prevent or reduce carbon pollution, including companies that have
expertise in renewable energy and energy efficiency. Other meetings
have been held with representatives of energy intensive industries,
such as the iron and steel and aluminum industries to help understand
the issues related to large industrial users of electricity.
7. Electric Utility Representatives
    Agency officials participated in many meetings with utilities and
their associations. The meetings focused on the importance of the
utility industry in reducing carbon emissions from power plants. Power
plant emissions are central to this rulemaking. The EPA encouraged
industry representatives to work with state environmental and energy
officers.
    The electric utility representatives included private utilities or
investor owned utilities. Public utilities and cooperative utilities
were also part of in-depth conversations about CAA section 111(d) with
EPA officials.
    The conversations included meetings with the EPA headquarters and
Regional offices. State officials were included in many of the
meetings. Meetings with utility associations and groups of utilities
were held with key EPA officials. The meetings covered technical,
policy, and legal topics of interest and utilities expressed a wide
variety of support and concerns about CAA section 111(d).
8. Electricity Grid Operators
    The EPA had a number of conversations with the Independent System
Operators and Regional Transmission Organizations (ISOs and RTOs) to
discuss the rule and issues related to grid operations and reliability.
EPA staff met with the ISO/RTO Council on several occasions to collect
their ideas. The EPA Regional Offices also met with the ISOs and RTOs
in their regions. System operators have offered suggestions in using
regional approaches to implement CAA section 111(d) while maintaining
reliable, affordable electricity.
9. Representatives From Non-Governmental Organizations
    Agency officials engaged with representatives of environmental
justice organizations during the outreach effort, for example, we
engaged with the National Environmental Justice Advisory Council
members in September 2013. The NEJAC is composed of stakeholders,
including environmental justice leaders and other

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

B. Key Messages From Stakeholders

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

C. Key Stakeholder Proposals

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

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

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

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

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

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

    \48\ Regional Greenhouse Gas Initiative 2013 Allowance
Allocation http://rggi.org/design/overview/allowance-allocation/2013-allocation.
    \49\ Regional Investments of RGGI CO2 Allowance
Proceeds, 2012 (2014), available at http://www.rggi.org/docs/Documents/2012-Investment-Report.pdf.
    \50\ Of the $707 million in auction proceeds invested by RGGI
participating states through 2012, 65 percent supported end-use
energy efficiency programs. See Regional Greenhouse Gas Initiative,
``Regional Investments of RGGI CO2 Allowance Proceeds,
2012'' (2014). Available at http://www.rggi.org/docs/Documents/2012-Investment-Report.pdf.
    \51\ Id.
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    Between 2005, when an agreement to implement RGGI was announced,
and 2012, power sector CO2 emissions in the RGGI
participating states fell by more than 40 percent.\52\ RGGI was not the
primary driver for these reductions but the reductions led RGGI-
participating states to later adjust the CO2 emission limits
downward.\53\ In January 2014, the participating states lowered the
overall allowable CO2 emission level in 2014 by 45 percent,
setting a multi-state CO2 emission limit for affected EGUs
of 91 million short tons of CO2 in 2014 and 78 million short
tons of CO2 in 2020, more than 50 percent below 2008
levels.\54\
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    \52\ Regional Greenhouse Gas Initiative, Report on Emission
Reduction Efforts of the States Participating in the Regional
Greenhouse Gas Initiative and Recommendations for Guidelines under
Section 111(d) of the Clean Air Act (2013).
    \53\ The first three-year control period under RGGI,
establishing CO2 emission limits for EGUs, began on
January 1, 2009.
    \54\ RGGI Press Release, January 13, 2014, http://www.rggi.org/docs/PressReleases/PR011314_AuctionNotice23.pdf.
---------------------------------------------------------------------------

    Similarly, California established an economy-wide market-based GHG
emissions trading program under the authority of its 2006 Global
Warming Solutions Act, which requires the state to reduce its 2020 GHG
emissions to 1990 levels.\55\ While California's emission trading
program, like its state emission limit, is multi-sector in scope, the
state projects that the emissions trading program and related
complementary measures will reduce power sector GHG emissions to less
than 80 million metric tons of CO2 equivalent by 2025, a 25
percent reduction from 2005 power sector emission levels.\56\ Prior to
the implementation of the emission trading program, California reports
that it reduced CO2 power sector emissions by 16 percent
from 2005 to a 2010-2012

averaging period, a reduction of 16 million metric tons of
CO2 equivalent.\57\
---------------------------------------------------------------------------

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

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

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

3. Utility Planning Approaches
    Two states, Minnesota and Colorado, have worked collaboratively
with their investor-owned utilities to develop multi-pollutant emission
reduction plans on a utility-wide basis. This multi-pollutant,
collaborative approach enables utilities to determine the least cost
way to meet long term and comprehensive energy and environmental goals.
    Colorado's Clean Air, Clean Jobs Act of 2010, for example, required
Colorado investor-owned utilities with coal plants to develop a multi-
pollutant plan to meet existing and reasonably foreseeable federal CAA
requirements.\60\ The utilities were not required to adopt a specific
plan set by the state but were, instead, required to work
collaboratively with the Colorado Department of Public Health and
Environmental and Colorado Public Utility Commission to develop an
acceptable plan. Xcel Energy, Colorado's largest investor-owned
utility, submitted a plan that was approved in 2010. With this plan,
Xcel Energy is projected to reduce its CO2 emissions from
generation in Colorado by 28 percent by 2020.\61\
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    \60\ Colorado Clean Air, Clean Jobs Act, HB1365.
    \61\ Xcel Energy, Colorado Clean Air-Clean Jobs Plan, available
at http://www.xcelenergy.com/Environment/Doing_Our_Part/Clean_Air_Projects/Colorado_Clean_Air_Clean_Jobs_Plan.
---------------------------------------------------------------------------

4. Renewable Portfolio Standards
    More than 25 states have mandatory renewable portfolio standards
that require retail electricity suppliers to supply a minimum
percentage or amount of their retail electricity load with electricity
generated from eligible sources of renewable energy.\62\ These
standards have been established via utility regulatory commissions,
legislatures and citizen ballots and requirements vary from state to
state. State RPS typically specify the types of renewable energy, or
other energy sources, that qualify for use toward achievement of the
standard, and often allow for the use of qualifying renewable energy
resources located outside of the state. They reduce utilization of
fossil fuel-fired EGUs and, thereby, lead to reductions in GHG
emissions by meeting a portion of the demand for electricity through
renewable or other energy sources.
---------------------------------------------------------------------------

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

    In 2007, the Minnesota legislature amended the state's 2001
renewable energy objective and established a renewable energy standard
(RES) requiring at least 25 percent of all electricity generated or
purchased in Minnesota to come from renewable energy by 2025. The
standard sets requirements and timetables, beginning in 2010, that vary
based on the provider. For example, in 2011, Xcel Energy had a
requirement to generate or purchase 15 percent of its total retail
sales from renewable energy while all other utilities had a target of 7
percent of total retail sales. According to the latest Minnesota
Department of Commerce report to the legislature on progress, all
utilities subject to the standard met it for 2011 and were on track to
meet their 2012 goals.\63\ The 2012 requirement increased to 18 percent
of total retail sales for Xcel Energy and 12 percent for all other
utilities.\64\ In 2013, the Minnesota legislature expanded the RES with
solar incentives and a specific solar energy standard requiring
Minnesota utilities to ensure that at least 1.5 percent of their retail
electricity sales in 2020 come from solar energy.\65\
---------------------------------------------------------------------------

    \63\ Report to the Minnesota Legislature: Progress on Compliance
By Electric Utilities With The Minnesota Renewable Energy Objective
and the Renewable Energy Standard, Prepared by: The Minnesota
Department of Commerce, Division of Energy Resources January 14,
2013; http://mn.gov/commerce/energy/images/2013RESLegReport.pdf.
    \64\ Id.
    \65\ Minnesota Statutes 2013, Section 216B.1691, Subdivision 2f.
Solar Energy Standard https://www.revisor.mn.gov/statutes/?id=216b.1691.
---------------------------------------------------------------------------

    The Oregon Renewable Portfolio Standard (RPS) is another example of
a state requirement for renewables. Originally enacted in 2007, it
requires that all utilities serving Oregon meet a percentage of their
retail electricity needs with qualified renewable resources. Like in
Minnesota, the percentage varies across utilities with the three
largest utilities required to reach five percent from renewable energy
sources starting in 2011, 15 percent in 2015, 20 percent in 2020, and
25 percent in 2025. Other electric utilities in the state are required
to reach levels of five percent or ten percent by 2025, depending on
their size. According to the latest RPS compliance reports submitted by
the largest utilities for the state, each had achieved the five percent
target as of the end of 2012.\66\
---------------------------------------------------------------------------

    \66\ Eugene Water Electric Board Oregon Renewable Portfolio
Standard 2012 Compliance Report and 2013-2030 Implementation Plan,
June 1, 2013. PacifiCorp's Renewable Portfolio Standard Oregon
Compliance Report for 2012, May 31, 2013. PGE 2012 Renewable
Portfolio Standard Compliance Report, June 1, 2013.
---------------------------------------------------------------------------

5. Demand-Side Energy Efficiency Programs
    Many electric utilities, third-party administrators, and states
implement demand-side energy efficiency programs to reduce generation
from EGUs by reducing electricity use, including peak demand. When
these programs reduce fossil fuel electricity generation, they also
reduce CO2 emissions. Demand-side energy efficiency programs
use a variety of energy efficiency measures to target a variety of end
uses and are often driven by existing state standards and programs,
such as policies requiring utilities to obtain ``all cost-effective
energy efficiency'' through long-term integrated resource planning
(IRP), renewable portfolio standards (RPS) that include efficiency as a
qualifying resource, energy efficiency resource standards (EERS),
public benefit funds, and other demand-side planning requirements.
    The purposes of demand-side energy efficiency programs vary; goals
include to reduce GHG emissions by reducing fossil-fired generation,
help states achieve energy savings goals, save energy and money for
consumers and improve electricity reliability. They are typically
funded through a small fee or surcharge on customer electricity bills,
but can also be funded by other sources, such as from RGGI
CO2 allowance auction proceeds mentioned above.

    Nationally, total spending on electric ratepayer-funded energy
efficiency programs was about $5 billion in 2012.\67\ Based on Lawrence
Berkeley National Laboratory (LBNL) projections, spending is projected
to reach $8.1 billion in 2025.\68\
---------------------------------------------------------------------------

    \67\ Consortium for Energy Efficiency Annual Industry Report:
2013 State of the Efficiency Program Industry--Budgets, Expenditures
and Impacts, 2014.
    \68\ Lawrence Berkeley National Laboratory (LBNL) The Future of
Utility Customer-Funded Energy Efficiency Programs in the United
States: Projected Spending and Savings to 2025 (http://emp.lbl.gov/sites/all/files/lbnl-5803e.pdf).
---------------------------------------------------------------------------

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

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

    California has been advancing energy efficiency through utility-run
demand-side energy efficiency programs for decades and considers energy
efficiency ``the bedrock upon which climate policies are built.'' \70\
It requires its investor-owned utilities to meet electricity load
``through all available energy efficiency and demand reduction
resources that are cost-effective, reliable and feasible.'' \71\ The
California Public Utility Commission works with the California Energy
Commission to determine the amount of cost-effective reduction
potential and establishes efficiency targets. A recent energy
efficiency potential study found that, even after years of running
programs, California can still tap ``tens of thousands of GWh in
potential savings . . . over the next decade.'' \72\ Investor-owned
utilities use demand-side energy efficiency programs to achieve their
targets and currently ``save about 3,000 GW per year, enough savings to
power about 600,000 households.'' \73\ Between 2010 and 2011, these
programs are estimated to have reduced CO2 by 3.8 million
tons.\74\
---------------------------------------------------------------------------

    \70\ December 27, 2013 Letter from Mary D. Nichols, Chairman of
California Air Resources Board, to EPA Administrator Gina McCarthy.
    \71\ Cal Pub. Utility Code Sec.  454.5 (a)(9)(C).
    \72\ Cited in December 27, 2013 Letter from Mary D. Nichols,
Chairman of California Air Resources Board, to EPA Administrator
Gina McCarthy.
    \73\ Id.
    \74\ Id.
---------------------------------------------------------------------------

    In Vermont, for example, the Vermont Legislature and the Vermont
Public Service Board (PSB) established the first statewide ``energy
efficiency utility'' in 1999 to provide energy efficiency services to
residences and businesses throughout the state.\75\ Vermont law
requires that the energy efficiency utility budgets be set at a level
to achieve ``all reasonably available, cost-effective energy
efficiency'' and then specific energy (kWh) and peak demand (kW)
savings levels are negotiated every three years.\76\ In 2013,
Efficiency Vermont, the PSB-appointed energy efficiency utility,
achieved annual savings of 1.66 percent of the state's electricity
sales, at a cost of 4.1 cents per kilowatt[hyphen]hour, lower than the
cost of comparable electric supply in the same year, which was 8.4
cents per kWh.\77\ Efficiency Vermont projects a net lifetime economic
value to Vermont of more than $60 million from the 2013 energy
efficiency investments.\78\
---------------------------------------------------------------------------

    \75\ State of Vermont Public Service Board, Energy Efficiency
Utility Creation and Structure. http://psb.vermont.gov/utilityindustries/eeu/generalinfo/ creationandstructure.
    \76\ Vermont Statute, Title 30: Public Service, 30 V.S.A. Sec.
209 (d)3(B). http://www.leg.state.vt.us/statutes/fullsection.cfm?Title=30&Chapter=005&Section=00209.
    \77\ Efficiency Vermont Savings Claim Summary 2013, Reported to
the Vermont Public Service Board and to the Vermont Public Service
Department, 2014, https://www.efficiencyvermont.com/docs/about_efficiency_vermont/annual_summaries/2013_savingsclaim_summary.pdf.
    \78\ Id.
---------------------------------------------------------------------------

6. Energy Efficiency Resource Standards
    More than 20 states have energy efficiency resource standards
(EERS) that require utilities to save a certain amount of energy each
year or cumulatively.\79\ They are typically multi-year requirements
expressed as a percentage of annual retail electricity sales or as
specific electricity savings amounts over a long term period relative
to a baseline of retail sales. Over the compliance period, an EERS
reduces fossil fuel-fired EGU generation through reductions in
electricity demand, thereby reducing CO2 emissions from the
power sector.
---------------------------------------------------------------------------

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

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

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

E. Conclusions

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

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

IV. Rule Requirements and Legal Basis

A. Summary of Rule Requirements

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

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

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

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

B. Summary of Legal Basis

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

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

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

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

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

A. Authority To Regulate Carbon Dioxide

    The EPA has the authority to regulate, under CAA section 111(d),
CO2 emissions from EGUs, under the Agency's construction of
the ambiguous provisions in CAA section 111(d)(1)(A)(i) that identify
the air pollutants subject to CAA section 111(d). The ambiguities stem
from apparent drafting errors that occurred during enactment of the
1990 CAA Amendments, which revised section 111(d).
    During the 1990 CAA Amendments, the House of Representatives and
the Senate each passed an amendment to CAA section 111(d)(1)(A)(i). The
two amendments differed from each other, and were not reconciled during
the Conference Committee and, as a result, both were enacted into law.
As amended by the Senate, the pertinent language of CAA section
111(d)(1) would exclude the regulation of any pollutant which is
``included on a list published under [CAA section] 112(b).'' \87\ As
amended by the House, the pertinent language in CAA section 111(d)(1)
would exclude the regulation of any pollutant which is ``emitted from a
source category which is regulated under section 112.'' \88\ The two
versions conflict with each other and thus are ambiguous. Under these
circumstances, the EPA may reasonably construe the provision to
authorize the regulation of GHGs under CAA section 111(d).
---------------------------------------------------------------------------

    \87\ Public Law 101-549, Sec.  302(a), 104 Stat. at 2574 (Nov.
15, 1990).
    \88\ Public Law 101-549, Sec.  108(g), 104 Stat. at 2467 (Nov.
15, 1990).
---------------------------------------------------------------------------

    It should be noted that the U.S. Supreme Court's holding in
American Electric Power Co. v. Connecticut, 131 S. Ct. 2527, 2537-38
(2011), that ``the Clean Air Act and the EPA actions it authorizes
displace any federal common law right to seek abatement of carbon-
dioxide emissions from fossil fuel-fired power plants'' was premised on
the Court's understanding that CAA section 111, including CAA section
111(d), applies to carbon dioxide emissions from those sources.
    We discuss this issue in more detail in the Legal Memorandum.

B. Authority To Regulate EGUs

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

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

C. Affected Sources

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

D. Implications for Tribes and U.S. Territories

    As noted in Section II.D of this preamble, although affected EGUs
located in Indian country operate as part of the interconnected system
of electricity production and distribution, affected EGUs located in
Indian country within a state's borders would not be encompassed within
the state's CAA section 111(d) plan. The EPA is aware of four
potentially affected power plants located in Indian country: The South
Point Energy Center, on Fort Mojave tribal lands within Arizona; the
Navajo Generating Station, on Navajo tribal lands within Arizona; the
Four Corners Power Plant, on Navajo tribal lands within New Mexico; and
the Bonanza Power Plant, on Ute tribal lands within Utah. The South
Point facility is an NGCC power plant, and the Navajo, Four Corners,
and Bonanza facilities are coal-fired power plants. The operators and
co-owners of these four facilities include investor-owned utilities,
cooperative utilities, public power agencies, and independent power
producers, most of which also co-own potentially affected EGUs within
state jurisdictions. We are not aware of any potentially affected EGUs
that are owned or operated by tribal entities. If it determines that
such a plan is necessary or appropriate, the EPA has the responsibility
to establish CAA section 111(d) plans for areas of Indian country where
affected sources are located unless a tribe on whose lands an affected
source (or sources) is located seeks and obtains authority from the EPA
to establish a plan itself, pursuant to the Tribal Authority Rule.\90\
The EPA intends to publish a supplemental proposal to establish
emission performance goals (if it determines that such action is
necessary or appropriate) covering the four potentially affected power
plants identified above, as well as any subsequently identified
similarly situated power plants, and also to proposed goals for U.S.
territories with affected EGUs. The EPA intends to take final action on
that proposal by June 2015. If a tribe does seek and obtain the
necessary authority to establish a plan itself, it is the EPA's
intention that the tribe would have flexibility to develop a plan
tailored to its circumstances, in the same manner as a state, to meet
CO2 emission performance goals that would be established by
the EPA based on application of the BSER to that area of Indian
country. The EPA is aware of actions that have been taken or are being
taken by some sources in tribal areas or territories and will be
mindful of these actions in considering establishment of a plan.
---------------------------------------------------------------------------

    \90\ See 40 CFR 49.1 to 49.11.
---------------------------------------------------------------------------

    The EPA invites comment on whether a tribe wishing to develop and
implement a CAA section 111(d) plan should have the option of including
the EGUs located in its area of Indian country in a multi-
jurisdictional plan with one or more states (i.e., treating the tribal
lands as an additional state).
    If the EPA develops one or more CAA section 111(d) federal plans
for areas of Indian country with affected EGUs, we are likewise
currently considering doing so on a multi-jurisdictional basis in
coordination with nearby states developing section 111(d) state plans.
The EPA solicits comment on such an approach for a federal plan.
    At this time, the EPA is not proposing CO2 emission
performance goals for areas of Indian country containing potentially
affected EGUs. We do plan to establish such goals in the future, to be
addressed through either tribal or federal plans, as discussed above.
The EPA notes that some present and planned actions being taken to
reduce criteria pollutants from EGUs in Indian country will result in
significant CO2 emission reductions relative to emissions in
the 2012 baseline period used in computing the state CO2

performance goals in this proposal.\91\ We invite comment on how the
BSER should be applied to potentially affected EGUs in Indian country.
We particularly invite comment on data sources for setting renewable
energy and demand-side energy efficiency targets.
---------------------------------------------------------------------------

    \91\ For example, a plan currently being implemented at the Four
Corners plant to satisfy regional haze requirements calls for
reduction of NOx emissions to be achieved in part by shutting down a
portion of the plant's generating capacity, and a similar plan has
been proposed for the Navajo plant. See 78 FR 62509 (October 22,
2013).
---------------------------------------------------------------------------

    The state-specific goals that the EPA is proposing are based on the
collection of affected EGUs located within that state. In setting goals
specific to an area of Indian country, the EPA proposes to base the
goals on the collection of affected EGUs located within that area of
Indian country. We request comment on this approach.

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

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

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

A. Introduction

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

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

B. Building Blocks for the Best System of Emission Reduction

    This subsection summarizes the EPA's analytic approach to
determining the best system of emission reduction (BSER) for
CO2 emissions from existing EGUs. Later subsections discuss
particular measures and how they form the basis of the BSER.\92\
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    \92\ The EPA is aware of the potential that one or more
facilities involved in programs mentioned or relied on in this
proposal may have received some form of assistance under the Energy
Policy Act of 2005 (EPAct). Section 402 (i) of the EPAct (codified
at 42 U.S.C. section 15962(i)) states:
    ``No technology, or level of emission reduction, solely by
reason of the use of the technology, or the achievement of the
emission reduction, by 1 or more facilities receiving assistance
under this Act, shall be considered to be--(1) adequately
demonstrated for purposes of section 111 of the Clean Air Act (42
U.S.C. 7411)[.]''
    In a February 26, 2014 Notice of Data Availability, the EPA
proposed to give this provision its natural meaning: the term
``solely'' modifies all of the provisions, so that any ``adequately
demonstrated'' finding by the EPA could not be based solely upon
technology, level of emission reduction, or achievement of the
emission reduction by a facility (or facilities) receiving
assistance. The EPA proposes the same interpretation here. The EPA
further believes that its proposed determination of the ``best
system of emission reduction . . . adequately demonstrated'' does
not depend exclusively on technology, level of emission reduction,
or achievement of emission reduction from facilities receiving EPAct
assistance, given the myriad number of technologies and emission
performance on which that proposed determination is based.
---------------------------------------------------------------------------

1. Overview of Approach
    In considering the appropriate scope of the proposed BSER, the EPA
evaluated three basic groupings of strategies for reducing
CO2 emission from EGUs: (i) Reductions achievable through
improvements in individual EGUs' emission rates (referred to throughout
this preamble as ``building block 1''); (ii) EGU CO2
emissions reductions achievable through re-dispatch from affected steam
EGUs to affected NGCC units (``building block 2''); and (iii) EGU
CO2 emissions reductions achievable by meeting demand for
electricity or electricity services through expanded use of low- or
zero-carbon generating capacity (``building block 3'') and through
expanded use of demand-side energy efficiency (``building block 4'').
While the first grouping plays the same role in each of our two
formulations of the BSER, the second and third groupings play different
roles: In the first formulation they constitute components of the BSER,
and in the second formulation they serve as the basis for why a
component of that formulation of the BSER--reduced utilization of the
higher-emitting affected EGUs--is adequately demonstrated.
    As described in the remainder of this section, the EPA concluded
that while certain strategies within the first grouping clearly should
be part of the BSER, it was not appropriate to limit consideration of
the BSER to this first grouping, for several reasons. First, we
determined that some strategies available in the other two groupings
can support reduced CO2 emissions from the fossil fuel-fired
EGUs by significant amounts and at lower costs than some of the
strategies in the first grouping. Second, we observed that strategies
in all three groupings were already being pursued by states and sources
taking advantage of the integrated nature of the electricity system, at
least in part for the purpose of reducing CO2 emissions.
Third, we were concerned that if measures from the first grouping that
improve heat rates at coal-fired steam EGUs were implemented in
isolation, without additional measures that encourage substitution of
less carbon-intensive ways of providing electricity services for more
carbon-intensive generation, the resulting increased efficiency of
coal-fired steam units would provide incentives to operate those EGUs
more, leading to smaller overall reductions in CO2
emissions.\93\ These factors reinforced the appropriateness of our
considering strategies from all three groupings for purposes of
determining the BSER.
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    \93\ Elsewhere in the preamble we refer to the potential for
efficiency improvements to lead to increased competitiveness and
therefore increased utilization as a ``rebound effect.''
---------------------------------------------------------------------------

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

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

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

    The EPA also examined application of CCS technology at existing
EGUs. CCS offers the technical potential for CO2 emission
reductions of over 90 percent, or smaller percentages in partial
applications. In the recently proposed Carbon Pollution Standards for
new fossil fuel-fired EGUs (79 FR 1430), we found that partial CCS was
adequately demonstrated for new fossil fuel-fired steam EGUs and
integrated gasification

combined cycle (IGCC) units. We also found that for these new units the
costs were not unreasonable, either for individual units or on a
national basis, and we proposed to find that application of partial CCS
is the BSER. However, application of CCS at existing units would entail
additional considerations beyond those at issue for new units.
Specifically, the cost of integrating a retrofit CCS system into an
existing facility would be expected to be substantial, and some
existing EGUs might have space limitations and thus might not be able
to accommodate the expansion needed to install CCS. Further, the
aggregated costs of applying CCS as a component of the BSER for the
large number of existing fossil fuel-fired steam EGUs would be
substantial and would be expected to affect the cost and potentially
the supply of electricity on a national basis. For these reasons,
although some individual facilities may find implementation of CCS to
be a viable CO2 mitigation option in their particular
circumstances,\98\ the EPA is not proposing and does not expect to
finalize CCS as a component of the BSER for existing EGUs in this
rulemaking.\99\ Nevertheless, CCS would be available to states and
sources as a compliance option.
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    \98\ CCS already has been or is being implemented at some
existing EGUs, as noted in the discussion of CCS later in the
preamble.
    \99\ As noted later in this preamble, we are nevertheless
seeking comment on the extent to which existing EGUs could implement
CCS in order to improve our understanding.
---------------------------------------------------------------------------

    Natural gas co-firing or conversion at coal-fired steam EGUs offers
greater potential CO2 emission reductions than heat rate
improvements, but at a higher cost (although less than the cost of
applying CCS technology). Because natural gas contains less carbon than
an energy-equivalent quantity of coal, converting a coal-fired steam
EGU to burn only natural gas would reduce the unit's CO2
emissions by approximately 40 percent. The CO2 reductions
are generally proportional to the amount of gas substituted for coal,
so if an EGU continued to burn mostly coal while co-firing natural gas
as, for example, 10 percent of the EGU's total heat input, the
CO2 emission reductions would be approximately four percent.
The EPA determined that the most significant cost associated with
natural gas conversion or co-firing is likely to be the incremental
cost of natural gas relative to the cost of coal. Using Energy
Information Administration (EIA) fuel price projections, we estimated
that the CO2 reductions achieved through natural gas
conversion or co-firing at an average coal-fired steam EGU would have
costs ranging from approximately $83 to $150 per metric ton.\100\ Thus,
although there have been past instances where coal-fired steam EGUs
have been converted to natural gas, and we expect some additional
future conversions where circumstances at individual EGUs make the
option particularly attractive, for the industry as a whole we would
expect that other approaches could reduce CO2 emissions from
existing EGUs at lower cost. However, gas conversion or co-firing would
be available to states and sources as a compliance option, and, as
noted later in the preamble, we are seeking comment on whether this
option should be considered part of the BSER.
---------------------------------------------------------------------------

    \100\ The lower end of the range is for conversion to 100
percent natural gas, which would allow EGUs to eliminate certain
fixed operating and maintenance costs associated with coal use but
not natural gas use. See Section VI.C.5.a below for further
discussion.
---------------------------------------------------------------------------

3. CO2 Emission Reductions Achievable Through Re-Dispatch
From Steam EGUs to NGCC Units
    The second grouping of CO2 emission reduction options
evaluated by the EPA in the BSER analysis involves reducing emissions
by shifting generation among affected EGUs. An obvious alternative to
substituting natural gas for coal at individual steam EGUs through
conversion or co-firing is instead to use natural gas to generate
electricity at a different affected EGU with a better heat rate--
notably a natural gas combined cycle (NGCC) unit--and to substitute
that electricity for electricity from the coal-fired steam EGU, thus
resulting in lower emissions from the coal-fired steam EGU and lower
emissions from the set of affected EGUs overall.\101\ The electricity
system is physically interconnected or networked and operated on an
integrated basis across large regions. System operators routinely
increase or decrease the electricity output of individual EGUs to
respond to changes in electricity demand, equipment availability, and
relative operating costs (or bid prices) of individual EGUs while
observing reliability-related constraints. It has long been common
industry practice for system operators to choose from among multiple
EGUs when deciding which EGU to ``dispatch'' to generate the next
increment of electricity needed to meet demand. Thus, the well-
established practices of the industry support our evaluation of ``re-
dispatch'' of generation from steam EGUs to NGCC units as a potential
component of the basis for the BSER to reduce CO2 emissions
from existing EGUs.
---------------------------------------------------------------------------

    \101\ Strategies in this grouping also include shifting
generation from steam EGUs burning oil or natural gas to more
efficient NGCC units.
---------------------------------------------------------------------------

    NGCC units can produce as much as 46 percent more electricity from
a given quantity of natural gas than steam EGUs,\102\ making the re-
dispatch approach a significantly less expensive way to reduce
CO2 emissions than conversion or co-firing of coal-fired
steam EGUs to burn natural gas. For example, using the same EIA fuel
cost projections as were used above to estimate the costs of natural
gas conversion or co-firing, we estimated that the cost of
CO2 reductions achievable by substituting electricity from
an existing NGCC unit for electricity from an average coal-fired steam
EGU would be approximately $30 per metric ton.\103\
---------------------------------------------------------------------------

    \102\ This estimate assumes an average heat rate of 10,434 Btu/
kWh for coal fossil fuel-fired steam units between 400 and 600 MW
and 7,130 Btu/kWh for NGCC units between 400 and 600 MW. See
NEEDSv.5.13 at http://www.epa.gov/powersectormodeling/BaseCasev513.html.
    \103\ See Section VI.C.2 below for further discussion.
---------------------------------------------------------------------------

    Our analysis indicated that the potential CO2 reductions
available through re-dispatch from steam EGUs to NGCC units are
substantial. As of 2012, there was approximately 245 GW of NGCC
capacity in the United States, 196 GW of which was placed in service
between 2000 and 2012.\104\ In 2012, the average utilization rate of
U.S. NGCC capacity was 46 percent, well below the utilization rates the
units are capable of achieving. In 2012 approximately 10 percent of
NGCC plants operated at annual utilization rates of 70 percent or
higher, and 19 percent of NGCC units operated at utilization rates of
at least 70 percent over the summer season. Average reported
availability generally exceeds 85 percent. We recognize that the
ability to increase NGCC utilization rates may also be affected by
infrastructure and system considerations, such as limits on the ability
of the natural gas industry to produce and deliver the increased
quantities of natural gas, the ability of steam EGUs to reduce
generation while remaining ready to supply electricity when needed in
peak demand hours, and the ability of the electric transmission system
to accommodate the changed geographic pattern of generation. However,
these considerations have not limited past rapid increases in NGCC
generation levels, as indicated by a 20 percent increase in natural gas
consumption for

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

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

    As discussed below in Section VI.C.2, the data and considerations
cited above support our assessment that an average NGCC utilization
rate in a range of 65 to 75 percent is a reasonable target for the
amount of additional NGCC generation that could be substituted for
higher carbon generation from steam EGUs as part of the BSER.\106\ If
re-dispatch consistent with a target average NGCC utilization rate of
70 percent had been achieved in 2012, the combined CO2
emissions of steam EGUs and NGCCs would have been reduced by
approximately 13 percent.
---------------------------------------------------------------------------

    \106\ Substitution would only occur to the extent that there is
both NGCC capacity whose generation could be increased and steam
EGUs whose generation could be decreased.
---------------------------------------------------------------------------

    Finally, we also note that mechanisms for encouraging re-dispatch
as a CO2 reduction measure have already been developed and
applied in the industry. Under both RGGI and California's Global
Warming Solutions Act, shifting generation from more carbon-intensive
EGUs to less carbon-intensive EGUs is a way to facilitate compliance
with regulatory requirements. In both cases, the industry has
demonstrated the ability to respond to the regulatory requirements of
these state programs.
4. CO2 Emission Reductions Achievable Through Other Actions
Underway in the Industry
    The third grouping of CO2 emission reduction options the
EPA evaluated in the BSER analysis encompasses other measures already
used in the industry and not included in the first two groupings. From
our evaluation of re-dispatch as an option for reducing CO2
emissions, it was apparent that relevant factors for consideration
include the integrated nature of the electricity system and the fact
that particular measures capable of reducing CO2 emissions
at EGUs were already being used and would continue to be used
throughout the industry, either for the purpose of compliance with
CO2 emission reduction requirements or to serve other
purposes and policy goals. That observation led us to consider what
other potential actions and options the industry was already using that
had resulted in or could result in, or support, the reduction of
CO2 emissions at EGUs. Again, we observed many such
instances, some taking place incidental to the routine operation of the
electricity system and others taking place in response to specific
state initiatives to reduce CO2 emissions from the power
sector. We concluded that there are two principal types of such
potential options for measures that support CO2 emission
reductions at EGUs affected under this proposal: Ongoing development
and use of low- and zero-carbon generating capacity, and ongoing
development and application of demand-side energy efficiency measures.
    Low-and zero-carbon generating capacity provides electricity that
can be substituted for generation from more carbon-intensive EGUs. More
than half the states already have established some form of state-level
renewable energy requirements, with targets calling on average for
almost 20 percent of 2020 generation to be supplied from renewable
sources. The EPA is unaware of analogous state policies to support
development of new nuclear units, but 30 states already have nuclear
EGUs (with five units under construction) and the generation from these
units is currently helping to avoid CO2 emissions from
fossil fuel-fired EGUs. Policies that encourage development of
renewable energy capacity and discourage premature retirement of
nuclear capacity could be useful elements of CO2 reduction
strategies and are consistent with current industry behavior. Costs of
CO2 reductions achievable through these policies have been
estimated in a range from $10 to $40 per metric ton.\107\
---------------------------------------------------------------------------

    \107\ See Section VI.C.3 below for further discussion.
---------------------------------------------------------------------------

    Demand-side energy efficiency programs produce electricity-
dependent services with less electricity, and thereby support reduced
generation from existing fossil fuel-fired EGUs by reducing the demand
for that generation. Reduced generation results in lower CO2
emissions. More than 40 states already have established some form of
demand-side energy efficiency polices, and individual states have
avoided up to 13 percent of their electricity demand. Again, policies
that encourage demand-side energy efficiency could be useful elements
of CO2 reduction strategies and are consistent with current
industry behavior. Using conservatively high estimates of the costs of
demand-side energy efficiency, the EPA estimates that the costs of
CO2 emission reductions achievable consistent with such
policies would be in a range of $16 to $24 per metric ton.\108\
---------------------------------------------------------------------------

    \108\ See Section VI.C.4 below for further discussion.
---------------------------------------------------------------------------

5. Summary of Building Blocks for the Best System of Emission Reduction
    Based on the analytic approach summarized above, the EPA has
identified the following four principal categories--``building
blocks''--of measures that provide the foundation of our BSER
determination for CO2 emissions from existing EGUs:
    1. Reducing the carbon intensity of generation at individual
affected EGUs through heat rate improvements.
    2. Reducing emissions from the most carbon-intensive affected EGUs
in the amount that results from substituting generation at those EGUs
with generation from less carbon-intensive affected EGUs (including
NGCC units under construction).
    3. Reducing emissions from affected EGUs in the amount that results
from substituting generation at those EGUs with expanded low- or zero-
carbon generation.
    4. Reducing emissions from affected EGUs in the amount that results
from the use of demand-side energy efficiency that reduces the amount
of generation required.
    Since they either result in improved operating efficiency or
support reductions in mass emissions at existing EGUs, each of the four
building blocks represents a demonstrated basis for reducing
CO2 emissions from affected EGUs that is already being
pursued in the power sector. In the next subsection, we discuss each of
the building blocks at length. Our approach for applying the building
blocks to each state's circumstances in order to develop state goals is
described in Section VII of this preamble.

C. Detailed Discussion of Building Blocks and Other Options Considered

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

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

    \109\ A ``steam EGU'' is an EGU that combusts fuel in a boiler
and uses the combustion heat to create steam which is then used to
drive a steam turbine that drives a generator to create electricity.
In contrast, a ``combined cycle EGU'' combusts fuel in a combustion
turbine that directly drives a generator, and the waste heat is then
used to create steam which is used to drive a steam turbine that
drives a generator to create more electricity. Steam EGUs can
combust a wide variety of fuels including coal and natural gas.
Combined cycle EGUs are more efficient at converting fuel energy to
electric energy but are limited to gaseous or liquid fuels, most
commonly natural gas or distillate oil. Almost all existing coal-
fired EGUs are steam EGUs (the exceptions are integrated
gasification combined cycle (IGCC) units where coal is processed to
create a gaseous fuel that is then combusted in a combined cycle
unit).
---------------------------------------------------------------------------

    The EPA is aware of the potential for ``rebound effects'' from
improvements in heat rates at individual EGUs. In this context, a
rebound effect would occur where, because of an improvement in its heat
rate, an EGU experiences a reduction in variable operating costs that
makes the EGU more competitive relative to other EGUs and consequently
raises the EGU's generation output. The increase in the EGU's
CO2 emissions associated with the increase in generation
output would offset the reduction in the EGU's CO2 emissions
caused by the decrease in its heat rate and rate of CO2
emissions per unit of generation output. The extent of the offset would
depend on the extent to which the EGU's generation output increased (as
well as the CO2 emission rates of the EGUs whose generation
was displaced). The EPA considers the rebound effect to be a potential
concern if heat rate improvements were the only approaches being
considered for the BSER, but believes that the effect can be addressed
by establishing the BSER as a combination of approaches that includes
not only heat rate improvements but also approaches that will encourage
reductions in electricity demand or increases in generation from lower-
or zero-emitting EGUs. The topic of potential rebound effects is
discussed further in Sections VI.D and VI.E below. For purposes of the
remainder of this subsection, no rebound effect is assumed.
    Although heat rate improvements have the potential to reduce
CO2 emissions from all types of affected EGUs, the EPA's
analysis indicates the potential is significantly greater for coal-
fired steam EGUs than for other EGUs, and for purposes of determining
the best system of emission reduction at this time, the EPA is
conservatively proposing to base its estimate of CO2
emission reductions from heat rate improvements on coal-fired steam
EGUs only.\110\ The remainder of this subsection focuses on the EPA's
analysis of potential heat rate improvements from coal-fired steam
EGUs. Our analysis of potential heat rate improvements from other types
of affected EGUs is addressed in Section VI.C.5 below.
---------------------------------------------------------------------------

    \110\ As noted in Section VI.C.5.d below, we are taking comment
on including heat rate improvement opportunities at other EGU types
in the basis for supporting the BSER. Also, for compliance purposes
states and EGUs would be able to rely on CO2 emission
reductions achieved through heat rate improvements at other types of
EGUs.
---------------------------------------------------------------------------

a. Ability of Heat Rate Improvements To Reduce CO2 Emissions
    The heat rate of an EGU is the amount of fuel energy input needed
(Btu, higher heating value basis) to produce 1 kWh of net electrical
energy output (and useful thermal energy in the case of cogeneration
units).\111\ The current weighted-average annual heat rate of U.S.
coal-fired EGUs in the range of 400 to 600 MW is approximately 10,434
Btu per net kWh.\112\ Because an EGU's CO2 emissions are
driven primarily by the amount of fuel consumed, at any fossil fuel-
fired EGU there is a strong correlation between potential heat rate
improvements and potential reductions in carbon-intensity.\113\
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    \111\ Heat rate can also be expressed on a gross basis--i.e.,
fuel input per kWh of gross electricity generated--instead of a net
basis--i.e., fuel input per kWh of net electricity sent to the grid.
The difference between gross and net electricity is the amount of
electricity used at the plant to operate components such as pumps,
fans, motors, and pollution control devices.
    \112\ See NEEDSv.5.13 at http://www.epa.gov/powersectormodeling/BaseCasev513.html.
    \113\ A small portion of some fossil fuel-fired EGU's
CO2 emissions may come from sources other than fuel, such
as limestone or other carbonates used to capture sulfur dioxide
(SO2) and/or hydrogen chloride (HCl) in a scrubber or dry
injection system. However, CO2 emissions from these
reagents will also tend to be reduced by heat rate improvements,
because reagent usage, and the associated CO2 emissions,
will decrease when the amount of fuel used decreases.
---------------------------------------------------------------------------

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

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

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

discerning the existence and possible magnitude of potential heat rate
improvements. Many EGUs regularly report to both the EPA and the U.S.
Department of Energy's Energy Information Administration (EIA)
CO2 emissions and generation data, from which heat input and
heat rate data can be computed. We have reviewed these data and have
identified several ``data apparent'' instances where an EGU's heat rate
experienced a substantial improvement in a short time--presumably
because of equipment upgrades installed at that point in time--that was
then sustained. These heat rate improvements ranged from 3 to 8
percent. In combination with bottom-up engineering analysis and the
further, more detailed EPA analysis of hourly data summarized below,
the individual EGU heat rate histories provide a strong basis for
considering heat rate improvement as a meaningful potential approach to
reducing the carbon intensity of generation at individual affected
fossil fuel-fired EGUs.
b. Amounts of Heat Rate Improvements
    In order to estimate the technical potential of heat rate
improvement opportunities at existing fossil fuel-fired EGUs suggested
by the discussion above, the EPA pursued two principal areas of
analysis. The first area concerned the heat rate improvements that
could be achieved by reducing heat rate variability at individual coal-
fired EGUs through adoption of best practices for operation and
maintenance. The second area concerned heat rate improvement
opportunities that could be achieved through further equipment
upgrades. Both analyses are summarized below along with our
conclusions, and are discussed in greater detail in the GHG Abatement
Measures TSD.
    For the best practices analysis, the EPA worked with the hourly
data reported to the EPA by affected EGUs subject to the monitoring and
reporting requirements of 40 CFR Part 75. The reported data include
hourly heat input and, for most reporting EGUs, hourly gross
generation, making it possible to compute hourly gross heat rates. We
used the hourly data to assess variability in the hourly gross heat
rates of approximately 900 individual coal-fired steam EGUs over the
period from 2002 to 2012. Specifically, the EPA evaluated the
consistency with which individual EGUs maintained their hourly heat
rates over time. We expected that a certain degree of short-term heat
rate variability was caused by factors beyond operators' control,
notably variation in hourly ambient temperature and hourly load, and
preliminary analysis confirmed our expectation. We therefore controlled
for variation in those factors by grouping the observed hourly heat
rate data for each EGU into subsets corresponding to ranges of hourly
ambient temperatures and hourly load levels.\115\ We believe that the
amount of residual variability within each data subset is an indication
of the degree of technical potential to improve the consistency with
which optimal heat rate performance is achieved by adopting operating
and maintenance best practices. For example, optimal heat rate
performance could be achieved with greater consistency through
practices such as turning off unneeded pumps at reduced loads,
installation of digital control systems, more frequent tuning of
existing control systems, or earlier like-kind replacement of worn
existing components. (Upgrades to existing equipment are considered
below.) By applying best practices to their operating and maintenance
procedures, owners and operators of EGUs could reduce heat rate
variability relative to average heat rates and, because the deviations
generally result in performance worse than the optimal heat rates,
improve the EGUs' average heat rates. Assuming that between 10 percent
and 50 percent of the deviation from top decile performance in each
subset of hourly heat rate observations within defined ranges of
temperature and load could be eliminated through adoption of best
practices, the result is a corresponding estimated range of 1.3 percent
to 6.7 percent technical potential for improvement in the average heat
rate of the entire fleet of coal-fired EGUs.\116\ Based on this
analysis, we believe a reasonable estimate for purposes of developing
state-specific goals is that affected coal-fired steam EGUs on average
could achieve a four percent improvement in heat rate through adoption
of best practices to reduce hourly heat rate variability. This estimate
corresponds to the elimination, on average across the fleet of affected
EGUs, of 30 percent of the deviation from top-decile performance in the
hourly heat rate for each EGU not attributable to hourly temperature
and load variation. We also solicit comment on the use of estimates up
to six percent, reflecting elimination on average of 50 percent of the
deviation from top-decile performance.
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    \115\ Temperature data are from the National Oceanic and
Atmospheric Administration's Integrated Surface Data, http://www.ncdc.noaa.gov/data-access/land-based-station-data/land-based-datasets/integrated-surface-database-isd. Electrical generation data
are from the EPA's Air Markets Program Data, http://ampd.epa.gov/ampd/.
    \116\ We examined whether the potential for heat rate
improvement varied based on EGU characteristics such as capacity,
boiler type, and location, and found no meaningful differences.
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    For the equipment upgrade analysis, we evaluated potential
opportunities to improve heat rates at affected EGUs through specific
upgrades identified in the 2009 Sargent & Lundy study. In that study,
Sargent & Lundy estimated ranges of potential heat rate improvement
achievable through a variety of equipment upgrades. We screened the
upgrades from the study to identify what we consider to be a reasonable
subset of equipment upgrades that would generally be beyond the scope
of investments we would expect to be made for purposes of achieving the
best-practices heat rate improvements discussed above. Based on the
average of the study's ranges of potential heat rate improvements from
the various upgrades in this subset, implementation of the full subset
of appropriate opportunities at a single EGU could be expected to
result in an aggregate heat rate improvement of approximately four
percent (incremental to the improvement achievable from adoption of
best practices). However, we recognize that this total may overstate
the average equipment upgrade opportunity across all EGUs because some
EGUs may have already implemented some of these upgrades. We therefore
propose to use as a data input for purposes of developing state goals
an estimate that, on average across the fleet of affected EGUs, only
half of the full equipment upgrade opportunity just described remains--
i.e., that for the fleet of affected EGUs as a whole, the technical
potential for heat rate improvements from equipment upgrades
incremental to the best-practices opportunity is on average two percent
rather than four percent. We solicit comment on increasing this figure
up to four percent.
    Some of the measures available to EGUs for reducing their carbon
intensity affect net heat rates rather than gross heat rates. Various
EGU components such as pumps, fans, motors, and pollution control
devices use electricity, a factor that is not accounted for in gross
heat rates (that is, fuel used per unit of gross energy output) but is
accounted for in net heat rates (that is, fuel used per unit of net
energy output sent to the electric grid or used for thermal purposes).
The electricity used by these components, referred to as auxiliary or
parasitic load, may represent from 4 to 12 percent of gross generation
at a coal-fired steam EGU.\117\ The analysis of

technical potential to reduce heat rate variability discussed above was
based on gross heat rate data. Like gross heat rate, parasitic load can
be addressed both through adoption of best practices and through
equipment upgrades, and some measures undertaken at EGUs may affect
parasitic load as well as gross heat rate. Because the hourly
generation data reported to the EPA represent gross generation, we have
less data available to directly analyze potential net heat rate
improvements than gross heat rate improvements. We have therefore not
included any separate estimate of parasitic load reductions achievable
through best practices in our goal-setting data inputs. However, these
opportunities would be available as a mechanism for reducing carbon-
intensity at affected EGUs and thus provide more flexibility and
opportunities for sources to improve their heat rates at reasonable
costs.\118\
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    \117\ Electric Power Research Institute 2011 Technical Report--
Program on Technology Innovation: Electricity Use in the Electric
Sector (Opportunities to Enhance Electric Energy Efficiency in the
Production and Delivery of Electricity).
    \118\ As proposed, the state-specific goals are expressed in the
form of CO2 emissions per net MWh, and reporting
requirements for sources would be in the same form, allowing
parasitic load reductions to contribute to improved measured heat
rates. If goals and reporting requirements were changed to a gross
MWh basis in the final rule, accounting for parasitic load
reductions as a source of CO2 reductions would require
additional procedures.
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    The total of the estimated potential heat rate improvements from
adoption of best practices to reduce heat rate variability and
implementation of equipment upgrades as discussed above is six percent.
This total is used as the data input for heat rate improvements in the
computation of proposed state goals discussed in Section VII.C below.
Because of the close relationship between an EGU's fuel consumption and
its CO2 emissions, a six percent heat rate improvement would
be associated with a reduction in CO2 emissions of
approximately six percent. We believe that this represents a reasonable
estimate of the technical potential for CO2 emission
reductions that would be achievable from affected coal-fired steam
EGUs, on average, through heat rate improvements as an element of the
best system of emission reduction.
    For purposes of developing the alternate set of goals on which we
are taking comment, as described in Section VII.E below, we have used a
more conservative estimate of a four percent heat rate improvement from
affected coal-fired EGUs on average. This level of improvement would be
consistent with those EGUs on average implementing best practices to
reduce heat rate variability without making further equipment upgrades,
or would be consistent with those EGUs on average implementing both
best practices and equipment upgrades, but to a lesser degree than we
have projected as being achievable for purposes of our proposal. We
view the four percent estimate as a reasonable minimum estimate of the
technical potential for heat rate improvement on average across
affected coal-fired steam EGUs.
c. Costs of Heat Rate Improvements
    By definition, any heat rate improvement made for the purpose of
reducing CO2 emissions will also reduce the amount of fuel
the EGU consumes to produce its electricity output. The cost
attributable to CO2 emission reductions therefore would be
the net cost to achieve the heat rate improvement after any savings
from reduced fuel expense. As summarized below, we estimate that, on
average, the savings in fuel cost associated with a six percent heat
rate improvement would be sufficient to cover much of the associated
costs, with the result that the net costs of heat rate improvements
associated with reducing CO2 emissions from affected EGUs
are relatively low.
    The EPA's most detailed estimates of the average costs required to
achieve the full range of heat rate improvements come from the 2009
Sargent & Lundy study discussed above. Based on the study, the EPA
estimated that for a range of heat rate improvements from 415 to 1205
Btus per kWh, corresponding to percentage heat rate improvements of 4
to 12 percent for a typical coal-fired EGU, the required capital costs
would range from $40 to $150 per kW. To correspond to the average heat
rate improvement of six percent that we have estimated to be achievable
through the combination of best practices and equipment upgrades, we
have estimated an average cost of $100 per kW, slightly above the
midpoint of the Sargent & Lundy study's range. At an estimated annual
capital charge rate of 14.3 percent, the carrying cost of an estimated
$100 per kW investment would be $14.30 per kW-year. For a coal-fired
EGU with a heat rate of 10,450 Btu per kWh, a utilization rate of 78
percent, and a coal price of $2.62 per MMBtu, a six percent heat rate
improvement would produce fuel cost savings of approximately $11.20 per
kW-year,\119\ leaving approximately $3.10 per kW-year of carrying cost
not recovered through fuel cost savings. At an average CO2
emission rate of 0.976 metric tons per MWh, the same six percent heat
rate improvement would reduce CO2 emissions by 0.40 metric
tons per kW-year.\120\ Thus, the average cost of CO2
reductions from heat rate improvements would be approximately $7.75 per
metric ton of CO2 ($3.10/0.40). If the average heat rate
improvement achievable for the $100 per kW investment were only four
percent, consistent with the heat rate improvement estimate in the
alternate goals on which we seek comment, the average cost of
CO2 reductions would be $11.63 per metric ton.\121\ On the
other hand, if an average heat rate improvement of four percent could
be achieved for an average investment of $50 per kW, reflecting an
assumption that the first improvements pursued would be the least
expensive ones, the average cost of CO2 reductions would
fall to $5.81 per metric ton.\122\
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    \119\ 10,450 Btu/kWh * 8760 hours/year * 78% utilization * $2.62
per MMBtu * 6% improvement * 0.000001 MMBtu/Btu = $11.2 per kW-year.
Data inputs for average coal-fired EGU heat rate, average coal-fired
EGU utilization, and average coal price are from the IPM 5.13 base
case for 2020.
    \120\ 8760 hours/year * 78% utilization * 0.976 metric tons/Mwh
* 6% improvement * 0.001 MW/kW = 0.40 metric tons of CO2
per kW-year. The estimated average coal-fired EGU CO2
emission rate per MWh is from the IPM 5.13 base case for 2020.
    \121\ $7.75 per metric ton of CO2 * 6%/4% = $11.63
per metric ton of CO2.
    \122\ $11.63 per metric ton of CO2 * $50/$100 = $5.81
per metric ton of CO2.
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    The EPA recognizes that the simplified cost analysis just described
will represent the costs for some EGUs better than others because of
differences in EGUs' individual circumstances. We further recognize
that reductions in the utilization rates of coal-fired EGUs anticipated
from other components proposed for inclusion in the best system of
emission reduction would tend to reduce the fuel savings associated
with heat rate improvements, thereby raising the effective cost of
achieving the CO2 emission reductions from the heat rate
improvements. Nevertheless, we still expect that the majority of the
investment required to capture the technical potential for
CO2 emission reductions from heat rate improvements would be
offset by fuel savings, and that the net costs of heat rate
improvements as an approach to reducing CO2 emissions from
existing fossil fuel-fired EGUs are reasonable.
    Based on the analyses of technical potential and cost summarized
above, we propose to find that a six percent reduction in the
CO2 emission rate of the coal-fired EGUs in a state, on
average, is a reasonable estimate of the amount of heat rate
improvement that can be implemented at a reasonable cost.\123\
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    \123\ We note that although we expect that heat rate
improvements are also available from other fossil fuel-fired EGUs,
we have conservatively not included CO2 emission rate
reductions for those EGUs in the state goals. However, as discussed
in Section VI.C.5.d below, we are requesting comment on this aspect
of the proposal. Further, states and sources would be free to use
heat rate improvements at those other units to help reach the state
goals.

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    We invite comment on all aspects of our analyses and findings
related to heat rate improvements, both as summarized here and as
further discussed in the Greenhouse Gas Abatement Measures TSD. As
noted earlier, we specifically request comment on increasing the
estimates of the amounts of heat rate improvement achievable through
adoption of best practices for operation and maintenance and through
equipment upgrades up to six percent and four percent, respectively,
representing a total potential improvement of up to ten percent,
particularly in light of the reasonable cost of heat rate improvements.
We also solicit comment on the quantitative impacts on the net heat
rates of coal-fired steam EGUs of operation at loads less than the
rated maximum unit loads.
2. Building Block 2--Dispatch Changes Among Affected EGUs
    The second element of the foundation for the EPA's BSER
determination for reducing CO2 emissions at affected fossil
fuel-fired EGUs goes to the achievement of reductions in mass emissions
at certain affected EGUs--in particular, fossil fuel-fired steam EGUs--
and entails an analysis of the extent to which generation at the most
carbon-intensive affected EGUs--again, in particular, fossil fuel-fired
steam EGUs--can be replaced with generation at less carbon-intensive
affected fossil fuel-fired EGUs--in particular, NGCC units that were in
operation or had commenced construction as of January 8, 2014, and are
therefore affected units for purposes of this rule.
a. Ability of Re-Dispatch To Reduce CO2 Emissions
    The nation's EGUs are interconnected by transmission grids
extending over large regions. EGU owners and grid operators, subject to
various reliability and operational constraints, use the flexibility
provided by these interconnections to prioritize among available EGUs
when deciding which units should be called upon (i.e., ``dispatched'')
to increase or decrease generation in order to meet electricity demand
at any point in time. Recognizing that increments of generation are to
some extent interchangeable, dispatch decisions are based on