
                           Industrial Sectors
                             [MMT CO2e] \54\
------------------------------------------------------------------------
                      Industrial sector                          2013
------------------------------------------------------------------------
Petroleum Refineries........................................       176.7
Onshore Oil & Gas Production................................        94.8
Municipal Solid Waste Landfills.............................        93.0
Iron & Steel Production.....................................        84.2
Cement Production...........................................        62.8
Natural Gas Processing Plants...............................        59.0
Petrochemical Production....................................        52.7
Hydrogen Production.........................................        41.9
Underground Coal Mines......................................        39.8
Food Processing Facilities..................................        30.8
------------------------------------------------------------------------

C. Challenges in Controlling Carbon Dioxide Emissions

    Carbon dioxide is a unique air pollutant and controlling it 
presents unique challenges. CO2 is emitted in enormous 
quantities, and those quantities, coupled with the fact that 
CO2 is relatively unreactive, make it much more difficult to 
mitigate by measures or technologies that are typically utilized within 
an existing power plant. Measures that may be used to limit 
CO2 emissions would include efficiency improvements, which 
have thermodynamic limitations and carbon capture and sequestration 
(CCS), which is energy resource intensive.
---------------------------------------------------------------------------

    \54\ U.S. EPA Greenhouse Gas Reporting Program Dataset as of 
August 18, 2014. http://ghgdata.epa.gov/ghgp/main.do.
---------------------------------------------------------------------------

    Unlike other air pollutants which are results of trace impurities 
in the fuel, products of incomplete or inefficient combustion, or 
combustion byproducts, CO2 is an inherent product of clean, 
efficient combustion of fossil fuels, and therefore is an unavoidable 
product generated in enormous quantities, far greater than any other 
air pollutant.\55\ In fact, CO2 is emitted in far greater 
quantities than all other air pollutants combined. Total emissions of 
all non-GHG air pollutants in the U.S., from all sources, in 2013, were 
121 million metric tons.56 57
---------------------------------------------------------------------------

    \55\ Lackner et al., ``Comparative Impacts of Fossil Fuels and 
Alternative Energy Sources'', Issues in Environmental Science and 
Technology (2010).
    \56\ This includes NAAQS and HAPs, based on the following table: 
(see table above).
    It should be noted that PM2.5 is included in the 
amounts for PM10. Lead, another NAAQS pollutant, is 
emitted in the amounts of approximately 1,000 tons per year, and, in 
light of that relatively small quantity, was excluded from this 
analysis. Ammonia (NH3) is included because it is a 
precursor to PM2.5 secondary formation. Note that one 
short ton is equivalent to 0.907185 metric ton.
    \57\ In addition, emissions of non-CO2 GHGs totaled 
1.168 billion metric tons of carbon-dioxide equivalents 
(CO2e) in 2013. See Table ES-2, Executive Summary, 1990-
2013 Inventory of U.S. Greenhouse Gas Emissions and Sinks. http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2015-Chapter-Executive-Summary.pdf. This includes emissions of 
methane, nitrous oxide, and fluorinated GHGs (hydrofluorocarbons, 
perfluorocarbons, sulfur hexafluoride, and nitrogen trifluoride). In 
the total, the emissions of each non-CO2 GHG have been 
translated from metric tons of that gas into metric tons of 
CO2e by multiplying the metric tons of the gas by the 
global warming potential (GWP) of the gas. (The GWP of a gas is a 
measure of the ability of one kilogram of that gas to trap heat in 
earth's atmosphere compared to one kilogram of CO2.)

----------------------------------------------------------------------------------------------------------------
                                                    2013 tons (million
                   Pollutant                           short tons)                       Reference
----------------------------------------------------------------------------------------------------------------
CO.............................................                   69.758  Trends file (http://www.epa.gov/ttnchie1/trends/ ttnchie1/trends/).
NOX............................................                   13.072   ''
PM10...........................................                   20.651   ''
SO2............................................                    5.098   ''
VOC............................................                   17.471   ''
NH3............................................                    4.221   ''
HAPS...........................................                    3.641  2011 NEI version 2 (http://www.epa.gov/ttn/chief/net/2011inventory.html).
                                                -------------------------
    Total......................................                  133.912
----------------------------------------------------------------------------------------------------------------


[[Page 64690]]

As noted above, total emissions of CO2 from coal-fired power 
plants alone--the largest stationary source emitter--were 1.575 billion 
metric tons in that year,\58\ and total emissions of CO2 
from all sources were 5.5 billion metric tons.59 60 Carbon 
makes up the majority of the mass of coal and other fossil fuels, and 
for every ton of carbon burned, more than 3 tons of CO2 is 
produced.\61\ In addition, unlike many of the other air pollutants that 
react with sunlight or chemicals in the atmosphere, or are rained out 
or deposited on surfaces, CO2 is relatively unreactive and 
difficult to remove directly from the atmosphere.62 63
---------------------------------------------------------------------------

    \58\ From Table 3-5 ``Inventory of U.S. Greenhouse Gas Emissions 
and Sinks: 1990-2013'', Report EPA 430-R-15-004, United States 
Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
    \59\ U.S. EPA, Greenhouse Gas Inventory Data Explorer, http://www.epa.gov/climatechange/ghgemissions/inventoryexplorer/#allsectors/allgas/gas/current.
    \60\ As another point of comparison, except for carbon dioxide, 
SO2 and NOX are the largest air pollutant 
emissions from coal-fired power plants. Over the past decade, U.S. 
power plants have emitted more than 200 times as much CO2 
as they have emitted SO2 and NOX. See de Gouw 
et al., ``Reduced emissions of CO2, NOX, and 
SO2 from U.S. power plants owing to switch from coal to 
natural gas with combined cycle technology,'' Earth's Future (2014).
    \61\ Each atom of carbon in the fuel combines with 2 atoms of 
oxygen in the air.
    \62\ Seinfeld J. and Pandis S., Atmospheric Chemistry and 
Physics: From Air Pollution to Climate Change (1998).
    \63\ The fact that CO2 is unreactive means that it is 
primarily removed from the atmosphere by dissolving in oceans or by 
being converted into biomass by plants. Herzog, H., ``Scaling up 
carbon dioxide capture and storage: From megatons to gigatons'', 
Energy Economics (2011).
---------------------------------------------------------------------------

    CO2's huge quantities and lack of reactivity make it 
challenging to remove from the smokestack. Retrofitted equipment is 
required to capture the CO2 before transporting it to a 
storage site. However, the scale of infrastructure required to directly 
mitigate CO2 emissions from existing EGUs through CCS can be 
quite large and difficult to integrate into the existing fossil fuel 
infrastructure. These CCS techniques are discussed in more depth 
elsewhere in the preamble for this rule and for the section 111(b) rule 
for new sources that accompanies this rule.
    The properties of CO2 can be contrasted with those of a 
number of other pollutants which have more accessible mitigation 
options. For example, the NAAQS pollutants--which generally are emitted 
in the largest quantities of any of the other air pollutants, except 
for CO2--each have more accessible mitigation options. 
Sulfur dioxide (SO2) is the result of a contaminant in the 
fuel, and, as a result, it can be reduced by using low-sulfur coal or 
by using flue-gas desulfurization (FGD) technologies. Emissions of 
NOX can be mitigated relatively easily using combustion 
control techniques (e.g., low-NOX burners) and by using 
downstream controls such as selective catalytic reduction (SCR) and 
selective non-catalytic reduction (SNCR) technologies. PM can be 
effectively mitigated using fabric filters, PM scrubbers, or 
electrostatic precipitators. Lead is part of particulate matter 
emissions and is controlled through the same devices. Carbon monoxide 
and VOCs are the products of incomplete combustion and can therefore be 
abated by more efficient combustion conditions, and can also be 
destroyed in the smokestack by the use of oxidation catalysts which 
complete the combustion process. Many air toxics are VOCs, such as 
polyaromatic hydrocarbons, and therefore can be abated in the same ways 
just described. But in every case, these pollutants can be controlled 
at the source much more readily than CO2 primarily because 
of the comparatively lower quantities that are produced, and also due 
to other attributes such as relatively greater reactivity and 
solubility.

D. The Utility Power Sector

1. A Brief History
    The modern American electricity system is one of the greatest 
engineering achievements of the past 100 years. Since the invention of 
the incandescent light bulb in the 1870s,\64\ electricity has become 
one of the major foundations for modern American life. Beginning with 
the first power station in New York City in 1882, each power station 
initially served a discrete set of consumers, resulting in small and 
localized electricity systems.\65\ During the early 1900s, smaller 
systems consolidated, allowing generation resources to be shared over 
larger areas. Interconnecting systems have reduced generation 
investment costs and improved reliability.\66\ Local and state 
governments initially regulated these growing electricity systems with 
federal regulation coming later in response to public concerns about 
rising electricity costs.\67\
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    \64\ Regulatory Assistance Project (RAP), Electricity Regulation 
in the US: A Guide, at 1 (2011), available at http://www.raponline.org/document/download/id/645.
    \65\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 2-4 (2d ed. 2010).
    \66\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 5-6 (2d ed. 2010). Investment in electric 
generation is extremely capital intensive, with generation 
potentially accounting for 65 percent of customer costs. If these 
costs can be spread to more customers, then this can reduce the 
amount that each individual customer pays. Federal Energy Regulatory 
Commission, Energy Primer: A Handbook of Energy Market Basics, at 38 
(2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \67\ Burn, An Energy Journal, The Electricity Grid: A History, 
available at http://burnanenergyjournal.com/the-electric-grid-a-history/ (last visited Mar. 9, 2015).
---------------------------------------------------------------------------

    Initially, states had broad authority to regulate public utilities, 
but gradually federal regulation increased. In 1920, Congress passed 
the Federal Water Power Act, creating the Federal Power Commission 
(FPC) and providing for the licensing of hydroelectric facilities on 
U.S. government lands and navigable waters of the U.S.\68\ During this 
time period, the U.S. Supreme Court found that state authority to 
regulate public utilities is limited, holding that the Commerce Clause 
does not allow state regulation to directly burden interstate 
commerce.\69\ For example, in Public Utilities Commission of Rhode 
Island v. Attleboro Steam & Electric Company, Rhode Island sought to 
regulate the electricity rates that a Rhode Island generator was 
charging to a company in Massachusetts that resold the electricity to 
Attleboro, Massachusetts.\70\ The Supreme Court found that Rhode 
Island's regulation was impermissible because it imposed a ``direct 
burden upon interstate commerce.'' \71\ The Supreme Court held that 
this kind of interstate transaction was not subject to state 
regulation. However, because Congress had not yet passed legislation to 
make these types of transactions subject to federal regulation, this 
became known as the ``Attleboro gap'' in regulation. In 1935, Congress 
passed the Federal Power Act (FPA), giving the FPC jurisdiction over 
``the transmission of electric energy in interstate commerce'' and 
``the sale of electric energy at wholesale in interstate commerce.'' 
\72\ Under FPA section 205, the FPC was tasked with ensuring that rates 
for jurisdictional services are just, reasonable, and not unduly 
discriminatory or preferential.\73\ FPA section 206 authorized the FPC 
to determine, after a hearing upon its own motion or in response to a 
complaint

[[Page 64691]]

filed at the Commission, whether jurisdictional rates are just, 
reasonable, and not unduly discriminatory or preferential.\74\ In 1938, 
Congress passed the Natural Gas Act (NGA), giving the FPC jurisdiction 
over the transmission or sale of natural gas in interstate 
commerce.\75\ The NGA also gave the FPC the jurisdiction to ``grant 
certificates allowing construction and operation of facilities used in 
interstate gas transmission and authorizing the provision of 
services.'' \76\ In 1977, the FPC became FERC after Congress passed the 
Department of Energy Organization Act.
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    \68\ The FPC became an independent Commission in 1930. United 
States Government Manual 1945: First Edition, at 486, available at 
http://www.ibiblio.org/hyperwar/ATO/USGM/FPC.html.
    \69\ New York v. Federal Energy Regulatory Commission, 535 U.S. 
1, 5 (2002) (citation omitted).
    \70\ Public Utils. Comm'n of Rhode Island v. Attleboro Steam & 
Elec. Co., 273 U.S. 83 (1927).
    \71\ Public Utils. Comm'n of Rhode Island v. Attleboro Steam & 
Elec. Co., 273 U.S. 83, 89 (1927).
    \72\ 16 U.S.C. 824(b)(1).
    \73\ 16 U.S.C. 824d.
    \74\ 16 U.S.C. 824e.
    \75\ Energy Information Administration, Natural Gas Act of 1938, 
available at http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngmajorleg/ngact1938.html.
    \76\ Energy Information Administration, Natural Gas Act of 1938, 
available at http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngmajorleg/ngact1938.html.
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    By the 1930s, regulated electric utilities that provided the major 
components of the electrical system--generation, transmission, and 
distribution--were common.\77\ These regulated monopolies are referred 
to as vertically-integrated utilities.
---------------------------------------------------------------------------

    \77\ Burn, An Energy Journal, The Electricity Grid: A History, 
available at http://burnanenergyjournal.com/the-electric-grid-a-history/ (last visited Mar. 9, 2015).
---------------------------------------------------------------------------

    As utilities built larger and larger electric generation plants, 
the cost per unit to generate electricity decreased.\78\ However, these 
larger plants were extremely capital intensive for any one company to 
fund.\79\ Some neighboring utilities solved this issue by agreeing to 
share electricity reserves when needed.\80\ These utilities began 
building larger transmission lines to deliver power in times when large 
generators experienced outages.\81\ Eventually, some utilities that 
were in reserve sharing agreements formed electric power pools to 
balance electric load over a larger area. Participating utilities gave 
control over scheduling and dispatch of their electric generation units 
to a system operator.\82\ Some power pools evolved into today's RTOs 
and ISOs.
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    \78\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \79\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \80\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \81\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \82\ Shively, B, Ferrare, J, Understanding Today's Electricity 
Business, Enerdynamics, at 94 (2012).
---------------------------------------------------------------------------

    In the past, electric utilities generally operated as state 
regulated monopolies, supplying end-use customers with generation, 
distribution, and transmission service.\83\ However, the ability of 
electric utilities to operate as natural monopolies came with consumer 
protection safeguards.\84\ ``In exchange for a franchised, monopoly 
service area, utilities accept an obligation to serve--meaning there 
must be adequate supply to meet customers' needs regardless of the 
cost.'' \85\ Under this obligation to serve, the utility agreed to 
provide service to any customer located within its service 
jurisdiction.
---------------------------------------------------------------------------

    \83\ Maryland Department of Natural Resources, Maryland Power 
Plants and the Environment: A Review of the Impacts of Power Plants 
and Transmission Lines on Maryland's Natural Resources, at 2-5 
(2006), available at http://esm.versar.com/pprp/ceir13/toc.htm.
    \84\ Pacific Power, Utility Regulation, at 1, available at 
https://www.pacificpower.net/content/dam/pacific_power/doc/About_Us/Newsroom/Media_Resources/Regulation.PP.08.pdf.
    \85\ Pacific Power, Utility Regulation, at 1, available at 
https://www.pacificpower.net/content/dam/pacific_power/doc/About_Us/Newsroom/Media_Resources/Regulation.PP.08.pdf.
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    On both a federal and state level, competition has entered the 
electricity sector to varying degrees in the last few decades.\86\ In 
the early 1990s, some states began to consider allowing competition to 
enter retail electric service.\87\ Federal and state efforts to allow 
competition in the electric utility industry have resulted in 
independent power producers (IPPs) \88\ producing approximately 37 
percent of net generation in 2013.\89\ Electric utilities in some 
states remain vertically integrated without retail competition from 
IPPs. Today, there are over 3,000 public, private, and cooperative 
utilities in the U.S.\90\ These utilities include both investor-owned 
utilities \91\ and consumer-owned utilities.\92\
---------------------------------------------------------------------------

    \86\ For example, in 1978, Congress passed the Public Utilities 
Regulatory Policies Act (PURPA) which allowed non-utility owned 
power plants to sell electricity. Burn, An Energy Journal, The 
Electricity Grid: A History, available at http://burnanenergyjournal.com/the-electric-grid-a-history/ (last visited 
Mar. 9, 2015). PURPA, the Energy Policy Act of 1992 (EPAct 1992), 
and the Energy Policy Act of 2005 (EPAct 2005) ``promoted 
competition by lowering entry barriers and increasing transmission 
access.'' The Electric Energy Market Competition Task Force, Report 
to Congress on Competition in Wholesale and Retail Markets for 
Electric Energy, at 2, available at http://www.ferc.gov/legal/fed-sta/ene-pol-act/epact-final-rpt.pdf (last visited Mar. 20, 2015).
    \87\ The Electric Energy Market Competition Task Force, Report 
to Congress on Competition in Wholesale and Retail Markets for 
Electric Energy, at 2, available at http://www.ferc.gov/legal/fed-sta/ene-pol-act/epact-final-rpt.pdf (last visited Mar. 20, 2015).
    \88\ These entities are also referred to as merchant generators.
    \89\ Energy Information Administration, Electric Power Annual, 
Table 1.1 Total Electric Power Summary Statistics, 2013 and 2012 
(2015), available at http://www.eia.gov/electricity/annual/html/epa_01_01.html.
    \90\ Regulatory Assistance Project (RAP), Electricity Regulation 
in the US: A Guide, at 9 (2011), available at http://www.raponline.org/document/download/id/645.
    \91\ Investor-owned utilities are private companies that are 
financed by a combination of shareholder equity and bondholder debt. 
Regulatory Assistance Project (RAP), Electricity Regulation in the 
US: A Guide, at 9 (2011), available at http://www.raponline.org/document/download/id/645.
    \92\ Consumer-owned utilities include municipal utilities, 
public utility districts, cooperatives, and a variety of other 
entities such as irrigation districts. Regulatory Assistance Project 
(RAP), Electricity Regulation in the US: A Guide, at 9-10 (2011), 
available at http://www.raponline.org/document/download/id/645.
---------------------------------------------------------------------------

    Over time, the grid slowly evolved into a complex, interconnected 
transmission system that allows electric generators to produce 
electricity that is then fed onto transmission lines at high 
voltages.\93\ These larger transmission lines are able to access 
generation that is located more remotely, with transmission lines 
crossing many miles, including state borders.\94\ Closer to end users, 
electricity is transformed into a lower voltage that is transported 
across

[[Page 64692]]

localized transmission lines to homes and businesses.\95\ Localized 
transmission lines make up the distribution system. These three 
components of the electricity system--generation, transmission, and 
distribution--are closely related and must work in coordination to 
deliver electricity from the point of generation to the point of 
consumption. This interconnectedness is a fundamental aspect of the 
nation's electricity system, requiring a complicated integration of all 
components of the system to balance supply and demand and a federal, 
state, and local regulatory network to oversee the physically 
interconnected network. Facilities planned and constructed in one 
segment can impact facilities and operations in other segments and vice 
versa.
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    \93\ Peter Fox-Penner, Electric Utility Restructuring: A Guide 
to the Competitive Era, Public Utility Reports, Inc., at 5, 34 
(1997). ``The extent of the power system's short-run physical 
interdependence is remarkable, if not entirely unique. No other 
large, multi-stage industry is required to keep every single 
producer in a region--whether or not owned by the same company--in 
immediate synchronization with all other producers.'' Id. at 34. 
``At an early date, those providing electric power recognized that 
peak use for one system often occurred at a different time from peak 
use in other systems. They also recognized that equipment failures 
occurred at different times in various systems. Analyses showed 
significant economic benefits from interconnecting systems to 
provide mutual assistance; the investment required for generating 
capacity could be reduced and reliability could be improved. This 
lead [sic] to the development of local, then regional, and 
subsequently three transmission grids that covered the U.S. and 
parts of Canada.'' Casazza, J. and Delea, F., Understanding Electric 
Power Systems, IEEE Press, at 5-6 (2d ed. 2010).
    \94\ Burn, An Energy Journal, The Electricity Grid: A History, 
available at http://burnanenergyjournal.com/the-electric-grid-a-history/ (last visited Mar. 9, 2015). Because of the ease and low 
cost of converting voltages in an alternating current (AC) system 
from one level to another, the bulk power system is predominantly an 
AC system rather than a direct current (DC) system. In an AC system, 
electricity cannot be controlled like a gas or liquid by utilizing a 
valve in a pipe. Instead, absent the presence of expensive control 
devices, electricity flows freely along all available paths, 
according to the laws of physics. U.S.-Canada Power System Outage 
Task Force, Final Report on the August 14, 2003 Blackout in the 
United States and Canada: Causes and Recommendations, at 6 (Apr. 
2004), available at http://www.ferc.gov/industries/electric/indus-act/reliability/blackout/ch1-3.pdf.
    \95\ Peter Fox-Penner, Electric Utility Restructuring: A Guide 
to the Competitive Era, Public Utility Reports, Inc., at 5 (1997).
---------------------------------------------------------------------------

    The North American electric grid has developed into a large, 
interconnected system.\96\ Electricity from a diverse set of generation 
resources such as natural gas, nuclear, coal, and renewables is 
distributed over high-voltage transmission lines divided across the 
continental U.S. into three synchronous interconnections--the Eastern 
Interconnection, Western Interconnection, and the Texas 
Interconnection.\97\ These three synchronous systems each act like a 
single machine.\98\ Diverse resources generate electricity that is 
transmitted and distributed through a complex system of interconnected 
components to industrial, business, and residential consumers. Unlike 
other industries where sources make operational decisions 
independently, the utility power sector is unique in that electricity 
system resources operate in a complex, interconnected grid system that 
is physically interconnected and operated on an integrated basis across 
large regions. Additionally, a federal, state, and local regulatory 
network oversees policies and practices that are applied to how the 
system is designed and operates. In this interconnected system, system 
operators must ensure that the amount of electricity available is 
precisely matched with the amount needed in real time. System operators 
have a number of resources potentially available to meet electricity 
demand, including electricity generated by electric generation units 
such as coal, nuclear, renewables, and natural gas, as well as demand-
side resources,\99\ such as EE \100\ and demand response.\101\ 
Generation, outages, and transmission changes in one part of the 
synchronous grid can affect the entire interconnected grid.\102\ The 
interconnection is such that ``[i]f a generator is lost in New York 
City, its affect is felt in Georgia, Florida, Minneapolis, St. Louis, 
and New Orleans.'' \103\ The U.S. Supreme Court has similarly 
recognized the interconnected nature of the electricity grid.\104\
---------------------------------------------------------------------------

    \96\ U.S.-Canada Power System Outage Task Force, Final Report on 
the August 14, 2003 Blackout in the United States and Canada: Causes 
and Recommendations, at 5 (Apr. 2004), available at http://www.ferc.gov/industries/electric/indus-act/reliability/blackout/ch1-3.pdf.
    \97\ Regulatory Assistance Project (RAP), Electricity Regulation 
in the US: A Guide, 2011, at 1, available at http://www.raponline.org/document/download/id/645.
    \98\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 159 (2d ed. 2010). In an amicus brief to the 
Supreme Court, a group of electrical engineers, economists, and 
physicists specializing in electricity explained, ``Energy is 
transmitted, not electrons. Energy transmission is accomplished 
through the propagation of an electromagnetic wave. The electrons 
merely oscillate in place, but the energy--the electromagnetic 
wave--moves at the speed of light. The energized electrons making 
the lightbulb in a house glow are not the same electrons that were 
induced to oscillate in the generator back at the power plant. . . . 
Energy flowing onto a power network or grid energizes the entire 
grid, and consumers then draw undifferentiated energy from that 
grid. A networked grid flexes, and electric current flows, in 
conformity with physical laws, and those laws do not notice, let 
alone conform to, political boundaries. . . . The path taken by 
electric energy is the path of least resistance . . . or, more 
accurately, the paths of least resistance. . . . If a generator on 
the grid increases its output, the current flowing from the 
generator on all paths on the grid increases. These increases affect 
the energy flowing into each point in the network, which in turn 
leads to compensating and corresponding changes in the energy flows 
out of each point.'' Brief Amicus Curiae of Electrical Engineers, 
Energy Economists and Physicists in Support of Respondents at 2, 8-
9, 11, New York v. FERC, 535 U.S. 1 (2001) (No. 00-568).
    \99\ ``Measures using demand-side resources comprise actions 
taken on the customer's side of the meter to change the amount and/
or timing of electricity use in ways that will provide benefits to 
the electricity supply system.'' David Crossley, Regulatory 
Assistance Project (RAP), Effective Mechanisms to Increase the Use 
of Demand-Side Resources, at 9 (2013), available at 
www.raponline.org.
    \100\ Energy efficiency is using less energy to provide the same 
or greater level of service. Demand-side energy efficiency refers to 
an extensive array of technologies, practices and measures that are 
applied throughout all sectors of the economy to reduce energy 
demand while providing the same, and sometimes better, level and 
quality of service.
    \101\ Demand response involves ``[c]hanges in electric usage by 
demand-side resources from their normal consumption patterns in 
response to changes in the price of electricity over time, or to 
incentive payments designed to induce lower electricity use at times 
of high wholesale market prices or when system reliability is 
jeopardized.'' Federal Energy Regulatory Commission, Reports on 
Demand Response & Advanced Metering, (Dec. 23, 2014), available at 
http://www.ferc.gov/industries/electric/indus-act/demand-response/dem-res-adv-metering.asp.
    \102\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 159 (2d ed. 2010).
    \103\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 160 (2d ed. 2010).
    \104\ Federal Power Comm'n v. Florida Power & Light Co., 404 
U.S. 453, at 460 (1972) (quoting a Federal Power Commission hearing 
examiner, ```If a housewife in Atlanta on the Georgia system turns 
on a light, every generator on Florida's system almost instantly is 
caused to produce some quantity of additional electric energy which 
serves to maintain the balance in the interconnected system between 
generation and load.''') (citation omitted). See also New York v. 
FERC, 535 U.S. 1, at 7 (2002) (stating that ``any electricity that 
enters the grid immediately becomes a part of a vast pool of energy 
that is constantly moving in interstate commerce.'') (citation 
omitted). In Federal Power Comm'n v. Southern California Edison Co., 
376 U.S. 205 (1964), the Supreme Court found that a sale for resale 
of electricity from Southern California Edison to the City of 
Colton, which took place solely in California, was under Federal 
Power Commission jurisdiction because some of the electricity that 
Southern California Edison marketed came from out of state. The 
Supreme Court stated that, ```federal jurisdiction was to follow the 
flow of electric energy, an engineering and scientific, rather than 
a legalistic or governmental, test.''' Id. at 210 (quoting 
Connecticut Light & Power Co. v. Federal Power Commission, 324 U.S. 
515, 529 (1945) (emphasis omitted)).
---------------------------------------------------------------------------

    Today, federal, state, and local entities regulate electricity 
providers.\105\ Overlaid on the physical electricity network is a 
regulatory network that has developed over the last century or more. 
This regulatory network ``plays a vital role in the functioning of all 
other networks, sometimes providing specific rules for functioning 
while at other times providing restraints within which their operation 
must be conducted.'' \106\ This unique regulatory network results in an 
electricity grid that is both physically interconnected and connected 
through a network of regulation on the local, state, and federal 
levels. This regulation seeks to reconcile the fact that electricity is 
a public good with the fact that facilities providing that electricity 
are privately owned.\107\ While this regulation began on the state and 
local levels, federal regulation of the electricity system increased 
over time. With the passage of the EPAct 1992 and the EPAct 2005, the 
federal government's role in electricity regulation greatly 
increased.\108\ ``The role of the regulator now includes support for 
the development of open

[[Page 64693]]

and fair wholesale electric markets, ensuring equal access to the 
transmission system and more hands-on oversight and control of the 
planning and operating rules for the industry.'' \109\
---------------------------------------------------------------------------

    \105\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 214 (2d ed. 2010).
    \106\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 213 (2d ed. 2010).
    \107\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 213 (2d ed. 2010).
    \108\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 214 (2d ed. 2010).
    \109\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 214 (2d ed. 2010).
---------------------------------------------------------------------------

2. Electric System Dispatch
    System operators typically dispatch the electric system through a 
process known as Security Constrained Economic Dispatch.\110\ Security 
Constrained Economic Dispatch has two components--economic generation 
of generation facilities and ensuring that the electric system remains 
reliable.\111\ Electricity demand varies across geography and time in 
response to numerous conditions, such that electric generators are 
constantly responding to changes in the most reliable and cost-
effective manner possible. The cost of operating electric generation 
varies based on a number of factors, such as fuel and generator 
efficiency.
---------------------------------------------------------------------------

    \110\ Economic Dispatch: Concepts, Practices and Issues, FERC 
Staff Presentation to the Joint Board for the Study of Economic 
Dispatch, Palm Springs, California (Nov. 13, 2005), available at 
http://www.ferc.gov/CalendarFiles/20051110172953-FERC%20Staff%20Presentation.pdf.
    \111\ Federal Energy Regulatory Commission, Security Constrained 
Economic Dispatch: Definitions, Practices, Issues and 
Recommendations: A Report to Congress (July 31, 2006). The Energy 
Policy Act of 2005 defined economic dispatch as ``the operation of 
generation facilities to produce energy at the lowest cost to 
reliably serve consumers, recognizing any operational limits of 
generation and transmission facilities.'' Energy Policy Act of 2005, 
Pub. L. 109-58, 119 Stat. 594 (2005), section 1234(b), available at 
http://www.ferc.gov/industries/electric/indus-act/joint-boards/final-cong-rpt.pdf.
---------------------------------------------------------------------------

    The decision to dispatch any particular electric generator depends 
upon the relative operating cost, or marginal cost, of generating 
electricity to meet the last increment of electric demand. Fuel is one 
common variable cost--especially for fossil-fueled generators. Coal 
plants will often have considerable variable costs associated with 
running pollution controls.\112\ Renewables, hydroelectric, and nuclear 
have little to no variable costs. If electricity demand decreases or 
additional generation becomes available on the system, this impacts how 
the system operator will dispatch the system. EGUs using technologies 
with relatively low variable costs, such as nuclear units and RE, are 
for economic reasons generally operated at their maximum output 
whenever they are available. When lower cost units are available to 
run, higher variable cost units, such as fossil-fuel generators, are 
generally the first to be displaced.
---------------------------------------------------------------------------

    \112\ Variable costs also include costs associated with 
operation and maintenance and costs of operating a pollution control 
and/or emission allowance charges.
---------------------------------------------------------------------------

    In states with cost-of-service regulation of vertically-integrated 
utilities, the utilities themselves form the balancing authorities who 
determine dispatch based upon the lowest marginal cost. These utilities 
sometimes arrange to buy and sell electricity with other balancing 
authorities. RTOs and ISOs coordinate, control, and monitor electricity 
transmission systems to ensure cost-effective and reliable delivery of 
power, and they are independent from market participants.
3. Reliability Considerations
    The reliability of the electric system has long been a focus of the 
electric industry and regulators. Industry developed a voluntary 
organization in the early 1960s that assisted with bulk power system 
coordination in the U.S. and Canada.\113\ In 1965, the northeastern 
U.S. and southeastern Ontario, Canada experienced the largest power 
blackout to date, impacting 30 million people.\114\ In response to the 
1965 blackout and a Federal Power Commission recommendation,\115\ 
industry developed the National Electric Reliability Council (NERC) and 
nine reliability councils. The organization later became known as the 
North American Electric Reliability Council to recognize Canada's 
participation.\116\ The North American Electric Reliability Council 
became the North American Electric Reliability Corporation in 
2007.\117\
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    \113\ North American Electric Reliability Corporation, History 
of NERC, at 1 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.
    \114\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 39 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \115\ The Federal Power Commission, a precursor to FERC, 
recommended ``the formation of a council on power coordination made 
up of representatives from each of the nation's regional 
coordinating organizations, to exchange and disseminate information 
and to review, discuss and assist in resolving interregional 
coordination matters.'' North American Electric Reliability 
Corporation, History of NERC, at 1 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.
    \116\ North American Electric Reliability Corporation, History 
of NERC, at 2 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.
    \117\ North American Electric Reliability Corporation, History 
of NERC, at 4 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.
---------------------------------------------------------------------------

    In August 2003, North America experienced its worst blackout to 
date creating an outage in the Midwest, Northeast, and Ontario, 
Canada.\118\ This blackout was massive in scale impacting an area with 
an estimated 50 million people and 61,800 megawatts of electric 
load.\119\ The U.S. and Canada formed a joint task force to investigate 
the causes of the blackout and made recommendations to avoid similar 
outages in the future. One of the task force's major recommendations 
was that the U.S. Congress should pass legislation making electric 
reliability standards mandatory and enforceable.\120\
---------------------------------------------------------------------------

    \118\ North American Electric Reliability Corporation, History 
of NERC, at 3 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.
    \119\ U.S.-Canada Power System Outage Task Force, Final Report 
on the August 14, 2003 Blackout in the United States and Canada: 
Causes and Recommendations, at 1 (Apr. 2004), available at http://www.ferc.gov/industries/electric/indus-act/reliability/blackout/ch1-3.pdf. The outage impacted areas within Ohio, Michigan, 
Pennsylvania, New York, Vermont, Massachusetts, Connecticut, New 
Jersey, and the Canadian province of Ontario. Id.
    \120\ U.S.-Canada Power System Outage Task Force, Final Report 
on the August 14, 2003 Blackout in the United States and Canada: 
Causes and Recommendations, at 2 (Apr. 2004), available at http://www.ferc.gov/industries/electric/indus-act/reliability/blackout/ch1-3.pdf.
---------------------------------------------------------------------------

    Congress responded to this recommendation in EPAct 2005, adding a 
new section 215 to the Federal Power Act making reliability standards 
mandatory and enforceable and authorizing the creation of a new 
Electric Reliability Organization (ERO). Under this new system, FERC 
certifies an entity as the ERO. The ERO develops reliability standards, 
which are subject to FERC review and approval. Once FERC approves 
reliability standards the ERO may enforce those standards or FERC can 
do so independently.\121\ In 2006, the Federal Energy Regulatory 
Commission (FERC) certified NERC as the ERO.\122\ ``NERC develops and 
enforces Reliability Standards; monitors the Bulk-Power System; 
assesses adequacy annually via a 10-year forecast and winter and summer 
forecasts; audits owners, operators and users for preparedness; and 
educates and trains industry personnel.'' \123\
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    \121\ Mandatory Reliability Standards for the Bulk-Power System, 
Order No. 693, 118 FERC ] 61,218, at P 3 (2007) (citing 16 U.S.C. 
824o(e)(3)).
    \122\ Rules Concerning Certification of the Electric Reliability 
Organization; and Procedures for the Establishment, Approval, and 
Enforcement of Electric Reliability Standards, Order No. 672, 114 
FERC ] 61,104 (2006).
    \123\ North American Electric Reliability Corporation, 
Frequently Asked Questions, at 2 (Aug. 2013), available at http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf.
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    The U.S., Canada, and part of Mexico are divided up into eight 
reliability

[[Page 64694]]

regional entities.\124\ These regional entities include Florida 
Reliability Coordinating Council (FRCC), Midwest Reliability 
Organization (MRO), Northeast Power Coordinating Council (NPCC), 
Reliability First Corporation (RFC), SERC Reliability Corporation 
(SERC), Southwest Power Pool, RE (SPP), Texas Reliability Entity (TRE), 
and Western Electricity Coordinating Council (WECC).\125\ Regional 
entity members come from all segments of the electric industry.\126\ 
NERC delegates authority, with FERC approval, to these regional 
entities to enforce reliability standards, both national and regional 
reliability standards, and engage in other standards-related duties 
delegated to them by NERC.\127\ NERC ensures that there is a 
consistency of application of delegated functions with appropriate 
regional flexibility.\128\ NERC divides the country into assessment 
areas and annually analyzes the reliability, adequacy, and associated 
risks that may affect the upcoming summer, winter, and long-term, 10-
year period. Multiple other entities such as FERC, the Department of 
Energy, state public utility commissions, ISOs/RTOs,\129\ and other 
planning authorities also consider the reliability of the electric 
system. There are numerous remedies that can be utilized to solve a 
potential reliability problem, including long-term planning, 
transmission system upgrades, installation of new generating capacity, 
demand response, and other demand side actions.
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    \124\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 49-50 (2012), available at 
http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \125\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 50 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \126\ North American Electric Reliability Corporation, Key 
Players, available at http://www.nerc.com/AboutNERC/keyplayers/Pages/default.aspx (last visited Mar. 12, 2015). ``The members of 
the regional entities come from all segments of the electric 
industry: investor-owned utilities; federal power agencies; rural 
electric cooperatives; state, municipal and provincial utilities; 
independent power producers; power marketers; and end-use 
customers.'' Id.
    \127\ North American Electric Reliability Corporation, 
Frequently Asked Questions, at 5 (2013), available at http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf. For 
example, a regional entity may propose reliability standards, 
including regional variances or regional reliability standards 
required to maintain and enhance electric service reliability, 
adequacy, and security in the region. See, e.g., Amended and 
Restated Delegation Agreement Between North American Reliability 
Corporation and Midwest Reliability Organization, Bylaws of the 
Midwest Reliability Organization, Inc., Section 2.2 (2012), 
available at http://www.nerc.com/FilingsOrders/us/Regional%20Delegation%20Agreements%20DL/MRO_RDA_Effective_20130612.pdf.
    \128\ North American Electric Reliability Corporation, 
Frequently Asked Questions, at 5 (2013), available at http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf.
    \129\ ISOs/RTOs plan for system needs by ``effectively managing 
the load forecasting, transmission planning, and system and resource 
planning functions.'' For example, the New York Independent System 
Operator (NYISO) conducts reliability planning studies, which ``are 
used to assess current reliability needs based on user trends and 
historical energy use.'' NYISO, Planning Studies, available at 
http://www.nyiso.com/public/markets_operations/services/planning/planning_studies/index.jsp. See also PJM, Reliability Assessments, 
available at https://www.pjm.com/planning/rtep-development/reliability-assessments.aspx (stating that the PJM ``Regional 
Transmission Expansion Planning (RTEP) process includes the 
development of periodic reliability assessments to address specific 
system reliability issues in addition to the ongoing expansion 
planning process for the interconnection process of generation and 
merchant transmission.'').
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4. Modern Electric System Trends
    Today, the electricity sector is undergoing a period of intense 
change. Fossil fuels--such as coal, natural gas, and oil--have 
historically provided a large percentage of electricity in the U.S., 
along with nuclear power, with smaller amounts provided by other types 
of generation, including renewables such as wind, solar, and 
hydroelectric power. Coal provided the largest percentage of the fossil 
fuel generation.\130\ In recent years, the nation has seen a sizeable 
increase in renewable generation such as wind and solar, as well as a 
shift from coal to natural gas.\131\ In 2013, fossil fuels supplied 67 
percent of U.S. electricity,\132\ but the amount of renewable 
generation capacity continued to grow.\133\ From 2007 to 2014, use of 
lower- and zero-carbon energy sources such as wind and solar grew, 
while other major energy sources such as coal and petroleum generally 
experienced declines.\134\ Renewable electricity generation, including 
from large hydro-electric projects, grew from 8 percent to 13 percent 
over that time period.\135\ Between 2000 and 2013, approximately 90 
percent of new power generation capacity built in the U.S. came in the 
form of natural gas or RE facilities.\136\ In 2015, the U.S. Energy 
Information Administration (EIA) projected the need for 28.4 GW of 
additional base load or intermediate load generation capacity through 
2020.\137\ The vast majority of this new electric capacity (20.4 GW) is 
already under development (under construction or in advanced planning), 
with approximately 0.7 GW of new coal-fired capacity, 5.5 GW of new 
nuclear capacity, and 14.2 GW of new NGCC capacity already in 
development.
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    \130\ U.S. Energy Information Administration, ``Table 7.2b 
Electricity Net Generation: Electric Power Sector'' data from 
Monthly Energy Review May 2015, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015).
    \131\ U.S. Energy Information Administration, ``Table 7.2b 
Electricity Net Generation: Electric Power Sector'' data from 
Monthly Energy Review May 2015, release data April 25, 2014, 
available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015).
    \132\ U.S. Energy Information Administration, ``Table 7.2b 
Electricity Net Generation: Electric Power Sector'' data from 
Monthly Energy Review May 2015, release data April 25, 2014, 
available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015).
    \133\ 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 RE 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.
    \134\ U.S. Energy Information Administration, ``Table 7.2b 
Electricity Net Generation: Electric Power Sector'' data from 
Monthly Energy Review May 2015, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015).
    \135\ Bloomberg New Energy Finance and the Business Council for 
Sustainable Energy, 2015 Factbook: Sustainable Energy in America, at 
16 (2015), available at http://www.bcse.org/images/2015%20Sustainable%20Energy%20in%20America%20Factbook.pdf. Bloomberg 
gave projections for 2014 values, accounting for seasonality, based 
on latest monthly values from EIA (data available through October 
2014).
    \136\ Energy Information Administration, Electricity: Form EIA-
860 detailed data (Feb. 17, 2015), available at http://www.eia.gov/electricity/data/eia860/.
    \137\ EIA, Annual Energy Outlook for 2015 with Projections to 
2040, Final Release, available at http://www.eia.gov/forecasts/AEO/pdf/0383(2015).pdf. The AEO numbers include projects that are under 
development and model-projected nuclear, coal, and NGCC projects.
---------------------------------------------------------------------------

    While the change in the resource mix has accelerated in recent 
years, wind, solar, other renewables, and EEresources have been 
reliably participating in the electric sector for a number of years. 
This rapid development of non-fossil fuel resources is occurring as 
much of the existing power generation fleet in the U.S. is aging and in 
need of modernization and replacement. In 2025, the average age of the 
coal-fired generating fleet is projected to be 49 years old, and 20 
percent of those units would be more than 60 years old if they remain 
in operation at that time. In its 2013 Report Card for America's 
Infrastructure, the American Society for Civil Engineers noted that 
``America relies on an aging electrical grid and pipeline distribution 
systems, some of which originated in the 1880s.'' \138\ While there has 
been an

[[Page 64695]]

increased investment in electric transmission infrastructure since 
2005, the report also found that ``ongoing permitting issues, weather 
events, and limited maintenance have contributed to an increasing 
number of failures and power interruptions.'' \139\ However, innovative 
technologies have increasingly entered the electric energy space, 
helping to provide new answers to how to meet the electricity needs of 
the nation. These new technologies can enable the nation to answer not 
just questions as to how to reliably meet electricity demand, but also 
how to meet electricity demand reliably and cost-effectively with the 
lowest possible emissions and the greatest efficiency.
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    \138\ American Society for Civil Engineers, 2013 Report Card for 
America's Infrastructure (2013), available at http://www.infrastructurereportcard .org/energy/.
    \139\ American Society for Civil Engineers, 2013 Report Card for 
America's Infrastructure (2013), available at http://www.infrastructurereportcard .org/energy/.
---------------------------------------------------------------------------

    Natural gas has a long history of meeting electricity demand in the 
U.S., with a rapidly growing role as domestic supplies of natural gas 
have dramatically increased. Natural gas net generation increased by 
approximately 32 percent between 2005 and 2014.\140\ In 2014, natural 
gas accounted for approximately 27 percent of net generation.\141\ EIA 
projects that this demand growth will continue with its Annual Energy 
Outlook 2015 (AEO 2015) Reference case forecasting that natural gas 
will produce 31 percent of U.S. electric generation in 2040.\142\
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    \140\ U.S. Energy Information Administration (EIA), Electric 
Power Monthly: Table 1.1 Net Generation by Energy Source: Total (All 
Sectors), 2005-February 2015 (2015), available athttp://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_1_1 (last visited 
May 26, 2015).
    \141\ Id.
    \142\ U.S. Energy Information Administration (EIA), Annual 
Energy Outlook 2015 with Projections to 2040, at 24-25 (2015), 
available at http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf. 
According to the EIA, the reference case assumes, ``Real gross 
domestic product (GDP) grows at an average annual rate of 2.4% from 
2013 to 2040, under the assumption that current laws and regulations 
remain generally unchanged throughout the projection period. North 
Sea Brent crude oil prices rise to $141/barrel (bbl) (2013 dollars) 
in 2040.'' Id. at 1. The EIA provides complete projection tables for 
the reference case in Appendix A of its report.
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    Renewable sources of electric generation also have a history of 
meeting electricity demand in the U.S. and are expected to have an 
increasing role going forward. A series of energy crises provided the 
impetus for RE development in the early 1970s. The OPEC oil embargo in 
1973 and oil crisis of 1979 caused oil price spikes, more frequent 
energy shortages, and significantly affected the national and global 
economy. In 1978, partly in response to fuel security concerns, 
Congress passed the Public Utilities Regulatory Policies Act (PURPA) 
which required local electric utilities to buy power from qualifying 
facilities (QFs).\143\ QFs were either cogeneration facilities \144\ or 
small generation resources that use renewables such as wind, solar, 
biomass, geothermal, or hydroelectric power as their primary 
fuels.\145\ Through PURPA, Congress supported the development of more 
RE generation in the U.S. States have also taken a significant lead in 
requiring the development of renewable resources. In particular, a 
number of states have adopted renewable portfolio standards (RPS). As 
of 2013, 29 states and the District of Columbia have enforceable RPS or 
similar laws.\146\
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    \143\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 220-221 (2d ed. 2010).
    \144\ Cogeneration facilities utilize a single source of fuel to 
produce both electricity and another form of energy such as heat or 
steam. Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 220-221 (2d ed. 2010).
    \145\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 220-221 (2d ed. 2010).
    \146\ U.S. Energy Information Administration (EIA), Annual 
Energy Outlook 2014 with Projections to 2040, at LR-5 (2014), 
available at http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf 
(last visited May 26, 2015).
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    Use of RE continues to grow rapidly in the U.S. In 2013, 
electricity generated from renewable technologies, including 
conventional hydropower, represented 13 percent of total U.S. 
electricity, up from 9 percent in 2005.\147\ In 2013, U.S. non-hydro RE 
capacity for the total electric power industry exceeded 80,000 MW, 
reflecting a fivefold increase in just 15 years.\148\ In particular, 
there has been substantial growth in the wind and photovoltaic (PV) 
markets in the past decade. Since 2009, U.S. wind generation has 
tripled and solar generation has grown twenty-fold.\149\
---------------------------------------------------------------------------

    \147\ Energy Information Administration, Annual Energy Outlook 
2015 with Projections to 2040, at ES-6 (2014) and Energy Information 
Administration, Monthly Energy Review, May 2015, Table 7.2b, 
available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
    \148\ Non-hydro RE capacity for the total electric power 
industry was more than 16,000 megawatts (MW) in 1998. Energy 
Information Administration, 1990-2013 Existing Nameplate and Net 
Summer Capacity by Energy Source Producer Type and State (EIA-860), 
available at http://www.eia.gov/electricity/data/state/.
    \149\ Energy Information Administration, Monthly Energy Review, 
May 2015, Table 7.2b, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
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    The global market for RE is projected to grow to $460 billion per 
year by 2030.\150\ RE growth is further encouraged by the significant 
amount of existing natural resources that can support RE production in 
the U.S.\151\ In the Energy Information Administration's Annual Energy 
Outlook 2015, RE generation grows substantially from 2013 to 2040 in 
the reference case and all alternative cases.\152\ In the reference 
case, RE generation increases by more than 70 percent from 2013 to 2040 
and accounts for over one-third of new generation capacity.\153\
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    \150\ ``Global Renewable Energy Market Outlook.'' Bloomberg New 
Energy Finance (Nov. 16, 2011), available at http://bnef.com/WhitePapers/download/53.
    \151\ Lopez et al., NREL, ``U.S. Renewable Energy Technical 
Potentials: A GIS-Based Analysis,'' (July 2012).
    \152\ Energy Information Administration, Annual Energy Outlook 
2015 with Projections to 2040, at 25 (2015), available at http://
www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf.
    \153\ Energy Information Administration, Annual Energy Outlook 
2015 with Projections to 2040, at ES-6 (2015), available at http://
www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf (last visited May 27, 
2015).
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    Price pressures caused by oil embargoes in the 1970s also brought 
the issues of conservation and EE to the forefront of U.S. energy 
policy.\154\ This trend continued in the early 1990s. EE has been 
utilized to meet energy demand to varying levels since that time. As of 
April 2014, 25 states \155\ have ``enacted long-term (3+ years), 
binding energy savings targets, or energy efficiency resource standards 
(EERS).'' \156\ Funding for EE programs has grown rapidly in recent 
years, with budgets for electric efficiency programs totaling $5.9 
billion in 2012.\157\
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    \154\ Edison Electric Institute, Making a Business of Energy 
Efficiency: Sustainable Business Models for Utilities, at 1 (2007), 
available at http://www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation/Documents/Making_Business_Energy_Efficiency.pdf. 
Congress passed legislation in the 1970s that jumpstarted energy 
efficiency in the U.S. For example, President Ford signed the Energy 
Policy and Conservation Act (EPCA) of 1975--the first law on the 
issue. EPCA authorized the Federal Energy Administration (FEA) to 
``develop energy conservation contingency plans, established vehicle 
fuel economy standards, and authorized the creation of efficiency 
standards for major household appliances.'' Alliance to Save Energy, 
History of Energy Efficiency, at 6 (2013) (citing Anders, ``The 
Federal Energy Administration,'' 5; Energy Policy and Conservation 
Act, S. 622, 94th Cong. (1975-1976)), available at https://www.ase.org/sites/ase.org/files/resources/Media%20browser/ee_commission_history_report_2-1-13.pdf.
    \155\ American Council for an Energy-Efficient Economy, State 
Energy Efficiency Resource Standards (EERS) (2014), available at 
http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf. ACEEE did 
not include Indiana (EERS eliminated), Delaware (EERS pending), 
Florida (programs funded at levels far below what is necessary to 
meet targets), Utah, or Virginia (voluntary standards) in its 
calculation.
    \156\ American Council for an Energy-Efficient Economy, State 
Energy Efficiency Resource Standards (EERS) (2014), available at 
http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf.
    \157\ American Council for an Energy-Efficient Economy, The 2013 
State Energy Efficiency Scorecard, at 17 (Nov. 2013), available at 
http://aceee.org/sites/default/files/publications/researchreports/e13k.pdf.

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[[Page 64696]]

    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 reliable supply of power at a reasonable cost.

E. Clean Air Act Regulations for Power Plants

    In this section, we provide a general description of major CAA 
regulations for power plants. We refer to these in later sections of 
this preamble.
1. Title IV Acid Rain Program
    The EPA's Acid Rain Program, established in 1990 under Title IV of 
the CAA, addresses the presence of acidic compounds and their 
precursors (i.e., SO2 and NOX), in the atmosphere 
by targeting ``the principal sources'' of these pollutants through an 
SO2 cap-and-trade program for fossil-fuel fired power plants 
and through a technology based NOX emission limit for 
certain utility boilers. Altogether, Title IV was designed to achieve 
reductions of ten million tons of annual SO2 emissions, and, 
in combination with other provisions of the CAA, two million tons of 
annual NOX emissions.\158\
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    \158\ 42 U.S.C. 7651(b).
---------------------------------------------------------------------------

    The SO2 cap-and-trade program was implemented in two 
phases. The first phase, beginning in 1995, targeted one-hundred and 
ten named power plants, including specific generator units at each 
plant, requiring the plants to reduce their cumulative emissions to a 
specific level.\159\ Under certain conditions, the owner or operator of 
a named power plant could reassign an affected unit's reduction 
requirement to another unit and/or request an extension of two years 
for meeting the requirement.\160\ Congress also established an energy 
conservation and RE reserve from which up to 300,000 allowances could 
be allocated for qualified energy conservation measures or qualified 
RE.\161\
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    \159\ 42 U.S.C. 7651c (Table A).
    \160\ 42 U.S.C. 7651c(b) and (d).
    \161\ 42 U.S.C. 7651c(f) and (g).
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    The second phase, beginning in 2000, expanded coverage to more than 
2,000 generating units and set a national cap at 8.90 million 
tons.\162\ Generally, allowances were allocated at a rate of 1.2 lbs/
mmBtu multiplied by the unit's baseline and divided by 2000.\163\ 
However, bonus allowances could be awarded to certain units.
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    \162\ U.S. Dept. of Energy, Energy Information Administration, 
``The Effects of Title IV of the Clean Air Act Amendments of 1990 on 
Electric Utilities: An Update,'' p. vii. (March 1997).
    \163\ See 42 U.S.C. 7651d.
---------------------------------------------------------------------------

    Title IV also required the EPA to hold or sponsor annual auctions 
and sales of allowances for a small portion of the total allowances 
allocated each year. This ensured that some allowances would be 
directly available for new sources, including independent power 
production facilities.\164\
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    \164\ 42 U.S.C. 7651o.
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    The provisions of the EPA's Acid Rain Program are implemented 
through permits issued under the EPA's Title V Operating Permit 
Program.\165\ In accordance with Title IV, moreover, each Title V 
permit application must include a compliance plan for the affected 
source that details how that source expects to meet the requirements of 
Title IV.\166\
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    \165\ 42 U.S.C. 7651g.
    \166\ Such plans may simply state that the owner or operator 
expects to hold sufficient allowances or, in the case of alternative 
compliance methods, must provide a ``comprehensive description of 
the schedule and means by which the unit will rely on one or more 
alternative methods of compliance in the manner and time authorized 
under [Title IV].'' 42 U.S.C. 7651g(b).
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2. Transport Rulemakings
    CAA section 110(a)(2)(D)(i)(I), the ``Good Neighbor Provision,'' 
requires SIPs to prohibit emissions that ``contribute significantly to 
nonattainment . . . or interfere with maintenance'' of the NAAQS in any 
other state.\167\ If the EPA finds that a state has failed to submit an 
approvable SIP, the EPA must issue a federal implementation plan (FIP) 
to prohibit those emissions ``at any time'' within the next two 
years.\168\
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    \167\ 42 U.S.C. 7410(a)(2)(D)(i)(I).
    \168\ EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 
1600-01 (2014) (citing 42 U.S.C. 7410(c)).
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    In three major rulemakings--the NOX SIP Call,\169\ the 
Clean Air Interstate Rule (CAIR),\170\ and the Cross State Air 
Pollution Rule (CSAPR) \171\--the EPA has attempted to delineate the 
scope of the Good Neighbor Provision. These rulemakings have several 
features in common. Although the Good Neighbor Provision does not speak 
specifically about EGUs, in all three rulemakings, the EPA set state 
emission ``budgets'' for upwind states based in part on emissions 
reductions achievable by EGUs through application of cost-effective 
controls. Each rule also adopted a phased approach to reducing 
emissions with both interim and final goals.
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    \169\ 63 FR 57356 (Oct. 27, 1998).
    \170\ 70 FR 25162 (May 12, 2005).
    \171\ 76 FR 48208 (Aug. 8, 2011).
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    a. NOX SIP Call. In 1998, the EPA promulgated the 
NOX SIP Call, which required 23 upwind states to reduce 
emissions of NOX that would impact downwind areas with ozone 
problems. The EPA determined emission reduction requirements based on 
reductions achievable through ``highly cost-effective'' controls--i.e., 
controls that would cost on average no more than $2,000 per ton of 
emissions reduced.\172\ The EPA determined that a uniform emission rate 
on large EGUs coupled with a cap-and-trade program was one such set of 
highly cost-effective controls.\173\ Accordingly, the EPA established 
an interstate cap-and-trade program--the NOX Budget Trading 
Program--as a mechanism for states to reduce emissions from EGUs and 
other sources in a highly cost-effective manner. The D.C. Circuit 
upheld the NOX SIP Call in most significant respects, 
including its use of costs to apportion emission reduction 
responsibilities.\174\
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    \172\ 63 FR at 57377-78.
    \173\ 63 FR at 57377-78. In addition to EGUs, the NOX 
SIP Call also set budgets based on highly cost-effective emission 
reductions from certain other large sources. Id.
    \174\ Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000).
---------------------------------------------------------------------------

    b. Clean Air Interstate Rule (CAIR). In 2005, the EPA promulgated 
CAIR, which required 28 upwind states to reduce emissions of 
NOX and SO2 that would impact downwind areas with 
projected nonattainment and maintenance problems for ozone and 
PM2.5. The EPA determined emission reduction requirements 
based on ``controls that are known to be highly cost effective for 
EGUs.'' \175\ The EPA established cap-and-trade programs for sources of 
NOX and SO2 in states that chose to participate 
in the trading programs via their SIPs and for states ultimately 
subject to a FIP.\176\ As relevant here, the D.C. Circuit remanded CAIR 
in North Carolina v. EPA due to in part the structure of its interstate 
trading provisions and the way in which EPA applied the cost-effective 
standard, but kept the rule in place while the EPA developed an 
acceptable substitute.\177\
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    \175\ 70 FR at 25163.
    \176\ 70 FR at 25273-75; 71 FR 25328 (April 28, 2006).
    \177\ 531 F.3d 896, 917-22 (D.C. Cir. 2008), modified on 
rehearing 550 F.3d 1176, 1178 (D.C. Cir. 2008).
---------------------------------------------------------------------------

    c. Cross-state Air Pollution Rule (CSAPR). In 2011, the EPA 
promulgated CSAPR, which required 27 upwind states to reduce emissions 
of NOX and SO2 that would impact downwind areas 
with projected nonattainment and

[[Page 64697]]

maintenance problems for ozone and PM2.5. The EPA determined 
emission reduction requirements based in part on the reductions 
achievable at certain cost thresholds by EGUs in each state, with 
certain provisions developed to account for the need to ensure 
reliability of the electric generating system.\178\ In the same action 
establishing these emission reduction requirements, the EPA promulgated 
FIPs that subjected states to trading programs developed to achieve the 
necessary reductions within each state.\179\ The U.S. Supreme Court 
upheld the EPA's use of cost to set emission reduction requirements, as 
well as its authority to issue the FIPs.\180\
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    \178\ 76 FR at 48270. The EPA adopted this approach in part to 
comport with the D.C. Circuit's opinion in North Carolina v. EPA 
remanding CAIR. Id. at 48270-71.
    \179\ 76 FR at 48209-16.
    \180\ EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 
(2014).
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3. Clean Air Mercury Rule
    On March 15, 2005, the EPA issued a rule to control mercury (Hg) 
emissions from new and existing fossil fuel-fired power plants under 
CAA section 111(b) and (d). The rule, known as the Clean Air Mercury 
Rule (CAMR), established, in relevant part, a nationwide cap-and-trade 
program under CAA section 111(d), which was designed to complement the 
cap-and-trade program for SO2 and NOX emissions 
under the Clean Air Interstate Rule (CAIR), discussed above.\181\ 
Though CAMR was later vacated by the D.C. Circuit on account of the 
EPA's flawed CAA section 112 delisting rule, the court declined to 
reach the merits of the EPA's interpretation of CAA section 
111(d).\182\ Accordingly, CAMR continues to be an informative model for 
a cap-and-trade program under CAA section 111(d).
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    \181\ See 70 FR 28606 (May 18, 2005).
    \182\ New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008).
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    The cap-and-trade program in CAMR was designed to take effect in 
two phases: in 2010, the cap was set at 38 tons of mercury per year, 
and in 2018, the cap would be lowered to 15 tons per year. The Phase I 
cap was set at a level reflecting the co-benefits of CAIR as determined 
through economic and environmental modeling.\183\ For the more 
stringent Phase II cap, the EPA projected that sources would ``install 
SCR [selective catalytic reduction] to meet their SO2 and 
NOX requirements and take additional steps to address the 
remaining Hg reduction requirements under CAA section 111, including 
adding Hg-specific control technologies (model applies ACI [activated 
carbon injection]), additional scrubbers and SCR, dispatch changes, and 
coal switching.'' \184\ Based on this analysis, EPA determined that the 
BSER ``refers to the combination of the cap-and-trade mechanism and the 
technology needed to achieve the chosen cap level.'' \185\
---------------------------------------------------------------------------

    \183\ 70 FR 28606, at 28617. The EPA's projections under CAIR 
showed a significant number of affected sources would install 
scrubbers for SO2 and selective catalytic reduction for 
NOX on coal-fired power plants, which had the co-benefit 
of capturing mercury emissions. Id. at 28619.
    \184\ 70 FR 28606, at 28619.
    \185\ 70 FR 28606, at 28620.
---------------------------------------------------------------------------

    To accompany the nationwide emissions cap, the EPA also assigned a 
statewide emissions budget for mercury. Pursuant to CAA section 111(d), 
states would be required to submit plans to the EPA ``detailing the 
controls that will be implemented to meet its specified budget for 
reductions from coal-fired Utility Units.'' \186\ Of course, states 
were ``not required to adopt and implement'' the emission trading 
program, ``but they [were] required to be in compliance with their 
statewide Hg emission budget.'' \187\
---------------------------------------------------------------------------

    \186\ 70 FR 28606, at 28621.
    \187\ 70 FR 28606, at 28621. That said, states could ``require 
reductions beyond those required by the [s]tate budget.'' Id. at 
28621.
---------------------------------------------------------------------------

4. Mercury Air Toxics Rule
    On February 16, 2012, the EPA issued the 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, arsenic, chromium, and nickel; and acid 
gases, including hydrochloric acid and hydrofluoric acid. These toxic 
air pollutants, also known as hazardous air pollutants or air toxics, 
are known to cause, or suspected of causing, nervous system damage, 
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.
    New or reconstructed EGUs (i.e., sources that commence construction 
or reconstruction after May 3, 2011) subject to the MATS rule are 
required to comply by April 16, 2012 or upon startup, whichever is 
later.
    Existing sources subject to the MATS rule were required to begin 
meeting the rule's requirements on April 16, 2015. Controls that will 
achieve the MATS performance standards are being installed on many 
units. Certain units, especially those that operate infrequently, may 
be considered not worth investing in given today's electricity market, 
and are closing. 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.
    Following promulgation of the MATS rule, industry, states and 
environmental organizations challenged many aspects of the EPA's 
threshold determination that regulation of EGUs is ``appropriate and 
necessary'' and the final standards regulating hazardous air pollutants 
from EGUs. The U.S. Court of Appeals for the D.C. Circuit upheld all 
aspects of the MATS rule. White Stallion Energy Center v. EPA, 748 F.3d 
1222 (D.C. Cir. 2014). In Michigan v. EPA, case no. 14-46, the U.S. 
Supreme Court reversed the portion of the D.C. Circuit decision finding 
the EPA was not required to consider cost when determining whether 
regulation of EGUs was ``appropriate'' pursuant to section 112(n)(1). 
The Supreme Court considered only the narrow question of whether the 
EPA erred in not considering cost when making this threshold 
determination. The Court's decision did not disturb any of the other 
holdings of the D.C. Circuit. The Court remanded the case to the D.C. 
Circuit for further proceedings, and the MATS rule remains in place at 
this time.
5. Regional Haze Rule
    Under CAA section 169A, Congress ``declare[d] as a national goal 
the prevention of any future, and the remedying of any existing, 
impairment of visibility'' in national parks and wilderness areas that 
results from anthropogenic emissions.\188\ To achieve this goal, 
Congress directed the EPA to promulgate regulations directing states to 
submit SIPs that ``contain such emission limits, schedules of 
compliance and other measures as may be necessary to make reasonable 
progress toward meeting the national goal. . . .'' \189\ One such 
measure that Congress deemed necessary to make reasonable progress was 
a requirement that certain older stationary sources that cause or 
contribute to visibility impairment ``procure, install, and operate, as 
expeditiously as practicable

[[Page 64698]]

. . . the best available retrofit technology,'' more commonly referred 
to as BART.\190\ When determining BART for large fossil-fuel fired 
utility power plants, Congress required states to adhere to guidelines 
to be promulgated by the EPA.\191\ As with other SIP-based programs, 
the EPA is required to issue a FIP within two years if a state fails to 
submit a regional haze SIP or if the EPA disapproves such SIP in whole 
or in part.\192\
---------------------------------------------------------------------------

    \188\ 42 U.S.C. 7491(a)(1).
    \189\ 42 U.S.C. 7491(b)(2).
    \190\ 42 U.S.C. 7491(b)(2)(A).
    \191\ 42 U.S.C. 7491(b)(2).
    \192\ 42 U.S.C. 7410(c); 7491(b)(2)(A).
---------------------------------------------------------------------------

    In 1999, the EPA promulgated the Regional Haze Rule to satisfy 
Congress' mandate that EPA promulgate regulations directing states to 
address visibility impairment.\193\ Among other things, the Regional 
Haze Rule allows states to satisfy the Act's BART requirement either by 
adopting source-specific emission limitations or by adopting 
alternatives, such as emissions-trading programs, that achieve greater 
reasonable progress than would source-specific BART.\194\ The Ninth 
Circuit and D.C. Circuit have both upheld the EPA's interpretation that 
CAA section 169A(b)(2) allows for BART alternatives in lieu of source-
specific BART.\195\ In 2005, the EPA promulgated BART Guidelines to 
assist states in determining which sources are subject to BART and what 
emission limitations to impose at those sources.\196\
---------------------------------------------------------------------------

    \193\ 64 FR 35714 (July 1, 1999) (codified at 40 CFR 51.308-
309).
    \194\ 40 CFR 51.308(e)(1) & (2).
    \195\ See Utility Air Regulatory Grp. v. EPA, 471 F.3d 1333 
(D.C. Cir. 2006); Ctr. for Econ. Dev. v. EPA, 398 F.3d 653 (D.C. 
Cir. 2005); Cent. Ariz. Water Dist. v. EPA, 990 F.2d 1531 (9th Cir. 
1993).
    \196\ 70 FR 39104 (July 6, 2005) (codified at 40 CFR pt. 51, 
app. Y).
---------------------------------------------------------------------------

    The Regional Haze Rule set a goal of achieving natural visibility 
conditions by 2064 and requires states to revise their regional haze 
SIPs every ten years.\197\ The first planning period, which ends in 
2018, focused heavily on the BART requirement. States (or the EPA in 
the case of FIPs) made numerous source-specific BART determinations, 
and developed several BART alternatives, for utility power plants. For 
the next planning period, states will need to determine whether 
additional controls are necessary at these plants (and others that were 
not subject to BART) in order to make reasonable progress towards the 
national visibility goal.\198\
---------------------------------------------------------------------------

    \197\ See 40 CFR 51.308(d)(1)(i)(B), (f).
    \198\ See 42 U.S.C. 7491(b)(2); 40 CFR 51.308(d)(3).
---------------------------------------------------------------------------

F. Congressional Awareness of Climate Change in the Context of the 
Clean Air Act Amendments \199\
---------------------------------------------------------------------------

    \199\ The following discussion is not meant to be exhaustive. 
There are many other instances outside the context of the CAA, 
before and after 1970, when Congress discussed or was presented with 
evidence on climate change.
---------------------------------------------------------------------------

    During its deliberations on the 1970 Clean Air Act Amendments, 
Congress learned that ongoing pollution, including from manmade carbon 
dioxide, could ``threaten irreversible atmospheric and climatic 
changes.'' \200\ At that time, Congress heard the views of scientists 
that carbon dioxide emissions tended to increase global temperatures, 
but that there was uncertainty as to the extent to which those 
increases would be offset by the decreases in temperatures brought 
about by emissions of particulates. President Nixon's Council on 
Environmental Quality (CEQ) reported that ``the addition of 
particulates and carbon dioxide in the atmosphere could have dramatic 
and long-term effects on world climate.'' \201\ The CEQ's First Annual 
Report, which was transmitted to Congress, devoted a chapter to ``Man's 
Inadvertent Modification of Weather and Climate.'' \202\ Moreover, 
Charles Johnson, Jr., Administrator of the Consumer Protection and 
Environmental Health Service, testified before the House Subcommittee 
on Public Health that ``the carbon dioxide balance might result in the 
heating up of the atmosphere whereas the reduction of the radiant 
energy through particulate matter released to the atmosphere might 
cause reduction in radiation that reaches the earth.'' \203\ 
Administrator Johnson explained that the Nixon Administration was 
``concerned . . . that neither of these things happen'' and that they 
were ``watching carefully the kind of prognosis, the kind of 
calculations that the scientists make to look at the continuous balance 
between heat and cooling of the total earth's atmosphere.'' \204\ He 
concluded that ``[w]hat we are trying to do, however, in terms of our 
air pollution effort should have a very salutary effect on either of 
these.'' \205\
---------------------------------------------------------------------------

    \200\ Sen. Scott, S. Debate on S. 4358 (Sept. 21, 1970), 1970 
CAA Legis. Hist. at 349.
    \201\ Council on Environmental Quality, ``The First Annual 
Report of the Council on Environmental Quality,'' p. 110 (Aug. 1970) 
(recognizing also that ``[man] can increase the carbon dioxide 
content of the atmosphere by burning fossil fuels'' and postulating 
that an increase in the earth's average temperature by about 2[deg] 
to 3[deg] F ``could in a period of decades, lead to the start of 
substantial melting of ice caps and flooding of coastal regions.'').
    \202\ Council on Environmental Quality, ``The First Annual 
Report of the Council on Environmental Quality,'' p. 93-104 (Aug. 
1970)
    \203\ Testimony of Charles Johnson, Jr., Administrator of the 
Consumer Protection and Environmental Health Service (Administration 
Testimony), Hearing of the House Subcommittee on Public Health and 
Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381.
    \204\ Testimony of Charles Johnson, Jr., Administrator of the 
Consumer Protection and Environmental Health Service (Administration 
Testimony), Hearing of the House Subcommittee on Public Health and 
Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381.
    \205\ Testimony of Charles Johnson, Jr., Administrator of the 
Consumer Protection and Environmental Health Service (Administration 
Testimony), Hearing of the House Subcommittee on Public Health and 
Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381.
---------------------------------------------------------------------------

    Scientific reports on climatic change continued to gain traction in 
Congress through the mid-1970s, including while Congress was 
considering the 1977 CAA Amendments. However, uncertainty continued as 
to whether the increased warming brought about by carbon dioxide 
emissions would be offset by cooling brought about by particulate 
emissions.\206\ Congress ordered, as part of the 1977 CAA Amendments, 
the National Oceanic and Atmospheric Administration to research and 
monitor the stratosphere ``for the purpose of early detection of 
changes in the stratosphere and climatic effects of such changes.'' 
\207\
---------------------------------------------------------------------------

    \206\ For instance, while scientists, such as Stephen Schneider 
of the National Center for Atmospheric Research, testified that 
``manmade pollutants will affect the climate,'' they believed that 
we would ``see a general cooling of the Earth's atmosphere.'' Rep. 
Scheuer, H. Debates on H.R. 10498 (Sept. 15, 1976), 1977 CAA Legis. 
Hist. at 6477. Additionally, the Department of Transportation's 
climatic impact assessment program and the Climatic Impact Committee 
of the National Research Council, National Academies of Science and 
Engineering both reported that ``warming or cooling'' could occur. 
Id. at 6476. See also Sen. Bumpers, S. Debates on S. 3219 (August 3, 
1976), 1977 CAA Legis. Hist. at 5368 (inserting ``Summary of 
Statements Received [in the Subcommittee on the Environment and the 
Atmosphere] from Professional Societies for the Hearings on Effects 
of Chronic Pollution'' into the record, which noted that ``there is 
near unamity [sic] that carbon dioxide concentrations in the 
atmosphere are increasing rapidly.'').
    \207\ ``Clean Air Act Amendments of 1977,'' Sec.  125, 91 Stat. 
at 728.
---------------------------------------------------------------------------

    Between the 1977 and 1990 Clean Air Act Amendments, scientific 
uncertainty yielded to the predominant view that global warming ``was 
likely to dominate on time scales that would be significant to human 
societies.'' \208\ In fact, as part of the 1990 Clean Air Act 
Amendments, Congress specifically required the EPA to collect data on 
carbon dioxide emissions--the most significant of the GHGs--from all 
sources subject to the

[[Page 64699]]

newly enacted operating permit program under Title V.\209\ Although 
Congress did not require the EPA to take immediate action to address 
climate change, Congress did identify certain tools that were 
particularly helpful in addressing climate change in the utility power 
sector. The Senate report discussing the acid rain provisions of Title 
IV noted that some of the measures that would reduce coal-fired power 
plant emissions of the precursors to acid rain would also reduce those 
facilities' emissions of CO2. The report stated:
---------------------------------------------------------------------------

    \208\ Peterson, Thomas C., William M. Connolley, and John Fleck, 
``The Myth of the 1970s Global Cooling Scientific Consensus,'' 
Bulletin of the American Meteorological Society, p. 1326 (September 
2008), available at http://journals.ametsoc.org/doi/pdf/10.1175/2008BAMS2370.1.
    \209\ ``Clean Air Act Amendments of 1990,'' Sec.  820, 104 Stat. 
at 2699.

    Energy efficiency is a crucial tool for controlling the 
emissions of carbon dioxide, the gas chiefly responsible for the 
intensification of the atmospheric `greenhouse effect.' In the last 
several years, the Committee has received extensive scientific 
testimony that increases in the human-caused emissions of carbon 
dioxide and other greenhouse gases will lead to catastrophic shocks 
in the global climate system. Accordingly, new title IV shapes an 
acid rain reduction policy that encourages energy efficiency and 
other policies aimed at controlling greenhouse gases.\210\
---------------------------------------------------------------------------

    \210\ Sen. Chafee, S. Debate on S. 1630 (Jan. 24, 1990), 1990 
CAA Legis. Hist. at 8662.

Similarly, Title IV provisions to encourage RE were justified because 
``renewables not only significantly curtail sulfur dioxide emissions, 
but they emit little or no nitrogen oxides and carbon dioxide''.\211\
---------------------------------------------------------------------------

    \211\ Additional Views of Rep. Markey and Rep. Moorhead, H.R. 
Rep. No. 101-490, at 674 (May 17, 1990).
---------------------------------------------------------------------------

G. International Agreements and Actions

    In this final rule, the U.S. is taking action to limit GHGs from 
one of its largest emission sources. Climate change is a global 
problem, and the U.S. is not alone in taking action to address it. The 
UNFCCC \212\ is the international treaty under which countries (called 
``Parties'') cooperatively consider what can be done to limit 
anthropogenic climate change \213\ and adapt to climate change impacts. 
Currently, there are 195 Parties to the UNFCCC, including the U.S. The 
Conference of the Parties (COP) meets annually and is currently 
considering commitments countries can make to limit emissions after 
2020. The 2015 COP will be in Paris and is expected to represent an 
historic step for climate change mitigation. The Parties to the UNFCC 
will meet to establish a climate agreement that applies to all 
countries and focuses on reducing GHG emissions. Such an outcome would 
send a beneficial signal to the markets and civil society about global 
action to address climate change.
---------------------------------------------------------------------------

    \212\ http://unfccc.int/2860.php.
    \213\ Article 2, Objective, The ultimate objective of this 
Convention and any related legal instruments that the Conference of 
the Parties may adopt is to achieve, in accordance with the relevant 
provisions of the Convention, stabilization of greenhouse gas 
concentrations in the atmosphere at a level that would prevent 
dangerous anthropogenic interference with the climate system. Such a 
level should be achieved within a time frame sufficient to allow 
ecosystems to adapt naturally to climate change, to ensure that food 
production is not threatened and to enable economic development to 
proceed in a sustainable manner. http://unfccc.int/files/essential_background/convention/background/application/pdf/convention_text_with_annexes_english_for_posting.pdf
---------------------------------------------------------------------------

    Many countries have announced their intended post-2020 commitments 
already, and other countries are expected to do so before December. In 
April 2015, the U.S. announced its commitment to reduce GHG emissions 
26-28 percent below 2005 levels by 2025.\214\
---------------------------------------------------------------------------

    \214\ United States Cover Note to Intended Nationally Determined 
Contribution (INDC). Available online at: http://www4.unfccc.int/submissions/INDC/Published%20Documents/United%20States%20of%20America/1/U.S.%20Cover%20Note%20INDC%20and%20Accompanying%20Information.pdf.
---------------------------------------------------------------------------

    As Parties to both the UNFCCC and the Kyoto Protocol,\215\ the 
European Union (EU) and member countries have taken aggressive action 
to reduce GHG emissions.\216\ EU initiatives to reduce GHG emissions 
include the EU Emissions Trading System, legislation to increase the 
adoption of RE sources, strengthened EE targets, vehicle emission 
standards, and support for the development of CCS technology for use by 
the power sector and other industrial sources. In 2009, the EU 
announced its ``20-20-20 targets,'' including a 20 percent reduction in 
GHG emissions from 1990 levels by 2020, an increase of 20 percent in 
the share of energy consumption produced by renewable resources, and a 
20 percent improvement in EE. In March 2015, the EU announced its 
commitment to reduce domestic GHG emissions by at least 40% from 1990 
levels by 2030.
---------------------------------------------------------------------------

    \215\ http://unfccc.int/kyoto_protocol/items/2830.php.
    \216\ http://ec.europa.eu/clima/policies/brief/eu/index_en.htm.
---------------------------------------------------------------------------

    Recently, China has also agreed to take action to address climate 
change. In November 2014, in a joint announcement by President Obama 
and China's President Xi, China pledged to curtail GHG emissions, with 
emissions peaking in 2030 and then declining thereafter, and to 
increase the share of energy from non-carbon sources (solar, wind, 
hydropower, nuclear) to 20 percent by 2030.
    Mexico is committed to reduce unconditionally 25 percent of its 
emissions of GHGs and short-lived climate pollutants (below business as 
usual) for the year 2030. This commitment implies a 22 percent 
reduction of GHG emissions and a 51 percent reduction of black carbon 
emissions.
    Brazil has reduced its net CO2 emissions more than any 
other country through a historic effort to slow forest loss. The 
deforestation rate in Brazil in 2014 was roughly 75 percent below the 
average for 1996 to 2005.\217\
---------------------------------------------------------------------------

    \217\ http://www.nature.com/news/stopping-deforestation-battle-for-the-amazon-1.17223.
---------------------------------------------------------------------------

    Together, countries that have already announced their intended 
post-2020 commitments, including the U.S., China, European Union, 
Mexico, Russian Federation and Brazil, make up a large majority of 
global emissions.
    President Obama's Climate Action Plan contains a number of policies 
and programs that are intended to cut carbon pollution that causes 
climate change and affects public health. The Clean Power Plan is a key 
component of the plan, addressing the nation's largest source of 
emissions in a comprehensive manner. Collectively, these policies will 
help spark business innovation, result in cleaner forms of energy, 
create jobs, and cut dependence on foreign oil. They also demonstrate 
to the rest of the world that the U.S. is contributing its share of the 
global effort that is needed to address climate change.\218\ This 
demonstration encourages other major economies to take on similar 
contributions, which is critical given the global impact of GHG 
emissions. The State Department Special Envoy for Climate Change Todd 
Stern, the lead U.S. climate change negotiator, noted the connection 
between domestic and international action to address climate change in 
his speech at Yale University on October 14, 2014:
---------------------------------------------------------------------------

    \218\ President Obama stated, in announcing the Climate Action 
Plan:
    ``The actions I've announced today should send a strong signal 
to the world that America intends to take bold action to reduce 
carbon pollution. We will continue to lead by the power of our 
example, because that's what the United States of America has always 
done.'' President Obama, Climate Action Plan speech, Georgetown 
University, 2013. Available at https://www.whitehouse.gov/the-press-office/2013/06/25/remarks-president-climate-change.

    This mobilization of American effort matters. Enormously. It 
matters because the United States is the biggest economy and largest 
historic emitter of greenhouse gases. Because, here, as in so many 
areas, we feel a responsibility to lead. And because here, as in so 
many areas, we find that American commitment is indispensable to 
effective international action.
    And make no mistake--other countries see what we are doing and 
are taking note. As I travel the world and meet with my

[[Page 64700]]

counterparts, the palpable engagement of President Obama and his 
team has put us in a stronger, more credible position than ever 
before.

    This final rule demonstrates to other countries that the U.S. is 
taking action to limit GHG emissions from its largest emission sources, 
in line with our international commitments. The impact of GHGs is 
global, and U.S. action to reduce GHG emissions complements and 
encourages ongoing programs and efforts in other countries.

H. Legislative and Regulatory Background for CAA Section 111

    In the final days of December 1970, Congress enacted sweeping 
changes to the Air Quality Act of 1967 to confront an ``environmental 
crisis.'' \219\ The Air Quality Act--which expanded federal air 
pollution control efforts after the enactment of the Clean Air Act of 
1963--prioritized the adoption of ambient air standards but failed to 
target stationary sources of air pollution. As a result, ``[c]ities up 
and down the east coast were living under clouds of smoke and daily air 
pollution alerts.'' \220\ In fact, ``[o]ver 200 million tons of 
contaminants . . . spilled into the air'' each year.\221\ The 1970 CAA 
Amendments were designed to face this crisis ``with urgency and in 
candor.'' \222\
---------------------------------------------------------------------------

    \219\ Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 
CAA Legis. Hist. at 224.
    \220\ Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-
1783 (Dec. 18, 1970), 1970 CAA Legis. Hist.pa at 123.
    \221\ Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 
CAA Legis. Hist. at 224. These pollutants fell into five main 
classes of pollutants: Carbon monoxide, particulates, sulfur oxides, 
hydrocarbons, and nitrogen oxides. See Sen. Boggs, id. at 244.
    \222\ Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-
1783 (Dec. 18, 1970), 1970 CAA Legis. Hist. at 123.
---------------------------------------------------------------------------

    For the most part, Congress gave EPA and the states flexible tools 
to implement the CAA. This is best exhibited by the newly enacted 
programs regulating stationary sources. For these sources, Congress 
crafted a three-legged regime upon which the regulation of stationary 
sources was intended to sit.
    The first prong--CAA sections 107-110--addressed what are commonly 
referred to as criteria pollutants, ``the presence of which in the 
ambient air results from numerous or diverse mobile or stationary 
sources'' and are determined to have ``an adverse effect on public 
health or welfare''.\223\ Under these provisions, states would have the 
primary responsibility for assuring air quality within their entire 
geographic area but would submit plans to the Administrator for 
``implementation, maintenance, and enforcement'' of national ambient 
air quality standards. These plans would include ``emission 
limitations, schedules, and timetables for compliance . . . and such 
other measures as may be necessary to insure attainment and 
maintenance'' of the national ambient air quality standards.\224\
---------------------------------------------------------------------------

    \223\ ``Clean Air Act Amendments of 1970,'' Pub. L. 91-604, 
Sec.  4, 84 Stat. 1676, 1678 (Dec. 31, 1970). The ``adverse effect'' 
criterion was later amended to refer to pollutants ``which may 
reasonably be anticipated to endanger public health or welfare''. 
See 42 U.S.C. 7408(a)(1)(A). Similar language is also used under the 
current CAA section 111. See 42 U.S.C. 7411(b)(1)(A).
    \224\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1680.
---------------------------------------------------------------------------

    The second prong--CAA section 111--addressed pollutants on a source 
category-wide basis. Under CAA section 111(b), the EPA lists source 
categories which ``contribute significantly to air pollution which 
causes or contributes to the endangerment of public health or 
welfare,'' And then establishes ``standards of performance'' for the 
new sources in the listed category.\225\ For existing sources in a 
listed source category, CAA section 111(d) set out procedures for the 
establishment of federally enforceable ``emission standards'' of any 
pollutant not otherwise controlled under the CAA's SIP provisions or 
CAA section 112.
---------------------------------------------------------------------------

    \225\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1684.
---------------------------------------------------------------------------

    Lastly, the third prong--CAA section 112--addressed hazardous air 
pollutants through the establishment of national ``emission standards'' 
at a level which ``provides an ample margin of safety to protect the 
public health''.\226\ All new or modified sources of any hazardous air 
pollutant would be required to meet these emission standards. Existing 
sources were required to meet the same standards or would be shut down 
unless they obtained a temporary EPA waiver or Presidential 
exemption.\227\
---------------------------------------------------------------------------

    \226\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1685.
    \227\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1685.
---------------------------------------------------------------------------

    At its inception, CAA section 111 was intended to bear a 
significant weight under this three-legged regime. Indeed, by 1977, the 
EPA had promulgated six times as many performance standards under CAA 
section 111 than emission standards under CAA section 112.\228\ That 
said, states, including Texas and New Jersey, levied ``substantial 
criticisms'' against the EPA for not moving rapidly enough.\229\ 
Accordingly, the 1977 CAA Amendments were designed to ``provide a 
greater role for the [s]tates in standards setting under the [CAA],'' 
``protect [s]tates from `environmental blackmail' as they attempt to 
regulate mobile and competitive industries,'' and lastly ``provide a 
check on the Administrator's inaction or failure to control emissions 
adequately.'' \230\
---------------------------------------------------------------------------

    \228\ H.R. Rep. No. 95-294, at 194 (May 12, 1977).
    \229\ H.R. Rep. No. 95-294, at 194 (May 12, 1977).
    \230\ H.R. Rep. No. 95-294, at 195 (May 12, 1977).
---------------------------------------------------------------------------

    At bottom, CAA section 111 rests on the definition of a standard of 
performance under CAA section 111(a)(1), which reads nearly the same 
now as it did when it was first adopted in the 1970 CAA Amendments. In 
1970, Congress defined standard of performance--a term which had not 
previously appeared in the CAA--as

a standard for emissions of air pollutants which reflects the degree 
of emission limitation achievable through the application of the 
best system of emission reduction which (taking into account the 
cost of achieving such reduction) the Administrator determines has 
been adequately demonstrated.\231\
---------------------------------------------------------------------------

    \231\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1683.

    Despite significant changes to this definition in 1977, Congress 
reversed course in 1990 and largely reinstated the original 
definition.\232\ As presently defined, the term applies to the 
regulation of new and existing sources under CAA sections 111(b) and 
(d).\233\
---------------------------------------------------------------------------

    \232\ ``Clean Air Act Amendments of 1990,'' Pub. L. 101-549, 
Sec.  403, 104 Stat. 2399, 2631 (Nov. 15, 1990) (retaining only the 
obligation to account for ``any nonair quality health and 
environmental impact and energy requirements'' that was added in 
1977).
    \233\ As CAA section 111(d) was originally adopted, state plans 
would have established ``emission standards'' instead of ``standards 
of performance.'' This distinction was later abandoned in 1977 and 
the same term is used in both CAA sections 111(b) and (d).
---------------------------------------------------------------------------

    The level of control reflected in the definition is generally 
referred to as the ``best system of emission reduction,'' or the BSER. 
The BSER, however, is not further defined, and only appeared after 
conference between the House and Senate in late 1970, and was neither 
discussed in the conference report nor openly debated in either 
chamber. Nevertheless, the originating bills from both houses shed 
light on its construction.
    The BSER grew out of proposed language in two bills, which, for the 
first time, targeted air pollution from stationary sources. The House 
bill sought to establish national emission standards to ``prevent and 
control . . . emissions [of non-hazardous pollutants] to the fullest 
extent compatible with the available technology and economic 
feasibility.'' \234\ The House also

[[Page 64701]]

proposed to prohibit the construction or operation of new sources of 
``extremely hazardous'' pollutants.\235\ The Senate bill, on the other 
hand, authorized ``Federal standards of performance,'' which would 
``reflect the greatest degree of emission control which the Secretary 
[later, the Administrator] determines to be achievable through 
application of the latest available control technology, processes, 
operating methods, or other alternatives.'' \236\ The Senate also would 
have authorized ``national emission standards'' for hazardous air 
pollution and other ``selected air pollution agents.'' \237\
---------------------------------------------------------------------------

    \234\ H.R. 17255, 91st Cong. Sec.  5 (1970).
    \235\ H.R. 17255, 91st Cong. Sec.  5 (1970).
    \236\ S. 4358, 91st Cong. Sec.  6 (1970) (emphasis added). The 
breadth of the Senate bill is further emphasized in the conference 
report, which explains that a standard of performance ``refers to 
the degree of emission control which can be achieved through process 
changes, operation changes, direct emission control, or other 
methods'' and also includes ``other means of preventing or 
controlling air pollution.'' S. Rep. No. 91-1196, at 15-16 (Sept. 
17, 1970).
    \237\ S. 4358, 91st Cong. Sec.  6 (1970).
---------------------------------------------------------------------------

    After conference, CAA section 111 emerged as one of the CAA's three 
programs for regulating stationary sources. In defining the newly 
formed ``standards of performance,'' Congress appeared to merge the 
various ``means of preventing and controlling air pollution'' under the 
Senate bill with the consideration of costs that was central to the 
House bill into the BSER. At the time, however, this definition only 
applied to new sources under CAA section 111(b).
    To regulate existing sources, Congress collapsed section 114 of the 
Senate bill into CAA section 111(d).\238\ Section 114 of the Senate 
bill established emission standards for ``selected air pollution 
agents,'' and was intended to bridge the gap between criteria 
pollutants and hazardous air pollutants. As proposed, the Senate 
identified fourteen substances for regulation under section 114 and 
only four substances for regulation under Senate bill 4358, section 
115, the predecessor of CAA section 112.\239\
---------------------------------------------------------------------------

    \238\ The House bill did not provide for the direct regulation 
of existing sources.
    \239\ See S. Rep. No. 91-1196, at 18 and 20 (Sept. 17, 1970).
---------------------------------------------------------------------------

    As adopted, CAA section 111(d) requires states to submit plans to 
the Administrator establishing ``emission standards'' for certain 
existing sources of air pollutants that were not otherwise regulated as 
criteria pollutants or hazardous air pollutants. This ensured that 
there would be ``no gaps in control activities pertaining to stationary 
source emissions that pose any significant danger to public health or 
welfare.'' \240\
---------------------------------------------------------------------------

    \240\ S. Rep. No. 91-1196, at 20 (Sept. 17, 1970) (discussing 
the relationship between sections 114 (addressing emission standards 
for ``selected air pollution agents'') and 115 (addressing hazardous 
air pollutants) of the Senate bill).
---------------------------------------------------------------------------

    The term ``emission standards,'' however, was not expressly defined 
in the 1970 CAA Amendments (save for purposes of citizen suit 
enforcement) even though the term was also used under the CAA's SIP 
provisions and CAA section 112.\241\ That said, under the newly enacted 
``ambient air quality and emission standards'' sections, Congress 
directed the EPA to provide states with information ``on air pollution 
control techniques,'' including data on ``available technology and 
alternative methods of prevention and control of air pollution'' and on 
``alternative fuels, processes, and operating methods which will result 
in elimination or significant reduction of emissions.'' \242\ 
Similarly, the Administrator would ``issue information on pollution 
control techniques for air pollutants'' in conjunction with 
establishing emission standards under CAA section 112. However, 
analogous text is absent from CAA section 111(d).
---------------------------------------------------------------------------

    \241\ See ``Clean Air Act Amendments of 1970,'' Sec.  12, 84 
Stat. at 1706.
    \242\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1679.
---------------------------------------------------------------------------

    After the enactment of the 1970 CAA Amendments, the EPA proposed 
standards of performance for an ``initial list of five stationary 
source categories which contribute significantly to air pollution'' in 
August 1971.\243\ The first category listed was for fossil-fuel fired 
steam generators, for which EPA proposed and promulgated standards for 
particulate matter, SO2, and NOX.\244\
---------------------------------------------------------------------------

    \243\ ``Standards of Performance for New Stationary Sources: 
Proposed Standards for Five Categories,'' 36 FR 15704 (Aug. 17, 
1971). See ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. 
at 1684 (requiring the Administrator to publish a list of categories 
of stationary sources within 90 days of the enactment of the 1970 
CAA Amendments).
    \244\ 36 FR at 15704-706; and ``Standards of Performance for New 
Stationary Sources,'' 36 FR 24876, 24879 (Dec. 23, 1971).
---------------------------------------------------------------------------

    Several years later, the EPA proposed its implementing regulations 
for CAA section 111(d).\245\ These regulations were finalized in 
November 1975, and provided for the publication of emission 
guidelines.\246\ The first emission guidelines were proposed in May 
1976 and finalized in March 1977.\247\
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    \245\ See ``State Plans for the Control of Existing 
Facilities,'' 39 FR 36102 (Oct. 7, 1974).
    \246\ See ``State Plans for the Control of Certain Pollutants 
from Existing Facilities,'' 40 FR 53340 (Nov. 17, 1975).
    \247\ See ``Phosphate Fertilizer Plants; Draft Guideline 
Document; Availability,'' 41 FR 19585 (May 12, 1976); and 
``Phosphate Fertilizer Plants; Final Guideline Document 
Availability,'' 42 FR 12022 (Mar. 1, 1977).
---------------------------------------------------------------------------

    Despite these first steps taken under CAA sections 111(b) and (d), 
Congress revisited the CAA in 1977 to address growing concerns with the 
nation's response to the 1973 oil embargo (noted above), to respond to 
new environmental problems such as stratospheric ozone depletion, and 
to resolve other issues associated with implementing the 1970 CAA 
Amendments.\248\ Most notably, an increase in coal use as a result of 
the oil crisis meant that ``vigorous and effective control'' of air 
emissions was ``even more urgent.'' \249\ Thus, to curb the projected 
surge in air emissions, Congress enacted several new provisions to the 
CAA. These new provisions include the prevention of significant 
deterioration (PSD) program, visibility protections, and requirements 
for nonattainment areas.\250\
---------------------------------------------------------------------------

    \248\ For example, Congress recognized that many air pollutants 
had not been regulated despite ``mounting evidence'' that these 
pollutants ``are associated with serious health hazards''. H.R. Rep. 
No. 94-1175, 22 (May, 15, 1976). Because EPA ``failed to promulgate 
regulations to institute adequate control measures,'' Congress 
ordered EPA to regulate four specific pollutants that had ``been 
found to be cancer-causing or cancer-promoting''. Id. at 23. This 
directive, reflected in CAA section 122, specifically added 
radioactive pollutants, cadmium, arsenic, and polycyclic organic 
matter ``under the various provisions of the Clean Air Act and 
allows their regulation as criteria pollutants under ambient air 
quality standards, as hazardous air pollutants, or under new source 
performance standards, as appropriate.'' H.R. Conf. Rep. No. 95-564, 
142 (Aug. 3, 1977), 1977 CAA Legis. Hist. at 522. At the same time, 
Congress made sure that these commands would have no effect on the 
Administrator's discretion to address ``any substance (whether or 
not enumerated [under CAA section 122(a))'' under CAA sections 108, 
112, or 111. 42 U.S.C. 7422(b).
    \249\ See Statement of EPA Administrator Costle, S. Hearings on 
S. 272, S. 273, S. 977, and S. 1469 (Apr. 5, 7, May 25, June 24 and 
30, 1977), 1977 CAA Legis. Hist. at 3532.
    \250\ See ``Clean Air Act Amendments of 1977,'' Pub. L. 95-95, 
Sec. Sec.  127-129, 91 Stat. 685 (Aug. 7, 1977).
---------------------------------------------------------------------------

    Congress also made significant changes to CAA section 111. For 
example, Congress amended the definition of a standard of performance 
(including by requiring the consideration of ``nonair quality health 
and environmental impact and energy requirements''), authorized 
alternative (e.g., work practice or design) standards in limited 
circumstances, provided states with authority to petition the 
Administrator for new or revised (and more stringent) standards, and 
imposed a strict regulatory schedule for establishing standards of 
performance for categories of major stationary sources that had not yet 
been listed.\251\
---------------------------------------------------------------------------

    \251\ ``Clean Air Act Amendments of 1977,'' Sec.  109, 91 Stat. 
at 697.

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[[Page 64702]]

    The 1977 definition for a standard of performance required ``all 
new sources to meet emission standards based on the reductions 
achievable through the use of the `best technological system of 
continuous emission reduction.' '' \252\ For fossil-fuel fired 
stationary sources, Congress further required a percentage reduction in 
emissions from the use of fuels.\253\ Together, this was designed to 
``force new sources to burn high-sulfur fuel thus freeing low-sulfur 
fuel for use in existing sources where it is harder to control 
emissions and where low-sulfur fuel is needed for compliance.'' \254\
---------------------------------------------------------------------------

    \252\ H.R. Rep. No. 95-294, at 192 (May 12, 1977). Congress 
separately defined ``technological system of continuous emission 
reduction'' as ``(A) a technological process for production or 
operation by any source which is inherently low-polluting or 
nonpolluting, or (B) technological system for continuous reduction 
of the pollution generated by a source before such pollution is 
emitted into the ambient air, including precombustion cleaning or 
treatment of fuels.'' ``Clean Air Act Amendments of 1977,'' Sec.  
109, 91 Stat. at 700; see also 42 U.S.C. 7411(a)(7).
    \253\ ``Clean Air Act Amendments of 1977,'' Sec.  109, 91 Stat. 
at 700.
    \254\ ``New Stationary Sources Performance Standards; Electric 
Utility Steam Generating Units,'' 44 FR 33580, 33581-82 (June 11, 
1979).
---------------------------------------------------------------------------

    Congress also clarified that with respect to CAA section 111(d), 
standards of performance (now applicable in lieu of emission standards) 
``would be based on the best available means (not necessarily 
technological)''.\255\ This was intended to distinguish existing source 
standards from new source standards, for which ``the requirement for 
[the BSER] has been more narrowly redefined as best technological 
system of continuous emission reduction.'' \256\ Additionally, Congress 
clarified that states could consider ``the remaining useful life'' of a 
source when applying a standard of performance to a particular existing 
source.\257\
---------------------------------------------------------------------------

    \255\ H.R. Rep. No. 95-294, at 195 (May 12, 1977).
    \256\ Sen. Muskie, S. Consideration of the H.R. Conf. Rep. No. 
95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353.
    \257\ This concept was already reflected in the EPA's CAA 
section 111(d) implementing regulations under 40 CFR 60.24(f). See 
40 FR 53340, 53347 (Nov. 17, 1975).
---------------------------------------------------------------------------

    In the twenty years since the 1970 CAA Amendments and in spite of 
the refinements of the 1977 CAA Amendments, ``many of the Nation's most 
important air pollution problems [had] failed to improve or [had] grown 
more serious.'' \258\ Indeed, in 1989, President George Bush said that 
`` `progress has not come quickly enough and much remains to be done.' 
'' \259\ This time, with the 1990 CAA Amendments, Congress 
substantially overhauled the CAA. In particular, Congress again added 
to the NAAQS program, completely revised CAA section 112, added a new 
title to target existing fossil fuel-fired stationary sources and 
address growing concerns with acid rain, imported an operating permit 
modeled off the Clean Water Act, and established a phase out of certain 
ozone depleting substances.
---------------------------------------------------------------------------

    \258\ H.R. Rep. No. 101-490, at 144 (May 17, 1990).
    \259\ H.R. Rep. No. 101-490, at 144 (May 17, 1990).
---------------------------------------------------------------------------

    All told, however, there was minimal debate on changes to CAA 
section 111. In fact, the only discussion centered on the repeal of the 
percentage reduction requirement, which became seen as unduly 
restrictive. Accordingly, Congress reverted the definition of 
``standard of performance'' to the definition agreed to in the 1970 CAA 
Amendments, but retained the requirement to consider nonair quality 
environmental impacts and energy requirements added in 1977.\260\ 
However, the repeal would only apply so long as the SO2 cap 
under CAA section 403(e) of the newly established acid rain program 
remained in effect.\261\ Lastly, Congress instructed the EPA to revise 
its new source performance standards for SO2 emissions from 
fossil fuel-fired power plants but required that the revised emission 
rate be no less stringent than before.\262\
---------------------------------------------------------------------------

    \260\ Congress also updated the regulatory schedule that was 
added in the 1977 CAA Amendments to reflect the newly enacted 1990 
CAA Amendments. See ``Clean Air Act Amendments of 1990,'' Sec.  108, 
104 Stat. 2467.
    \261\ ``Clean Air Act Amendments of 1990,'' Sec.  403, 104 Stat. 
at 2631.
    \262\ ``Clean Air Act Amendments of 1990,'' Sec.  301, 104 Stat. 
at 2631.
---------------------------------------------------------------------------

I. 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.'' \263\ The EPA has 
listed more than 60 stationary source categories under this 
provision.\264\ 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.\265\ These standards are known as new source performance 
standards (NSPS), and they are national requirements that apply 
directly to the sources subject to them.
---------------------------------------------------------------------------

    \263\ CAA section 111(b)(1)(A).
    \264\ See 40 CFR 60 subparts Cb--OOOO.
    \265\ CAA section 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 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 a 
particular source, 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.'' \266\ 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.\267\ Once a state receives the EPA's approval of 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 the Act.
---------------------------------------------------------------------------

    \266\ CAA section 111(d)(2)(A).
    \267\ CAA section 111(d)(2)(A).
---------------------------------------------------------------------------

    Section 302(d) of the CAA defines the term ``state'' to include the 
Commonwealth of Puerto Rico, the Virgin Islands, Guam, American Samoa 
and the Commonwealth of the Northern Mariana Islands. While 40 CFR part 
60 contains a separate definition of ``state'' at section 60.2, this 
definition expands on, rather than narrows, the definition in section 
302(d) of the CAA. The introductory language to 40 CFR 60.2 provides: 
``The terms in this part are defined in the Act or in this section as 
follows.'' Section 60.2 defines ``State'' as

[[Page 64703]]

``all non-Federal authorities, including local agencies, interstate 
associations, and State-wide programs that have been delegated 
authority to implement: (1) The provisions of this part and/or (2) the 
permit program established under part 70 of this chapter. The term 
State shall have its conventional meaning where clear from the 
context.'' The EPA believes that the last sentence refers to the 
conventional meaning of ``state'' under the CAA. Thus, the EPA believes 
the term ``state'' as used in the emission guidelines is most 
reasonably interpreted as including the meaning ascribed to that term 
in section 302(d) of the CAA, which expressly includes U.S. 
territories.
    Section 301(d)(A) of the CAA recognizes that the American Indian 
tribes are sovereign Nations and authorizes the EPA to ``treat tribes 
as States under this Act''. The Tribal Authority Rule (63 FR 7254, 
February 12, 1998) identifies that EPA will treat tribes in a manner 
similar to states for all of the CAA provisions with the exception of, 
among other things, specific plan submittal and implementation 
deadlines under the CAA. As a result, though they operate as part of 
the interconnected system of electricity production and distribution, 
affected EGUs located in Indian country would not be encompassed within 
a state's CAA section 111(d) plan. Instead, an Indian tribe with one or 
more affected EGUs located in its area of Indian country \268\ will 
have the opportunity, but not the obligation, to apply for eligibility 
to develop and implement a CAA section 111(d) plan. The Indian tribe 
would need to be approved by the EPA as eligible to develop and 
implement a CAA section 111(d) plan following the procedure set forth 
in 40 CFR part 49. Once a tribe is approved as eligible for that 
purpose, it would be treated in the same manner as a state, and 
references in the emission guidelines to states would refer equally to 
the tribe. The EPA notes that, while tribes have the opportunity to 
apply for eligibility to administer CAA programs, they are not required 
to do so. Further, the EPA has established procedures in 40 CFR part 49 
(see particularly 40 CFR 49.7(c)) that permit eligible tribes to 
request approval of reasonably severable partial program elements. 
Those procedures are applicable here.
---------------------------------------------------------------------------

    \268\ 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.
---------------------------------------------------------------------------

    In these final emission guidelines, the term ``state'' encompasses 
the 50 states and the District of Columbia, U.S. territories, and any 
Indian tribe that has been approved by the EPA pursuant to 40 CFR 49.9 
as to develop and implement a CAA section 111(d) plan.
    The EPA issued regulations implementing CAA section 111(d) in 
1975,\269\ and has revised them in the years since.\270\ (We refer to 
the regulations generally as the implementing 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.\271\ 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,\272\ and the EPA must take final action on 
the state plans within 4 months of the due date for those plans,\273\ 
although the EPA has authority to extend those deadlines.\274\ In this 
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.
---------------------------------------------------------------------------

    \269\ ``State Plans for the Control of Certain Pollutants from 
Existing Facilities,'' 40 FR 53340 (Nov. 17, 1975).
    \270\ The most recent amendment was in 77 FR 9304 (Feb. 16, 
2012).
    \271\ 40 CFR 60.22. In the 1975 rulemaking, the EPA explained 
that it used the term ``emission 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 53343.
    \272\ 40 CFR 60.23(a)(1).
    \273\ 40 CFR 60.27(b).
    \274\ 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)).\275\ In 
addition, the agency has regulated additional pollutants under CAA 
section 111(d) in conjunction with CAA section 129.\276\ The agency has 
not previously regulated CO2 or any other GHGs under CAA 
section 111(d).
---------------------------------------------------------------------------

    \275\ 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).
    \276\ 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).
---------------------------------------------------------------------------

    The EPA's previous CAA section 111(d) actions were necessarily 
geared toward the pollutants and industries regulated. Similarly, in 
this 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 utility 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.\277\
---------------------------------------------------------------------------

    \277\ 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).
---------------------------------------------------------------------------

    In this action, the EPA is promulgating emission guidelines for 
states to follow in developing their CAA section 111(d) plans to reduce 
emissions of CO2 from the utility power sector.

J. Clean Power Plan Proposal and Supplemental Proposal

    On June 18, 2014, the EPA proposed emission guidelines for states 
to follow in developing plans to address GHG emissions from existing 
fossil fuel-fired electric generating units (EGUs). Specifically, the 
EPA proposed rate-based goals for CO2 emissions for each

[[Page 64704]]

state with existing fossil fuel-fired EGUs, as well as guidelines for 
plans to achieve those goals. On November 4, 2014, the EPA published a 
supplemental proposal that proposed emission rate-based goals for 
CO2 emissions for U.S. territories and areas of Indian 
country with existing fossil fuel-fired EGUs. In the supplemental 
proposal, the EPA also solicited comment on authorizing jurisdictions 
(including any states, territories and areas of Indian country) without 
existing fossil fuel-fired EGUs subject to the proposed emission 
guidelines to partner with jurisdictions (including any states) that do 
have existing fossil fuel-fired EGUs subject to the proposed emission 
guidelines in developing multi-jurisdictional plans. The EPA also 
solicited comment on the treatment of RE, demand-side EE and other new 
low- or zero-emitting electricity generation across international 
boundaries in a state plan.
    The EPA also issued two documents after the June 18, 2014 proposal. 
On October 30, 2014, the EPA published a NODA in which the agency 
provided additional information on several topics raised by 
stakeholders and solicited comment on the information presented. This 
action covered three topic areas: 1) the emission reduction compliance 
trajectories created by the interim goal for 2020 to 2029, 2) certain 
aspects of the building block methodology, and 3) the way state-
specific CO2 goals are calculated.
    In a separate action, the EPA published a document regarding 
potential methods for determining the mass that is equivalent to an 
emission rate-based CO2 goal (79 FR 67406; November 13, 
2014). With the action, the EPA also made available, in the docket for 
this rulemaking, a TSD that provided two examples of how a state, U.S. 
territory or tribe could translate a rate-based CO2 goal to 
total metric tons of CO2 (a mass-based equivalent).

K. Stakeholder Outreach and Consultations

    Following the direction in the Presidential Memorandum to the 
Administrator (June 25, 2013),\278\ the EPA engaged in extensive and 
vigorous outreach to stakeholders and the general public at every stage 
of development of this rule. Our outreach has included direct 
engagement with the energy and environment officials in states, tribes, 
and a full range of stakeholders including leaders in the utility power 
sector, labor leaders, non-governmental organizations, other federal 
agencies, other experts, community groups and members of the public. 
The EPA participated in more than 300 meetings before the rule was 
proposed and more than 300 after the proposal.
---------------------------------------------------------------------------

    \278\ 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.
---------------------------------------------------------------------------

    Throughout the rulemaking process, the agency has encouraged, 
organized, and participated in hundreds of meetings about CAA section 
111(d) and reducing carbon pollution from existing power plants. The 
agency's outreach prior to proposal, as well as during the public 
comment period, was designed to solicit policy ideas,\279\ concerns, 
and technical information. The agency received 4.3 million comments 
about all aspects of the proposed rule and thousands of people 
participated in the agency's public hearings, webinars, listening 
sessions,\280\ teleconferences and meetings held all across the 
country.
---------------------------------------------------------------------------

    \279\ The EPA received more than 2,000 emails offering input 
into the development of these guidelines through email and a Web-
based form. 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.
    \280\ Summaries of the 11 public listening sessions in 2013 are 
available at www.regulations.gov at EPA Docket ID No. EPA-HQ-OAR-
2014-0020.
---------------------------------------------------------------------------

    Our engagement has brought together a variety of states and 
stakeholders to discuss a wide range of issues related to the utility 
power sector and the development of emission guidelines under CAA 
section 111(d). The meetings were attended by the EPA Regional 
Administrators, other senior managers and staff who have been 
instrumental in the development of the rule and will play key roles in 
developing and implementing it.
    This outreach process has produced a wealth of information which 
has informed this rule 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 dialogue with states 
and stakeholders will continue 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 states will play in addressing carbon pollution from 
power plants. We firmly believe that our outreach has resulted in a 
more workable rule that will achieve the statutory goals and has 
enhanced the likelihood of timely and successful achievement of the 
carbon reduction goals, given the critical importance and urgency of 
the concrete action.
    The EPA has given stakeholder comments careful consideration and, 
as a result, this final rule includes features that are responsive to 
many stakeholder concerns.
1. Public Hearings
    More than 2,700 people attended the public hearings sessions held 
in Atlanta, Denver, Pittsburgh, and Washington, DC. More than 1,300 
people spoke at the public hearings. Additionally, about 100 people 
attended the public hearing held in Phoenix, Arizona, on the November 
4, 2014 supplemental proposal. Speakers at the public hearings 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 
with the impacts of climate change on their health and on future 
generations, others were worried about the impact of regulations on the 
economy. Their support for the agency's efforts varied.
2. State Officials
    Since fall 2013, the agency has provided multiple opportunities for 
the states to inform this rulemaking. Administrator McCarthy has 
engaged with governors from states with a variety of interests in the 
rulemaking. Other senior agency officials have engaged with every 
branch and major agency of state government--including state 
legislators, attorneys general, state energy, environment, and utility 
officials, and governors' staff.
    On several occasions, state environmental commissioners met with 
senior agency officials to provide comments on the Clean Power Plan. 
The EPA organized, encouraged and attended meetings with states to 
discuss multi-state planning efforts. States have come together with 
several collaborative groups to discuss ways to work together to make 
the Clean Power Plan more affordable. The EPA has participated in and 
supported the states in these discussions. 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 implement the 
requirements of this rulemaking. The meetings provided state leaders, 
including governors, environmental commissioners, energy officers, 
public utility commissioners, and air directors, opportunities to 
engage with the EPA officials. In addition, the states

[[Page 64705]]

submitted public comments from several agencies within each state. The 
wealth of comments and input from states was important in developing 
the final rulemaking.
    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 EPA reached out to all 
50 states to engage with both environmental and energy departments at 
all levels of government. As an example, a three-part webinar series in 
June/July 2014 for the states and tribes offered an interactive format 
for technical staff at the EPA and in the states/tribes to exchange 
ideas and ask clarifying question. The webinars were then posted online 
so other stakeholders could view them. A few weeks after the postings, 
the EPA organized follow-up conference calls with stakeholder groups. 
Also, the EPA hosted scores of technical meetings between states and 
the EPA in the weeks and months after the rule was proposed.
    Additionally, the EPA organized ``hub'' calls; these 
teleconferences brought all of the states in a given EPA region 
together to discuss technical and interstate aspects of the proposal. 
These exchanges helped provide the stakeholders with the information 
they needed to comment on the proposal effectively. The EPA also held a 
series of webinars with state environmental associations and their 
members on a series of technical issues.
    The agency has collected policy papers and comment letters from 
states with overarching energy goals and technical details on the 
states' utility power sector. EPA leadership and staff also 
participated in webinars and meetings with state and tribal officials 
hosted by collaborative groups and trade associations. After the 
comment period closed, and based on our meetings over the last year, as 
well as written comments on the proposal and NODA, the EPA analyzed 
information about data errors that needed to be addressed for the final 
rule. In February and March 2015, we reached out to particular states 
to clarify ambiguous or unclear information that was submitted to the 
EPA related to NEEDS and eGRID data. The EPA contacted particular 
states to clarify the technical comments or concerns to ensure that any 
changes we make are accurate and appropriate.
    To help prepare for implementation of this rule, the agency 
initiated several outreach activities to assist with state planning 
efforts. The agency participated in meetings organized by the National 
Association of State Energy Officials (NASEO), the National Association 
of Regulatory Utility Commissioners (NARUC), and the National 
Association of Clean Air Agencies (NACAA) (the ``3N'' groups). Meeting 
participants discussed issues related to EE and RE.
    To help state officials prepare for the planning process that will 
take place in the states, the EPA presented a webinar on February 24, 
2015. This webinar provided an update on training plans and further 
connection with states in the implementation process. Forty-nine 
states, the District of Columbia, and 14 tribes were represented at 
this webinar. The EPA is developing a state plan electronic collection 
system to receive, track, and store state submittals of plans and 
reports. The EPA plans to use an integrated project team to solicit 
stakeholder input on the system during development. The team 
membership, including state representatives, will bring together the 
business and technology skills required to construct a successful 
product and promote transparency in the EPA's implementation of the 
rule.
    To help identify training needs for the final Clean Power Plan, the 
agency reached out to a number of state and local organizations such as 
the Central State Air Resources Agencies and other such regional air 
agencies. The EPA's outreach on training has included sharing the plans 
with the states and incorporating changes to the training topics based 
on the states' needs. The EPA training plan includes a wide variety of 
topics such as basic training on the electric power sector as well as 
specific pollution control strategies to reduce carbon emissions from 
power plants. In particular, the states requested training on how to 
use programs such as combined heat and power, EE and RE to reduce 
carbon emissions. The EPA will continue to work with states to tailor 
training activities to their needs.
    The agency has engaged, and will continue to engage with states, 
territories, Washington, DC, and tribes after the rulemaking process 
and throughout implementation.
3. Tribal Officials
    The EPA conducted significant outreach to and consultation with 
tribes. Tribes are not required to, but may, develop or adopt Clean Air 
Act programs. The EPA is aware of four facilities with affected EGUs 
located in Indian country: the South Point Energy Center, in Fort 
Mojave Indian country, geographically located within Arizona; the 
Navajo Generating Station, in Navajo Indian country, geographically 
located within Arizona; the Four Corners Power Plant, in Navajo Indian 
country, geographically located within New Mexico; and the Bonanza 
Power Plant, in Ute Indian country, geographically located within Utah. 
The EPA offered consultation to the leaders of the tribes on whose 
lands these facilities are located as well as all of the federally 
recognized tribes to ensure that they had the opportunity to have 
meaningful and timely input into this rule. Section III (``Stakeholder 
Outreach and Conclusions'') of the June 18, 2014 proposal documents the 
EPA's extensive outreach efforts to tribal officials prior to that 
proposal, including an informational webinar, outreach meeting, 
teleconferences with tribal officials and the National Tribal Air 
Association (NTAA), and letters offering consultation. Additional 
outreach to tribal officials conducted by the EPA prior to the November 
4, 2014 supplemental proposal is discussed in Section II.D 
(``Additional Outreach and Consultation'') of the supplemental 
proposal. The additional outreach for the supplemental proposal 
included consultations with all three tribes that have affected EGUs on 
their lands, as well as several other tribes that requested 
consultation, and also additional teleconferences with the NTAA.
    After issuing the supplemental proposal, the EPA offered an 
additional consultation to the leaders of all federally recognized 
tribes. The EPA held an informational meeting open to all tribes and 
also held consultations with the Navajo Nation, Fort McDowell Yavapai 
Nation, Fort Mojave Tribe, Ak-Chin Indian Community, and Hope Tribe on 
November 18, 2014. The EPA held a consultation with the Ute Tribe of 
the Uintah and Ouray Reservation on December 16, 2014, and a 
consultation with the Gila River Indian Community on January 15, 2015. 
The EPA held a public hearing on the supplemental proposal on November 
19, 2014, in Phoenix, Arizona. On April 28, 2015, the EPA held an 
additional consultation with the Navajo Nation.
    Tribes were interested in the impact of this rule on other ongoing 
regulatory actions at the affected EGUs, such as permitting or 
requirements for the best available retrofit technology (BART). Tribes 
also noted that it was important to allow RE projects on tribal lands 
to contribute toward meeting state goals. Some tribes indicated an 
interest in being involved in the development of implementation plans 
for areas of Indian country. Additional detail regarding the EPA's 
outreach to tribes and comments and recommendations from tribes can be 
found in Section X.F of this preamble.

[[Page 64706]]

4. U.S. Territories
    The EPA has met with individual U.S. territories and affected EGUs 
in U.S. territories during the rulemaking process. On July 22, 2014, 
the EPA met with representatives from the Puerto Rico Environmental 
Quality Board, the Puerto Rico Electric Power Authority, the Governor's 
Office, and the Office of Energy, Puerto Rico. On September 8, 2014, 
the EPA held a meeting with representatives from the Guam Environmental 
Protection Agency (GEPA) and the Guam Power Authority and, on February 
18, 2015, the EPA met again with representatives from GEPA.
5. Industry Representatives
    Agency officials have engaged with industry leaders and 
representatives from trade associations in many 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 rule is on the utility power sector, many of 
the meetings with industry have been with utilities and industry 
representatives directly related to the utility power 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 RE 
and EE. 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.
6. Electric Utility Representatives
    Agency officials participated in many meetings with utilities and 
their associations to discuss all aspects of the proposed guidelines. 
We have met with all types of companies that produce electricity, 
including 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).
7. Electricity Grid Operators
    The EPA had a number of conversations with the 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.
8. Representatives from Community and Non-governmental Organizations
    Agency officials engaged with community groups representing 
vulnerable communities, and faith-based groups, among others, during 
the outreach effort. In response to a request from communities, the EPA 
held a day-long training on the Clean Power Plan on October 30, 2014, 
in Washington DC At this meeting, the EPA met with a number of 
environmental groups to provide information on how the agency plans on 
reducing carbon pollution from existing power plants using CAA section 
111(d).
    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. Many members of faith communities 
attended the four public hearings.
    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 EE and low-cost carbon reductions.
    In winter/spring 2015, EPA continued to offer webinars and 
teleconferences for community groups on the rulemaking.
9. Environmental Justice Organizations
    Agency officials engaged with environmental justice groups 
representing communities of color, low-income communities and others 
during the outreach effort. Agency officials also engaged with the 
EPA's National Environmental Justice Advisory Council (NEJAC) members 
in September 2013. The NEJAC is composed of stakeholders, including 
environmental justice leaders and other leaders from state and local 
government and the private sector. Additionally, the agency conducted a 
community call on February 26, 2015, and on February 27, 2015, the EPA 
conducted a follow up webinar for participants in an October 30, 2014 
training session. The EPA also held a webinar for communities on the 
Clean Air Act (CAA) and section 111(d) of the CAA on April 2, 2015. The 
agency, in partnership with FERC and DOE, held two additional webinars 
for communities on the electricity grid and on energy markets on June 
11, 2015, and July 9, 2015.
    During the EPA's extensive outreach conducted before and after 
proposal, the EPA has heard a variety of issues raised by environmental 
justice communities. Communities expressed the desire for the agency to 
conduct an environmental justice (EJ) analysis and to require that 
states in the development of their state plans conduct one as well. 
Additionally, they asked that the agency require that states engage 
with communities in the development of their state plans and that the 
agency conduct meaningful involvement with communities, throughout the 
whole rulemaking process, including the implementation phase. 
Furthermore, communities stressed the importance of low-income and 
communities of color receiving the benefits of this rulemaking and 
being protected from being adversely impacted by this rulemaking.
    The purpose of this rule is to substantially reduce emissions of 
CO2, a key contributor to climate change, which adversely 
and disproportionately affects vulnerable and disadvantaged communities 
in the U.S. and around the world. In addition, the rule will result in 
substantial reductions of conventional air pollutants, providing 
immediate public health benefits to the communities where the 
facilities are located and for many miles around. The EPA is committed 
to ensuring that all Americans benefit from the public health and other 
benefits that this rule will bring. Further discussion of the impacts 
of this rule on vulnerable communities and actions that the EPA is 
taking to address concerns cited by communities is available in 
Sections IX and XII.J of this preamble.
10. Labor
    Senior agency officials 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

[[Page 64707]]

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 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.
11. Other Federal Agencies and Independent Agencies
    Throughout the development of the rulemaking, the EPA consulted 
with other federal agencies with relevant expertise. For example, the 
EPA met with managers from the U.S. Department of Agriculture's 
(USDA's) Rural Utility Service to discuss the rule and potential 
effects on affected EGUs in rural areas and how USDA programs could 
interact with affected EGUs during rule implementation.
    The U.S. Department of Energy (DOE) was a frequent source of 
expertise on the proposed and final rule. EPA management and staff had 
numerous meetings with management and staff at DOE on a range of 
topics, including the effectiveness and costs of energy generation 
technologies, and EE.
    DOE provided technical assistance relating to RE and demand-side 
EE, including RE and demand-side EE cost and performance data and, for 
RE, information on the feasibility of deploying and reliably 
integrating increased RE generation. Further, EPA and DOE staff 
discussed emission measurement and verification (EM&V) strategies.
    The EPA also consulted with DOE on electric reliability issues. EPA 
staff and managers met and spoke with DOE staff and managers throughout 
the development of the proposed and final rules on topic related to 
electric system reliability.
    EPA officials worked closely with DOE and Federal Energy Regulatory 
Commission (FERC) officials to ensure, to the greatest extent possible, 
that actions taken by states and affected EGUs to comply with the final 
rule mitigate potential electric system reliability issues. Senior EPA 
officials met with each of the FERC Commissioners and EPA staff had 
frequent contact with FERC staff throughout the development the rule. 
FERC held four technical conferences to discuss implications of 
compliance approaches to the rule for electric reliability. EPA staff 
attended the four conferences and EPA leadership spoke at all of them. 
The EPA, DOE, and FERC will continue to work together to ensure 
electric grid reliability in the development and implementation of 
state plans.

L. Comments on the Proposal

    The Administrator signed the proposed emission guidelines on June 
2, 2014, and, on the same day, the EPA made this version available to 
the public at http://www.epa.gov/cleanpowerplan/. The 120-day public 
comment period on the proposal began on June 18, 2014, the day of 
publication of the proposal in the Federal Register. On September 18, 
2014, in response to requests from stakeholders, the EPA extended the 
comment period by 45 days, to December 1, 2014, giving stakeholders 
over 165 days to review and comment upon the proposal. Stakeholders 
also had the opportunity to comment on the NODA, as well as the Federal 
Register document and TSD regarding potential methods for determining 
the mass that is equivalent to an emission rate-based CO2 
goal, through December 1, 2014. The EPA offered a separate 45-day 
comment period for the November 4, 2014 supplemental proposal, and that 
comment period closed on December 19, 2014.
    The EPA received more than 4.2 million comments on the proposed 
carbon pollution emission guidelines from a range of stakeholders that 
included, including state environmental and energy officials, local 
government officials, tribal officials, public utility commissioners, 
system operators, utilities, public interest advocates, and members of 
the public. The agency received comments on many aspects of the 
proposal and many suggestions for changes that would address issues of 
concern.

III. Rule Requirements and Legal Basis

A. Summary of Rule Requirements

    The EPA is establishing emission guidelines for states to use in 
developing plans to address GHG 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 source category-specific 
CO2 emission performance rates, state-specific goals, 
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.
    The EPA has determined that the BSER is the combination of emission 
rate improvements and limitations on overall emissions at affected EGUs 
that can be accomplished through the following three sets of measures 
or building blocks:

    1. Improving heat rate at affected coal-fired steam EGUs.
    2. Substituting increased generation from lower-emitting 
existing natural gas combined cycle units for generation from 
higher-emitting affected steam generating units.
    3. Substituting increased generation from new zero-emitting RE 
generating capacity for generation from affected fossil fuel-fired 
generating units.

    Consistent with CAA section 111(d) and other rules promulgated 
under this section, the EPA is taking a traditional, performance-based 
approach to establishing emission guidelines for affected sources and 
applying the BSER to two source subcategories of existing fossil fuel-
fired EGUs--fossil fuel-fired electric utility steam generating units 
and stationary combustion turbines. The EPA is finalizing source 
subcategory-specific emission performance rates that reflect the EPA's 
application of the BSER. For fossil fuel-fired steam generating units, 
we are finalizing a performance rate of 1,305 lb CO2/MWh. 
For stationary combustion turbines, we are finalizing a performance 
rate of 771 lb CO2/MWh. The EPA has also translated the 
source subcategory-specific CO2 emission performance rates 
into equivalent statewide rate-based and mass-based CO2 
goals and is providing those as an option for states to use.
    Under CAA section 111(d), each state must develop, adopt, and then 
submit its plan to the EPA. For its CAA section 111(d) plan, a state 
will determine whether to apply these emission performance rates to 
each affected EGU, individually or together, or to take an alternative 
approach and meet either an equivalent statewide rate-based goal or an 
equivalent statewide mass-based

[[Page 64708]]

goal, as provided by the EPA in this rulemaking.
    States with one or more affected EGUs will be required to develop 
and implement plans that set emission standards for affected EGUs. The 
CAA section 111(d) emission guidelines that the EPA is promulgating in 
this action apply to only the 48 contiguous states and any Indian tribe 
that has been approved by the EPA pursuant to 40 CFR 49.9 as eligible 
to develop and implement a CAA section 111(d) plan.\281\ Because 
Vermont and the District of Columbia do not have affected EGUs, they 
will not be required to submit a state plan. Because the EPA does not 
possess all of the information or analytical tools needed to quantify 
the BSER for the two non-contiguous states with otherwise affected EGUs 
(Alaska and Hawaii) and the two U.S. territories with otherwise 
affected EGUs (Guam and Puerto Rico), these emission guidelines do not 
apply to those areas, and those areas will not be required to submit 
state plans on the schedule required by this final action.
---------------------------------------------------------------------------

    \281\ In the case of a tribe that has one or more affected EGUs 
in its area of Indian country, the tribe has the opportunity, but 
not the obligation, to establish a CO2 emission standard 
for each affected EGU located in its area of Indian country and a 
CAA section 111(d) plan for its area of Indian country. If the tribe 
chooses to establish its own plan, it must seek and obtain authority 
from the EPA to do so pursuant to 40 CFR 49.9. If it chooses not to 
seek this authority, the EPA has the responsibility to determine 
whether it is necessary or appropriate, in order to protect air 
quality, to establish a CAA section 111(d) plan for an area of 
Indian country where affected EGUs are located.
---------------------------------------------------------------------------

    In developing its CAA section 111(d) plan, a state will have the 
option of choosing from two different approaches: (1) An ``emission 
standards'' approach, or (2) a ``state measures'' approach. With an 
emission standards approach, a state will apply all requirements for 
achieving the subcategory-specific CO2 emission performance 
rates or the state-specific CO2 emission goal to affected 
EGUs in the form of federally enforceable emission standards. With a 
state measures approach, a state plan would be comprised, at least in 
part, of measures implemented by the state that are not included as 
federally enforceable components of the plan, along with a backstop of 
federally enforceable emission standards for affected EGUs that would 
apply in the event the plan does not achieve its anticipated level of 
CO2 emission performance.
    The EPA is requiring states to make their final plan submittals by 
September 6, 2016, or to make an initial submittal by this date in 
order to obtain an extension for making their final plan submittals no 
later than September 6, 2018, which is 3 years from the signature date 
of the rule. In order to receive an extension, states, in the initial 
submittal, must address three required components sufficiently to 
demonstrate that a state is able to undertake steps and processes 
necessary to timely submit a final plan by the extended date of 
September 6, 2018. The first required component is identification of 
final plan approach or approaches under consideration, including a 
description of progress made to date. The second required component is 
an appropriate explanation for why the state requires additional time 
to submit a final plan beyond September 6, 2016. The third required 
component for states to address in the initial submittal is a 
demonstration of how they have been engaging with the public, including 
vulnerable communities, and a description of how they intend to 
meaningfully engage with community stakeholders during the additional 
time (if an extension is granted) for development of the final plan.
    Affected EGUs must achieve the final emission performance rates or 
equivalent state goals by 2030 and maintain that level thereafter. The 
EPA is establishing an 8-year interim period over which states must 
achieve the full required reductions to meet the CO2 
performance rates, and this begins in 2022. This 8-year interim period 
from 2022 through 2029, is separated into three steps, 2022-2024, 2025-
2027, and 2028-2029, each associated with its own interim 
CO2 emission performance rates that states must meet, as 
explained in Section VI of this preamble.
    For the final emission guidelines, the EPA is revising the list of 
components required in a final state plan submittal to reflect: (1) 
Components required for all state plan submittals; (2) components 
required for the emission standards approach; and (3) components 
required for the state measures approach. The revised list of 
components also reflects the approvability criteria, which are no 
longer separate from the state plan submittal components.
    All state plans must include the following components:

 Description of the plan approach and geographic scope
 Identification of the state's CO2 interim period 
goal (for 2022-2029), interim steps (interim step goal 1 for 2022-
2024; interim step goal 2 for 2025-2027; interim step goal 3 for 
2028-2029) and final CO2 emission goal of 2030 and beyond
 Demonstration that the plan submittal is projected to 
achieve the state's CO2 emission goal \282\
---------------------------------------------------------------------------

    \282\ A state that chooses to set emission standards that are 
identical to the emission performance rates for both the interim 
period and in 2030 and beyond need not identify interim state goals 
nor include a separate demonstration that its plan will achieve the 
state goals.
---------------------------------------------------------------------------

 State recordkeeping and reporting requirements
 Certification of hearing on state plan
 Supporting documentation

    Also, in all state plans, as part of the supporting documentation, 
a state must include a description of how they considered reliability 
in developing its state plan.
    State plan submittals using the emission standards approach must 
also include:

     Identification of each affected EGU; identification of 
federally enforceable emission standards for the affected EGUs; and 
monitoring, recordkeeping and reporting requirements.
     Demonstrations that each emission standard will result 
in reductions that are quantifiable, non-duplicative, permanent, 
verifiable, and enforceable.

    State plan submittals using the state measures approach must also 
include:

     Identification of each affected EGU; identification of 
federally enforceable emission standards for affected EGUs (if 
applicable); identification of backstop of federally enforceable 
emission standards; and monitoring, recordkeeping and reporting 
requirements.
     Identification of each state measure and demonstration 
that each state measure will result in reductions that are 
quantifiable, non-duplicative, permanent, verifiable, and 
enforceable.

    In addition to these requirements, each state plan must follow the 
EPA implementing regulations at 40 CFR 60.23.
    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 negative declaration 
submitted to the EPA by September 6, 2016. In the case of a tribe that 
has one or more affected EGUs in its area of Indian country,\283\ the 
tribe has the opportunity, but not the obligation, to establish a CAA 
section 111(d) plan for its area of Indian country. If a tribe with one 
or more affected EGUs located in its area of

[[Page 64709]]

Indian country does not submit a plan or does not receive EPA approval 
of a submitted plan, the EPA has the responsibility to establish a CAA 
section 111(d) plan for that area if it determines that such a plan is 
necessary or appropriate.
---------------------------------------------------------------------------

    \283\ 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 Power Plant; one on Ute lands, the Bonanza 
Power Plant; 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.
---------------------------------------------------------------------------

    During implementation of its approved state plan, each state must 
demonstrate to the EPA that its affected EGUs are meeting the interim 
and final performance requirements included in this final rule through 
monitoring and reporting requirements. State plan requirements and 
flexibilities are described more fully in Section VIII of this 
preamble.

B. Brief Summary of Legal Basis

    This rule is consistent with the requirements of CAA section 111(d) 
and the implementing regulations.\284\ 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. 
Concurrently with this rule, the EPA is finalizing a CAA section 111(b) 
rulemaking establishing standards of performance for CO2 
emissions from new fossil fuel-fired EGUs, from modified fossil fuel-
fired EGUs, and from reconstructed fossil fuel-fired EGUs, and any of 
those sets of section 111(b) standards of performance provides the 
requisite predicate for this rulemaking.
---------------------------------------------------------------------------

    \284\ Under CAA section 111(d), there is no requirement that the 
EPA make a finding that the emissions from existing sources that are 
the subject of regulation cause or contribute significantly to air 
pollution which may reasonably be anticipated to endanger public 
health or welfare. As predicates to promulgating regulations under 
CAA section 111(d) for existing sources, the EPA must make 
endangerment and cause-or-contribute-significantly findings for 
emissions from the source category, and the EPA must promulgate 
regulations for new sources in the source category. In the CAA 
section 111(b) rule for CO2 emissions for new affected 
EGUs that the EPA is promulgating concurrently with this rule, the 
EPA discusses the endangerment and cause-or-contribute-significantly 
findings and explains why the EPA has already made them for the 
affected EGU source categories so that the EPA is not required to 
make them for CO2 emissions from affected EGUs, and, in 
the alternative, why, if the EPA were required to make those 
findings, it was making them in that rulemaking.
---------------------------------------------------------------------------

    A key step in promulgating requirements under CAA section 111(d)(1) 
is determining the ``best system of emission reduction which . . . the 
Administrator determines has been adequately demonstrated'' (BSER) 
under CAA section 111(a)(1). It is clear by the terms of section 
111(a)(1) and the implementing regulations for section 111(d) that the 
EPA is authorized to determine the BSER; \285\ accordingly, in this 
rulemaking, the EPA is determining the BSER.
---------------------------------------------------------------------------

    \285\ The EPA is not re-opening that interpretation in this 
rulemaking.
---------------------------------------------------------------------------

    The EPA is finalizing the BSER for fossil fuel-fired EGUs based on 
building blocks 1, 2, and 3. Building block 1 includes operational 
improvements and equipment upgrades that the coal-fired steam-
generating EGUs in the state may undertake to improve their heat rate. 
It qualifies as part of the BSER because it improves the carbon 
intensity of the affected EGUs in generating electricity through 
actions the affected sources may undertake that are adequately 
demonstrated and whose cost is ``reasonable.'' Building blocks 2 and 3 
include increases in low- or zero-emitting generation which substitute 
for generation from the affected EGUs and thereby reduce CO2 
emissions from those sources. All of these measures are components of a 
``system of emission reduction'' for the affected EGUs because they 
entail actions that the affected EGUs may themselves undertake that 
have the effect of reducing their emissions. Further, these measures 
meet the criteria in CAA section 111(a)(1) and the case law for the 
``best'' system of emission reduction that is ``adequately 
demonstrated'' because they achieve the appropriate level of 
reductions, their cost is ``reasonable,'' they do not have adverse non-
air quality health and environmental impacts or impose adverse energy 
requirements, and they are each well-established among affected EGUs. 
It should be emphasized that these measures are consistent with current 
trends in the electricity sector.
    Building blocks 2 and 3 may be implemented through a set of 
measures, including reduced generation from the fossil fuel-fired EGUs. 
These measures do not, however, reduce the amount of electricity that 
can be sold or that is available to end users. In addition, states 
should be expected to allow their affected EGUs to trade rate-based 
emission credits or mass-based emission allowances (trading) because 
trading is well-established for this industry and has the effect of 
focusing costs on the affected EGUs for which reducing emissions is 
most cost-effective. Because trading facilitates implementation of the 
building blocks and may help to optimize cost-effectiveness, trading is 
a method of implementing the BSER as well.
    As a result, an affected EGU has a set of choices for achieving its 
emission standards. For example, an affected coal-fired steam 
generating unit can achieve a rate-based standard through a set of 
actions that implement the building block 1 measures and that implement 
the building block 2 and 3 measures through a set of actions that range 
from purchasing full or partial interest in existing NGCC or new RE 
assets to purchasing ERCs that represent the environmental attributes 
of increased NGCC generation or new renewable generation. In addition, 
the affected EGU may reduce its generation and thereby reduce the 
extent that it needs to implement the building blocks. The affected EGU 
may also purchase rate-based emission credits from other affected EGUs. 
If the state chooses to impose a mass-based emission standard, the 
coal-fired steam generating unit may implement building block 1 
measures, purchase mass-based emission allowances from other affected 
EGUs, or reduce its generation. In light of the available sources of 
lower- and zero-emitting replacement generation, this approach would 
achieve an appropriate level of emission reductions and maintain the 
reliability of the electricity system.
    With the promulgation of the emission guidelines, each state must 
develop and submit a plan to achieve the CO2 emission 
performance rates established by the EPA or the equivalent statewide 
rate-based or mass-based goal provided by the EPA in this rule. The EPA 
interprets CAA section 111(d) to allow states to establish standards of 
performance and provide for their implementation and enforcement 
through either the ``emission standards'' or the ``state measures'' 
plan type. In the case of the ``emission standards'' plan type, the 
emission standards establish standards of performance, and the other 
components of the plan provide for their implementation and 
enforcement. In the case of the ``state measures'' plan type, -the 
state submits a plan that relies upon measures that are only 
enforceable as a matter of state law that will, in conjunction with any 
emission standards on affected EGUs, result in the achievement of the 
applicable performance rates or state goals by the affected EGUs. Under 
the state measures plan type, states must also submit a federally 
enforceable backstop and a mechanism that would trigger implementation 
of the backstop; therefore, in a state measures plan, the standards of 
performance take the form of the backstop, the trigger mechanism 
provides for the implementation of such backstop, and the other 
required components of the plan provide for

[[Page 64710]]

implementation and enforcement of the standards of performance.
    These two types of state plans and their respective approaches, 
which could be implemented on a single-state or multi-state basis, 
allow states to meet the statutory requirements of section 111(d) while 
accommodating the wide range of regulatory requirements and other 
programs that states have deployed or will deploy in the electricity 
sector that reduce CO2 emissions from affected EGUs. It 
should be noted that both state plan types allow the state flexibility 
in assigning the emission performance obligations to its affected EGUs 
in the form of standards of performance as long as the required 
emission performance level is met. Both plan types harness the 
efficiencies of emission reduction opportunities in the interconnected 
electricity system and are fully consistent with the principles of 
cooperative federalism that underlie the Clean Air Act generally and 
CAA section 111(d) particularly. That is, both plan types achieve the 
emission performance requirements through the vehicle of a state plan, 
and provide 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.
    Both state plan types, 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 appropriate measures to rely 
upon for its plan. The state may adopt measures that assure the 
achievement of the requisite CO2 emission performance rate 
or state goal by the affected EGUs, and is not limited to the measures 
that the EPA identifies as part of the BSER.
    In this rulemaking, the EPA establishes reasonable deadlines for 
state plan submission. Under CAA section 111(d)(1), state plans must 
``provide for implementation and enforcement'' of the standards of 
performance, and under CAA section 111(d)(2), the state plans must be 
``satisfactory'' for the EPA to approve them. In this rulemaking, the 
EPA is finalizing the criteria that the state plans must meet under 
these requirements.
    The EPA discusses its legal interpretation in more detail in other 
parts of this preamble and provides additional information about 
certain issues in the Legal Memorandum included in the docket for this 
rulemaking.

IV. Authority for This Rulemaking, Definition of Affected Sources, and 
Treatment of Source Categories

A. EPA's Authority Under CAA Section 111(d)

    EPA's authority for this rule is CAA section 111(d). CAA section 
111(d) provides that the EPA will promulgate regulations under which 
each state will establish standards of performance for existing sources 
for any air pollutant that meets two criteria. First, CAA section 
111(d) applies to air pollutants that are not regulated as a criteria 
pollutant under section 108 or as a hazardous air pollutant (HAP) under 
CAA section 112. 42 U.S.C. 7411(d)(1)(A)(i).\286\ Second, section 
111(d) applies only to air pollutants for which the existing source 
would be regulated under section 111 if it were a new source. 42 U.S.C. 
7411(d)(1)(A)(ii). Here, carbon dioxide (CO2) meets both 
criteria: (1) It is not a criteria pollutant regulated under section 
108 nor a HAP regulated under CAA section 112, and (2) CO2 
emissions from new power plants (including newly constructed, modified 
and reconstructed power plants) are regulated under the CAA section 
111(b) rule that is being finalized along with this rule.
---------------------------------------------------------------------------

    \286\ Section 111(d) might be read to apply to HAP under certain 
circumstances. However, because carbon dioxide is not a HAP, this 
issue does not need to be resolved in the context of this rule.
---------------------------------------------------------------------------

B. CAA Section 112 Exclusion to CAA Section 111(d) Authority

    CAA section 111(d) contains an exclusion that limits the regulation 
under CAA section 111(d) of air pollutants that are regulated under CAA 
section 112. 42 U.S.C. 7411(d)(1)(A)(i). This ``Section 112 Exclusion'' 
in CAA section 111(d) was the subject of a significant number of 
comments based on two differing amendments to this exclusion enacted in 
the 1990 CAA Amendments. As discussed in more detail below, the House 
and the Senate each initially passed different amendments to the 
Section 112 Exclusion and both amendments were ultimately passed by 
both houses and signed into law. In 2005, in connection with the Clean 
Air Mercury Rule (CAMR), the EPA discussed the agency's interpretation 
of the Section 112 Exclusion in light of these two differing amendments 
and concluded that the two amendments were in conflict and that the 
provision should be read as follows to give both amendments meaning: 
where a source category has been regulated under CAA section 112, a CAA 
section 111(d) standard of performance cannot be established to address 
any HAP listed under CAA section 112(b) that may be emitted from that 
particular source category. See 70 FR 15994, 16029-32 (March 29, 2005).
    In June 2014, the EPA presented this previous interpretation as 
part of the proposal and requested comment on it. The EPA received 
numerous comments on its previous interpretation, including comments on 
the proper interpretation and effect of each of the two differing 
amendments, and whether the Section 112 Exclusion should be read to 
mean that the EPA's regulation of HAP from power plants under CAA 
section 112 bars the EPA from establishing CAA section 111(d) 
regulations covering CO2 emissions from power plants. In 
particular, many comments focused on two specific issues. First, some 
commenters--including some industry and state commenters that had 
previously endorsed the EPA's interpretation of the Section 112 
Exclusion in other contexts \287\--argued that the EPA's 2005 
interpretation was in error because it allowed the regulation of 
certain pollutants from source categories under CAA section 111(d) when 
those source categories were also regulated for different pollutants 
under CAA section 112. Second, some commenters argued that the EPA's 
previous interpretation of the House amendment (as originally 
represented in 2005 at 70 FR at 16029-30) was in error because it 
improperly read that amendment as focusing on whether a source category 
was regulated under CAA section 112 rather than on whether the air 
pollutant was regulated under CAA section 112, and that improper 
reading lead to an interpretation that was inconsistent with the 
structure and purpose of the CAA.
---------------------------------------------------------------------------

    \287\ For example, in the CAMR litigation (State of New Jersey 
v. EPA, No. 05-1097 (D.C. Cir.), the joint brief filed by a group of 
intervenors and an amicus (including six states and the West 
Virginia Department of Environmental Protection, and Utility Air 
Regulatory Group and nine other industry entities) stated that the 
EPA had interpreted section 111(d) in light of the two different 
amendments and that the EPA's interpretation was ``a reasoned way to 
reconcile the conflicting language and the Court should defer to the 
EPA's interpretation.'' Joint Brief of State Respondent-Intervenors, 
Industry Respondent-Intervernors, and State Amicus, filed May 18, 
2007, at 25.
---------------------------------------------------------------------------

    In light of the comments, the EPA has reconsidered its previous 
interpretation of the Section 112 Exclusion and, in particular, 
considered whether the exclusion precludes the regulation under CAA 
section 111(d) of CO2 from power plants given that power 
plants are regulated for certain HAP under CAA section 112. On this 
issue, the EPA

[[Page 64711]]

has concluded that the two differing amendments are not properly read 
as conflicting. Instead, the House amendment and the Senate Amendment 
should each be read to mean the same in the context presented by this 
rule: that the Section 112 Exclusion does not bar the regulation under 
CAA section 111(d) of non-HAP from a source category, regardless of 
whether that source category is subject to standards for HAP under CAA 
section 112. In reaching this conclusion, the EPA has revised its 
previous interpretation of the House amendment, as discussed below.
1. Structure of the CAA and Pre-1990 Section 112 Exclusion
    The Clean Air Act sets out a comprehensive scheme for air pollution 
control, addressing three general categories of pollutants emitted from 
stationary sources: (1) Criteria pollutants (which are addressed in 
sections 108-110); (2) hazardous pollutants (which are addressed under 
section 112); and (3) ``pollutants that are (or may be) harmful to 
public health or welfare but are not or cannot be controlled under 
sections 108-110 or 112.'' 40 FR 53340 (Nov. 17, 1975).
    Six ``criteria'' pollutants are regulated under sections 108-110. 
These are pollutants that the Administrator has concluded ``cause or 
contribute to air pollution which may reasonably be anticipated to 
endanger public health or welfare;'' ``the presence of which in the 
ambient air results from numerous and diverse mobile or stationary 
sources;'' and for which the Administrator has issued, or plans to 
issue, ``air quality criteria. 42 U.S.C. 7408(a)(1). Once the EPA 
issues air quality criteria for such pollutants, the Administrator must 
propose primary National Ambient Air Quality Standards (NAAQS) for 
them, set at levels ``requisite to protect the public health'' with an 
``adequate margin of safety.'' 42 U.S.C. 7409(a)-(b). States must then 
adopt plans for implementing NAAQS. 42 U.S.C. 7410.
    HAP are regulated under CAA section 112 and include the pollutants 
listed by Congress in section 112(b)(1) and other pollutants that the 
EPA lists under sections 112(b)(2) and (b)(3). CAA section 112 further 
provides that the EPA will publish and revise a list of ``major'' and 
``area'' source categories of HAP, and then establish emissions 
standards for HAP emitted by sources within each listed category. 42 
U.S.C. 7412(c)(1) & (2).
    CAA section 111, 42 U.S.C. 7411, is the third part of the CAA's 
structure for regulating stationary sources. Section 111 has two main 
components. First, section 111(b) requires the EPA to promulgate 
federal ``standards of performance'' addressing new stationary sources 
that cause or contribute significantly to ``air pollution which may 
reasonably be anticipated to endanger public health or welfare.'' 42 
U.S.C. 7411(b)(1)(A). Once the EPA has set new source standards 
addressing emissions of a particular pollutant under CAA section 
111(b), CAA section 111(d) provides that the EPA will promulgate 
regulations requiring states to establish standards of performance for 
existing stationary sources of the same pollutant. 42 U.S.C. 
7411(d)(1).
    Together, the criteria pollutant/NAAQS provisions in sections 108-
110, the hazardous air pollutant provisions in section 112, and 
performance standard provisions in section 111 constitute a 
comprehensive scheme to regulate air pollutants with ``no gaps in 
control activities pertaining to stationary source emissions that pose 
any significant danger to public health or welfare.'' S. Rep. No. 91-
1196, at 20 (1970).\288\
---------------------------------------------------------------------------

    \288\ In subsequent CAA amendments, Congress has maintained this 
three-part scheme, but supplemented it with the Preservation of 
Significant Deterioration (PSD) program, the Acid Rain Program and 
the Regional Haze program.
---------------------------------------------------------------------------

    The specific role of CAA section 111(d) in this structure can be 
seen in CAA subsection 111(d)(1)(A)(i), which provides that regulation 
under CAA section 111(d) is intended to cover pollutants that are not 
regulated under either the criteria pollutant/NAAQS provisions or 
section 112. Prior to 1990, this limitation was laid out in plain 
language, which stated that CAA section 111(d) regulation applied to 
``any air pollutant . . . for which air quality criteria have not been 
issued or which is not included on a list published under section 
[108(a)] or [112(b)(1)(A)].'' This plain language demonstrated that 
section 111(d) is designed to regulate pollutants from existing sources 
that fall in the gap not covered by the criteria pollutant provisions 
or the hazardous air pollutant provisions.
    This gap-filling purpose can be seen in the early legislative 
history of the CAA. As originally enacted in the 1970 CAA, the 
precursor to CAA section 111 (which was originally section 114) was 
described as covering pollutants that would not be controlled by the 
criteria pollutant provisions or the hazardous air pollutant 
provisions. See S. Committee Rep. to accompany S. 4358 (Sept. 17, 
1970), 1970 CAA Legis. Hist. at 420 (``It should be noted that the 
emission standards for pollutants which cannot be considered hazardous 
(as defined in section 115 [which later became section 112]) could be 
established under section 114 [later, section 111]. Thus, there should 
be no gaps in control activities pertaining to stationary source 
emissions that pose any significant danger to public health or 
welfare.''); Statement by S. Muskie, S. Debate on S. 4358 (Sept. 21, 
1970), 1970 CAA Legis. Hist. at 227 (``[T]he bill [in section 114] 
provides the Secretary with the authority to set emission standards for 
selected pollutants which cannot be controlled through the ambient air 
quality standards and which are not hazardous substances.'').
2. The 1990 Amendments to the Section 112 Exclusion
    The Act was amended extensively in 1990. Among other things, 
Congress sought to accelerate the EPA's regulation of hazardous 
pollutants under section 112. To that end, Congress established a 
lengthy list of HAP; set criteria for listing ``source categories'' of 
such pollutants; and required the EPA to establish standards for each 
listed source category's hazardous pollutant emissions. 42 U.S.C. 
7412(b), (c) and (d). In the course of overhauling the regulation of 
HAP under section 112, Congress needed to edit section 111(d)'s 
reference to section 112(b)(1)(A), which was to be eliminated as part 
of the revisions to section 112.
    To address the obsolete cross-reference to section 7412(b)(1)(A), 
Congress passed two differing amendments--one from the Senate and one 
from the House--that were never reconciled in conference. The Senate 
amendment replaced the cross reference to old section 112(b)(1)(A) with 
a cross-reference to new section 112. Pub. L. 101-549, Sec.  302(a), 
104 Stat. 2399, 2574 (1990). The House amendment replaced the cross-
reference with the phrase ``emitted from a source category which is 
regulated under section [112].'' Pub. L. 101-549, Sec.  108(g), 104 
Stat. 2399, 2467 (1990).\289\ Both amendments were

[[Page 64712]]

enacted into law, and thus both are part of the current CAA. To 
determine how this provision is properly applied in light of the two 
differing amendments, we first look at the Senate amendment, then at 
the House amendment, then discuss how the two amendments are properly 
read together.

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

    \289\ Originally, when the House bill to amend the CAA was 
introduced in January 1989, it focused on amendments to control HAP. 
Of particular note, the amendments to section 112 included a 
provision that excluded regulation under section 112 of ``[a]ny air 
pollutant which is included on the list under section 108(a), or 
which is regulated for a source category under section 111(d).'' 
H.R. 4, Sec.  2 (Jan. 3, 1989), 1990 CAA Legist. Hist. at 4046. In 
other words, the Section 112 Exclusion in section 111(d) that was 
ultimately contained in the House amendment was originally crafted 
as what might be called a ``Section 111(d) Exclusion'' in section 
112. This is significant because the ``source category'' phrasing in 
the original January 1989 text with respect to section 111(d) makes 
sense, whereas the ``source category'' phrasing in the 1990 House 
amendment does not. When referring to the scope of what is regulated 
under section 111(d), it makes sense to frame that scope with 
respect to source categories, because section 111 regulation begins 
with the identification of source categories under section 
111(b)(1)(A). By contrast, regulation under section 112 begins with 
the identification of HAP under section 112(b); the listing of 
source categories under section 112(c) is secondary to the listing 
of HAP. From this history, and in light of this difference between 
the scope of what is regulated in sections 111 and 112, it is 
reasonable to conclude that the ``source category'' phrasing is a 
legacy from the original 1989 bill--that is, when converting the 
1989 text into the Section 112 Exclusion that we see in the 1990 
House amendment, the legislative drafters continued to use phrasing 
based on ``source category'' notwithstanding that this phrasing 
created a mismatch with the way that the scope of section 112 
regulation is determined.
---------------------------------------------------------------------------

3. The Senate Amendment is Clear and Unambiguous
    Unlike the ambiguous amendment to CAA section 111(d) in the House 
amendment (discussed below), the Senate amendment is straightforward 
and unambiguous. It maintained the pre-1990 meaning of the Section 112 
Exclusion by simply substituting ``section 112(b)'' for the prior 
cross-reference to ``section 112(b)(1)(A).'' Pub. L. 101-549, Sec.  
302(a), 104 Stat. 2399, 2574 (1990). So amended, CAA section 111(d) 
mandates that the EPA require states to submit plans establishing 
standards for ``any air pollutant . . . which is not included on a list 
published under section [108(a)] or section [112(b)].'' Thus, the 
Section 112 Exclusion resulting from the Senate amendment would 
preclude CAA section 111(d) regulation of HAP emission but would not 
preclude CAA section 111(d) regulation of CO2 emissions from 
power plants notwithstanding that power plants are also regulated for 
HAP under CAA section 112.
    Some commenters have argued that the Senate amendment should be 
given no effect, because only the House amendment is shown in the U.S. 
Code, and because the Senate amendment appeared under the heading 
``conforming amendments,'' and for various other reasons. The EPA 
disagrees. The Senate amendment, like the House amendment, was enacted 
into law as part of the 1990 CAA amendments, and must be given effect.
    First, that the U.S. Code only reflects the House amendment does 
not change the fact that both amendments were signed into law as part 
of the 1990 Amendments, as shown in the Statutes at Large. Pub. L. 101-
549, Sec. Sec.  108(g) and 302(a), 104 Stat. 2399, 2467, 2574 (1990). 
Where there is a conflict between the U.S. Code and the Statutes at 
Large, the latter controls. See 1 U.S.C. 112 & 204(a); Stephan v. 
United States, 319 U.S. 423, 426 (1943) (``the Code cannot prevail over 
the Statutes at Large when the two are inconsistent''); Five Flags Pipe 
Line Co. v. Dep't of Transp., 854 F.2d 1438, 1440 (D.C. Cir. 1988) 
(``[W]here the language of the Statutes at Large conflicts with the 
language in the United States Code that has not been enacted into 
positive law, the language of the Statutes at Large controls.'').
    Second, the ``conforming'' label is irrelevant. A ``conforming'' 
amendment may be either substantive or non-substantive. Burgess v. 
United States, 553 U.S. 124, 135 (2008). And while the House Amendment 
contains more words, it also qualifies as a ``conforming amendment'' 
under the definition in the Senate Legislative Drafting Manual, Section 
126(b)(2) (defining ``conforming amendments'' as those ``necessitated 
by the substantive amendments of provisions of the bill''). Here, both 
the House and Senate amendments were ``necessitated by'' Congress' 
revisions to section 112 in the 1990 CAA Amendment, which included the 
deletion of old section 112(b)(1)(A). Thus, the House's amendment is no 
less ``conforming'' than the Senate's, and the heading under which it 
was enacted (``Miscellaneous Guidance'') does not suggest any more 
importance than ``Conforming Amendments.'' In any event, courts gives 
full effect to conforming amendments, see Washington Hosp. Ctr. v. 
Bowen, 795 F.2d 139, 149 (D.C. Cir. 1986), and so neither the Senate 
Amendment nor the House amendment can be ignored.
    Third, the legislative history of the Senate amendment supports the 
conclusion that the substitution of the updated cross-reference was not 
a mindless, ministerial decision, but reflected a decision to choose an 
update of the cross reference instead of the text that was inserted 
into the Section 112 Exclusion by the House amendment. In mid-1989, the 
House and Senate introduced identical bills (H.R. 3030 and S. 1490, 
respectively) to provide for ``miscellaneous'' changes to the CAA. In 
both the Senate and House bills as they were introduced in mid-1989, 
the Section 112 Exclusion was to be amended by taking out ``or 
112(b)(1)(A)'' and inserting ``or emitted from a source category which 
is regulated under section 112.'' H.R. 3030, as introduced, 101st Cong. 
Sec.  108 (Jul. 27, 1989); S. 1490, as introduced, 101st Cong. Sec.  
108 (Aug. 3, 1989). See 1990 CAA Legis. Hist. at 3857 (noting that H.R. 
3030 and S.1490, as introduced, were the same). Although S. 1490 was 
identical to H.R. 3030 when they were introduced, the Senate reported a 
vastly different bill (S.1630) at the end of 1989. See S. 1630, as 
reported (Dec. 20, 1989), 1990 CAA Legis. Hist. at 7906. As reported 
and eventually passed, S. 1630 did not contain the text in the House 
amendment (``or emitted from a source category which is regulated under 
section 112'') and instead contained the substitution of cross 
references (changing ``section 112(b)(1)(A)'' to ``section 112(b)''). 
See S. 1630, as reported, 101st Cong. Sec.  305, 1990 CAA Legis. Hist. 
at 8153; S. 1630, as passed, Sec.  305 (Apr. 3, 1990), 1990 CAA Legis. 
Hist. at 4534. Though the EPA is not aware of any statements in the 
legislative history that expressly explain the Senate's intent in 
making these changes to the Senate bill, the sequence itself supports 
the conclusion that the Senate's substitution reflects a decision to 
retain the pre-1990 approach of using a cross-reference to 112(b) to 
define the scope of the Section 112 Exclusion. Whether the difference 
in approach between the final Senate amendment in S.1630 and the House 
amendment in H.R. 3030 creates a substantive difference or are simply 
two different means of achieving the same end depends on what 
interpretation one gives to the text in the House amendment, which we 
turn to next.
4. The House Amendment
    a. The House amendment is ambiguous. Before looking at the specific 
text of the House amendment, it is helpful to review some principles of 
statutory interpretation. First, statutory interpretation begins with 
the text, but does not end there. As the D.C. Circuit Court has 
explained, ``[t]he literal language of a provision taken out of context 
cannot provide conclusive proof of congressional intent.'' Bell 
Atlantic Telephone Cos. v. F.C.C., 131 F.3d 1044, 1047 (D.C. Cir. 
1977). See King v. Burwell, 2015 U.S. LEXIS 4248, *19(``[O]ftentimes 
the `meaning--or ambiguity--of certain words or phrases may only become 
evident when placed in context.' Brown & Williamson, 529 U. S., at 132, 
120 S. Ct. 1291, 146 L. Ed. 2d 121. So when deciding whether the 
language is plain, we must read the words `in their context and with a 
view to their place in the overall statutory scheme.' Id., at 133, 120 
S. Ct. 1291, 146 L. Ed. 2d 121 (internal quotation marks omitted). Our 
duty, after all, is `to construe statutes, not isolated provisions.' 
Graham County Soil and

[[Page 64713]]

Water Conservation Dist. v. United States ex rel. Wilson, 559 U. S. 
280, 290, 130 S. Ct. 1396, 176 L. Ed. 2d 225 (2010) (internal quotation 
marks omitted).''). In addition, statutes should not be given a 
``hyperliteral'' reading that is contrary to established canons of 
statutory construction and common sense. See RadLAX Gateway Hotel v. 
Amalgamated Bank, 132 S.Ct. 2065, 2070-71 (2012).
    Further, a proper reading of statutory text ``must employ all the 
tools of statutory interpretation, including text, structure, purpose, 
and legislative history.'' Loving v. I.R.S., 742 F.3d 1013, 1016 (D.C. 
Cir. 2014) (internal quotation omitted). See, also, Robinson v. Shell 
Oil Co., 519 U.S. 337, 341 (1997) (statutory interpretation involves 
consideration of ``the language itself, the specific context in which 
that language is used, and the broader context of the statute as a 
whole.''). Moreover, one principle of statutory construction that has 
particular application here is that provisions in a statute should be 
read to be consistent, rather than conflicting, if possible. This 
principle was discussed in the recent case of Scialabba v. Cuellar De 
Osorio, 134 S. Ct. 2191, 2214 (concurring opinion by Chief Justice 
Roberts and Justice Scalia), 2219-2220 (dissent by Justices Sotomayor, 
Breyer and Thomas)(2014). As Justice Sotomayor wrote (at 134 S. Ct. at 
2220):

    ``We do not lightly presume that Congress has legislated in 
self-contradicting terms. See A. Scalia & B. Garner, Reading Law: 
The Interpretation of Legal Texts 180 (2012) (``The provisions of a 
text should be interpreted in a way that renders them compatible, 
not contradictory. . . . [T]here can be no justification for 
needlessly rendering provisions in conflict if they can be 
interpreted harmoniously''). . . . Thus, time and again we have 
stressed our duty to ``fit, if possible, all parts [of a statute] 
into [a] harmonious whole.'' FTC v. Mandel Brothers, Inc., 359 U.S. 
385, 389, 79 S. Ct. 818, 3 L. Ed. 2d 893 (1959); see also Morton v. 
Mancari, 417 U.S. 535, 551, 94 S. Ct. 2474, 41 L. Ed. 2d 290 (1974) 
(when two provisions ``are capable of co-existence, it is the duty 
of the courts . . . to regard each as effective''). In reviewing an 
agency's construction of a statute, courts ``must,'' we have 
emphasized, ``interpret the statute `as a . . . coherent regulatory 
scheme' '' rather than an internally inconsistent muddle, at war 
with itself and defective from the day it was written. Brown & 
Williamson, 529 U.S., at 133, 120 S. Ct. 1291, 146 L. Ed. 2d 121.

    As amended by the House, CAA section 111(d)(1)(A)(i) limits CAA 
section 111(d) to any air pollutant ``for which air quality criteria 
have not been issued or which is not included on a list published under 
section 7408(a) of this title or emitted from a source category which 
is regulated under section 7412 of this title . . .'' This statutory 
text is ambiguous and subject to numerous possible readings.
    First, the text of the House-amended version of CAA section 111(d) 
could be read literally as authorizing the regulation of any pollutant 
that is not a criteria pollutant. This reading arises if one focuses on 
the use of ``or'' to join the three clauses:

    The Administrator shall prescribe regulations . . . under which 
each State shall submit to the Administrator a plan which 
establishes standards of performance for any existing source for any 
air pollutant [1] for which air quality criteria have not been 
issued or [2] which is not included on a list published under 
section 7408(a) of this title or [3] emitted from a source category 
which is regulated under section 7412 of this title. . . .

    42 U.S.C. 7411(d)(1) (emphasis and internal numbering added). 
Because the text contains the conjunction ``or'' rather than ``and'' 
between the three clauses, a literal reading could read the three 
clauses as alternatives, rather than requirements to be imposed 
simultaneously. In other words, a literal reading of the language of 
section 111(d) provides that the Administrator may require states to 
establish standards for an air pollutant so long as either air quality 
criteria have not been established for that pollutant, or one of the 
remaining criteria is met. If this reading were applied to determine 
whether the EPA may promulgate CAA section 111(d) regulations for 
CO2 from power plants, the result would be that 
CO2 from power plants could be regulated under CAA section 
111(b) because air quality criteria have not been issued for 
CO2 and therefore whether CO2 or power plants are 
regulated under CAA section 112 would be irrelevant. This reading, 
however, is not a reasonable reading of the statute because, among 
other reasons, it gives little or no meaning to the limitation covering 
HAP that are regulated under CAA section 112 and thus is contrary to 
both the CAA's comprehensive scheme created by the three sets of 
provisions (under which CAA section 111 is not intended to duplicate 
the regulation of pollutants regulated under section 112) and the 
principle of statutory construction that text should not be construed 
such that a provision does not have effect.
    A second reading of CAA section 111(d) as revised by the House 
amendment focuses on the lack of a negative before the third clause. 
That is, unlike the first and second clauses that each contain negative 
phrases (either ``has not been issued'' or ``which is not included''), 
the third clause does not. One could presume that the negative from the 
second clause was intended to carry over, implicitly inserting another 
``which is not'' before ``emitted from a source category which is 
regulated under section [112].'' But that is a presumption, and not the 
plain language of the statute. The text as amended by the House says 
that the EPA ``shall'' prescribe regulations for ``any air pollutant . 
. . emitted from a source category which is regulated under section 
[112].'' 42 U.S.C. 7411(d)(1). Thus, CAA section 111(d)(1)(A)(i) could 
be read as providing for the regulation of emissions of pollutants if 
they are emitted from a source category that is regulated under CAA 
section 112. Like the first reading discussed above, this reading would 
authorize the regulation of CO2 emissions from existing 
power plants under CAA section 111(d). But, this second reading is not 
reasonable because it would provide for the regulation of a source's 
HAP emissions under CAA section 111(d) when those same emissions were 
also subject to standards under CAA section 112. Thus, this reading 
would be contrary to Congress's intent that CAA section 111(d) 
regulation fill the gap between the other programs by covering 
pollutants that the other programs do not, but not duplicate the 
regulation of pollutants that the other programs cover.
    If one does presume that the ``which is not'' phrase is intended to 
carry over to the third clause, then CAA section 111(d) regulation 
under the House amendment would be limited to ``any air pollutant . . . 
which is not . . . emitted from a source category which is regulated 
under section [112].'' Even with this presumption, however, the House 
amendment contains further ambiguities with respect to the phrases ``a 
source category'' and ``regulated under section 112,'' and how those 
phrases are used within the structure of the provision limiting what 
air pollutants may be regulated under CAA section 111(d).
    The phrase ``regulated under section 112'' is ambiguous. As the 
Supreme Court has explained in the context of other statutes using a 
variation of the word ``regulate,'' an agency must consider what is 
being regulated. See Rush Prudential HMO, Inc. v. Moran, 536 U.S. 355, 
366 (2002) (It is necessary to ``pars[e] . . . the `what' '' of the 
term ``regulates.''); UNUM Life Ins. Co. of Am. v. Ward, 526 U.S. 358, 
363 (1999) (the term `` `regulates insurance' . . . requires 
interpretation, for [its] meaning is not plain.''). Here, one possible 
reading is that the phase modifies the words ``a source category'' 
without

[[Page 64714]]

regard to what pollutants are regulated under section 112, which then 
presents the issue of what meaning to give to the phrase ``a source 
category.''
    Under this reading, and assuming the phrase ``a source category'' 
is read to mean the particular source category, the House amendment 
would preclude the regulation under CAA section 111(d) of a specific 
source category for any pollutant if that source category has been 
regulated for any HAP under CAA section 112.\290\ The effect of this 
reading would be to preclude the regulation of CO2 from 
power plants under CAA section 111(d) because power plants have been 
regulated for HAP under CAA section 112. This is the interpretation 
that the EPA applied to the House amendment in connection with the CAMR 
rule in 2005, when looking at the question of whether HAP can be 
regulated under CAA section 111(d) for a source category that is not 
regulated for HAP under section 112, and some commenters have advocated 
for this interpretation here. But, after considering all of the 
comments and reconsidering this interpretation, the EPA has concluded 
that this interpretation of the House amendment is not a reasonable 
reading because it would disrupt the comprehensive scheme for 
regulating existing sources created by the three sets of provisions 
covering criteria pollutants, HAP and the other pollutants that fall 
outside of those two programs and frustrate the role that section 111 
is intended to play.\291\ Specifically, under this interpretation, the 
EPA could not regulate a source category's emissions of HAP under CAA 
section 112, and then promulgate regulations for other pollutants from 
that source category under CAA section 111(d).\292\ There is no reason 
to conclude that the House amendment was intended to abandon the 
existing structure and relationship between the three programs in this 
way. Indeed, Congress expressly provided that regulation under CAA 
section 112 was not to ``diminish or replace the requirements of'' the 
EPA's regulation of non-hazardous pollutants under section 7411. See 42 
U.S.C. 7412(d)(7). Further, consistent with CAA section 112's direction 
that EPA list ``all categories and subcategories of major sources and 
area [aka, non-major] sources'' of HAP and then establish CAA section 
112 standards for those categories and subcategories, 42 U.S.C. 
7412(c)(1) and (c)(2), the EPA has listed and regulated over 140 
categories of sources under CAA section 112. Thus, this reading would 
eviscerate the EPA's authority under section 111(d) and prevent it from 
serving as the gap-filling provision within the comprehensive scheme of 
the CAA as Congress intended.\293\ In short, it is not reasonable to 
interpret the Section 112 Exclusion in section 111(d) to mean that the 
existence of CAA section 112 standards covering hazardous pollutants 
from a source category would entirely eliminate regulation of non-
hazardous emissions from that source category under section 
111(d).\294\
---------------------------------------------------------------------------

    \290\ ``A source category'' could also be interpreted to mean 
``any source category.'' Under this interpretation, CAA 111(d) 
regulation would be limited to air pollutants that are not emitted 
by any source category for which the EPA has issued standards for 
HAP under CAA section 112. This interpretation is not reasonable 
because it would effectively read CAA 111(d) out of the statute. 
Given the extensive list of source categories regulated under CAA 
112 and the breadth of pollutants emitted by those categories 
collectively, literally all air pollutants would be barred from CAA 
111(d) regulation under this interpretation.
    \291\ In assessing any interpretation of section 111(d), EPA 
must consider how the three main programs set forth in the CAA work 
together. See UARG, 134 S. Ct. at 2442 (a ``reasonable statutory 
interpretation must account for . . . the broader context of the 
statute as a whole'') (quotation omitted).
    \292\ Supporters of this interpretation have noted that the EPA 
could regulate power plants under both CAA section 111(d) and CAA 
section 112 if it regulated under section 111(d) first, before the 
Section 112 Exclusion is triggered. But that argument actually 
further demonstrates another reason why this interpretation is 
unreasonable. There is no basis for concluding that Congress 
intended to mandate that section 111(d) regulation occur first, nor 
is there any logical reason why the need to regulate under section 
111(d) should be dependent on the timing of such regulation in 
relation to CAA 112 regulation of that source category.
    \293\ Some commenters have stated that EPA could choose to 
regulate both HAP and non-HAP under section 111(d), and thus could 
regulate HAP without creating a gap. But this presumes that Congress 
intended EPA to have the choice of declining to regulate a section 
112-listed source category for HAP under section 112, which is 
inconsistent with the mandatory language in section 112. See, e.g., 
section 112(d)(1)(``The Administrator shall promulgate regulations 
establishing emissions standards for each category or subcategory of 
major sources and area sources of hazardous air pollutants listed 
for regulation pursuant to subsection (c) of this section in 
accordance with the schedules provided in subsections (c) and (e) of 
this section.''). Moreover, given the prescriptive language that 
Congress added into section 112 concerning how to set standards for 
HAP, see section 112(d)(2) and (d)(3), it is unreasonable to 
conclude that Congress intended that the EPA could simply choose to 
ignore the provisions in section 112 and instead regulate HAP for a 
section 112 listed source category under section 111(d).
    Further, some supporters of this interpretation have suggested 
that EPA could regulate CO2 under section 112. But this 
suggestion fails to consider that sources emitting HAP are major 
sources if they emit 10 tons of any HAP. See CAA section 112(a)(1). 
Thus, if CO2 were regulated as a HAP, and because 
emissions of CO2 tend to be many times greater than 
emissions of other pollutants, a huge number of smaller sources 
would become regulated for the first time under the CAA.
    \294\ Even if one were to determine that this interpretation 
were the proper reading of the House amendment that would not be the 
end of the analysis. Instead, that reading would create a conflict 
between the Senate amendment and the House amendment that would need 
to be resolved. In that event, the proper resolution of a conflict 
between the two amendments would be the analysis and conclusion 
discussed in the Proposed Rule's legal memorandum (discussing EPA's 
analysis in the CAMR rule at 70 FR 15994, 16029-32): The two 
amendments must be read together so as to give some effect to each 
amendment and they are properly read together to provide that, where 
a source category is regulated under section 112, the EPA may not 
establish regulations covering the HAP emissions from that source 
category under section 111(d).
---------------------------------------------------------------------------

    b. The EPA's Interpretation of the House Amendment. Having 
concluded that the interpretations discussed above are not reasonable, 
the EPA now turns to what it has concluded is the best, and sole 
reasonable, interpretation of the House amendment as it applies to the 
issue here.
    The EPA's interpretation of the House amendment as applied to the 
issue presented in this rule is that the Section 112 Exclusion excludes 
the regulation of HAP under CAA section 112 if the source category at 
issue is regulated under CAA section 112, but does not exclude the 
regulation of other pollutants, regardless of whether that source 
category is subject to CAA section 112 standards. This interpretation 
reads the phrase ``regulated under section 112'' as modifying the words 
``source category'' (as does the interpretation discussed above) but 
also recognizes that the phrase ``regulated under section 112'' refers 
only to the regulation of HAP emissions. In other words, the EPA's 
interpretation recognizes that source categories ``regulated under 
section 112'' are not regulated by CAA section 112 with respect to all 
pollutants, but only with respect to HAP. Thus, it is reasonable to 
interpret the House amendment of the Section 112 Exclusion as only 
excluding the regulation of HAP emissions under CAA section 111(d) and 
only when that source category is regulated under CAA section 112. We 
note that this interpretation of the House amendment alone is the same 
as the 2005 CAMR interpretation of the two amendments combined: Where a 
source category has been regulated under CAA section 112, a CAA section 
111(d) standard of performance cannot be established to address any HAP 
listed under CAA section 112(b) that may be emitted from that 
particular source category. See 70 FR 15994, 16029-30 (March 29, 2005).

[[Page 64715]]

    There are a number of reasons why the EPA's interpretation is 
reasonable and avoids the issues discussed above.
    First, the EPA's interpretation reads the House amendment to the 
Section 112 Exclusion as determining the scope of what air pollutants 
are to be regulated under CAA section 111(d), as opposed to creating a 
wholesale exclusion for source categories. The other text in 
subsections 111(d)(1)(A)(i) and (ii) modify the phrase ``any air 
pollutant.'' Thus, reading the Section 112 Exclusion to also address 
the question of what air pollutants may be regulated under CAA section 
111(d) is consistent with the overall structure and focus of CAA 
section 111(d)(1)(A).
    Second, the EPA's interpretation furthers--rather than undermines--
the purpose of CAA section 111(d) within the long-standing structure of 
the CAA. That is, this interpretation supports the comprehensive 
structure for regulating various pollutants from existing sources under 
the criteria pollutant/NAAQS program under sections 108-110, the HAP 
program under section 112, and other pollutants under section 111(d), 
and avoids creating a gap in that structure. See King v. Burwell, 2015 
U.S. LEXIS 4248, *28 (2015)(``A provision that may seem ambiguous in 
isolation is often clarified by the remainder of the statutory scheme . 
. . because only one of the permissible meanings produces a substantive 
effect that is compatible with the rest of the law.'') (quoting United 
Sav. Assn. of Tex. v. Timbers of Inwood Forest Associates, Ltd., 484 U. 
S. 365, 371, 108 S. Ct. 626, 98 L. Ed. 2d 740 (1988)'')
    Third, by avoiding the creation of gaps in the statutory structure, 
the EPA's interpretation is consistent with the legislative history 
demonstrating that Congress's intent in the 1990 CAA Amendments was to 
expand the EPA's regulatory authority across the board, compelling the 
agency to regulate more pollutants, under more programs, more 
quickly.\295\ Conversely, the EPA is aware of no statement in the 
legislative history indicating that Congress simultaneously sought to 
restrict the EPA's authority under CAA section 111(d) or to create gaps 
in the comprehensive structure of the statute. If Congress had intended 
this amendment to make such a change, one would expect to see some 
indication of that in the legislative history.
---------------------------------------------------------------------------

    \295\ See S. Rep. No. 101-228 at 133 (``There is now a broad 
consensus that the program to regulate hazardous air pollutants . . 
. should be restructured to provide the EPA with authority to 
regulate industrial and area sources of air pollution . . . in the 
near term''), reprinted in 5 A Legislative History of the Clean Air 
Act Amendments of 1990 (``Legis. Hist.'') 8338, 8473 (Comm. Print 
1993); S. Rep. No. 101-228 at 14 (``The bill gives significant 
authority to the Administrator in order to overcome the deficiencies 
in [the NAAQS program]'') & 123 (``Experience with the mobile source 
provisions in Title II of the Act has shown that the enforcement 
authorities . . . need to be strengthened and broadened . . .''), 
reprinted in 5 Legis. Hist. at 8354, 8463; H.R. Rep. No. 101-952 at 
336-36, 340, 345 & 347 (discussing enhancements to Act's motor 
vehicle provisions, the EPA's new authority to promulgate chemical 
accident prevention regulations, the enactment of the Title V permit 
program, and enhancements to the EPA's enforcement authority), 
reprinted in 5 Legis. Hist. at 1786, 1790, 1795, & 1997.
---------------------------------------------------------------------------

    Fourth, when applied in the context of this rule, the EPA's 
interpretation of the House amendment is consistent with the Senate 
amendment. Thus, this interpretation avoids creating a conflict within 
the statute. See discussion above of Scialabba v. Cuellar De Osorio, 
134 S. Ct. 2191 at 2220 (citing and quoting, among other authorities, 
A. Scalia & B. Garner, Reading Law: The Interpretation of Legal Texts 
180 (2012) (``The provisions of a text should be interpreted in a way 
that renders them compatible, not contradictory. . . . [T]here can be 
no justification for needlessly rendering provisions in conflict if 
they can be interpreted harmoniously'')).
    In sum, when this interpretation of the House amendment is applied 
in the context of this rule, the result is that the EPA may promulgate 
CAA section 111(d) regulations covering carbon dioxide emissions from 
existing power plants notwithstanding that power plants are regulated 
for their HAP emissions under CAA section 112.
5. The Two Amendments Are Easily Reconciled and Can Be Given Full 
Effect
    Given that both the House and Senate amendments should be read 
individually as having the same meaning in the context presented in 
this rule, giving each amendment full effect is straight-forward: The 
Section 112 Exclusion in section 111(d) does not foreclose the 
regulation of non-HAP from a source category regardless of whether that 
source category is also regulated under CAA section 112. As applied 
here, the EPA has the authority to promulgate CAA section 111(d) 
regulations for CO2 from power plants notwithstanding that 
power plants are regulated for HAP under CAA section 112.

C. Authority To Regulate EGUs

    In a separate, concurrent action, the EPA is also finalizing a CAA 
section 111(b) rulemaking that regulates CO2 emissions from 
new, modified, and reconstructed EGUs. The promulgation of these 
standards provides 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 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 standards for sources that undertake new construction, 
modifications, or reconstructions.
    The EPA is finalizing a rulemaking under CAA section 111(b) for 
CO2 emissions from affected EGUs concurrently with this CAA 
section 111(d) rulemaking, which will provide the requisite predicate 
for applicability of CAA section 111(d).\296\
---------------------------------------------------------------------------

    \296\ 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).
---------------------------------------------------------------------------

D. Definition of Affected Sources

    For the emission guidelines, an affected EGU is any fossil fuel-
fired electric utility steam generating unit (i.e., utility boiler or 
integrated gasification combined cycle (IGCC) unit) or stationary 
combustion turbine that was in operation or had commenced

[[Page 64716]]

construction as of January 8, 2014,\297\ and that meets the following 
criteria, which differ depending on the type of unit. To be an affected 
EGU, such a unit, if it is a fossil fuel-fired electric utility steam 
generating unit (i.e., a utility boiler or IGCC unit), must serve a 
generator capable of selling greater than 25 MW to a utility power 
distribution system and have a base load rating greater than 260 GJ/h 
(250 MMBtu/h) heat input of fossil fuel (either alone or in combination 
with any other fuel). If such a unit is a stationary combustion 
turbine, the unit must meet the definition of a combined cycle or 
combined heat and power combustion turbine, serve a generator capable 
of selling greater than 25 MW to a utility power distribution system, 
and have a base load rating of greater than 260 GJ/h (250 MMBtu/h).
---------------------------------------------------------------------------

    \297\ Under Section 111(a) of the CAA, determination of affected 
sources is based on the date that the EPA proposes action on such 
sources. January 8, 2014 is the date the proposed GHG standards of 
performance for new fossil fuel-fired EGUs were published in the 
Federal Register (79 FR 1430).
---------------------------------------------------------------------------

    When considering and understanding applicability, the following 
definitions may be helpful. Simple cycle combustion turbine means any 
stationary combustion turbine which does not recover heat from the 
combustion turbine engine exhaust gases for purposes other than 
enhancing the performance of the stationary combustion turbine itself. 
Combined cycle combustion turbine means any stationary combustion 
turbine which recovers heat from the combustion turbine engine exhaust 
gases to generate steam that is used to create additional electric 
power output in a steam turbine. Combined heat and power (CHP) 
combustion turbine means any stationary combustion turbine which 
recovers heat from the combustion turbine engine exhaust gases to heat 
water or another medium, generate steam for useful purposes other than 
exclusively for additional electric generation, or directly uses the 
heat in the exhaust gases for a useful purpose.
    We note that certain affected EGUs are exempt from inclusion in a 
state plan. Affected EGUs that may be excluded from a state's plan are 
(1) those units that are subject to subpart TTTT as a result of 
commencing modification or reconstruction; (2) steam generating units 
or IGCC units that are currently and always have been subject to a 
federally enforceable permit limiting net-electric sales to one-third 
or less of its potential electric output or 219,000 MWh or less on an 
annual basis; (3) non-fossil units (i.e., units that are capable of 
combusting 50 percent or more non-fossil fuel) that have historically 
limited the use of fossil fuels to 10 percent or less of the annual 
capacity factor or are subject to a federally enforceable permit 
limiting fossil fuel use to 10 percent or less of the annual capacity 
factor; (4) stationary combustion turbines that are not capable of 
combusting natural gas (i.e., not connected to a natural gas pipeline); 
(5) combined heat and power units that are subject to a federally 
enforceable permit limiting, or have historically limited, annual net 
electric sales to a utility power distribution system to the product of 
the design efficiency and the potential electric output or 219,000 MWh 
(whichever is greater) or less; (6) units that serve a generator along 
with other steam generating unit(s), IGCC(s), or stationary combustion 
turbine(s) where the effective generation capacity (determined based on 
a prorated output of the base load rating of each steam generating 
unit, IGCC, or stationary combustion turbine) is 25 MW or less; (7) 
municipal waste combustor unit subject to subpart Eb of Part 60; or (8) 
commercial or industrial solid waste incineration units that are 
subject to subpart CCCC of Part 60.
    The rationale for applicability of this final rule is multi-fold. 
We had proposed that affected EGUs were those existing fossil fuel-
fired EGUs that met the applicability criteria for coverage under the 
final GHG standards for new fossil fuel-fired EGUs being promulgated 
under section 111(b). However, we are finalizing that States need not 
include certain units that would otherwise meet the CAA section 111(b) 
applicability in this CAA section 111(d) emission guidelines. These 
include simple cycle turbines, certain non-fossil units, and certain 
combined heat and power units. The final 111(b) standards include 
applicability criteria for simple cycle combustion turbines, for 
reasons relating to implementation and minimizing emissions from all 
future combustion turbines. However, for the following reasons none of 
the building blocks would result in emission reductions from simple 
cycle turbines so we are not requiring that States including them in 
their CAA section 111(d) plans.
    First, even more than combined cycle units, simple cycle units have 
limited opportunities, compared to steam generating units, to reduce 
their heat rate. Most combustion turbines likely already follow the 
manufacturer's recommended regular preventive/restorative maintenance 
for both reliable and efficiency reasons. These regularly scheduled 
maintenance practices are highly effective methods to maintain heat 
rates, and additional fleet-wide reductions from simple cycle 
combustion turbines are likely less than 2 percent. In addition, while 
approximately one-fifth of overall fossil fuel-fired capacity (GW) 
consists of simple cycle turbines, these units historically have 
operated at capacity factors of less than 5 percent and only provide 
about 1 percent of the fossil fuel-fired generation (GWh). Combustion 
turbine capacity can therefore only contribute CO2 emissions 
amounting to approximately 2 percent of total coal-steam CO2 
emissions. Any single-digit percentage reduction in combustion turbine 
heat rates would therefore provide less than 1 percent reduction in 
total fossil-fired CO2 emissions.
    Further, we are not aware of an approach to estimate any limited 
opportunities that existing simple cycle turbines may have to reduce 
their heat rate. Similar to coal-steam EGUs, we do not have the unit-
specific detailed design information on existing individual simple 
cycle combustion turbines that is necessary for a detailed assessment 
of the heat rate improvement potential via best practices and upgrades 
for each unit. While the EPA could conduct a ``variability analysis'' 
of simple cycle historical hourly heat rate data (as was done for coal-
steam EGUs), the various simple cycle models in use and the 
historically lower capacity factors of the simple cycle fleet (less run 
time per start, and more part load operation) would require a simple 
cycle analysis that includes more complexity and likely more 
uncertainty than in the coal-steam analysis. Therefore, we do not 
consider it feasible to estimate potential reductions due to heat rate 
improvements from simple cycle turbines, and even if it were, we have 
concluded those reductions would be negligible compared to the 
reductions from steam generating units. Hence, we do not consider 
building block 1 as practically applicable to simple cycle units.
    Second, the vast majority of simple cycle turbines serve a specific 
need--providing power during periods of peak electric demand (i.e., 
peaking units). The existing block of simple cycle turbines are the 
only units that are able to start fast enough and ramp to full load 
quickly enough to serve as peaking units. If these units were to be 
used under building block 2 to displace higher emitting coal-fired 
units, they would no longer be available to serve as peaking units. 
Therefore, building block 2 could not be applied to simple cycle

[[Page 64717]]

combustion turbines without jeopardizing grid reliability.
    Third, many commenters on the CAA section 111(b) proposal stated 
that simple cycle turbines will be used to provide backup power to 
intermittent renewable sources of power such as wind and solar. 
Consequently, adding additional generation from intermittent renewable 
sources has the potential to actually increase emissions from simple 
cycle turbines. Therefore, applying building block 3 based on the 
capacity of simple cycle turbines would not result in emission 
reductions from simple cycle combustion turbines. Finally, the EPA 
expects existing simple cycle turbines to continue to operate as they 
historically have operated, as peaking units. Including simple cycle 
turbines in CAA section 111(d) applicability would impact the numerical 
value of state goals, but it would not impact the stringency of the 
plans. Such inclusion would increase burden but result in no 
environmental benefit.
    Additionally, under CAA section 111(b) final applicability 
criteria, new dedicated non-fossil and industrial CHP units are not 
affected sources if they include permit restrictions on the amount of 
fossil fuel they burn and the amount of electricity they sell. Such 
units historically have had no regulatory mandate to include permit 
requirements limiting the use of fossil fuel or electric sales. We are 
exempting them from inclusion in CAA section 111(d) state plans in the 
interest of consistency with CAA section 111(b) and based on their 
historical fuel use and electric sales.
    We discuss changes in applicability of units in relation to state 
plans in Section VIII of this preamble.

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

    In this rulemaking, the EPA is combining the listing of sources 
from the two existing source categories for the affected EGUs, as 
listed in 40 CFR subpart Da and 40 CFR subpart KKKK, into a single 
location, 40 CFR subpart UUUU, for purposes of addressing the 
CO2 emissions from existing affected EGUs. The EPA is also 
codifying all of the requirements for the affected EGUs in a new 
subpart UUUU of 40 CFR part 60 and including all GHG emission 
guidelines for the affected sources--fossil fuel-fired electric utility 
steam generating units, as well as stationary combustion turbines--in 
that newly created subpart.\298\
---------------------------------------------------------------------------

    \298\ The EPA is not codifying any of the requirements of this 
rulemaking in subparts Da or KKKK.
---------------------------------------------------------------------------

    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. 
Combining the listing of sources into one location, subpart UUUU, will 
facilitate implementation of CO2 mitigation measures, such 
as shifting generation from higher to lower-carbon intensity generation 
among existing sources (e.g., shifting from utility boilers to NGCC 
units), and emission trading among sources in the source category.
    As discussed in the January 8, 2014 proposal for the CAA section 
111(b) standards for GHG emissions from EGUs (79 FR 1430), 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 January 8, 2014 proposal, the EPA proposed separate 
standards of performance for new 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. For the final standards of performance for new construction of 
affected EGUs, the EPA is codifying the final requirements in a new 40 
CFR part 60 subpart TTTT.
    In this rulemaking, the EPA is combining the two listed source 
categories into a single source category for purposes of the emission 
guidelines for the CO2 emissions from existing affected 
EGUs. Because the two source categories are pre-existing and the EPA 
would not be subjecting any additional sources to regulation, the 
combined source category is not considered a new source category that 
the EPA must list under CAA section 111(b)(1)(A). As a result, this 
final rule does not list a new source category under section 
111(a)(1)(A), nor does this final rule revise either of the two source 
categories--fossil fuel--fired electric utility steam generating units 
and stationary combustion turbines--that the EPA has already listed 
under that provision. Thus, the EPA is not required to make a finding 
that the combined source category causes or contributes significantly 
to air pollution which may reasonably be anticipated to endanger public 
health or welfare.

V. The Best System of Emission Reduction and Associated Building Blocks

    In the June 2014 proposal, the EPA proposed to determine that the 
best system of emission reduction adequately demonstrated (BSER) for 
reducing CO2 emissions from existing EGUs was a combination 
of measures--(1) increasing the operational efficiency of existing 
coal-fired steam EGUs, (2) substituting increased generation at 
existing NGCC units for generation at existing steam EGUs, (3) 
substituting generation from low- and zero-carbon generating capacity 
for generation at existing fossil fuel-fired EGUs, and (4) increasing 
demand-side EE to reduce the amount of fossil fuel-fired generation--
which we categorized as four ``building blocks.'' As an alternative to 
the proposed building blocks 2, 3, and 4, the EPA also identified 
reduced generation in the amount of those building blocks as part of 
the BSER. These measures are not the only approaches EGUs can take to 
reduce CO2, but are those that the EPA felt best met the 
statutory criteria. We solicited comment on all aspects of our BSER 
determination, including a broad array of other approaches. We have 
considered thoroughly the extensive comments submitted on a variety of 
topics related to the BSER and the individual building blocks, along 
with our own continued analysis, and we are finalizing the BSER based 
on the first three building blocks, with certain refinements.
    Consistent with the approach taken in the proposed rule, in 
determining the BSER we have taken account of the unique 
characteristics of CO2 pollution, particularly its global 
nature, huge quantities, and the limited means for controlling it; and 
the unique characteristics of the source category, particularly the 
exceptional degree of interconnectedness among individual affected EGUs 
and the longstanding practice of coordinating planning and operations 
across multiple sources, reflecting the fact that each EGU's function 
is interdependent with the function of other EGUs. Each building

[[Page 64718]]

block is a proven approach for reducing emissions from the affected 
source category that is appropriate in this pollutant- and industry-
specific context. The BSER also encompasses a variety of measures or 
actions that individual affected EGUs could take to implement the 
building blocks, including (i) direct investment in efficiency 
improvements and in lower- and zero-carbon generation, (ii) cross-
investment in these activities through mechanisms such as emissions 
trading approaches, where the state-established standards of 
performance to which sources are subject incorporate such approaches, 
and (iii) reduction of higher-carbon generation.
    With attention to emission reduction costs, electricity rates, and 
the importance of ensuring continued reliability of electricity 
supplies, the individual building blocks and the overall BSER have been 
defined not at the maximum possible degree of stringency but at a 
reasonable degree of stringency designed to appropriately balance 
consideration of the various BSER factors. Additional, non-building 
block-specific aspects of the BSER quantification methodology discussed 
below are similarly mindful of these considerations. This approach to 
determination of the BSER provides compliance headroom that ensures 
that the emission limitations reflecting the BSER are achievable by the 
source category, but nevertheless, as required by the CAA, will result 
in meaningful reductions in CO2 emissions from this sector. 
The wide range of actions encompassed in the building blocks, and a 
further wide range of possible emissions-reducing actions not included 
in the BSER but nevertheless available to help with compliance, ensure 
that those emission limitations are achievable by individual affected 
EGUs as well.
    The final BSER incorporates certain changes from the proposed rule, 
reflecting the EPA's consideration of comments responding to the 
approaches outlined in the proposal and our own further analysis. The 
principal changes are the exclusion from the BSER of emission 
reductions achievable through demand-side EE and through nuclear 
generation; a revised approach to determination of emission reductions 
achievable through increased RE generation; a consistent approach to 
determination of emission reductions achievable through all the 
building blocks that better reflects the regional nature of the 
electricity system and entails separate analyses for the Eastern, 
Western, and Texas Interconnections; and a revised interim goal period 
of 2022 to 2029 (instead of the proposed interim period of 2020 to 
2029). These changes to the BSER and the building blocks are discussed 
in more detail later in this section of the preamble.
    Also, to address concerns identified in the proposal and the 
October 30, 2014 NODA and in response to associated comments, in the 
final rule we have represented the emission limitations achievable 
through the BSER in the form of uniform CO2 emission 
performance rates for each of two affected source subcategories: Steam 
generating units and stationary combustion turbines. However, like the 
proposed rule, the final rule also provides weighted-average state-
specific goals that a state may choose as an alternative method for 
complying with its obligation to set standards of performance for its 
affected EGUs--an alternative, that is, to adopting the nationwide 
subcategory-based CO2 emission performance rates as the 
standard of performance for its affected EGUs. The reformulation of the 
emission limitations as uniform CO2 emission performance 
rates is discussed in this section and in section VI of the preamble, 
and the relation of the performance rates to the state-specific goals 
and states' section 111(d) plan options is discussed in sections VII 
and VIII of the preamble.
    Section V.A. describes our determination of the final BSER, 
including a discussion of the associated emissions performance level, 
and provides the rationale for our determination. In section V.B. we 
address certain legal issues in greater detail, including key issues 
raised in comments. Sections V.C. through V.E. contain more detailed 
discussions of the three individual building blocks included in the 
final BSER. Further information can be found in the GHG Mitigation 
Measures TSD for the CPP Final Rule, the CO2 Emission 
Performance Rate and Goal Computation TSD for the CPP Final Rule, the 
Response to Comments document, and, about certain topics, the Legal 
Memorandum for the Clean Power Plan Final Rule, all of which are 
available in the docket.

A. The Best System of Emission Reduction

    This section sets forth our determination of the BSER for reducing 
CO2 emissions from existing EGUs, including a discussion of 
the associated emissions performance level, and the rationale for that 
determination. In section V.A.1., we describe the legal framework for 
determination of the BSER in general. Section V.A.2. summarizes the 
determination of the BSER for this rule. In section V.A.3., we discuss 
changes from the proposal. Section V.A.4. provides more detail on our 
determination of the BSER, including our determinations regarding the 
individual elements of the BSER, as applied to the two subcategories of 
fossil steam units and combustion turbines. In section V.A.5., we 
explain the specific actions that individual affected EGUs in the two 
subcategories may take to implement the building blocks and thereby 
achieve the EPA-identified source subcategory-specific emission 
performance rates that, in turn, form the basis for the standards of 
performance that states must set. Because these actions implement the 
building blocks, they may be understood as part of the BSER. In this 
discussion, we recognize that states can choose to set sources' 
standards of performance in different forms and that the form of the 
standard affects how various types of actions can be used to comply 
with the standard. In section V.A.6., we discuss the substantial 
compliance flexibility provided by additional measures, not included in 
the BSER, that individual affected EGUs can use to achieve their 
standards of performance. Finally, section V.A.7. addresses the 
severability of the building blocks.
1. Legal Requirements for BSER in the Emission Guidelines
    a. Introduction. In the June 2014 proposal for this rule, we 
described the principal legal requirements for standards of performance 
under CAA section 111(d)(1) and (a)(1). We based our description in 
part on our discussion of the legal requirements for standards of 
performance under CAA section 111(b) and (a)(1), which we included in 
the January 2014 proposal for standards of performance for 
CO2 emissions from new fossil fuel-fired EGUs. In the latter 
proposal, we noted that the D.C. Circuit has handed down numerous 
decisions that interpret CAA section 111(a)(1), including its component 
elements, and we reviewed that case law in detail.\299\
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    \299\ 79 FR 1430, 1462 (January 8, 2014).
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    We received comments on our proposed interpretation, and in light 
of those comments, in this final rule, we are clarifying our 
interpretation in certain respects. We discuss our interpretation 
below.\300\
---------------------------------------------------------------------------

    \300\ We also discuss our interpretation of the requirements for 
standards of performance and the BSER under section 111(b), for new 
sources, in the section 111(b) rulemaking that the EPA is finalizing 
simultaneously with this rule and in the Legal Memorandum for this 
rule. Our interpretations of these requirements in the two rules are 
generally consistent except to the extent that they reflect 
distinctions between new and existing sources. For example, as 
discussed in the section 111(b) rule, the legislative history 
indicates that Congress intended that the BSER for new industrial 
facilities, which were expected to have lengthy useful lives, would 
include the most advanced pollution controls available, but Congress 
had a broader conception of the BSER for existing facilities.

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[[Page 64719]]

    b. CAA requirements and court interpretation.\301\ Section 
111(d)(1) directs the EPA to promulgate regulations establishing a 
section 110-like procedure under which states submit state plans that 
establish ``standards of performance'' for emissions of certain air 
pollutants from sources which, if they were new sources, would be 
regulated under section 111(b), and that implement and enforce those 
standards of performance.
---------------------------------------------------------------------------

    \301\ Our interpretation of the CAA provisions at issue is 
guided by Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-43 (1984). 
In Chevron, the U.S. Supreme Court set out a two-step process for 
agency interpretation of statutory requirements: the agency must, at 
step 1, determine whether Congress's intent as to the specific 
matter at issue is clear, and, if so, the agency must give effect to 
that intent. If congressional intent is not clear, then, at step 2, 
the agency has discretion to fashion an interpretation that is a 
reasonable construction of the statute.\\
---------------------------------------------------------------------------

    The term ``standard of performance'' is defined to mean--

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.

Section 111(a)(1).
    These provisions authorize the EPA to determine the BSER for the 
affected sources and, based on the BSER, to establish emission 
guidelines that identify the minimum amount of emission limitation that 
a state, in its state plan, must impose on its sources through 
standards of performance. Consistent with these CAA requirements, the 
EPA's regulations require that the EPA's guidelines reflect--

the degree of emission reduction achievable through the application 
of the best system of emission reduction which (taking into account 
the cost of such reduction) the Administrator has determined has 
been adequately demonstrated.\302\
---------------------------------------------------------------------------

    \302\ 40 CFR 60.21(e). This definition was promulgated as part 
of the EPA's CAA 111(d) implementing regulations and was not updated 
to reflect the textual changes adopted by Congress in 1977. That 
said, Congress recognized that those changes ``merely make[] 
explicit what was implicit in the previous language.'' H.R. Rep. No. 
95-294, at 190 (May 12, 1977).

    The EPA's approach in this rulemaking is to determine the BSER on a 
source subcategory-wide basis, to determine the emission limitation 
that results from applying the BSER to the sources in the subcategory, 
and then to establish emission guidelines for the states that 
incorporate those emission limitations. The EPA expresses these 
emission limitations in the form of emission performance rates, and 
they must be achievable by the source subcategory through the 
application of the BSER.
    Following the EPA's promulgation of emission guidelines, each state 
must determine the standards of performance for its sources, which the 
EPA's regulations call ``designated facilities.'' \303\ A state has 
broad discretion in doing so. CAA section 111(d)(1) requires the EPA's 
regulations to ``permit the State in applying a standard of performance 
to any particular source . . . to take into consideration, among other 
factors, the remaining useful life of the . . . source. . .'' \304\ In 
addition, under CAA section 116, the state is authorized to set a 
standard of performance for any particular source that is more 
stringent than the emission limit contained in the EPA's emission 
guidelines.\305\ Thus, for any particular source, a state may apply a 
standard of performance that is either more stringent or less stringent 
than the performance level in the emission guidelines, as long as, in 
total, the state's sources achieve at least the same degree of emission 
limitation as included in the EPA's emission guidelines. The states 
must include the standards of performance in their state plans and 
submit the plans to the EPA for review.\306\ Under CAA section 
111(d)(2)(A), the EPA approves state plans as long as they are 
``satisfactory.''
---------------------------------------------------------------------------

    \303\ 40 CFR 60.24(b)(3).
    \304\ The EPA's regulations, promulgated prior to enactment of 
the ``remaining useful life'' provision of section 111(d)(1), 
provide: ``Unless otherwise specified in the applicable subpart on a 
case-by-case basis for particular designated facilities, or classes 
of facilities, States may provide for the application of less 
stringent emission standards or longer compliance schedules than 
those otherwise required'' by the corresponding emission guideline. 
40 CFR 60.24(f). Some of the factors that a state may consider for 
this case-by-case analysis include the ``cost of control resulting 
from plant age, location, or basic process design'' and the 
``physical impossibility of installing necessary control 
equipment,'' among other factors ``that make application of a less 
stringent standard or final compliance time significantly more 
reasonable.'' Id.
    \305\ In addition, CAA section 116 authorizes the state to set 
standards of performance for all of its sources that, together, are 
more stringent than the EPA's emission guidelines.
    \306\ 40 CFR 60.23.
---------------------------------------------------------------------------

    As noted in the January 2014 proposal and discussed in more detail 
above under section II.G, Congress first included the definition of 
``standard of performance'' when enacting CAA section 111 in the 1970 
Clean Air Act Amendments (CAAA), amended it in the 1977 CAAA, and then 
amended it again in the 1990 CAAA to largely restore the definition as 
it read in the 1970 CAAA. It is in the legislative history for the 1970 
and 1977 CAAA that Congress primarily addressed the definition as it 
read at those times and that legislative history provides guidance in 
interpreting this provision.\307\ In addition, although the D.C. 
Circuit has never reviewed a section 111(d) rulemaking, the Court has 
reviewed section 111(b) rulemakings on numerous occasions during the 
past 40 years, handing down decisions dated from 1973 to 2011,\308\ 
through which the Court has developed a body of case law that 
interprets the term ``standard of performance.''
---------------------------------------------------------------------------

    \307\ In the 1970 CAAA, Congress defined ``standard of 
performance,'' under Sec.  111(a)(1), as:
    a standard for emissions of air pollutants which reflects the 
degree of emission limitation achievable through the application of 
the best system of emission reduction which (taking into account the 
cost of achieving such reduction) the Administrator determines has 
been adequately demonstrated.
    In the 1977 CAAA, Congress revised the definition to distinguish 
among different types of sources, and to require that for fossil 
fuel-fired sources, the standard (i) be based on, in lieu of the 
``best system of emission reduction . . . adequately demonstrated,'' 
the ``best technological system of continuous emission reduction . . 
. adequately demonstrated;'' and (ii) require a percentage reduction 
in emissions. In addition, in the 1977 CAAA, Congress expanded the 
parenthetical requirement that the Administrator consider the cost 
of achieving the reduction to also require the Administrator to 
consider ``any nonair quality health and environmental impact and 
energy requirements.''
    In the 1990 CAAA, Congress again revised the definition, this 
time repealing the requirements that the standard of performance be 
based on the best technological system and achieve a percentage 
reduction in emissions, and replacing those provisions with the 
terms used in the 1970 CAAA version of Sec.  111(a)(1) that the 
standard of performance be based on the ``best system of emission 
reduction . . . adequately demonstrated.'' This 1990 CAAA version is 
the current definition, which is applicable at present. Even so, 
because parts of the definition as it read under the 1977 CAAA were 
retained in the 1990 CAAA, the explanation in the 1977 CAAA 
legislative history, and the interpretation, in the case law, of 
those parts of the definition remain relevant to the definition as 
it reads today.
    \308\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. 
Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, (D.C. 
Cir. 1973); Portland Cement Ass'n v. EPA, 665 F.3d 177 (D.C. Cir. 
2011). See also Delaware v. EPA, No. 13-1093 (D.C. Cir. May 1, 
2015).
---------------------------------------------------------------------------

    c. Key elements of interpretation. The emission guidelines 
promulgated by the Administrator must include emission limitations that 
are ``achievable'' by the source category by application of a ``system 
of emission reduction'' that is ``adequately demonstrated'' and that 
the EPA determines to be the ``best,''

[[Page 64720]]

``taking into account'' the factors of ``cost . . . nonair quality 
health and environmental impact and energy requirements.'' The D.C. 
Circuit has stated that in determining the ``best'' system, the EPA 
must also take into account ``the amount of air pollution'' \309\ 
reduced and the role of ``technological innovation.'' \310\ The Court 
has emphasized that the EPA has discretion in weighing those various 
factors.311 312
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    \309\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 
1981).
    \310\ See Sierra Club v. Costle, 657 F.2d at 347.
    \311\ See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999).
    \312\ Although CAA section 111(a)(1) may be read to state that 
the factors enumerated in the parenthetical are part of the 
``adequately demonstrated'' determination, the D.C. Circuit's case 
law appears to treat them as part of the ``best'' determination. See 
Sierra Club v. Costle, 657 F.2d at 330 (recognizing that CAA section 
111 gives the EPA authority ``when determining the best 
technological system to weigh cost, energy, and environmental 
impacts''). Nevertheless, it does not appear that those two 
approaches would lead to different outcomes. See, e.g., Lignite 
Energy Council v. EPA, 198 F.3d at 933 (rejecting challenge to the 
EPA's cost assessment of the ``best demonstrated system''). In this 
rule, the EPA treats the factors as part of the ``best'' 
determination, but, as noted, even if the factors were part of the 
``adequately demonstrated'' determination, our analysis and outcome 
would be the same.
---------------------------------------------------------------------------

    Our overall approach to determining the BSER and emission 
guidelines, which incorporates the various elements, is as follows: In 
developing an emission guideline, we generally engage in an analytical 
approach that is similar to what we conduct under CAA section 111(b) 
for new sources. First, we identify ``system[s] of emission reduction'' 
that have been ``adequately demonstrated'' for a particular source 
category. Second, we determine the ``best'' of these systems after 
evaluating the amount of reductions, costs, any nonair health and 
environmental impacts, energy requirements, and, in the alternative, 
the advancement of technology (that is, we apply a formulation of the 
BSER with the above noted factors, and then, in the alternative, we 
apply a formulation of the BSER with those same factors plus the 
advancement of technology). And third, we select an achievable emission 
limit--here, the emission performance rates--based on the BSER.\313\ In 
contrast to subsection (b), however, subsection (d)(1) assigns to the 
states, not the EPA, the obligation of setting standards of performance 
for the affected sources. As discussed below in the following 
subsection, in examining the range of reasonable options for states to 
consider in setting standards of performance under these guidelines, we 
identified a number of considerations, including the interconnected 
operations of the affected sources and the characteristics of the 
CO2 pollutant.
---------------------------------------------------------------------------

    \313\ See, e.g., Oil and Natural Gas Sector: New Source 
Performance Standards and National Emission Standards for Hazardous 
Air pollutants Reviews, 77 FR 49490, 49494 (Aug. 16, 2012) 
(describing the three-step analysis in setting a standard of 
performance).
---------------------------------------------------------------------------

    The remainder of this subsection discusses the various elements in 
our general analytical approach.
(1) System of Emission Reduction
    As we discuss below, the CAA does not define the phrase ``system of 
emission reduction.'' The ordinary, everyday meaning of ``system'' is a 
set of things or parts forming a complex whole; a set of principles or 
procedures according to which something is done; an organized scheme or 
method; and a group of interacting, interrelated, or interdependent 
elements.\314\ With this definition, the phrase ``system of emission 
reduction'' takes a broad meaning: a set of measures that work together 
to reduce emissions. The EPA interprets this phrase to carry an 
important limitation: Because the emission guidelines for the existing 
sources must reflect ``the degree of emission limitation achievable 
through the application of the best system of emission reduction . . . 
adequately demonstrated,'' the system must be limited to measures that 
can be implemented--``appl[ied]''--by the sources themselves, that is, 
as a practical matter, by actions taken by the owners or operators of 
the sources. As we discuss below, this definition is sufficiently broad 
to include the building blocks.
---------------------------------------------------------------------------

    \314\ Oxford Dictionary of English (3rd ed.) (2010), available 
at http://www.oxforddictionaries.com/us/definition/american_english/system; see also American Heritage Dictionary (5th ed.) (2013), 
available at http://www.yourdictionary.com/system#americanheritage; 
and The American College Dictionary (C.L. Barnhart, ed. 1970) (``an 
assemblage or combination of things or parts forming a complex or 
unitary whole'').
---------------------------------------------------------------------------

(2) ``Adequately Demonstrated''
    Under section 111(a)(1), in order for a ``system of emission 
reduction'' to serve as the basis for an ``achievable'' emission 
limitation, the Administrator must determine that the system is 
``adequately demonstrated.'' This means, according to the D.C. Circuit, 
that the system is ``one which has been shown to be reasonably 
reliable, reasonably efficient, and which can reasonably be expected to 
serve the interests of pollution control without becoming exorbitantly 
costly in an economic or environmental way.'' \315\ It does not mean 
that the system ``must be in actual routine use somewhere.'' \316\ 
Rather, the Court has said, ``[t]he Administrator may make a projection 
based on existing technology, though that projection is subject to the 
restraints of reasonableness and cannot be based on `crystal ball' 
inquiry.'' \317\ Similarly, the EPA may ``hold the industry to a 
standard of improved design and operational advances, so long as there 
is substantial evidence that such improvements are feasible.'' \318\ 
Ultimately, the analysis ``is partially dependent on `lead time,''' 
that is, ``the time in which the technology will have to be 
available.'' \319\ Unlike for CAA section 111(b) standards that are 
applicable immediately after the effective date of their promulgation, 
under CAA section 111(e), compliance with CAA section 111(d) standards 
may be set sometime in the future. This is due, in part, to the period 
of time for states to submit state plans and for the EPA to act on 
them.
---------------------------------------------------------------------------

    \315\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. 
Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \316\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted) (discussing the Senate and 
House bills and reports from which the language in CAA section 111 
grew).
    \317\ Ibid.
    \318\ Sierra Club v. Costle, 657 F.2d 298, 364 (1981).
    \319\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted).
---------------------------------------------------------------------------

(3) ``Best''
    In determining which adequately demonstrated system of emission 
reduction is the ``best,'' the EPA considers the following factors:
(a) Costs
    Under CAA section 111(a)(1), the EPA is required to take into 
account ``the cost of achieving'' the required emission reductions. As 
described in the January 2014 proposal,\320\ in several cases the D.C. 
Circuit has elaborated on this cost factor and formulated the cost 
standard in various ways, stating that the EPA may not adopt a standard 
the cost of which would be ``exorbitant,'' \321\ ``greater than the 
industry could bear and survive,'' \322\ ``excessive,'' \323\ or 
``unreasonable.'' \324\ These formulations appear to be synonymous, and 
for convenience, in this rulemaking, we will use reasonableness as the 
standard,

[[Page 64721]]

so that a control technology may be considered the ``best system of 
emission reduction . . . adequately demonstrated'' if its costs are 
reasonable, but cannot be considered the best system if its costs are 
unreasonable.325 326
---------------------------------------------------------------------------

    \320\ 79 FR 1430, 1464 (January 8, 2014).
    \321\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999).
    \322\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 
1975).
    \323\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \324\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \325\ These cost formulations are consistent with the 
legislative history of section 111. The 1977 House Committee Report 
noted:
    In the [1970] Congress [sic: Congress's] view, it was only right 
that the costs of applying best practicable control technology be 
considered by the owner of a large new source of pollution as a 
normal and proper expense of doing business.
    1977 House Committee Report at 184. Similarly, the 1970 Senate 
Committee Report stated:
    The implicit consideration of economic factors in determining 
whether technology is ``available'' should not affect the usefulness 
of this section. The overriding purpose of this section would be to 
prevent new air pollution problems, and toward that end, maximum 
feasible control of new sources at the time of their construction is 
seen by the committee as the most effective and, in the long run, 
the least expensive approach.
    S. Comm. Rep. No. 91-1196 at 16.
    \326\ We received comments that we do not have authority to 
revise the cost standard as established in the case law, e.g., 
``exorbitant,'' ``excessive,'' etc., to a ``reasonableness'' 
standard that the commenters considered less protective of the 
environment. We agree that we do not have authority to revise the 
cost standard as established in the case law, and we are not 
attempting to do so here. Rather, our description of the cost 
standard as ``reasonableness'' is intended to be a convenient term 
for referring to the cost standard as established in the case law.
---------------------------------------------------------------------------

    The D.C. Circuit has repeatedly upheld the EPA's consideration of 
cost in reviewing standards of performance. In several cases, the Court 
upheld standards that entailed significant costs, consistent with 
Congress's view that ``the costs of applying best practicable control 
technology be considered by the owner of a large new source of 
pollution as a normal and proper expense of doing business.'' \327\ See 
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 
1973); \328\ Portland Cement Association v. Ruckelshaus, 486 F.2d 375, 
387-88 (D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. 
Cir. 1981) (upholding standard imposing controls on SO2 
emissions from coal-fired power plants when the ``cost of the new 
controls . . . is substantial'').\329\
---------------------------------------------------------------------------

    \327\ 1977 House Committee Report at 184.
    \328\ The costs for these standards were described in the 
rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769 
(March 21, 1972).
    \329\ Indeed, in upholding the EPA's consideration of costs 
under other provisions requiring consideration of cost, courts have 
also noted the substantial discretion delegated to the EPA to weigh 
cost considerations with other factors. Chemical Mfr's Ass'n v. EPA, 
870 F. 2d 177, 251 (5th Cir. 1989); Am. Iron & Steel Inst. v. EPA, 
526 F. 2d 1027, 1054 (3d Cir. 1975); Ass'n of Pacific Fisheries v. 
EPA, 615 F. 2d 794, 808 (9th Cir. 1980).
---------------------------------------------------------------------------

    As discussed below, the EPA may consider costs on both a source-
specific basis and a sector-wide, regional, or nationwide basis.
(b) Non-Air Health and Environmental Impacts
    Under CAA section 111(a)(1), the EPA is required to take into 
account ``any nonair quality health and environmental impact'' in 
determining the BSER. As the D.C. Circuit has explained, this 
requirement makes explicit that a system cannot be ``best'' if it does 
more harm than good due to cross-media environmental impacts.\330\
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    \330\ Portland Cement v. EPA, 486 F. 2d at 384; Sierra Club v. 
Costle, 657 F. 2d at 331; see also Essex Chemical Corp. v. 
Ruckelshaus, 486 F. 2d at 439 (remanding standard to consider solid 
waste disposal implications of the BSER determination).
---------------------------------------------------------------------------

(c) Energy Considerations
    Under CAA section 111(a)(1), the EPA is required to take into 
account ``energy requirements.'' As discussed below, the EPA may 
consider energy requirements on both a source-specific basis and a 
sector-wide, region-wide, or nationwide basis. Considered on a source-
specific basis, ``energy requirements'' entails, for example, the 
impact, if any, of the system of emission reduction on the source's own 
energy needs.
(d) Amount of Emissions Reductions
    In the proposed rulemakings for this rule and the associated 
section 111(b) rule, we noted that although the definition of 
``standard of performance'' does not by its terms identify the amount 
of emissions from the category of sources or the amount of emission 
reductions achieved as factors the EPA must consider in determining the 
``best system of emission reduction,'' the D.C. Circuit has stated that 
the EPA must do so. See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. 
Cir. 1981) (``we can think of no sensible interpretation of the 
statutory words ``best . . . system'' which would not incorporate the 
amount of air pollution as a relevant factor to be weighed when 
determining the optimal standard for controlling . . . 
emissions'').\331\ The fact that the purpose of a ``system of emission 
reduction'' is to reduce emissions, and that the term itself explicitly 
incorporates the concept of reducing emissions, supports the Court's 
view that in determining whether a ``system of emission reduction'' is 
the ``best,'' the EPA must consider the amount of emission reductions 
that the system would yield. Even if the EPA were not required to 
consider the amount of emission reductions, the EPA has the discretion 
to do so, on grounds that either the term ``system of emission 
reduction'' or the term ``best'' may reasonably be read to allow that 
discretion.
---------------------------------------------------------------------------

    \331\ Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was 
governed by the 1977 CAAA version of the definition of ``standard of 
performance,'' which revised the phrase ``best system of emission 
reduction'' to read, ``best technological system of continuous 
emission reduction.'' As noted above, the 1990 CAAA deleted 
``technological'' and ``continuous'' and thereby returned the phrase 
to how it read under the 1970 CAAA. The court's interpretation of 
the 1977 CAAA phrase in Sierra Club v. Costle to require 
consideration of the amount of air emissions remains valid for the 
1990 CAAA phrase ``best system of emission reduction.''
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(e) Sector- or Nationwide Component of Factors in Determining the BSER
    As discussed in the January 2014 proposal for the section 111(b) 
rulemaking and the proposal for this rulemaking, another component of 
the D.C. Circuit's interpretations of CAA section 111 is that the EPA 
may consider the various factors it is required to consider on a 
national or regional level and over time, and not only on a plant-
specific level at the time of the rulemaking.\332\ The D.C. Circuit 
based this interpretation--which it made in the 1981 Sierra Club v. 
Costle case, which concerned the NSPS for new power plants--on a review 
of the legislative history, stating,
---------------------------------------------------------------------------

    \332\ 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club v. 
Costle, 657 F.2d at 351).

    [T]he Reports from both Houses on the Senate and House bills 
illustrate very clearly that Congress itself was using a long-term 
lens with a broad focus on future costs, environmental and energy 
effects of different technological systems when it discussed section 
111.\333\
---------------------------------------------------------------------------

    \333\ Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 
(citing legislative history).

The Court has upheld EPA rules that the EPA ``justified . . . in terms 
of the policies of the Act,'' including balancing long-term national 
---------------------------------------------------------------------------
and regional impacts:

    The standard reflects a balance in environmental, economic, and 
energy consideration by being sufficiently stringent to bring about 
substantial reductions in SO2 emissions (3 million tons 
in 1995) yet does so at reasonable costs without significant energy 
penalties . . . . By achieving a balanced coal demand within the 
utility sector and by promoting the development of less expensive 
SO2 control technology, the final standard will expand 
environmentally acceptable energy supplies to existing power plants 
and industrial sources.
    By substantially reducing SO2 emissions, the standard 
will enhance the potential for long term economic growth at both the 
national and regional levels.\334\
---------------------------------------------------------------------------

    \334\ Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR 
at 33583/3-33584/1). In the January 2014 proposal, we explained that 
although the D.C. Circuit decided Sierra Club v. Costle before the 
Chevron case was decided in 1984, the D.C. Circuit's decision could 
be justified under either Chevron step 1 or 2. 79 FR 1430, 1466 
(January 8, 2014).

    In this rule, the EPA is considering costs and energy implications 
on the

[[Page 64722]]

basis of (i) their source-specific impacts and (ii) a sector-wide, 
regional, or national basis, both separately and in combination with 
each other.
(4) Achievability of the Emission Limitation in the Emission Guidelines
    Before discussing the requirement under section 111(d) that the 
emission limitation in the emission guidelines must be ``achievable,'' 
it is useful to discuss the comparable requirement under section 111(b) 
for new sources. For new sources, CAA section 111(b)(1)(B) and (a)(1) 
provides that the EPA must establish ``standards of performance,'' 
which are standards for emissions that reflect the degree of emission 
limitation that is ``achievable'' through the application of the BSER. 
According to the D.C. Circuit, a standard of performance is 
``achievable'' if a technology can reasonably be projected to be 
available to an individual source at the time it is constructed that 
will allow it to meet the standard.\335\ Moreover, according to the 
Court, ``[a]n achievable standard is one which is within the realm of 
the adequately demonstrated system's efficiency and which, while not at 
a level that is purely theoretical or experimental, need not 
necessarily be routinely achieved within the industry prior to its 
adoption.'' \336\ To be achievable, a standard ``must be capable of 
being met under most adverse conditions which can reasonably be 
expected to recur and which are not or cannot be taken into account in 
determining the `costs' of compliance.'' \337\ To show a standard is 
achievable, the EPA must ``(1) identify variable conditions that might 
contribute to the amount of expected emissions, and (2) establish that 
the test data relied on by the agency are representative of potential 
industry-wide performance, given the range of variables that affect the 
achievability of the standard.'' \338\
---------------------------------------------------------------------------

    \335\ Sierra Club v. Costle, 657 F.2d 298, 364, n. 276 (D.C. 
Cir. 1981).
    \336\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 
(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \337\ Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433, n.46 (D.C. 
Cir. 1980).
    \338\ Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) 
(citing Nat'l Lime Ass'n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). In 
considering the representativeness of the source tested, the EPA may 
consider such variables as the ```feedstock, operation, size and 
age' of the source.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433 
(D.C. Cir. 1980). Moreover, it may be sufficient to ``generalize 
from a sample of one when one is the only available sample, or when 
that one is shown to be representative of the regulated industry 
along relevant parameters.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 
434, n.52 (D.C. Cir. 1980).
---------------------------------------------------------------------------

    The D.C. Circuit established these standards for achievability in 
cases concerning CAA section 111(b) new source standards of 
performance. There is no case law under CAA section 111(d). Assuming 
that those standards for achievability apply under section 111(d), in 
this rulemaking, we are taking a similar approach for the emission 
limitation that the EPA identifies in the emission guidelines. For 
existing sources, section 111(d)(1) requires the EPA to establish 
requirements for state plans that, in turn, must include ``standards of 
performance.'' Through long-standing regulations \339\ and consistent 
practice, the EPA has interpreted this provision to require the EPA to 
promulgate emission guidelines that determine the BSER for a source 
category and that identify the amount of emission limitation achievable 
by application of the BSER.
---------------------------------------------------------------------------

    \339\ 40 CFR 60.21(e).
---------------------------------------------------------------------------

    The EPA has promulgated these emission guidelines on the basis that 
the existing sources can achieve the limitation, even though the state 
retains discretion to apply standards of performance to individual 
sources that are more or less stringent.
    As indicated in the proposed rulemakings for this rule and the 
associated section 111(b) rule, the requirement that the emission 
limitation in the emission guidelines be ``achievable'' based on the 
``best system of emission reduction . . . adequately demonstrated'' 
indicates that the technology or other measures that the EPA identifies 
as the BSER must be technically feasible. See 79 FR 1430, 1463 (January 
8, 2014). At least in some cases, in determining whether the emission 
limitation is achievable, it is useful to analyze the technical 
feasibility of the system of emission reduction, and we do so in this 
rulemaking.
(5) Expanded Use and Development of Technology
    The D.C. Circuit has long held that Congress intended for CAA 
section 111 to create incentives for new technology and therefore that 
the EPA is required to consider technological innovation as one of the 
factors in determining the ``best system of emission reduction.'' See 
Sierra Club v. Costle, 657 F.2d at 346-47. The Court has grounded its 
reading in the statutory text.\340\ In addition, the Court's 
interpretation finds firm support in the legislative history.\341\ The 
legislative history identifies three different ways that Congress 
designed CAA section 111 to authorize standards of performance that 
promote technological improvement: (i) The development of technology 
that may be treated as the ``best system of emission reduction . . . 
adequately demonstrated;'' under section 111(a)(1); \342\ (ii) the 
expanded use of the best demonstrated technology; \343\ and (iii) the 
development of emerging technology.\344\ Even if the EPA were not 
required to consider technological innovation as part of its 
determination of the BSER, it would be reasonable for the EPA to 
consider it, either because technological innovation may be considered 
an element of the term ``best,'' or because the term ``best system of 
emission reduction'' is ambiguous as to whether technological 
innovation may be considered, and it is reasonable for the EPA to 
interpret it to authorize consideration of technological innovation in 
light of Congress's emphasis on technological innovation.
---------------------------------------------------------------------------

    \340\ Sierra Club v. Costle, 657 F. 2d at 346 (``Our 
interpretation of section 111(a) is that the mandated balancing of 
cost, energy, and nonair quality health and environmental factors 
embraces consideration of technological innovation as part of that 
balance. The statutory factors which EPA must weigh are broadly 
defined and include within their ambit subfactors such as 
technological innovation.'').
    \341\ See S. Rep. No. 91-1196 at 16 (1970) (``Standards of 
performance should provide an incentive for industries to work 
toward constant improvement in techniques for preventing and 
controlling emissions from stationary sources''); S. Rep. No. 95-127 
at 17 (1977) (cited in Sierra Club v. Costle, 657 F.2d at 346 n. 
174) (``The section 111 Standards of Performance . . . sought to 
assure the use of available technology and to stimulate the 
development of new technology'').
    \342\ See Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 
391 (D.C. Cir. 1973) (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'').
    \343\ 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'').
    \344\ See Sierra Club v. Costle, 657 F.2d at 351 (upholding a 
standard of performance designed to promote the use of an emerging 
technology).
---------------------------------------------------------------------------

    In any event, as discussed below, the EPA may justify the control 
measures identified in this rule as the BSER even without considering 
the factor of incentivizing technological innovation or development.
(6) EPA Discretion
    The D.C. Circuit has made clear that the EPA has broad discretion 
in determining the appropriate standard of performance under the 
definition in CAA section 111(a)(1), quoted above. Specifically, in 
Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981), the Court 
explained that ``section 111(a) explicitly instructs the EPA to balance 
multiple concerns when promulgating a

[[Page 64723]]

NSPS,'' \345\ and emphasized that ``[t]he text gives the EPA broad 
discretion to weigh different factors in setting the standard.'' \346\ 
In Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999), the 
Court reiterated:
---------------------------------------------------------------------------

    \345\ Sierra Club v. Costle, 657 F.2d at 319.
    \346\ Sierra Club v. Costle, 657 F.2d at 321; see also New York 
v. Reilly, 969 F. 2d at 1150 (because Congress did not assign the 
specific weight the Administrator should assign to the statutory 
elements, ``the Administrator is free to exercise [her] discretion'' 
in promulgating an NSPS).

    Because section 111 does not set forth the weight that should be 
assigned to each of these factors, we have granted the agency a 
great degree of discretion in balancing them. . . . EPA's choice [of 
the `best system'] will be sustained unless the environmental or 
economic costs of using the technology are exorbitant. . . . EPA 
[has] considerable discretion under section 111.\347\
---------------------------------------------------------------------------

    \347\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999) (paragraphing revised for convenience). See New York v. 
Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992) (``Because Congress did 
not assign the specific weight the Administrator should accord each 
of these factors, the Administrator is free to exercise his 
discretion in this area.''); see also NRDC v. EPA, 25 F.3d 1063, 
1071 (D.C. Cir. 1994) (EPA did not err in its final balancing 
because ``neither RCRA nor EPA's regulations purports to assign any 
particular weight to the factors listed in subsection (a)(3). That 
being the case, the Administrator was free to emphasize or 
deemphasize particular factors, constrained only by the requirements 
of reasoned agency decisionmaking.'').

    d. Approach to the source category and subcategorizing. Section 111 
requires the EPA first to list source categories that may reasonably be 
expected to endanger public health or welfare and then to regulate new 
sources within each such source category. Section 111(b)(2) grants the 
EPA discretion whether to ``distinguish among classes, types, and sizes 
within categories of new sources for the purpose of establishing [new 
source] standards,'' which we refer to as ``subcategorizing.'' Section 
111(d)(1), in conjunction with section 111(a)(1), simply requires the 
EPA to determine the BSER, does not prescribe the method for doing so, 
and is silent as to whether the EPA may subcategorize. The EPA 
interprets this provision to authorize the EPA to exercise discretion 
as to whether and, if so, how to subcategorize. In addition, the 
regulations under CAA section 111(d) provide that the Administrator 
will specify different emission guidelines or compliance times or both 
``for different sizes, types, and classes of designated facilities when 
costs of the control, physical limitations, geographical location, or 
similar factors make subcategorization appropriate.'' \348\
---------------------------------------------------------------------------

    \348\ 40 CFR 60.22(b)(5).
---------------------------------------------------------------------------

    As with any of its own regulations, the EPA has authority to 
interpret or revise these regulations.
    Of course, regardless of whether the EPA subcategorizes within a 
source category for purposes of determining the BSER and the emissions 
performance level for the emission guideline, as part of its CAA 
section 111(d) plan, a state retains great flexibility in assigning 
standards of performance to its affected EGUs. Thus, the state may, if 
it wishes, impose different emission reduction obligations on different 
sources, as long as the overall level of emission limitation is at 
least as stringent as the emission guidelines.
2. The BSER for This Rule--Overview
    a. Summary. This section describes the EPA's overall approach to 
establishing the BSER. This rule, promulgated under CAA section 111(d), 
establishes emission guidelines for states to use in establishing 
standards of performance for affected EGUs, and the BSER is the central 
determination that the EPA must make in formulating the guidelines. In 
order to establish the BSER we have considered the subcategory of the 
steam affected EGUs as a whole, and the subcategory of the combustion 
turbine affected EGUs as a whole, and have identified the BSER for each 
subcategory as the measures that the sources, viewed together and 
operating under the standards of performance established for them by 
the states, can implement to reduce their emissions to an appropriate 
amount, and that meet the other requirements for the BSER including, 
for example, cost reasonableness.\349\ After identifying the BSER in 
this manner, the EPA determines the performance levels--in this case, 
the CO2 emission performance rates--for the steam generators 
and for the combustion turbines.
---------------------------------------------------------------------------

    \349\ In this rulemaking, our determination that the costs are 
reasonable means that the costs meet the cost standard in the case 
law no matter how that standard is articulated, that is, whether the 
cost standard is articulated through the terms that the case law 
uses, e.g., ``exorbitant,'' ``excessive,'' etc., or through the term 
we use for convenience, ``reasonableness''.
---------------------------------------------------------------------------

    In establishing the BSER the EPA also considered the set of actions 
that an EGU, operating under a standard of performance established by 
its state, may take to achieve the applicable performance rate, if the 
state adopts that rate as the standard of performance and applies it to 
the EGUs in its jurisdiction, or to achieve the equivalent mass-based 
limit, and that meet the other requirements for the BSER. These actions 
implement the BSER and may therefore be understood as part of the BSER.
    An example illustrating the relationship between the measures 
determined to constitute the BSER for the source category and the 
actions that may be undertaken by individual sources that are therefore 
also part of the BSER is the substitution of zero-emitting generation 
for CO2-emitting generation. This measure involves two 
distinct actions: Increasing the amount of zero-emitting generation and 
reducing the amount of CO2-emitting generation. From the 
perspective of the source category, the two actions are halves of a 
single balanced endeavor, but from the perspective of any individual 
affected EGU, the two actions are separable, and a particular affected 
EGU may decide to implement either or both of the actions. Further, an 
individual source may choose to invest directly in actions at its own 
facility or an affiliated facility or to cross-invest in actions at 
other facilities on the interconnected electricity system.
    To reiterate the overall context for the BSER: In this rule, the 
EPA determined the BSER, and applied it to the category of affected 
EGUs to determine the performance levels--that is, the CO2 
emission performance rates--for steam generators and for combustion 
turbines. States must impose standards of performance on their sources 
that implement the CO2 emission performance rates, or, as an 
alternative method of compliance, in total, achieve the equivalent 
emissions performance level that the CO2 emission 
performance rates would achieve if applied directly to each source as 
the standard or emissions limitation it must meet.\350\ Each state has 
flexibility in how it assigns the emission limitations to its affected 
EGUs--and in fact, the state can be more stringent than the guidelines 
require--but one of the state's choices is to convert the 
CO2 emission performance rates into standards of 
performance--which may incorporate emissions trading--for each of its 
affected EGUs. If a state does so, then the affected EGUs may achieve 
their emission limits by taking the actions that qualify as the BSER. 
Since the BSER and, in this case its constituent elements, reflect the 
criteria of reasonable cost and other BSER criteria, the BSER assures 
that there is at least one pathway--the CO2 emission 
performance rates--for the state and its affected EGUs to take that 
achieves the requisite level of emission reductions, while, again, 
assuring that the affected EGUs can achieve those emission limits

[[Page 64724]]

at reasonable cost and consistent with the other factors for the BSER.
---------------------------------------------------------------------------

    \350\ The approaches that states may take in their plans are 
discussed in section VIII.
---------------------------------------------------------------------------

    This section describes the EPA's process and basis for determining 
the BSER for the purpose of determining the CO2 emission 
performance rates.\351\ The EPA is identifying the BSER as a well-
established set of measures that have been used by EGUs for many years 
to achieve various business and policy purposes, and have been used in 
recent years for the specific purpose of reducing EGUs' CO2 
emissions, and that are appropriate for carbon pollution (given its 
global nature and large quantities, and the limited means to control 
it) and afforded by the highly integrated nature of the utility power 
sector. We evaluated these measures with a view to the states' 
obligation to establish standards of performance and included in our 
BSER determination consideration of the range of options available for 
states to employ in establishing those standards of performance. These 
measures include: (i) Improving heat rate at existing coal-fired steam 
EGUs on average by a specified percentage (building block 1); (ii) 
substituting increased generation from existing NGCC units for reduced 
generation at existing steam EGUs in specified amounts (building block 
2); and (iii) substituting increased generation from new zero-emitting 
RE generating capacity for reduced generation at existing fossil fuel-
fired EGUs in specified amounts (building block 3). It should be noted 
that building block 2 incorporates reduced generation from steam EGUs 
and building block 3 incorporates reduced generation from all fossil 
fuel-fired EGUs.\352\ Further, as discussed below, given the global 
nature of carbon pollution and the highly integrated utility power 
sector, each of the building blocks incorporates various mechanisms for 
facilitating cross-investment by individual affected EGUs in emission 
rate improvements or emission reduction activities at other locations 
on the interconnected electricity system. The range of mechanisms 
includes bilateral investment of various kinds; the issuance and 
acquisition of ERCs representing the emissions-reducing effects of 
specific activities, where available under state plans; and more 
general emissions trading using rate-based credits or mass-based 
allowances (as discussed in section V.A.2.f. below), where the affected 
EGUs are operating under standards of performance that incorporate 
emissions trading.\353\
---------------------------------------------------------------------------

    \351\ Other sections in this preamble describe how EPA 
calculated the CO2 emission performance rates based on 
the BSER.
    \352\ The building block measures are not designed to reduce 
electricity generation overall; they are focused on maintaining the 
same level of electricity generation, but through less polluting 
processes.
    \353\ Conditions for the use of these mechanisms under various 
state plans are discussed in section VIII.
---------------------------------------------------------------------------

    The set of measures identified as the BSER for the source category 
encompasses a menu of actions that are part of the BSER and that 
individual affected EGUs may implement in different amounts and 
combinations in order to achieve their emission limits at reasonable 
cost. This menu includes actions that: (i) Affected steam EGUs can 
implement to improve their heat rates; (ii) affected steam EGUs can 
implement to increase generation from lower-emitting existing NGCC 
units in specified amounts; (iii) all affected EGUs can implement to 
increase generation from new low- or zero-carbon generation sources in 
specified amounts; (iv) all affected EGUs can implement to reduce their 
generation in specified amounts; and (v) all affected EGUs operating 
under a standard of performance that incorporates emissions trading can 
implement by means of purchasing rate-based emission credits or mass-
based emission allowances from other affected EGUs, since the effect of 
the purchase would be the same as achieving the other listed actions 
through direct means.\354\
---------------------------------------------------------------------------

    \354\ Again, conditions for the use of these mechanisms under 
various state plans are discussed in section VIII.
---------------------------------------------------------------------------

    Importantly, affected EGUs also have available numerous other 
measures that are not included in the BSER but that could materially 
help the EGUs achieve their emission limits and thereby provide 
compliance flexibility. Examples include, among numerous other 
approaches, investment in demand-side EE, co-firing with natural gas 
(for coal-fired steam EGUs), and investment in new generating units 
using low- or zero-carbon generating technologies other than those that 
are part of building block 3.
    b. The EPA's review of measures for determining the BSER. The EPA 
described in the proposal for this rule the analytical process by which 
the EPA determined the BSER for this source category. The EPA is 
finalizing large parts of that analysis, but the EPA is also refining 
that analysis as informed by the information and data discussed by 
commenters and our further evaluation. What follows is the EPA's final 
determination.
    As described in the proposal, to determine the BSER, the EPA began 
by considering the characteristics of CO2 pollution and the 
utility power sector. Not surprisingly, whenever the EPA begins the 
regulatory process under section 111, it initially undertakes these 
same inquiries and then proceeds to fashion the rule to fit the 
industry. For example, in 1979, the EPA finalized new standards of 
performance to limit emissions of SO2 from new, modified, 
and reconstructed EGUs.\355\ In assessing the final SO2 
standard, the EPA carried out extensive analyses of a range of 
alternative SO2 standards ``to identify environmental, 
economic, and energy impacts associated with each of the alternatives 
considered at the national and regional levels.'' \356\ In identifying 
the best system underlying the final standard, the EPA evaluated ``coal 
cleaning and the relative economics of FGD [flue gas desulfurization] 
and coal cleaning'' together as the ``best demonstrated system for 
SO2 emission reduction.'' \357\ The EPA also took into 
account the unique features of power transmission along the 
interconnected grid and the unique commercial relationships that rely 
on those features.\358\
---------------------------------------------------------------------------

    \355\ The need for new standards was due in part to findings 
that in 1976, steam electric generating units were responsible for 
``65 percent of the SO2 . . . emissions on a national 
basis.'' 44 FR 33580, 33587 (June 11, 1979). The EPA explained that 
[u]nder the current performance standards for power plants, national 
SO2 emissions are projected to increase approximately 17 
percent between 1975 and 1995. Impacts will be more dramatic on a 
regional basis.'' Id. Thus, ``[o]n January 27, 1977, EPA announced 
that it had initiated a study to review the technological, economic, 
and other factors needed to determine to what extent the 
SO2 standard for fossil-fuel-fired steam generators 
should be revised.'' Id. at 33587-33588.
    \356\ 44 FR 33580, 33582 (June 11, 1979).
    \357\ 44 FR 33580, 33593. The EPA considered an investigation by 
the U.S. Department of the Interior regarding the amount of sulfur 
that could be removed from various coals by physical coal cleaning. 
Id. at 33593.
    \358\ See 44 FR 33580, 33597-33600 (taking into account ``the 
amount of power that could be purchased from neighboring 
interconnected utility companies'' and noting that ``[a]lmost all 
electric utility generating units in the United States are 
electrically interconnected through power transmission lines and 
switching stations'' and that ``load can usually be shifted to other 
electric generating units'').
---------------------------------------------------------------------------

    Similarly, in 1996, the EPA finalized section 111(b) standards and 
111(d) emission guidelines to ensure that certain municipal solid waste 
(MSW) landfills controlled landfill gases to the level achievable 
through application of the BSER.\359\ EPA's identification of this BSER 
was critically influenced by the ``unique emission pattern of

[[Page 64725]]

landfills.'' \360\ Unlike ``typical stationary source[s],'' which only 
generate emissions while in operation, MSW landfills can ``continue to 
generate and emit a significant quantity of emissions'' long after the 
facility has closed or otherwise stopped accepting waste.\361\ In 
recognition of this salient and unique characteristic of landfills, the 
EPA set the BSER based on an emission-reducing system of gas collection 
and control that remained in place as long as emissions remained above 
a certain threshold--even after the regulated landfill had permanently 
closed.\362\ The EPA acknowledged that for some landfills, it could 
take 50 to 100 years for emissions to drop below the cutoff.\363\
---------------------------------------------------------------------------

    \359\ 61 FR 9905, 9905 (March 12, 1996). In the rule, the EPA 
referred to the BSER for both new and existing MSW landfills as 
``the best demonstrated system of continuous emission reduction,'' 
as well as the ``BDT''--short for ``best demonstrated technology.'' 
See, e.g., id. at 9905-07, 9913-14.
    \360\ 61 FR 9905, 9908; see 56 FR 24468, 24478 (May 30, 1991) 
(explaining at proposal that because landfill-gas emission rates 
``gradually increase'' from zero after the landfill opens, and 
``gradually decrease'' from peak emissions after closure, the EPA's 
identification of the BSER for landfills inherently requires a 
determination of ``when controls systems must be installed and when 
they may be removed'').
    \361\ See U.S. EPA, Municipal Solid Waste Landfills, Volume 1: 
Summary of the Requirements for the New Source Performance Standards 
and Emission Guidelines for Municipal Solid Waste Landfills, Docket 
No. EPA-453R/96-004 at 1-3 (February 1999).
    \362\ 61 FR 9905, 9907-08.
    \363\ 61 FR 9905, 9908.
---------------------------------------------------------------------------

    For this rule, we discuss at length in the proposed rule and in 
section II above the unique characteristics of CO2 
pollution. The salient facts include the global nature of 
CO2, which makes the specific location of emission 
reductions unimportant; the enormous quantities of CO2 
emitted by the utility power sector, coupled with the fact that 
CO2 is relatively unreactive, which make CO2 much 
more difficult to mitigate by measures or technologies that are 
typically utilized within an existing power plant; the need to make 
large reductions of CO2 in order to protect human health and 
the environment; and the fact that the utility power sector is the 
single largest source category by a considerable margin.
    We also discuss at length in the proposal and in section II above 
the unique characteristics of the utility power sector. Topics of that 
discussion include the physical properties of electricity and the 
integrated nature of the electricity system. Here, we reiterate and 
emphasize that the utility power sector is unique in the extent to 
which it must balance supply and demand on a real-time basis, with 
limited electricity storage capacity to act as a buffer. In turn, the 
need for real-time synchronization across each interconnection has led 
to a uniquely high degree of coordination and interdependence in both 
planning and real-time system operation among the owners and operators 
of the facilities comprised within each of the three large electrical 
interconnections covering the contiguous 48 states. Given these unique 
characteristics, it is not surprising that the North American power 
system has been characterized as a ``complex machine.'' \364\ The core 
function of providing reliable electricity service is carried out not 
by individual electricity generating units but by the complex machine 
as a whole. Important subsidiary functions such as management of costs 
and management of environmental impacts are also carried out to a great 
extent on a multi-unit basis rather than an individual-unit basis. 
Generation from one generating unit can be and routinely is substituted 
for generation from another generating unit in order to keep the 
complex machine operating while observing the machine's technical, 
environmental, and other constraints and managing its costs.
---------------------------------------------------------------------------

    \364\ S. Massoud Amin, ``Securing the Electricity Grid,'' The 
Bridge, Spring 2010, at 13, 14; Phillip F. Schewe, The Grid: A 
Journey Through the Heart of Our Electrified World 1 (2007).
---------------------------------------------------------------------------

    The EPA also reviewed broad trends within the utility power 
sector.\365\ It is evident that, in the recent past, coal-fired 
electricity generation has been reduced, and projected future trends 
are for continued reduction. By the same token, lower-emitting NGCC 
generation and renewable generation have increased, and projected 
future trends are for continued increases.\366\ A survey of integrated 
resource plans (IRPs), included in the docket, shows that fossil fuel-
fired EGUs are taking actions to reduce emissions of both non-GHG air 
pollutants and GHGs.\367\ Some fossil fuel-fired EGUs are investing in 
lower- or zero-emitting generation. In fact, our review indicates that 
the great majority of fossil fuel-fired generators surveyed are 
including new RE resources in their planning. In addition, some fossil 
fuel-fired EGUs are using those measures to replace their higher-
emitting generation. Some fossil fuel-fired generators appear to be 
reducing their higher-emitting generation without fully replacing it 
themselves. These measures in aggregate result in the replacement of 
higher-emitting generation with lower- or zero-emitting generation, 
reflecting the integrated nature of the electricity system.
---------------------------------------------------------------------------

    \365\ These trends are discussed in more detail in sections V.D. 
and V.E. below.
    \366\ Demand-side energy efficiency measures have also 
increased, and the projected future trends are for continued 
increase.
    \367\ See memorandum entitled ``Review of Electric Utility 
Integrated Resource Plans'' (May 7, 2015) available in the docket.
---------------------------------------------------------------------------

    The EPA examined state and company programs intended at least in 
part to reduce CO2 from fossil fuel-fired power plants. 
These programs include GHG performance standards established by states 
including California, New York, Oregon, and Washington; utility 
planning approaches carried out by companies in Colorado and Minnesota; 
and renewable portfolio standards (RPS) established in more than 25 
states.\368\ They also include market-based initiatives, such as RGGI 
and the GHG emissions trading program established by the California 
Global Warming Solutions Act, and conservation and demand reduction 
programs.
---------------------------------------------------------------------------

    \368\ See 79 FR 34848-34850.
---------------------------------------------------------------------------

    We also examined federal legislative and regulatory programs, as 
well as state programs currently in operation, that address pollutants 
other than CO2 emitted by the power sector. These programs 
include, among others, the CAA Title IV program to reduce 
SO2 and NOX, the MATS program to reduce mercury 
and air toxic emissions, and the CSAPR program to reduce SO2 
and NOX.\369\ This analysis demonstrated that, among other 
measures, the application of control technology, fuel-switching, and 
improvements in the operational efficiency of EGUs all resulted in 
reductions in a range of pollutants. These programs also demonstrate 
that replacement of higher-emitting generation with lower-emitting 
generation--including generation shifts between coal-fired EGUs and 
natural gas-fired EGUs and generation shifts between fossil fuel-fired 
EGUs and RE generation--also reduces emissions. Some of these programs 
also include emissions trading among the power plants.
---------------------------------------------------------------------------

    \369\ Many of these programs are discussed in section II.
---------------------------------------------------------------------------

    In this rule, when evaluating the types and amounts of measures 
that the source category can take to reduce CO2 emissions, 
we have appropriately taken into account the global nature of the 
pollutant and the high degree to which each individual affected EGU is 
integrated into a ``complex machine'' that makes it possible for 
generation from one generating unit to be replaced with generation from 
another generating unit for the purpose of reducing generation from 
CO2-emitting generating units. We have also taken into 
account the trends away from higher-carbon generation toward lower- and 
zero-carbon generation. These factors strongly support consideration of 
emission reduction approaches that

[[Page 64726]]

focus on the machine as a whole--that is, the overall source category--
by shifting generation from dirtier to cleaner sources in addition to 
emission reduction approaches that focus on improving the emission 
rates of individual sources.
    The factors just discussed that support consideration of emission 
reduction measures at the source-category level likewise strongly 
support consideration of mechanisms such as emissions trading 
approaches, especially since, as discussed in section VIII, the states 
will have every opportunity to design their section 111(d) plans to 
allow the affected EGUs in their respective jurisdictions to employ 
emissions trading approaches to achieve the standards of performance 
established in those plans. In short, as discussed in more detail in 
section V.A.2.f. below, it is entirely feasible for states to establish 
standards of performance that incorporate emissions trading, and it is 
reasonable to expect that states will do so. These approaches lower 
overall costs, add flexibility, and make it easier for individual 
sources to address pollution control objectives. To the extent that the 
purchase of an emissions credit or allowance represents the purchase of 
surplus emission reductions by an emitting source, emissions trading 
represents, in effect, the investment in pollution control by the 
purchasing source, notwithstanding that the control activity may be 
occurring at another source. As noted above, the utility power sector 
has a long history of using the ``complex machine'' to address 
objectives and constraints of various kinds. When afforded the 
opportunity to address environmental objectives on a multi-unit basis, 
the industry has done so. Congress and the EPA have selected emissions 
trading approaches when addressing regional pollution from the utility 
power sector contributing to problems such as acid precipitation and 
interstate transport of ozone and particulate matter. Similarly, states 
have selected market-based approaches for their own programs to address 
regional and global pollutants. The industry has readily adapted to 
that form of regulation, taking advantage of the flexibility and 
incorporating those programs into the planning and operation of the 
``machine.'' Further reinforcing our conclusion that reliance on 
trading is appropriate is the extensive interest in using such 
mechanisms that states and utilities demonstrated through their formal 
comments and in discussions during the outreach process. The role of 
emissions trading is discussed further in section V.A.2.f. below.
    This entire review has made clear that there are numerous measures 
that, alone or in various combinations, merit analysis for inclusion in 
the BSER. The review has also made clear that the unique 
characteristics of CO2 pollution and the unique, 
interconnected and interdependent manner in which affected EGUs and 
other generating sources operate within the electricity sector make 
certain types of measures and mechanisms available and appropriate for 
consideration as the BSER for this rule that would not be appropriate 
for other pollutants and other industrial sectors. For purposes of this 
discussion, the measures can be categorized in terms of the essential 
characteristics of the four building blocks described in the proposal: 
measures that (i) reduce the CO2 emission rate at the unit; 
(ii) substitute generation from existing lower-emitting fossil fuel-
fired units for generation from higher-emitting fossil fuel-fired 
units; (iii) substitute generation from new low- or zero-emitting 
generating capacity, especially RE, for generation from fossil fuel-
fired units; and (iv) increase demand-side EE to avoid generation from 
fossil fuel-fired units. In the proposal, we described our evaluations 
of various measures in each of these categories. In this rule, with the 
benefit of comments, we have refined our evaluation of which specific 
measures should comprise the first three building blocks, and, for 
reasons discussed below, we have determined that the fourth building 
block, demand-side EE, should not be included in the BSER in these 
guidelines.
    The measures are discussed more fully below, but it should be noted 
here that because of the integrated nature of the utility power 
sector--in which individual EGUs' operations intrinsically depend on 
the operations of other generators--coupled with the sector's high 
degree of planning and reliability safeguards, the measures in the 
second and third categories (which involve generation shifts to lower- 
and zero-emitting sources) may occur through several different actions 
from the perspective of an individual source, all of which are 
equivalent from the perspective of the source category as a whole. 
First, a higher-emitting fossil unit may invest in cleaner generation 
without reducing its own generation, which, in the presence of 
requirements for the source category as a whole to reduce 
CO2 emissions, would result in less demand for, and 
therefore reductions in generation by, other higher-emitting units. 
Second, a higher-emitting fossil unit may reduce its generation, which, 
in the presence of requirements for the source category as a whole to 
reduce CO2 emissions, would result in increased demand for, 
and therefore increased amounts of, cleaner generation. Third, a 
higher-emitting fossil unit may do both of these things, directly 
replacing part of its generation with investments in lower- or zero-
emitting generation. In addition, for measures in all of the 
categories, multiple mechanisms exist by which an individual affected 
EGU may make these investments, ranging from bilateral investments, to 
purchase of credits representing the emissions-reducing benefits of 
specific activities, to purchase of general rate-based emissions 
credits or mass-based emission allowances. As discussed below, 
mechanisms involving tradable credits or allowances are well within the 
realm of consideration for the standards of performance states can 
choose to apply to their EGUs and hence, are entirely appropriate for 
EPA to consider in evaluating these measures in the course of making 
its BSER determination.
    c. State establishment of standards of performance and source 
compliance. Before identifying in detail the measures that the BSER 
comprises, it is useful to describe the process by which the states 
establish the standards of performance with which the affected EGUs 
must comply, and the implications for the sources that will be 
operating subject to those standards of performance. As part of the 
EPA's emission guidelines in this rule, and based on the BSER, the EPA 
is identifying CO2 emission performance rates that reflect 
the BSER and, pursuant to subsection 111(d)(1), requiring states to 
establish standards of performance for affected EGUs in order to 
implement those rates. States, of course, could simply impose those 
rates on each affected EGU in their respective jurisdictions, but we 
are also offering states alternative approaches to carrying out their 
obligations. For purposes of defining these alternatives and 
facilitating states' efforts to formulate compliance plans encompassing 
maximum flexibilities, we are aggregating the performance rates into 
goals for each state. The state, in turn, has the option of setting 
specific standards of performance for its EGUs such that the emission 
limitations from the EGUs operating under those standards of 
performance together meet the performance rates or the state goal. To 
do this, the state must adopt a plan that establishes the EGUs' 
standards of

[[Page 64727]]

performance and that implements and enforces those standards.
    Each state has significant flexibility in several respects. For 
example, as mentioned, a state may impose standards of performance on 
its steam EGU sources and on its combustion turbine sources that simply 
reflect the respective CO2 emission performance rates for 
those subcategories set in the emission guidelines. Alternatively, a 
state may impose standards with differing degrees of stringency on 
various sources, and, in fact, may be more stringent overall than its 
state goal requires. In addition--and most importantly for purposes of 
describing the BSER--a state may set standards of performance as mass 
limits (e.g., tons of CO2 per year) rather than as emission 
rates (e.g., lbs of CO2 per MWh). Moreover, a state may make 
the limits tradable (subject to conditions described in section VIII 
below), whether the limits are rate-based or mass-based. The form of 
the emission limits, whether emission rate limits or mass limits, has 
implications for what specific actions that are part of the BSER the 
individual affected EGUs may take to achieve those limits as well as 
what specific non-BSER measures are available to the individual 
affected EGUs for compliance flexibility. For example, if an individual 
source chooses to adopt building block 3 by both investing in lower- or 
zero-emitting generation and reducing its own generation, both those 
actions will be accounted for in its emission rate and both will 
therefore help the source meet its rate-based limit. If the same 
individual source takes the same actions but is subject to a mass-based 
limit, the action of reducing its generation will directly count in 
helping the source meet its own mass-based limit but the action of 
investing in cleaner generation will not. However, the investment in 
lower-or zero-emitting generation by that source and other sources 
collectively will help the overall source category achieve the emission 
limits consistent with the BSER and in doing so will make it easier for 
that source and other sources collectively to meet their mass-based 
limits.
    In instances where a state establishes standards of performance 
that incorporate emissions trading, the tradable credits or allowances 
can serve as a medium through which affected EGUs can invest in any 
emission reduction measure.
    d. Identification of the BSER measures. We now discuss the 
evaluation of potential measures for inclusion in the BSER for the 
source category as a whole.
    (1) Measures that reduce individual affected EGUs' CO2 
emission rates.
    As described in the proposal, the measures that the affected EGUs 
could implement to improve their CO2 emission rates include 
a set of measures that the EPA determined would result in improvements 
in heat rate at coal-fired steam EGUs in the amount of 6 percent on 
average, and the EPA proposed that this set of measures qualifies as a 
component of the BSER. In this final rule, the EPA concludes that those 
measures do qualify as a component of the BSER. However, as described 
in section V.C. below, based on responsive comments and further 
evaluation, the EPA has refined its approach to quantifying the 
emission reductions achievable through heat rate improvements and no 
longer includes a separate increment of emission reductions 
attributable to equipment upgrades. Also, rather than evaluating the 
emission reductions available from these measures on a nationwide basis 
as in the proposal, the EPA has quantified the emission reductions 
achievable through building block 1 on a regional basis, consistent 
with the EPA's proposals to better reflect the regional nature of the 
interconnected electrical system and the treatment of the other 
building blocks in this final rule. As a result of these refinements, 
the EPA is identifying the heat rate improvements achievable by coal-
fired steam EGUs as 4.3 percent for the Eastern Interconnection, 2.1 
percent for the Western Interconnection, and 2.3 percent for the Texas 
Interconnection. The refinements are based, in significant part, on the 
numerous comments we received on our proposed approaches, especially 
those from states and utilities.
    These heat rate improvement measures include best practices such as 
improved staff training, boiler chemical cleaning, cleaning air 
preheater coils, and use of various kinds of software, as well as 
equipment upgrades such as turbine overhauls. These are measures that 
the owner/operator of an affected coal-fired steam EGU may take that 
would have the effect of reducing the amount of CO2 the 
source emits per MWh. As a result, these measures would help the source 
achieve an emission limit expressed as either an emission rate limit or 
as a mass limit. We note again that in the context both of the 
integrated electricity system and of available and anticipated state 
approaches to setting standards of performance, emissions trading 
approaches could be used as mechanisms through which one affected EGU 
could invest in heat rate improvements at another EGU. We note this 
aspect below in describing the actions an individual affected EGU can 
take to implement the BSER and discuss it in more detail in section 
V.A.2.f.
    These heat rate improvements are a low-cost option that fit the 
criteria for the BSER, except that they lead to only small emission 
reductions for the source category.\370\ Given the magnitude of the 
environmental problem and projections by climate scientists that much 
larger emission reductions are needed from fossil fuel-fired EGUs to 
address climate change, the EPA looked at additional measures to reduce 
emission rates. This reflects our conclusion that, given the 
availability of other measures capable of much greater emission 
reductions, the emission reductions limited to this set of heat rate 
improvement measures would not meet one of the considerations critical 
to the BSER determination--the quantity of emissions reductions 
resulting from the application of these measures is too small for these 
measures to be the BSER by themselves for this source category.
---------------------------------------------------------------------------

    \370\ As further discussed below, if heat rate improvements at 
coal-fired steam EGUs were implemented in isolation, without other 
measures to reduce CO2 emissions, the heat rate 
improvements could lead to increases in competitiveness and 
utilization of the coal-fired EGUs--a so-called ``rebound effect''--
causing increases in CO2 emissions that could partially 
or even entirely offset the CO2 emission reductions 
achieved through the reductions in the amount of CO2 
emissions per MWh of generation.
---------------------------------------------------------------------------

    Specifically, as described in the proposal, the EPA also considered 
co-firing (including 100 percent conversion) with natural gas, a 
measure that presented itself in part because of the recent increase in 
availability and reduction in price of natural gas, and the industry's 
consequent increase in reliance on natural gas.\371\ The EPA also 
considered implementation of carbon capture and storage (CCS).\372\ The 
EPA found that some of these co-firing and CCS measures are technically 
feasible and within price ranges that the EPA has found to be cost 
effective in the context of other GHG rules, that a segment of the 
source category may implement these measures, and that the resulting 
emission reductions could be potentially significant.
---------------------------------------------------------------------------

    \371\ The EPA further addressed co-firing in the October 30, 
2014 NODA. 79 FR 64549-51.
    \372\ CCS is also sometimes referred to as carbon capture and 
sequestration.
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    However, these co-firing and CCS measures are more expensive than 
other available measures for existing sources. This is because the 
integrated nature of the electricity system affords significantly lower 
cost options, ones that fossil fuel-fired power plants

[[Page 64728]]

throughout the U.S. and in foreign nations are already using to reduce 
their CO2 emissions.
    The less expensive options include shifting generation to existing 
NGCC units--an option that has become particularly attractive in light 
of the increased availability and lower prices of natural gas--as well 
as shifting generation to new RE generating units. A comparison of the 
costs of converting an existing coal-fired boiler to burn 100 percent 
natural gas compared to the cost of shifting generation to an existing 
NGCC unit illustrates this point. Because an NGCC unit burns natural 
gas significantly more efficiently than an affected steam EGU does, the 
cost of shifting generation from the steam EGU to an existing NGCC unit 
is significantly cheaper in most cases than more aggressive emission 
rate reduction measures at the steam EGU. As a result, as a practical 
matter, were the EPA to include co-firing and CCS in the BSER and 
promulgate performance standards accordingly, few EGUs would likely 
comply with their emission standards through co-firing and CCS; rather, 
the EGUs would rely on the lower cost options of substituting lower- or 
zero-emitting generation or, as a related matter, reducing 
generation.\373\
---------------------------------------------------------------------------

    \373\ Many EGUs would also rely on demand-side energy efficiency 
measures.
---------------------------------------------------------------------------

    The EPA also considered heat rate improvement opportunities at oil- 
and gas-fired steam EGUs and NGCC units and found that the available 
emission reductions would likely be more expensive or too small to 
merit consideration as a material component of the BSER.
    Thus, in reviewing the entire range of control options, it became 
clear that controlling CO2 from affected EGUs at levels that 
are commensurate with the sector's contribution to GHG emissions and 
thus necessary to mitigate the dangers presented by climate change, 
could depend in part, but not primarily, on measures that improve 
efficiency at the power plants. Rather, most of the CO2 
controls need to come in the form of those other measures that are 
available to the utility power sector thanks specifically to the 
integrated nature of the electricity system, and that involve, in one 
form or another, replacement of higher emitting generation with lower- 
or zero-emitting generation.
    Although the presence of lower-cost options that achieve the 
emission reduction goals means that the EPA is not identifying either 
natural gas co-firing or CCS at coal-fired steam EGUs, or heat rate 
improvements at other types of EGUs, as part of the BSER, those 
controls remain measures that some affected EGUs may be expected to 
implement and that as a result, will provide reductions that those 
affected EGUs may rely on to achieve their emission limits or may sell, 
through emissions trading, to other affected EGUs to achieve emission 
limits (to the extent permitted under the relevant section 111(d) 
plans). Another example of a non-BSER measure that an affected EGU in 
certain circumstances could choose to implement is the conversion of 
waste heat from electricity generation into useful thermal energy. The 
EPA further discusses the potential use of these non-BSER measures for 
compliance flexibility below.
    The EPA's quantification of the CO2 emission reductions 
achievable through heat rate improvements as a component of the BSER 
(building block 1) is discussed in section V.C. of this preamble and in 
the GHG Mitigation Measures TSD for the CPP Final Rule.
    (2) Measures available because of the integrated electricity 
system.
    To determine the BSER that meets the expectations and requirements 
of the CAA, including the achievement of meaningful reductions of 
CO2, the EPA turned next to the set of measures that 
presented themselves as a result of the fact that the operations of 
individual affected EGUs are interdependent on and integrated with one 
another and with the overall electricity system. Those are the measures 
in the categories represented in the proposal by building blocks 2, 3, 
and 4. This section discusses the components of the BSER that relate to 
building blocks 2 and 3, which the EPA is finalizing as components of 
the BSER. This section also discusses the measures comprising the 
proposed building block 4, which the EPA is not including in the BSER 
in this final rule.
    It bears reiterating that the extent to which the operations of 
individual affected EGUs are integrated with one another and with the 
overall electricity system is a highly salient and unique attribute of 
this source category. Because of this integration, the individual 
sources in the source category operate through a network that 
physically connects them to each other and to their customers, an 
interconnectedness that is essential to their operation under the 
status quo and by all indications is projected to be augmented further 
on a continual basis in the future to address fundamental objectives of 
reliability assurance and cost reduction. This physical 
interconnectedness exists to serve a set of interlocking regimes that, 
to a substantial extent, determine, if not dictate, any given EGU's 
operations on a nearly moment-to-moment basis. In analyzing BSER from 
the perspective of the overall source category, because the affected 
EGUs are connected to each other operationally, a combination of 
dispatching and investment in lower- and zero-emitting generation 
allows the replacement of higher-emitting generation with lower-
emitting and zero-emitting generation (measures in building blocks 2 
and 3), and thereby reduces emissions while continuing to serve load.
    As noted above, substitution of higher-emitting generation for 
lower- or zero-emitting generation may include reduced generation, 
depending on the specific action taken by the individual EGU. Likewise, 
when incorporated into standards of performance, emissions trading 
mechanisms may be readily used for implementing these building blocks. 
We discuss these aspects below in describing the actions that 
individual sources may take to implement the building blocks.
    (a) Substituting generation from lower-emitting affected EGUs for 
generation from higher-emitting affected EGUs.
    In the proposal, the EPA observed that substantial CO2 
emission reductions could be achieved at reasonable cost by increasing 
generation from existing NGCC units and commensurately reducing 
generation from steam EGUs. Because NGCC units produce much less 
CO2 per MWh of generation than steam EGUs--typically less 
than half as much CO2 as coal-fired steam EGUs, which 
account for most generation from steam EGUs--this generation shift 
reduces CO2 emissions. We also noted that because NGCC units 
can generate as much as 46 percent more electricity from a given 
quantity of natural gas than a steam unit can, generation shifting from 
coal-fired steam EGUs to existing NGCC units is a more cost-effective 
strategy for reducing CO2 emissions from the source category 
than converting coal-fired steam EGUs to combust natural gas or co-
firing coal and natural gas in steam EGUs. We proposed to find that 
shifting generation consistent with a 70 percent target utilization 
rate (based on nameplate capacity) for NGCC units was feasible and 
should be a component of the BSER.
    As described in section V.D. below, analysis reflecting 
consideration of the many comments we received on the EPA's proposal 
with respect to this issue supports the inclusion of generation 
shifting from higher-emitting to lower-emitting EGUs as a component of 
the BSER. Shifting of generation

[[Page 64729]]

among EGUs is an everyday occurrence within the integrated operations 
of the utility power sector that is used to ensure that electricity is 
provided to meet customer demands in the most economic manner 
consistent with system constraints. Generation shifting to lower-
emitting units has been recognized as an approach for reducing 
emissions in other EPA rules such as CSAPR.
    The EPA's analysis continues to show that the magnitude of emission 
reductions included in the proposed rule from generation shifting is 
achievable. In response to our request for comment on the proposed 
target utilization rates, some commenters stated that summer capacity 
ratings are a more appropriate basis upon which to compute a target 
utilization than nameplate capacity ratings used at proposal. We agree, 
and accordingly, using the same data on historical generation as at 
proposal, we have reanalyzed feasible NGCC utilization levels expressed 
in terms of summer capacity ratings and have found that a 75 target 
utilization rate based on summer capacity ratings is feasible.
    The EPA is finalizing a determination that generation shift from 
higher-emitting affected EGUs to lower-emitting affected EGUs is a 
component of the BSER (building block 2). Our quantification of the 
associated emission reductions is discussed in section V.D. of this 
preamble and in the GHG Mitigation Measures TSD for the CPP Final Rule.
    (b) Substituting increased generation from new low- or zero-carbon 
generating capacity for generation from affected EGUs.
    Reducing generation from fossil fuel-fired EGUs and replacing it 
with generation from lower- or zero-emitting EGUs is another method for 
reducing CO2 emissions from the utility power sector. In the 
proposal, the EPA identified RE generating capacity and nuclear 
generating capacity as potential sources of lower- or zero-
CO2 generation that could replace higher-CO2 
generation from affected EGUs.
    (i) Increased generation from new RE generating capacity.
    The EPA's survey of trends and actions already being taken in the 
utility power sector indicated that RE generating capacity and 
generation have grown rapidly in recent years, in part because of the 
environmental benefits of shifting away from fossil fuel-fired 
generation and in part because of improved economics of RE generation 
relative to fossil fuel-fired generation. It is clear that increasing 
the amount of new RE generating capacity and allowing the increased RE 
generation to replace generation from fossil fuel-fired EGUs can reduce 
CO2 emissions from the affected source category. 
Accordingly, we proposed to include replacement of defined quantities 
of fossil generation by RE generation in the BSER.
    The EPA is finalizing the determination that substitution of RE 
generation from new RE generating capacity is a component of the BSER 
but, with the benefit of comments responding to the EPA's proposals on 
regionalization and techno-economic analytic approaches, the EPA has 
adjusted the approach for determining the quantities of RE generation. 
As part of the adjustment in approach, we have also refocused the 
quantification solely on generation from new RE generating capacity 
rather than total (new and existing) RE generating capacity as in the 
proposal. Our quantification of the RE generation component of the BSER 
is discussed in section V.E. of the preamble and in the GHG Mitigation 
Measures TSD for the CPP Final Rule.
    (ii) Increased and preserved generation from nuclear generating 
capacity.
    In the June 2014 proposal, the EPA also identified the replacement 
of generation from fossil fuel-fired EGUs with generation from nuclear 
units as a potential approach for reducing CO2 emissions 
from the affected source category. We proposed to include two elements 
of nuclear generation in the BSER: An element representing projected 
generation from nuclear units under construction; and an element 
representing preserved generation from existing nuclear generating 
capacity at risk of retirement, and we took comment on all aspects of 
these proposals.
    Like generation from new RE generating capacity, generation from 
new nuclear generating capacity can clearly replace fossil fuel-fired 
generation and thereby reduce CO2 emissions. However, there 
are also important differences between these types of low- or zero-
CO2 generation. Investments in new nuclear capacity are very 
large capital-intensive investments that require substantial lead 
times. By comparison, investments in new RE generating capacity are 
individually smaller and require shorter lead times. Also, important 
recent trends evidenced in RE development, such as rapidly growing 
investment and rapidly decreasing costs, are not as clearly evidenced 
in nuclear generation. We view these factors as distinguishing the 
under-construction nuclear units from RE generating capacity, 
indicating that the new nuclear capacity is likely of higher cost and 
therefore less appropriate for inclusion in the BSER. Accordingly, as 
described in section V.A.3., the EPA is not finalizing increased 
generation from under-construction nuclear capacity as a component of 
the BSER.
    The EPA is likewise not finalizing the proposal to include a 
component representing preserved existing nuclear generation in the 
BSER. On further consideration, we believe it is inappropriate to base 
the BSER on elements that will not reduce CO2 emissions from 
affected EGUs below current levels. Existing nuclear generation helps 
make existing CO2 emissions lower than they would otherwise 
be, but will not further lower CO2 emissions below current 
levels. Accordingly, as described in section V.A.3., the EPA is not 
finalizing preservation of generation from existing nuclear capacity as 
a component of the BSER.
    (iii) Generation from new NGCC units.
    New NGCC units--that is, units that had not commenced construction 
as of January 8, 2014, the date of publication of the proposed 
CO2 standards of performance for new EGUs under section 
111(b)--are not subject to the standards of performance that will be 
established for existing sources under section 111(d) plans based on 
the BSER determined in this final rule. In the June 2014 proposed 
emission guidelines for existing EGUs, the EPA solicited comment on 
whether to include this measure in the BSER. Commenters raised numerous 
concerns, and after consideration of the comments, we are not including 
replacement of generation from affected EGUs through the construction 
of new NGCC capacity in the BSER. In this section, we discuss the 
reasons for our approach.
    The EPA did not include reduced generation from affected EGUs 
achieved through construction and operation of new NGCC capacity in the 
proposed BSER because we expected that the CO2 emission 
reductions achieved through such actions would, on average, be more 
costly than CO2 emission reductions achieved through the 
proposed BSER measures. However, our determination not to include new 
construction and operation of new NGCC capacity in the BSER in this 
final rule rests primarily on the achievable magnitude of emission 
reductions rather than costs.
    Unlike emission reductions achieved through the use of any of the 
building blocks, emission reductions achieved through the use of new 
NGCC capacity require the construction of additional CO2-
emitting generating capacity, a consequence that is inconsistent with

[[Page 64730]]

the long-term need to continue reducing CO2 emissions beyond 
the reductions that will be achieved through this rule. New generating 
assets are planned and built for long lifetimes--frequently 40 years or 
more--that are likely longer than the expected remaining lifetimes of 
the steam EGUs whose CO2 emissions would initially be 
displaced be the generation from the new NGCC units. The new capacity 
is likely to continue to emit CO2 throughout these longer 
lifetimes, absent decisions to retire the units before the end of their 
planned lifetimes or to install CCS technology in the future at 
substantial additional cost. Because of the likelihood of 
CO2 emissions for decades, the overall net emission 
reductions achievable through the construction and operation of new 
NGCC are less than for the measures including in the BSER, such as 
increased generation at existing NGCC capacity, which would be expected 
to reach the end of its useful life sooner than new NGCC capacity, or 
construction and operation of zero-emitting RE generating capacity. We 
view the production of long-term CO2 emissions that 
otherwise would not be created as inconsistent with the BSER 
requirement that we consider the magnitude of emissions reductions that 
can be achieved. For this reason, we are not including replacement of 
generation from affected EGUs through the construction and operation of 
new NGCC capacity in the final BSER.
    Commenters also raised a concern with the interrelation of section 
111(b) and section 111(d). New NGCC capacity is distinguished from the 
other non-BSER measures discussed above by the fact that its 
CO2 emissions would be subject to the CO2 
standards for new EGUs being established under section 111(b). Section 
111 creates an express distinction between the sources subject to 
section 111(b) and the sources subject to section 111(d), and 
commenters expressed concern that to allow section 111(b) sources to 
play a direct role in setting the BSER under section 111(d) would be 
inconsistent with congressional intent to treat the two sets of sources 
separately. Section VIII of this preamble includes a discussion of ways 
to address new NGCC capacity in the context of different types of 
section 111(d) plans.
    (c) Increasing demand-side EE to avoid generation and emissions 
from fossil fuel-fired EGUs.
    The final category of approaches for reducing generation and 
CO2 emissions from affected EGUs that the EPA considered in 
the proposal involves increasing demand-side EE. When demand-side EE is 
increased, energy consumers need less electricity in order to provide 
the same level of electricity-dependent services--e.g., heating, 
cooling, lighting, and use of motors and electronic devices. Through 
the integrated electricity system, including the connection of 
customers to affected EGUs through the electricity grid, reduced demand 
for electricity, in turn, leads to reduced generation and reduced 
CO2 emissions. Our examination of actions and trends 
underway in the utility power sector confirmed that investments in 
demand-side EE programs are increasing. We proposed to include 
avoidance of defined quantities of fossil fuel-fired generation through 
increased demand-side EE as a component of the BSER (proposed building 
block 4). However, we also took comment on which building blocks should 
comprise the BSER and on our determination as to whether each building 
block met the various statutory factors.
    Commenters expressed a wide range of views on the proposed reliance 
on demand-side EE in the BSER. Some commenters strongly supported the 
proposal, with suggestions for improvements, while some commenters 
strongly opposed the proposal and took the position that it exceeded 
the EPA's legal authority. We do not address the merits of these 
comments here because, for the reasons discussed in section V.B.3.c.(8) 
below, we are not finalizing the proposal to include avoided generation 
achieved through demand-side EE as a component of the BSER. However, we 
note that most commenters also supported the use of demand-side EE for 
compliance whether or not it is used in determining the BSER, and we 
are allowing demand-side EE to be used for that purpose. (We also 
emphasize that the emission limitations reflective of the BSER are 
achievable even if aggregate generation is not reduced through demand-
side EE.)
    (3) Further analysis to quantify the BSER.
    While the discussion above summarizes how and why the components of 
the BSER were determined in terms of qualitative characteristics, it 
still leaves a wide range of potential stringencies for the BSER. As 
explained in sections V.C., V.D., and V.E. below, discussing building 
blocks 1, 2, and 3 respectively, the EPA has determined a reasonable 
level of stringency for each of the building blocks rather than the 
maximum possible level of stringency. We have taken this approach in 
part to ensure that there is ``headroom'' within the BSER measures that 
provides greater assurance of the achievability of the BSER for the 
source category and for individual sources. We believe this approach is 
permissible under the CAA. Another aspect of our methodology for 
computing the CO2 emission performance rates, further 
described in section V.A.3.f. and section VI, is that the 
CO2 emission performance rate applicable to a given source 
subcategory in all three interconnections reflects the emission rate 
achievable by that source subcategory through application of the 
building blocks in the interconnection where that achievable emission 
rate is the highest (i.e., least stringent).\374\ This aspect of our 
methodology not only ensures that the nationwide CO2 
emission performance rates are achievable by affected EGUs in all three 
interconnections but also provides additional headroom within the BSER 
for affected EGUs in the two interconnections that did not set the 
CO2 emission performance rates ultimately used. Additional 
headroom within the BSER is available through the use of emissions 
trading approaches, because the final rule does not limit the use of 
these mechanisms to sources within the same interconnections. In fact, 
in response to proposals that emerged from the comment record and 
direct engagement with states and stakeholders reflecting their strong 
interest in pursuing multi-state approaches, the guidelines include 
mechanisms for implementing standards of performance that incorporate 
interstate trading, as discussed in section VIII. (In addition, as 
further discussed below, the rule also permits section 111(d) plans to 
allow the use of non-BSER measures for compliance in certain 
circumstances, increasing both compliance flexibility and the assurance 
that the emission limitations reflecting application of the BSER are 
achievable.)
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    \374\ Specifically, the annual CO2 emission 
performance rates applicable to steam EGUs in all three 
interconnections are the annual emission rates achievable by that 
subcategory in the Eastern Interconnection through application of 
the building blocks. Similarly, the annual CO2 emission 
performance rates applicable to stationary combustion turbines in 
all three interconnections are the annual emission rates achievable 
by that subcategory in the Texas Interconnection for years from 2022 
to 2026, and in the Eastern Interconnection for years from 2027 to 
2030, through application of the building blocks. Additional 
information is provided in the CO2 Emission Performance 
Rate and State Goal Computation TSD in the docket.
---------------------------------------------------------------------------

    Further, the sets of measures in each of these individual building 
blocks, in the stringency assigned in this rule, meet the criteria for 
the BSER. That is, they each achieve the appropriate level of 
reductions, are of reasonable cost, do not impose energy penalties on 
the

[[Page 64731]]

affected EGUs and do not result in non-air quality pollutants, and have 
acceptable cost and energy implications on a source-by-source basis and 
for the energy sector as a whole. In addition, as explained below, each 
is adequately demonstrated. Importantly, past industry practice and 
current trends strongly support each of the building blocks, as do 
federal and state pollution control programs that require or result in 
similar measures.
    For example, all of the measures in building blocks 2 and 3 have 
been implemented for decades, initially for reasons unrelated to 
pollution control, then in recent years in order to control non-GHG air 
pollutants, and more recently, for purposes of CO2-emission 
control by states and companies. Moreover, Congress itself recognized 
in enacting the acid rain provisions of CAA Title IV that RE measures 
reduce CO2 from affected EGUs. In addition, the EPA has 
relied on the measures in building blocks 2 and 3 in other rules.
    It should also be noted that building blocks 2 and 3 also meet the 
criteria for the BSER in combination with one another and with building 
block 1, as described below.
    e. Actions that individual affected EGUs could take to apply or 
implement the building blocks. We now turn to a summary of measures or 
actions that individual EGUs could take to apply or implement the 
building blocks and that are therefore, in that sense, part of the 
BSER.
    (1) Improvement in CO2 emission rate at the unit.
    An affected EGU may take steps to improve its CO2 
emission rate as discussed above for the source category as a whole. As 
discussed in section V.C., the record makes clear that coal-fired steam 
EGUs can make, and have made, heat rate improvements to a greater or 
lesser degree, resulting in reductions in CO2 emissions. The 
resulting improvement in an EGU's CO2 emission rate would 
help the EGU achieve an emission limit imposed in the form of an 
emission rate. If the EGU's emission limit is imposed in the form of a 
mass standard, the heat rate improvement would also lower the EGU's 
mass emissions provided that the EGU held the amount of its generation 
constant or increased its generation by a smaller percentage than the 
efficiency improvement. Under a mass-based standard that incorporates 
emission trading, an EGU that improves its heat rate would need fewer 
emission allowances for each MWh of generation whatever level of 
generation it chose to produce.
    (2) Actions to implement measures in building blocks 2 and 3.
    Viewing the BSER from the perspective of an individual EGU, there 
are several ways that affected EGUs can access the measures in building 
blocks 2 and 3, thanks to the integrated nature of the electricity 
system, coupled with the system's high degree of planning and 
reliability mechanisms. The affected EGUs can: (a) Invest in lower- or 
zero-emitting generation, which will lead to reductions in higher-
emitting generation at other units in the integrated system; (b) reduce 
their generation, which in the presence of emission reduction 
requirements applicable to the source category as a whole will have the 
effect of increasing demand for, and thereby incentivize investment in, 
the measures in the building blocks elsewhere in the integrated system; 
or (c) both invest in the measures in the building blocks and reduce 
their own generation, effectively replacing their generation with 
cleaner generation. The availability of these options is further 
enhanced where the individual EGU is operating under a standard of 
performance that incorporates emissions trading.
    (a) Investment in measures in building blocks 2 and 3.
    An affected EGU may take the following actions to invest in the 
measures in building blocks 2 and 3. For building block 2, the owner/
operator of a steam EGU may increase generation at an existing NGCC 
unit it already owns, or one that it purchases or invests in. In 
addition, the owner/operator may, through a bilateral transaction with 
an existing NGCC unit, pay the unit to increase generation, and acquire 
the CO2-reducing effects of that increased generation in the 
form of a credit, as discussed below.
    Similarly, for building block 3, an owner/operator of an affected 
EGU may build, or purchase an ownership interest in, new RE generating 
capacity and acquire the CO2-reducing effects of that 
increased generation. Alternatively, an owner/operator may, through 
bilateral transactions, purchase the CO2-reducing effects of 
that increased generation from renewable generation providers, again, 
in the form of a credit.
    In case of an investment in either building block 2 or building 
block 3 by a unit subject to a rate-based form of CO2 
performance standard, it would be reasonable for state plans to 
authorize affected EGUs to use an approved and validated instrument 
such as an ``emission rate credit'' (ERC) representing the emissions-
reducing benefit of the investment.\375\
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    \375\ Criteria for issuance of valid ERCs and for tracking 
credits after issuance are discussed in section VIII below.
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    When combined with reduced generation, either at the affected EGU 
or elsewhere in the interconnected system, the types of actions listed 
above would be fully equivalent to building blocks 2 and 3 when viewed 
from the perspective of the overall source category. Thus, a source 
could achieve a standard of performance identical to the applicable 
CO2 emission performance rate in the EPA emission 
guidelines, through implementation of the actions described above for 
building blocks 2 and 3, along with the actions described further above 
for building block 1.
    The EPA anticipates that in instances where section 111(d) plans 
provide for the use of instruments such as ERCs as a mechanism to 
facilitate use of these measures, organized markets will develop so 
that owner/operators of affected EGUs that have invested in measures 
eligible for the issuance of ERCs will be able to sell those credits 
and other affected EGUs will be able to purchase them. Such markets 
have developed for other instruments used for emissions trading 
purposes. For example, liquid markets for SO2 allowances 
developed rapidly following the implementation of Title IV of the 1990 
Clean Air Act Amendments establishing the Acid Rain Program. Members of 
Congress and industry had expressed concern during the legislative 
debate that the lack of a liquid SO2 allowance market would 
create challenges for affected sources that needed to acquire 
allowances to meet their compliance obligations. Congress added 
statutory provisions to ensure that, should a market not develop, 
sources could purchase needed allowances directly from the EPA. In 
fact, these provisions went unused because a liquid market for 
allowances did develop very quickly. Sources engaged in allowance 
transactions directly with other sources as they sought to lower 
compliance costs. Market intermediaries offered services to sources to 
match allowance buyers and sellers and helped sources understand their 
compliance options. Trade associations worked with members to develop 
standardized contracts and other tools to facilitate allowance 
transactions, thereby reducing transaction costs. Similar developments 
have occurred in state-

[[Page 64732]]

level renewable portfolio standard programs.\376\
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    \376\ The emergence of markets under the Acid Rain Program and 
other environmental programs where trading has been permitted, as 
well as state and industry support for the development of markets 
under states' section 111(d) plans, is discussed in a recent report 
by the Advanced Energy Economy Institute. AEE Institute, Markets 
Drive Innovation--Why History Shows that the Clean Power Plan Will 
Stimulate a Robust Industry Response (July 2015), available at 
https://www.aee.net/aeei/initiatives/epa-111d.html#epa-reports-and-white-papers.
---------------------------------------------------------------------------

    If states choose to allow through their section 111(d) plans 
mechanisms or standards of performance involving instruments such as 
ERCs, the EPA believes that there would be an ample supply of such 
credits, for several reasons. First, as discussed in sections V.D. and 
V.E., the EPA has established the stringencies for building blocks 2 
and 3 at levels that are reasonable and not at the maximum achievable 
levels, providing headroom for investment in the measures in these 
building blocks beyond the amounts reflected in the CO2 
emission performance rates reflecting application of the BSER. In 
addition, if emission limits are set at the CO2 emission 
performance rates, affected EGUs in two of the three interconnections 
on average do not need to implement the building blocks to their full 
available extent in order to achieve their emission limits (because the 
performance rates for each source category are the emission rates 
achievable by that source subcategory through application of the 
building blocks in the interconnection where that achievable emission 
rate is the highest), providing further opportunities in those 
interconnections to generate surplus emission reductions that could be 
used as the basis for issuance of ERCs. Further, to the extent that 
section 111(d) plans take advantage of the latitude the final 
guidelines provide for states to set standards of performance 
incorporating emissions trading on an interstate basis among affected 
EGUs in different interconnections, all sources can take advantage of 
the headroom available in other interconnections. As a result, 
significant amounts of existing NGCC capacity and potential for RE 
remain available to serve as the basis for issuance of ERCs for all 
affected EGUs in both source subcategories to rely on to achieve their 
emission limits. Because we recognize the ready availability to states 
of standards of performance that incorporate emissions trading--and 
because such standards can easily encompass interstate trading--this 
rule includes by express design a variety of options that states and 
utilities can select to pursue interstate compliance regimes that 
mirror the interconnected operation of the electricity system. As a 
result, the EPA believes that it is reasonable to anticipate that a 
virtually nationwide emissions trading market for compliance will 
emerge, and that ERCs will be effectively available to any affected EGU 
wherever located, as long as its state plan authorizes emissions 
trading among affected EGUs.\377\
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    \377\ There is a theoretical possibility--which we view as 
extremely unlikely--that the affected EGUs in a given state or group 
of states that has chosen to pursue a technology-specific rate-based 
approach could have insufficient access to ERCs because of the 
choices of certain other states to pursue mass-based or blended-rate 
approaches. We view this as very unlikely in part because of the 
conservative assumptions used in calculating the emission reductions 
available through the building blocks and the broad availability of 
non-BSER emission reduction opportunities, such as energy 
efficiency, that will generate ERCs. If such a situation arises, and 
the state or states implementing the technology-specific rates does 
not have, within the state or states, sufficient ERC-generation 
potential to match their compliance requirements, the EPA will work 
with the state or states to ensure that there is a mechanism that 
the state or states can include in their state plans to allow the 
affected EGUs in the state or states to generate additional ERCs 
where the state or states can demonstrate that the ERCs do not 
represent double-counting under other state programs. One potential 
mechanism would be to assume for purposes of demonstrating 
compliance with their standards of performance that the generation 
replacing any reductions in generation at those affected EGUs that 
was not paired with verified ERCs came from existing NGCC units in 
other states from which ERCs were not accessible. In other words, 
any reductions in fossil steam generation from 2012 levels in a 
state or states that was implementing technology-specific rates that 
could not be matched by increases in NGCC generation or by ERCs from 
zero-emitting sources, and for which it could be demonstrated that 
no further ERCs can be procured, could generate building block 2 
ERCs as if that level of displaced generation were NGCC generation. 
A demonstration that no further ERCs are procurable would have to 
include demonstrations that the capacity factor of all NGCC 
generation in the state or states was expected to be greater than 75 
percent and that further deployment of RE would go beyond the 
amounts found available in the BSER. States could distribute these 
additional ERCs to ensure compliance by affected EGUs. Before such 
ERCs could be created by a state or states, a framework would have 
to be submitted to the EPA for approval including documentation of 
the levels of fossil steam and NGCC generation in the state or 
states, a demonstration that no further ERCs are accessible, and the 
total amount of building block 2 ERCs to be created.
---------------------------------------------------------------------------

    It should also be noted that although in a state that sets emission 
limits in a rate-based form the measures in building blocks 2 and 3 can 
be taken into account directly in computations to determine whether an 
individual affected EGU has achieved its emission limit, in a state 
that sets emission limits in a mass-based form these measures are not 
taken into account directly in computations to determine whether an 
individual affected EGU has achieved its emission limit. However, by 
reducing generation and therefore CO2 emissions from the 
group of affected EGUs within a region, in a state with mass-based 
limits implementation of these measures facilitates the ability of the 
individual EGUs within the region to achieve their limits by choosing 
to reduce their own generation and emissions.
    (b) Reduced generation.
    In addition, the owner/operator of an affected EGU may help itself 
meet its emission limit by reducing its generation. If the owner/
operator reduces generation and therefore the amount of its 
CO2 emissions, then, if the affected EGU is subject to an 
emission rate limit, the owner/operator will need to implement fewer of 
the building block measures, e.g., buy fewer ERCs, to achieve its 
emission rate; and if the affected EGU is subject to a mass emission 
limit, the owner/operator will need fewer mass allowances. As discussed 
below, at the levels that the EPA has selected for the BSER, reduced 
generation at higher-emitting EGUs does not decrease the amount of 
electricity available to the system and end users because lower-
emitting (or zero-emitting) generation will be available from other 
sources.
    An owner/operator may take actions to ensure that it reduces its 
generation. For example, it may accept a permit restriction on the 
amount of hours that it generates. In addition or alternatively, it may 
represent the cost of additional emission credits or allowances that 
would be required due to incremental generation as an additional 
variable cost that increases the total variable cost considered when 
dispatch decisions are made for the unit.
    Because of the integrated nature of the electricity system, 
combined with the system's high degree of planning and reliability 
safeguards, as well as the long planning horizon afforded by this rule, 
individual affected EGUs can implement the building blocks by reducing 
generation to achieve their emission performance standards.\378\ 
Individual affected steam EGUs can reduce their generation in the 
amounts of building blocks 2 and 3, while individual affected NGCC 
units can reduce their generation in the amount of building block 3. 
With emission limits for the source category as a whole in place, the 
resulting reduction in supply of higher-emitting generation will 
incentivize additional utilization of existing NGCC capacity, the 
resulting reduction in overall fossil fuel-fired

[[Page 64733]]

generation will incentivize investment in additional RE generating 
capacity, and the integrated system's response to these incentives will 
ensure that there will be sufficient electricity generated to continue 
to meet the demand for electricity services.
---------------------------------------------------------------------------

    \378\ For purposes of this discussion, we assume that coal-fired 
steam generators also implement building block 1 measures so that 
they will implement the full set of measures needed to achieve their 
emission limit.
---------------------------------------------------------------------------

    (c) Emissions trading.
    As described above, viewed from the perspective of the source 
category as a whole, it is reasonable for our analysis of the BSER to 
include an element of source-category-wide multi-unit compliance which 
could be implemented via a state-set standard of performance 
incorporating emissions trading, under which EGUs could engage in 
trading of rate-based emission credits or mass-based emission 
allowances. By the same token, viewed from the perspective of an 
individual EGU, consideration of the ready availability to states of 
the opportunity to establish standards of performance that incorporate 
emissions trading is integral to our analysis. Accordingly, our 
assessment of the actions available to individual EGUs for achieving 
standards of performance reflecting the BSER includes the purchase of 
rate-based emission credits or mass-based emission allowances, because 
one of the things an affected EGU can do to achieve its emission limit 
is to buy a credit or an allowance from another affected EGU that has 
over-complied. The use of purchased credits or allowances would have to 
be authorized, of course, in the purchasing EGUs' states' section 
111(d) plans and would have to meet conditions set out for such 
approaches in section VIII below. The role of emissions trading in the 
BSER analysis is discussed further in section V.A.2.f. below.
    f. The role of emissions trading. In making its BSER determination 
here, the EPA examined a number of technologies and emission reduction 
measures that result in lower levels of CO2 emissions and 
evaluated each one on the basis of the several criteria on which the 
EPA relies in determining the BSER. In contrast to section 111(b), 
however, section 111(d)(1) obliges the states, not the EPA, to set 
standards of performance for the affected EGUs in order to implement 
the BSER. Accordingly, with respect to each measure or control strategy 
under consideration, the EPA also evaluated whether or not the states 
could establish standards of performance for affected EGUs that would 
allow those sources to adopt the measure in question. In this case, the 
EPA identified a host of factors that persuaded us that states could-- 
and, in fact, may be expected to--establish standards of performance 
that incorporate emissions trading.\379\ These wide-ranging factors 
include (i) the global nature of the air pollutant in question--i.e., 
CO2; (ii) the transactional nature of the industry; (iii) 
the interconnected functioning of the industry and the coordination of 
generation resources at the level of the regional grid; (iv) the 
extensive experience that states--and EGUs--already have with emissions 
trading; and (v) material in the record demonstrating strong interest 
on the part of many states and affected EGUs in using emissions trading 
to help meet their obligations.\380\
---------------------------------------------------------------------------

    \379\ As an alternative to authorizing trading that would still 
provide a degree of multi-unit flexibility, a state could choose in 
its state plan to give an owner of multiple affected EGUs 
flexibility regarding how the owner distributes any credits or 
allowances it acquires among its affected EGUs.
    \380\ Numerous states submitted comments urging the EPA to allow 
states to develop trading programs, as suggested in the proposal, 
including interstate trading programs. They include, for example, 
Alabama (EPA should develop and issue guidelines that allow options 
for multi[hyphen]state plans and interstate credit trading programs, 
comment 23584), California (EPA should provide flexibility for 
allowance trading programs to be integrated into state plans, 
comment 23433), Hawaii (supports use of emission credit trading with 
other entities to achieve compliance, comment 23121), Massachusetts 
(EPA should explore possibility of hosting a third[hyphen]party 
emissions trading bank that can allow states interested in allowance 
trading to plug and play in to a wider, more cost[hyphen]effective 
market, comment 31910), Michigan (supports emissions trading 
programs, comment 23987), Minnesota (develop model trading rule that 
states could incorporate by reference as part of plan and 
automatically be included in multi-state mass trading program, 
comment 23987), North Carolina (EPA should examine a system of 
banking and trading for energy efficiency, comment 23542), Oregon 
(EPA should expand the explicit options for multi[hyphen]state plans 
beyond cap[hyphen]and-trade, comment 20678), Washington (supporting 
trading, comment 22764), Wisconsin (requesting EPA to develop a 
national trading program, Post[hyphen]111(d) Proposal Questions to 
EPA WI Questions for 7/16 Hub call).
    In addition, several groups of states supported trading 
programs: Georgetown Climate Center (a group of state environmental 
agency leaders, energy agency leaders, and public utility 
commissioners from California, Colorado, Connecticut, Delaware, 
Illinois, Maine, Maryland, Massachusetts, Minnesota, New Hampshire, 
New York, Oregon, Rhode Island, Vermont, and Washington) (``We 
believe states should have maximum flexibility to determine what 
kinds of collaborations might work for them. These could include 
submission of joint plans, standardized approaches to trading 
renewable or energy efficiency credits. . . . We also encourage EPA 
to help facilitate such interstate agreements or multi-state 
collaborations by working with states to either identify or provide 
a platform or framework that states may elect to use for the 
tracking and trading of avoided generation or emissions credits due 
to interstate efficiency or renewable energy.'' comment 23597, at 
39-40); RGGI (including Connecticut, Delaware, Maine, Maryland, 
Massachusetts, New Hampshire, New York, Rhode Island, Vermont) 
(``[E]very serious proposal to reduce carbon emissions from EGUs, 
from proposed US legislation to programs in place in California and 
Europe, has identified allowance trading as the best approach.'' 
Comment 22395 at 7-8); Western States Center for New Energy Economy 
(including Arizona, California, Colorado, Idaho, Montana, Nevada, 
Oregon, South Dakota, Utah, Washington) (``Some degree of RE and EE 
credit trading among states may support compliance, even in the 
absence of a comprehensive regional plan. Therefore, EPA should 
support approaches which allow states flexibility to allocate credit 
for these zero-carbon resources, along with approaches which allow 
states to reach agreements on the allocation of carbon liabilities. 
This includes ensuring that existing tracking mechanisms for 
renewable energy in the West, such as the Western Renewable Energy 
Generation Information System (WREGIS), are compatible with the 
final proposal.'' Comment 21787 at 5); Midcontinent States 
Environmental and Energy Regulators (including Arkansas, Illinois, 
Michigan, Minnesota Missouri, Wisconsin) (EPA should also provide 
states with optional . . . systems (or system) for tracking 
emissions, allowances, reduction credits, and/or generation 
attributes that states may choose to use in their 111(d) plans,'' 
comment 22535 at 3).
    In addition, trading programs were supported by, among others, a 
group of Attorneys General from 11 states and the District of 
Columbia. Comment 25433 (Attorneys General from New York, 
California, Connecticut, Maine, Maryland, Massachusetts, New Mexico, 
Oregon, Rhode Island, Vermont, Washington, District of Columbia, and 
New York City Corporation Counsel).
    Numerous industry commenters also supported trading, including 
Alliant Energy Corporate Services, Inc. (comment 22934), Calpine 
(comment 23167), DTE Energy (comment 24061), Exelon (comment 23428 
and 23155), Michigan Municipal Electric Association (MMEA) (comment 
23297), National Climate Coalition (comment 22910), Pacific Gas and 
Electric Company (comment 23198), Western Power Trading Forum (WPTF) 
(comment 22860). Environmental advocates also supported trading, 
including Clean Air Task Force (comment 22612), Environmental 
Defense Fund (comment 23140), Institute for Policy Integrity, New 
York University School of Law (comment 23418).
---------------------------------------------------------------------------

    The states' and EGUs' interest in emissions trading is rooted in 
the well-recognized benefits that trading provides. The experience of 
multiple trading programs over many years has shown that some units can 
achieve emission reductions at lower cost than others, and a system 
that allows for those lower-cost reductions to be maximized is more 
cost-effective overall to the industry and to society. Trading provides 
an affected EGU other options besides direct implementation of emission 
reduction measures in its own facility or an affiliated facility when 
lower-cost emission reduction opportunities exist elsewhere. 
Specifically, the affected EGU can cross-invest, that is, invest in 
actions at facilities owned by others, in exchange for rate-based 
emission credits or mass-based emission allowances. Through cross-
investment, trading allows each affected EGU to access the control 
measures that other affected EGUs decide to implement, which in this 
case include all the building blocks as well as other measures.
    Accordingly, our analysis of the measures under consideration in 
our BSER determination reflected the well-

[[Page 64734]]

founded conclusion that it is reasonable for states to incorporate 
emissions trading in the standards of performance they establish for 
affected EGUs and that many, if not all, would do so.\381\
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    \381\ As discussed in the Legal Memorandum, the EPA has 
promulgated other rulemakings, including the transport rulemakings--
the NOX SIP Call and CAIR, which required states to 
submit SIPs, and CSAPR, which allows SIPs--on the premise of 
interstate emission trading.
---------------------------------------------------------------------------

    Whether viewed from the perspective of an individual EGU or the 
source category as a whole, emissions trading is thus an integral part 
of our BSER analysis. Again, we concluded that this is reasonable given 
the global nature of the pollutant, the transactional and 
interconnected nature of this industry, and the long history and 
numerous examples demonstrating that, in this sector, trading is 
integral to how regulators have established, and sources have complied 
with, environmental and similar obligations (such as RE standards) when 
it was appropriate to do so given the program objective. The 
reasonableness is further demonstrated by the numerous comments (some 
of which are noted above) from industry, states, and other stakeholders 
in this rulemaking that supported allowing states to adopt trading 
programs to comply with section 111(d) and encouraged EPA to facilitate 
trading across state lines through the use of trading-ready state 
plans. The EPA's reliance on trading in its BSER determination does not 
mean, however, that states are required to establish trading programs 
(just as states are not required to implement the building blocks that 
comprise BSER). Nor does it mean that trading is the only transactional 
approach that we could have considered in setting the BSER or that 
states could use to effectuate the building blocks were they to decide 
that they did not want to take on the responsibility of running a 
trading program. Rather, it is simply a recognition of the nature of 
this industry and the long history of trading as an important 
regulatory tool in establishing regulatory regimes for this industry 
and its reasonable availability to states in establishing standards of 
performance.
    As an initial matter, trading is permissible for these emission 
guidelines because CO2 is a global pollutant; the location 
of its emission does not affect the location of the environmental harm 
it causes. For CO2, it is the total amount of emissions from 
the source category that matters, not the specific emissions from any 
one EGU. The fact that trading allows sources to shift emissions from 
one location to another does not impede achievement of the 
environmental goal of reducing CO2 pollution. In its 
character as a pollutant whose impacts extend beyond local areas, 
CO2 pollution resembles to some extent the regional 
SO2 pollution that Congress chose to address with the 
emissions trading program enacted in Title IV of the 1990 CAA 
Amendments. The argument in support of trading approaches is even 
stronger for CO2 pollution, whose adverse effects are global 
rather than merely regional like the SO2 emissions 
contributing to acid precipitation.
    Further, as discussed elsewhere in the preamble, the utility power 
sector--and the affected EGUs and other generation assets that it 
encompasses--has a long history of working on a coordinated basis to 
meet operating and environmental objectives, necessitated and 
facilitated by the unique interconnectedness and interdependence of the 
sector. That history includes joint dispatch for economic and 
reliability purposes, both within large utility systems and in multi-
utility power pools that have evolved into RTOs; joint power plant 
ownership arrangements; and long-term and short-term bilateral power 
purchase arrangements. More recently, the sector's history also 
includes emissions trading programs designed by Congress, the EPA, and 
the states to address regional environmental problems and, most 
recently, climate change. Examples of such programs are noted below.
    Essentially, trading does nothing more than commoditize compliance, 
with the following two important results emerging from that: It reduces 
the overall costs of controls and spreads those costs among the entire 
category of regulated entities while providing a greater range of 
options for sources that may not want to make on-site investments for 
controlling their emissions and may prefer to make the same investment, 
via the purchase of the tradable compliance instrument, at another 
generating source. Building blocks 2 and 3 entail affected EGUs 
investing in increased generation from existing NGCC units and RE. The 
affected EGUs could do so in any number of ways, including acquiring 
ownership interests in existing NGCC or RE facilities or entering into 
bilateral transactions with the owners of existing NGCC facilities or 
RE sources. As discussed elsewhere, it is reasonable to expect that 
these actions can develop into discrete, tradable commodities (e.g., an 
ERC) and that liquid markets will develop, which would reduce 
transaction costs and allow an affected EGU to comply with its emission 
limits by purchasing discrete units in amounts tailored closely to its 
compliance needs. The existence of such tradable commodities also 
incentivizes over-compliance by affected EGUs, which can then sell 
their over-compliance in the form of ERCs or allowances to other 
affected EGUs. Moreover, as noted elsewhere, the opportunity to trade 
is consistent with the EPA's regional approach for the building blocks.
    By the same token, the opportunity to trade incentivizes affected 
EGUs to over-comply with building block 1. Thus, the opportunity to 
trade supports the EPA's assumptions about what an average affected EGU 
can achieve with regards to heat rate improvement even if each and 
every affected EGU cannot achieve that level of improvement. In 
addition, trading incentivizes affected EGUs to consider low-cost, non-
BSER methods to reduce emissions as well, and, as discussed below, 
there are numerous non-BSER methods, ranging from implementation of 
demand-side EE programs to natural gas co-firing.
    Trading has become an important mechanism for achieving 
environmental goals in the electricity sector in part because trading 
allows environmental regulators to set an environmental goal while 
preserving the ability of the operators of the affected EGUs to decide 
the best way to meet it taking account of the full range of 
considerations that govern their overall operations. For example, 
commenters were concerned that because of building block 2, the 
emission guidelines would require state environmental regulators to 
make dispatch decisions for the electricity markets, a role that state 
environmental regulators do not currently play. Although building block 
2 entails substituting existing NGCC generation for steam generation, 
implementing the emission limits that are based in part on building 
block 2 through a trading program provides the individual affected EGUs 
with a great deal of control over their own generation while the 
industry as a whole achieves the environmental goals. For example, 
individual steam generators have the option of maintaining their 
generation as long as they acquire additional ERCs. Moreover, trading 
provides a way for states to set standards of performance that realize 
the required emissions reduction without requiring any form of 
``environmental dispatch'' because, as many existing trading programs 
have shown, monetization of the environmental constraint is consistent 
with a least-cost dispatch system. Trading also supports the EPA's 
approach to the ``remaining useful life'' provision in section 
111(d)(1) because with trading, an affected EGU with a

[[Page 64735]]

limited remaining useful life can avoid the need to implement long-term 
emission reduction measures and can instead purchase ERCs or other 
tradable instruments, such as mass-based allowances, thereby allowing 
the state to meet the requirements of this rule.
    The EPA's job in issuing these emission guidelines is to determine 
the BSER that has been adequately demonstrated and to set emission 
limitations that are achievable through the application of the BSER and 
implementable through standards of performance established by the 
states. The three building blocks are the EPA's determination of what 
technology is adequately demonstrated. We also consider trading an 
integral part of the BSER analysis because, in addition to being 
available to states for incorporation in the standards of performance 
they set for affected EGUs, trading has been adequately demonstrated 
for this industry in circumstances where systemic rather than unit-
level reductions are central. Congress, the EPA, and state regulators 
have established successful environmental programs for this industry 
that allow trading of environmental (or similar) attributes, and 
trading has been widely used by the industry to comply with these 
programs. Examples include the CAA Title IV Acid Rain Program, the 
NOX SIP Call (currently referred to as the NOX 
Budget Trading Program), the Clean Air Interstate Rule (CAIR), the 
Cross-State Air Pollution Rule (CSAPR),\382\ the Regional Haze trading 
programs, the Clean Air Mercury Rule,\383\ RGGI, the trading program 
established by California AB32, and the South Coast Air Quality 
Management District RECLAIM program. We describe these programs in 
section II.E. of this preamble. In addition, we note in the Legal 
Memorandum accompanying this preamble that Congress, in enacting the 
Title IV acid rain trading program, and the EPA, in promulgating the 
regulatory trading programs listed, recognized both the suitability of 
trading for the EGU industry and the benefits of trading in reducing 
costs, spreading costs to affected EGUs throughout the sector, and 
facilitating the ability of affected EGUs to comply with their emission 
limits. In addition, as we discuss in section V.E. of this preamble, 
many states have adopted RE standards that promote RE through the 
trading of renewable energy certificates (RECs).
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    \382\ For example, in CSAPR, which covered the states in the 
eastern half of the U.S., the EPA assumed the existence of trading 
across those states in the rule's cost estimates contained in the 
RIA. ``Regulatory Impact Analysis for the Federal Implementation 
Plans to Reduce Interstate Transport of Fine Particulate Matter and 
Ozone in 27 States; Correction of SIP Approvals for 22 States'' 32 
(June 2011), http://www.epa.gov/airtransport/CSAPR/pdfs/FinalRIA.pdf. In addition, the rule is being implemented either 
through federal implementation plans (FIPs) that authorize 
interstate emission trading or SIPs that authorize interstate 
emissions trading.
    \383\ Although the CAMR trading program never took effect 
because the rule was vacated on other grounds, it consisted of a 
nationwide trading program that the EPA adopted under CAA section 
111(d). Some states declined to allow their sources to participate 
in the trading program on the grounds that nationwide trading was 
not appropriate for the air pollutant at issue, mercury, a HAP that 
caused adverse local impacts.
---------------------------------------------------------------------------

    Based on this history, it is reasonable for the EPA to determine 
that states can establish standards of performance that incorporate 
trading and, as a result, for the purpose of making a BSER 
determination here to evaluate prospective emission control measures in 
light of the availability of trading. Trading is a regulatory mechanism 
that works well for this industry. The environmental attributes in the 
preceding programs (representing emissions of air pollutants) are 
identical to or similar in nature to the environmental attribute here 
(CO2 emissions). The markets for RECs show that robust 
markets for RE, in particular, already exist.
    Given the benefits of trading and the background of multi-unit 
coordination grounded in the nature of the utility power sector, it is 
natural for sources and states to look for opportunities to apply 
similar coordination to a regional problem such as reduction of 
CO2 emissions from the sector. As noted earlier, the EPA 
heard this interest expressed during the outreach process for this 
rulemaking and saw it reflected in comments on the proposal. Emissions 
trading was prominent in these expressions of interest; while the 
proposal allowed trading and encouraged the development of multi-state 
plans which would allow the benefits of trading to extend over larger 
regions, we heard that interest was even greater in ``trading-ready'' 
plans that would use trading mechanisms and market-based coordination, 
rather than state-to-state coordination, as the primary means of 
facilitating multi-unit approaches to compliance. The general industry 
and state preference for multi-unit compliance approaches makes great 
sense in the context of the industry and this pollutant, as does the 
specific preference for trading-ready section 111(d) plans, and we have 
made efforts in the final rule to accommodate trading-ready plans as 
described in section VIII.
    g. Measures that reduce CO2 emissions or CO2 
emission rates but are not included in the BSER. There are numerous 
other measures that are available to at least some affected EGUs to 
help assure that they can achieve their emission limits, even though 
the EPA is not identifying these measures as part of the BSER. These 
measures include demand-side EE implementable by affected EGUs; new or 
uprated nuclear generation; renewable measures other than those that 
are part of building block 3, including distributed generation solar 
power and off-shore wind; combined heat and power and waste heat power; 
and transmission and distribution improvements. In addition, a state 
may implement measures that yield emission reductions for use in 
reducing the obligations on affected EGUs, such as demand-side EE 
measures not implementable by affected EGUs, including appliance 
standards, building codes, and drinking water or wastewater system 
efficiency measures. The availability of these measures further assures 
that the appropriate level of emission reductions can be achieved and 
that affected EGUs will be able to achieve their emission limits.
    h. Ability of EGUs to implement the BSER. The EPA's analysis, based 
in part on observed decades-long behavior of EGUs, shows that all types 
and sizes of affected EGUs in all locations are able to undertake the 
actions described as the BSER, including investor-owned utilities, 
merchant generators, rural cooperatives, municipally-owned utilities, 
and federal utilities. Some may need to focus more on certain measures; 
for example, an owner of a small generation portfolio consisting of a 
single coal-fired steam EGU may need to rely more on cross-investment 
approaches, possibly including the purchase of emission credits or 
allowances, because of a lack of sufficient scale to diversify its own 
portfolio to include NGCC capacity and RE generating capacity in 
addition to coal-fired capacity. As a legal matter, it is not necessary 
that each affected EGU be able to implement the BSER, but in any event, 
in this rule, all affected EGUs can do so. Since states can reasonably 
be expected to establish standards of performance incorporating 
emissions trading, affected EGUs may rely on emissions trading 
approaches authorized under their states' section 111(d) plans to, in 
effect, invest in building block measures that are physically 
implemented at other locations. As discussed above, the EPA's 
quantification of the CO2 emission performance rates in a 
manner that provides headroom within the BSER also contributes to the 
ability of all

[[Page 64736]]

affected EGUs to implement the BSER and achieve emissions limitations 
consistent with those performance rates.
    i. Subcategorization. As noted above, in this rule, we are treating 
all fossil fuel-fired EGUs as a single category, and, in the emission 
guidelines that we are promulgating with this rule, we are treating 
steam EGUs and combustion turbines as separate subcategories. We are 
determining the BSER for steam EGUs and the BSER for combustion 
turbines, and applying the BSER to each subcategory to determine a 
performance rate for that subcategory. We are not further 
subcategorizing among different types of steam EGUs or combustion 
turbines. As we discuss below, this approach is fully consistent with 
the provisions of section 111(d), which simply require the EPA to 
determine the BSER, do not prescribe the method for doing so, and are 
silent as to subcategorization. This approach is also fully consistent 
with other provisions in section 111, which require the EPA first to 
list source categories that may reasonably be expected to endanger 
public health or welfare and then to regulate new sources within each 
such source category, and which grant the EPA discretion whether to 
subcategorize the sources for purposes of determining the BSER.
    As discussed below, each affected EGU can achieve the performance 
rate by implementing the BSER, specifically, by taking a range of 
actions--some of which depend on features of the section 111(d) plan 
chosen by the state, such as the choice of rate-based or mass-based 
standards of performance and the choice of whether and how to permit 
emissions trading--including investment in the building blocks, 
replaced or reduced generation, and purchase of emission credits or 
allowances. Further, in the case of a rate-based state plan, several 
other compliance options not included in the BSER for this rule are 
also available to all affected EGUs, including investment in demand-
side EE measures. Such compliance options may also indirectly help 
affected EGUs achieve compliance under a mass-based plan.
    Our approach of subcategorizing between steam EGUs and combustion 
turbines is reasonable because building blocks 1 and 2 apply only to 
steam EGUs. Moreover, our approach of not further subcategorizing as 
between different types of steam EGUs or combustion turbines reflects 
the reasonable policy that affected EGUs with higher emission rates 
should reduce their emissions by a greater percentage than affected 
EGUs with lower emission rates and can do so at a reasonable cost using 
the approaches we have identified as the BSER as well as other 
available measures.
    Of course, a state retains great flexibility in assigning standards 
of performance to its affected EGUs and can impose different emission 
reduction obligations on its sources, as long as the overall level of 
emission limitation is at least as stringent as the emission 
guidelines, as discussed below.
3. Changes From Proposal
    For the BSER determined in this final rule, based on consideration 
of comments responding to a broad array of topics considered in the 
proposal, the EPA has adopted certain modifications to the proposed 
BSER. In this subsection we describe the most important modifications, 
including some that relate to individual building blocks and some that 
are more general. Additional modifications that relate to individual 
building blocks are discussed in the respective sections for those 
building blocks below (sections V.C. through V.E.).
    We note that taken together, the modifications yield emission 
reductions requirements that commence more gradually than the proposed 
goals but are projected to produce greater overall annual emission 
reductions by 2030.\384\ We also note that the modifications lead to 
requirements that are more uniform across states than the proposed 
state goals (consistent with the direction of certain alternatives on 
which we sought comment in the proposal), with the final requirements 
generally becoming more stringent (compared to the proposal) in states 
with the highest 2012 CO2 emission rates and less stringent 
in states with lower 2012 CO2 emission rates.
---------------------------------------------------------------------------

    \384\ For the proposed rule, the EPA projected total 
CO2 emission reductions from 2005 levels of 29% in 2025 
and 30% in 2030. For the final rule, the EPA projects total 
CO2 emissions reductions from 2005 levels of 28% in 2025 
and 32% in 2030. See Regulatory Impact Analysis for the CPP Proposed 
Rule, Table 3-6, and Regulatory Impact Analysis for the CPP Final 
Rule, Table 3-6, available in the docket.
---------------------------------------------------------------------------

    a. Interpretations of CAA section 111. In the June 2014 proposal, 
the EPA proposed interpretations of section 111(a)(1) and (d), and 
applied these interpretations to existing fossil fuel-fired EGUs.\385\ 
Informed by comments, the EPA has clarified some of these 
interpretations, and has developed a more refined understanding of how 
some of these interpretations should be applied. The clarified and more 
refined interpretations replace the proposed interpretations.
---------------------------------------------------------------------------

    \385\ The June 2014 proposal in part referenced proposed 
interpretations of section 111(a)(1) that the EPA explained in the 
January 2014 proposal to address CO2 emissions from new 
fossil fuel-fired EGUs under section 111(b).
---------------------------------------------------------------------------

    Two of these points merit mention here. First, the EPA is 
clarifying in this rule that the interpretation of ``system of emission 
reduction'' does not include emission reduction measures that the 
states have authority to mandate without the affected EGUs being able 
to implement the measures themselves (e.g., appliance standards or 
building codes). In the final rule, we have clarified that the 
components of the BSER must be implementable by the affected EGUs, not 
just by the states, and we show that all the components of the BSER 
have been demonstrated to be achievable on that basis without reliance 
on actions that can be accomplished only through government mandates. 
Further discussion of these points can be found throughout this section 
on the BSER and the following sections on the individual building 
blocks.
    Second, the EPA has adopted a combined interpretation of sections 
111(a)(1) and 111(d) that, compared to the proposal, better reflects 
the historical interpretations of section 111(a)(1), which have 
generally supported emissions standards that are nationally uniform for 
sources incorporating a given technology, and gives less weight to the 
state-focused character of section 111(d), which calls for emissions 
standards to be implemented through the development of individual state 
plans. The proposed state goals were heavily (although not entirely) 
dependent on the emission reduction opportunities available to the EGUs 
in each individual state, and because the relative magnitudes of these 
opportunities varied by state, states with similar EGU fleet 
compositions could have faced state goals of different stringencies, 
potentially making it difficult for multiple states to set the same 
standards of performance for affected EGUs using the same technologies 
(assuming the states were interested in setting standards of 
performance for their various affected EGUs in such a manner). Some 
commenters viewed this potential result as inconsistent with section 
111(a)(1), inequitable, or both. In response, we took further comment 
on these potential disparities in the October 30, 2014 NODA. In this 
final rule, we are obviating those concerns by assessing the emission 
reduction opportunities at an appropriate regional scale, consistent 
with alternatives on which we sought comment, and using this regional 
information to reformulate the proposed emissions standards as 
nationally

[[Page 64737]]

uniform emissions standards for the emission guidelines.\386\ National 
uniformity is consistent with prior section 111 rulemaking and advances 
a number of other goals central to this rulemaking. The methodological 
refinements related to regional assessment of emission reduction 
opportunities and the use of uniform emissions standards by technology 
subcategory are further discussed below.
---------------------------------------------------------------------------

    \386\ Of course, a source in one state may face different 
requirements than similar sources in other states, depending on 
whether the state adopts the state measures approach or, if it 
adopts the emission standards approach, whether it imposes a mass 
limit or an emission rate and, if the latter, at what level.
---------------------------------------------------------------------------

    b. Approach to quantification of emission reductions from increased 
RE generation. In the June 2014 proposal, the EPA described two 
possible approaches for quantifying the amount of emission reductions 
achievable from affected EGUs through the use of RE generation. The 
proposed approach used information on state RPS aggregated at a 
regional level along with historical RE generation data to project the 
amount of RE generation used in quantifying the emission reductions 
achievable through the BSER. The alternative approach used information 
on the technical and market potential for development of renewable 
resources in each state to project the RE-related emission reductions. 
In the October 30, 2014 NODA, we sought comment on an additional 
approach of aggregating the state-level information to a regional 
level, as suggested by some commenters. In this final rule we are 
adopting a combination of these approaches that uses historical RE 
generating capacity deployment data aggregated to a regional level, 
supported and confirmed by projections of market potential developed 
through a techno-economic approach.
    In the June 2014 proposal, RE generation was also quantified as 
generation from total--that is, existing and new--RE generating 
capacity, a formulation that was consistent with the formulation of 
most RPS, which are typically framed in terms of total rather than 
incremental generation. In response to the EPA's request for comment on 
this approach, commenters observed that the approach was inconsistent 
with the approach taken for other building blocks, and that generation 
from RE generating capacity that already existed as of 2012 should not 
be treated as reducing emissions of affected EGUs from 2012 levels. As 
just noted, we are not using the RPS-based methodology in the final 
rule, and we agree with comments that quantification of RE generation 
on an incremental basis is both more consistent with the treatment of 
other building blocks and more consistent with the general principle 
that the BSER should comprise incremental measures that will reduce 
emissions below existing levels, not measures that are already in 
place, even if those in-place measures help current emission levels be 
lower than would be the case without the measures. The final rule 
therefore defines the RE component of the BSER in terms of incremental 
rather than total RE generation.\387\ Further details regarding the 
final rule's quantification of RE generation are provided in section 
V.E. below.
---------------------------------------------------------------------------

    \387\ Generation from existing RE capacity will continue to make 
compliance with mass-based standards easier to achieve by making the 
overall amount of fossil fuel-fired generation that is required to 
meet the demand for energy services lower than it would otherwise 
be, thereby keeping CO2 emissions lower than they would 
otherwise be.
---------------------------------------------------------------------------

    c. Exclusion from the BSER of emission reductions from use of 
under-construction or preserved nuclear capacity. In the June 2014 
proposal, the EPA included in building block 3 provisions reflecting 
the ability for nuclear generation to replace fossil generation and 
thereby reduce CO2 emissions at affected EGUs. We proposed 
to include in building block 3 the potential generation from five 
under-construction nuclear generating units whose construction had 
commenced prior to the issuance of the proposal. In addition, to 
address the potential that some currently operating nuclear facilities 
may shut down prior to 2030, the proposal incorporated into the BSER 
for each state with nuclear capacity a projected 5.8 percent reduction 
in nuclear generation, based on an estimate of potential nationwide 
loss of nuclear generation from existing units. We sought comment on 
all aspects of these proposed approaches. While we recognize the 
important role nuclear power plants have to play in providing carbon-
free generation in an all-of-the-above energy system, for this final 
rule, the BSER does not include either of the components related to 
nuclear generation.
    The EPA received numerous comments on the proposed BSER components 
related to nuclear power. With respect to generation from under-
construction nuclear units, some commenters expressed strong opposition 
to the inclusion of this generation in the BSER and the setting of 
state goals, stating that inclusion would result in very stringent 
state goals for the states where the units are being built and that the 
inclusion of the generation in the goals is premature because the 
units' actual completion dates could be delayed. Commenters also stated 
that inclusion of the under-construction nuclear generation in the BSER 
would be inequitable because states where the same heavy investment in 
zero-CO2 generation was not being made would have relatively 
less stringent goals.
    With respect to generation from existing nuclear units, some 
commenters stated that our method of accounting for potential unit 
shutdowns was flawed, observing that even if the prediction of a 5.8 
percent nationwide loss of nuclear generation were accurate, the actual 
shutdowns would occur in a handful of states, resulting in much larger 
losses of generation in those particular states.
    Upon consideration of comments and the accompanying data, the EPA 
has determined that the BSER should not include either of the 
components related to nuclear generation from the proposal. With 
respect to nuclear units under construction, although we believe that 
other refinements to this final rule would address commenters' concerns 
that goals for the particular states where the units are located would 
be overly stringent either in absolute terms or relative to other 
states, we also acknowledge that, in comparison to RE generating 
technology, investments in new nuclear units tend to be individually 
much larger and to require longer lead times. Also, important recent 
trends evidenced in RE development, such as rapidly growing investment 
and rapidly decreasing costs, are not as clearly evidenced in nuclear 
generation. We view these factors as distinguishing the under-
construction nuclear units from RE generating capacity, indicating that 
the new nuclear capacity is likely of higher cost and therefore less 
appropriate for inclusion in the BSER. Excluding the under-construction 
nuclear units from the BSER, but allowing emission reductions 
attributable to generation from the units to be used for compliance as 
discussed below and in section VIII, will recognize the CO2 
emission reduction benefits achievable through the significant ongoing 
commitment required to complete these major investments.
    With respect to existing nuclear units, although again we believe 
that other refinements in the final rule would address the concern 
about disparate impacts on particular states, we acknowledge that we 
lack information on shutdown risk that would enable us to improve the 
estimated 5.8 percent factor for nuclear capacity at risk of

[[Page 64738]]

retirement. Further, based in part on comments received on another 
aspect of the proposal--specifically, the proposed inclusion of 
existing RE generation in the goal-setting computations--we believe 
that it is inappropriate to base the BSER in part on the premise that 
the preservation of existing low- or zero-carbon generation, as opposed 
to the production of incremental, low- or zero-carbon generation, could 
reduce CO2 emissions from current levels. Accordingly, we 
have determined not to reflect either of the nuclear elements in the 
final BSER.
    Generation from under-construction or other new nuclear units and 
capacity uprates at existing nuclear units would still be able to help 
sources meet emission rate-based standards of performance through the 
creation and use of credits, as noted in section V.A.6.b. and section 
VIII.K.1.a.(8), and would help sources meet mass-based standards of 
performance through reduced utilization of fossil generating capacity 
leading to reduced CO2 emissions at affected EGUs. However, 
consistent with the reasons just discussed for not reflecting 
preservation of existing nuclear capacity in the BSER--namely, that 
such preservation does not actually reduce existing levels of emissions 
from affected EGUs--the rule does not allow preservation of generation 
from existing or relicensed nuclear capacity to serve as the basis for 
creation of credits that individual affected EGUs could use for 
compliance, as further discussed in section VIII.K.1.a.(8).\388\
---------------------------------------------------------------------------

    \388\ As with generation from existing RE capacity, generation 
from existing nuclear capacity will continue to make compliance with 
mass-based standards easier to achieve by making the overall amount 
of fossil fuel-fired generation that is required to meet the demand 
for energy services lower than it would otherwise be, thereby 
keeping CO2 emissions lower than they would otherwise be.
---------------------------------------------------------------------------

    d. Exclusion from the BSER of emission reductions from demand-side 
EE. The June 2014 proposal included demand-side EE measures in building 
block 4 as part of the BSER. The EPA took comment on the attributes of 
each of the proposed building blocks, and building block 4 was a topic 
of considerable controversy among commenters. While many commenters 
recognized demand-side EE as an integral part of the electricity 
system, emphasized its cost-effectiveness as a means of reducing 
CO2 emissions from the utility power sector, and strongly 
supported its inclusion in the BSER, other commenters expressed 
significant concerns.
    As explained in section V.B.3.c.(8) below, our traditional 
interpretation and implementation of CAA section 111 has allowed 
regulated entities to produce as much of a particular good as they 
desire provided that they do so through an appropriately clean (or low-
emitting) process. While building blocks 1, 2, and 3 fall squarely 
within this paradigm, the proposed building block 4 does not. In view 
of this, since the BSER must serve as the foundation of the emission 
guidelines, the EPA has not included demand-side EE as part of the 
final BSER determination.
    It should be noted that commenters also took the position that the 
EPA should allow demand-side EE as a means of compliance with the 
requirements of this rule, and, as discussed in section V.A.6.b. and 
section VIII below, we agree.
    e. Consistent regionalized approach to quantification of emission 
reductions from all building blocks. In the June 2014 proposal, the EPA 
treated each of the building blocks differently with respect to the 
regional scale on which the building block was applied for purposes of 
assessing the emission reductions achievable through use of that 
building block. Building block 1 was quantified at a national scale, 
identifying a single heat rate improvement opportunity applicable on 
average to all coal-fired steam EGUs. Building block 2 was quantified 
at the scale of each individual state, considering the amount of 
generation that could be shifted from steam EGUs to NGCC units within 
the state, although we solicited comment on considering generation 
shifts at a broader regional scale. The RE component of building block 
3 was quantified at a regional scale using RPS information as a proxy 
for RE development potential, and the regional results were then 
applied to each state in the region using the state's baseline data; an 
alternative methodology on which we requested comment quantified the RE 
component using a techno-economic approach on a state-specific basis. 
In the October 2014 NODA, we requested comment on using a techno-
economic approach to quantify RE generation potential at a regional 
scale and took broad comment on strategies for better aligning the BSER 
with the regionally interconnected electrical grid.\389\ We also 
solicited comment on the appropriate regional boundaries or regional 
structure to facilitate this approach.
---------------------------------------------------------------------------

    \389\ 79 FR 64543, 64551-52.
---------------------------------------------------------------------------

    For the final rule, with the benefit of comments received in 
response to these proposals and alternatives, we have adopted a 
consistent regionalized approach to quantification of emission 
reductions achievable through all the building blocks. Under this 
approach, each of the building blocks is quantified and applied at the 
regional level, resulting in the computation for each region of a 
performance rate for steam EGUs and a performance rate for NGCC units. 
For each of the technology subcategories, we identify the most 
conservative--that is, the least stringent --of the three regional 
performance rates. We then apply these least stringent subcategory-
specific performance rates to the baseline data for the EGU fleet in 
each state to establish state goals of consistent stringency across the 
country. (Note that the actual state goals vary among states to reflect 
the differences in generation mix among states in the baseline year.) 
Further description of the steps in this overall process is contained 
in the preamble sections addressing the individual building blocks 
(sections V.C., V.D., and V.E.), CO2 emission performance 
rate computation (section VI), and state goal computation (section 
VII), as well as the GHG Mitigation Measures TSD for the CPP Final Rule 
and the CO2 Emission Performance Rate and Goal Computation 
TSD for the CPP Final Rule available in the docket.
    Compared to the more state-focused quantification approach selected 
in the proposal, and as recognized in the NODA, a regionalized approach 
better reflects the interconnected system within which interdependent 
affected EGUs actually carry out planning and operations in order to 
meet electricity demand. We have already discussed the relevance of the 
interconnected system and the interdependent operations of EGUs as 
factors supporting consideration of building blocks 2 and 3 as elements 
of the BSER for this pollutant and this industry, and these same 
factors support quantifying the emission reductions achievable through 
building blocks 2 and 3 on a regionalized basis. Because it better 
reflects how the industry works, a regionalized approach also better 
represents the full scope of emission reduction opportunities available 
to individual affected EGUs through the normal transactional processes 
of the industry, which do not stop at state borders but rather extend 
throughout these interconnected regions. With respect to building block 
1, which comprises types of emission reduction measures that in other 
rulemakings under CAA section 111 would typically be evaluated on a 
nationwide basis, for this rule, as discussed in section V.C. below, we 
are quantifying the emission reductions achievable through building

[[Page 64739]]

block 1 on a regional basis in order to treat the building blocks 
consistently and to ensure that for each region the quantification of 
the BSER represents only as much potential emission reduction from 
building block 1 as our analysis of historical data indicates can be 
achieved on average by the affected EGUs in that region.
    Characterizing and quantifying the measures included in the BSER on 
a regional basis rather than a state-limited basis is also appropriate 
because states can establish standards of performance that incorporate 
emissions trading, including trading between and among EGUs operating 
in different states, and thus provide EGUs the opportunity to trade. 
Emissions trading provides at least one mechanism by which owners of 
affected EGUs can access any of the building blocks at other locations. 
With emissions trading, an affected EGU whose access to heat rate 
improvement opportunities, incremental generation from existing NGCC 
units, or generation from new RE generating capacity is relatively 
favorable can overcomply with its own standard of performance and sell 
rate-based emission credits or mass-based emission allowances to other 
affected EGUs. Purchase of the credits or allowances by the other EGUs 
represents cross-investment in the emission reduction opportunities, 
and such cross-investment can be carried out on as wide a geographic 
scale as trading rules allow.
    The regions we have determined to be appropriate for the 
regionalized approach in the final rule are the Eastern, Western, and 
Texas Interconnections.\390\ In determining that the appropriate 
regional level for quantification of the BSER was the level of the 
interconnection, the EPA considered several factors. First, consistent 
with our goal of aligning regulation with the reality of the 
interconnected electricity system, we considered the regional scale on 
which electricity is actually produced, physically coordinated, and 
consumed in real time--specifically the Eastern, Western, and Texas 
Interconnections. The Bulk Power System (BPS) in the contiguous U.S. 
(including adjacent portions of Canada and Mexico) consists of these 
three interconnections, which are alternating current (AC) power grids 
where power flows freely from generating sources to consuming loads. 
These interconnections are separately planned and operated; they are 
connected to each other only through low-capacity direct current (DC) 
tie lines. Each interconnection is managed to maintain a single 
frequency and to maintain stable voltage levels throughout the 
interconnection. Physically, each interconnection functions as a large 
pool, where all electricity delivered to the electric grid flows by 
displacement over all transmission lines in the interconnection and 
must be continually balanced with load to ensure reliable electricity 
service to customers throughout each interconnection. ``Since power 
flows on all transmission paths, it is not uncommon to find 
circumstances in which part of a power delivery within one balancing 
area flows on transmission lines in adjoining areas, or part of a power 
delivery between two balancing areas flows over the transmission 
facilities of a third area.'' \391\ The interconnections are the 
``complex machines'' within which EGUs plan, coordinate, and operate, 
manifesting a degree of both long-term and real-time interdependence 
that is unique to this industry. We concluded that, absent a compelling 
reason to adopt a smaller regional scale for evaluation of 
CO2 emission reduction opportunities for the electric power 
sector--which we have not found, as discussed below--the 
interconnections should be the regions used for evaluation of the BSER 
for CO2 emission reductions from the electric power sector 
because of the fundamental characteristics of electricity, the 
industry's basic interconnected physical infrastructure, and the 
interdependence of the affected EGUs within each interconnection.
---------------------------------------------------------------------------

    \390\ The Texas Interconnection encompasses the portion of the 
Texas electricity system commonly known as ERCOT (for the Electric 
Reliability Council of Texas). The state of Texas has areas within 
the Eastern and Western Interconnections as well as the Texas 
Interconnection.
    \391\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 188 (2d ed. 2010).
---------------------------------------------------------------------------

    Second, we considered whether the interconnection subregions for 
which various planning and operational functions are carried out by 
separate institutional actors would represent more appropriate regions 
than the entire interconnnections, and concluded that they would not. 
Interconnection planning and management follows the NERC functional 
model, which defines subregional areas and regional entities within 
each interconnection for the purposes of balancing generation with load 
and ensuring that reliability is maintained. While a variety of 
organizations plan and operate these subregions, those activities 
always occur in the context of the interconnections, and the subregions 
cannot be operated autonomously. The need to maintain common frequency 
and stable voltage levels throughout the interconnections requires 
constantly changing flows of electricity between the planning and 
operating subregions within each interconnection.
    Because each interconnection is a freely flowing AC grid, any power 
generated or consumed flows through the entire interconnection in real 
time; as a result of this highly interconnected nature of the power 
system, the management of generation and load on the grid must be 
carefully maintained. This management is carried out principally by 
subregional entities responsible for the operation of the grid, but 
this operation must be coordinated in real time to ensure the 
reliability of the system. Regional operators must coordinate the 
dispatch of power, not only in their own areas, but also with the other 
subregions within the interconnection. Although this coordination has 
always been important, grid planning and management has evolved to be 
increasingly interconnection-wide, through the development of larger 
regional entities, such as RTO/ISOs, or large-utility dispatch across 
multiple balancing areas. As a result, the fact that much of the 
necessary coordination for the interconnections is performed regionally 
on a partially decentralized basis (at least in the case of the Eastern 
and Western Interconnections) or occurs through the operation of 
automated equipment and the physics of the grid does not render the 
subregions more relevant than the interconnections as the ultimate 
regions within which electricity supply and demand must balance.
    Moreover, some planning and standard setting activities are 
undertaken explicitly at the interconnection level. For example, 
interconnections also have interconnection reliability operating limits 
(IROLs).\392\ A joint FERC-NERC report on the September 8, 2011 
Arizona-Southern California outages outlined the importance of 
IROLs.\393\

[[Page 64740]]

The report noted that to ensure the reliable operation of the bulk 
power system, entities must identify a plan for IROLs to avoid 
cascading outages. ``In order to ensure the reliable operation of the 
BPS, entities are required to identify and plan for IROLs, which are 
SOLs that, if violated, can cause instability, uncontrolled separation, 
and cascading outages. Once an IROL is identified, system operators are 
then required to create plans to mitigate the impact of exceeding such 
a limit to maintain system reliability.'' \394\
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    \392\ For example, the Eastern Interconnection has Reliability 
Standard IRO-006-EAST-1, Transmission Loading Relief Procedure for 
the Eastern Interconnection, available at http://www.nerc.com/files/IRO-006-EAST-1.pdf (providing an ``Interconnection-wide transmission 
loading relief procedure (TLR) for the Eastern Interconnection that 
can be used to prevent and/or mitigate potential or actual System 
Operating Limit (SOL) and Interconnection Reliability Operating 
Limit (IROL) exceedances to maintain reliability of the Bulk 
Electric System (BES).'').
    \393\ FERC-NERC, Arizona-Southern California Outages on 
September 8, 2011: Causes and Recommendations (Apr. 2012), available 
at http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nerc-report.pdf.
    \394\ FERC-NERC, Arizona-Southern California Outages on 
September 8, 2011: Causes and Recommendations, at 97 (Apr. 2012), 
available at http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nerc-report.pdf.
---------------------------------------------------------------------------

    Congress recognized the significance of the three interconnections 
in the American Recovery and Reinvestment Act of 2009 (Recovery Act) 
when it provided $80 million in funding for interconnection-based 
transmission planning.\395\ In order to fulfill this Congressional 
mandate, DOE and FERC signed a memorandum of understanding to enumerate 
their roles ``for activities related to the Resource Assessment and 
Interconnection Planning project funded by the American Recovery and 
Reinvestment Act of 2009 (Recovery Act). Among the objectives of the 
project is to facilitate the development or strengthening of 
capabilities in each of the three interconnections serving the 
contiguous lower forty-eight States, to prepare analyses of 
transmission requirements under a broad range of alternative futures 
and develop long-term interconnection-wide transmission plans.'' \396\ 
DOE issued awards to five organizations that performed work in the 
Western, Eastern, and Texas Interconnections to develop long-term 
interconnection-wide transmission expansion plans.\397\
---------------------------------------------------------------------------

    \395\ American Reinvestment and Recovery Act of 2009, Title IV, 
Public Law 111-5 (2009).
    \396\ Memorandum of Understanding Between the U.S. Department of 
Energy and the Federal Energy Regulatory Commission, available at 
http://www.ferc.gov/legal/mou/mou-doe-ferc.pdf.
    \397\ DOE, Recovery Act Interconnection Transmission Planning, 
available at http://energy.gov/oe/services/electricity-policy-coordination-and-implementation/transmission-planning/recovery-act.
---------------------------------------------------------------------------

    In Order No. 1000, FERC also took a broader regional view of 
transmission planning.\398\ FERC required each public utility 
transmission provider to participate in a regional transmission 
planning process that produces a regional transmission plan. FERC also 
required neighboring transmission planning regions to coordinate with 
each other. This interregional coordination includes identifying 
methods for evaluating interregional transmission facilities as well as 
establishing a common method or methods of cost allocation for 
interregional transmission facilities.
---------------------------------------------------------------------------

    \398\ Transmission Planning and Cost Allocation by Transmission 
Owning and Operating Public Utilities, Order No. 1000, FERC Stats. & 
Regs. ] 31,323 (2011), order on reh'g, Order No. 1000-A, 139 FERC ] 
61,132, order on reh'g, Order No. 1000-B, 141 FERC ] 61,044 (2012), 
aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 
2014).
---------------------------------------------------------------------------

    In addition to Congressional, DOE, and FERC recognition of the 
importance of the three interconnections, NERC also considers them to 
be significant. NERC Organizational Standards ``are based upon certain 
Reliability Principles that define the foundation of reliability for 
North American bulk electric systems.'' \399\ These principles take a 
broad view of electric system reliability, considering the reliability 
of interconnected bulk electric systems. For example, Reliability 
Principle 1 states, ``Interconnected bulk electric systems shall be 
planned and operated in a coordinated manner to perform reliably under 
normal and abnormal conditions as defined in the NERC standards.'' 
\400\ NERC took a similarly broad view of system reliability when it 
delegated its authority to monitor and enforce mandatory reliability 
standards to a single Regional Entity in both the Western and Texas 
Interconnections (WECC in the West and the Texas Reliability Entity in 
the ERCOT region of Texas).\401\ Moreover, both WECC and ERCOT have 
interconnection-wide reliability standards.\402\ The Eastern 
Interconnection has multiple reliability regions with some differences 
in standards, but power flows and reliability are managed through a 
single Reliability Coordinator Information System that tracks power 
flows for all transmission transactions.\403\
---------------------------------------------------------------------------

    \399\ NERC, Reliability and Market Interface Principles, at 1, 
available at http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInterfacePrinciples.pdf.
    \400\ NERC, Reliability and Market Interface Principles, at 1, 
available at http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInterfacePrinciples.pdf.
    \401\ NERC, Key Players, available at http://www.nerc.com/AboutNERC/keyplayers/Pages/default.aspx.
    \402\ WECC, Standards, available at https://www.wecc.biz/Standards/Pages/Default.aspx (last visited July 3, 2015); Texas 
Reliability Entity, Reliability Standards, available at http://www.texasre.org/standards_rules/Pages/Default.aspx (last visited 
July 3, 2015).
    \403\ The NERC glossary defines the Reliability Coordinator 
Information System as the ``system that Reliability Coordinators use 
to post messages and share operating information in real time.'' 
NERC, Glossary of Terms Used in Reliability Standards (Apr. 20, 
2009), available at http://www.eia.gov/electricity/data/eia411/nerc_glossary_2009.pdf.
---------------------------------------------------------------------------

    The importance that Congress, DOE, FERC, and NERC each place upon 
the interconnections for electric reliability and operational issues is 
another factor supporting our decision to set the interconnections as 
the regional boundaries for the establishment of BSER. The utilization 
of the three interconnections for both planning and reliability 
purposes is a clear indication of the importance that electricity 
system regulators, operators, and industry place upon the 
interconnections. Those responsible for the electricity system 
recognize the need to ensure that there is a free flow of electricity 
throughout each interconnection such that transmission planning and 
reliability analysis are occurring at the interconnection level. 
Further, this vigilance with respect to considering reliability from an 
interconnection-wide basis recognizes that each of the interconnections 
behaves as a single machine where ``outages, generation, transmission 
changes, and problems in any one area in the synchronous network can 
affect the entire network.'' \404\ By setting the three 
interconnections as the regions for purposes of BSER, we are acting 
consistent with the way in which planning, reliability, and industry 
experts view the electricity system.
---------------------------------------------------------------------------

    \404\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 159 (2d ed. 2010).
---------------------------------------------------------------------------

    An additional factor weighing against the use of planning or 
operational subregions of the interconnections as the regions for our 
BSER analysis for this rule is that the borders of those subregions 
occasionally change as planning and management functions evolve or as 
owners of various portions of the grid change affiliations. This is not 
a merely theoretical consideration; numerous ISO/RTO and other regional 
boundaries have substantially changed in recent years. For example, in 
2012, Duke Energy Ohio and Duke Energy Kentucky integrated into 
PJM.\405\ The following year, in December 2013, Entergy and its six 
utility operating companies joined MISO, creating the MISO South 
Region.\406\ The integration

[[Page 64741]]

of MISO South correspondingly led to changes in NERC's regional 
assessment areas.\407\ FERC also recently approved the integration of 
the Western Areas Power Administration--Upper Great Plains, Basin 
Electric Power Cooperative, and Heartland Consumers Power District into 
SPP.\408\ Additionally, PacifiCorp and the CAISO recently began 
operating the western Energy Imbalance Market (EIM).\409\ Other 
entities such as NV Energy, Arizona Public Service Co., and Puget Sound 
Energy are planning to participate in the EIM in the future.\410\ The 
EIM ``creates significant reliability and renewable integration 
benefits for consumers by sharing and economically dispatching a broad 
array of resources.'' \411\ This history of changing regional 
boundaries leads us to the conclusion that selecting smaller regional 
boundaries for purposes of setting the BSER would merely represent a 
snapshot of current, changeable regional boundaries. As we have seen 
with recent, large-scale changes regarding ISO/RTO boundaries and NERC 
reliability assessment areas, such regions would likely not stand the 
test of the time, nor would smaller regional boundaries accurately 
reflect electricity flows on the grid. The EPA believes that the 
interconnections are the most stable and reasonable regional boundaries 
for setting BSER.
---------------------------------------------------------------------------

    \405\ PJM, Duke Energy Ohio, Inc., and Duke Energy Kentucky, 
Inc., Successfully Integrated Into PJM (Jan. 3, 2012), available at 
http://www.pjm.com/~/media/about-pjm/newsroom/2012-releases/
20120103-duke-ohio-and-kentucky-integrate-into-pjm.ashx.
    \406\ South Region Integration, available at https://www.misoenergy.org/WhatWeDo/StrategicInitiatives/SouthernRegionIntegration/Pages/SouthernRegionIntegration.aspx 
(noting that the creation of the MISO South Region ``brought over 
18,000 miles of transmission, ~50,000 megawatts of generation 
capacity, and ~30,000 MW of load into the MISO footprint.'').
    \407\ NERC previously included Entergy and its six operating 
areas as part of the SERC Assessment Areas. NERC, 2014 Summer 
Reliability Assessment (May 2014), available at http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2014SRA.pdf. ``MISO now 
coordinates all RTO activities in the newly combined footprint, 
consisting of all or parts of 15 states with the integration of 
Entergy and other MISO South entities. This transition has led to 
substantial changes to MISO's market dispatch, creating the 
potential for unanticipated flows across the following systems: 
Tennessee Valley Authority (TVA), Associated Electric Cooperative 
Inc. (AECI), and Southern Balancing Authority.'' Id. at 7.
    \408\ SPP, FERC approves Integrates System joining SPP (Nov. 12, 
2014), available at http://www.spp.org/publications/FERC%20approves%20IS%20membership.pdf.
    \409\ NREL, Energy Imbalance Market, available at http://www.nrel.gov/electricity/transmission/energy_imbalance.html.
    \410\ CAISO, EIM Company Profiles (May 2015), available at 
http://www.caiso.com/Documents/EIMCompanyProfiles.pdf.
    \411\ CAISO, Energy Imbalance Market, available at http://www.caiso.com/informed/pages/stakeholderprocesses/energyimbalancemarket.aspx.
---------------------------------------------------------------------------

    Third, we considered whether transmission constraints, and the fact 
that the specific locations of generation resources and loads within 
each interconnection clearly matter to grid planning and operations, 
necessitate evaluation of the emission reductions available from the 
building blocks at scales smaller than the interconnections. We 
concluded that no reduction in scale was needed due to such 
constraints. The same industry trends that are reflected in the BSER--
the changing efficiencies and mix of existing fossil EGUs and the 
development of RE throughout each interconnection--as well as the 
management of the interconnected grid as loads are reduced through EE, 
which is not reflected in the final BSER, are already driving power 
system development and are being managed through interconnection-wide 
planning, coordination and operations, and will continue to be managed 
in that manner in the future with or without this rule. While 
electricity supply and demand must be balanced in real time in a manner 
that observes all security constraints at that point in time, and key 
aspects of that management are carried out at a subregional scale, the 
emissions standards established in this rule can be met over longer 
timeframes through processes managed at larger geographic scales, just 
as they are today. We believe this rule will reinforce these 
developments and help provide a secure basis for moving forward. If a 
local transmission constraint requires that for reliability reasons a 
higher-emitting resource must operate during a certain period of time 
in preference to a lower-emitting resource that would otherwise be the 
more economic choice when all costs are considered, nothing in this 
rule prevents the higher-emitting source from being operated. If the 
same transmission constraint causes the same conditions to occur 
frequently, the extra cost associated with finding alternative ways to 
reduce emissions will provide an economic incentive for concerned 
parties to explore ways to relieve the transmission constraint. If 
relieving the constraint would be more costly than employing 
alternative measures to reduce emissions, the rule allows parties to 
pursue those alternative emission reduction measures. Accommodation of 
intermittent constraints and evaluation of alternatives for relieving 
or working around them have been routine operating and planning 
practices within the utility power sector for many years; the rule will 
not change these basic economic practices that occur today. The 2022-29 
schedule for the rule's interim goals and the 2030 schedule for the 
rule's final goals allow time for planning and investment comparable to 
the sector's typical planning horizons.
    Finally, the EPA also considered whether the smaller geographic 
scales on which affected EGUs may typically engage in energy and 
capacity transactions necessitate evaluating the emission reductions 
available from the building blocks at scales smaller than the 
interconnections, and again concluded that a smaller scale was not 
necessary or justified. We first note that electricity trading occurs 
today throughout the interconnection through RTO/ISO markets and active 
spot markets, often over large areas such as RTO/ISOs, or managed over 
large dispatch areas outside RTOs. These trades result in 
interconnection-wide changes in flow that are managed in real time. 
Moreover, the exchange of power is not limited to these areas. For 
example, RTOs regularly manage flows between RTOs, and EGUs near the 
boundaries of RTOs impact multiple subregions across the 
interconnections, so that any subregional boundaries that might be 
evaluated for potential relevance as trading region boundaries will 
change as conditions and EGU choices change, while interconnection 
boundaries will remain stable.
    In addition, the final rule permits trading of rate-based emission 
credits or mass-based emission allowances. Emission allowances and 
other commodities associated with electricity generation activities, 
such as RECs, which, again, represent investments in pollution control 
measures, are already traded separately from the underlying electric 
energy and capacity. There is no reason that whatever geographic limits 
may exist for electricity and capacity transactions by an affected EGU 
should also limit the EGU's transactions for validly issued rate-based 
emission credits or mass-based emission allowances. In fact, as 
discussed below, the final rule not only allows national trading 
without regard to the interconnection boundaries, but also includes a 
number of options that readily facilitate states' and utilities' very 
extensive reliance on emissions trading. It is appropriate for the rule 
to take this approach, in part, because the non-local nature of the 
impacts of CO2 pollution do not necessitate geographic 
constraints, and in the absence of a policy reason to constrain the 
geographic scope of trading, the largest possible scope is the most 
efficient scope.
    f. Uniform CO2 emission performance rates by technology 
subcategory. In conjunction with the refinements to the interpretations 
of section 111 reflected in the final rule, the EPA has refined the 
methodology for applying the BSER to the affected EGUs so as to 
incorporate performance rates that are uniform across technology 
subcategories.

[[Page 64742]]

    Specifically, the final rule establishes a performance rate of 1305 
lbs. per net MWh for all affected steam EGUs nationwide and a 
performance rate of 771 lbs. per net MWh for all affected stationary 
combustion turbines nationwide. The computations of these performance 
rates and the determinations of state goals reflecting the performance 
rates are described in sections VI and VII of the preamble, 
respectively. As described above, in its proposed rule and NODA, the 
EPA solicited comment on a number of proposals to reflect the regional 
nature of the electricity system in the methodology for quantifying the 
emission limitations reflective of the BSER. At the same time, the EPA 
also consistently emphasized the need for strategies to ensure the 
achievability and flexibility of the established emission limitations 
and to increase opportunities for interstate and industry-wide 
coordination. This modification is consistent with a number of comments 
we received in response to those proposals. The commenters took the 
position that the proposed state goals varied too much among states and 
unavoidably implied, or would inevitably result in, states establishing 
inconsistent standards of performance for sources of the same 
technology type in their respective states, which in the commenters' 
view was not appropriate under section 111.
    Having determined to adopt regional alternatives for computing the 
emission reductions achievable under each building block, the EPA has 
further determined to exercise discretion not to subcategorize based on 
the regions, and instead to apply a nationally uniform CO2 
emission performance rate for each source subcategory. Evaluating the 
emission reduction opportunities achievable through application of the 
BSER on a broad regionalized basis, which is appropriate for the 
reasons discussed above, makes it possible to express the degree of 
emission limitation reflecting the BSER as CO2 emission 
performance rates that are uniform for all affected EGUs in a 
technology subcategory within each region. However, the goals and 
strategies embodied in the EPA's proposed rule are best effected by 
setting uniform emission performance rates nationally and not just 
regionally, as recognized by commenters favoring the use of nationally 
uniform performance rates by technology subcategory. Nationally uniform 
emission performance rates create greater parity among the emission 
reduction goals established for states across the contiguous U.S. and 
increase the ability of states and affected EGUs to coordinate emission 
reduction strategies, including through the use of emission trading 
mechanisms if states choose to allow such mechanisms, which we consider 
likely.
    Having determined that the performance rates computed on a regional 
basis merit consideration as nationally applicable performance rates, 
we are also determining that the objectives of achievability and 
flexibility would best be met by using the least stringent of the 
regional performance rates for the three interconnections for each 
technology subcategory as the basis for nationally uniform performance 
rates for that technology subcategory rather than by using the most 
stringent of the regional performance rates.\412\ Under this approach, 
the CO2 emission performance rate reflecting the BSER for 
all steam EGUs is uniform across the contiguous U.S., regardless of the 
state or interconnection where the steam EGUs are located. While it is 
true that steam EGUs in the Western and Texas Interconnections have 
opportunities to implement the measures in the building blocks to a 
greater extent than the steam EGUs in the Eastern Interconnection--for 
example, under building block 2, they have relatively greater amounts 
of incremental NGCC generation available to replace their generation in 
all years for which performance rates were computed--we do not conclude 
that this means that the EGUs in all three interconnections should be 
assigned the most stringent CO2 emission performance rate 
computed for any of the three regions. Applying nationally the 
performance rate computed for the interconnection with the lease 
stringent rate ensures that the emission limitations are achievable by 
the affected EGUs in all three interconnections. The use of a common 
CO2 emission performance rate across all of the steam EGUs 
in all three regions also allocates the burdens of the BSER equally 
across the steam EGU source subcategory. The same is true for the 
combustion turbine source subcategory, even though, in any year for 
which emission performance rates are computed, the combustion turbines 
in two of the interconnections have relatively greater opportunities to 
replace their generation with generation from new RE generating 
capacity than combustion turbines in the third interconnection.\413\
---------------------------------------------------------------------------

    \412\ The Eastern, Western, and Texas Interconnections each 
encompass large and diverse populations of EGUs with numerous and 
diverse opportunities to reduce CO2 emissions through 
application of the measures in each of the three building blocks. 
Based on these considerations of scale and diversity, we conclude 
that each of the interconnections is sufficiently representative of 
the source subcategories and emission reduction opportunities 
encompassed in the BSER to potentially serve as the basis for 
CO2 emission performance rates applicable to the 
respective source subcategories on a nationwide basis.
    \413\ As discussed in section VI and the CO2 Emission 
Performance Rate and State Goal Computation TSD, the emission 
performance rates for each technology subcategory are computed by 
region for each year from 2022 through 2030, and the region with the 
least stringent emission rate for a particular subcategory, whose 
rate therefore is used for all three regions, can differ across 
years. In the case of the steam EGU subcategory, the nationwide rate 
for all years is the rate computed for the Eastern Interconnection. 
In the case of the NGCC subcategory, the nationwide rate is the rate 
computed for the Texas Interconnection for the years from 2022 
through 2026 and the rate computed for the Eastern Interconnection 
for the years from 2027 through 2030.
---------------------------------------------------------------------------

    In addition, using the least stringent rate provides greater 
``headroom''--that is, emission reduction opportunities beyond those 
reflected in the performance rates--to affected EGUs in the 
interconnections that do not set the nationwide level. This greater 
``headroom'' provides greater nationwide compliance flexibility and 
assurance that the standards set by the states based on the emission 
guidelines will be achievable at reasonable cost and without adverse 
impacts on reliability. This is because affected EGUs in the 
interconnections that do not set the nationwide level have more 
opportunities to directly invest in each of the building blocks in 
their respective regions, and affected EGUs in the interconnection that 
does set the nationwide level may in effect invest in the opportunities 
in the other interconnections through trading. At the same time, our 
approach still represents the degree of emission limitation achievable 
through use of an appropriately large and diverse set of emission 
reduction opportunities and can therefore reasonably be considered the 
``best'' system of emission reduction for each technology subcategory.
    Our approach in this rulemaking thus not only addresses the 
comments we received regarding potentially disparate impacts of the 
approach presented in the proposal, it is also generally consistent 
with the approach we have taken in other NSPS rulemakings, where 
standards of performance or emission guidelines have typically been 
established at uniform stringencies for all units in a given source 
subcategory, and where once the best system of emission reduction has 
been identified, stringencies are generally set based on what is 
reasonably achievable using that system.

[[Page 64743]]

    Providing each state with a state-specific weighted average rate-
based goal allows the state to determine how the emission reduction 
requirements should be allocated among the state's affected EGUs. We 
continue to believe that, as in the proposal, this is an important 
source of flexibility for states in developing their section 111(d) 
plans. Accordingly, in this final rule we are providing uniform 
CO2 emission performance rates for each source subcategory 
and also translating those rates to state-specific weighted average 
rate-based goals. For additional flexibility, we are also translating 
the state-specific rate-based goals into state-specific mass-based 
goals. Our determinations of the emission performance rates are 
described in section VI below, and our determinations of the rate-based 
and mass-based state goals are described in section VII below.
    We note here that the weighted-average state goals reflect the 
application of the uniform CO2 emission performance rates 
for affected steam EGUs and affected NGCC units to the respective units 
in each subcategory in each state. Each state goal therefore reflects 
uniform stringency of emission reduction requirements with respect to 
affected units in each source subcategory, but also reflects the EGU 
fleet composition and historical generation specific to that particular 
state. Compared to the computation approach reflected in the proposed 
state goals, the revised approach to quantify the BSER on a regional 
basis and to translate the results into nationally uniform emission 
performance rates by source subcategory results in more stringent goals 
(compared to the proposal) for states whose generation has historically 
been most heavily concentrated at coal-fired steam EGUs. This shift is 
an expected consequence of the use of uniform performance rates by 
source subcategory. At proposal, these states' goals reflected 
artificial assumptions in the selected goal quantification methodology 
that to a considerable extent limited their emission reduction 
opportunities based on their states' borders, and the proposed goals 
therefore were less stringent in states which had substantial coal 
generation and little local NGCC capacity. The final rule more 
realistically recognizes that emission reduction opportunities, like 
other aspects of the interconnected electricity system, are regional 
and are not constrained by state borders. The final rule also reflects 
the EPA's emphasis in the proposal on ensuring the achievability and 
flexibility of the emission guidelines and increasing opportunities for 
interstate and industry-wide coordination. We consequently apply the 
same emission performance rates to coal-fired units in states with 
heavy reliance on coal-fueled generation as we do to coal-fired units 
in other states, which produces more stringent state goals than at 
proposal for the states with the highest concentrations of coal-fired 
generation. At the same time, the final goals for some states are less 
stringent than their proposed goals. For example, a goal based on the 
least stringent regional rates is less stringent for some states than a 
goal based on state-specific emission reduction opportunities would be. 
Accordingly, the differences among the final state goals are generally 
smaller than the differences among the proposed state goals. All of the 
final rate-based state goals are necessarily in the range bounded by 
the CO2 emission performance rate for NGCC units and the 
CO2 emission performance rate for steam EGUs because all of 
the state goals are computed as a weighted average of those two 
performance rates, and this range is narrower than the range of state 
goals in the proposal.
    The computations of the uniform CO2 emission performance 
rates are shown in the CO2 Emission Performance Rate and 
Goal Computation TSD for the CPP Final Rule. These uniform emission 
performance rates are applicable to the states and areas of Indian 
country \414\ located in the contiguous U.S. that have affected 
EGUs.\415\ We have not in this rule applied the uniform emission 
performance rates to Alaska, Hawaii, Puerto Rico, or Guam--states and 
territories that have otherwise affected EGUs but are isolated from the 
three major interconnections--and will determine how to address the 
requirements of section 111(d) with respect to these jurisdictions at a 
later time. Further discussion regarding the isolated jurisdictions can 
be found in section VII.F. of the preamble.
---------------------------------------------------------------------------

    \414\ As explained in section III.A. above, an Indian tribe 
whose area of Indian country has affected EGUs will have the 
opportunity but not the obligation to seek authority to develop and 
implement a section 111(d) plan. If no tribal plan is approved, the 
EPA has the responsibility to establish a plan if it determines that 
such a plan is necessary or appropriate.
    \415\ As noted earlier, there are currently no affected EGUs in 
Vermont or the District of Columbia.
---------------------------------------------------------------------------

    g. Establishment of a 2022-2029 interim compliance period. The June 
2014 proposal separately quantified emission limitations applicable to 
an interim 2020-29 period and to the period beginning in 2030. The EPA 
took broad comment on this proposed timing. Although the proposal 
provided flexibility in the timing with which emission reductions could 
be made over the course of the 2020-2029 period in order to achieve 
compliance with the emission limitations applicable to that interim 
period, many commenters perceived the start of the period as too soon 
and stated that it provided insufficient time for planning and 
investments necessary for sources to begin implementation activities 
while maintaining reliable electricity supplies.
    The EPA has considered these comments and in the final rule has 
established an interim compliance period of 2022-2029, providing two 
additional years for planning and investment before the start of 
compliance. We are persuaded by comments and by our own further 
analysis that this timeframe is appropriate and will, in combination 
with the glide path of emission reductions reflected in the final 
building blocks and the states' flexibility to define their own paths 
of emission reductions over the interim period (as discussed in section 
VIII), provide adequate time for necessary planning and investment 
activities. This will enable the final rule's requirements to be 
implemented in an orderly manner while reliability of electricity 
supplies is maintained. Further discussion is provided in the sections 
of the preamble addressing the individual building blocks (sections 
V.C., V.D., and V.E.) and on electricity system reliability (section 
VIII.G.2.).
    The initial compliance date of 2022, coupled with the fact that the 
2030 standard is phased in over the subsequent eight years, affords 
affected EGUs the benefit of having an extended planning period before 
they need to incur any significant obligations. Where needed, states 
may take the period through September 2018 to develop their final 
plans, and affected EGUs will be able to work with the states during 
that period to develop compliance approaches. States will also have the 
flexibility to select their own emissions trajectories in such a way 
that certain emission reduction measures could be implemented later in 
the interim period (again, provided that their affected EGUs still meet 
the interim performance rates or interim goal over the interim period 
as a whole). As a result, if the affected EGUs in those states need to 
incur any expenses before the adoption of the final state plans, those 
expenses need not be more than minimal. It is worth noting that an 
earlier state plan submission date provides regulated sources with more 
certainty and time to

[[Page 64744]]

plan for compliance, but has no effect on the time when compliance must 
be achieved, as the mandatory compliance period begins in 2022 for all 
states. Some states that already have established programs for limiting 
CO2 emissions from power plants may adopt and submit to the 
EPA state plans by September 6, 2016. In those states, sources will 
already have developed compliance approaches to meet state law 
requirements. Other states that submit plans by September 6, 2016, may 
be expected to work with their affected EGUs to determine a reasonable 
compliance approach, in light of the fact that compliance is not 
required to begin until 2022. It is also possible that some states will 
submit neither final state plans nor initial submittals by September 6, 
2016, and that the EPA will promulgate federal plans. Sources in those 
states will have more than five years to meet their 2022 compliance 
obligations, a lengthy period that will afford them the opportunity to 
plan before incurring significant expenditures.
    These periods of time are consistent with current industry practice 
in changing generation or adding new generation. For example, in June 
2015, Alabama Power Company announced plans to acquire 500 MW of RE 
generation over the next six years. This amount would make up between 
four and five percent of Alabama Power's generation mix.\416\ In 
addition, the study of utility IRPs placed in the docket for this 
rulemaking \417\ shows that sources are able to replace coal-fired 
generation with natural-gas fired generation and add incremental 
amounts of RE (as well as take other actions, such as implement demand-
side EE programs), on a gradual basis, after a several-year lead time, 
over an extended period, as provided for under the final rule.
---------------------------------------------------------------------------

    \416\ Alabama Power Co., ``Petition for a Certificate of 
Convenience and Necessity,'' submitted to the Alabama Public Service 
Commission (June 25, 2015) (petition requests ``a certificate of 
convenience and necessity for the construction or acquisition of 
renewable energy and environmentally specialized generating 
resources and the acquisition of rights and the assumption of 
payment obligations under power purchase arrangements pertaining to 
renewable energy and environmentally specialized generating 
resources, together with all transmission facilities, fuel supply 
and transportation arrangements, appliances, appurtenances, 
equipment, acquisitions and commitments necessary for or incident 
thereto'') (included in the docket for this rulemaking). See Swartz, 
Kristi, ``Alabama Power plan would dramatically boost its renewables 
portfolio,'' E&E Publishing, July 16, 2015.
    \417\ See memorandum entitled ``Review of Electric Utility 
Integrated Resource Plans'' (May 7, 2015) available in the docket.
---------------------------------------------------------------------------

    h. Refinements to stringency for individual building blocks. For 
each individual building block, the EPA has reexamined the data and 
assumptions used at proposal in light of comments solicited and has 
made a number of refinements in the final rule based on that 
information. The refinements are discussed in the preamble sections for 
each building block (sections V.C., V.D., and V.E.) and emission 
performance rate computation (section VI) and in the GHG Mitigation 
Measures TSD for the CPP Final Rule and the CO2 Emission 
Performance Rate and Goal Computation TSD for the CPP Final Rule. As 
previously noted, viewed in terms of projected nationwide emission 
reductions (but not necessarily with respect to each individual state), 
these refinements generally tend to make the interim goals somewhat 
less stringent than at proposal and the 2030 goals somewhat more 
stringent than at proposal. In addition to the changes described above, 
the refinements include the following:

     Use of regional rates ranging from 2.1 percent to 4.3 
percent (rather than 6 percent) as the average heat rate improvement 
opportunity achievable by steam units under building block 1.
     Use of 75 percent of summer capacity (rather than 70 
percent of nameplate capacity) as the target capacity factor for 
existing NGCC units under building block 2.
     Use of updated information from the National Renewable 
Energy Laboratory (NREL) on RE costs and potential, and revision of 
the list of quantified RE technologies to exclude landfill gas under 
building block 3.
4. Determination of the BSER
    In this rule, the EPA is finalizing as the BSER a combination of 
building blocks 1, 2, and 3, with refinements as discussed below. The 
building blocks constitute the BSER from the perspective of the source 
category as a whole. Each building block can be implemented through 
standards of performance set by the states and includes a set of 
actions that individual sources can use to achieve the emission 
limitations reflecting the BSER. These actions and mechanisms, which 
include reduced generation and emissions trading approaches where the 
state-set standards of performance incorporate trading and which may be 
understood as part of the BSER, will be discussed below in section 
V.A.5. Each of the building blocks consists of measures that the source 
category and individual affected EGUs have already demonstrated the 
ability to implement. In quantifying the application of each building 
block, the EPA has identified reasonable levels of stringency rather 
than the maximum possible levels.
    As discussed above, one of the modifications being made in this 
rule is the establishment of uniform performance rates by technology 
subcategory, which enhances the rule's achievability and flexibility 
and facilitates coordination among the states and across the industry. 
However, in the first instance, the emission reductions achievable 
through use of the building blocks are being evaluated on a regional 
basis that reflects the regional nature of the interconnected 
electricity system and the region-wide scope of opportunities available 
for affected EGUs to access emission reduction measures. The EPA 
recognizes that the emission reduction opportunities under these 
building blocks vary by region because of regional differences in the 
existing mix of types of fossil fuel-fired EGUs and the available 
opportunities to increase low- and zero-carbon generation. 
Consequently, in order to achieve uniform performance rates by 
technology subcategory, while respecting these regional differences in 
emission reduction opportunities, we have determined that it is 
reasonable not to establish the stringency of the BSER separately by 
region based on the maximum emission reduction that would be achievable 
in that region, but instead to establish uniform stringency across all 
regions at a level that is achievable at reasonable cost in any region. 
Thus, for each technology subcategory, the BSER is the combination of 
the elements described above at the combined stringency that is 
reasonably achievable in the region where the CO2 emission 
performance rates determined to be achievable at reasonable cost by the 
EGUs in that subcategory through application of the building blocks 
were least stringent.\418\
---------------------------------------------------------------------------

    \418\ The determinations of stringency for each source 
subcategory were made independently for each year from 2022 through 
2030, and in the case of the NGCC category, the limiting region 
changed over time. Thus, for the NGCC category, the uniform 
CO2 emission performance rate is based on the stringency 
achievable in the Texas Interconnection for the years from 2022 
through 2026 and the stringency achievable in the Eastern 
Interconnection for the years from 2027 through 2030. For the steam 
EGU subcategory, the uniform CO2 emission performance 
rate is based on the stringency achievable in the Eastern 
Interconnection in all years.
---------------------------------------------------------------------------

    This approach is consistent with the EPA's efforts to enhance the 
achievability and flexibility of the rule and to promote interstate and 
industry coordination and reflects the regional strategies emphasized 
in the proposal and the NODA. It is also consistent with the approach 
we have taken in other NSPS rulemakings, where the degree of emission 
limitation achievable through

[[Page 64745]]

the application of the BSER for each subcategory of affected sources 
generally has been determined not on the basis of what is achievable by 
the sources that can reduce emissions most easily, but instead on the 
basis of what is reasonably achievable through the application of the 
BSER across a range of sources. This approach also provides compliance 
headroom--in addition to the headroom provided by our approach to 
setting the stringency for each individual building block--for affected 
EGUs in regions where additional emission reductions can be achieved at 
reasonable cost, thereby promoting nationwide compliance flexibility. 
Further, because we are authorizing states to establish standards of 
performance that incorporate trading without geographic restrictions, 
the opportunity of affected EGUs to engage in emissions trading, to the 
extent allowed under the relevant section 111(d) plans, ensures the 
availability of additional, lower-cost emission reduction opportunities 
in other regions that will also promote compliance flexibility and 
reduce compliance costs.
    As discussed in section XI of the preamble and the Regulatory 
Impact Analysis, application of the BSER determined as summarized above 
is projected to result in substantial and meaningful reductions of 
CO2 emissions.
    Briefly, the elements of the BSER are:

Building block 1: Improving heat rate at affected coal-fired steam EGUs 
in specified percentages.
Building block 2: Substituting increased generation from existing 
affected NGCC units for generation from affected steam EGUs in 
specified quantities.
Building block 3: Substituting generation from new zero-emitting RE 
generating capacity for generation from affected EGUs in specified 
quantities.

    a. Building block 1. Building block 1--improving heat rate at 
affected coal-fired steam EGUs--is a component of the BSER with respect 
to coal-fired steam EGUs \419\ because the measures the affected EGUs 
may undertake to achieve heat rate improvements are technically 
feasible and of reasonable cost, and perform well with respect to other 
factors relevant to a determination of the ``best system of emission 
reduction . . . adequately demonstrated.'' Building block 1 is a 
``system of emission reduction'' for steam EGUs because owners of these 
EGUs can take actions that will improve their heat rates and thereby 
reduce their rates of CO2 emissions with respect to 
generation.
---------------------------------------------------------------------------

    \419\ For the reasons discussed in the proposal, the EPA is not 
determining that heat rate improvements at other types of affected 
EGUs, such as NGCC units and oil-fired and natural gas-fired steam 
EGUs, are components of the BSER. However, all types of affected 
EGUs would be able to employ heat rate improvements as measures to 
help achieve compliance with their assigned standards of 
performance.
---------------------------------------------------------------------------

    The EPA has analyzed the technical feasibility, costs, and 
magnitude of CO2 emission reductions achievable through heat 
rate improvements at coal-fired steam EGUs based on engineering studies 
and on these EGUs' reported operating and emissions data. We conclude 
that taking action to improve heat rates is a common and well-
established practice within the industry that is capable of achieving 
meaningful reductions in CO2 emissions at reasonable cost, 
although, as discussed earlier, we also conclude that the quantity of 
emission reductions achievable through heat rate improvement measures 
is insufficient for these measures alone to constitute the BSER. 
Specifically, we have determined that an average heat rate improvement 
ranging from 2.1 to 4.3 percent by all affected coal-fired EGUs, 
depending on the region, is an element of the BSER, based on the 
inclusion of those amounts of improvement in the three regions, 
determined through our regional analysis. Our analysis and conclusions 
are discussed in Section V.C. below and in the GHG Mitigation Measures 
TSD for the CPP Final Rule. Additional analysis and conclusions with 
respect to cost reasonableness are discussed in section V.A.4.d. below.
    Consideration of other BSER factors also favors a conclusion that 
building block 1 is 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. By definition, heat rate improvements 
do not cause increases in net energy usage. Although we are justifying 
building block 1 as part of the BSER without reference to technological 
innovation, we also consider technological innovation in the 
alternative, and we note that building block 1 encourages the spread of 
more advanced technology to EGUs currently using components with older 
designs.
    As noted in the June 2014 proposal, 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). Unless mitigated, the 
occurrence of a rebound effect would reduce the emission reductions 
achieved by building block 1, exacerbating the inadequacy of emission 
reductions that is the basis for our conclusion that building block 1 
alone would not represent the BSER for this industry. However, we 
believe that our concern about the potential rebound effect 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, thereby allowing building 
block 1 to be considered an appropriate part of the BSER for 
CO2 emissions at affected EGUs as long as the building block 
is applied in combination with other building blocks.
    b. Building block 2. Building block 2--substituting generation from 
less carbon-intensive affected EGUs (specifically ``existing'' NGCC 
units, meaning units that were operating or had commenced construction 
as of January 8, 2014) for generation from the most carbon-intensive 
affected EGUs--is a component of the BSER for steam EGUs because 
generation shifts that will reduce the amount of CO2 
emissions at higher-emitting EGUs and from the source category as a 
whole are technically feasible, are of reasonable cost, and perform 
well with respect to other factors relevant to a determination of the 
``best system of emission reduction . . . adequately demonstrated.'' 
Building block 2 is a ``system of emission reduction'' for steam EGUs 
because incremental generation from existing NGCC units will result in 
reduced generation and emissions from steam EGUs, and owners of steam 
EGUs can, and many do, invest in incremental generation from NGCC units 
through a variety of possible mechanisms. A steam EGU investing in 
incremental generation from NGCC units may choose to reduce its own 
generation or may maintain its generation level and choose to allow the 
reduction in generation to occur at other steam EGUs through the 
coordinated planning and operation of the interconnected electricity 
system. An

[[Page 64746]]

affected EGU may also invest in emission reductions from building block 
2 through the mechanism of engaging in emissions trading where the EGU 
is operating under a standard of performance that incorporates trading.
    The EPA's analysis and conclusions regarding the technical 
feasibility, costs, and magnitude of CO2 emission reductions 
achievable at high-emitting EGUs through generation shifts to lower-
emitting affected EGUs are discussed in Section V.D. below. Additional 
analysis and conclusions with respect to cost reasonableness are 
discussed in section V.A.4.d. below. We consider generation shifts 
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. 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. Our analysis demonstrates that the 
emission reductions that can be achieved or supported by such 
generation shifts are substantial and of reasonable cost. Further, 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.
    Building block 2 is adequately demonstrated as a ``system of 
emission reduction'' for affected steam EGUs. As discussed in section 
V.B., since the time of the 1970 CAA Amendments, the utility power 
sector has recognized that generation shifts are a means of controlling 
air pollutants; in the 1990 CAA Amendments, Congress recognized that 
generation shifts among EGUs are a means of reducing emissions from 
this sector; and generation shifts similarly have been recognized as a 
means of reducing emissions under trading programs established by the 
EPA to implement the Act's provisions. It is common practice in the 
industry to account for the cost of emission allowances as a variable 
cost when making security-constrained, cost-based dispatch decisions; 
doing so integrates generation shifts into the operating practices used 
to achieve compliance with environmental requirements in an economical 
manner. These industry trends are further discussed in section V.D. 
Thus, legislative history, regulatory precedent, and industry practice 
support interpreting the broad term ``system of emission reduction'' as 
including substituting lower-emitting generation for higher-emitting 
generation through generation shifts among affected EGUs.
    An important additional consideration supporting the determination 
that building block 2 is adequately demonstrated as a ``system of 
emission reduction'' is that owners of affected steam EGUs have the 
ability to invest in generation shifts as a way of reducing emissions. 
The owner of an affected EGU could invest in such generation shifts in 
several ways, including by increasing operation of an NGCC unit that it 
already owns or by purchasing an existing NGCC unit and increasing 
operation of that unit. Increases in generation by NGCC units over 
baseline levels can also serve as the basis for creation of 
CO2 ERCs--that is, instruments representing the ability of 
incremental electricity generated by NGCC units to cause emission 
reductions at affected steam EGUs, as distinct from the incremental 
electricity itself. Again, it is important to note that the acquisition 
of such ERCs represents an investment in the actions of the facility or 
facilities whose alteration of utilization levels generated the 
emissions rate improvement or reduction. In the context of the BSER, 
purchase of instruments representing the emissions-reducing benefit of 
an action is simply a medium of investment in the underlying emissions 
reduction action. These mechanisms are discussed further in section 
V.A.5. In this rule, the EPA is establishing minimum criteria for the 
creation of valid ERCs by NGCC units and for the use of such ERCs by 
affected steam EGUs for demonstrating compliance with emission rate-
based standards of performance established under state plans. The 
existence of minimum criteria will ensure that crediting mechanisms are 
feasible and will facilitate the development of organized markets to 
simplify the process of buying and selling ERCs. The minimum criteria 
are discussed in section VIII of this preamble.
    We note that an affected EGU investing in building block 2 to 
reduce emissions may, but need not, also choose to reduce its own 
generation as part of its approach for meeting the standard of 
performance assigned to it by its state. Through the coordinated 
operation of the integrated electricity system, subject to the 
collective emission reduction requirements that will be imposed on 
affected EGUs in order to meet the emissions standards representing the 
BSER, an increase in NGCC generation will be offset elsewhere in the 
interconnection by a decrease in other generation. Because of the need 
to meet the collective emission reduction requirements, the decrease in 
generation resulting from that coordinated operation is most likely to 
be generation from an affected steam EGU. Measures taken by affected 
EGUs that result in emission reductions from other EGUs in the source 
category may appropriately be deemed measures to implement or apply the 
``system of emission reduction'' of substituting lower-emitting 
generation for higher-emitting generation.
    Consideration of other BSER factors also supports a determination 
to include building block 2 as a component of the BSER. 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.\420\ With respect to energy impacts, building block 2 
represents replacement of electrical energy from one generator with 
electrical energy from another generator that consumes less fuel, so 
the overall energy impact should be a reduction in fuel consumption by 
the overall source category as well as by individual affected coal-
fired steam EGUs. Although for purposes of this rule we consider the 
incentive for technological innovation only in the alternative, we note 
that building block 2 promotes greater use of the NGCC technology 
installed in the existing fleet of NGCC units, which is newer and more 
advanced than the technology installed in much of the older existing 
fleet of steam EGUs. For all these reasons, the

[[Page 64747]]

measures in building block 2 qualify as a component of the ``best 
system of emission reduction . . . adequately demonstrated.''
---------------------------------------------------------------------------

    \420\ For example, 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. EPA believes the difference would on average be even more 
pronounced when comparing existing coal and NGCC units.
---------------------------------------------------------------------------

    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.\421\ Through application of this building block considered 
in isolation, some affected EGUs--mostly coal-fired steam EGUs--would 
reduce their generation and CO2 emissions, while other 
affected EGUs--NGCC units--would increase their generation and 
CO2 emissions. However, because for each MWh of generation, 
NGCC units produce fewer CO2 emissions than coal-fired steam 
EGUs, the total quantity of CO2 emissions from all affected 
EGUs in aggregate would decrease without a reduction in total 
electricity generation. In the context of the integrated electricity 
system, where the operation of affected EGUs of multiple types is 
routinely coordinated to provide a highly substitutable service, and in 
the context of CO2 emissions, where location is not a 
consideration (in contrast with other pollutants), a measure that takes 
advantage of that integration to reduce CO2 emissions from 
the overall set of affected EGUs is readily understood as a means to 
implement 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, 
some industry participants are already moving in this direction for 
this purpose (while other participants are moving in the same direction 
for other purposes). Standards of performance that incorporate 
emissions trading can facilitate the implementation of such a 
``system'' and such approaches have already been used in the 
electricity industry to address CO2 as well as other 
pollutants, as discussed above.
---------------------------------------------------------------------------

    \421\ 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 proposed carbon pollution 
standards for new fossil fuel-fired EGUs.
---------------------------------------------------------------------------

    c. Building block 3. Building block 3--substituting generation from 
expanded RE generating capacity for generation from affected EGUs--is a 
component of the BSER because the expansion and use of renewable 
generating capacity to reduce emissions from affected EGUs is 
technically feasible, is of reasonable cost, and performs well with 
respect to other factors relevant to a determination of the ``best 
system of emission reduction . . . adequately demonstrated.'' Building 
block 3 is a ``system of emission reduction'' for all affected EGUs 
because incremental RE generation will result in reduced generation and 
emissions from affected EGUs, and owners or operators of affected EGUs 
can apply or implement building block 3 through a number of actions. 
For example, they can invest in incremental RE generation either 
directly or through the purchase of ERCs. An affected EGU investing in 
incremental RE generation may choose to reduce its own generation by a 
corresponding amount or may choose to allow the reduction in generation 
to occur at other affected EGUs through the coordinated planning and 
operation of the interconnected electricity system. An affected EGU can 
also invest in RE generation by means of engaging in emissions trading 
where the EGU is operating under a standard of performance that 
incorporates trading.
    The EPA's analysis and conclusions regarding the technical 
feasibility, costs, and magnitude of the measures in building block 3 
are discussed in Section V.E. below. Additional analysis and 
conclusions with respect to cost reasonableness are discussed in 
section V.A.4.d. below. We consider construction and operation of 
expanded RE generating capacity to be proven, well-established 
practices within the industry consistent with recent industry trends. 
States are already pursuing policies that encourage production of 
greater amounts of RE, such as the establishment of targets for 
procurement of renewable generating capacity. Moreover, as discussed 
earlier, markets are likely to develop for ERCs that would facilitate 
investment in increased RE generation as a means of helping sources 
comply with their standards of performance; indeed, markets for RECs, 
which similarly facilitate investment in RE for other purposes, are 
already well-established. As noted in Section V.A.5. below, an 
allowance system or tradable emission rate system would provide 
incentives for affected EGUs to reduce their emissions as much as 
possible where such reductions could be achieved economically (taking 
into account the value of the emission credits or allowances), 
including by substituting generation from new RE generating capacity 
for their own generation, or could provide a mechanism, as stated 
above, for such sources to invest in or acquire such generation.
    Building block 3 is adequately demonstrated as a ``system of 
emission reduction'' for all affected EGUs. As discussed in section II, 
RE generation has been relied on since the 1970s to provide energy 
security by replacing some fossil fuel-fired generation. Both Congress 
and the EPA have previously established frameworks under which RE 
generation could be used as a means of achieving emission reductions 
from the utility power sector, as discussed in section V.B. Investment 
in RE generation has grown rapidly, such that in recent years the 
amount of new RE generating capacity brought into service has been 
comparable to the amount of new fossil fuel-fired capacity. Rapid 
growth in RE generation is projected to continue as costs of RE 
generation fall relative to the costs of other generation technologies. 
These trends are further discussed in section V.E. Interpretation of a 
``system of emission reduction'' as including RE generation for 
purposes of this rule is thus supported by legislative history, 
regulatory precedent, and industry practice.
    Also supporting the determination that building block 3 is 
adequately demonstrated as a ``system of emission reduction'' is the 
fact that owners of affected EGUs have the ability to invest in RE 
generation as a way of reducing emissions. As with building block 2, 
this can be accomplished in several ways. For example, the owner of an 
affected EGU could invest in new RE generating capacity and operate 
that capacity in order to obtain ERCs. Alternatively, the affected EGU 
could purchase ERCs created based on the operation of an unaffiliated 
RE generating facility, effectively investing in the actions at another 
site that allow CO2 emission reductions to occur. These 
mechanisms are discussed further in section V.A.5. As with building 
block 2, in this rule the EPA is establishing minimum criteria for the 
creation of valid ERCs by new RE generators and for the use of such 
ERCs by affected EGUs for demonstrating compliance with emission rate-
based standards of performance established under state plans. The 
existence of minimum criteria will ensure that crediting mechanisms are 
feasible and will facilitate the development of organized markets to 
simplify the process of buying and selling credits. The minimum 
criteria are discussed in section VIII of the preamble.
    As with building block 2, an affected EGU investing in building 
block 3 to reduce emissions may, but need not, also choose to reduce 
its own generation as part of its approach for meeting the standard of 
performance assigned to it by its state. Through the coordinated 
operation of the integrated electricity system, subject to the 
collective requirements that will be imposed on affected EGUs in order 
to meet the

[[Page 64748]]

emissions standards representing the BSER, an increase in RE generation 
will be offset elsewhere in the interconnection by a decrease in other 
generation. Because of the need to meet the collective requirements, 
the decrease in generation resulting from that coordinated operation is 
most likely to be generation from an affected EGU. Measures taken by 
affected EGUs that result in emission reductions from other sources in 
the source category may appropriately be deemed methods to implement 
the ``system of emission reduction.''
    The renewable capacity measures in building block 3 generally 
perform well against other BSER criteria. Generation from wind turbines 
and solar voltaic installations, two common renewable technologies, 
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. With 
respect to energy impacts, fossil fuel consumption will decrease both 
for the source category as a whole and for individual affected EGUs. 
Although the variable nature of generation from renewable resources 
such as wind and solar units requires special consideration from grid 
operators to address possible changes in operating reserve 
requirements, renewable generation has grown quickly in recent years, 
as discussed above, and grid planners and operators have proven capable 
of addressing any consequent changes in requirements through ordinary 
processes. The EPA believes that planners and operators will be 
similarly capable of addressing any changes in requirements due to 
future growth in renewable generation through ordinary processes, but 
notes that in addition, the reliability safety valve in this rule, 
discussed in section VIII.G.2, will ensure the absence of adverse 
energy impacts. With respect to technological innovation, which we 
consider for the BSER only in the alternative, incentives for expansion 
of renewable capacity encourage technological innovation in improved 
renewable technologies as well as more extensive deployment of current 
advanced technologies. For all these reasons, the measures in building 
block 3 qualify as a component of the ``best system of emission 
reduction . . . adequately demonstrated.''
    d. Combination of all three building blocks. The final BSER 
includes a combination of all three 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 
also performs well against the other BSER factors; and its components 
are well-established. The combination of the three building blocks will 
achieve greater CO2 emission reductions at reasonable costs 
than possible combinations with fewer building blocks and will also 
perform better against other BSER factors. We therefore find the 
combination of all three building blocks to be the ``best system of 
emission reduction . . . adequately demonstrated'' for reducing 
CO2 emissions at affected EGUs.
    As already discussed, each of the individual building blocks 
generally performs well with respect to the BSER factors identified by 
the statute and the D.C. Circuit. (The exception, which we have pointed 
out above, is that building block 1, if implemented in isolation, would 
achieve an insufficient magnitude of emission reductions to be 
considered the BSER.) The EPA expects that combinations of the building 
blocks would perform better than the individual building blocks. 
Beginning with the most obvious and important advantage, combinations 
of the building blocks will achieve greater emission reductions than 
the individual building blocks would in isolation, assuming that the 
building blocks are applied with the same stringency. Because fossil 
fuel-fired EGUs generally have higher variable costs than other EGUs, 
it will generally be fossil fuel-fired generation that is replaced when 
low-variable cost RE generation is increased. At the levels of 
stringency determined to be reasonable in this rule, opportunities to 
deploy building block 2 to replace higher-emitting generation and to 
deploy building block 3 to replace any emitting generation are not 
exhausted. Thus, as the system of emission reduction is expanded to 
include each of these building blocks, the emission reductions that 
will be achieved increase.
    Because the stringency and timing of emission reductions achievable 
through use of each individual building block have been set based on 
what is achievable at reasonable cost rather than the maximum 
achievable amount, the stringency of the combination of building blocks 
is also reasonable, and the combination provides headroom and 
additional flexibility for states in setting standards of performance 
and for sources in complying with those standards to choose among 
multiple means of reducing emissions.
    With respect to the quantity of emission reductions expected to be 
achieved from building block 1 in particular, the BSER encompassing all 
three building blocks is a substantial improvement over building block 
1 in isolation. As noted earlier, the EPA is concerned that 
implementation of building block 1 in isolation not only would achieve 
insufficient emission reductions assuming generation levels from 
affected steam EGUs were held constant, but also has the potential to 
result in a ``rebound effect.'' The nature of the potential rebound 
effect is that by causing affected steam EGUs to improve their heat 
rates and thereby lower their variable operating costs, building block 
1 if implemented in isolation would make those EGUs more competitive 
relative to other, lower-emitting fossil fuel-fired EGUs, possibly 
resulting in increased generation and higher emissions from the 
affected steam EGUs in spite of their lower emission rates. Combining 
building block 1 with the other building blocks addresses this concern 
by ensuring that owner/operators of affected steam EGUs as a group 
would have appropriate incentives not only to improve the steam EGUs' 
efficiency but also to reduce generation from those EGUs consistent 
with replacement of generation by low- or zero-emitting EGUs. While 
combining building block 1 with either building block 2 or 3 should 
address this concern, the combination of all three building blocks 
addresses it more effectively by strengthening the incentives to reduce 
generation from affected steam EGUs.
    The combination of all three building blocks is also of reasonable 
cost, for a number of independent reasons described below. The emission 
reductions associated with the BSER determined in this rule are 
significant, necessary, and achievable. As discussed in section V.A.1. 
above, the Administrator must take cost into account when determining 
that the measures constituting the BSER are adequately demonstrated, 
and the Administrator has done so here. Below, we summarize information 
on the cost of the building block measures and discuss the several 
independent reasons for the Administrator's determination that the 
costs of the building block 1, 2, and 3 measures, alone or in 
combination, are reasonable. In considering whether these costs are 
reasonable, the EPA considered the costs in light of both the observed 
and projected effects of GHGs in the atmosphere, their effect on 
climate, and

[[Page 64749]]

the public health and welfare risks and impacts associated with such 
climate change, as described in Section II.A. The EPA focused on public 
health and welfare impacts within the U.S., but the impacts in other 
world regions strengthen the case for action because impacts in other 
world regions can in turn adversely affect the U.S. or its citizens. In 
looking at whether costs were reasonable, the EPA also considered that 
EGUs are by far the largest emitters of GHGs among stationary sources 
in the U.S., as more fully set forth in section II.B.
    As described in sections V.C. through V.E. and the GHG Mitigation 
Measures TSD, the EPA has determined that the cost of each of the three 
building blocks is reasonable. In summary, these cost estimates are $23 
per ton of CO2 reductions for building block 1, $24 per ton 
for building block 2, and $37 per ton for building block 3. The EPA 
estimates that, together, the three building blocks are able to achieve 
CO2 reductions at an average cost of $30 per ton, which the 
EPA likewise has determined is reasonable. The $30 per ton estimate is 
an average of the estimates for each building block, weighted by the 
total estimated cumulative CO2 reductions for each of these 
building blocks over the 2022-2030 period. While it is possible to 
weight each building block by other amounts, the EPA believes that 
weighting by cumulative CO2 reductions best reflects the 
average cost of total reduction potential across the three building 
blocks. The EPA considers each of these cost levels reasonable for 
purposes of the BSER established for this rule.
    The EPA views the weighted average cost estimate as a 
conservatively high estimate of the cost of deploying all three 
building blocks simultaneously. The simultaneous application of all 
three building blocks produces interactive dynamics, some of which 
could increase the cost and some of which could decrease the cost 
represented in the individual building blocks. For example, one dynamic 
that would tend to raise costs (and whose omission would therefore make 
the weighted average understate costs) is that the emission reduction 
measures associated with building blocks 2 and 3 both prioritize the 
replacement of higher-cost generation (from affected steam EGUs in the 
case of building block 2 and from all affected EGUs in the case of 
building block 3). The EPA recognizes that the increased magnitude of 
generation replacement when building blocks 2 and 3 are implemented 
together necessitates that some of the generation replacement will 
occur at more efficient affected EGUs, at a relatively higher cost; 
however, this is a consequence of the greater emission reductions that 
can be achieved by combining building blocks, not an indication that 
any individual building block has become more expensive because of the 
combined deployment.
    Also, the EPA recognizes that when building block 1 is combined 
with the other building blocks, the combination 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 
same reductions if building block 1 were implemented in isolation 
(assuming for purposes of this discussion that the rebound effect is 
not an issue and that the affected steam EGUs would in fact reduce 
their emissions if building block 1 were implemented in 
isolation).\422\ However, we believe that the cost of emission 
reductions achieved through heat rate improvements in the context of a 
three-building block BSER will remain reasonable for two reasons. 
First, as discussed in section V.C. below, even when conservatively 
high investment costs are assumed, the cost of CO2 emission 
reductions achievable through heat rate improvements is low enough that 
the cost per ton of CO2 emission reductions will remain 
reasonable even if that cost is substantially increased. Second, 
although under a BSER encompassing all three building blocks the volume 
of coal-fired generation will decrease, that decrease is unlikely to be 
spread uniformly among all coal-fired EGUs. It is more likely that some 
coal-fired EGUs will decrease their generation slightly or not at all 
while others will 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 will be 
a tendency for such investments to be concentrated in EGUs whose 
generation output is expected to decrease the least. This enlightened 
bias in spending on heat rate improvements--that is, focusing 
investments on EGUs where such improvements will have the largest 
impacts and produce the highest returns, given consideration of 
projected changes in dispatch patterns--will tend to mitigate any 
deterioration in the cost of CO2 emission reductions 
achievable through heat rate improvements.
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    \422\ 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. Commenters have also stated that 
operating at lower capacity factors may cause units to experience 
deterioration in heat rates.
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    In contrast with those prior examples, combining the building 
blocks also produces interactive dynamics that significantly reduce the 
cost for CO2 reductions represented in the individual 
building blocks (and whose omission would therefore make the weighted 
average overstate costs). Foremost among these dynamics is the 
stabilization of wholesale power prices. When assessed individually, 
building blocks 2 and 3 have opposite impacts on wholesale power 
prices, although in each case, the direction of the wholesale power 
price impact corresponds to an increasing cost of that building block 
in isolation. For example, building block 2 promotes more utilization 
of existing NGCC capacity, which (assessed on its own) would increase 
natural gas consumption and therefore price, in turn raising wholesale 
power prices (which are often determined by gas-fired generators as the 
power supplier on the margin); this dynamic puts upward pressure on the 
cost of achieving CO2 reductions through shifting generation 
from steam EGUs to NGCC units.\423\ Meanwhile, building block 3 
increases RE deployment; because RE generators have very little 
variable cost, an increase in RE generation replaces other supply with 
higher variable cost, which would yield lower wholesale power prices. 
Lower wholesale power prices would make further RE deployment less 
competitive against generation from existing emitting sources; while 
this dynamic would generally reduce electricity prices to consumers, it 
also puts upward pressure on the cost of achieving CO2 
reductions through increased RE deployment.\424\ Applying building 
blocks 2 and 3 together produces significantly more CO2 
reductions at a relatively lower cost because the countervailing nature 
of these wholesale power price dynamics mitigates the primary cost 
drivers for each building block.\425\
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    \423\ The EPA's cost-effectiveness estimate of $24 per ton for 
building block 2 reflects these market dynamics.
    \424\ The EPA's cost-effectiveness estimate of $37 per ton for 
building block 3 reflects these market dynamics.
    \425\ Notwithstanding the interactive dynamics that improve the 
cost effectiveness of emission reductions when building blocks 2 and 
3 are implemented together, we also consider each of these building 
blocks to be independently of reasonable cost, so that either 
building block 2 or 3 alone, or combinations of the building blocks 
that include either but not both of these two building blocks, could 
be the BSER if a court were to strike down the other building block, 
as discussed in section V.A.7. below. (We also note in section 
V.A.7. that a combination of building blocks 2 and 3 without 
building block 1 could be the BSER if a court were to strike down 
building block 1.)

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[[Page 64750]]

    The EPA believes the dynamics tending to cause the weighted average 
above to overstate costs of the combination of building blocks are 
greater than the dynamics tending to cause costs to be understated, and 
that the weighted average costs are therefore conservatively high. 
Analysis performed by the EPA at an earlier stage of the rulemaking 
supports this conclusion. At proposal, the EPA evaluated the cost of 
increasing NGCC utilization (building block 2) and deploying 
incremental RE generation (building block 3) independently, as well as 
the cost of simultaneously increasing NGCC utilization and incremental 
RE generation. The average cost (in dollars per ton of CO2 
reduced) was less for the combined building block scenario, showing 
that the net outcome of the interactivity effects described above is a 
reduction in cost per ton when compared to cost estimates that do not 
incorporate this interactivity.\426\
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    \426\ Specifically, at proposal the EPA quantified the average 
cost, in dollar per ton of CO2 reduced, of building 
blocks 1, 2, and 3 ($22.5 per ton) to be less than the cost of 
either building block 2 ($28.9 per ton) or building block 3 ($23.4 
per ton) alone.
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    A final reason why the EPA considers the weighted-average cost 
above conservatively high is that simply combining the building blocks 
at their full individual stringencies overstates the stringency of the 
BSER. As discussed in section V.A.3.f and section VI, the BSER reflects 
the combined degree of emission limitation achieved through application 
of the building blocks in the least stringent region. By definition, in 
the other two regions, the BSER is less stringent than the simple 
combination of the three building blocks whose stringency is 
represented in the weighted-average cost above.
    The cost estimates for each of the three building blocks cited 
above--$23, $24, and $37 per ton of CO2 reductions from 
building blocks 1, 2, and 3, respectively--are each conservatively high 
for the reasons discussed in section V.C., V.D., and V.E. below. 
Likewise, the $30 per ton weighted-average cost of all three building 
blocks is a conservatively high estimate of the cost of the combination 
of the three individual building block costs, as described above. While 
conservatively high, and especially so in the case of the $30 per ton 
weighted-average cost, these estimates fall well within the range of 
costs that are reasonable for the BSER for this rule.
    In assessing cost reasonableness for the BSER determination for 
this rule, the EPA has compared the estimated costs discussed above to 
two types of cost benchmark. The first type of benchmark comprises 
costs that affected EGUs incur to reduce other air pollutants, such as 
SO2 and NOX. In order to address various 
environmental requirements, many coal-fired EGUs have been required to 
decide between either shutting down or installing and operating flue 
gas desulfurization (FGD) equipment--that is, wet or dry scrubbers--to 
reduce their SO2 emissions. The fact that many of these EGUs 
have chosen scrubbers in preference to shutting down is evidence that 
scrubber costs are reasonable, and we believe that the cost of these 
controls can reasonably serve as a cost benchmark for comparison to the 
costs of this rule. We estimate that for a 300-700 MW coal-fired steam 
EGU with a heat rate of 10,000 Btu per kWh and operating at a 70 
percent utilization rate, the annualized costs of installing and 
operating a wet scrubber are approximately $14 to $18 per MWh and the 
annualized costs of installing and operating a dry scrubber are 
approximately $13 to $16 per MWh.\427\
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    \427\ For details of these computations, see the memorandum 
``Comparison of building block costs to FGD costs'' available in the 
docket.
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    In comparison, we estimate that for a coal-fired steam EGU with a 
heat rate of 10,000 Btu per kWh, assuming the conservatively high cost 
of $30 per ton of CO2 removed through the combination of all 
three building blocks, the cost of reducing CO2 emissions by 
the amount required to achieve the uniform CO2 emission 
performance rate for steam EGUs of 1,305 lbs. CO2 per MWh 
would be equivalent to approximately $11 per MWh. The comparable costs 
for achieving the required emission performance rate for steam EGUs 
through use of the individual building blocks range from $8 to $14 per 
MWh. For an NGCC unit with a heat rate of 7,800 Btu per kWh, assuming a 
conservatively high cost of $37 per ton of CO2 removed 
through the use of building block 3,\428\ the cost of reducing 
CO2 emissions by the amount required to achieve the uniform 
CO2 emission performance rate for NGCC units of 771 lbs. 
CO2 per MWh would be equivalent to approximately $3 per 
MWh.\429\ These estimated CO2 reduction costs of $3 to $14 
per MWh to achieve the CO2 emission performance rates are 
either less than the ranges of $14 to $18 and $13 to $16 per MWh to 
install and operate a wet or dry scrubber, or in the case of 
CO2 emission reductions at a steam unit achieved through 
building block 3, near the low end of the ranges of scrubber costs. 
This comparison demonstrates that the costs associated with the BSER in 
this rule are reasonable compared to the costs that affected EGUs 
commonly face to comply with other environmental requirements.
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    \428\ The comparison for an NGCC unit considers only building 
block 3 because building blocks 1 and 2 do not apply to NGCC units.
    \429\ For details of these computations, see the memorandum 
``Comparison of building block costs to FGD costs'' available in the 
docket.
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    The second type of benchmark comprises CO2 prices that 
owners of affected EGUs use for planning purposes in their IRPs. 
Utilities subject to requirements to prepare IRPs commonly include 
assumptions regarding future environmental regulations that may become 
effective during the time horizon covered by the IRP, and assumptions 
regarding CO2 regulations are often represented in the form 
of assumed prices per ton of CO2 emitted or reduced. A 
survey of the CO2 price assumptions from 46 recent IRPs 
shows a range of CO2 prices in the IRPs' reference cases of 
$0 to $30 per ton, and a range of CO2 prices in the IRPs' 
high cases from $0 to $110 per ton.\430\ In comparison, the 
conservatively high, weighted-average cost of $30 per ton removed 
described above is at the high end of the range of reference case 
assumptions but at the low end of the range of the high case 
assumptions. The costs of the individual building blocks are likewise 
well within the range of the high case assumptions, and either at or 
slightly above the high end of the reference case assumptions. This 
comparison demonstrates that the costs associated with the BSER in this 
rule are reasonable compared to the expectations of the industry for 
the potential costs of CO2 regulation.
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    \430\ See Synapse Energy Economics Inc., 2015 Carbon Dioxide 
Price Forecast (March 3, 2015) at 25-28, available at http://www.synapse-energy.com/sites/default/files/2015%20Carbon%20Dioxide%20Price%20Report.pdf.
---------------------------------------------------------------------------

    In addition to comparison to these benchmarks, there is a third 
independent way in which EPA has considered cost. In light of the 
severity of the observed and projected climate change effects on the 
U.S., U.S. interests, and U.S. citizens, combined with EGUs' large 
contribution to U.S. GHG emissions, the costs of the BSER measures are 
reasonable when compared to other potential control measures for this 
sector available under

[[Page 64751]]

section 111. Given EGUs' large contribution to U.S. GHG emissions, any 
attempt to address the serious public health and environmental threat 
of climate change must necessarily include significant emission 
reductions from this sector. The agency would therefore consider even 
relatively high costs--which these are not--to be reasonable. Imposing 
only the lower cost reduction measures in building block 1 would not 
achieve sufficient reductions given the scope of the problem and EGUs' 
contribution to it. While the EPA also considered measures such as CCS 
retrofits for all fossil-fired EGUs or co-firing at all steam units, 
the EPA determined that these costs were too high when considered on a 
sector-wide basis. Furthermore, the EPA has not identified other 
measures available under section 111 that are less costly and would 
achieve emission reductions that are commensurate with the scope of the 
problem and EGUs' contribution to it. Thus, the EPA determined that the 
costs of the measures in building blocks 1, 2 and 3, individually or in 
combination, are reasonable because they achieve an appropriate balance 
between cost and amount of reductions given the other potential control 
measures under section 111.
    As required under Executive Order 12866, the EPA conducts benefit-
cost analyses for major Clean Air Act rules.\431\ While benefit-cost 
analysis can help to inform policy decisions, as permissible and 
appropriate under governing statutory provisions, the EPA does not use 
a benefit-cost test (i.e., a determination of whether monetized 
benefits exceed costs) as the sole or primary decision tool when 
required to consider costs or to determine whether to issue regulations 
under the Clean Air Act, and is not using such a test here.\432\ 
Nonetheless, the EPA observes that the costs of the building block 1, 2 
and 3 measures, both individually and combined as discussed in this 
section above, are less than the central estimates of the social cost 
of carbon. Developed by an interagency workgroup, the social cost of 
carbon (SC-CO2) is an estimate of the monetary value of 
impacts associated with marginal changes in CO2 emissions in 
a given year.\433\ It is typically used to assess the avoided damages 
as a result of regulatory actions (i.e., benefits of rulemakings that 
lead to an incremental reduction in cumulative global CO2 
emissions).\434\ The central values for the SC-CO2 range 
from $40 per short ton in 2020 to $48 per short ton in 2030.\435\ The 
weighted-average cost estimate of $30 per ton is well below this range.
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    \431\ The EPA's regulatory impact analysis for this rule, which 
appropriately includes a representation of the flexibility available 
under the rule to comply using a combination of BSER and non-BSER 
measures (such as demand-side energy efficiency) is discussed in 
section XI of the preamble.
    \432\ See memo entitled ``Consideration of Costs and Benefits 
Under the Clean Air Act'' available in the docket.
    \433\ Estimates are presented in the Technical Support Document: 
Technical Update of the Social Cost of Carbon for Regulatory Impact 
Analysis Under Executive Order 12866 (May 2013, Revised July 2015), 
Interagency Working Group on Social Cost of Carbon, with 
participation by Council of Economic Advisers, Council on 
Environmental Quality, Department of Agriculture, Department of 
Commerce, Department of Energy, Department of Transportation, 
Environmental Protection Agency, National Economic Council, Office 
of Energy and Climate Change, Office of Management and Budget, 
Office of Science and Technology Policy, and Department of Treasury 
(May 2013, Revised July 2015). Available at: https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf> Accessed 7/11/2015.
    \434\ The SC-CO2 estimates do not include all 
important damages because of current modeling and data limitations. 
The 2014 IPCC report observed that SC-CO2 estimates omit 
various impacts that would likely increase damages. See IPCC, 2014: 
Climate Change 2014: Impacts, Adaptation, and Vulnerability. 
Contribution of Working Group II to the Fifth Assessment Report of 
the Intergovernmental Panel on Climate Change. Cambridge University 
Press, Cambridge. https://www.ipcc.ch/report/ar5/wg2/.
    \435\ The 2010 and 2013 TSDs present SC-CO2 in 2007$ 
per metric ton. The unrounded estimates from the current TSD were 
adjusted to (1) 2011$ using GDP Implicit Price Deflator (1.061374), 
http://www.bea.gov/iTable/index_nipa.cfm and (2) short tons using 
the conversion factor of 0.90718474 metric tons in a short ton. 
These estimates were rounded to two significant digits.
---------------------------------------------------------------------------

    Finally, the EPA notes that the combination of all three building 
blocks would perform consistently with the individual building blocks 
with respect to non-air energy and environmental impacts. There is no 
reason to expect an adverse non-air environmental or energy impact from 
deployment of the combination of the three building blocks, whether 
considered on a source-by-source basis, on a sector-wide or national 
basis, or both. In fact, the combination of the building blocks, like 
the building blocks individually, as discussed above, would be expected 
to produce non-air environmental co-benefits in the form of reduced 
water usage and solid waste production (and, in addition to these non-
air environmental co-benefits, would also be expected to reduce 
emissions of non-CO2 air pollutants such as SO2, 
NOX, and mercury). Likewise, with respect to technological 
innovation, which we consider only in the alternative, the building 
blocks in combination would have the same positive effects that they 
would have if implemented independently.
    e. Other combinations of the building blocks. The EPA has 
considered whether other combinations of the building blocks, such as a 
combination of building blocks 1 and 2 or a combination of building 
blocks 1 and 3, could be the BSER. We believe that any such 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. As with the combination of 
three building blocks discussed above, any combination of building 
blocks would achieve greater emission reductions than the individual 
building blocks encompassed in that combination would achieve if 
implemented in isolation. Further, the cost of any combination would be 
driven principally by the combined stringency and would remain 
reasonable in aggregate, such that the conclusions on cost 
reasonableness discussed in section V.A.4.d. would continue to apply. 
We have already noted our determination that building block 1 in 
isolation is not the BSER because it would not produce a sufficient 
quantity of emission reductions. A combination of building block 1 with 
one of the other building blocks would produce greater emission 
reductions and would not be subject to this concern. Any combination of 
building blocks including building block 1 and at least one other 
building block would also address the concern about potential ``rebound 
effect,'' discussed above, that could occur if building block 1 were 
implemented in isolation. Finally, there is no reason to expect any 
combination of the building blocks to have adverse non-air energy or 
environmental impacts, and the implications for technological 
innovation, which we consider only in the alternative, would likewise 
be positive for any combination of the building blocks because those 
implications are positive for the individual building blocks and there 
is no reason to expect negative interaction from a combination of 
building blocks.
    For these reasons, any combination of the building blocks (but not 
a BSER comprising building block 1 in isolation) could be the BSER if 
it were not for the fact that a BSER comprising all three of the 
building blocks will achieve greater emission reductions at a 
reasonable cost and is therefore ``better.'' As discussed below in 
section V.A.7., we intend for the individual building blocks to be 
severable, such that if a court were to deem building block 2 or 3 
defective, but not both, the BSER would comprise the remaining building 
blocks.
    f. Achievability of emission limits. As noted, based on the BSER, 
the EPA has

[[Page 64752]]

established a source subcategory-specific emission performance rate for 
fossil steam units and one for NGCC units. As discussed in section 
V.A.1.c., for new sources, standards of performance must be 
``achievable'' under CAA section 111(a)(1), and the D.C. Circuit has 
identified criteria for achievability.\436\ In this rule, the EPA is 
taking the approach that while the states are not required to adopt 
those source subcategory-specific emission performance rates as the 
standards of performance for their affected EGUs, those rates must be 
achievable by the steam generator and NGCC subcategories, respectively. 
In addition, the EPA is assuming that the achievability criteria in the 
case law for new sources apply to existing sources under section 
111(d). For the reasons discussed next, for this rule, the source 
subcategory-specific emission performance rates are achievable in 
accordance with those criteria in the case law.
---------------------------------------------------------------------------

    \436\ See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 
(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974); Nat'l Lime 
Ass'n v. EPA, 627 F.2d 416, 433, n.46 (D.C. Cir. 1980); Sierra Club 
v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) (citing Nat'l Lime 
Ass'n v. EPA, 627 F.2d 416 (D.C. Cir. 1980).
---------------------------------------------------------------------------

    As noted, the building blocks include several features that assure 
that affected EGUs may implement them. The building blocks may be 
implemented through a range of methods, including through the purchase 
of ERCs and emission trading. In addition, the building blocks 
incorporate ``headroom.'' Moreover, the source subcategory-specific 
emission performance rates apply on an annual or longer basis, so that 
short-term issues need not jeopardize compliance. In addition, we 
quantify the emission performance rates based on the degree of emission 
limitation achievable by affected EGUs in the region where application 
of the combined building blocks results in the least stringent emission 
rate. Because the means to implement the building blocks are widely 
available and because of the just-noted flexibilities and approaches to 
the emission performance rates, all types of affected steam generating 
units, operating throughout the lower-48 states and under all types of 
regulatory regimes, are able to implement building blocks 1, 2 and 3 
and thereby achieve the emission performance rate for fossil steam 
units, and all types of NGCC units operating in all states under all 
types of regulatory requirements are able to implement building block 3 
and thereby achieve the emission performance rate for NGCC units.\437\
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    \437\ We discuss the ability of affected EGUs to implement the 
building blocks in more detail in sections V.C., V.D., and V.E. and 
the accompanying support documents.
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    Commenters have raised questions about whether particular 
circumstances could arise, such as the sudden loss of certain 
generation assets, that would cause the implementation of the building 
blocks to cause reliability problems, and have cautioned that these 
circumstances could preclude implementation of the building blocks and 
thus achievement of the emission performance rates. Commenters have 
also raised concerns about whether affected EGUs with limited remaining 
useful lives can implement the building blocks and achieve the emission 
performance rates. We address those concerns in section VIII, where we 
authorize state plans to include a reliability mechanism and discuss 
affected EGUs with limited remaining useful lives. Accordingly, we 
conclude that the source subcategory-specific emission performance 
standards are achievable in accordance with the case law.
5. Actions Under the BSER That Sources Can Take To Achieve Standards of 
Performance
    Based on the determination of the BSER described above, the EPA has 
identified a performance rate of 1305 lbs. per net MWh for affected 
steam EGUs and a performance rate of 771 lbs. per net MWh for affected 
stationary combustion turbines. The computations of these performance 
rates and the determinations of state goals reflecting these rates are 
described in sections VI and VII of the preamble, respectively.
    Under section 111(d), states determine the standards of performance 
for individual sources. The EPA is authorizing states to express the 
standards of performance applicable to affected EGUs as either emission 
rate-based limits or mass-based limits. As described above, the sets of 
actions that sources can take to comply with these standards implement 
or apply the BSER and, in that sense, may be understood as part of the 
BSER.
    A source to which a state applies an emission rate-based limit can 
achieve the limit through a combination of the following set of 
measures (to the extent allowed by the state plan), all of which are 
components of the BSER, again, in the sense that they implement or 
apply it:
     Reducing its heat rate (building block 1).
     Directly investing in, or purchasing ERCs created as a 
result of, incremental generation from existing NGCC units (building 
block 2).
     Directly investing in, or purchasing ERCs created as a 
result of, generation from new or uprated RE generators (building 
block 3).
     Reducing its utilization, coupled with direct 
investment in or purchase of ERCs representing building blocks 2 and 
3 as indicated above.
     Investing in surplus emission rate reductions at other 
affected EGUs through the purchase or other acquisition of rate-
based emission credits.

    A source to which a state applies a mass-based limit can achieve 
the limit through a combination of the following set of measures (to 
the extent allowed by the state plan), all of which are likewise 
components of the BSER:

     Reducing its heat rate (building block 1).
     Reducing its utilization and allowing its generation to 
be replaced or avoided through the routine operation of industry 
reliability planning mechanisms and market incentives.
     Investing in surplus emission reductions at other 
affected EGUs through the purchase or other acquisition of mass-
based emission allowances.

    The EPA has determined appropriate CO2 emission 
performance rates for each of the two source subcategories as a whole 
achievable through application of the building blocks. The wide ranges 
of measures included in the BSER and available to individual sources as 
indicated above provide assurance that the source category as a whole 
can achieve standards of performance consistent with those emissions 
standards using components of the BSER, whether states choose to 
establish emission rate-based limits or mass-based limits. The wide 
ranges of measures included in the BSER also provide assurance that 
each individual affected EGU could achieve the standard of performance 
its state establishes for it using components of the BSER. Of course, 
sources may also employ measures not included in the BSER, to the 
extent allowed under the applicable state plan.
    In the remainder of this subsection, we discuss further how 
affected EGUs can use each of the measures listed above to achieve 
emission rate-based forms of performance standards and mass-based forms 
of performance standards, indicating that all types of owner/operators 
of affected EGUs--i.e., vertically integrated utilities and merchant 
generators; investor-owned, government-owned, and customer-owned 
(cooperative) utilities; and owner/operators of large, small, and 
single-unit fleets of generating units--have the ability to implement 
each of the building blocks in some way. In the following subsection we 
discuss the use

[[Page 64753]]

of measures not in the BSER that can help sources achieve the standards 
of performance.
    a. Use of BSER measures to achieve an emission rate-based standard. 
Under an emission-rate based form of performance standards, compliance 
is nominally determined through a comparison of the affected EGU's 
emission rate to the emission rate standard. The emissions-reducing 
impact of BSER measures that reduce CO2 emissions through 
reductions in the quantity of generation rather than through reductions 
in the amount of CO2 emitted per unit of generation would 
not be reflected in an affected EGU's emission rate computed solely 
based on measured stack emissions and measured electricity generation 
but can readily be reflected in an emission rate computation by 
averaging ERCs acquired by the affected EGU into the rate computation.
    In section VIII.K, we discuss the processes for issuance and use of 
ERCs that can be included in the emission rate computations that 
affected EGUs perform to demonstrate compliance with an emission rate 
standard. This ERC mechanism is analogous to the approach the EPA has 
used to reflect building blocks 2 and 3 in the uniform emission rates 
representing the BSER, as discussed in section VI below. As summarized 
below and as discussed in greater detail in section VIII.K, the 
existence of a clearly feasible path for usage of ERCs ensures that 
emission reductions achievable through implementation of the measures 
in building blocks 2 and 3 are available to assist all affected EGUs in 
achieving compliance with standards of performance based on the BSER.
    (1) Building block 1.
    The owner/operator of an affected steam EGU can take steps to 
reduce the unit's heat rate, thereby lowering the unit's CO2 
emission rate. Examples of actions in this category are included in 
section V.C. below and in the GHG Mitigation Measures TSD for the CPP 
Final Rule. Any type of owner/operator can take advantage of this 
measure.
    (2) Building block 2.
    The owner/operator of an affected EGU can average the EGU's 
emission rate with ERCs issued on the basis of incremental generation 
from an existing NGCC unit. As permitted under the EGU's state's 
section 111(d) plan, the owner/operator of the affected EGU could 
accomplish this through either common ownership of the NGCC unit, a 
bilateral transaction with the owner/operator of the NGCC unit, or a 
transaction for ERCs through an intermediary, which could but need not 
involve an organized market.\438\ As discussed earlier, based on 
observation of market behavior both inside and outside the electricity 
industry, we expect that intermediaries will seek opportunities to 
participate in such transactions and that organized markets are likely 
to develop as well if section 111(d) plans authorize the use of ERCs. 
While the opportunity to acquire ERCs through common ownership of NGCC 
facilities might not extend to owner/operators of single EGUs or small 
fleets, all owner/operators would have the ability to engage in 
bilateral or intermediated purchase transactions for ERCs just as they 
can engage in transactions for other kinds of goods and services.
---------------------------------------------------------------------------

    \438\ Each of these methods of implementing building block 2 
meets the criteria for the BSER in that (i) as we discuss in section 
V.D. and supporting documents, each of these methods is adequately 
demonstrated;(ii) the costs of each of these methods on a source-by-
source basis are reasonable, as discussed above; and (iii) none of 
these methods causes adverse energy impacts or non-quality 
environmental impacts.
---------------------------------------------------------------------------

    In section VIII.K below, the EPA sets out the minimum criteria that 
must be satisfied for generation and issuance of a valid ERC based upon 
incremental electricity generation by an existing NGCC unit. Those 
criteria generally concern ensuring that the physical basis for the 
ERC--i.e., qualifying generation by an existing NGCC unit and the NGCC 
unit CO2 emissions associated with that qualifying 
generation--is adequately monitored and that there is an adequate 
administrative process for tracking credits to avoid double-counting. 
In the case of ERCs related to building block 2, the monitoring 
criteria would generally be satisfied by standard 40 CFR part 75 
monitoring.
    The owner/operator of an affected steam EGU would use the ERCs it 
has acquired for compliance--whether acquired through ownership of NGCC 
capacity, a bilateral transaction, or an intermediated transaction--by 
adding the ERCs to its measured net generation when computing its 
CO2 emission rate for purposes of demonstrating compliance 
with its emission rate-based standard of performance.
    (3) Building block 3.
    The owner/operator of an affected EGU can average the EGU's 
emission rate with ERCs issued on the basis of generation from new 
(i.e., post-2012) RE generating capacity, including both newly 
constructed capacity and new uprates to existing RE generating 
capacity. As permitted under the EGU's state's section 111(d) plan, the 
owner/operator of the affected EGU could accomplish this through either 
common ownership of the RE generating capacity, a bilateral transaction 
with the owner/operator of the RE generating capacity, or a transaction 
for ERCs through an intermediary, which could, but need not, involve an 
organized market.\439\ As discussed earlier, based on observation of 
market behavior both inside and outside the electricity industry, we 
expect that intermediaries will seek opportunities to participate in 
such transactions and that organized markets are likely to develop as 
well if section 111(d) plans authorize the use of ERCs. While the 
opportunity to acquire ERCs through common ownership of RE generating 
facilities might not extend to owner/operators of single EGUs or small 
fleets, all owner/operators would have the ability to engage in 
bilateral or intermediated purchase transactions for ERCs just as they 
can engage in transactions for other kinds of goods and services.
---------------------------------------------------------------------------

    \439\ As with building block 2, each of these methods of 
implementing building block 3 meets the criteria for the BSER in 
that (i) as we discuss in section V.E. and supporting documents, 
each of these methods is adequately demonstrated; (ii) the costs of 
each of these methods on a source-by-source basis are reasonable, as 
discussed above; and (iii) none of these methods causes adverse 
energy impacts or non-quality environmental impacts.
---------------------------------------------------------------------------

    In section VIII.K below, the EPA sets out the minimum criteria that 
must be satisfied for generation and issuance of a valid ERC based upon 
generation from new RE generating capacity. Those criteria generally 
concern assuring that the physical basis for the ERC--i.e., generation 
by qualifying new RE capacity--is adequately monitored and that there 
is an adequate administrative process for tracking credits to avoid 
double-counting.\440\
---------------------------------------------------------------------------

    \440\ The possible use of types of RE generating capacity that 
are not included in the BSER is discussed in section V.A.6. and 
section VIII of the preamble.
---------------------------------------------------------------------------

    As with building block 2, the owner/operator of an affected EGU 
would use the ERCs it has acquired for compliance--whether acquired 
through ownership of qualifying RE generating capacity, a bilateral 
transaction, or an intermediated transaction--by adding the ERCs to its 
measured net generation when computing its CO2 emission rate 
for purposes of demonstrating compliance with its emission rate-based 
standard of performance.
    (4) Reduced generation.
    The owner/operator of an affected EGU can reduce the unit's 
generation and reflect that reduction in the form of a lower emission 
rate provided that the owner/operator also acquires some amount of ERCs 
to use in computing the unit's emission rate for purposes of 
demonstrating compliance. As

[[Page 64754]]

permitted under the EGU's state's section 111(d) plan, the ERCs could 
be acquired through investment in incremental generation from existing 
NGCC capacity, generation from new RE generating capacity, or purchase 
from an entity with surplus ERCs. If the owner/operator does not 
average any ERCs into the unit's emission rate, reducing the unit's own 
generation will proportionately reduce both the numerator and 
denominator of the fraction and therefore will not affect the computed 
emission rate (unless the unit retires, reducing its emission rate to 
zero). However, if the owner/operator does average ERCs into the unit's 
emission rate, then a proportional reduction in both the numerator and 
the portion of the denominator representing the unit's measured 
generation will amplify the effect of the acquired ERCs in the 
computation, with the result that the more the unit reduces its 
generation, the fewer ERCs will be needed to reach a given emission 
rate-based standard of performance. All owner/operators have the 
ability to reduce generation, and as discussed above all also would be 
capable of acquiring ERCs, so all would be capable of reflecting 
reduced utilization in their emission rates for purposes of 
demonstrating compliance.
    (5) Emissions trading approaches.
    To the extent allowed under standards of performance that 
incorporate emissions trading or otherwise through the relevant section 
111(d) plans, the owner/operator of an affected EGU can acquire 
tradable rate-based emission credits representing an investment in 
surplus emission rate reductions not needed by another affected EGU and 
can average those credits into its own emission rate for purposes of 
demonstrating compliance with its rate-based standard of performance. 
The approach would have to be authorized in the appropriate section 
111(d) plan and would have to conform to the minimum conditions for 
such approaches described in section VIII below. As we have repeatedly 
noted, based on our reading of the comment record and the discussions 
that occurred during the outreach process, it is reasonable to presume 
that such authorization will be forthcoming from states that submit 
plans establishing rate-based standards of performance for their 
affected EGUs.
    Under a rate-based emissions trading approach, credits are 
initially created and issued according to processes defined in the 
state plan. After credits are initially issued, the owner/operator of 
an affected EGU needing additional credits can acquire credits through 
common ownership of another affected EGU or through a bilateral 
transaction with the other affected EGU, or the owner/operator of the 
affected EGU can acquire credits in a transaction through an 
intermediary, which could, but need not, involve an organized market. 
As discussed earlier, based on observation of market behavior both 
inside and outside the electricity industry, we expect that 
intermediaries will seek opportunities to participate in such 
transactions and that organized markets are likely to develop as well 
if section 111(d) plans and/or standards of performance established 
thereunder authorize emissions trading. While the opportunity to 
acquire credits through common ownership might not extend to owner/
operators of single EGUs or small fleets, all owner/operators would 
have the ability to engage in bilateral or intermediated purchase 
transactions for credits just as they can engage in transactions for 
other kinds of goods and services.
    Further details regarding the possible use of rate-based emission 
credits in a state plan (using ERCs issued on the basis of investments 
in building blocks 2 and 3 and potentially other measures as the 
credits) are provided in section VIII.K.
    b. Use of BSER measures to achieve a mass-based standard. Under a 
mass-based form of the standard, compliance is determined through a 
comparison of the affected EGU's monitored mass emissions to a mass-
based emission limit. Although a state could choose to impose specific 
mass-based limits that each EGU would be required to meet on a physical 
basis, in past instances where mass-based limits have been established 
for large numbers of sources it has been typical for the limit on each 
affected EGU to be structured as a requirement to periodically 
surrender a quantity of emission allowances equal to the source's 
monitored mass emissions. The EPA believes that section 111(d) 
encompasses the flexibility for plans to impose mass-based standards in 
the typical manner where the standard of performance for each affected 
EGU consists of a requirement to surrender emission allowances rather 
than a requirement to physically comply with a unit-specific emissions 
cap.
    Measurements of mass emissions at a given affected EGU capture 
reductions in the EGU's emissions arising from both reductions in 
generation and reductions in the emission rate per MWh. Accordingly, 
under a mass-based standard there is no need to provide a mechanism 
such as the ERC mechanism described above in order to properly account 
for emission reductions attributable to particular types of BSER 
measures. The relative simplicity of the mechanics of monitoring and 
determining compliance are significant advantages inherent in the use 
of mass-based standards rather than emission rate-based standards.
    (1) Building block 1.
    The owner/operator of an affected steam EGU can take steps to 
reduce the unit's heat rate, thereby lowering the unit's CO2 
mass emissions. Examples of actions in this category are included in 
section V.C. below and in the GHG Mitigation Measures TSD for the CPP 
Final Rule. Any type of owner/operator can take advantage of this 
measure.
    (2) Reduced generation.
    The owner/operator of an affected EGU can reduce its generation, 
thereby lowering the unit's CO2 mass emissions. Any type of 
owner/operator can take advantage of this measure. Although some action 
or combination of actions to increase lower-carbon generation or reduce 
electricity demand somewhere in the interconnected electricity system 
of which the affected EGU is a part will be required to enable 
electricity supply and demand to remain in balance, the affected EGU 
does not need to monitor or track those actions in order to use its 
reduction in generation to help achieve compliance with the mass-based 
standard. Instead, multiple participants in the interconnected 
electricity system will act to ensure that supply and demand remain in 
balance, subject to the complex and constantly changing set of 
constraints on operation of the system, just as those participants have 
routinely done for years.
    Of course, if the owner/operator of the affected EGU wishes to play 
a direct role in driving the increase in lower-carbon generation or 
demand-side EE required to offset a reduction in the affected EGU's 
generation, the owner/operator may do so as part of whatever role it 
happens to play as a participant in the interconnected electricity 
system. However, the owner/operator will achieve the benefit that 
reduction in generation brings toward compliance with the mass-based 
standard whether it takes those additional actions itself or instead 
allows other participants in the interconnected electricity system to 
play that role.
    (3) Emissions trading approaches.
    To the extent allowed under the relevant section 111(d) plans--as 
the record indicates that it is reasonable to expect it will be--the 
owner/operator of an affected EGU can acquire tradable mass-based 
emission allowances representing investment in surplus emission 
reductions not needed by another affected EGU and can aggregate those 
allowances with any other

[[Page 64755]]

allowances it already holds for purposes of demonstrating compliance 
with its mass-based standard of performance. The approach would have to 
be authorized in the appropriate section 111(d) plan and would have to 
conform to the minimum conditions for such approaches described in 
section VIII below.
    Under a mass-based emissions trading approach, the total number of 
allowances to be issued is defined in the state plan, and affected EGUs 
may obtain an initial quantity of allowances through an allocation or 
auction process. After that initial process, the owner/operator of an 
affected EGU needing additional allowances can acquire allowances 
through common ownership of another affected EGU or through a bilateral 
transaction with the other affected EGU, or the owner/operator of the 
affected EGU can acquire allowances in a transaction through an 
intermediary, which could but need not involve an organized market. As 
discussed earlier, based on observation of market behavior both inside 
and outside the electricity industry, we expect that intermediaries 
will seek opportunities to participate in such transactions and that 
organized markets are likely to develop as well if section 111(d) plans 
authorize the use of emissions trading. While the opportunity to 
acquire allowances through common ownership might not extend to owner/
operators of single EGUs or small fleets, all owner/operators would 
have the ability to engage in bilateral or intermediated purchase 
transactions for allowances just as they can engage in transactions for 
other kinds of goods and services.
    Further details regarding the possible use of mass-based emission 
allowances in a state plan are provided in section VIII.J.
6. Use of Non-BSER Measures To Achieve Standards of Performance
    In addition to the BSER-related measures that affected EGUs can use 
to achieve the standards of performance set in section 111(d) plans, 
there are a variety of non-BSER measures that could also be employed 
(to the extent permitted under a given plan). This final rule does not 
limit the measures that affected EGUs may use for achieving standards 
of performance to measures that are included in the BSER; thus, the 
existence of these non-BSER measures provides flexibility allowing the 
individual affected EGUs and the source category to achieve emission 
reductions consistent with application of the BSER at the levels of 
stringency reflected in this final rule even if one or more of the 
building blocks is not implemented to the degree that the EPA has 
determined to be reasonable for purposes of quantifying the BSER. In 
this way, non-BSER measures provide additional flexibility to states in 
establishing standards of performance for affected EGUs through section 
111(d) plans and to individual affected EGUs for achieving those 
standards.
    Any of the non-BSER measures described below would help the 
affected source category as a whole achieve emission limits consistent 
with the BSER. The non-BSER measures either reduce the amount of 
CO2 emitted per MWh of generation from the set of affected 
EGUs or reduce the amount of generation, and therefore associated 
CO2 emissions, from the set of affected EGUs. However, the 
manner in which the various non-BSER measures would help individual 
affected EGUs meet their individual standards of performance varies 
according to the type of measure and the type of standard of 
performance--i.e., whether the standard is emission rate-based or mass-
based.
    In general, a non-BSER measure that reduces the amount of 
CO2 emitted per MWh of generation at an affected EGU will 
reduce the amount of CO2 emissions monitored at the EGU's 
stack (assuming the quantity of generation is held constant). Measures 
of this type can help the EGU meet either an emission rate-based or 
mass-based standard of performance.
    Other non-BSER measures do not reduce an affected EGU's 
CO2 emission rate but rather facilitate reductions in 
CO2 emissions by reducing the amount of generation from 
affected EGUs. Under a mass-based standard, the collective reduction in 
emissions from the set of affected EGUs is reflected in the collective 
monitored emissions from the set of affected EGUs. An individual EGU 
that reduces its generation and emissions will be able to use the 
measure to help achieve its mass-based limit. Individual EGUs that do 
not reduce their generation and emissions will be able to use the 
measure, if the relevant section 111(d) plans provide for allowance 
trading, by purchasing emission allowances no longer needed by EGUs 
that have reduced their emissions.
    Under an emission rate-based standard, non-BSER measures that 
reduce generation from affected EGUs but do not reduce an affected 
EGU's emission rate generally can facilitate compliance by serving as 
the basis for ERCs that affected EGUs can average into their emission 
rates for purposes of demonstrating compliance. Section VIII.K. 
includes a discussion of the issuance of ERCs based on various non-BSER 
measures. Affected EGUs could use such ERCs to the extent permitted by 
the relevant section 111(d) plans.
    The remainder of this section discusses some specific types of non-
BSER measures. The first set discussed includes measures that can 
reduce the amount of CO2 emitted per MWh of generation, and 
the second set discussed includes measures that can reduce 
CO2 emissions by reducing the amount of generation from 
affected EGUs. In some cases, considerations related to use of these 
measures for compliance are discussed below in section VIII on state 
plans. The EPA notes that this is not an exhaustive list of non-BSER 
measures that could be employed to reduce CO2 emissions from 
affected EGUs, but merely a set of examples that illustrate the extent 
of the additional flexibility such measures provide to states and 
affected EGUs under the final rule.
    a. Non-BSER measures that reduce CO2 emissions per MWh 
generated. In the June 2014 proposal, the EPA discussed several 
potential measures that could reduce CO2 emissions per MWh 
generated at affected EGUs but that were not proposed to be part of the 
BSER. The measures discussed included heat rate improvements at 
affected EGUs other than coal-fired steam EGUs; fuel switching from 
coal to natural gas at affected EGUs, either completely (conversion) or 
partially (co-firing); and carbon capture and storage by affected EGUs. 
One reason for not proposing to consider these measures to be part of 
the BSER was that they were more costly than the BSER measures. Another 
reason was that the emission reduction potential was limited compared 
to the potential available from the measures that were proposed to be 
included in the BSER. However, we also noted that circumstances could 
exist where these measures could be sufficiently attractive to deploy, 
and that the measures could be used to help affected EGUs achieve 
emission limits consistent with the BSER.
    In the final rule, the EPA has reached determinations consistent 
with the proposal with respect to these measures: namely, that they do 
not merit inclusion in the BSER, but that they are capable of helping 
affected EGUs achieve compliance with standards of performance and are 
likely to be used for that purpose by some units. To the extent that 
they are selectively employed, they provide flexibility for the source 
category as a whole and for individual affected EGUs to achieve 
emission limits reflective of the BSER, as discussed above.

[[Page 64756]]

    (1) Heat rate improvement at affected EGUs other than coal-fired 
steam EGUs.
    Building block 1 reflects the opportunity to improve heat rate at 
coal-fired steam EGUs but not at other affected EGUs. As the EPA stated 
at proposal, the potential CO2 reductions available from 
heat rate improvements at coal-fired steam EGUs are much larger than 
the potential CO2 reductions available from heat rate 
improvements at other types of EGUs, and comments offered no persuasive 
basis for reaching a different conclusion. Nevertheless, we recognize 
that there may be instances where an owner/operator finds heat rate 
improvement to be an attractive option at a particular non-coal-fired 
affected EGU, and nothing in the rule prevents the owner/operator from 
implementing such a measure and using it to help achieve a standard of 
performance.
    (2) Carbon capture and storage at affected EGUs.
    Another approach for reducing CO2 emissions per MWh of 
generation from affected EGUs is the application of carbon capture and 
storage (CCS) technology. Consistent with the June 2014 proposal, we 
are determining that use of full or partial CCS technology should not 
be part of the BSER for existing EGUs because it would be more 
expensive than the measures determined to be part of the BSER, 
particularly if applied broadly to the overall source category. At the 
same time, we note that retrofit of CCS technology may be a viable 
option at some individual facilities, particularly where the captured 
CO2 can be used for enhanced oil recovery (EOR). For 
example, construction of one CCS retrofit application with EOR has 
already been completed at a unit at the Boundary Dam plant in Canada, 
and construction of another CCS retrofit application with EOR is 
underway at the W.A. Parish plant in Texas. We expect the costs of CCS 
to decline as implementation experience increases. CO2 
emission rate reductions achieved through retrofit of CCS technology 
would be available to help affected EGUs achieve emission limits 
consistent with the BSER. State plan considerations related to CCS are 
discussed in section VIII.I.2.a.
    (3) Fuel switching to natural gas at affected EGUs.
    In the proposal we discussed the opportunity to reduce 
CO2 emissions at an individual affected EGU by switching 
fuels at the EGU, particularly by switching from coal to natural gas. 
Most coal-fired EGUs could be modified to burn natural gas instead, and 
the potential CO2 emission reductions from this measure are 
large--approximately 40 percent in the case of conversion from 100 
percent coal to 100 percent natural gas, and proportionately smaller 
for partial co-firing of coal with natural gas. The primary reason for 
not considering this measure part of the BSER, both at proposal and in 
this final rule, is that it is more expensive than the BSER measures. 
In particular, combusting natural gas in a steam EGU is less efficient 
and generally more costly than combusting natural gas in an NGCC unit. 
For the category as a whole, CO2 emissions can be achieved 
far more cheaply by combusting additional natural gas in currently 
underutilized NGCC capacity and reducing generation from coal-fired 
steam EGUs (building block 2) than by combusting natural gas instead of 
coal in steam EGUs.
    Some owner/operators are already converting some affected EGUs from 
coal to natural gas, and it is apparent that the measure can be 
attractive compared to alternatives in certain circumstances, such as 
when a unit must meet tighter unit-specific limits on emissions of non-
GHG pollutants, the options for meeting those emission limits are 
costly, and retirement of the unit would necessitate transmission 
upgrades that are costly or cannot be completed quickly. CO2 
emission reductions achieved in these situations are available to help 
achieve emission limits consistent with the BSER.
    (4) Fuel switching to biomass at affected EGUs.
    Some affected EGUs may seek to co-fire qualified biomass with 
fossil fuels. The EPA recognizes that the use of some biomass-derived 
fuels can play an important role in controlling increases of 
CO2 levels in the atmosphere. As with the other non-BSER 
measures discussed in this section, the EPA expects that use of biomass 
may be economically attractive for certain individual sources even 
though on a broader scale it would likely be more expensive or less 
achievable than the measures determined to be part of the BSER. Section 
VIII.I.2.c describes the process and considerations for states 
proposing to use different kinds of biomass in state plans.
    (5) Waste heat-to-energy conversion at affected EGUs.
    Certain affected EGUs in urban areas or located near industrial or 
commercial facilities with needs for thermal energy may be able add new 
equipment to capture some of the waste heat from their electricity 
generation processes and use it to create useful thermal output, 
thereby engaging in combined heat and power (CHP) production. While the 
set of affected EGUs in locations making this measure feasible may be 
limited, where feasible the potential CO2 emission rate 
improvements can be substantial: Depending on the process used, the 
efficiency with which fuel is converted to useful energy can be 
increased by 25 percent or more. The final rule allows an owner/
operator applying CHP technology to an affected EGU to account for the 
increased efficiency by counting the useful thermal output as 
additional MWh of generation, thereby lowering the unit's computed 
emission rate and assisting with achievement of an emission rate-based 
standard of performance. (The EPA notes that unless the unit also 
reduced its fuel usage, the addition of the capability to capture waste 
heat and produce useful thermal output would not reduce the unit's mass 
emissions and therefore would not directly help the unit achieve a 
mass-based standard of performance.\441\)
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    \441\ However, the EPA notes that a state could establish a 
mechanism for encouraging affected EGUs to apply CHP technology 
under a mass-based plan, for example, through awards of emission 
allowances to CHP projects.
---------------------------------------------------------------------------

    b. Non-BSER measures that reduce CO2 emissions by 
reducing fossil fuel-fired generation.
    A second group of non-BSER measures has the potential to reduce 
CO2 emissions from affected EGUs by reducing the amount of 
generation from those EGUs. As discussed above, under a section 111(d) 
plan with mass-based standards of performance, no special action is 
required to enable measures of this nature to help the source category 
as a whole and individual affected EGUs achieve their emission limits, 
because the CO2-reducing effects are captured in monitored 
stack emissions. However, under a section 111(d) plan with rate-based 
standards of performance, affected EGUs would need to acquire ERCs 
based on the non-BSER activities that could be averaged into their 
emission rate computations for purposes of determining compliance with 
their standards of performance.
    (1) Demand-side EE.
    One of the major approaches available for achieving CO2 
emission reductions from the utility power sector is demand-side EE. In 
the June 2014 proposal, the EPA identified demand-side EE as one of the 
four proposed building blocks for the BSER. We continue to believe that 
significant emission reductions can be achieved by the source category 
through use of such measures at reasonable costs. In fact, we believe 
that the potential emission reductions from demand-side EE rival those 
from building blocks 2 and 3 in magnitude, and that demand-side EE is 
likely to

[[Page 64757]]

represent an important component of some state plans, particularly in 
instances where a state prefers to develop a plan reflecting the state 
measures approach discussed in section VIII below. We also expect that 
many sources would be interested in including demand-side EE in their 
compliance strategies to the extent permitted, and we received comment 
that it should be permitted.
    For the reasons discussed in section V.B.3.c.(8) below, the EPA has 
determined not to include demand-side EE in the BSER in this final 
rule. However, the final rule authorizes generation avoided through 
investments in demand-side EE to serve as the basis for issuance of 
ERCs when appropriate conditions are met. In section VIII.K below, the 
EPA sets out the minimum criteria that must be satisfied for generation 
and issuance of a valid ERC based upon implementation of new demand-
side EE programs. Those criteria generally concern ensuring that the 
physical basis for the ERC--in this case, generation avoided through 
implementation of demand-side EE measures--is adequately evaluated, 
measured, and verified and that there is an adequate administrative 
process for tracking credits.
    Through their authority over legal requirements such as building 
codes, states have the ability to drive certain types of demand-side EE 
measures that are beyond the reach of private-sector entities. The EPA 
recognizes that, by definition, this type of measure is beyond the 
ability of affected EGUs to invest in either directly or through 
bilateral arrangements. However, the final rule also authorizes 
generation avoided through such state policies to serve as the basis 
for issuance of ERCs that in turn can be used by affected EGUs. The 
section 111(d) plan would need to include appropriate provisions for 
evaluating, measuring, and verifying the avoided MWh associated with 
the state policies, consistent with the criteria discussed in section 
VIII.K below.
    (2) New or uprated nuclear generating capacity.
    In the June 2014 proposal, the EPA included generation from the 
five nuclear units currently under construction as part of the proposed 
BSER. As discussed above in section V.A.3.c., upon consideration of 
comments, we have determined that generation from these units should 
not be part of the BSER. However, we continue to observe that the zero-
emitting generation from these units would be expected to replace 
generation from affected EGUs and thereby reduce CO2 
emissions, and the continued commitment of the owner/operators to 
completion of the units is essential in order to realize that result. 
Accordingly, a section 111(d) plan may rely on ERCs issued on the basis 
of generation from these units and other new nuclear units. For the 
same reason, a plan may rely on ERCs issued on the basis of generation 
from uprates to the capacity of existing nuclear units. Requirements 
for state plan provisions intended to serve this purpose are discussed 
in section VIII.K.
    (3) Zero-emitting RE generating technologies not reflected in the 
BSER.
    The range of available zero-emitting RE generating technologies is 
broader than the range of RE technologies determined to be suitable for 
use in quantification of building block 3 as an element of the BSER. 
Examples of additional zero-emitting RE technologies not included in 
the BSER that could be used to achieve emission limits consistent with 
the BSER include offshore wind, distributed solar, and fuel cells. 
These technologies were not included in the range of RE technologies 
quantified for the BSER because they are generally more expensive than 
the measures that were included and the other measures in the BSER. 
However, these technologies are equally capable of replacing generation 
from affected EGUs and thereby reducing CO2 emissions. 
Further, as with any technology, there are likely to be certain 
circumstances where the costs of these technologies are more attractive 
relative to alternatives, making the technologies likely to be deployed 
to some extent. Indeed, distributed solar is already being widely 
deployed in much of the U.S. and offshore wind, while still unusual in 
this country, has been extensively deployed in some other parts of the 
world. We expect innovation in RE generating technologies to continue, 
making such technologies even more attractive over time. A section 
111(d) plan may rely on ERCs issued on the basis of generation from new 
and uprated installations of these technologies. The necessary state 
plan provisions are discussed in section VIII.K.
    (4) Non-zero-emitting RE generating technologies.
    Generation from new or expanded facilities that combust qualified 
biomass or biogenic portions of municipal solid waste (MSW) to produce 
electricity can also replace generation from affected EGUs and thereby 
control CO2 levels in the atmosphere.\442\ While the EPA 
believes it is reasonable to consider generation from these fuels and 
technologies to be forms of RE generation, the fact that they can 
produce stack emissions containing CO2 means that a section 
111(d) plan seeking to permit use of such generation to serve as the 
basis for issuance of ERCs must include appropriate consideration of 
feedstock characteristics and climate benefits. Specifically, the use 
of some kinds of biomass has the potential to offer a wide range of 
environmental benefits, including carbon benefits. However these 
benefits can only be realized if biomass feedstocks are sourced 
responsibly and attributes of the carbon cycle related to the biomass 
feedstock are taken into account. Section VIII.I.2.c describes the 
process and considerations for states proposing to use biomass in state 
plans. Section VIII.K describes additional provisions related to ERCs.
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    \442\ The EPA and many states have recognized the importance of 
integrated waste materials management strategies that emphasize a 
hierarchy of waste prevention and all other productive uses of waste 
materials to reduce the volume of disposed waste materials (see 
section VIII for more discussion of waste-to-energy strategies).
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    (5) Waste heat-to-electricity conversion at non-affected 
facilities.
    Industrial facilities that install new equipment to capture waste 
heat from an existing combustion process and then use the waste heat to 
generate electricity--a form of combined heat and power (CHP) 
production--can produce generation that replaces generation from 
affected EGUs and thereby reduces CO2 emissions. A section 
111(d) plan may rely on ERCs issued on the basis of generation of this 
nature provided that the facility does not generate and sell sufficient 
electricity to qualify as a new EGU for purposes of section 111(b) and 
is not covered under section 111(d) for another source category. More 
information is provided in section VIII.K.
    (6) Reduction in transmission and distribution line losses.
    Reductions of electricity line losses incurred from the 
transmission and distribution system between the points of generation 
and the points of consumption by end-users allow the same overall 
demand for electricity services to be met with a smaller overall 
quantity of electricity generation. Such reductions in generation 
quantities would tend to reduce generation by affected EGUs, thereby 
reducing CO2 emissions. The opportunity for improvement is 
large because, on average, line losses account for approximately seven 
percent of all electricity generation. The EPA recognizes that, in 
general, only the

[[Page 64758]]

owner/operators of the transmission and distribution facilities have 
the ability to undertake line loss reduction investments, and that 
merchant generators may have little opportunity to engage a contractor 
to pursue such opportunities on a bilateral basis. Nevertheless, for 
entities that do have the opportunity to make such investments, 
generation avoided through investment that reduces transmission and 
distribution line losses may serve as the basis for issuance of ERCs 
that in turn can be used by affected EGUs. Further information is 
provided in section VIII.K.
7. Severability
    The EPA intends that the components of the BSER summarized above be 
severable. It is reasonable to consider the building blocks severable 
because the building blocks do not depend on one another. Building 
blocks 2 and 3 are feasible and demonstrated means of reducing 
CO2 emissions from the utility power sector that can be 
implemented independently of the other building blocks. If implemented 
in combination with at least one of the other building blocks, building 
block 1 is also a feasible and demonstrated means of reducing 
CO2 emission from the utility power sector.\443\ As 
discussed in sections V.C. through V.E. below, we have determined that 
each building block is independently of reasonable cost whether or not 
the other building blocks are applied, and that alternative 
combinations of the building blocks are likewise of reasonable cost, 
and we have determined reasonable schedules and stringencies for 
implementation of each building block independently, based on factors 
that generally do not vary depending on the implementation of other 
building blocks.
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    \443\ The heat rate improvement measures included in building 
block 1 are capable of being implemented independently of the 
measures in the other building blocks but, as discussed earlier, 
unless at least one other building block is also implemented, a 
``rebound effect'' arising from improved competitiveness and 
increased generation at the EGUs implementing heat rate improvements 
could weaken or potentially even eliminate the ability of building 
block 1 to achieve CO2 emission reductions.
---------------------------------------------------------------------------

    Further, building block 2, building block 3, and all combinations 
of the building blocks (implemented on the schedules and at the 
stringencies determined to be reasonable in this rule) would achieve 
meaningful degrees of emission reductions,\444\ although less than the 
combination of all three building blocks. No combination of the 
building blocks would lead to adverse non-air environmental or energy 
impacts or impose a risk to the reliability of electricity supplies.
---------------------------------------------------------------------------

    \444\ This conclusion would not extend to a BSER comprising 
solely building block 1, in part because of the possibility of 
rebound effects discussed earlier.
---------------------------------------------------------------------------

    In the event that a court should deem building block 2 or 3 
defective, but not both, the standards and state goals can be 
recomputed on the basis of the remaining building blocks. All of the 
data and procedures necessary to determine recomputed state goals using 
any combination of the building blocks are set forth in the 
CO2 Emission Performance Rate and Goal Computation TSD for 
the CPP Final Rule available in the docket.

B. Legal Discussion of Certain Aspects of the BSER

    This section includes a legal analysis of various aspects of EPA's 
determination of the BSER, including responses to some of the major 
adverse comments. These aspects include (1) the EPA's authority to 
determine the BSER; (2) the approach to subcategorization; (3) the 
EPA's basis for determining that building blocks 2 and 3 qualify as 
part of the BSER under CAA sections 111(d)(1) and (a)(1), 
notwithstanding commenters' arguments that these building blocks cannot 
be considered part of the BSER because they are not based on measures 
integrated into the design or operation of the affected source's own 
production processes or methods or because they are dependent on 
actions by entities other than the affected source; (4) the 
relationship between an affected EGU's implementation of building 
blocks 2 and 3 and CO2 emissions reductions; (5) how reduced 
generation relates to the BSER; (6) reasons why, contrary to assertions 
by commenters, this rule is within the EPA's statutory authority, is 
not inconsistent with the Federal Power Act or state laws governing 
public utility commissions, and does not result in what the U.S. 
Supreme Court described as ``an enormous and transformative expansion 
in [the] EPA's regulatory authority''; \445\ and (7) reasons that, 
contrary to assertions by commenters, the stringency of the BSER for 
this rule for CO2 emissions from existing affected EGUs is 
not inconsistent with the stringency of the BSER for the rules the EPA 
is promulgating at the same time for CO2 emissions from new 
or modified affected EGUs.
---------------------------------------------------------------------------

    \445\ Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2444 (2014).
---------------------------------------------------------------------------

1. The EPA's Authority To Determine the BSER
    In this section, we explain why the EPA, and not the states, has 
the authority to determine the BSER and, therefore, the level of 
emission limitation required from the existing sources in the source 
category in section 111(d) rulemaking and the associated state plans.
    CAA section 111(d)(1) requires the EPA to establish a section 110-
like procedure under which each state submits a plan that ``establishes 
standards of performance for any existing source of air pollutant'' and 
``provides for the implementation and enforcement of such standards of 
performance.'' As CAA section 111(d) was originally adopted in the 1970 
CAA Amendments, however, state plans were required to establish 
``emission standards''--an undefined term--rather than ``standards of 
performance,'' a term that was limited to CAA section 111(b).\446\ The 
1970 provision was in effect when the EPA issued the 1975 implementing 
regulations for CAA section 111(d),\447\ which remain in effect to this 
day.
---------------------------------------------------------------------------

    \446\ See 1970 CAA Amendments, Sec.  4, 84 Stat. at 1683-84. 
Subsequently, in 1977, Congress replaced the term ``emission 
standard'' with ``standards of performance.'' See 1977 CAA 
Amendments, Sec.  109, 91 Stat. at 699.
    \447\ See ``State Plans for the Control of Certain Pollutants 
From Existing Facilities,'' 40 FR 53340 (Nov. 17, 1975).
---------------------------------------------------------------------------

    These regulations establish a cooperative framework that is similar 
to that under CAA section 110. First, the EPA develops ``emission 
guidelines'' for source categories, which are defined as a final 
guideline document reflecting ``the degree of emission reduction 
achievable through the application of the best system of emission 
reduction . . . which the Administrator has determined has been 
adequately demonstrated.'' Then, the states submit implementation plans 
to regulate any existing sources.\448\
---------------------------------------------------------------------------

    \448\ See ``State Plans for the Control of Certain Pollutants 
From Existing Facilities,'' 40 FR 53340 (Nov. 17, 1975).
---------------------------------------------------------------------------

    The preamble to these regulations carefully considered the 
allocation of responsibilities as between the EPA and the states for 
purposes of CAA section 111(d), and concluded that the EPA is 
responsible for determining the level of emission limitation from the 
source category, while the states have the responsibility of assigning 
emission requirements to their sources that assured their achievement 
of that level of emission limitation.\449\ The EPA

[[Page 64759]]

explained ``that some substantive criterion was intended to govern not 
only the Administrator's promulgation of standards but also [her] 
review of state plans.'' \450\ The EPA added, ``it would make no sense 
to interpret [CAA] section 111(d) as requiring the Administrator to 
base approval or disapproval of state plans solely on procedural 
criteria. Under that interpretation, states could set extremely lenient 
standards--even standards permitting greatly increased emissions--so 
long as [the] EPA's procedural requirements were met.'' \451\ The EPA 
concluded that ``emission guidelines, each of which will be subjected 
to public comment before final adoption, will serve [the] function'' of 
providing substantive criteria ``in advance to the states, to industry, 
and to the general public'' to aid states in ``developing and enforcing 
control plans under [CAA] section 111(d).'' \452\ Thus, the 
implementing regulations make clear that the EPA is responsible for 
determining the level of emission limitation that the state plans must 
achieve.
---------------------------------------------------------------------------

    \449\ As we made clear in the proposed rulemaking, we are not 
re-opening these regulations (on the issue of the authority to 
determine the BSER or any other issue, unless specifically indicated 
otherwise) in this rulemaking, and our discussion of these 
regulations in responding to comments does not constitute a re-
opening.
    \450\ ``State Plans for the Control of Certain Pollutants from 
Existing Facilities,'' 40 FR 53340, 53342 (Nov. 17, 1975).
    \451\ ``State Plans for the Control of Certain Pollutants from 
Existing Facilities,'' 40 FR 53340, 53343 (Nov. 17, 1975).
    \452\ ``State Plans for the Control of Certain Pollutants from 
Existing Facilities,'' 40 FR 53340, 53343 (Nov. 17, 1975).
---------------------------------------------------------------------------

    In 1977, Congress revised CAA section 111(d) to require that the 
states adopt ``standards of performance,'' as defined under CAA section 
111(a)(1). As noted above, a standard of performance is defined as ``a 
standard for emissions of air pollutants which reflects the degree of 
emission limitation achievable through the application of the best 
system of emission reduction which . . . the Administrator determines 
has been adequately demonstrated.'' (Emphasis added.) By its terms, 
this provision provides that the EPA has the responsibility of 
determining whether the ``best system of emission reduction'' is 
``adequately demonstrated.'' By giving the EPA this responsibility, 
this provision is clear that Congress assigned the role of determining 
the ``best system of emission reduction'' to the EPA. Even if the 
provision may be considered to be silent or ambiguous on that question, 
the EPA reasonably interprets the provision to assign the 
responsibility of identifying the ``best system of emission reduction'' 
to the Administrator for the same reasons discussed in the preamble to 
the 1975 implementing regulations.
    In addition, in the legislative history of the 1977 CAA Amendments, 
when Congress replaced the term ``emission standards'' under CAA 
section 111(d)(1) with the term ``standards of performance,'' Congress 
endorsed the overall approach of the implementing regulations, which 
lends further credence to the proposition that the EPA has the 
responsibility for determining the ``best system of emission 
reduction'' and the amount of emission limitation from the existing 
sources. Specifically, in the House report that introduced the 
substantive changes to CAA section 111, the Committee explained that 
``[t]he Administrator would establish guidelines as to what the best 
system for each category of existing sources is.'' \453\ States, on the 
other hand, ``would be responsible for determining the applicability of 
such guidelines to any particular source or sources.'' \454\ The use of 
the term ``guidelines,'' which does not appear in CAA section 111(d), 
indicates Congress was aware of and approved of the approach taken in 
the EPA's implementing regulations for establishing guidelines, which 
determine the BSER. At a minimum, if Congress disapproved of the EPA's 
implementing regulations, we would not expect the House report to adopt 
the EPA's terminology to clarify CAA section 111(d).
---------------------------------------------------------------------------

    \453\ H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis 
added).
    \454\ H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis 
added).
---------------------------------------------------------------------------

    In addition, Congress expressly referred to our ``guidelines'' in 
CAA section 129, added as part of the 1990 CAA Amendments. Congress 
added CAA section 129 to address solid waste combustion and 
specifically directed the Administrator to establish ``guidelines 
(under section 111(d) and this section) and other requirements 
applicable to existing units.'' \455\ This reference also indicates 
that Congress was aware of and approved the EPA's regulations under 
section 111(d).
---------------------------------------------------------------------------

    \455\ CAA section 129(a)(1)(A) (emphasis added).
---------------------------------------------------------------------------

    The EPA has followed the same approach described in the 
implementation regulations in all its rulemakings under section 111(d). 
Thus, in all cases, the EPA has identified the type of emission 
controls for the source category and the level of emission limitation 
based on those controls.\456\ The EPA's longstanding and consistent 
interpretation of CAA section 111(d) is also ``evidence showing that 
the statute is in fact not ambiguous,'' and that the EPA's 
interpretation should be adopted.\457\
---------------------------------------------------------------------------

    \456\ See 40 CFR part 60, subpart Ca (large municipal waste 
combustors), 56 FR 5514 (Feb. 11, 1991), 40 CFR 60.30a-.39a 
(subsequently withdrawn and superseded by Subpart Cb, see 60 FR 
65387 (Dec. 19, 1995)); Subpart Cb (large municipal waste combustors 
constructed on or before September 20, 1994), 60 FR 65387 (Dec. 19, 
1995), 40 CFR 60.30b-.39b (as amended in 1997, 2001, and 2006); 
Subpart Cc (municipal solid waste landfills), 61 FR 9905 (Mar. 12, 
1996), 40 CFR 60.30c-.36c (as amended in 1998, 1999, and 2000); 
Subpart Cd (sulfuric acid production units), 60 FR 65387 (Dec. 19, 
1995), 40 CFR 60.30d-.32d; Subpart Ce (hospital/medical/infectious 
waste incinerators), 62 FR 48348 (Sept. 15, 1997), 40 CFR 
60.30e-.39e (as amended in 2009 and 2011); Subpart BBBB (small 
municipal waste combustion units constructed on or before August 30, 
1999), 65 FR 76738 (Dec. 6, 2000), 40 CFR 60.1500-.1940; Subpart 
DDDD (commercial and industrial solid waste incineration units that 
commenced construction on or before November 30, 1999), 65 FR 75338 
(Dec. 1, 2000), 40 CFR 60.2500-.2875 (as amended in 2005, 2011, and 
2013); Subpart FFFF (other solid waste incineration units that 
commenced construction on or before December 9, 2004), 70 FR 74870 
(Dec. 16, 2005), 40 CFR 60.2980-.3078 (as amended in 2006); Subpart 
HHHH (coal-electric utility steam generating units), 70 FR 28606 
(May 18, 2005) (subsequently vacated by the D.C. Circuit in New 
Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008)); Subpart MMMM 
(existing sewage sludge incineration units), 76 FR 15372 (Mar. 21, 
2011), 40 CFR 60.5000-.5250; ``Phosphate Fertilizer Plants, Final 
Guideline Document Availability,'' 42 FR 12022 (Mar. 1, 1977) (not 
codified); ``Kraft Pulp Mills; Final Guideline Document; 
Availability,'' 44 FR 29828 (May 22, 1979) (not codified); and 
``Primary Aluminum Plants; Availability of Final Guideline 
Document,'' 45 FR 26294 (Apr. 17, 1980) (not codified).
    \457\ Scalia, Antonin, Judicial Deference to Administrative 
Interpretations of Law, 1989 Duke L.J. 511, 518; see Riverkeeper v. 
Entergy, 556 U.S. 208, 235 (2009).
---------------------------------------------------------------------------

    Lastly, this interpretation is consistent with the Supreme Court's 
reading of CAA section 111(d) in American Electric Power Co. There, the 
Court explained that ``EPA issues emissions guidelines, see 40 CFR 
60.22, .23 (2009); in compliance with those guidelines and subject to 
federal oversight, the States then issue performance standards for 
stationary sources within their jurisdiction, Sec.  7411(d)(1).'' \458\
---------------------------------------------------------------------------

    \458\ Am. Elec. Power Co. v. Connecticut, 131 S. Ct. 2527, 2537-
38 (2011).
---------------------------------------------------------------------------

    As noted in the response to comment document, some commenters 
agreed with our interpretation, just discussed, while others argued 
that the states should be given the authority to determine the best 
system of emission reduction and, therefore, the level of emission 
limitation from their sources. For the reasons just discussed, this 
latter interpretation is an incorrect interpretation of CAA section 
111(d)(1) and (a)(1), and we are not compelled to abandon our 
longstanding practice.
2. Approach to Subcategorization
    As noted above, in this rule, we are treating all fossil fuel-fired 
EGUs as a single category, and, in the emission

[[Page 64760]]

guidelines that we are promulgating with this rule, we are treating 
steam EGUs and combustion turbines as separate subcategories. We are 
determining the BSER for steam EGUs and the BSER for combustion 
turbines, and applying the BSER to each subcategory to determine a 
performance rate for that subcategory. We are not further 
subcategorizing among different types of steam EGUs or combustion 
turbines.
    This approach is fully consistent with the provisions of section 
111(d), which simply require the EPA to determine the BSER, do not 
prescribe the method for doing so, and are silent as to 
subcategorization. This approach is also fully consistent with other 
provisions in CAA section 111, which require the EPA first to list 
source categories that may reasonably be expected to endanger public 
health or welfare \459\ and then to regulate new sources within each 
such source category,\460\ and which grant the EPA discretion whether 
to subcategorize new sources for purposes of determining the BSER.\461\
---------------------------------------------------------------------------

    \459\ CAA section 111(b)(1)(A).
    \460\ CAA section 111(b)(1)(B).
    \461\ CAA section 111(b)(2).
---------------------------------------------------------------------------

    For this rule, our approach of subcategorizing between steam EGUs 
and combustion turbines is reasonable because building blocks 1 and 2 
apply only to steam EGUs. No further subcategorization is appropriate 
because each affected EGU can achieve the performance rate by 
implementing the BSER. Specifically, as noted, each affected EGU may 
take a range of actions including investment in the building blocks, 
replacing or reducing generation, and emissions trading, as enabled or 
facilitated by the implementation programs the states adopt. Further, 
in the case of a rate-based state plan, several other compliance 
options not included in the BSER for this rule are also available to 
all affected sources, including investment in demand-side EE measures. 
Such compliance options help affected sources achieve compliance under 
a mass-based plan, even if indirectly. Our approach to 
subcategorization in this rule is consistent with our approach to 
subcategorization in previous section 111 rules for this industry, in 
which we determined whether or not to subcategorize on the basis of the 
ability of affected EGUs with different characteristics (e.g., size or 
type of fuel used) to implement the BSER and achieve the emission 
limits).\462\
---------------------------------------------------------------------------

    \462\ Compare ``Revision of Standards of Performance for 
Nitrogen Oxide Emissions From New Fossil-Fuel Fired Steam Generating 
Units; Revisions to Reporting Requirements for Standards of 
Performance for New Fossil-Fuel Fired Steam Generating Units: Final 
Rule,'' 63 FR 49442 (Sept. 16, 1998) and ``Proposed Revision of 
Standards of Performance for Nitrogen Oxide Emissions From New 
Fossil-Fuel Fired Steam Generating Units: Proposed Revisions,'' 62 
FR 36948, 36943 (July 9, 1997) (establishing a single NOX 
emission limit for new fossil-fuel fired steam generating units, and 
not subcategorizing, because the affected units could implement the 
BSER of SCR and achieve the promulgated emission limits) with 
``National Emission Standards for Hazardous Air Pollutants From Coal 
and Oil-Fired Electric Utility Steam Generating Units and Standards 
of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-
Commercial-Institutional, and Small Industrial-Commercial-
Institutional Steam Generating Units: Final Rule,'' 77 FR 9304 (Feb. 
16, 2012) (MATS rule) and ``National Emission Standards for 
Hazardous Air Pollutants From Coal and Oil-Fired Electric Utility 
Steam Generating Units and Standards of performance for Fossil-Fuel-
Fired Electric Utility, Industrial-Commercial-Institutional, and 
Small Industrial-Commercial-Institutional Steam Generating Units: 
Proposed Rule,'' 76 FR 24976, 25036-37 (May 3, 2011) 
(subcategorizing coal fired units designed to burn coal with greater 
than or equal to 8,300 Btu/lb (for Hg emissions only), coal-fired 
units designed to burn coal with less than 8,300 Btu/lb (for Hg 
emissions only), IGCC units, liquid oil units, and solid oil-derived 
units; evaluating ``subcategorization of lignite coal vs. other coal 
ranks; subcategorization of Fort Union lignite coal vs. Gulf Coast 
lignite coal vs. other coal ranks; subcategorization by EGU size 
(i.e., MWe); subcategorization of base load vs. peaking units (e.g., 
low capacity utilization units); subcategorization of wall-fired vs. 
tangentially-fired units; and subcategorization of small, non-
profit-owned units vs. other units;'' but deciding not to adopt 
those latter subcategorizations).
---------------------------------------------------------------------------

    In addition, there are numerous possible criteria to use in 
subcategorizing, including, among others, subcategorizing on the basis 
of age; size; steam conditions (i.e., subcritical or supercritical); 
type of fuel, including type of coal (i.e., lignite, bituminous, and 
sub-bituminous), and coal refuse; and method of combustion (i.e., 
fluidized bed combustion, pulverized coal combustion, and 
gasification). In addition, there are different possible combinations 
of those categories. At least some of those criteria do not have 
logical cut-points. Furthermore, we have not been presented with, nor 
can we discern, a method of subcategorizing based on these or other 
criteria that is appropriate in light of the BSER for the affected EGUs 
and their ability to meet the emission limits. Moreover, our approach 
of not further subcategorizing as between different types of steam EGUs 
or combustion turbines reflects the reasonable policy that affected 
EGUs with higher emission rates should reduce their emissions by a 
greater percentage than affected EGUs with lower emission rates, and 
can do so by implementing the BSER we are identifying.
    In addition, a section 111(d) rule presents less of a need to 
subcategorize because the states retain great flexibility in assigning 
standards of performance to their affected EGUs. Thus, a state can, if 
it wishes, impose different emission reduction obligations on its 
sources, as long as the overall level of emission limitation is at 
least as stringent as the emission guidelines, as discussed below. This 
means that if a state is concerned that its different sources have 
different capabilities for compliance, it can adjust the standards of 
performance in imposes on its sources accordingly.
3. Building Blocks 2 and 3 as a ``System of Emission Reduction''
    a. Overview.
    As we explain above, the emission performance rates that we include 
in this rule's emission guidelines are achievable by the affected EGUs 
through the application of the BSER, which includes the three building 
blocks. Commenters object that building blocks 2 (generation shift) and 
3 (RE) cannot, as a legal matter, be considered part of the BSER under 
CAA section 111(d)(1) and (a)(1). These commenters explain that in 
their view, under CAA section 111, the emission performance rates must 
be based on, and therefore the BSER must be limited to, methods for 
emission control that the owner/operator of the affected source can 
integrate into the design or operation of the source itself, and cannot 
be based on actions taken beyond the source or actions involving third-
party entities.\463\ For these reasons, these commenters argue that the 
phrase ``system of emission reduction'' cannot be

[[Page 64761]]

interpreted to include building blocks 2 and 3.
---------------------------------------------------------------------------

    \463\ See, e.g., comments by UARG at 6-7 (``Standards 
promulgated under section 111 must be source-based and reflect 
measures that the source's owner can integrate into the design or 
operation of the source itself. A standard cannot be based on 
actions taken beyond the source itself that somehow reduce the 
source's utilization.''); comments by UARG at 31 (the building 
blocks other than building block 1 take a `` `beyond-the-source' 
approach'' and ``impermissibly rely on measures that go beyond the 
boundaries of individual affected EGUs and that are not within the 
control of individual EGU owners and operators''); comments by UARG 
at 33 (the ``system'' of emission reduction ``can refer only to 
reductions resulting from measures that are incorporated into the 
source itself;'' section 111 is ``designed to improve the emissions 
performance of new and existing sources in specific categories based 
on the application of achievable measures implemented in the design 
or production process of the source at reasonable cost.''); comments 
by American Chemistry Council et al. (``Associations'') at 60-61 
(EPA's proposed BSER analysis is unlawful because it ``looks beyond 
the fence line of the fossil fuel-fired EGUs that are the subject of 
this rulemaking;'' ``the standard of performance must . . . be 
limited to the types of actions that can be implemented directly by 
an existing source within [the appropriate] class or category.'').
---------------------------------------------------------------------------

    We disagree with these comments, and note that other commenters 
were supportive of our determination to include building blocks 2 and 
3. Under CAA section 111(d)(1) and (a)(1), the EPA's emission 
guidelines must establish achievable emission limits based on the 
``best system of emission reduction . . . adequately demonstrated.'' 
While some commenters assert that emission guidelines must be limited 
in the manner summarized above, the phrase ``system of emission 
reduction,'' by its terms and when read in context, contains no such 
limits. To the contrary, its plain meaning is deliberately broad and is 
capacious enough to include actions taken by the owner/operator of a 
stationary source designed to reduce emissions from that affected 
source, including actions that may occur off-site and actions that a 
third party takes pursuant to a commercial relationship with the owner/
operator, so long as those actions enable the affected source to 
achieve its emission limitation. Such actions include the measures in 
building blocks 2 and 3, which, when implemented by an affected source, 
enable the source to achieve their emission limits because of the 
unique characteristics of the utility power sector. For purposes of 
this rule, we consider a ``system of emission reduction''--as defined 
under CAA section 111(a)(1) and applied under CAA section 111(d)(1)--to 
encompass a broad range of pollution-reduction actions, which includes 
the measures in building blocks 2 and 3. Furthermore, the measures in 
building blocks 2 and 3 fall squarely within EPA's historical 
interpretation of section 111, pursuant to which the focus for the BSER 
has been on how to most cleanly produce a good, not on how much of the 
good should be produced.
    Our interpretation that a ``system of emission reduction'' is broad 
enough to include the measures in building blocks 2 and 3 is supported 
by the following: Our interpretation of the phrase ``system of emission 
reduction'' is consistent with its plain meaning and statutory context; 
our interpretation accommodates the very design of CAA section 
111(d)(1), which covers a range of source categories and air 
pollutants; \464\ our interpretation is supported by the legislative 
history of CAA section 111(d)(1) and (a)(1), which indicates Congress's 
intent to give the EPA broad discretion in determining the basis for 
CAA section 111 control requirements, particularly for existing 
sources, and Congress's intent to authorize the EPA to consider 
measures that could be carried out by parties other than the affected 
sources; and our interpretation is reasonable in light of comparisons 
to CAA provisions that give the EPA similar authority to consider such 
measures and to CAA provisions that would preclude the EPA from 
considering such measures.
---------------------------------------------------------------------------

    \464\ Because it is designed to apply to a range of air 
pollutants not regulated under other provisions, CAA section 111(d) 
may be described as a ``catch-all'' or ``gap-filler.'' As such, a 
``system of emission reduction'' as applied under CAA section 111(d) 
should be interpreted flexibly to accommodate this role.
---------------------------------------------------------------------------

    In addition to the reasons stated above, the EPA's interpretation 
is also reasonable for the following reasons: (i) Building blocks 2 and 
3 fit well within the structure and economics of the utility power 
sector. (ii) Fossil fuel-fired EGUs are already implementing the 
measures in these building blocks for various reasons, including for 
purposes of reducing CO2 emissions. (iii) Interpreting the 
phrase ``system of emission reduction'' to incorporate building blocks 
2 and 3 is consistent with (a) other provisions in the CAA, including 
the acid rain provisions in Title IV and the SIP provisions in CAA 
section 110, along with the EPA's regulations implementing the CAA SIP 
requirements concerning interstate transport and regional haze, each of 
which is based on at least some of the same measures included in 
building blocks 2 and 3; (b) prior EPA action under CAA section 111(d), 
including the 2005 Clean Air Mercury Rule,\465\ which is based on some 
of the same measures in building blocks 2 and 3; (c) the various 
provisions of the CAA that authorize emissions trading, because 
emissions trading entails a source meeting its emission limitation 
based on the actions of another entity; and (d) the pollution 
prevention provisions of the CAA, which make clear that a primary goal 
of the CAA is to encourage federal and state actions that reduce or 
eliminate, through any measures, the amount of pollution produced at 
the source.\466\ (iv) Lastly, interpreting the phrase ``system of 
emission reduction'' to authorize the EPA, in formulating its BSER 
determination, to weigh a broad range of emission-reducing measures 
that includes building blocks 2 and 3 is consistent with Congress's 
intent to address urgent environmental problems and to protect public 
health and welfare against risks, as well as Congress's expectation 
that American industry would be able to develop the innovative 
solutions necessary to protect public health and welfare.
---------------------------------------------------------------------------

    \465\ This rule was vacated by the D.C. Circuit on other 
grounds. New Jersey v. EPA, 517 F.3d 574, 583-84 (D.C. Cir. 2008), 
cert. denied sub nom. Util. Air Reg. Group v. New Jersey, 555 U.S. 
1169 (2009).
    \466\ As noted in the Legal Memorandum, in several of these 
rulemakings and in the course of litigation, the fossil fuel-fired 
electric power sector has taken positions that are consistent with 
the EPA's interpretation that the BSER may include building blocks 2 
and 3.
---------------------------------------------------------------------------

    Congress passed the CAA, including its several amendments, to 
protect public health and welfare from ``mounting dangers,'' including 
``injury to agricultural crops and livestock, damage to and the 
deterioration of property, and hazards to air and ground 
transportation.'' \467\ In doing so, Congress established numerous 
programs to address air pollution problems and provided the EPA with 
guidance and flexibility in carrying out many of those programs. Even 
if we were to accept commenters' view that the system of emission 
reduction identified as best here is not integrated into the design or 
operation of the regulated sources, in the context of this industry and 
this pollutant it is reasonable to reject the narrow interpretation 
urged by some commenters that the ``system of emission reduction'' 
applicable to the affected EGUs must be limited to only those measures 
that can be integrated into the design or operation of the source 
itself. The plain language of the statute does not support such an 
interpretation, and to adopt it would limit the ``system of emission 
reduction'' to measures that are either substantially more expensive or 
substantially less effective at reducing emissions than the measures in 
building blocks 2 and 3, notwithstanding the absence of any statutory 
language imposing such a limit. Such a result would be contrary to the 
goals of the CAA and would ignore the facts that sources in the 
electric generation industry routinely address planning and operating 
objectives on a broad, multi-source basis using the measures in 
building blocks 2 and 3 and would seek to use building blocks 2 and 3 
(as well as non-BSER measures) to comply with whatever emission 
standards are set as a result of this rule. Indeed, as already 
observed, building blocks 2 and 3 are already being used to reduce 
emissions, and to do so specifically by operation of the industry's 
inherent multi-source functions.
---------------------------------------------------------------------------

    \467\ CAA section 101(a)(2).
---------------------------------------------------------------------------

    Although the BSER provisions are sufficiently broad to include, for 
affected EGUs, the measures in building blocks 2 and 3, they also 
incorporate significant constraints on the types of

[[Page 64762]]

measures that may be included in the BSER. We discuss those constraints 
at the end of this section. They include the section 111(d)(1) and 
(a)(1) requirements that emission reductions occur from the affected 
sources; that the emission performance standards for which the BSER 
forms the basis be achievable; that the system of emission reduction be 
adequately demonstrated; and that the EPA account for cost, non-air 
quality impacts, and energy requirements in determining the ``best'' 
system of emission reduction that is adequately demonstrated. The 
constraints included in these statutory requirements do not preclude 
building blocks 2 and 3 from the BSER. In interpreting these statutory 
requirements for determining the BSER, the EPA is consistent with past 
practice and current policy for both section 111 regulatory actions as 
well as regulatory actions under other CAA provisions for the electric 
power sector, under which the EPA has generally taken the approach of 
basing regulatory requirements on controls and measures designed to 
reduce air pollutants from the production process without limiting the 
aggregate amount of production. This approach has been inherent in our 
past interpretation and application of section 111 and we maintain this 
interpretation in this rulemaking.\468\ While inclusion of building 
blocks 2 and 3 is consistent with our interpretation of the statutory 
requirements, inclusion of building block 4 is not, and for that 
reason, we are declining to include building block in the BSER. 
Finally, we briefly note additional constraints that focus the BSER 
identified for new sources under section 111(b) on controls that assure 
that sources are well-controlled at the time of construction.
---------------------------------------------------------------------------

    \468\ As we note in section V.A., this rulemaking presents a 
unique set of circumstances, including the global nature of 
CO2 and the emission control challenges that 
CO2 presents (which limit the availability and 
effectiveness of control measures), combined with the facts that the 
electric power industry (including fossil fuel-fired steam 
generators and combustion turbines) is highly integrated, 
electricity is fungible, and generation is substitutable (which all 
facilitate the generation shifting measures encompassed in building 
blocks 2 and 3). Our interpretation of section 111 as focusing on 
limiting emissions without limiting aggregate production must take 
into account those unique circumstances.
---------------------------------------------------------------------------

    b. System of emission reduction as a broad range of measures.
    (1) Plain meaning and context of ``system of emission reduction.''
    The phrase ``system of emission reduction'' appears in the 
definition of a ``standard of performance'' under CAA section 
111(a)(1). That definition reads:

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.

Pursuant to this definition, it is clear that a ``system of emission 
reduction'' serves as the basis for emission limits embodied by CAA 
section 111 standards. For this reason, emission limits must be 
``achievable'' through the ``application'' of the ``best'' ``system of 
emission reduction'' ``adequately demonstrated.'' Under CAA section 
111(d)(1), such a limit is established for ``any existing source,'' 
which is defined as any existing ``building, structure, facility, or 
installation which emits or may emit any air pollutant.'' \469\
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    \469\ See CAA section 111(d)(1) (applying a standard of 
performance to any existing source); (a)(6) (defining the term 
``existing source'' as any stationary source other than a new 
source); and (a)(3) (defining the term ``stationary source'' as 
``any building, structure, facility, or installation which emits or 
may emit any air pollutant,'' however, explaining that ``[n]othing 
in subchapter II [i.e., Title II] of this chapter relating to 
nonroad engines shall be construed to apply to stationary internal 
combustion engines.'')
---------------------------------------------------------------------------

    Although a ``system of emission reduction'' lays the groundwork for 
CAA section 111 standards, the term ``system'' is not defined in the 
CAA. As a result, we look first to its ordinary meaning.
    Abstractly, the term ``system'' means a set of things or parts 
forming a complex whole; a set of principles or procedures according to 
which something is done; an organized scheme or method; and a group of 
interacting, interrelated, or interdependent elements.\470\ As a 
phrase, ``system of emission reduction'' takes a broad meaning to serve 
a singular purpose: It is a set of measures that work together to 
reduce emissions.
---------------------------------------------------------------------------

    \470\ Oxford Dictionary of English (3rd ed.) (2010), available 
at http://www.oxforddictionaries.com/us/definition/american_english/system; see also American Heritage Dictionary (5th ed.) (2013), 
available at http://www.yourdictionary.com/system#americanheritage; 
and The American College Dictionary (C.L. Barnhart, ed. 1970) (``an 
assemblage or combination of things or parts forming a complex or 
unitary whole'').
---------------------------------------------------------------------------

    When read in context, the phrase ``system of emission reduction'' 
carries important limitations: because the ``degree of emission 
limitation'' must be ``achievable through the application of the best 
system of emission reduction,'' (emphasis added), the ``system of 
emission reduction'' must be limited to a set of measures that work 
together to reduce emissions and that are implementable by the sources 
themselves.
    As a practical matter, the ``source'' includes the ``owner or 
operator'' of any building, structure, facility, or installation for 
which a standard of performance is applicable. For instance, under CAA 
section 111(e), it is the ``owner or operator'' of a source who is 
prohibited from operating ``in violation of any standard of performance 
applicable to such source.'' \471\
---------------------------------------------------------------------------

    \471\ While this section provides for enforcement in the context 
of new sources, a CAA section 111(d) plan must provide for the 
enforcement of a standard of performance for existing sources.
---------------------------------------------------------------------------

    Thus, a ``system of emission reduction'' for purposes of CAA 
section 111(d) means a set of measures that source owners or operators 
can implement to achieve an emission limitation applicable to their 
existing source.\472\
---------------------------------------------------------------------------

    \472\ Some commenters read the proposed rulemaking as taking the 
position that the phrase ``system of emission reduction'' includes 
anything whatsoever that reduces emissions, and criticized that 
interpretation as too broad. See UARG comment, at 3-4. We are not 
taking that interpretation here. In this final rule, we agree that 
the phrase should be limited to exclude, inter alia, actions beyond 
the ability of the owners/operators to control.
---------------------------------------------------------------------------

    In contrast, a ``system of emission reduction'' does not include 
actions that only a state or other governmental entity could take that 
would have the effect of reducing emissions from the source category, 
and that are beyond the ability of the affected sources' owners/
operators to take or control. Additionally, actions that a source owner 
or operator could take that would not have the effect of reducing 
emissions from the source category, such as purchasing offsets, would 
also not qualify as a ``system of emission reduction.''
    Building blocks 2 and 3 each fall within the meaning of a ``system 
of emission reduction'' because they consist of measures that the 
owners/operators of the affected EGUs can implement to achieve their 
emission limits. In doing so, the affected EGUs will achieve the 
overall emission reductions the EPA identifies in this rule. We 
describe these building block 2 and 3 measures in detail elsewhere in 
this rule, including the specific actions that owners/operators of 
affected EGUs can take to implement the measures.
    It should be noted that defining the scope of a ``system of 
emission reduction'' is not the end of our inquiry under CAA section 
111(a)(1); rather, as noted above, a standard of performance must 
reflect the application of the ``best system of emission reduction . . 
. adequately demonstrated.'' (Emphasis

[[Page 64763]]

added.) Thus, in determining the BSER, the Administrator must first 
determine whether the available systems of emission reduction are 
``adequately demonstrated,'' based on the criteria, described above, 
set out by Congress in the legislative history and the D.C. Circuit in 
case law. After identifying the ``adequately demonstrated'' systems of 
emission reduction, the Administrator then selects the ``best'' of 
these, based on several factors, including amount of emission 
reduction, cost, non-air quality health and environmental impact and 
energy requirements. Only after the Administrator weighs all of these 
considerations can she determine the BSER and, based on that, establish 
a standard of performance under CAA section 111(b) or an emission 
guideline under CAA section 111(d).
    For purposes of this final rule, it is not necessary to enumerate 
all of the types of measures that do or do not constitute a ``system of 
emission reduction.'' What is relevant is that building blocks 2 and 3 
each qualify as part of the ``system of emission reduction.'' As noted, 
they focus on supply-side activities and they each constitute measures 
that the affected EGUs can implement that will allow those EGUs to 
achieve the degree of emission limitation that the EPA has identified 
based on those building blocks. Further, these building blocks also 
satisfy the other statutory criteria enumerated in CAA section 
111(a)(1).
    (2) Other indications that the BSER provisions encompass a broad 
range of measures.
    The EPA's plain meaning interpretation that the BSER provisions in 
CAA section 111(d)(1) and (a)(1) are designed to include a broad range 
of measures, including building blocks 2 and 3, is supported by several 
other indications in the CAA and the legislative history of section 
111.
    (a) Scope of CAA section 111(d)(1).
    First, the broad scope of CAA section 111(d)(1) supports our 
interpretation of the BSER because a wide range of control measures is 
appropriate for the wide range of source categories and air pollutants 
covered under CAA section 111(d).
    In the 1970 CAA Amendments, Congress established a regulatory 
regime for existing stationary sources of air pollutants that may be 
envisioned as a three-legged stool, designed to address ``three 
categories of pollutants emitted from stationary sources'': (1) 
Criteria pollutants (identified under CAA section 109 and regulated 
under section 110); (2) hazardous air pollutants (identified and 
regulated under section 112); and (3) ``pollutants that are (or may be) 
harmful to public health or welfare but are not'' criteria or hazardous 
air pollutants.\473\ Congress enacted CAA section 111(d) to cover this 
third category of air pollutants and, in this sense, Congress designed 
it to apply to any air pollutants that were not otherwise regulated as 
toxics or NAAQS pollutants.\474\ This would include air pollutants that 
the EPA might later, when more information became available, designate 
as NAAQS or hazardous air pollutants, as well as air pollutants that 
Congress may not have been aware of at the time.\475\ In addition, the 
indications are that Congress expected CAA section 111(d) to be a 
significant source of regulatory activity, by some measures, more 
active than CAA section 112. This is evident because Congress expected 
that CAA section 111(d) would cover more air pollutants than either CAA 
section 109/110 (criteria pollutants) or CAA section 112 (hazardous air 
pollutants).\476\ In addition, in the 1990 CAA Amendments, Congress 
enacted CAA section 129 to achieve emission reductions from a major 
source category, solid waste incinerators, and established CAA section 
111(d) as the basic mechanism for that provision. The EPA subsequently 
promulgated a number of CAA section 129/111(d) rulemakings.\477\ 
Finally, it should be noted that Congress designed CAA section 111(d) 
to cover a wide range of source categories--including any source 
category that the EPA identifies under subsection 111(b)(1)(A) as 
meeting the criteria of, in general, causing or contributing 
significantly to air pollution that may reasonably be anticipated to 
endanger public health or welfare--along with the wide range of air 
pollutants.
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    \473\ 40 FR 53340, 53340 (Nov. 17, 1975) (EPA regulations 
implementing CAA section 111(d)).
    \474\ See S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 420 (``It should be noted that the emission 
standards for pollutants which cannot be considered hazardous (as 
defined in section 115 [i.e., the bill's version of CAA section 112] 
could be established under section 114 [i.e., the bill's version CAA 
section 111]. Thus, there should be no gaps in control activities 
pertaining to stationary source emissions that pose any significant 
danger to public health or welfare.'').
    \475\ See S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 420.
    \476\ See S. Rep. No. 91-1196, at 9; 18-20, 1970 CAA Legis. 
Hist. at 418-20. The Senate Committee Report identified 14 
substances as subject to the provision that became section 111(d), 
four substances as hazardous air pollutants that would be regulated 
under the provision that became section 112, and 5 substances as 
criteria pollutants that would be regulated under the provisions 
that became sections 109-110 (and more ``as knowledge increases''). 
In particular, the Report recognized that in particular, relatively 
few air pollutants may qualify as hazardous air pollutants, but that 
other air pollutants that did not qualify as hazardous air 
pollutants would be regulated under what became section 111(d).
    \477\ See, e.g., Standards of Performance for New Stationary 
Sources and Emission Guidelines for Existing Sources: Hospital/
Medical/Infectious Waste Incinerators, 62 FR 48348, 48359 (Sept. 15, 
1997); Standards of Performance for New Stationary Sources and 
Emission Guidelines for Existing Sources: Commercial and Industrial 
Solid Waste Incineration Units, 65 FR 75338, 75341 (Dec. 1, 2000).
---------------------------------------------------------------------------

    Because Congress designed CAA section 111(d) to cover a wide range 
of air pollutants--including ones that Congress may not have been aware 
of at the time it enacted the provision--and a wide range of 
industries, it is logical that Congress intended that the BSER 
provision, as applied to CAA section 111(d), have a broad scope so as 
to accommodate the range of air pollutants and source categories.
    (b) Legislative history of CAA section 111.
    (i) Breadth of ``system of emission reduction.''
    The phrase ``system of emission reduction,'' particularly as 
applied under CAA section 111(d), should be broadly interpreted 
consistent with its plain meaning but also in light of its legislative 
history. The version of CAA section 111(d)(1) that Congress adopted as 
part of the 1970 CAA Amendments read largely as CAA section 111(d)(1) 
does at present, except that it required states to impose ``emission 
standards'' on any existing source. (Congress replaced that term with 
``standards of performance'' in the 1977 CAA Amendments.) The 1970 CAA 
Amendments version of CAA section 111(d)(1) neither defined ``emission 
standards'' nor imposed restrictions on the EPA in determining the 
basis for the emission standards.\478\
---------------------------------------------------------------------------

    \478\ Although not defined under CAA section 111, the term was 
used in other provisions and defined in some of them. The term was 
defined under the CAA's citizen suit provision. See 1970 CAA 
Amendments, Pub. L. 91-604, Sec.  12, 84 Stat. 1676, 1706 (Dec. 31, 
1970) (defined as ``(1) a schedule or timetable of compliance, 
emission limitation, standard of performance or emission standard, 
or (2) a control or prohibition respecting a motor vehicle fuel or 
fuel additive . . . . .''). Congress also used it in the CAA's NAAQS 
provisions and in CAA section 112. Under the CAA's NAAQS provisions 
(i.e., the ``Ambient Air Quality and Emission Standards'' 
provisions), Congress directed the EPA to issue information on ``air 
pollution control techniques,'' and include data on ``available 
technology and alternative methods of prevention and control of air 
pollution'' as well as on ``alternative fuels, processes, and 
operating methods which will result in elimination or significant 
reduction of emissions.'' Id., Sec.  4, 84 Stat. at 1679. Similarly, 
under CAA section 112, the Administrator was required to ``from time 
to time, issue information on pollution control techniques for air 
pollutants'' subject to emission standards. Id., 84 Stat. at 1685. 
These statements provide additional context for the term's broad 
intent.
---------------------------------------------------------------------------

    For new sources, CAA section 111(b)(1)(B), as enacted in the 1970 
CAA Amendments (and as it largely still

[[Page 64764]]

reads), required the EPA to promulgate ``standards of performance,'' 
and defined that term, much like the present definition, as emission 
standards based on the ``best system of emission reduction . . . 
adequately demonstrated.'' This quoted phrase was not included in 
either the House or Senate versions of the provision, and, instead, was 
added during the joint conference between the House and Senate. The 
conference report accompanying the text offers no clarifications.
    The House and Senate bills do, however, provide some insights. The 
House bill, H.R. 17255, would have required new sources of non-
hazardous air pollutants to ``prevent and control such emissions to the 
fullest extent compatible with the available technology and economic 
feasibility, as determined by the Secretary.'' \479\ The Senate bill, 
S. 4358, would have established ``Federal standards of performance for 
new sources,'' which, in turn, were to ``reflect the greatest degree of 
emission control which the Secretary determines to be achievable 
through application of the latest available control technology, 
processes, operating methods, or other alternatives.'' \480\ The Senate 
Committee Report explains that ``performance standards should be met 
through application of the latest available emission control technology 
or through other means of preventing or controlling air pollution.'' 
\481\ This Report further elaborates that the term ``standards of 
performance''

    \479\ H.R. 17255, Sec.  5, 1970 CAA Legis. Hist. at 921-22. The 
reference to ``Secretary'' was to the Secretary of Health Education 
and Welfare, which, at the time, was the agency with responsibility 
for air pollution regulations.
    \480\ S. 4358, Sec.  6, 1970 Legis. Hist. at 554-55 (emphasis 
added).
    \481\ S. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 415-16 (emphasis added).

refers to the degree of emission control which can be achieved 
through process changes, operation changes, direct emission control, 
or other methods. The Secretary should not make a technical judgment 
as to how the standard should be implemented. He should determine 
the achievable limits and let the owner or operator determine the 
most economic, acceptable technique to apply.\482\
---------------------------------------------------------------------------

    \482\ S. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 415-16 (emphasis added).

Thus, the Senate bill clearly envisioned that standards of performance 
would not be based on a particular technology or even a particular 
method to prevent or control air pollution.\483\ This vision contrasted 
with the House bill, which would have restricted performance standards 
to economically feasible technical controls.
---------------------------------------------------------------------------

    \483\ Notably, the Senate report identifies pollution control 
and pollution prevention as objectives of the Senate provision. 
Pollution prevention is discussed more generally below as a 
``primary purpose'' of the CAA, however, the report makes clear that 
pollution prevention measures--which the EPA understands to include 
such measures as building blocks 2 and 3--are appropriate under CAA 
section 111.
---------------------------------------------------------------------------

    Following the House-Senate Conference, the enacted version of the 
legislation defined a ``standard of performance'' to mean

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) the Administrator determines has 
been adequately demonstrated.\484\
---------------------------------------------------------------------------

    \484\ CAA section 111(a)(1) under the 1970 CAA Amendments 
(emphasis added).

While the phrase ``system of emission reduction'' was not discussed in 
the Conference Report, an exhibit titled ``Summary of the Provisions of 
Conference Agreement on the Clean Air Amendments of 1970'' was added to 
the record during the Senate's consideration of the Conference Report 
and sheds some light on the phrase. According to the summary, ``[t]he 
agreement authorizes regulations to require that new major industry 
plants such as power plants, steel mills, and cement plants achieve a 
standard of emission performance based on the latest available control 
technology, processes, operating methods, and other alternatives.'' 
\485\ In light of this summary, the phrase ``system of emission 
reduction'' appears to blend the broad spirit of S. 4358 (which 
required the ``latest available control technology, processes, 
operating methods, or other alternatives'') with the cost concerns 
identified in H.R. 17255 (which required consideration of ``economic 
feasibility'' when establishing federal emission standards for new 
stationary sources). This history strongly suggests that Congress 
intended to authorize the EPA to consider a wide range of measures in 
calculating a standard of performance for stationary sources. At a 
minimum, there is no indication that Congress intended to preclude 
measures or actions such as the ones in building blocks 2 and 3 from 
the EPA's assessment of the BSER.
---------------------------------------------------------------------------

    \485\ Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-
1783 (Dec. 17, 1970), 1970 CAA Legis. Hist. at 130.
---------------------------------------------------------------------------

    Notwithstanding this broad approach, as we discuss in the Legal 
Memorandum, the legislative history of the 1970 CAA Amendments also 
indicates that Congress intended that new sources be well-controlled at 
the source, in light of their expected lengthy useful lives.
    In 1977, Congress amended CAA section 111(a)(1) to limit the types 
of controls that could be the basis of standards of performance for new 
sources to technological controls. Congress was clear, however, that 
existing source standards, which were no longer developed as ``emission 
standards,'' would not be limited to technological measures. 
Specifically, the 1977 CAA Amendments revised CAA section 111(a)(1) to 
require all new sources to meet emission standards based on the 
reductions achievable through the use of the ``best technological 
system of continuous emission reduction.'' \486\ According to the 
legislative history, [t]his mean[t] that new sources may not comply 
merely by burning untreated fuel, either oil or coal.'' \487\ The new 
requirement stemmed in part from Congress's concern over the shocks 
that the country experienced during the 1973-74 Arab Oil Embargo, which 
led Congress to revise CAA section 111 to ``encourage and facilitate 
the increased use of coal, and to reduce reliance (by new and old 
sources alike), upon petroleum to meet emission requirements.'' \488\ 
Imposing a new technological requirement (along with a new percentage 
reduction requirement) under CAA section 111 was designed to ``force 
new sources to burn high-sulfur fuel thus freeing low-sulfur fuel for 
use in existing sources where it is harder to control emissions and 
where low-sulfur fuel is needed for compliance.'' \489\ Congress 
nonetheless recognized that despite narrowing new source standards to 
the best ``technological system of continuous emission reduction,'' 
many ``innovative approaches may in fact reduce the economic and energy 
impact of emissions control,'' and the Administrator should still be 
encouraged to consider other technologically based techniques for 
emissions reduction, including ``precombustion cleaning or treatment of 
fuels.'' \490\ This is discussed in more detail below.
---------------------------------------------------------------------------

    \486\ CAA section 111(a)(1) (1977).
    \487\ H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. 
at 2659.
    \488\ H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. 
at 2659.
    \489\ New Stationary Sources Performance Standards; Electric 
Utility Steam Generating Units, 44 FR 33580, 33581-33582 (June 11, 
1979).
    \490\ H.R. Rep. No. 95-294, at 189 (May 12, 1977), 1977 CAA 
Legis. Hist. at 2656.
---------------------------------------------------------------------------

    Despite these changes with respect to new sources, the 1977 CAA 
Amendments further reinforce the

[[Page 64765]]

notion that with respect to existing sources, the BSER was never 
intended to be narrowly applied. In 1977, Congress changed CAA section 
111(d)(1) to require that states adopt ``standards of performance'' and 
made clear that such standards were to be based on the ``best system of 
continuous emission reduction . . . adequately demonstrated,'' \491\ 
but generally maintained the breadth of that term. Although Congress 
inserted the word ``continuous'' into the phrase, Congress explained 
that ``standards in the Section 111(d) state plan would be based on the 
best available means (not necessarily technological) for categories of 
existing sources to reduce emissions.'' \492\ This was intended to 
distinguish existing source standards from new source standards, for 
which ``the requirement for [BSER] has been more narrowly redefined as 
best technological system of continuous emission reduction.'' 
493 494
---------------------------------------------------------------------------

    \491\ CAA section 111(a)(1)(C) under the 1977 CAA Amendments.
    \492\ H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. 
at 2662 (emphasis added). Congress also endorsed the EPA's practice 
of establishing ``emission guidelines'' under CAA section 111(d). 
See H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 
2662 (``The Administrator would establish guidelines as to what the 
best system for each such category of existing sources is. However, 
the state would be responsible for determining the applicability of 
such guidelines to any particular source or sources.'').
    \493\ Sen. Muskie, S. Consideration of the H.R. Conf. Rep. No. 
95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353.
    \494\ In 1977, Congress added a new substantive definition for 
``emission standard'' generally applicable throughout the CAA. 1977 
CAA Amendments, Public Law 95-95, Sec.  301, 91 Stat. 685, 770 (Aug. 
7, 1977) (defining ``emission limitation'' and ``emission standard'' 
as ``a requirement established by the State or the Administrator 
which limits the quantity, rate, or concentration of emissions of 
air pollutants on a continuous basis, including any requirement 
relating to the operation or maintenance of a source to assure 
continuous emission reduction.''). Congress also added a generally 
applicable definition of standard of performance, defined as ``a 
requirement of continuous emission reduction, including any 
requirement relating to the operation or maintenance of a source to 
assure continuous emission reduction.'' Id.
---------------------------------------------------------------------------

    In the 1990 CAA Amendments, Congress restored the 1970s vintage 
definition of a standard of performance as applied to both new and 
existing sources. With respect to existing sources, this had the effect 
of no longer requiring that the BSER be ``continuous.'' \495\ Further, 
nothing in the 1990 CAA Amendments or their legislative history 
indicates that Congress intended to impose new constraints on the types 
of systems of emission reduction that could be considered under CAA 
section 111(d)(1) and (a)(1). In contrast, Congress retained the 
definition of the term ``technological system of continuous emission 
reduction,'' which means ``a technological process for production or 
operation by any source which is inherently low-polluting or 
nonpolluting,'' CAA section 111(a)(7)(A), or ``a technological system 
for continuous reduction of the pollution generated by a source before 
such pollution is emitted into the ambient air, including precombustion 
cleaning or treatment of fuels,'' CAA section 111(a)(7)(B).
---------------------------------------------------------------------------

    \495\ We note that the general definition of a standard of 
performance at CAA section 302(l) still uses ``continuous.'' Even if 
this provision applies to section 111, it does not affect our 
analysis in this rule, including our interpretation that BSER 
includes building blocks 2 and 3.
---------------------------------------------------------------------------

    That term continues to be used in reference to new sources in 
certain circumstances, under CAA section 111(b), (h), and (j).\496\ 
However, it is not and never has been used to regulate existing 
sources. In this manner, the 1990 CAA Amendments further reinforce the 
breadth and flexibility of the phrase ``system of emission reduction,'' 
particularly as it applies to existing sources under CAA section 
111(d).
---------------------------------------------------------------------------

    \496\ There are numerous reasons to find that particular CAA 
section 111(b) standards of performance should be based on controls 
installed at the source at the time of new construction. This is due 
in part to the recognition that new sources have long operating 
lives over which initial capital costs can be amortized, as 
recognized in the legislative history for section 111. Thus, new 
construction is the preferred time to drive capital investment in 
emission controls. See, e.g., S. Rep. No. 91-1196, at 15-16, 1970 
CAA Legis. Hist. at 416 (``[t]he overriding purpose of this section 
[concerning new source performance standards] would be to prevent 
new air pollution problems, and toward that end, maximum feasible 
control of new sources at the time of their construction is seen by 
the committee as the most effective and, in the long run, the least 
expensive approach.''); see also 1977 CAA Amendments, Sec.  109, 91 
Stat. at 700, (redefining, with respect to new sources, CAA section 
111(a)(1) to reflect the best ``technological system of continuous 
emission reduction'' and adding CAA section 111(a)(7) to define this 
new term). However, as a result of the 1990 revisions to CAA section 
111(a)(1), which replaced the phrase ``technological system of 
continuous emission reduction'' with ``system of emission 
reduction,'' new source standards would not be restricted to being 
based on technological control measures.
---------------------------------------------------------------------------

    For these reasons, the 1970, 1977, and 1990 legislative histories 
support the EPA's interpretation in this rule that the term is 
sufficiently broad to encompass building blocks 2 and 3.
    (ii) Reliance on actions taken by other entities.
    The legislative history supports the EPA's interpretation of 
``system of emission reduction'' in another way as well: The 
legislative history makes clear that Congress intended that standards 
of performance for electric power plants could be based on measures 
implemented by other entities, for example, entities that ``wash,'' or 
desulfurize, coal (or, for oil-fired EGUs, that desulfurize oil). This 
legislative history is consistent with the EPA's view that the ``system 
of emission reduction'' may include actions taken by an entity with 
whom the owner/operator of the affected source enters into a 
contractual relationship as long as those actions allow the affected 
source to meet its emission limitation. By the same token, this 
legislative history directly refutes commenters' assertions that the 
phrase ``system of emission reduction'' must not include actions taken 
by entities other than the affected sources.\497\
---------------------------------------------------------------------------

    \497\ See, e.g., comments by UARG at 31 (the building blocks 
other than building block 1 take a `` `beyond-the-source' approach'' 
and ``impermissibly rely on measures that go beyond the boundaries 
of individual affected EGUs and that are not within the control of 
individual EGU owners and operators''); comments by American 
Chemistry Council et al. (``Associations'') at 60-61 (EPA's proposed 
BSER analysis is unlawful because it ``looks beyond the fence line 
of the fossil fuel-fired EGUs that are the subject of this 
rulemaking;'' ``the standard of performance must . . . be limited to 
the types of actions that can be implemented directly by an existing 
source within [the appropriate] class or category.'').
---------------------------------------------------------------------------

    As noted above, in the 1977 CAA Amendments, Congress revised the 
basis for standards of performance for new fossil fuel-fired stationary 
sources to be a ``technological system of continuous emission 
reduction,'' including ``precombustion cleaning or treatment of 
fuels.'' \498\ Precombustion cleaning or treatment reduces the amount 
of sulfur in the fuel, which means that the fuel can be combusted with 
fewer SO2 emissions, and that in turn means that the source 
can achieve a lower emission limit. Congress understood that these fuel 
cleaning techniques would not necessarily be accomplished at the 
affected source and, in revising CAA section 111(a)(1), wanted to 
ensure that such techniques would not be overlooked. For example, the 
1977 House Committee report indicates that an assessment of the best 
technological system of continuous emission reduction for fossil fuel-
fired power plants would include off-site or third-party pre-combustion 
techniques for reducing emissions at the source (``e.g., various coal-
cleaning technologies such as solvent refining, oil desulfurization at 
the refinery'').\499\

[[Page 64766]]

Thus, the standard of performance reflecting the best technological 
system implementable by an affected source could be based, in part, on 
technologies used at off-site facilities owned and operated by third-
parties.
---------------------------------------------------------------------------

    \498\ 1977 CAA Amendments, Sec.  109, 91 Stat. at 700; see also 
CAA section 111(a)(7).
    \499\ H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. 
at 2655 (emphasis added). Generally speaking, coal cleaning 
activities also are conducted by third parties. For instance, EPA 
recognized in a regulatory analysis of new source performance 
standards for industrial-commercial-institutional steam generating 
units that the technology ``requires too much space and is too 
expensive to be employed at individual industrial-commercial-
institutional steam generating units.'' U.S. EPA, Summary of 
Regulatory Analysis for New Source Performance Standards: 
Industrial-Commercial-Institutional Steam Generating Units of 
Greater than 100 Million Btu/hr Heat Input, EPA-450/3-86-005, p. 4-4 
(June 1986).
---------------------------------------------------------------------------

    In the 1990 CAA Amendments, Congress eliminated many of the 
restrictions and other provisions added in the 1977 CAA Amendments by 
largely reinstating the 1970 CAA Amendments' definition of ``standard 
of performance.'' Nevertheless, there is no indication that in doing 
so, Congress intended to preclude the EPA from considering coal 
cleaning by third parties (which had been considered within the scope 
of the best system of emission reduction even under the 1970 CAA 
Amendments),\500\ and in fact, the EPA's regulations promulgated after 
the 1990 CAA Amendments continue to impose standards of performance 
that are based on third-party coal cleaning.\501\
---------------------------------------------------------------------------

    \500\ See U.S. EPA, Background Information for Proposed New-
Source Performance Standards: Steam Generators, Incinerators, 
Portland Cement Plants, Nitric Acid Plants, Sulfuric Acid Plants, 
Office of Air Programs Tech. Rep. No. APTD-0711, p. 7 (Aug. 1971) 
(indicating the ``desirability of setting sulfur dioxide standards 
that would allow the use of low-sulfur fuels as well as fuel 
cleaning, stack-gas cleaning, and equipment modifications'' 
(emphasis added)).
    \501\ 40 CFR 60.49b(n)(4); see also Amendments to New Source 
Performance Standards (NSPS) for Electric Utility Steam Generating 
Units and Industrial-Commercial-Institutional Steam Generating 
Units; Final Rule, 72 FR 32742 (June 13, 2007).
---------------------------------------------------------------------------

    (c) Consistency of a broad interpretation of CAA section 111 with 
the overall structure of the CAA.
    Interpreting CAA section 111(d)(1) and (a)(1) to authorize the 
EPA's consideration of the building block 2 and 3 measures is 
consistent with the overall structure of the CAA, particularly as it 
was amended in 1970, when Congress added CAA section 111 in much the 
same form that it reads today.
    In the 1970 CAA Amendments, for the most part, and particularly for 
stationary source provisions, Congress painted with broad brush 
strokes, giving broad authority to the EPA or the states. That is, 
Congress established general requirements that were intended to produce 
stringent results, but gave the EPA or the states great discretion in 
fashioning the types of measures to achieve those results.
    For example, under CAA section 109, Congress authorized the EPA to 
promulgate national ambient air quality standards (NAAQS) for air 
pollutants, and Congress established general criteria and procedural 
requirements, but left to the EPA discretion to identify the air 
pollutants and select the standards. Under CAA section 110, Congress 
required the states to submit to the EPA SIPs, required that the plans 
attain the NAAQS by a date certain, and established procedural 
requirements, but allowed the states broad discretion in determining 
the substantive requirements of the SIPs.
    Under CAA section 111(b), Congress directed the EPA to list source 
categories that endanger public health or welfare and established 
procedural requirements, but did not include other substantive 
requirements, and instead gave the EPA broad discretion to determine 
the criteria for endangerment.
    Under CAA section 112, Congress required the EPA to regulate 
certain air pollutants and to set ``emission standards'' that meet 
general criteria, and established procedural requirements, but did not 
include other substantive requirements and, instead, gave the EPA broad 
discretion in identifying the types of pollutants and in determining 
the standards.\502\ By and large, Congress left these provisions intact 
in the 1977 CAA Amendments.503 504
---------------------------------------------------------------------------

    \502\ By comparison, under the 1990 CAA Amendments, Congress 
substantially transformed CAA section 112 to be significantly more 
prescriptive in directing EPA rulemaking, which reflected Congress's 
increased knowledge of hazardous air pollutants and impatience with 
the EPA's progress in regulating.
    \503\ In the 1977 CAA Amendments, Congress applied the same 
broad drafting approach to the stratospheric ozone provisions it 
adopted in CAA sections 150-159. There, Congress authorized the EPA 
to determine whether, ``in the Administrator's judgment, any 
substance, practice, process, or activity may reasonably be 
anticipated to affect the stratosphere, especially ozone in the 
stratosphere, and such effect may reasonably be anticipated to 
endanger public health or welfare,'' and then directed the EPA, if 
it made such a determination, to ``promulgate regulations respecting 
the control of such process practice, process, or activity. . . .'' 
CAA section 157(a). This provision does not further specify 
requirements for the regulations.
    \504\ On the other hand, in those instances in which Congress 
had a clear idea as to the emission limitations that it thought 
should be imposed, it mandated those emission limits, e.g., in Title 
II concerning motor vehicles.
---------------------------------------------------------------------------

    Congress drafted the CAA section 111(d) requirements in the 1970 
CAA Amendments, and revised them in the 1977 CAA Amendments, in a 
manner that is similar to the other stationary source requirements, 
just described, in CAA sections 109, 110, 111(b), and 112. The CAA 
section 111(d) requirements are broadly phrased, include procedural 
requirements but no more than very general substantive requirements, 
and give broad discretion to the EPA to determine the basis for the 
required emission limits and to the states to set the standards. It 
should be noted that this drafting approach is not unique to the CAA; 
on the contrary, Congress ``usually does not legislate by specifying 
examples, but by identifying broad and general principles that must be 
applied to particular factual instances.'' \505\
---------------------------------------------------------------------------

    \505\ Pub. Citizen v. U.S. Dept. of Justice, 491 U.S. 440, 475 
(1989) (Kennedy, J., concurring).
---------------------------------------------------------------------------

    In light of this statutory framework, it is clear that Congress 
delegated to the EPA the authority to administer CAA section 111, 
including by authorizing the EPA to apply the ``broad and general 
principles'' contained in CAA section 111(a)(1) to the particular 
circumstances we face today.
    (3) Comments and responses.
    While some commenters support the EPA's interpretation of section 
111 to authorize the inclusion of building blocks 2 and 3 in the BSER, 
other commenters assert that the emission standards must be based on 
measures that the sources subject to CAA section 111--in this rule, the 
affected EGUs--apply to their own design or operations, and, as a 
result, in this rule, cannot include measures implemented at entities 
other than the affected EGUs that have the effect of reducing 
generation, and therefore emissions, from the affected EGUs. The 
commenters assert that various provisions in CAA section 111 make this 
limitation clear. We do not find those arguments persuasive.
    First, some commenters state that under CAA section 111(d)(1) and 
(a)(1), the existing sources subject to the standards of performance 
must be able to achieve their emission limit, but that they are able to 
do so only through measures integrated into the source's own design and 
operation. As a result, according to these commenters, those are the 
only types of measures that may qualify as a ``system of emission 
reduction'' that may form the basis of the emissions standards. We 
disagree. We see nothing in CAA section 111(d)(1) or (a)(1) which by 
its terms limits CAA section 111 to measures that must be integrated 
into the sources' own design or operation. Rather, we recognize that in 
order for an emission limitation based on the BSER to be 
``achievable,'' the BSER must consist of measures that can be 
undertaken by an affected source--that is, its owner or operator. As 
noted elsewhere in the

[[Page 64767]]

preamble, the affected sources subject to this rule are fully able to 
meet their emission standards by undertaking the measures described in 
all three building blocks. Moreover, as discussed, the measures in 
building blocks 2 and 3 are highly effective in achieving 
CO2 emission reductions from these affected EGUs, given the 
unique characteristics of the industry. This reinforces the conclusion 
that the term ``system of emission reduction'' is broad enough to 
include these measures.
    The broad nature of CAA section 111(d)(1) and (a)(1) is also 
confirmed by comparing it to CAA provisions that explicitly require 
controls on the design or operations of an affected source. The most 
notable comparison is at CAA section 111(a)(7). The term 
``technological system of continuous emission reduction,'' which was 
added in 1977 and remains as a separately defined term means, in part, 
``a technological process for production or operation by any source 
which is inherently low-emitting or nonpolluting.'' (Emphasis added.) 
With respect to this portion of the definition (and ignoring the 
additional text, which includes ``precombustion cleaning or treatment 
of fuels'' and clearly encompasses off-site activities), it could be 
argued that between 1977 and 1990 new source performance standards 
should be restricted to measures that could be integrated into the 
design or operation of a source. However, commenters' assertion that 
the BSER must be limited in a similar fashion ignores the deliberate 
change in 1990 to restore the broader definition of a standard of 
performance (i.e., that it be based on the BSER and not the TSCER). In 
any case, the narrower scope of CAA section 111(a)(7) was never 
applicable to the regulation of existing sources under CAA section 
111(d).
    Several other examples of standard setting in the CAA shed light on 
ways in which Congress has constrained the EPA's review. CAA section 
407(b)(2) provides that the EPA base 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.'' (Emphasis added.) Likewise, in determining best 
available retrofit technology under CAA section 169A, the state (or 
Administrator) must ``take into consideration the costs of compliance, 
the energy and nonair quality environmental impacts, any existing 
pollution control technology in use at the source, the remaining useful 
life of the source, and the degree of improvement in visibility which 
may reasonably be anticipated to result from the use of such 
technology.'' \506\ (Emphasis added.) These provisions make clear that 
Congress knew how to constrain the basis for emission limits to 
measures that are integrated into the design or operation of the 
affected source, and that its choice to base CAA section 111(d)(1) and 
(a)(1) standards of performance on a ``system of emission reduction'' 
indicates Congress' intent to authorize a broader basis for those 
standards.
---------------------------------------------------------------------------

    \506\ Even under BART, the EPA is authorized to allow emissions 
trading between sources. See, e.g., 40 CFR 51.308(e)(1) & (2); Util. 
Air Reg. Group v. EPA, 471 F.3d 1333 (D.C. Cir. 2006); Ctr. for 
Econ. Dev. v. EPA, 398 F.3d 653 (D.C. Cir. 2005); and Cent. Ariz. 
Water Dist. v. EPA, 990 F.2d 1531 (9th Cir. 1993).
---------------------------------------------------------------------------

    Some commenters also argue that other provisions in CAA section 111 
indicate that Congress intended that CAA section 111(d)(1) and (a)(1) 
be limited to measures that are integrated into the source's design or 
operations. This argument is unpersuasive for several reasons. First, 
it would be unreasonable to presume that Congress intended to limit the 
BSER, indirectly through these other provisions, to measures that are 
integrated into the affected source's design or operations, when 
Congress could have done so expressly, as it did for the above-
discussed CAA section 407(b)(2) NOX requirements.
    Second, the interpretations that commenters offer for these various 
provisions misapply the text. For example, commenters note that under 
CAA section 111(d)(1), (a)(3), and (a)(6), the standards of performance 
apply to ``any existing source,'' and an ``existing source'' is defined 
to include ``any stationary source,'' which, in turn, is defined as 
``any building, structure, facility, or installation which emits or may 
emit any air pollutant.'' Commenters assert that these applicability 
and definitional provisions indicate that the BSER provisions in CAA 
section 111(d)(1) and (a)(1) must be interpreted to require that the 
control measures must be integrated into the design or operations of 
the source itself.
    We disagree. These applicability and definitional provisions are 
jurisdictional in nature. Their purpose is simply to identify the types 
of sources whose emissions are to be addressed under CAA section 
111(d), i.e., stationary sources, as opposed to other types of sources, 
e.g., mobile sources, whose emissions are addressed under other CAA 
provisions (such as CAA Title II). This purpose is made apparent by the 
terms of CAA section 111(a)(3), which contains two sentences (the 
second of which commenters seem to ignore). The first sentence 
provides: ``The term `stationary source' means any building, structure, 
facility, or installation which emits or may emit any air pollutant.'' 
The second sentence provides: ``Nothing in subchapter II of this 
chapter relating to nonroad engines shall be construed to apply to 
stationary internal combustion engines.'' This second sentence explains 
that stationary internal combustion engines are to be regulated under 
CAA section 111, and not Title II (relating to mobile sources), which 
confirms that the purpose of the definition of stationary source is 
jurisdictional in nature--to identify the emissions that are to be 
regulated under section 111, as opposed to other CAA provisions.
    These applicability and definitional provisions say nothing about 
the system of emission reduction--whether it is limited to measures 
integrated into the design or operation of the source itself or may be 
broader--that may form the basis of the standards for those emissions 
that are to be promulgated under CAA section 111.
    Third, this argument by commenters does not account for the 
commonsense proposition that it is the owner/operator of the stationary 
source, not the source itself, who is responsible for taking actions to 
achieve the emission rate, so that actions that the owner/operator is 
able to take should be considered in determining the appropriate 
standards for the source's emissions. Again, it is common sense that 
buildings, structures, facilities, and installations can take no 
actions--only owners and operators can install and maintain pollution 
control equipment; only owners and operators can solicit precombustion 
cleaning or treatment of fuel services; and only owners and operators 
can apply for a permit or trade allowances.\507\ Other provisions in 
CAA section 111 make clear the role of the owner/operator. CAA section 
111(e) provides that for new sources, the burden of compliance falls on 
the ``owner or operator.'' \508\ The same is necessarily true for 
existing sources. This supports the EPA's view that the basis for 
whether a control measure qualifies as a ``system of emission 
reduction'' under CAA section 111(d)(1)

[[Page 64768]]

and (a)(1) is whether it is something that the owner/operator can 
implement in order to achieve the emissions standard assigned to the 
source--if so, the control measure should qualify as a ``system of 
emission reduction''--and not whether the control measure is integrated 
into the source's own design or operation.
---------------------------------------------------------------------------

    \507\ Industry commenters also acknowledged that it is the owner 
or operator that implements the control requirements. See UARG 
comment at 19 (section 111(d) ``provides for the regulation of 
individual emission sources through performance standards that are 
based on what design or process changes an individual source's owner 
can integrate into its facility'').
    \508\ CAA section 111(e) provides: (``[I]t shall be unlawful for 
any owner or operator of any new source to operate such source in 
violation of any [applicable] standard of performance.'')
---------------------------------------------------------------------------

    Commenters also argue that CAA section 111(h), which authorizes 
``design, equipment, work practice or operational standard[s]'' 
(together, ``design standards'') only when a source's emissions are not 
emitted through a conveyance or cannot be measured, makes clear that 
CAA section 111 standards of performance must be based on measures 
integrated into a source's own design or operations. We disagree. CAA 
section 111(h) concerns the relatively rare situation in which an 
emission standard, which entails a numerical limit on emissions, is not 
appropriate because emissions cannot be measured, due either to the 
nature of the pollutant (i.e., the pollutant is not emitted through a 
conveyance) or the nature of the source category (i.e., the source 
category is not able to conduct measurements). CAA section 111(h) 
provides that in such cases, the EPA may instead impose design 
standards rather than establish an emission standard (i.e., the EPA can 
require sources to implement a particular design, equipment, work 
practice, or operational standard). When an emissions standard is 
appropriate, as in the present rule, CAA section 111(h) is silent as to 
what types of measures--whether limited to a source's own design or 
operations--may be considered as the system of emission reduction.\509\ 
In any event, CAA section 111(h) applies only to standards promulgated 
by the Administrator, and therefore appears by its terms to be limited 
to CAA section 111(b) rulemakings for new, modified, or reconstructed 
sources, not CAA section 111(d) rulemakings for existing sources.
---------------------------------------------------------------------------

    \509\ For this same reason, the fact that CAA section 111(h) 
authorizes the EPA to impose certain types of standards--such as, 
among others, work practice or operational standards--only in 
limited circumstances not present in this rulemaking, does not mean 
that the EPA cannot consider those same measures as the BSER in 
promulgating a standard of performance.
---------------------------------------------------------------------------

    Some commenters identify other provisions of CAA section 111 that, 
in their view, prove that CAA section 111 is limited to control 
measures that are integrated within the design or operations of the 
source. We do not find those arguments persuasive, for the reasons 
discussed in the supporting documents for this rule.
    Commenters also argue, more generally, that Congress knew how to 
authorize control measures such as RE, as indicated by Congress's 
inclusion of those measures in Title IV (relating to acid rain), so the 
fact that Congress did not explicitly include these measures in the 
BSER provisions of CAA section 111(d)(1) and (a)(1) indicates that 
Congress did not intend that they be included as part of the BSER, and 
instead intended that the BSER be limited to measures integrated into 
the sources' design or operations. This argument misses the mark. The 
provisions of CAA section 111(d)(1) and (a)(1) do not explicitly 
include any specific emission reduction measures--neither RE measures 
(like the ones Congress wanted to incentivize under Title IV), nor 
measures that are integrated into the sources' design or operations 
(like the retrofit control measures Congress required under CAA section 
407(b)). But this contrast with other CAA provisions does not mean that 
Congress did not intend the BSER to include any of those types of 
measures. Rather, this contrast supports viewing a ``system of emission 
reduction'' under CAA section 111 as sufficiently broad to encompass a 
wide range of measures for the purpose of emission reduction of a wide 
range of pollutants from a wide range of stationary sources.\510\
---------------------------------------------------------------------------

    \510\ It should also be noted that Title IV is limited to 
particular pollutants (i.e., SO2 and NOX) and 
particular sources--fossil fuel-fired EGUs--and as a result, lends 
itself to greater specificity about the types of control measures. 
Section 111(d), in contrast, applies to a wide range of source 
types, which, as discussed above, supports reading it to authorize a 
broad range of control measures.
---------------------------------------------------------------------------

    c. Deference to interpret the BSER to include building blocks 2 and 
3.
    To the extent that it is not clear whether the phrase ``system of 
emission reduction'' may include the measures in building blocks 2 and 
3, the EPA's interpretation of CAA section 111(d) and (a) is reasonable 
\511\ in light of our discretion to determine ``whether and how to 
regulate carbon-dioxide emissions from power plants . . . .'' \512\
---------------------------------------------------------------------------

    \511\ EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 
1603 (2014) (``We routinely accord dispositive effect to an agency's 
reasonable interpretation of ambiguous statutory language.'').
    \512\ American Electric Power Co. v. Connecticut, 131 S. Ct. 
2527, 2538 (2011) (``AEP'') (emphasis added).
---------------------------------------------------------------------------

    Our interpretation that a ``system of emission reduction'' for the 
affected EGUs may include building blocks 2 and 3 is a reasonable 
construction of the statute for the reasons described above and in this 
section below.
    (1) Consistency of building blocks 2 and 3 with the structure of 
the utility power sector.
    (a) Integration of the utility power sector.
    Certain characteristics of the utility power sector are of central 
importance for understanding why the measures of building blocks 2 and 
3 qualify as part of the system of emission reduction. As discussed 
above, electricity is highly substitutable and the utility power sector 
is highly integrated, so much so that it has been likened to a 
``complex machine.'' \513\ Specifically, the utility power sector is 
characterized by physical, as well as operational, interconnections 
between electricity generators themselves, and between those generators 
and electricity users. Because of the physical properties of 
electricity and the current low availability of large scale electricity 
storage, generation and load (or use) must be instantaneously balanced 
in real time. As a result, the utility power sector is uniquely 
characterized by extensive planning and highly coordinated operation. 
These features have been present for decades, and in fact, over time, 
the sector has become more highly integrated. Another important 
characteristics of the utility power sector is that although the states 
have developed both regulated and de-regulated markets, the generation 
of electricity reflects a least-cost dispatch approach, under which 
electricity is generated first by the generators with the lowest 
variable cost.
---------------------------------------------------------------------------

    \513\ S. Massoud Amin, ``Securing the Electricity Grid,'' The 
Bridge, Spring 2010, at 13, 14; Phillip F. Schewe, The Grid: A 
Journey Through the Heart of Our Electrified World 1 (2007).
---------------------------------------------------------------------------

    These characteristics of the sector have facilitated the overall 
objective of providing reliable electric service at least cost subject 
to a variety of constraints, including environmental constraints. 
Moreover, in each type of market, the sector has developed mechanisms, 
including the participation of institutional actors, to safeguard 
reliability and to assure least cost service.
    Congress,\514\ the Courts,\515\ the EPA in its regulatory 
actions,\516\ and states in

[[Page 64769]]

their regulatory actions \517\ have recognized the integrated nature of 
the utility power sector.
---------------------------------------------------------------------------

    \514\ See CAA section 404(f)(2)(B)(iii)(I) (conditioning a 
utility's eligibility for certain allowances on implementing an 
energy conservation and electric power plan that evaluates a range 
of resources to meet expected future demand at least cost); see also 
S. Rep. No. 101-228, at 319-20 (Dec. 20, 1989) (recognizing that 
``utilities already engage in power-pooling arrangements to ensure 
maximum flexibility and efficiency in supplying power'' to support 
the establishment of an allowance system under Title IV).
    \515\ New York v. Federal Energy Regulatory Commission, 535 U.S. 
1, at 7 (2002) (citing Brief for Respondent FERC 4-5).
    \516\ ``Stack Heights Emissions Balancing Policy,'' 53 FR 480, 
482 (Jan. 7, 1988).
    \517\ See 79 FR 34830, 34880 (June 18, 2014) (discussing 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, and quoting December 27, 2013 
Letter from Mary D. Nichols, Chairman of California Air Resources 
Board, to EPA Administrator Gina McCarthy).
---------------------------------------------------------------------------

    (b) Significance of integrated utility power sector for the BSER.
    The fungibility of electricity, coupled with the integration of the 
utility power sector, means that, assuming that demand is held 
constant, adding electricity to the grid from one generator will result 
in the instantaneous reduction in generation from other generators. 
Similarly, reductions in generation from one generator lead to the 
instantaneous increase in generation from other generators. Thus, the 
operation of individual EGUs is integrated and coordinated with the 
operations of other EGUs and other sources of generation, as well as 
with electricity users. This allows for locational flexibility across 
the sector in meeting demand for electricity services. The institutions 
that coordinate planning and operations routinely use this flexibility 
to meet demand for electricity services economically while satisfying 
constraints, including environmental constraints. Because of these 
characteristics, EGU owner/operators have long conducted their 
business, including entering into commercial arrangements with third 
parties, based on the premise that the performance and operations of 
any of their facilities is substantially dependent on the performance 
and operation of other facilities, including ones they neither own nor 
operate. For example, when an EGU goes off-line to perform maintenance, 
its customer base is served by other EGUs that increase their 
generation. Similarly, if an EGU needs to assure that it can meet its 
obligations to supply a certain amount of generation, it may enter into 
arrangements to purchase that generation, if it needs to, from other 
EGUs.
    Because of this structure, fossil fuel-fired EGUs can reduce their 
emissions by taking the actions in building blocks 2 and 3. 
Specifically, fossil fuel-fired EGUs may generate or cause the 
generation of increased amounts of lower- or zero-emitting 
electricity--through contractual arrangements, investment, or 
purchase--which will back out higher-emitting generation, and thereby 
lower emissions. In addition, fossil fuel-fired EGUs may reduce their 
generation, which, given the overall emission limits this rule 
requires, will have the effect of stimulating lower- or zero-emitting 
generation.
    It should also be noted that CO2 is particularly well-
suited for building blocks 2 and 3 because it is a global, not local, 
air pollutant, so that the location where it is emitted does not affect 
its environmental impact. The U.S. Supreme Court in the UARG case 
highlighted the importance of taking account of the unique 
characteristics of CO2.\518\
---------------------------------------------------------------------------

    \518\ See Util. Air. Reg. Group v. EPA, 134 S. Ct. 2427, 2441 
(2014).
---------------------------------------------------------------------------

    In light of these characteristics of the utility power sector, as 
well as the characteristics of CO2 pollution, it is 
reasonable for the EPA to reject an interpretation of the term ``system 
of emission reduction'' that would exclude building blocks 2 and 3 from 
consideration in this rule and instead restrict consideration to 
measures integrated into each individual affected source's design or 
operation, especially since the record and other publicly available 
information makes clear that the measures in the two building blocks 
are effective in reducing emissions and are already widely used.
    As discussed above, no such restriction on the measures that can be 
considered part of a ``system of emission reduction'' is required by 
the statutory language, and the legislative history demonstrates that 
Congress intended an interpretation of the phrase broad enough to 
encompass building blocks 2 and 3. The narrow interpretation advocated 
by some commenters would permit consideration only of potential 
CO2 reduction measures that are either more expensive than 
building blocks 2 and 3 (such as the use of natural gas co-firing at 
affected EGUs or the application of CCS technology) or measures capable 
of achieving far less reduction in CO2 emissions (such as 
the heat rate improvement measures included in building block 1). 
Imposing such a restrictive interpretation--one which is not called for 
by the statute--would be inconsistent with CAA section 111's specific 
requirement that standards be based on the ``best'' system of emission 
reduction and, as discussed below, would be inconsistent with 
Congressional design that the CAA be comprehensive and address the 
major environmental issues.\519\
---------------------------------------------------------------------------

    \519\ See King v. Burwell, No. 14-114 (2015) (slip op., at 21) 
(``But in every case we must respect the role of the Legislature, 
and take care not to undo what it has done.'').
---------------------------------------------------------------------------

    The unique characteristics of the sector described above require 
coordinated action in the fundamental, primary function of EGUs--and in 
meeting current pollution control requirements to the extent that EGUs 
operate in dispatch systems that apply variable costs in determining 
dispatch--and affected EGUs necessarily already plan and operate on a 
multi-unit basis. In doing so, they already make use of building blocks 
2 and 3 to meet operational and environmental objectives in a cost-
effective manner, as further described below. CO2 is a 
global pollutant that is exceptionally well-suited to emission 
reduction efforts optimized on a broad geographic scale rather than on 
a unit-by-unit basis. It is also clear from both comments and 
communications received through the Agency's outreach efforts that 
affected EGUs will seek to use building blocks 2 and 3 to achieve 
compliance with the emission standards set in the section 111(d) plans 
following promulgation of this rule. For these reasons--and the 
additional reasons discussed below--interpreting ``system of emission 
reduction'' so as to allow consideration in this rule of only the 
individual pieces of the ``complex machine,'' and to forbid 
consideration of the ways in which the pieces actually fit and work 
together as parts of that machine, such as building blocks 2 and 3, 
cannot be justified. This is particularly so in light of the dilemma 
presented by the types of control options that commenters argue are the 
only ones authorized under section 111(a)(1), which are controls that 
apply to the design or operation of the affected EGUs themselves. On 
the one hand, the control measures in building block 1 yield only a 
small amount of emission reductions. On the other hand, control 
measures such as carbon capture and storage, or co-firing with natural 
gas, could yield much greater emission reductions, but are 
substantially more expensive than building blocks 2 and 3.
    (2) Current implementation of measures in building blocks 2 and 3.
    The requirement that the ``system of emission reduction'' be 
``adequately demonstrated'' suggests that we begin our review under CAA 
section 111(d)(1) and (a)(1) with the systems that sources are already 
implementing to reduce their emissions. As noted above, fossil fuel-
fired EGUs have long implemented, and are continuing to implement, the 
measures in building blocks 2 and 3 for various purposes, including for 
the purpose of reducing CO2 emissions \520\--

[[Page 64770]]

and certainly always with the effect of reducing emissions. This is a 
strong indicator that these measures should be considered part of a 
``system of emission reduction'' for CO2 emissions from 
these sources. The requirement that the ``system of emission 
reduction'' be ``adequately demonstrated'' indicates that the 
implementation of control mechanisms or other actions that the sources 
are already taking to reduce their emissions are of particular 
relevance in establishing the emission reduction requirements of CAA 
section 111(d)(1) and (a)(1). As a result, such measures are a logical 
starting point for consideration as a ``system of emission reduction'' 
under CAA section 111.
---------------------------------------------------------------------------

    \520\ A number of utilities 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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    (3) Reliance in CAA Title IV on building block measures.
    Some of the building block approaches to reducing emissions in the 
utility power sector were first tested around the time that Congress 
adopted the 1970 CAA Amendments.\521\ Over time, these techniques have 
become more established within the industry, and by the 1990 CAA 
Amendments, Congress based the Title IV acid rain program for existing 
fossil fuel-fired EGUs in part on the same measures that are considered 
here.
---------------------------------------------------------------------------

    \521\ See, e.g., Shepard, Donald S., A Load Shifting Model for 
Air Pollution Control in the Electric Power Industry, Journal of the 
Air Pollution Control Association, Vol. 20:11, pp. 756-761 (November 
1970).
---------------------------------------------------------------------------

    (a) Overview.
    It is logical that in determining whether the ``system of emission 
reduction'' that Congress established in CAA section 111(d)(1) and 
(a)(1) is broad enough to include the measures in building blocks 2 and 
3 as the basis for establishing emission guidelines for fossil fuel-
fired EGUs, an inquiry should be made into the tools that Congress 
relied on in other CAA provisions to reduce emissions from those same 
sources. The most useful CAA provision to examine for this purpose is 
Title IV, which includes a nationwide cap-and-trade program under which 
coal-fired power plants must have allowances for their SO2 
emissions.
    Title IV includes several signals that it is especially relevant 
for interpreting and implementing CAA section 111(d) for purposes of 
this rule. Title IV applies to most of the same sources that this rule 
applies to--existing coal-fired EGUs and other utility boilers, as well 
as NGCC units. In addition, Congress added Title IV in the 1990 CAA 
Amendments at the same time that Congress largely reinstated the 1970-
vintage reading of section 111(a)(1) to adopt the currently applicable 
definition of a ``standard of performance,'' which is based on the 
``best system of emission reduction . . . adequately demonstrated.'' 
Moreover, Congress linked Title IV and CAA section 111 in certain 
respects. Specifically, Congress conditioned the revisions to CAA 
section 111(a)(1), i.e., eliminating the percentage reduction and most 
of the other limitations under the 1977 CAA Amendments, on the 
continued applicability of the Title IV SO2 cap, so that if 
the cap were eliminated, the changes would, by operation of law, also 
be eliminated, and the 1977 version of section 111(a)(1) would be 
reinstated.\522\ Additionally, Congress authorized the EPA to establish 
standards of performance for new and existing industrial (non-EGU) 
sources of SO2 emissions if emissions from these sources 
might exceed 1985 levels and failed to decline at the expected 
rate.\523\ While industrial sources were not required to participate 
under Title IV--they could elect to do so, under CAA section 410(a)--
Congress believed SO2 reductions from these sources were 
``an essential component of the reductions sought under [Title IV]'' 
and intended that Title IV would ``assure[ ] that these projected 
reductions occur and will not be overcome by future growth in 
emissions.'' \524\ As such, Congress viewed federal standards of 
performance as the appropriate backstop to Title IV even for sources 
that could not otherwise be regulated under CAA section 111(d).\525\ 
Together, these signals suggest that it is reasonable for the EPA to 
consider Title IV when interpreting and implementing CAA section 111.
---------------------------------------------------------------------------

    \522\ 1990 CAA Amendments, Sec.  403, 104 Stat. at 2631 
(requiring repeal of amendments to CAA section 111(a)(1) upon any 
cessation of effectiveness of CAA section 403(e), which requires new 
units to hold allowances for each ton of SO2 emitted). 
Congress believed that mandating a technological standard through 
the percentage reduction requirement in section 111(a)(1) would 
ensure the continued availability of low sulfur coal for existing 
sources. In other words, the percentage reduction requirement 
discouraged compliance with new source performance standards based 
solely on fuel shifting because it was much more costly to achieve 
the percentage reduction with lower sulfur coal. This belief was 
expressed during the 1977 CAA Amendments and is discussed above as 
part of the legislative history of section 111.
    \523\ 1990 CAA Amendments, Sec.  406, 104 Stat. at 2632-33; see 
also S. Rep. No. 101-228, at 282 (industrial source emissions 
totaled 5.6 million tons of SO2 in 1985).
    \524\ S. Rep. No. 101-228, at 345 (Dec. 20, 1989).
    \525\ To reiterate, ordinarily, standards of performance cannot 
be used to regulate SO2 emissions from existing sources 
because of the pollutant exclusions in CAA section 111(d).
---------------------------------------------------------------------------

    For present purposes, the essential features of Title IV are that 
it regulates SO2 emissions from coal-fired EGUs by adopting 
a nationwide cap of 8.95 million tons to be achieved through a tradable 
allowance system. As we explain below, the provisions of Title IV and 
its legislative history make clear that Congress based the stringency 
of the emission limitation requirement (8.95 million tons) and the 
overall structure of the approach (a cap-and-trade system) on 
Congress's recognition that the affected EGUs had a set of tools 
available to them to reduce their emissions, including through a shift 
to lower emitting generation and use of RE, along with add-on controls 
and other measures. Thus, Title IV provides a close analogy to CAA 
section 111: Generation shift and RE were part of Congress's basis for 
the Title IV emission requirements, and that is analogous to building 
blocks 2 and 3 serving as part of the ``system of emission reduction'' 
that is the EPA's basis for the section 111(d) emission guidelines. For 
this reason, the fact that in Title IV, Congress relied on generation 
shift and RE as the basis for the SO2 emission limitations 
for affected EGUs strongly supports interpreting CAA section 111(d)(1) 
and (a)(1) to include use of those same measures as part of the 
``system of emission reduction'' as the basis for CO2 
emission limitations for those same sources.
    (b) Title IV provisions.
    Several provisions of Title IV make explicit Congress's reliance on 
some of the same measures as are in building blocks 2 and 3. Title IV 
begins with a statement of congressional ``findings,'' including the 
finding that ``strategies and technologies for the control of 
precursors to acid deposition exist now that are economically feasible, 
and improved methods are expected to become increasingly available over 
the next decade.'' CAA section 401(a)(4) (emphasis added). Title IV 
then identifies as its ``purposes,'' ``to reduce the adverse effects of 
acid deposition through reductions in annual emissions of sulfur 
dioxide . . . and nitrogen oxides,'' as well as ``to encourage energy 
conservation, use of renewable and clean alternative technologies, and 
pollution prevention as a long-range strategy, consistent with the 
provisions of this subchapter, for reducing air pollution and other 
adverse impacts of energy production and use.'' CAA section 401(b) 
(emphasis added).
    By its terms, this statement of Title IV's purposes explicitly 
embraces the

[[Page 64771]]

use of RE. Moreover, the legislative history makes clear that the 
reference in the ``findings'' section quoted above to ``strategies and 
technologies'' includes generation shift to lower-emitting generation. 
Specifically, the Senate Report stated that an ``allowance system'' 
\526\ would encourage such ``technologies and strategies'' as
---------------------------------------------------------------------------

    \526\ See S. Rep. No. 101-228, at 320 (Dec. 20, 1989).

energy efficiency; enhanced emissions reduction or control 
technologies--like sorbent injection, cofiring with natural gas, 
integrated gasification combined cycles; fuel-switching and least-
emissions dispatching in order to maximize emissions reductions. 
\527\
---------------------------------------------------------------------------

    \527\ See S. Rep. No. 101-228, at 316 (Dec. 20, 1989) (emphasis 
added).

Congress's reliance on generation shifting and RE to reduce acid rain 
precursors from affected EGUs in Title IV strongly supports the EPA's 
authority to identify those same measures as part of the CAA section 
111 ``system of emission reduction'' to reduce CO2 emissions 
from those same sources.
    In addition, Title IV includes other provisions expressly 
concerning RE. In CAA section 404(f) and (g), Congress set aside a 
special pool of allowances to encourage use of RE. In order to obtain a 
special allowance (which would authorize emissions from a coal-fired 
utility), an electric utility needed to pay for qualifying RE sources 
``directly or through purchase from another person.'' \528\ These 
measures confirm Congress's recognition that RE was available to the 
industry, was desirable to encourage from a policy perspective, and was 
appropriate to consider in determining the amount of pollution 
reduction the law should require.
---------------------------------------------------------------------------

    \528\ CAA section 404(f)(2)(B)(i).
---------------------------------------------------------------------------

    (c) Title IV legislative history.
    Numerous statements in the legislative history confirm that 
Congress based the Title IV requirements on the fact that affected EGUs 
could reduce their SO2 emissions through a set of measures, 
including shifting to lower-emitting generation as well as reliance on 
RE.
    For example, the Senate Committee Report \529\ and Senator 
Baucus,\530\ a member of the Senate Committee on Environment and Public 
Works and Chairman of the House and Senate Clean Air Conferees, both 
emphasized that affected EGUs could rely on, among other things, 
``least-emissions dispatching in order to maximize emissions 
reductions.'' Similarly, statements supporting the RE reserve were 
included in the legislative history on the House side.
---------------------------------------------------------------------------

    \529\ S. Rep. No. 101-228 (Dec. 20, 1989), 1990 CAA Legis. Hist. 
at 8656.
    \530\ S. Debates on Conf. Rep. to accompany S. 1630, H.R. Rep. 
No. 101-952 (Oct. 27, 1990), 1990 CAA Legis. Hist. at 1033-35 
(statement of Senator Baucus, inserting ``the Clean Air Conference 
Report'' into the record).

    We believe that this provision of the bill will establish a 
balanced and workable approach that will provide certainty for 
utility companies that are considering conservation and renewables, 
while at the same time strengthening the environmental goals of this 
legislation.\531\
---------------------------------------------------------------------------

    \531\ H.R. Rep. No. 101-490, at 368-69; 674-76 (May 17, 1990) 
(additional views of Reps. Markey and Moorhead) (``We believe that 
H.R. 3030, as amended, will create a strong and effective incentive 
for utilities to immediately pursue energy conservation and 
renewable energy sources as key components of their acid rain 
control strategies.''); see also Rep. Collins, H. Debates on H.R. 
Conf. Rep. No. 101-952 (Oct. 26, 1990), 1990 CAA Legis. Hist. at 
1307 (``The bottom line is that our Nation's utilities and 
production facilities must reach beyond coal, oil, and fossil fuels. 
The focus must shift instead toward conservation and renewables such 
as hydropower, solar thermal, photovoltaics, geothermal, and wind. 
These clean sources and energy, available in virtually limitless 
supply, are the way of the future.'').

    (4) Reliance on RE measures to reduce CO2.
    The Title IV legislative history also makes clear that Congress 
viewed RE measures as a means to reduce CO2 for the purpose 
of mitigating climate change. By the time of the 1990 CAA Amendments, 
Congress had long been aware that emissions of CO2 and other 
GHGs put upward pressure on world temperatures and threatened to change 
the climate in destructive ways. In 1967, President Lyndon Johnson sent 
a letter to Congress recognizing that carbon dioxide was changing the 
composition of the atmosphere.\532\ The record for the 1970 CAA 
Amendments include hearings \533\ and a report by the National Academy 
of Sciences noting that carbon dioxide emissions could heat the 
atmosphere.\534\ A 1976 report noting the phenomenon was included in 
the record for the 1977 CAA Amendments.\535\ A 1977 Report by the 
National Academy of Sciences warned that average temperatures would 
rise due to the burning of fossil fuel.\536\ By the time of the 1990 
CAA Amendments, the dangers had become more clearly evident. Senate 
hearings beginning in 1988 had presented testimony from Dr. James E. 
Hansen of the National Aeronautics and Space Administration and other 
scientists that described the dangers of climate change caused by 
anthropogenic carbon dioxide and other GHG emissions and asserted that 
as a result of those emissions, the climate was in fact already 
changing.\537\
---------------------------------------------------------------------------

    \532\ ``Special Message to the Congress on Conservation and 
Restoration of Natural Beauty (Feb. 8, 1965). http://www.presidency.ucsb.edu/ws/?pid=27285 (``This generation has altered 
the composition of the atmosphere on a global scale through 
radioactive materials and a steady increase in carbon dioxide from 
the burning of fossil fuels.'').
    \533\ Testimony of Charles Johnson, Jr., Administrator of the 
Consumer Protection and Environmental Health Service (Administration 
Testimony), Hearing of the House Subcommittee on Public Health and 
Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381 (stating that 
``the carbon dioxide balance might result in the heating up of the 
atmosphere whereas the reduction of the radiant energy through 
particulate matter released to the atmosphere might cause reduction 
in radiation that reaches the earth'').
    \534\ 1970 CAA Legis. Hist. at 244, 257 S. Debate on S. 4358 
(Sept. 21, 1970) (statement of Sen. Boggs) (replicating Chapter IV 
of the Council on Environmental Quality's first annual report, which 
states, ``the addition of particulates and carbon dioxide in the 
atmosphere could have dramatic and long-term effects on world 
climate.'').
    \535\ 122 Cong. Rec. S25194 (daily ed. Aug. 3, 1976) (statement 
of Sen. Bumpers) (inserting into the record, ``Summary of Statements 
Received from Professional Societies for the Hearings on Effects of 
Chronic Pollution (in the Subcommittee on the Environment and the 
Atmosphere),'' which stated, ``there is near unanimity that carbon 
dioxide concentrations in the atmosphere are increasing rapidly. 
Though even the direction (warming or cooling) of the climate change 
to be caused by this is unknown, very profound changes in the 
balance of climate factors that determine temperature and rainfall 
on the earth are almost certain within 100 years'').
    \536\ National Academy of Sciences, ``Energy and Climate: 
Studies in Geophysics'' viii (1977), http://www.nap.edu/openbook.php?record_id=12024 (noting that a fourfold to eightfold 
increase in carbon dioxide by the latter part of the twenty-second 
century would increase average world temperature by more than 6 
degrees Celsius).
    \537\ S. Rep. No. 101-228, at 322 (Dec. 20, 1989), at 1990 
Legis. Hist. at 8662 (``In the last several years, the Committee has 
received extensive scientific testimony that increases in the human-
caused emissions of carbon dioxide and other GHGs will lead to 
catastrophic shocks in the global climate system.''); History, 
Jurisdiction, and a Summary of Activities of the Committee on Energy 
and Natural Resources During the 100th Congress, S. Rep. No. 101-
138, at 5 (Sept. 1989); ``Global Warming Has Begun, Expert Tells 
Senate,'' New York Times, June 24, 1988, http://www.nytimes.com/1988/06/24/us/global-warming-has-begun-expert-tells-senate.html.
---------------------------------------------------------------------------

    In enacting the 1990 CAA Amendments, Congress identified reductions 
in carbon dioxide emissions as an important co-benefit of the 
reductions in coal use and stressed that the RE measures would achieve 
those reductions. Senator Fowler, the author of the provision that 
established a RE technology reserve within the allowance system, noted 
that RE technologies, ``can greatly reduce emissions of . . . global 
warming gases. That makes them a potent weapon against catastrophic 
climate change . . . .'' \538\
---------------------------------------------------------------------------

    \538\ Sen. Fowler, S. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA 
Legis. Hist. at 7106.
---------------------------------------------------------------------------

    In addition, the 1990 CAA Amendments required EGUs covered by the 
monitoring requirements of the Title IV acid rain program to report 
their CO2 emissions.\539\
---------------------------------------------------------------------------

    \539\ 1990 CAA Amendments, Sec.  821, 104 Stat. at 2699.

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

[[Page 64772]]

    (5) Other EPA actions that rely on the building block measures.
    Another indication that it is reasonable to interpret the CAA 
section 111(d)(1) and (a)(1) provisions for the BSER to include the 
measures in building blocks 2 and 3 is that the EPA and states have 
relied on these measures to reduce emissions in a number of other CAA 
actions.
    For example, in 2005, the EPA promulgated a rule to control mercury 
emissions from fossil fuel-fired power plants under section 111(d): The 
Clean Air Mercury Rule (CAMR).\540\ The EPA established a nationwide 
cap-and-trade program that took effect in two phases: In 2010, the cap 
was set at 38 tons per year, and in 2018, the cap was lowered to 15 
tons per year. The EPA expected, on the basis of modeling, that sources 
would achieve the second phase, 15-ton per year cap cost-effectively by 
choosing among a set of measures that included shifting generation to 
lower-emitting units.\541\ CAMR was vacated by the D.C. Circuit on 
other grounds,\542\ but it shows that in the only other section 111(d) 
rule that the EPA attempted for affected EGUs, the EPA relied on 
shifting generation as part of the BSER in a CAA section 111(d) 
rulemaking for fossil fuel-fired EGUs.
---------------------------------------------------------------------------

    \540\ 70 FR 28606 (May 18, 2005).
    \541\ 70 FR 28606, 28619 (May 18, 2005) (``Under the CAMR 
scenario modeled by EPA, units [were] projected to meet their 
SO2 and NOX requirements and take additional 
steps to address the remaining [mercury] reduction requirements 
under CAA section 111, including adding [mercury]-specific control 
technologies (model applies [activated carbon injection]), 
additional scrubbers and [selective catalytic reduction], dispatch 
changes, and coal switching.'').
    \542\ New Jersey v. EPA, 517 F.3d 574, 583-84 (D.C. Cir. 2008), 
cert. denied sub nom. Util. Air Reg. Group v. New Jersey, 555 U.S. 
1169 (2009).
---------------------------------------------------------------------------

    In 2011, the EPA promulgated the Cross State Air Pollution Rule 
(CSAPR),\543\ in which it set statewide emission budgets for 
NOX and SO2 emitted by fossil fuel-fired EGUs, 
and based those standards in part on shifts to lower-emitting 
generation. CSAPR established state-wide emissions budgets based on a 
range of cost-effective actions that EGUs could take, and set the 
stringency of the deadlines for some required reductions in part 
because of the availability of ``increased dispatch of lower-emitting 
generation which can be achieved by 2012.'' \544\ The EPA developed a 
federal implementation plan (FIP) that established a trading program to 
meet the state-wide emission budgets set by CSAPR. The EPA projected 
that sources would meet their emission reduction obligations by 
implementing a range of emission control approaches, including the 
operation of add-on controls, switches to lower-emitting coal, and 
``changes in dispatch and generation shifting from higher emitting 
units to lower emitting units.'' \545\ The U.S. Supreme Court upheld 
CSAPR in EPA v. EME Homer City Generation, L.P.\546\
---------------------------------------------------------------------------

    \543\ 76 FR 48208 (Aug. 8, 2011).
    \544\ 76 FR at 48452.
    \545\ 76 FR at 48279-80. The exact mix of controls varied for 
different air pollutants and different time periods, but in all 
cases, shifting generation from higher to lower emitting units was 
one of the expected control strategies for the fossil fuel-fired 
power plants. Prior to CSAPR, the EPA promulgated two other 
transport rules, the NOX SIP Call (1998) and the Clean 
Air Interstate Rule (CAIR) (2005), which similarly established 
standards based on analysis of the availability and cost of emission 
reductions achievable through the use of add-on controls and 
generation shifting, and also authorized and encouraged the 
implementation of RE and demand-side EE measures. CAIR: 70 FR 25162, 
25165, 25256, 25279 (May 12, 2005) (allowing use of allowance set-
asides for renewables and energy efficiency); NOX SIP 
Call: 63 FR 57356, 57362, 57436, 57438, 57449 (Oct. 27, 1998) 
(authorizing and encouraging SIPs to rely on renewables and energy 
efficiency to meet the state budgets).
    \546\ 134 S. Ct. 1584 (2014).
---------------------------------------------------------------------------

    With respect to RE, in 2004, the EPA provided guidance to states 
for adopting attainment SIPs under CAA section 110 that include RE 
measures.\547\ Some states have done so. For example, Connecticut 
included in its SIP reductions from solar photovoltaic 
installations.\548\ In 2012, the EPA provided additional guidance on 
this topic.\549\ In addition, the EPA 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 RE in a SIP and to provide real-world examples and lessons 
learned through those states' case studies.\550\
---------------------------------------------------------------------------

    \547\ 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.
    \548\ 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).
    \549\ ``Roadmap for Incorporating EE/RE Policies and Programs 
into SIPs/TIPs'' (July 2012), http://epa.gov/airquality/eere/manual.html.
    \550\ 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.
---------------------------------------------------------------------------

    (6) Other rules that relied on actions by other entities.
    The EPA has promulgated numerous actions that establish control 
requirements for affected sources on the basis of actions by other 
entities or actions other than measures integrated into the design or 
operations of the affected sources. This section summarizes some of 
those actions. First, virtually all pollution control requirements 
require the affected sources to depend in one way or another on other 
entities, such as control technology manufacturers. Second, the EPA has 
promulgated numerous regulatory actions that are based on trading of 
mass-based emission allowances or rate-based emission credits, in which 
many sources meet their emission limitation requirements by purchasing 
allowances or credits from other sources that reduce emissions.
    (a) Third-party transactions.
    To reiterate, commenters argue that the ``system of emission 
reduction'' must be limited to measures taken by the affected source 
itself because only those measures are under the control of the 
affected source, as opposed to third parties, and therefore only those 
measures can assure that the affected source will achieve its emission 
limits. But this argument is belied by the fact that for a wide range 
of pollution control measures--including many that are indisputably 
part of a ``system of emission reduction''--affected sources are in 
fact dependent on third parties. For example, to implement any type of 
add-on pollution control equipment that is available only from a third-
party manufacturer, the affected source is dependent upon that third 
party for developing and constructing the necessary controls, and for 
offering them for sale. Indeed, the affected sources may be dependent 
upon third parties to install (and in some cases to operate) the 
controls as well, and in fact, in the CAIR rule, the EPA established 
the compliance date based on the limited availability of the 
specialized workforce needed to install the controls needed by the 
affected EGUs.\551\ In addition, EGU owners and operators may be 
dependent on the actions of third parties to finance the controls and 
third-party regulators to assure the mechanism for repaying that 
financing. However, this dependence does not mean that the emission 
limit based on that equipment is not achievable. Rather, the fact that 
the owner or operator of the affected source can arrange with the 
various third parties to

[[Page 64773]]

acquire, install, and pay for the equipment means that emission limit 
is achievable.
---------------------------------------------------------------------------

    \551\ 70 FR 25162, 25216-25225 (May 12, 2005). The EPA noted 
that its view was ``based on the NOX SIP Call 
experience.'' Id. at 25217.
---------------------------------------------------------------------------

    In this rule, as noted, the affected EGUs may, in many cases, 
implement the measures in building blocks 2 and 3 directly, and, in 
other cases, implement those measures by engaging in market 
transactions with third parties that are as much within the affected 
EGUs' control as engaging in market transactions with the range of 
third parties involved in pollution control equipment. By the same 
token, the market transactions that the affected EGUs engage in with 
third parties to implement the measures in building blocks 2 and 3 are 
comparable to the market transactions that affected EGUs engage in as 
part of their normal course of business, which include, among many 
examples, transactions with RTOs/ISOs or balancing authorities, 
entities in organized markets.
    (b) Emissions trading.
    Additional precedent that the ``system of emission reduction'' may 
include the measures in building blocks 2 and 3 and is not limited to 
measures that a source can integrate into its own design or operations, 
without being dependent on other entities, is found in the many rules 
that Congress has enacted or that the EPA has promulgated that allow 
EGUs and other sources to meet their emission limits by trading with 
other sources. In a trading rule, the EPA authorizes a source to meet 
its emission limit by purchasing mass-based emission allowances or 
rate-based emission credits generated from other sources, typically 
ones that implement controls that reduce their emissions to the point 
where they are able to sell allowances or credits. As a result, the 
availability of trading reduces overall costs to the industry by 
focusing the controls on the particular sources that have the least 
cost to implement controls. For present purposes, what is relevant is 
that in a trading program, some affected sources choose to meet their 
emission limits not by implementing emission controls integrated into 
their own design or operations, but rather by purchasing allowances or 
credits. These affected sources, therefore, are dependent on the 
actions of other entities, which are the ones that choose to meet their 
emission limits by implementing emission controls, which permits them 
to sell allowances or credits. They are dependent, however, in the same 
way that a source acquiring pollution control technology for the 
purposes of meeting a NSPS is dependent on a vendor of that technology 
to fulfill its contractual obligations. That is, the source operator 
purchasing a credit or an allowance is acquiring an equity in the 
technology or action applied to the credit-selling source for purposes 
of achieving a reduction in emissions occurring at the selling source. 
Trading programs have been commonplace under the CAA, particularly for 
EGUs, for decades. They include the acid rain trading program in Title 
IV of the CAA, the trading programs in the transport rules promulgated 
by the EPA under the ``good neighbor provision'' of CAA section 
110(a)(2)(D)(i)(I), the Clean Air Mercury Rule, and the regional haze 
rules. In each of these actions, the Congress or the EPA recognized 
that some of the affected EGUs would implement controls or take other 
actions that would lower their emissions and thereby allow them to sell 
allowances to other EGUs, which were dependent on the purchase of those 
allowances to meet their obligations.\552\ For the reasons just 
described, these trading rules refute commenters' arguments for 
limiting the scope of the ``system of emission reduction.''
---------------------------------------------------------------------------

    \552\ For example, in the enacting the acid rain program under 
CAA Title IV, Congress explicitly recognized that some sources would 
comply by purchasing allowances instead of implementing controls. S. 
Rep. No. 101-228, at 303 (Dec. 20, 1989). Similarly, in promulgating 
the NOX SIP Call in 1998, the EPA stated, ``Since EPA's 
determination for the core group of sources is based on the adoption 
of a broad-based trading program, average cost-effectiveness serves 
as an adequate measure across sources because sources with high 
marginal costs will be able to take advantage of this program to 
lower their costs.'' 63 FR at 57399 (emphasis added). By the same 
token, in promulgating the Cross State Air Pollution Rule, the EPA 
stated, ``the preferred trading remedy will allow source owners to 
choose among several compliance options to achieve required emission 
reductions in the most cost effective manner, such as installing 
controls, changing fuels, reducing utilization, buying allowances, 
or any combination of these actions.'' 76 FR at 48272 (emphasis 
added).
---------------------------------------------------------------------------

    (c) NSPS rules for EGUs that depend on the integrated grid.
    The EPA has promulgated NSPS for EGUs that include requirements 
based on the fact that an EGU may reduce its generation, and therefore 
its emissions, because the integration of the grid allows another EGU 
to increase generation and thereby avoid jeopardizing the supply of 
electricity. For example, in 1979, the EPA finalized new standards of 
performance to limit emissions of SO2 from new, modified, 
and reconstructed EGUs. In evaluating the best system against concerns 
of electric service reliability, the EPA took into account the unique 
features of power transmission along the interconnected grid and the 
unique commercial relationships that rely on those features.\553\
---------------------------------------------------------------------------

    \553\ See 44 FR 33580, 33597-33600 (taking into account ``the 
amount of power that could be purchased from neighboring 
interconnected utility companies'' and noting that ``[a]lmost all 
electric utility generating units in the United States are 
electrically interconnected through power transmission lines and 
switching stations'' and that ``load can usually be shifted to other 
electric generating units'').
---------------------------------------------------------------------------

    Additionally, in 1982, the EPA recognized that utility turbines 
could meet a NOX emission limit without unacceptable 
economic consequences because ``other electric generators on the grid 
can restore lost capacity caused by turbine down time.'' \554\ We 
describe the relevant parts of these rules in greater detail in the 
Legal Memorandum.
---------------------------------------------------------------------------

    \554\ 47 FR 3767, 3768 (Jan. 27, 1982).
---------------------------------------------------------------------------

    (7) Consistency with the purposes of the Clean Air Act.
    Interpreting the term ``system of emission reduction'' broadly to 
include building blocks 2 and 3 (so that the ``best system of emission 
reduction . . . adequately demonstrated'' may include those measures as 
long as they meet all of the applicable requirements) is also 
consistent with the purposes of the CAA. Most importantly, these 
purposes include protecting public health and welfare by 
comprehensively addressing air pollution, and, particularly, protecting 
against urgent and severe threats. In addition, these purposes include 
promoting pollution prevention measures, as well as the advancement of 
technology that reduces air pollution.
    (a) Purpose of protecting public health and welfare.
    The first provisions in the Clean Air Act set out the 
``Congressional findings and declaration of purpose.'' CAA section 101. 
CAA section 101(a)(2) states the finding that ``the growth in the 
amount and complexity of air pollution brought about by urbanization, 
industrial development, and the increasing use of motor vehicles, has 
resulted in mounting dangers to the public health and welfare.'' CAA 
section 101(a)(3) states the finding that ``air pollution prevention 
(that is, the reduction or elimination, through any measures, of the 
amount of pollutants produced or created at the source) and air 
pollution control at its source is the primary responsibility of States 
and local governments.'' CAA section 101(a) states the finding that 
``Federal financial assistance and leadership is essential for the 
development of cooperative Federal, State, regional, and local programs 
to prevent and control air pollution.''
    CAA section 101(b) next states ``[t]he purposes'' of the Clean Air 
Act. The first purpose is ``to protect and enhance the

[[Page 64774]]

quality of the Nation's air resources so as to promote the public 
health and welfare and the productive capacity of its population.'' CAA 
section 101(b)(1). The second is ``to initiate and accelerate a 
national research and development program to achieve the prevention and 
control of air pollution.'' CAA section 101(b)(2). The third is ``to 
provide technical and financial assistance to State and local 
governments in connection with the development and execution of their 
air pollution prevention and control programs.'' CAA section 101(b)(3). 
The fourth is ``to encourage and assist the development and operation 
of regional air pollution prevention and control programs.'' CAA 
section 101(c) adds that ``[a] primary goal of this Act is to encourage 
or otherwise promote reasonable Federal, State, and local governmental 
actions, consistent with the provisions of this Act, for pollution 
prevention.''
    As just quoted, these provisions are explicit that the purpose of 
the CAA is ``to protect and enhance the quality of the Nation's air 
resources so as to promote the public health and welfare and the 
productive capacity of its population.'' Moreover, Congress designed 
the CAA to be ``the comprehensive vehicle for protection of the 
Nation's health from air pollution'' \555\ and, in fact, designed CAA 
section 111(d) to address air pollutants not covered under other 
provisions, specifically so that ``there should be no gaps in control 
activities pertaining to stationary source emissions that pose any 
significant danger to public health or welfare.'' \556\ Furthermore, in 
these purpose provisions, Congress recognized that while pollution 
prevention and control are the primary responsibility of the States, 
``federal leadership'' would be essential.
---------------------------------------------------------------------------

    \555\ H.R. Rep. No. 95-294, at 42 (May 12, 1977), 1977 CAA 
Legis. Hist. at 2509 (discussing a provision in the House Committee 
bill that became CAA section 122, requiring the EPA to study and 
regulate radioactive air pollutants and three other air pollutants).
    \556\ S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 420 (discussing section 114 of the Senate Committee 
bill, which was the basis for CAA section 111(d)).
---------------------------------------------------------------------------

    At its core, Congress designed the CAA to address urgent and severe 
threats to public health and welfare. This purpose is evident 
throughout 1970 CAA Amendments, which authorized stringent remedies 
that were necessary to address those problems. By 1970, Congress viewed 
the air pollution problem, which had been worsening steadily as the 
nation continued to industrialize and as automobile travel dramatically 
increased after World War II,\557\ as nothing short of a national 
crisis.\558\ With the 1970 CAA Amendments, Congress enacted a stringent 
response, designed to match the severity of the problem. At the same 
time, Congress did not foreclose the EPA's ability to address new 
environmental concerns; in fact, Congress largely deferred to the EPA's 
expertise in identifying pollutants and sources that adversely affect 
public health or welfare. In doing so, Congress authorized the EPA to 
establish national ambient air quality standards for the most pervasive 
air pollutants--including the precursors for the choking smog that 
blanketed urban areas \559\--to protect public health with an ample 
margin of safety. Disappointed that the states had not taken effective 
action to that point to curb air pollution, ``Congress reacted by 
taking a stick to the States'' \560\ and including within the 1970 CAA 
Amendments both the requirement that the states develop plans to assure 
that their air quality areas would meet those standards by no later 
than five years, and the threat of imposition of federal requirements 
if the states did not timely adopt the requisite plans. Congress also 
required the EPA to establish standards for hazardous air pollutants 
that could result in shutting sources down. Congress added stringent 
controls on automobiles, overriding industry objections that the 
standards were not achievable. In addition, Congress added CAA section 
111(b), which required the EPA to list categories based on harm to 
public health and regulate new sources in those categories. Congress 
then designed CAA section 111(d) to assure, as the Senate Committee 
Report for the 1970 CAA Amendments noted, that ``there should be no 
gaps in control activities pertaining to stationary source emissions 
that pose any significant danger to public health or welfare.'' \561\
---------------------------------------------------------------------------

    \557\ See Dewey, Scott Hamilton, Don't Breathe the Air: Air 
Pollution and U.S. Environmental Politics, 1945-1970 (Texas A&M 
University Press 2000).
    \558\ 1970 was a significant year in environmental legislation, 
but it was also marked as ``a year of environmental concern.'' Sen. 
Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. 
at 223. By mid-1970, Congress recognized that ``[o]ver 200 million 
tons of contaminants [were] spilled into the air each year in 
America . . . . And each year these 200 million tons of pollutants 
endanger the health of [the American] people.'' Id. at 224. ``Cities 
up and down the east coast were living under clouds of smog and 
daily air pollution alerts.'' Sen. Muskie, S. Consideration of the 
Conference Rep. (Dec. 18, 1970), 1970 CAA Legis. Hist. at 124. Put 
simply, America faced an ``environmental crisis.'' Sen. Muskie, S. 
Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. at 224. 
The conference agreement, it was reported, ``faces the air pollution 
crisis with urgency and in candor. It makes hard choices, provides 
just remedies, requires stiff penalties.'' Sen. Muskie, S. 
Consideration of the Conference Rep. (Dec. 18, 1970), 1970 CAA 
Legis. Hist. at 123. ``[I]t represents [Congress'] best efforts to 
act with the knowledge available . . . in an affirmative but 
constructive manner.'' Id. at 150.
    \559\ See Dewey, Scott Hamilton, Don't Breathe the Air: Air 
Pollution and U.S. Environmental Politics, 1945-1970 (Texas A&M 
University Press 2000) at 230 (``By the mid-1960s, top federal 
officials showed an increasing sense of alarm regarding the health 
effects of polluted air. In June, 1966, Secretary of Health, 
Education, and Welfare John W. Gardner testified before the Muskie 
subcommittee: ``We believe that air pollution at concentrations 
which are routinely sustained in urban areas of the United States is 
a health hazard to many, if not all, people.'').
    \560\ Train v. NRDC, 421 U.S. 60, 64 (1975).
    \561\ S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 420 (discussing section 114 of the Senate Committee 
bill, which was the basis for CAA section 111(d)). Note that in the 
1977 CAA Amendments, the House Committee Report made a similar 
statement. H.R. Rep. No. 95-294, at 42 (May 12, 1977), 1977 CAA 
Legis. Hist. at 2509 (discussing a provision in the House Committee 
bill that became CAA section 122, requiring EPA to study and then 
take action to regulate radioactive air pollutants and three other 
air pollutants).
---------------------------------------------------------------------------

    Similarly, the 1977 and 1990 CAA Amendments were also designed to 
respond to new and/or pressing environmental issues. For example, in 
1977 then-EPA Administrator Costle testified before Congress that the 
expected increase in coal use (in response to various energy crises, 
including the 1973-74 Arab Oil Embargo) ``will make vigorous and 
effective control even more urgent.'' \562\ Similarly, by 1990, 
Congress recognized that ``many of the Nation's most important air 
pollution problems [had] failed to improve or [had] grown more 
serious.'' \563\ Indeed, President George H. W. Bush said that `` 
`progress has not come quickly enough and much remains to be done.' '' 
\564\
---------------------------------------------------------------------------

    \562\ Statement of Administrator Costle, Hearings before the 
Subcommittee on Energy Production and Supply of the Senate Committee 
on Energy and Natural Resources (Apr. 5, 7, May 25, June 24 and 30, 
1977), 1977 CAA Legis. Hist. at 3532 (discussing the relationship 
between the National Energy Plan and the Administration's proposed 
CAA amendments). Some of the specific changes to the CAA include the 
addition of the PSD program, visibility protections, requirements 
for nonattainment areas, and stratospheric ozone provisions.
    \563\ H.R. Rep. No. 101-490, at 144 (May 17, 1990).
    \564\ H.R. Rep. No. 101-490, at 144 (May 17, 1990). Some of the 
changes adopted in 1990 include revisions to the NAAQS nonattainment 
program, a more aggressive and substantially revised CAA section 
112, the new acid rain program, an operating permits program, and a 
program for phasing out of certain ozone depleting substances.
---------------------------------------------------------------------------

    Climate change has become the nation's most important environmental 
problem. We are now at a critical juncture to take meaningful action to 
curb the growth in CO2 emissions and forestall the impending 
consequences of prior inaction. CO2 emissions from existing 
fossil fuel-fired power plants

[[Page 64775]]

are by far the largest source of stationary source emissions. They emit 
almost three times as much CO2 as do the next nine 
stationary source categories combined, and approximately the same 
amount of CO2 emissions as all of the nation's mobile 
sources. The only controls available that can reduce CO2 
emissions from existing power plants in amounts commensurate with the 
problems they pose are the measures in building blocks 2 and 3, or far 
more expensive measures such as CCS.
    Thus, interpreting the ``system of emission reduction'' provisions 
in CAA section 111(d)(1) and (a)(1) to allow the nation to meaningfully 
address the urgent and severe public health and welfare threats that 
climate change pose is consistent with what the CAA was designed to 
do.\565\ This interpretation is also consistent with the cooperative 
purpose of section 111(d) to assure that the CAA comprehensively 
address those threats through the mechanism of state plans, where the 
states assume primary responsibility under federal leadership. See King 
v. Burwell, 576 U.S. (2015), No. 14-114 (2015), slip op. at 15 (``We 
cannot interpret federal statutes to negate their own stated purposes'' 
(quoting New York State Dept. of Social Servs. v. Dublino, 413 U.S. 
405, 419-20 (1973)); id. at 21 (``A fair reading of legislation demands 
a fair understanding of the legislative plan.'').\566\
---------------------------------------------------------------------------

    \565\ In addition, as we have noted, in designing the 1970 CAA 
Amendments, Congress was aware that carbon dioxide increased 
atmospheric temperatures. In 1970, when Congress learned that ``the 
carbon dioxide balance might result in the heating up of the 
atmosphere'' and that particulate matter ``might cause reduction in 
radiation,'' the Nixon Administration assured Congress that ``[w]hat 
we are trying to do, however, in terms of our air pollution effort 
should have a very salutary effect on either of these.'' Testimony 
of Charles Johnson, Jr., Administrator of the Consumer Protection 
and Environmental Health Service (Administration Testimony), Hearing 
of the House Subcommittee on Public Health and Welfare (Mar. 16, 
1970), 1970 CAA Legis. Hist. at 1381. Many years later, scientific 
consensus has formed around the particular causes and effects of 
climate change; and the tools put in place in 1970 can be read 
fairly to address these concerns.
    \566\ This final rule is also consistent with the CAA's purpose 
of protecting health and welfare. For example, the CAA authorizes 
the EPA to regulate air pollutants as soon as the EPA can determine 
that those pollutants pose a risk of harm, and not to wait until the 
EPA can prove that those pollutants actually cause harm. See H.R. 
Rep. No. 95-294, at 49 (May 12, 1977), 1977 CAA Legis. Hist. at 2516 
(describing the CAA as being designed . . . to assure that 
regulatory action can effectively prevent harm before it occurs; to 
emphasize the predominant value of protection of public health''). 
The protective spirit of the CAA extends to the present rule, in 
which the EPA regulates on the basis of building blocks 2 and 3 
because the range of available and cost-effective measures in those 
building blocks achieves more pollution reduction than building 
block 1 alone. Indeed, add-on controls that are technically capable 
of reducing CO2 emissions at the scale necessitated by 
the severity of the environmental risk--for example, CCS 
technology--are not as cost-effective as building blocks 2 and 3 on 
an industry-wide basis, and while the costs of the add-on controls 
can be expected to be reduced over time, it is not consonant with 
the protective spirit of the CAA to wait.
---------------------------------------------------------------------------

    (b) Purpose of encouraging pollution prevention.
    Interpreting ``system of emission reduction'' to include building 
blocks 2 and 3 is also consistent with the CAA's purpose to encourage 
pollution prevention. CAA section 101(c) states that ``[a] primary goal 
of [the CAA] is to encourage or otherwise promote reasonable federal, 
state, and local governmental actions, consistent with the provisions 
of this chapter, for pollution prevention.'' Indeed, in the U.S. Code, 
in which the CAA is codified as chapter 85, the CAA is entitled, ``Air 
Pollution Prevention and Control.'' \567\ CAA section 101(a)(3) 
describes ``air pollution prevention'' as ``the reduction or 
elimination, through any measures, of the amount of pollutants produced 
or created at the source''. (Emphasis added.) The reference to ``any 
measures'' highlights the breadth of what Congress considered to be 
pollution prevention, that is, any and all measures that reduce or 
eliminate pollutants at the source.\568\
---------------------------------------------------------------------------

    \567\ See Air Quality Act of 1967, Pub. L. 90-148, Sec.  2, 81 
Stat. 485 (Nov. 21, 1967) (adding ``Title I--Air Pollution 
Prevention and Control'' to the CAA, along with Congress' initial 
findings and purposes under CAA section 101).
    \568\ Section 101 emphasizes the importance of air pollution 
prevention in two other provisions: CAA section 101(b)(4) states 
that one of ``the purposes of [title I of the CAA, which includes 
section 111] are . . . (b) to encourage and assist the development 
and operation of regional air pollution prevention and control 
programs.'' CAA section 101(a)(3) adds: ``The Congress finds--. . . 
(3) that air pollution prevention . . . and air pollution control at 
its source is the primary responsibility of states and local 
governments.'' In fact, section 101 mentions pollution prevention no 
less than 6 times.
---------------------------------------------------------------------------

    The measures in building blocks 2 and 3 qualify as ``pollution 
prevention'' measures because they are ``any measures'' that ``reduc[e] 
or eliminate[e] . . . the amount of pollutants produced or created at 
the [fossil fuel-fired affected] source[s].'' Thus, consistent with the 
CAA's primary goals, it is therefore reasonable to interpret a ``system 
of emission reduction,'' as including the pollution prevention measures 
in building blocks 2 and 3.
    (c) Purpose of advancing technology to control air pollution.
    This final rule is also consistent with CAA section 111's purpose 
of promoting the advancement of pollution control technology based on 
the expectation that American industry will be able to develop 
innovative solutions to the environmental problems.
    The legislative history and case law of CAA section 111 identify 
three different ways that Congress designed CAA section 111 to 
authorize standards of performance that promote technological 
improvement: (i) The development of technology that may be treated as 
the ``best system of emission reduction . . . adequately 
demonstrated;'' under CAA section 111(a)(1); \569\ (ii) the expanded 
use of the best demonstrated technology; \570\ and (iii) the 
development of emerging technology.\571\ This rule is consistent with 
the second of those ways--it expands the use of the measures in 
building blocks 2 and 3, which are already established and provide 
substantial reductions at reasonable cost. As discussed below, the use 
of the measures in these building blocks will be most fully expanded 
when organized markets develop, and our expectation that those markets 
will develop is consistent with the Congress's view, just described, 
that CAA section 111 should promote technological innovation.
---------------------------------------------------------------------------

    \569\ See Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 
391 (D.C. Cir. 1973) (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'').
    \570\ See S. Rep. 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'').
    \571\ See Sierra Club v. Costle, 657 F.2d at 351 (upholding a 
standard of performance designed to promote the use of an emerging 
technology).
---------------------------------------------------------------------------

    This final rule is also consistent with Congress's overall view 
that the CAA Amendments as a whole were designed to promote 
technological innovation. In enacting the CAA, Congress articulated its 
expectation that American industry would be creative and come up with 
innovative solutions to the urgent and severe problem of air pollution. 
This is manifest in the well-recognized technology-forcing nature of 
the CAA, and was expressed in numerous, sometimes ringing, statements 
in the legislative history about the belief that American industry will 
be able to develop the needed technology. For example, in the 1970 
floor debates, Congress recalled that the nation had put a man on the 
moon a year before and had won World War II a quarter century earlier, 
and attributed much of the credit for those singular achievements to 
American industry and its ability to be productive and innovative. 
Congress expressed confidence that American industry

[[Page 64776]]

could meet the challenges of developing air pollution controls as 
well.\572\
---------------------------------------------------------------------------

    \572\ Sen. Muskie, S. Debates on S. 4358 (Sept. 21, 1970), 1970 
CAA Legis. Hist. at 227 (``At the beginning of World War II industry 
told President Roosevelt that his goal of 100,000 planes each year 
could not be met. The goal was met, and the war was won. And in 
1960, President Kennedy said that America would land a man on the 
moon by 1970. And American industry did what had to be done. Our 
responsibility in Congress is to say that the requirements of this 
bill are what the health of the Nation requires, and to challenge 
polluters to meet them.''). See Blaime, A.J., The Arsenal of 
Democracy: FDR, Detroit, and an Epic Quest to Arm an America at War 
(Houghton Mifflin Harcourt 2014); Carew, Michael G., Becoming the 
Arsenal: The American Industrial Mobilization for World War II, 
1938-1942 (University Press of America, Inc. 2010).
---------------------------------------------------------------------------

    (d) Response to commenters concerning purpose.
    Commenters have stated that the proposed rule ``would transform CAA 
section 111 into something untethered to its statutory language and 
unrecognizable to the Congress that created it.'' \573\ Commenters with 
this line of comments focused on the ramifications of building block 4, 
which the EPA has decided does not belong in BSER using EPA's 
historical interpretation of BSER. Regardless of whether the comments 
are accurate with respect to building block 4 measures, they are 
certainly not accurate with respect to the three building blocks that 
the EPA is defining as the BSER. This rule would be recognizable to the 
Congresses that created and amended CAA section 111 and is carefully 
fashioned to the statutory text in CAA section 111(d) and (a)(1). This 
final rule would be recognizable to the Congress that adopted CAA 
section 111 in 1970 as part of a bold, far-reaching law designed to 
address comprehensively an air pollution crisis that threatened the 
health of millions of Americans; to have EPA and the States work 
cooperatively to develop state-specific approaches to address a 
national problem; to challenge industry to meet that crisis with 
creative energy; and to give the EPA broad authority--under section 111 
and other provisions--to craft the needed emission limitations. This 
final rule would be recognizable to the Congress that revised CAA 
section 111 in 1977 to explicitly authorize that standards be based on 
actions taken by third parties (fuel cleaners). And this final rule 
would be recognizable to the Congress that revised CAA section 111 in 
1990 to be linked to the Acid Rain Program that Congress adopted at the 
same time, which regulated the same industry (fossil fuel-fired EGUs) 
through some of the same measures (generation shifts and RE), and that 
explicitly acknowledged that those measures (RE) would also reduce 
CO2 and thereby address the dangers of climate change. To 
reiterate, for the reasons explained in this preamble, this rule is 
grounded in our reasonable interpretation of CAA section 111(d) and 
(a)(1).
---------------------------------------------------------------------------

    \573\ UARG comment at 31. See id. at 18, 29, 49. This comment 
appears to be a reference to the Supreme Court's statement in UARG. 
See Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2444 (2014).
---------------------------------------------------------------------------

    (8) Constraints on the BSER--treatment of building block 4 and 
response to comments concerning precedents.
    Although the BSER provisions are sufficiently broad to include, for 
affected EGUs, the measures in building blocks 2 and 3, they also 
incorporate significant constraints on the types of measures that may 
be included in the BSER. We discuss those constraints in this section. 
These constaints explain why we are not including building block 4 in 
the BSER. In addition, these constraints explain why our reliance on 
building blocks 2 and 3 will have limited precedential effect for other 
rulemakings, and serve as our basis for responding to commenters who 
expressed concern that reliance on building blocks 2 and 3 would set a 
precedent for the EPA to rely on similar measures in promulgating 
future air pollution controls for other sectors.\574\
---------------------------------------------------------------------------

    \574\ Commenters offered hypothetical examples to illustrate 
their concerns over precedential effects, discussed below. Some 
commenters objected that our proposed interpretation of the BSER 
failed to include limiting principles. In the Legal Memorandum, we 
note that the statutory constraints discussed in this section of the 
preamble constitute limits on the type of the BSER that the EPA is 
authorized to determine.
---------------------------------------------------------------------------

    As discussed above, the emission limits in the CAA section 111(d) 
emission guidelines that this rule promulgates are based on the EPA's 
determination, for the affected EGUs, of the ``system of emission 
reduction'' that is the ``best,'' taking into account ``cost'' and 
other factors, and that is ``adequately demonstrated.'' Those 
components include certain interpretations and applications and provide 
constraints on the types of measures or controls that the EPA may 
determine to include in the BSER.
    (a) Emission reductions from affected sources.
    The first constraint is that the BSER must assure emission 
reductions from the affected sources. Under section 111(d)(1), the 
states must submit state plans that ``establish[] standards of 
performance for any existing source,'' and, under section 111(a)(1) and 
the EPA's implementing regulations, those standards are informed by the 
EPA's determination of the best system of emission reduction adequately 
demonstrated. Because the emission standards must apply to the affected 
sources, actions taken by affected sources that do not result in 
emission reductions from the affected sources--for example, offsets 
(e.g., the planting of forests to sequester CO2)--do not 
qualify for inclusion in the BSER. Building blocks 2 and 3 achieve 
emission reductions from the affected EGUs, and thus are not precluded 
under this constraint.
    (b) Controls or measures that affected EGUs can implement.
    The second constraint is that because the affected EGUs must be 
able to achieve their emission performance rates through the 
application of the BSER, the BSER must be controls or measures that the 
EGUs themselves can implement. Moreover, as noted, the D.C. Circuit has 
established criteria for achievability in the section 111(b) case law; 
e.g., sources must be able to achieve their standards under a range of 
circumstances. If those criteria are applicable in a section 111(d) 
rule, the BSER must be of a type that allows sources to meet those 
achievability criteria. As noted, under this rule, affected EGUs can 
achieve their emission performance rates in the various circumstances 
under which they operate, through the application of the building 
blocks.
    (c) ``Adequately demonstrated.''
    The third constraint is that the system of emission reduction that 
the EPA determines to be the best must be ``adequately demonstrated.'' 
To qualify as the BSER, controls and measures must align with the 
nature of the regulated industry and the nature of the pollutant so 
that implementation of those controls or measures will result in 
emission reductions from the industry and allow the sources to achieve 
their emission performance standards. The history of the effectiveness 
of the controls or other measures, or other indications of their 
effectiveness, are important in determining whether they are adequately 
demonstrated.
    More specifically, the application of building blocks 2 and 3 to 
affected EGUs has a number of unique characteristics. Building blocks 2 
and 3 entail the production of the same amount of the same product--
electricity, a fungible product that can be produced using a variety of 
highly substitutable generation processes--through the cleaner (that 
is, less CO2-intensive) processes of shifting dispatch from 
steam generators to existing NGCC units, and from both steam generators 
and NGCC units to renewable generators.

[[Page 64777]]

    The physical properties of electricity and the highly integrated 
nature of the electricity system allow the use of these cleaner 
processes to generate the same amount of electricity. In addition, the 
electricity sector is primarily domestic--little electricity is 
exported outside the U.S.--and there is low capacity for storage. In 
addition, the electricity sector is highly regulated, planned, and 
coordinated. As a result, holding demand constant, an increase in one 
type of generation will result in a decrease in another type of 
generation. Moreover, the higher-emitting generators, which are fossil 
fuel-fired, have higher variable costs than renewable generators, so 
that increased renewable generation will generally back out fossil 
fuel-fired generation.
    Because of these characteristics, the electricity sector has a long 
and well-established history of substituting one type of generation for 
another. This has occurred for a wide variety of reasons, many of which 
are directly related to the system's primary purposes and functions, as 
well as for environmental reasons. As a result, at present, there is a 
well-established network of business and operational relationships and 
past practices that supports building blocks 2 and 3. As noted 
elsewhere, a large segment of steam generators already have business 
relationships with existing NGCC units, and a large segment of all 
fossil fuel-fired EGUs already own, co-own, or have invested in RE.
    Many of these characteristics are unique to the utility power 
sector. Moreover, this complex of characteristics, ranging from the 
physical properties of electricity and the integrated nature of the 
grid to the institutional mechanisms that assure reliability and the 
existing practices and business relationships in the industry, combine 
to facilitate the implementation of building blocks 2 and 3 in a 
uniquely efficient manner. This supports basing the emission limits on 
the ability of owners and operators of fossil fuel-fired EGUs to 
replace their generation with cleaner generation in other locations, 
sometimes owned by other entities.
    As noted above, commenters offered hypothetical examples to 
illustrate their concerns over precedential effects. Most of their 
concerns focused on building block 4, and most of their hypothetical 
examples concerned reductions in demand for various types of products. 
We address these concerns in the response to comments document, but we 
note here that, in any event, these concerns are mooted because we are 
not finalizing building block 4. Some commenters offered hypothetical 
examples for building blocks 2 and 3 as well. For example, some 
commenters asserted that the EPA could ``develop standards of 
performance for tailpipe emissions from motor vehicles'' by ``requiring 
car owners to shift some of their travel to buses,'' which the 
commenters considered analogous to building block 2; or by ``requiring 
there to be more electric vehicle purchases,'' which the commenters 
considered analogous to building block 3.\575\
---------------------------------------------------------------------------

    \575\ UARG comment at 2-3.
---------------------------------------------------------------------------

    Commenters' concerns over precedential impact cannot be taken to 
mean that the building blocks should not be considered to meet the 
requirements of the BSER or that the affected EGUs cannot be considered 
to meet the emission limits by implementing those measures. Moreover, 
because many of these individual characteristics, and their inherent 
complexity, are unique to the utility power sector, building blocks 2 
and 3 as applied to fossil fuel-fired EGUs will have a limited 
precedent for other industries and other types of rulemakings. For 
example, the commenter's hypothetical examples noted above are 
inapposite for several reasons. The hypotheticals appear to be premised 
on government action mandating actions not implementable by emitting 
sources (e.g., that a government would ``require[e] car owners to shift 
some of their travel to buses, or . . . require[e] there to be more 
electric vehicle purchases''), whereas the measures in building blocks 
2 and 3 can be implemented by the affected EGUs. Nor have commenters 
attempted to address how car owners shifting travel to buses or 
purchasing more electric vehicles could be translated into lower 
tailpipe standards for motor vehicles.\576\
---------------------------------------------------------------------------

    \576\ In any event, it is questionable whether measures such as 
those hypothesized by the commenters would be consistent with the 
provisions of Title II.
---------------------------------------------------------------------------

    (d) ``Best'' in light of ``cost . . . nonair quality health and 
environmental impact and energy requirements'' and EPA's past practice 
and current policy.
    The fourth constraint, or set of constraints, is that the system of 
emission reduction must be the ``best,'' ``taking into account the cost 
of achieving such reduction and any nonair quality health and 
environmental impact and energy requirements.'' As noted, in light of 
the D.C. Circuit case law, the EPA has considered cost and energy 
factors on both an individual source basis and on the basis of the 
nationwide electricity sector. In determining what is ``best,'' the EPA 
has broad discretion to balance the enumerated factors.\577\ In 
interpreting and applying these provisions in this rulemaking to 
regulate CO2 emissions from affected EGUs under section 
111(d), we are acting consistently with our past practice for applying 
these provisions in previous section 111 rulemakings and for regulating 
air pollutants from the electricity sector under other provisions of 
the CAA, as well as current policy.
---------------------------------------------------------------------------

    \577\ See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999).
---------------------------------------------------------------------------

    The great majority of our regulations under section 111 have been 
111(b) regulations for new sources. As discussed in the Legal 
Memorandum and briefly below, the BSER identified under section 111(b) 
is designed to assure that affected sources are well controlled at the 
time of construction, and that approach is consistent with the design 
expressed in the legislative history for the 1970 CAA Amendments that 
enacted the provision.
    Traditionally, CAA section 111 standards have been rate-based, 
allowing as much overall production of a particular good as is desired, 
provided that it is produced through an appropriately clean (or low-
emitting) process. CAA section 111 performance standards have primarily 
targeted the means of production in an industry and not consumers' 
demand for the product. Thus, the focus for the BSER has been on how to 
most cleanly produce a good, not on limiting how much of the good can 
be produced.
    One example of the focus under section 111 on clean production, not 
limitation of product is provided by the revised new source performance 
standards for electric utility steam generating units that we 
promulgated in 1979 following the 1977 CAA Amendments to limit 
emissions of SO2, PM, and NOX. In relevant part, 
the revised standards limited SO2 emissions to 1.20 lb/
million BTU heat input and imposed a 90 percent reduction in potential 
SO2 emissions. This was based on the application of flue gas 
desulfurization (FGD) together with coal preparation techniques. In the 
preamble, we explain that ``[t]he intent of the final standards is to 
encourage power plant owners and operators to install the best 
available FGD systems and to implement effective operation and 
maintenance procedures but not to create power supply disruptions.'' 
578 579

[[Page 64778]]

EPA has taken the same overall approach in its section 111(d) 
rules,\580\ including the CAMR rule noted below.
---------------------------------------------------------------------------

    \578\ See, e.g., 44 FR 33580, at 33599 (June 11, 1979). In this 
rulemaking, the EPA recognized the ability of the integrated grid to 
minimize power disruptions: ``When electric load is shifted from a 
new steam-electric generating unit to another electric generating 
unit, there would be no net change in reserves within the power 
system. Thus, the emergency condition provisions prevent a failed 
FGD system from impacting upon the utility company's ability to 
generate electric power and prevents an impact upon reserves needed 
by the power system to maintain reliable electric service.'' Id.
    \579\ The EPA's 1982 revised new source performance standards 
for certain stationary gas turbines provide another example of a 
rulemaking that focused controls on reducing emissions, as well as 
reliance on the integrated grid to avoid power disruptions. 44 FR 
33580 (June 11, 1979). In response to comments that requested a 
NOX emission limit exemption for base load utility gas 
turbines, the EPA explained that ``for utility turbines . . . since 
other electric generators on the grid can restore lost capacity 
caused by turbine down time'' the NOX emission limit of 
1150 ppm for such turbines would not be rescinded. 44 FR 33580, at 
33597-98.
    \580\ 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).
---------------------------------------------------------------------------

    Similarly, in a series of rulemakings regulating air pollutants 
from EGUs under several provisions of the CAA, we have focused our 
efforts on assuring that electricity is generated through cleaner or 
lower-emitting processes, and we have not sought to limit the aggregate 
amount of electricity that is generated. We describe those rules in 
section II, elsewhere in this section V.B.3., and in the Legal 
Memorandum.
    For example, as discussed in the Legal Memorandum, in the three 
transport rules promulgated under CAA section 110(a)(2)(D)(i)(I)--the 
NOX SIP Call, CAIR, and CSAPR--which regulated precursors to 
ozone-smog and particulate matter, the EPA based certain aspects of the 
regulatory requirements on the fact that fossil fuel-fired EGUs could 
shift generation to lower-emitting sources. In CAMR, the 2005 
rulemaking under section 111(d) regulating mercury emissions from coal-
fired EGUs, the EPA based the first phase of control requirements on 
the actions the affected EGUs were required to take under CAIR, 
including shifting generation to lower-emitting sources. In addition, 
as also discussed in the Legal Memorandum, in the EPA's 2012 MATS rule 
regulating mercury from coal-fired EGUs under section 112, at 
industry's urging, the EPA allowed compliance deadlines to be extended 
for coal-fired EGUs that desired to substitute replacement power of any 
type, including NGCC units or RE, for compliance purposes.
    While these and other rulemakings for fossil fuel-fired EGUs took 
different approaches towards lower-emitting generation and renewable 
generation, they all were based on control measures that reduced 
emissions without reducing aggregate levels of electricity generation. 
It should be noted that even though some of those rules established 
overall emission limits in the form of budgets implemented through a 
cap-and-trade program, the EPA recognized that the fossil fuel-fired 
EGUs that were subject to the rules could comply by shifting generation 
to lower-emitting EGUs, including relying on RE. In this manner, the 
rules limited emissions but on the basis that the industry could 
implement lower-emitting processes, and not based on reductions in 
overall generation.
    We are applying the same approach to this rulemaking. Our basis for 
this rulemaking is that affected EGUs can implement a system of 
emission reduction that will reduce the amount of their emissions 
without reducing overall electricity generation. This approach takes 
into account costs by minimizing economic disruption as well as the 
nation's energy requirements by avoiding the need for environmental-
based reductions in the aggregate amount of electricity available to 
the consumer, commercial, and industrial sectors.
    This approach is a reasonable exercise of the EPA's discretion 
under section 111, consistent with the U.S. Supreme Court's statements 
in its 2011 decision, American Electric Power Co. v. Connecticut, that 
the CAA and the EPA actions it authorizes displace any federal common 
law right to seek abatement of CO2 emissions from fossil-
fuel fired power plants. There, the Court emphasized that CAA section 
111 authorizes the EPA--which the Court identified as the ``expert 
agency''--to regulate CO2 emissions from fossil fuel-fired 
power plants based an ``informed assessment of competing interests . . 
. . Along with the environmental benefit potentially achievable, our 
Nation's energy needs and the possibility of economic disruption must 
weigh in the balance.'' \581\
---------------------------------------------------------------------------

    \581\ American Electric Power Co. v. Connecticut, 131 S. Ct. 
2527, 2539-40 (2011).
---------------------------------------------------------------------------

    Similarly, the D.C. Circuit, in a 1981 decision upholding the EPA's 
section 111(b) standards for air pollutants from fossil fuel-fired 
EGUs, stated that section 111 regulations concerning the electric power 
sector ``demand a careful weighing of cost, environmental, and energy 
considerations.'' \582\ This exercise of policy discretion is 
consistent with Congress's expectation that the Administrator ``should 
determine the achievable limits'' \583\ and ``would establish 
guidelines as to what the best system for each such category of 
existing sources is.'' \584\ As the D.C. Circuit explained, ``[i]t 
seems likely that if Congress meant . . . to curtail EPA's discretion 
to weigh various policy considerations it would have explicitly said so 
in section 111, as it did in other parts of the statute.'' \585\
---------------------------------------------------------------------------

    \582\ Sierra Club v. EPA, 657 F.2d 298, 406 (D.C. Cir. 1981). 
Id. at 406 n. 526.
    \583\ S. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 415-16 (explaining that the ``[Administrator] should 
determine the achievable limits and let the owner or operator 
determine the most economic, acceptable technique to apply.'').
    \584\ H.R. Rep. No. 95-294, at 195 (May 12, 1977).
    \585\ Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981).
---------------------------------------------------------------------------

    Our interpretation that CAA section 111 targets supply-side 
activities that allow continued production of a product through use of 
a cleaner process, rather than targeting consumer-oriented behavior, 
also furthers Congress' intent of promoting cleaner production measures 
``to protect and enhance the quality of the Nation's air resources so 
as to promote the public health and welfare and the productive capacity 
of its population.'' \586\ This principle is also consistent with 
promoting ``reasonable . . . governmental actions . . . for pollution 
prevention.'' \587\
---------------------------------------------------------------------------

    \586\ CAA section 101(b)(1).
    \587\ CAA section 101(c).
---------------------------------------------------------------------------

    In this rule, we are applying that same approach in interpreting 
the BSER provisions of section 111. That is, we are basing the 
regulatory requirements on measures the affected EGUs can implement to 
assure that electricity is generated with lower emissions, taking into 
account the integrated nature of the industry and current industry 
practices. Building blocks 1, 2 and 3 fall squarely within this 
paradigm; they do not require reductions in the total amount of 
electricity produced.
    We recognize that commenters have raised extensive legal concerns 
about building block 4. We recognize that building block 4 is different 
from building blocks 1, 2, and 3 and the pollution control measures 
that we have considered under CAA section 111. Accordingly, under our 
interpretation of section 111, informed by our past practice and 
current policy, today's final action excludes building block 4 from the 
BSER. Building block 4 is outside our paradigm for section 111 as it 
targets

[[Page 64779]]

consumer-oriented behavior and demand for the good, which would reduce 
the amount of electricity to be produced.
    Although numerous commenters urged us to include demand-side EE 
measures as part of the BSER, as we had proposed to do, we conclude 
that we cannot do so under our historical practice, current policy, and 
current approach to interpreting section 111 as well as our historical 
practice in regulating the electricity sector under other CAA 
provisions. While building blocks 2 and 3 are rooted in our past 
practice and policy, building block 4 is not and would require a change 
(which we are not making) in our interpretation and implementation and 
application of CAA section 111.
    Excluding demand-side EE measures from the BSER has the benefit of 
allaying legal and other concerns raised by commenters, including 
concerns that individuals could be ``swept into'' the regulatory 
process by imposing requirements on ``every household in the land.'' 
\588\ While building block 4 could have been implemented without 
imposing requirements on individual households, this final rule 
resolves any doubt on this matter and is not based on the inclusion of 
demand-side EE as part of the BSER.
---------------------------------------------------------------------------

    \588\ See Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2436 
(2014).
---------------------------------------------------------------------------

    By the same token, we are not finalizing reduced generation of 
electricity overall as the BSER. Instead, components of the BSER focus 
on shifting generation to lower- or zero-emitting processes for 
producing electricity.\589\
---------------------------------------------------------------------------

    \589\ As discussed below, however, reduced generation remains 
important to this rule in that it is one of the methods for 
implementing the building blocks.
---------------------------------------------------------------------------

    (e) Constraints for new sources.
    For new sources, practical and policy concerns support the 
interpretation of basing the BSER on controls that new sources can 
install at the time of construction, so that they will be well-
controlled throughout their long useful lives. This approach is 
consistent with the legislative history. We discuss this at greater 
length in the Legal Memorandum.
4. Relationship Between a Source's Implementation of Building Blocks 2 
and 3 and Its Emissions
    In this section, we discuss the relationship between an affected 
EGU's implementation of the measures in building blocks 2 and 3 and 
that affected EGU's own generation and emissions. As discussed above, 
an affected EGU subject to a CAA section 111(d) state plan that imposes 
an emission rate-based standard may achieve that standard in part by 
implementing the measures in building block 2 (for a steam generator) 
and building block 3 (for a steam generator or combustion turbine). 
That is, an affected EGU may invest in low- or zero-emitting generation 
and may apply credits from that generation against its emission rate. 
Those credits reduce the affected EGU's emission rate and thereby help 
it to achieve its emission limit.
    In addition, the additional low- or zero-emitting generation that 
results from the affected EGU's investment will generally displace 
higher-emitting generation. This is because, as described above, 
higher-emitting generation generally has higher variable costs, 
reflecting its fuel costs, than, at least, zero-emitting generation. 
Displacement of higher-emitting generation will lower overall 
CO2 emissions from the source category of affected EGUs.
    If an affected EGU implements building block 2 or 3 by reducing its 
own generation, it will reduce its own emissions. However, the affected 
EGU may also or alternatively choose to implement building block 2 or 3 
by investing in lower- or zero-emitting generation that does not, in 
and of itself, reduce the amount of its own generation or emissions. 
Even so, implementation of building blocks 2 and 3 will reduce 
CO2 from some affected EGUs, and therefore reduce 
CO2 on a source category-wide basis.
    This outcome is, however, consistent with the requirements of CAA 
section 111(d)(1) and (a)(1). To reiterate, CAA section 111(d)(1) 
requires that ``any existing source'' have a ``standard of 
performance,'' defined under CAA section 111(a)(1) 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 [BSER] . . . .'' These 
provisions require by their terms that ``any existing source'' must 
have a ``standard of performance,'' but nothing in these provisions 
requires a particular amount--or, for that matter, any amount--of 
emission reductions from each and every existing source. That the 
``standard of performance'' is defined on the basis of the ``degree of 
emission limitation achievable through the application of the [BSER]'' 
does not mean that each affected EGU must achieve some amount of 
emission reduction, for the following reasons.
    The cornerstone of the definition of the term ``standard of 
performance'' is the BSER. In determining the BSER, the EPA must 
consider the amount of emission reduction that the system may achieve, 
and must consider the ability of the affected EGUs to achieve the 
emission limits that result from the application of the BSER. The EPA 
is authorized to include in the BSER, for this source category, the 
measures in building blocks 2 and 3 because, when applied to the source 
category, these measures result in emission standards that may be 
structured to ensure overall emission reductions from the source 
category and remain achievable by the affected EGUs. This remains so 
regardless of whether the ``degree of emission limitation achievable 
through the application of the [BSER]'' by any particular source 
results in actual emission reductions from that source.
    The application of the building blocks has an impact that is 
similar to that of an emissions trading program, under which, overall, 
the affected sources reduce emissions, but any particular source does 
not need to reduce its emissions and, in fact, may increase its 
emissions, as long as it purchases sufficient credits or allowances 
from other sources. In fact, we expect that many states will carry out 
their obligations under this rule by imposing standards of performance 
that incorporate trading or other multi-entity generation-replacement 
strategies. Indeed, any emission rate-based standard may not 
necessarily result in emission reductions from any particular affected 
source (or even all of the affected sources in the category) as a 
result of the ability of the particular source (or even all of them) to 
increase its production and, therefore, its emissions, even while 
maintaining the required emission rate.
5. Reduced Generation and Implementation of the BSER
    In the proposed rulemaking, we described the BSER as the measures 
included in building block 1 as well the set of measures included in 
building blocks 2, 3 and 4 or, in the alternative, reduced generation 
or utilization by the affected EGUs in the amount of building blocks 2, 
3 and 4. In this final rule, based on the comments and further 
evaluation, we are refining our approach to the BSER. Specifically, we 
are determining the BSER as the combination of measures included in 
building blocks 1, 2, and 3.Building blocks 2 and 3 entail substitution 
of lower-emitting generation for higher-emitting generation, which 
ensures that aggregate production levels can continue to meet demand 
even where an individual affected EGU decreases its

[[Page 64780]]

own output to reduce emissions. The amount of generation from the 
increased utilization of existing NGCC units determines a portion of 
the amount of reduced generation that affected fossil fuel-fired steam 
EGUs could undertake to achieve building block 2, and the amount of 
generation from the use of expanded lower- or zero-emitting generating 
capacity that could be provided, determines a portion of the amount of 
reduced generation that affected fossil fuel-fired steam EGUs, as well 
as the entire amount of reduced generation that affected NGCC units 
could undertake to implement building blocks 2 and 3. This section 
discusses the reasons that reduced generation is one of the set of 
reasonable and well-established actions that an affected EGU can 
implement to achieve its emission limits. We are not finalizing our 
proposal that reduced overall generation of electricity may by itself 
be considered the BSER, for the reason that reduced generation by 
itself does not fit within our historical and current interpretation of 
the BSER. Specifically, reduced generation by itself is about changing 
the amount of product produced rather than producing the same product 
with a process that has fewer emissions.
    a. Background. As noted, for both rate-based and mass-based state 
plans, affected EGUs may take a set of actions to comply with their 
emission standards. An affected EGU may comply with an emission rate-
based standard (e.g., a limit on the amount of CO2 per MWh) 
by acquiring, through one means or another, credits from lower- or 
zero-emitting generation (building blocks 2 or 3) to reduce its 
emission rate for compliance purposes. In addition, the affected EGU 
may reduce its generation, and if it does so, it then needs to acquire 
fewer of those credits to meet its emission rate.\590\ Under these 
circumstances, the affected EGU would in effect replace part of its 
higher-emitting generation with lower- or zero-emitting generation. On 
the other hand, an affected EGU that is subject to a mass-based 
standard--for example, a requirement to hold enough allowances to cover 
its emissions (e.g., one allowance for each ton of emissions in any 
year)--may comply at least in part by reducing its generation and, 
thus, its emissions. Therefore, one type of action that an affected EGU 
may take to achieve either of these emission limits is to reduce its 
generation. Further, reduced generation by individual sources offers a 
pathway to compliance in and of itself. That is, a state may adopt a 
mass-based goal, assign mass-based standards to its sources, and those 
sources may comply with their mass-based limits by, in addition to 
implementing building block 1 measures, reducing their generation in 
the appropriate amounts, and without taking any other actions.
---------------------------------------------------------------------------

    \590\ An affected EGU that is subject to an emission rate, e.g., 
pounds of CO2 per MWh generated, cannot achieve that rate 
simply by reducing its generation (unless it shuts down, in which 
case it would achieve a zero emission rate). This is because 
although reducing generation results in fewer emissions, it does 
not, by itself, result in fewer emissions per MWh generated.
---------------------------------------------------------------------------

    b. Well-established use of reduced generation to comply with 
environmental requirements. Reduced generation is a well-established 
method for individual fossil fuel-fired power plants to comply with 
their emission limits.
    Reduced generation in the amounts contemplated in this rule, as 
undertaken by individual sources to achieve their emission limits, 
reduces emissions from the affected sources, but because of the 
integrated and interconnected nature of the power sector, can be 
accommodated without significant cost or disruption. The electric 
transmission grid interconnects the nation's generation resources over 
large regions. Electric system operators coordinate, control, and 
monitor the electric transmission grid to ensure cost-effective and 
reliable delivery of power. These system operators continuously balance 
electricity supply and demand, ensuring that needed generation and/or 
demand resources are available to meet electricity demand. Diverse 
resources generate electricity that is transmitted and distributed 
through a complex system of interconnected components to end-use 
consumers.
    The electricity system was designed to meet these core functions. 
The three components of the electricity supply system--generation, 
transmission and distribution--coordinate to deliver electricity from 
the point of generation to the point of consumption. This 
interconnectedness is a fundamental aspect of the nation's electricity 
system, requiring a complicated integration of all components of the 
system to balance supply and demand and a federal, state and local 
regulatory network to oversee the physically interconnected network. 
Electricity from a diverse set of generation resources such as natural 
gas, nuclear, coal and renewables is distributed over high-voltage 
transmission lines. The system is planned and operated to ensure that 
there are adequate resources to meet electricity demand plus additional 
available capacity over and above the capacity needed to meet normal 
peak demand levels. System operators have a number of resources 
potentially available to meet electricity demand, including electricity 
generated by electric generation units of various types as well as 
demand-side resources. Importantly, if generation is reduced from one 
generator, safeguards are in place to ensure that adequate supply is 
still available to meet demand. We describe these safeguards in the 
background section of this preamble.
    Both Congress and the EPA have recognized reduced generation as one 
of the measures that fossil fuel-fired EGUs may implement to reduce 
their emissions of air pollutants and thereby achieve emission limits. 
Congress, in enacting the allowance requirements in CAA Title IV, under 
which fossil fuel-fired EGUs must hold an allowance for each ton of 
SO2 emitted, explicitly recognized that fossil fuel-fired 
EGUs could meet this requirement by reducing their generation. In fact, 
Congress anticipated that fossil fuel-fired EGUs may choose to comply 
with the SO2 emission limits by reducing utilization, and 
included provisions that specifically addressed reduced utilization. 
For example, CAA section 408(c)(1)(B) includes requirements for an 
owner or operator of an EGU that meets the Phase 1 SO2 
reduction obligations and the NOX reduction obligations ``by 
reducing utilization of the unit as compared with its baseline or by 
shutting down the unit.''
    The EPA has also recognized in several rulemakings limiting 
emissions from fossil fuel-fired EGUs that reduced generation is one of 
the methods of emission reduction that an EGU was expected to rely on 
to achieve its emission limitations. Examples include rulemakings to 
impose requirements that sources implement BART to reduce their 
emissions of air pollutants that cause or contribute to visibility 
impairment. As explained earlier, for certain older stationary sources 
that cause or contribute to visibility impairment, including fossil 
fuel-fired EGUs, states must determine BART on the basis of five 
statutory factors, such as costs and energy and non-air quality 
impacts.\591\ In 1980, the EPA promulgated a regulatory definition of 
BART: ``an emission limitation based on the degree of reduction 
achievable through the best system of continuous emission reduction for 
each pollutant which is emitted by an existing stationary facility.'' 
\592\ Both the statutory factors and the regulatory definition resemble 
the definition of the BSER under CAA section 111(a)(1)

[[Page 64781]]

(although, as noted, the statutory definition of BART is more 
technology focused than the definition of BSER). In its regional haze 
SIP, the State of New York determined that BART for the NOX 
emissions from two coal-fired boilers that served as peaking units was 
caps on baseline emissions rates and annual capacity factors of 5 
percent and 10 percent, respectively.\593\
---------------------------------------------------------------------------

    \591\ CAA section 169A(g)(2).
    \592\ 40 CFR 51.301.
    \593\ 77 FR 24794, 24810 (Apr. 25, 2012).
---------------------------------------------------------------------------

    There have been numerous other instances in which fossil fuel-fired 
EGUs have reduced their individual generation, or placed limits on 
their generation, in order to achieve, or obviate, emission standards. 
In fact, there are numerous examples of EGUs that take restrictions on 
hours of operation in their permits for the purpose of avoiding CAA 
obligations, including avoiding triggering the requirements of the 
Prevention of Significant Deterioration (PSD), Nonattainment New Source 
Review (NNSR), or Title V programs (including Title V fees), and 
avoiding triggering HAP requirements. Such restrictions may also be 
taken to limit emissions of pollutants, such as limiting emissions of 
criteria pollutants for attainment purposes.
    More specifically, EPA's regulations for a number of air programs 
expressly recognize that certain sources may take enforceable limits on 
hours of operation in order to avoid triggering CAA obligations that 
would otherwise apply to the source. 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.\594\ A source may voluntarily obtain a synthetic minor 
limitation--that is, a legally and practicably enforceable restriction 
that has the effect of limiting emissions below the relevant level--to 
avoid triggering a major stationary source requirement.\595\ Such 
synthetic minor limits may be based on restrictions on the hours of 
operation, as provided in EPA's regulations defining ``potential to 
emit,'' as well as on air pollution control equipment. ``Potential to 
emit'' is defined, for instance, in the regulations for the PSD program 
for permits issued under federal authority as: ``the maximum capacity 
of a stationary source to emit a pollutant under its physical and 
operational design. Any physical or operational limitation on the 
capacity of the source to emit a pollutant, including air pollution 
control equipment and restrictions on hours of operation . . . shall be 
treated as part of its design if the limitation or the effect it would 
have on emissions is federally enforceable,'' \596\ or ``legally and 
practicably enforceable by a state or local air pollution control 
agency.'' \597\ The regulations for other air programs similarly 
recognize that potential to emit may be limited through restrictions on 
hours of operations in their corresponding definitions of ``potential 
to emit.'' \598\ These regulatory provisions make clear that 
restrictions on potential to emit include both ``air pollution control 
equipment'' and ``restrictions on hours of operation,'' and indicate 
that these are equally cognizable means of restricting emissions to 
comply with, or avoid, CAA requirements.\599\
---------------------------------------------------------------------------

    \594\ See, e.g., CAA sections 112(a)(1), 112(d)(1), 165(a), 
169(1), 172(c)(5), 173(a) & (c), 501(2), 502(a), 302(j).
    \595\ See, e.g., Memorandum from Terrell Hunt, Assoc. 
Enforcement Counsel, U.S. EPA, & John Seitz, Director, Stationary 
Source Compliance Div., U.S. EPA, Guidance on Limiting Potential to 
Emit in New Source Permitting, at 1-2, 6 (June 13, 1989), available 
at http://www.epa.gov/region07/air/nsr/nsrmemos/lmitpotl.pdf 
(``Restrictions on production or operation that will limit potential 
to emit include limitations on quantities of raw materials consumed, 
fuel combusted, hours of operation, or conditions which specify that 
the source must install and maintain controls that reduce emissions 
to a specified emission rate or to a specified efficiency level.'') 
(emphasis added).
    \596\ 40 CFR 52.21(b)(4) (emphasis added).
    \597\ John Seitz, Director, Office of Air Quality Planning and 
Standards, and Robert Van Heuvelen, Director, Office of Regulatory 
Enforcement, Release of Interim Policy on Federal Enforceability of 
Limitations on Potential to Emit, at 3 (Jan. 22, 1996), available at 
http://www.epa.gov/region07/air/nsr/nsrmemos/pottoemi.pdf.
    \598\ See 40 CFR 51.166(b)(4) (addressing SIP approved PSD 
programs), 51.165(a)(1)(iii) (addressing SIP approved NNSR 
programs), 70.2 (addressing Title V operating permit programs), and 
63.2 (addressing hazardous air pollutants).
    \599\ See, e.g., 40 CFR 52.21(b)(4).
---------------------------------------------------------------------------

    As one of many examples of a fossil-fuel fired EGU taking 
restrictions on hours of operation for the purpose of avoiding CAA 
obligations, Manitowoc Public Utilities in Wisconsin obtained a Title V 
renewal permit that limited the operating hours of the single simple-
cycle combustion turbine to not more than 194 hours per month, averaged 
over any consecutive 12 month period, as part of limiting its potential 
to emit for volatile organic compounds below the Title V threshold of 
100 tpy, and carbon monoxide, NOX and SO2 below 
the PSD threshold of 250 tpy.\600\ As another example, Sunbury 
Generation LP in Pennsylvania obtained a minor new source 
preconstruction permit, called a plan approval, for a repowering 
project from the Pennsylvania Department of Environmental Protection in 
2013 that limited the hours of operation of three combined cycle 
combustion turbines that were planned for construction in order to 
remain below the significance threshold for GHGs.\601\ The Legal 
Memorandum includes numerous other examples of power plants accepting 
permit limits that reduce generation to meet, or avoid the need to 
meet, emission limits.
---------------------------------------------------------------------------

    \600\ See Final Operation Permit No. 436123380-P10 for Manitowoc 
Public Utilities--Custer Street (Wis. Dept. Nat. Res., 8/19/2013), 
Condition ZZZ.1.a(1) at p. 9 (Limiting potential to emit) and n. 11 
(``These conditions are established so that the potential emissions 
for volatile organic compounds will not exceed 99 tons per year and 
potential emissions for carbon monoxide, nitrogen oxides and sulfur 
dioxide emissions from the facility will not exceed 249 tons per 
year.''). See also Analysis and Preliminary Determination for the 
Renewal of Operation Permit 436123380-P01 (Wis. Dept. Nat. Res., 5/
21/2013) at p. 5 (noting that the ``existing facility is a major 
source under Part 70 because potential emissions of sulfur dioxide, 
nitrogen oxides and carbon monoxide exceed 100 tons per year. The 
existing facility is a minor source under PSD and an area source of 
federal HAP'' and further noting that after renewal, ``the facility 
will continue to be a major source under Part 70 because potential 
emissions of sulfur dioxide, nitrogen oxides and carbon monoxide 
exceed 100 tons per year. The facility will also continue to be a 
minor source under PSD and an area source of federal HAP.'').
    \601\ See Plan Approval No. 55-00001E for Sunbury Generation LP 
(Pa. Dept. Env. Protection, 4/1/2013), Conditions #016 on pp. 24, 32 
and 40 (limiting turbine units to operating no more than 7955, 6920, 
or 8275 hours in any 12 consecutive month period depending on which 
of three turbine options was selected); Memorandum from J. Piktel to 
M. Zaman, Addendum to Application Review Memo for the Repowering 
Project (Pa. Dept. Env. Protection, 4/1/2013) at p. 2 of 10 (noting 
that source had ``calculated a maximum hours per year (12 
consecutive month period) of operation for the sources proposed for 
each of the turbine options in order to remain below the 
significance threshold for GHGs.'').
---------------------------------------------------------------------------

    There are several ways that an affected EGU may implement reduced 
generation. For example, an EGU may accept a permit requirement that 
specifically limits its operating hours. In addition, an EGU may treat 
the cost of its generation as including an additional amount associated 
with environmental impacts, which requires it to raise its bid price, 
so that the EGU is dispatched less.
    c. Other aspects of reduced generation.
    The amounts of increased existing NGCC generation and new 
renewables, in the amounts reflected in building blocks 2 and 3, can be 
substituted for generation at 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 block 3 will develop at the 
levels requisite to ensure an adequate and reliable supply of 
electricity at the same time that affected EGUs may

[[Page 64782]]

choose to reduce their CO2 emissions by means of reducing 
their generation.
    Reduced generation by affected EGUs, in the amounts that affected 
EGUs may rely on to implement the selected building blocks, will not 
have adverse effects on the utility power sector and will not reduce 
overall electricity generation. In light of the emission limits of this 
rule, because of the availability of the measures in building blocks 2 
and 3, and because the grid is interconnected and the electricity 
system is highly planned, reductions in generation by fossil fuel-fired 
EGUs in the amount contemplated if they were to implement the building 
blocks, and occurring over the lengthy time frames provided under this 
rule, will result in replacement generation that generally is lower- or 
zero-emitting. 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. As a result, 
reduced generation will not give rise to reliability concerns or have 
other adverse effects on the utility power sector and are of reasonable 
cost for the affected source category and the nationwide electricity 
system.\602\ All these results come about because the operation of the 
electrical grid through integrated generation, transmission, and 
distribution networks creates substitutability 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 new lower- and zero-emitting EGUs (building block 3). Further, this 
substitutability increases over longer timeframes with the opportunity 
to invest in infrastructure improvements, and as noted elsewhere, this 
rule provides an extended state plan and source compliance horizon.
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    \602\ Although, as discussed in the text in this section of the 
preamble, we are not treating reduced overall generation of 
electricity as the BSER (because it does not meet our historical and 
current approach of defining the BSER to include methods that allow 
the same amount of production but with a lower-emitting process) we 
note that reduced generation by individual higher-emitting EGUs to 
implement building blocks 2 and 3 meets the following criteria for 
the BSER: As the examples in the text and in the Legal Memorandum 
make clear, reduced generation is ``adequately demonstrated'' as a 
method of reducing emissions (because Congress and the EPA have 
recognized it and on numerous occasions, power plants have relied on 
it); it is of reasonable cost; it does not have adverse effects on 
energy requirements at the level of the individual affected source 
(because it does not require additional energy usage by the source) 
or the source category or the U.S.; and it does not create adverse 
environmental problems.
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    d. Comments concerning limiting principles.
    A commenter stated that ``an interpretation of [`system of emission 
reduction'] that relies primarily on reduced utilization has no clear 
limiting principle.'' \603\ We disagree with this concern, for the 
following reasons.
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    \603\ EEI comment, at 284.
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    As discussed, in this final rule, we are identifying the BSER as 
the combination of the three building blocks. Building blocks 2 and 3 
entail substitution of lower- or zero-emitting generation for higher-
emitting generation, and one component of that substitution is reduced 
generation, which is limited in several respects discussed below. 
Accordingly, our identification of the BSER in this final rule does not 
``rel[y] primarily'' on reduced utilization in and of itself (and 
therefore reduced generation of the product overall, electricity) as 
the BSER. Rather, the BSER is, in addition to building block 1, the 
substitution of lower- or zero-emitting generation for higher emitting 
generation, and reduced utilization may be a way to implement that 
substitution and is one of numerous methods that affected EGUs may 
employ to achieve or help achieve the emission limits established by 
these emission guidelines.\604\ The commenter's concerns over a 
perceived lack of a limiting principle cannot be taken to mean that 
reduced generation by higher-emitting EGUs cannot be considered to be a 
method for affected EGUs to achieve their emission limits.
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    \604\ Indeed, load shifting--as substitute generation is 
sometimes called--is an ``easy and fairly inexpensive strategy'' 
that ``may be used in conjunction with other control measures'' for 
``emission reduction.'' Donald S. Shepard, ``A Load Shifting Model 
for Air Pollution Control in the Electric Power Industry,'' Journal 
of the Air Pollution Control Association, Vol. 20, No. 11, p. 760 
(Nov. 1970). In fact, load shifting has been recognized as a 
pollution control technique as early as 1968, when it was included 
in the ``Chicago Air Pollution System Model'' for controlling 
incidents of extremely high pollution. E.J. Croke, et al., ``Chicago 
Air Pollution System Model, Third Quarterly Progress Report,'' 
Chicago Department of Air Pollution Control, p. 186 (1968) 
(discussing the feasibility of ``Control by Load Reduction'' in 
combination with load shifting as applied to the Commonwealth Edison 
Company), available at http://www.osti.gov/scitech/servlets/purl/4827809. The report also considered ``combining fuel switching and 
load reduction'' as a possible air pollution abatement technique. 
See id. at 188. The report recognized, as an initial matter, that 
the Commonwealth Edison Company (CECO) was ``constrained to meet the 
total load demand'' but that ``load reduction at one plant or even a 
number of plants is usually feasible by shifting the power demand to 
other plants in the system.'' Id. As a result, the report noted, 
``load shifting within the physical limits of the CECO system . . . 
may be a highly desirable control mechanism.'' Id. The report also 
predicted that ``[i]n the future, it may be possible to form 
reciprocal agreements to obtain `pollution abatement' power from 
neighbor companies during a pollution incident and return this 
borrowed power at some later date.'' Id. at 187.
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    Moreover, reduced generation, as applied to affected EGUs in this 
rule, is limited in a number of respects. The amount of reduced 
generation is the amount of replacement generation that is lower- or 
zero-emitting, that is of reasonable cost, that can be generated 
without jeopardizing reliability, and that meets the other requirements 
for the BSER. As discussed, that amount is the amount of generation in 
building blocks 2 and 3.\605\
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    \605\ The EPA notes that affected EGUs are not actually required 
to collectively reduce generation by the amount represented in the 
BSER, and may collectively reduce generation by more or less than 
that amount. Individual affected EGUs are free to choose reduced 
generation or other means of reducing emissions, as permitted by 
their state plans, in order to achieve the standards of performance 
established for them by their states.
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    Finally, as discussed, the integrated nature of the electricity 
system, coupled with the high substitutability of electricity, allows 
EGUs to reduce their generation without adversely affecting the 
availability of their product. Those characteristics facilitate 
replacement of generation that has been reduced, and for that reason, 
EGUs have a long history of reducing their generation and either 
replacing it directly or having it replaced through the operation of 
the interconnected electricity system through measures similar to those 
in building blocks 2 and 3. Thus, an EGU can either directly replace 
its generation, or simply reduce its generation, and in the latter 
case, the integrated grid, combined with the high degree of planning 
and various reliability safeguards, will result in entities providing 
replacement generation. This means that consumers receive exactly the 
same amount of the same product, electricity, after the reduced 
generation that they received before it. No other industry is both 
physically interconnected in this manner and manufactures such a highly 
substitutable product; as a result, the use of reduced generation is 
not easily transferrable to another industry.
6. Reasons That This Rule Is Within the EPA's Statutory Authority and 
Does Not Represent Over-Reaching
    In this section, we respond to adverse comments that the EPA is 
overreaching in this rulemaking by attempting to direct the energy 
sector. These commenters construed the proposed rulemaking as the EPA 
proposing to mandate the implementation of the measures in the building 
blocks,

[[Page 64783]]

including investment in RE and implementation of a broad range of state 
and utility demand-side EE programs. Commenters added that in some 
instances, the affected EGUs and states would have no choice but to 
take the actions in the building blocks because they would not 
otherwise be able to achieve their emission standards. Commenters also 
emphasized that with the proposed portfolio approach, the rule would 
impose federally enforceable requirements on a wide range of entities 
that do not emit CO2 and have not previously been subject to 
CAA regulation. Commenters cite the U.S. Supreme Court's statements in 
Utility Air Regulatory Group v. EPA (UARG) \606\ that caution an agency 
against interpreting its statutory authority in a way that ``would 
bring about an enormous and transformative expansion in [its] 
regulatory authority without clear congressional authorization,'' and 
that add, ``When an agency claims to discover in a long-extant statute 
an unheralded power to regulate `a significant portion of the American 
economy,' . . . we typically greet its announcement with a measure of 
skepticism.'' \607\ Commenters assert that in this rule, the EPA is 
taking the actions that the UARG opinion cautioned against. For the 
reasons discussed below, these comments are incorrect and misunderstand 
fundamental aspects of this rule. In addition, to the extent these 
comments address either building block 4 or the portfolio approach they 
are moot, because the EPA is not finalizing those elements of the 
proposal.
---------------------------------------------------------------------------

    \606\ 134 S. Ct. 2427 (2014).
    \607\ Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2444 
(2014) (citations omitted).
---------------------------------------------------------------------------

    In this rule, the EPA is following the same approach that it uses 
in any rulemaking under CAA section 111(d), which is designed to 
regulate the air pollutants from the source category at issue. First, 
the EPA identifies the BSER to reduce harmful air pollution. Second, 
based on the BSER, the EPA promulgates emission guidelines, which 
generally take the form of emission rates applicable to the affected 
sources. In this case, the EPA is promulgating a uniform CO2 
emission performance rate for steam-generating EGUs and a uniform 
CO2 emission performance rate for combustion turbines, and 
the EPA is translating those rates into a combined emission rate and 
equivalent mass limit for each state. These emission guidelines serve 
as the guideposts for state plan requirements. The states, in turn, 
promulgate standards of performance and, in doing so, retain 
significant flexibility either to promulgate rate-based emission 
standards that mirror the emission performance rates in the guidelines, 
promulgate rate-based emission standards that are equivalent to the 
emission performance rates in the guidelines, or promulgate equivalent 
mass-based emission standards. The sources, in turn, are required to 
comply with their emission standards, and may do so through any means 
they choose. Alternatively, the state may adopt the state-measures 
approach, which provides additional flexibility.
    Thus, the EPA is not requiring that the affected EGUs take any 
particular action, such as implementation of the building blocks. 
Rather, as just explained, the EPA is regulating the affected EGUs' 
emissions by requiring that the state submit state plans that achieve 
specified emission performance levels. The states may choose from a 
wide range of emission limits to impose on their sources, and the 
sources may choose from a wide range of compliance options to achieve 
their emission limits. Those options include various means of 
implementing the building blocks as well as numerous other compliance 
options, ranging from--depending in part on whether the state imposes a 
rate-based or mass-based emission limit--implementation of demand-side 
EE measures to natural gas co-firing.\608\
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    \608\ In fact, the EPA is expressly precluded from mandating 
specific controls except in certain limited circumstances. See 42 
U.S.C. 7411(b)(5). For instance, the EPA is authorized to mandate a 
particular ``design, equipment, work practice, or operational 
standard, or combination thereof,'' when it is ``not feasible to 
prescribe or enforce a standard of performance'' for new sources. 42 
U.S.C. 7411(h)(1). CAA section 111(h) also highlights for us that 
while ``design, equipment, work practice, or operational standards'' 
may be directly mandated by the EPA, CAA section 111(a)(1) 
encompasses a broader suite of measures for consideration as the 
BSER.
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    As some indication of the diverse set of actions we expect to 
comply with the requirements of this rule, we note that demand-side EE 
programs, in particular, are expected to be a significant compliance 
method, in light of their low costs. In addition, the National 
Association of Clean Air Agencies (NACAA) has issued a report that 
provides a detailed discussion of 25 approaches to CO2 
reduction in the electricity sector.\609\ In addition, we note that the 
nine RGGI states--Connecticut, Delaware, Maine, Maryland, 
Massachusetts, New Hampshire, New York, Rhode Island and Vermont--have 
indicated that they intend to maintain their current state programs, 
which this rule would allow, and there are reports that other states 
may seek to join RGGI.\610\ Similarly, California has indicated that it 
intends to maintain its current state program, which this rule would 
allow. Other states could employ the types of methods used in Oregon, 
Washington, Colorado, or Minnesota, described in the background section 
of this preamble.
---------------------------------------------------------------------------

    \609\ NACAA, ``Implementing EPA's Clean Power Plan: A Menu of 
Options (May 2015), http://www.4cleanair.org/NACAA_Menu_of_Options. 
NACAA describes itself as ``the national, non-partisan, non-profit 
association of air pollution control agencies in 41 states, the 
District of Columbia, four territories and 116 metropolitan areas.'' 
Id.
    \610\ Martinson, Erica, ``Cap and trade lives on through the 
states,'' Politico (May 27, 2014), http://www.politico.com/story/2014/05/cap-and-trade-states-107135.html.
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    As a practical matter, we expect that for some affected EGUs, 
implementation of the building blocks will be the most attractive 
option for compliance. This does not mean, contrary to the adverse 
comments noted above, that this rule constitutes a redesign of the 
energy sector. As discussed above, the building blocks meet the 
criteria to be part of the best system of emission reduction . . . 
adequately demonstrated. The fact that some sources will implement the 
building blocks and that this may result in changes in the electricity 
sector does not mean that the building blocks cannot be considered the 
BSER under CAA section 111(d).
    In this rule, as with all CAA section 111(d) rules, the EPA is not 
directly regulating any entities. Moreover, the EPA is not finalizing 
the proposed portfolio approach. Accordingly, the EPA is neither 
requiring nor authorizing the states to regulate non-affected EGUs in 
their CAA section 111(d) plans.\611\
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    \611\ A state may regulate non-EGUs as part of a state measures 
approach, but those measures would not be federally enforceable.
---------------------------------------------------------------------------

    Moreover, contrary to adverse comments, this rule does not require 
the states to adopt a particular type of energy policy or implement 
particulate types of energy measures. Under this rule, a state may 
comply with its obligations by adopting the emission standards approach 
to its state plan and imposing rate-based or mass-based emission 
standards on its affected EGUs. In this manner, this rule is consistent 
with prior section 111(d) rulemaking actions, in which the states have 
complied by promulgating one or both of those types of standards of 
performance. In this rulemaking, as an alternative, the state may adopt 
the state measures approach, under which the state could, if it wishes, 
adopt particular types of energy measures that would lead to reductions 
in emissions from its EGUs. But again, this rule does not require the 
state to implement a

[[Page 64784]]

particular type of energy policy or adopt particular types of energy 
measures.
    It is certainly reasonable to expect that compliance with these air 
pollution controls will have costs, and those costs will affect the 
electricity sector by discouraging generation of fossil fuel-fired 
electricity and encouraging less costly alternative means of generating 
electricity or reducing demand. But for affected EGUs, air pollution 
controls necessarily entail costs that affect the electricity sector 
and, in fact, the entire nation, regardless of what BSER the EPA 
identifies as the basis for the controls. For example, had some type of 
add-on control such as CCS been identified as the BSER for coal-fired 
EGUs, sources that complied by installing that control would incur 
higher costs. As a result, generation from coal-fired EGUs would be 
expected to decrease and be replaced at least in part by generation 
from existing NGCC units and new renewables because those forms of 
generation would see their competitive positions improved.
    This basic fact that EPA regulation of air pollutants from affected 
EGUs invariably affects the utility sector is well-recognized and in no 
way indicates that such regulation exceed the EPA's authority. In 
revising CAA section 111 in the 1977 CAA Amendments, Congress 
explicitly acknowledged that the EPA's rules under CAA section 111 for 
EGUs would significantly impact the energy sector.\612\ The Courts have 
recognized that, too. The U.S. Supreme Court, in its 2011 decision that 
the CAA and the EPA actions it authorizes displace any federal common 
law right to seek abatement of CO2 emissions from fossil 
fuel-fired power plants, emphasized that CAA section 111 authorizes the 
EPA--which the Court identified as the ``expert agency''--to regulate 
CO2 emissions from these sources in a manner that balances 
``our Nation's energy needs and the possibility of economic 
disruption:''
---------------------------------------------------------------------------

    \612\ The D.C. Circuit acknowledged this legislative history in 
Sierra Club v. EPA, 657 F.2d 298, 331 (D.C. Cir. 1981). There, the 
Court stated:
    [T]he Reports from both Houses on the Senate and House bills 
illustrate very clearly that Congress itself was using a long-term 
lens with a broad focus on future costs, environmental and energy 
effects of different technological systems when it discussed section 
111. [Citing S. Rep. No. 95-127, 95th Cong., 1st Sess. (1977), 3 
Legis. Hist. 1371; H.R. Rep. No. 95-294, 95th Cong., 1st Sess. 188 
(1977), 4 Legis. Hist. 2465.]

    The appropriate amount of regulation in any particular 
greenhouse gas-producing sector cannot be prescribed in a vacuum: As 
with other questions of national or international policy, informed 
assessment of competing interests is required. Along with the 
environmental benefit potentially achievable, our Nation's energy 
needs and the possibility of economic disruption must weigh in the 
balance.
    The [CAA] entrusts such complex balancing to EPA in the first 
instance, in combination with state regulators. Each ``standard of 
performance'' EPA sets must ``tak[e] into account the cost of 
achieving [emissions] reduction and any nonair quality health and 
environmental impact and energy requirements.'' Sec.  7411(a)(1), 
(b)(1)(B), (d)(1); see also 40 CFR 60.24(f) (EPA may permit state 
plans to deviate from generally applicable emissions standards upon 
demonstration that costs are ``[u]n-reasonable''). EPA may 
``distinguish among classes, types, and sizes'' of stationary 
sources in apportioning responsibility for emissions reductions. 
Sec.  7411(b)(2), (d); see also 40 CFR 60.22(b)(5). And the agency 
may waive compliance with emission limits to permit a facility to 
test drive an ``innovative technological system'' that has ``not 
[yet] been adequately demonstrated.'' Sec.  7411(j)(1)(A). The Act 
envisions extensive cooperation between federal and state 
authorities, see Sec.  7401(a), (b), generally permitting each state 
to take the first cut at determining how best to achieve EPA 
emissions standards within its domain, see Sec.  7411(c)(1), (d)(1)-
(2).
    It is altogether fitting that Congress designated an expert 
agency, here, EPA