the standard or emissions limitation it must meet.\350\ Each state has
flexibility in how it assigns the emission limitations to its affected
EGUs--and in fact, the state can be more stringent than the guidelines
require--but one of the state's choices is to convert the
CO2 emission performance rates into standards of
performance--which may incorporate emissions trading--for each of its
affected EGUs. If a state does so, then the affected EGUs may achieve
their emission limits by taking the actions that qualify as the BSER.
Since the BSER and, in this case its constituent elements, reflect the
criteria of reasonable cost and other BSER criteria, the BSER assures
that there is at least one pathway--the CO2 emission
performance rates--for the state and its affected EGUs to take that
achieves the requisite level of emission reductions, while, again,
assuring that the affected EGUs can achieve those emission limits

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    \371\ The EPA further addressed co-firing in the October 30,
2014 NODA. 79 FR 64549-51.
    \372\ CCS is also sometimes referred to as carbon capture and
sequestration.
---------------------------------------------------------------------------

    However, these co-firing and CCS measures are more expensive than
other available measures for existing sources. This is because the
integrated nature of the electricity system affords significantly lower
cost options, ones that fossil fuel-fired power plants

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

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

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

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

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

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

affected EGUs and do not result in non-air quality pollutants, and have
acceptable cost and energy implications on a source-by-source basis and
for the energy sector as a whole. In addition, as explained below, each
is adequately demonstrated. Importantly, past industry practice and
current trends strongly support each of the building blocks, as do
federal and state pollution control programs that require or result in
similar measures.
    For example, all of the measures in building blocks 2 and 3 have
been implemented for decades, initially for reasons unrelated to
pollution control, then in recent years in order to control non-GHG air
pollutants, and more recently, for purposes of CO2-emission
control by states and companies. Moreover, Congress itself recognized
in enacting the acid rain provisions of CAA Title IV that RE measures
reduce CO2 from affected EGUs. In addition, the EPA has
relied on the measures in building blocks 2 and 3 in other rules.
    It should also be noted that building blocks 2 and 3 also meet the
criteria for the BSER in combination with one another and with building
block 1, as described below.
    e. Actions that individual affected EGUs could take to apply or
implement the building blocks. We now turn to a summary of measures or
actions that individual EGUs could take to apply or implement the
building blocks and that are therefore, in that sense, part of the
BSER.
    (1) Improvement in CO2 emission rate at the unit.
    An affected EGU may take steps to improve its CO2
emission rate as discussed above for the source category as a whole. As
discussed in section V.C., the record makes clear that coal-fired steam
EGUs can make, and have made, heat rate improvements to a greater or
lesser degree, resulting in reductions in CO2 emissions. The
resulting improvement in an EGU's CO2 emission rate would
help the EGU achieve an emission limit imposed in the form of an
emission rate. If the EGU's emission limit is imposed in the form of a
mass standard, the heat rate improvement would also lower the EGU's
mass emissions provided that the EGU held the amount of its generation
constant or increased its generation by a smaller percentage than the
efficiency improvement. Under a mass-based standard that incorporates
emission trading, an EGU that improves its heat rate would need fewer
emission allowances for each MWh of generation whatever level of
generation it chose to produce.
    (2) Actions to implement measures in building blocks 2 and 3.
    Viewing the BSER from the perspective of an individual EGU, there
are several ways that affected EGUs can access the measures in building
blocks 2 and 3, thanks to the integrated nature of the electricity
system, coupled with the system's high degree of planning and
reliability mechanisms. The affected EGUs can: (a) Invest in lower- or
zero-emitting generation, which will lead to reductions in higher-
emitting generation at other units in the integrated system; (b) reduce
their generation, which in the presence of emission reduction
requirements applicable to the source category as a whole will have the
effect of increasing demand for, and thereby incentivize investment in,
the measures in the building blocks elsewhere in the integrated system;
or (c) both invest in the measures in the building blocks and reduce
their own generation, effectively replacing their generation with
cleaner generation. The availability of these options is further
enhanced where the individual EGU is operating under a standard of
performance that incorporates emissions trading.
    (a) Investment in measures in building blocks 2 and 3.
    An affected EGU may take the following actions to invest in the
measures in building blocks 2 and 3. For building block 2, the owner/
operator of a steam EGU may increase generation at an existing NGCC
unit it already owns, or one that it purchases or invests in. In
addition, the owner/operator may, through a bilateral transaction with
an existing NGCC unit, pay the unit to increase generation, and acquire
the CO2-reducing effects of that increased generation in the
form of a credit, as discussed below.
    Similarly, for building block 3, an owner/operator of an affected
EGU may build, or purchase an ownership interest in, new RE generating
capacity and acquire the CO2-reducing effects of that
increased generation. Alternatively, an owner/operator may, through
bilateral transactions, purchase the CO2-reducing effects of
that increased generation from renewable generation providers, again,
in the form of a credit.
    In case of an investment in either building block 2 or building
block 3 by a unit subject to a rate-based form of CO2
performance standard, it would be reasonable for state plans to
authorize affected EGUs to use an approved and validated instrument
such as an ``emission rate credit'' (ERC) representing the emissions-
reducing benefit of the investment.\375\
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    \375\ Criteria for issuance of valid ERCs and for tracking
credits after issuance are discussed in section VIII below.
---------------------------------------------------------------------------

    When combined with reduced generation, either at the affected EGU
or elsewhere in the interconnected system, the types of actions listed
above would be fully equivalent to building blocks 2 and 3 when viewed
from the perspective of the overall source category. Thus, a source
could achieve a standard of performance identical to the applicable
CO2 emission performance rate in the EPA emission
guidelines, through implementation of the actions described above for
building blocks 2 and 3, along with the actions described further above
for building block 1.
    The EPA anticipates that in instances where section 111(d) plans
provide for the use of instruments such as ERCs as a mechanism to
facilitate use of these measures, organized markets will develop so
that owner/operators of affected EGUs that have invested in measures
eligible for the issuance of ERCs will be able to sell those credits
and other affected EGUs will be able to purchase them. Such markets
have developed for other instruments used for emissions trading
purposes. For example, liquid markets for SO2 allowances
developed rapidly following the implementation of Title IV of the 1990
Clean Air Act Amendments establishing the Acid Rain Program. Members of
Congress and industry had expressed concern during the legislative
debate that the lack of a liquid SO2 allowance market would
create challenges for affected sources that needed to acquire
allowances to meet their compliance obligations. Congress added
statutory provisions to ensure that, should a market not develop,
sources could purchase needed allowances directly from the EPA. In
fact, these provisions went unused because a liquid market for
allowances did develop very quickly. Sources engaged in allowance
transactions directly with other sources as they sought to lower
compliance costs. Market intermediaries offered services to sources to
match allowance buyers and sellers and helped sources understand their
compliance options. Trade associations worked with members to develop
standardized contracts and other tools to facilitate allowance
transactions, thereby reducing transaction costs. Similar developments
have occurred in state-

level renewable portfolio standard programs.\376\
---------------------------------------------------------------------------

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

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

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

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

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

    (c) Emissions trading.
    As described above, viewed from the perspective of the source
category as a whole, it is reasonable for our analysis of the BSER to
include an element of source-category-wide multi-unit compliance which
could be implemented via a state-set standard of performance
incorporating emissions trading, under which EGUs could engage in
trading of rate-based emission credits or mass-based emission
allowances. By the same token, viewed from the perspective of an
individual EGU, consideration of the ready availability to states of
the opportunity to establish standards of performance that incorporate
emissions trading is integral to our analysis. Accordingly, our
assessment of the actions available to individual EGUs for achieving
standards of performance reflecting the BSER includes the purchase of
rate-based emission credits or mass-based emission allowances, because
one of the things an affected EGU can do to achieve its emission limit
is to buy a credit or an allowance from another affected EGU that has
over-complied. The use of purchased credits or allowances would have to
be authorized, of course, in the purchasing EGUs' states' section
111(d) plans and would have to meet conditions set out for such
approaches in section VIII below. The role of emissions trading in the
BSER analysis is discussed further in section V.A.2.f. below.
    f. The role of emissions trading. In making its BSER determination
here, the EPA examined a number of technologies and emission reduction
measures that result in lower levels of CO2 emissions and
evaluated each one on the basis of the several criteria on which the
EPA relies in determining the BSER. In contrast to section 111(b),
however, section 111(d)(1) obliges the states, not the EPA, to set
standards of performance for the affected EGUs in order to implement
the BSER. Accordingly, with respect to each measure or control strategy
under consideration, the EPA also evaluated whether or not the states
could establish standards of performance for affected EGUs that would
allow those sources to adopt the measure in question. In this case, the
EPA identified a host of factors that persuaded us that states could--
and, in fact, may be expected to--establish standards of performance
that incorporate emissions trading.\379\ These wide-ranging factors
include (i) the global nature of the air pollutant in question--i.e.,
CO2; (ii) the transactional nature of the industry; (iii)
the interconnected functioning of the industry and the coordination of
generation resources at the level of the regional grid; (iv) the
extensive experience that states--and EGUs--already have with emissions
trading; and (v) material in the record demonstrating strong interest
on the part of many states and affected EGUs in using emissions trading
to help meet their obligations.\380\
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    \379\ As an alternative to authorizing trading that would still
provide a degree of multi-unit flexibility, a state could choose in
its state plan to give an owner of multiple affected EGUs
flexibility regarding how the owner distributes any credits or
allowances it acquires among its affected EGUs.
    \380\ Numerous states submitted comments urging the EPA to allow
states to develop trading programs, as suggested in the proposal,
including interstate trading programs. They include, for example,
Alabama (EPA should develop and issue guidelines that allow options
for multi[hyphen]state plans and interstate credit trading programs,
comment 23584), California (EPA should provide flexibility for
allowance trading programs to be integrated into state plans,
comment 23433), Hawaii (supports use of emission credit trading with
other entities to achieve compliance, comment 23121), Massachusetts
(EPA should explore possibility of hosting a third[hyphen]party
emissions trading bank that can allow states interested in allowance
trading to plug and play in to a wider, more cost[hyphen]effective
market, comment 31910), Michigan (supports emissions trading
programs, comment 23987), Minnesota (develop model trading rule that
states could incorporate by reference as part of plan and
automatically be included in multi-state mass trading program,
comment 23987), North Carolina (EPA should examine a system of
banking and trading for energy efficiency, comment 23542), Oregon
(EPA should expand the explicit options for multi[hyphen]state plans
beyond cap[hyphen]and-trade, comment 20678), Washington (supporting
trading, comment 22764), Wisconsin (requesting EPA to develop a
national trading program, Post[hyphen]111(d) Proposal Questions to
EPA WI Questions for 7/16 Hub call).
    In addition, several groups of states supported trading
programs: Georgetown Climate Center (a group of state environmental
agency leaders, energy agency leaders, and public utility
commissioners from California, Colorado, Connecticut, Delaware,
Illinois, Maine, Maryland, Massachusetts, Minnesota, New Hampshire,
New York, Oregon, Rhode Island, Vermont, and Washington) (``We
believe states should have maximum flexibility to determine what
kinds of collaborations might work for them. These could include
submission of joint plans, standardized approaches to trading
renewable or energy efficiency credits. . . . We also encourage EPA
to help facilitate such interstate agreements or multi-state
collaborations by working with states to either identify or provide
a platform or framework that states may elect to use for the
tracking and trading of avoided generation or emissions credits due
to interstate efficiency or renewable energy.'' comment 23597, at
39-40); RGGI (including Connecticut, Delaware, Maine, Maryland,
Massachusetts, New Hampshire, New York, Rhode Island, Vermont)
(``[E]very serious proposal to reduce carbon emissions from EGUs,
from proposed US legislation to programs in place in California and
Europe, has identified allowance trading as the best approach.''
Comment 22395 at 7-8); Western States Center for New Energy Economy
(including Arizona, California, Colorado, Idaho, Montana, Nevada,
Oregon, South Dakota, Utah, Washington) (``Some degree of RE and EE
credit trading among states may support compliance, even in the
absence of a comprehensive regional plan. Therefore, EPA should
support approaches which allow states flexibility to allocate credit
for these zero-carbon resources, along with approaches which allow
states to reach agreements on the allocation of carbon liabilities.
This includes ensuring that existing tracking mechanisms for
renewable energy in the West, such as the Western Renewable Energy
Generation Information System (WREGIS), are compatible with the
final proposal.'' Comment 21787 at 5); Midcontinent States
Environmental and Energy Regulators (including Arkansas, Illinois,
Michigan, Minnesota Missouri, Wisconsin) (EPA should also provide
states with optional . . . systems (or system) for tracking
emissions, allowances, reduction credits, and/or generation
attributes that states may choose to use in their 111(d) plans,''
comment 22535 at 3).
    In addition, trading programs were supported by, among others, a
group of Attorneys General from 11 states and the District of
Columbia. Comment 25433 (Attorneys General from New York,
California, Connecticut, Maine, Maryland, Massachusetts, New Mexico,
Oregon, Rhode Island, Vermont, Washington, District of Columbia, and
New York City Corporation Counsel).
    Numerous industry commenters also supported trading, including
Alliant Energy Corporate Services, Inc. (comment 22934), Calpine
(comment 23167), DTE Energy (comment 24061), Exelon (comment 23428
and 23155), Michigan Municipal Electric Association (MMEA) (comment
23297), National Climate Coalition (comment 22910), Pacific Gas and
Electric Company (comment 23198), Western Power Trading Forum (WPTF)
(comment 22860). Environmental advocates also supported trading,
including Clean Air Task Force (comment 22612), Environmental
Defense Fund (comment 23140), Institute for Policy Integrity, New
York University School of Law (comment 23418).
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    The states' and EGUs' interest in emissions trading is rooted in
the well-recognized benefits that trading provides. The experience of
multiple trading programs over many years has shown that some units can
achieve emission reductions at lower cost than others, and a system
that allows for those lower-cost reductions to be maximized is more
cost-effective overall to the industry and to society. Trading provides
an affected EGU other options besides direct implementation of emission
reduction measures in its own facility or an affiliated facility when
lower-cost emission reduction opportunities exist elsewhere.
Specifically, the affected EGU can cross-invest, that is, invest in
actions at facilities owned by others, in exchange for rate-based
emission credits or mass-based emission allowances. Through cross-
investment, trading allows each affected EGU to access the control
measures that other affected EGUs decide to implement, which in this
case include all the building blocks as well as other measures.
    Accordingly, our analysis of the measures under consideration in
our BSER determination reflected the well-

founded conclusion that it is reasonable for states to incorporate
emissions trading in the standards of performance they establish for
affected EGUs and that many, if not all, would do so.\381\
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    \381\ As discussed in the Legal Memorandum, the EPA has
promulgated other rulemakings, including the transport rulemakings--
the NOX SIP Call and CAIR, which required states to
submit SIPs, and CSAPR, which allows SIPs--on the premise of
interstate emission trading.
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    Whether viewed from the perspective of an individual EGU or the
source category as a whole, emissions trading is thus an integral part
of our BSER analysis. Again, we concluded that this is reasonable given
the global nature of the pollutant, the transactional and
interconnected nature of this industry, and the long history and
numerous examples demonstrating that, in this sector, trading is
integral to how regulators have established, and sources have complied
with, environmental and similar obligations (such as RE standards) when
it was appropriate to do so given the program objective. The
reasonableness is further demonstrated by the numerous comments (some
of which are noted above) from industry, states, and other stakeholders
in this rulemaking that supported allowing states to adopt trading
programs to comply with section 111(d) and encouraged EPA to facilitate
trading across state lines through the use of trading-ready state
plans. The EPA's reliance on trading in its BSER determination does not
mean, however, that states are required to establish trading programs
(just as states are not required to implement the building blocks that
comprise BSER). Nor does it mean that trading is the only transactional
approach that we could have considered in setting the BSER or that
states could use to effectuate the building blocks were they to decide
that they did not want to take on the responsibility of running a
trading program. Rather, it is simply a recognition of the nature of
this industry and the long history of trading as an important
regulatory tool in establishing regulatory regimes for this industry
and its reasonable availability to states in establishing standards of
performance.
    As an initial matter, trading is permissible for these emission
guidelines because CO2 is a global pollutant; the location
of its emission does not affect the location of the environmental harm
it causes. For CO2, it is the total amount of emissions from
the source category that matters, not the specific emissions from any
one EGU. The fact that trading allows sources to shift emissions from
one location to another does not impede achievement of the
environmental goal of reducing CO2 pollution. In its
character as a pollutant whose impacts extend beyond local areas,
CO2 pollution resembles to some extent the regional
SO2 pollution that Congress chose to address with the
emissions trading program enacted in Title IV of the 1990 CAA
Amendments. The argument in support of trading approaches is even
stronger for CO2 pollution, whose adverse effects are global
rather than merely regional like the SO2 emissions
contributing to acid precipitation.
    Further, as discussed elsewhere in the preamble, the utility power
sector--and the affected EGUs and other generation assets that it
encompasses--has a long history of working on a coordinated basis to
meet operating and environmental objectives, necessitated and
facilitated by the unique interconnectedness and interdependence of the
sector. That history includes joint dispatch for economic and
reliability purposes, both within large utility systems and in multi-
utility power pools that have evolved into RTOs; joint power plant
ownership arrangements; and long-term and short-term bilateral power
purchase arrangements. More recently, the sector's history also
includes emissions trading programs designed by Congress, the EPA, and
the states to address regional environmental problems and, most
recently, climate change. Examples of such programs are noted below.
    Essentially, trading does nothing more than commoditize compliance,
with the following two important results emerging from that: It reduces
the overall costs of controls and spreads those costs among the entire
category of regulated entities while providing a greater range of
options for sources that may not want to make on-site investments for
controlling their emissions and may prefer to make the same investment,
via the purchase of the tradable compliance instrument, at another
generating source. Building blocks 2 and 3 entail affected EGUs
investing in increased generation from existing NGCC units and RE. The
affected EGUs could do so in any number of ways, including acquiring
ownership interests in existing NGCC or RE facilities or entering into
bilateral transactions with the owners of existing NGCC facilities or
RE sources. As discussed elsewhere, it is reasonable to expect that
these actions can develop into discrete, tradable commodities (e.g., an
ERC) and that liquid markets will develop, which would reduce
transaction costs and allow an affected EGU to comply with its emission
limits by purchasing discrete units in amounts tailored closely to its
compliance needs. The existence of such tradable commodities also
incentivizes over-compliance by affected EGUs, which can then sell
their over-compliance in the form of ERCs or allowances to other
affected EGUs. Moreover, as noted elsewhere, the opportunity to trade
is consistent with the EPA's regional approach for the building blocks.
    By the same token, the opportunity to trade incentivizes affected
EGUs to over-comply with building block 1. Thus, the opportunity to
trade supports the EPA's assumptions about what an average affected EGU
can achieve with regards to heat rate improvement even if each and
every affected EGU cannot achieve that level of improvement. In
addition, trading incentivizes affected EGUs to consider low-cost, non-
BSER methods to reduce emissions as well, and, as discussed below,
there are numerous non-BSER methods, ranging from implementation of
demand-side EE programs to natural gas co-firing.
    Trading has become an important mechanism for achieving
environmental goals in the electricity sector in part because trading
allows environmental regulators to set an environmental goal while
preserving the ability of the operators of the affected EGUs to decide
the best way to meet it taking account of the full range of
considerations that govern their overall operations. For example,
commenters were concerned that because of building block 2, the
emission guidelines would require state environmental regulators to
make dispatch decisions for the electricity markets, a role that state
environmental regulators do not currently play. Although building block
2 entails substituting existing NGCC generation for steam generation,
implementing the emission limits that are based in part on building
block 2 through a trading program provides the individual affected EGUs
with a great deal of control over their own generation while the
industry as a whole achieves the environmental goals. For example,
individual steam generators have the option of maintaining their
generation as long as they acquire additional ERCs. Moreover, trading
provides a way for states to set standards of performance that realize
the required emissions reduction without requiring any form of
``environmental dispatch'' because, as many existing trading programs
have shown, monetization of the environmental constraint is consistent
with a least-cost dispatch system. Trading also supports the EPA's
approach to the ``remaining useful life'' provision in section
111(d)(1) because with trading, an affected EGU with a

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

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

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

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

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

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

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

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

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

    b. Approach to quantification of emission reductions from increased
RE generation. In the June 2014 proposal, the EPA described two
possible approaches for quantifying the amount of emission reductions
achievable from affected EGUs through the use of RE generation. The
proposed approach used information on state RPS aggregated at a
regional level along with historical RE generation data to project the
amount of RE generation used in quantifying the emission reductions
achievable through the BSER. The alternative approach used information
on the technical and market potential for development of renewable
resources in each state to project the RE-related emission reductions.
In the October 30, 2014 NODA, we sought comment on an additional
approach of aggregating the state-level information to a regional
level, as suggested by some commenters. In this final rule we are
adopting a combination of these approaches that uses historical RE
generating capacity deployment data aggregated to a regional level,
supported and confirmed by projections of market potential developed
through a techno-economic approach.
    In the June 2014 proposal, RE generation was also quantified as
generation from total--that is, existing and new--RE generating
capacity, a formulation that was consistent with the formulation of
most RPS, which are typically framed in terms of total rather than
incremental generation. In response to the EPA's request for comment on
this approach, commenters observed that the approach was inconsistent
with the approach taken for other building blocks, and that generation
from RE generating capacity that already existed as of 2012 should not
be treated as reducing emissions of affected EGUs from 2012 levels. As
just noted, we are not using the RPS-based methodology in the final
rule, and we agree with comments that quantification of RE generation
on an incremental basis is both more consistent with the treatment of
other building blocks and more consistent with the general principle
that the BSER should comprise incremental measures that will reduce
emissions below existing levels, not measures that are already in
place, even if those in-place measures help current emission levels be
lower than would be the case without the measures. The final rule
therefore defines the RE component of the BSER in terms of incremental
rather than total RE generation.\387\ Further details regarding the
final rule's quantification of RE generation are provided in section
V.E. below.
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    \387\ Generation from existing RE capacity will continue to make
compliance with mass-based standards easier to achieve by making the
overall amount of fossil fuel-fired generation that is required to
meet the demand for energy services lower than it would otherwise
be, thereby keeping CO2 emissions lower than they would
otherwise be.
---------------------------------------------------------------------------

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

retirement. Further, based in part on comments received on another
aspect of the proposal--specifically, the proposed inclusion of
existing RE generation in the goal-setting computations--we believe
that it is inappropriate to base the BSER in part on the premise that
the preservation of existing low- or zero-carbon generation, as opposed
to the production of incremental, low- or zero-carbon generation, could
reduce CO2 emissions from current levels. Accordingly, we
have determined not to reflect either of the nuclear elements in the
final BSER.
    Generation from under-construction or other new nuclear units and
capacity uprates at existing nuclear units would still be able to help
sources meet emission rate-based standards of performance through the
creation and use of credits, as noted in section V.A.6.b. and section
VIII.K.1.a.(8), and would help sources meet mass-based standards of
performance through reduced utilization of fossil generating capacity
leading to reduced CO2 emissions at affected EGUs. However,
consistent with the reasons just discussed for not reflecting
preservation of existing nuclear capacity in the BSER--namely, that
such preservation does not actually reduce existing levels of emissions
from affected EGUs--the rule does not allow preservation of generation
from existing or relicensed nuclear capacity to serve as the basis for
creation of credits that individual affected EGUs could use for
compliance, as further discussed in section VIII.K.1.a.(8).\388\
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    \388\ As with generation from existing RE capacity, generation
from existing nuclear capacity will continue to make compliance with
mass-based standards easier to achieve by making the overall amount
of fossil fuel-fired generation that is required to meet the demand
for energy services lower than it would otherwise be, thereby
keeping CO2 emissions lower than they would otherwise be.
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    d. Exclusion from the BSER of emission reductions from demand-side
EE. The June 2014 proposal included demand-side EE measures in building
block 4 as part of the BSER. The EPA took comment on the attributes of
each of the proposed building blocks, and building block 4 was a topic
of considerable controversy among commenters. While many commenters
recognized demand-side EE as an integral part of the electricity
system, emphasized its cost-effectiveness as a means of reducing
CO2 emissions from the utility power sector, and strongly
supported its inclusion in the BSER, other commenters expressed
significant concerns.
    As explained in section V.B.3.c.(8) below, our traditional
interpretation and implementation of CAA section 111 has allowed
regulated entities to produce as much of a particular good as they
desire provided that they do so through an appropriately clean (or low-
emitting) process. While building blocks 1, 2, and 3 fall squarely
within this paradigm, the proposed building block 4 does not. In view
of this, since the BSER must serve as the foundation of the emission
guidelines, the EPA has not included demand-side EE as part of the
final BSER determination.
    It should be noted that commenters also took the position that the
EPA should allow demand-side EE as a means of compliance with the
requirements of this rule, and, as discussed in section V.A.6.b. and
section VIII below, we agree.
    e. Consistent regionalized approach to quantification of emission
reductions from all building blocks. In the June 2014 proposal, the EPA
treated each of the building blocks differently with respect to the
regional scale on which the building block was applied for purposes of
assessing the emission reductions achievable through use of that
building block. Building block 1 was quantified at a national scale,
identifying a single heat rate improvement opportunity applicable on
average to all coal-fired steam EGUs. Building block 2 was quantified
at the scale of each individual state, considering the amount of
generation that could be shifted from steam EGUs to NGCC units within
the state, although we solicited comment on considering generation
shifts at a broader regional scale. The RE component of building block
3 was quantified at a regional scale using RPS information as a proxy
for RE development potential, and the regional results were then
applied to each state in the region using the state's baseline data; an
alternative methodology on which we requested comment quantified the RE
component using a techno-economic approach on a state-specific basis.
In the October 2014 NODA, we requested comment on using a techno-
economic approach to quantify RE generation potential at a regional
scale and took broad comment on strategies for better aligning the BSER
with the regionally interconnected electrical grid.\389\ We also
solicited comment on the appropriate regional boundaries or regional
structure to facilitate this approach.
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    \389\ 79 FR 64543, 64551-52.
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    For the final rule, with the benefit of comments received in
response to these proposals and alternatives, we have adopted a
consistent regionalized approach to quantification of emission
reductions achievable through all the building blocks. Under this
approach, each of the building blocks is quantified and applied at the
regional level, resulting in the computation for each region of a
performance rate for steam EGUs and a performance rate for NGCC units.
For each of the technology subcategories, we identify the most
conservative--that is, the least stringent --of the three regional
performance rates. We then apply these least stringent subcategory-
specific performance rates to the baseline data for the EGU fleet in
each state to establish state goals of consistent stringency across the
country. (Note that the actual state goals vary among states to reflect
the differences in generation mix among states in the baseline year.)
Further description of the steps in this overall process is contained
in the preamble sections addressing the individual building blocks
(sections V.C., V.D., and V.E.), CO2 emission performance
rate computation (section VI), and state goal computation (section
VII), as well as the GHG Mitigation Measures TSD for the CPP Final Rule
and the CO2 Emission Performance Rate and Goal Computation
TSD for the CPP Final Rule available in the docket.
    Compared to the more state-focused quantification approach selected
in the proposal, and as recognized in the NODA, a regionalized approach
better reflects the interconnected system within which interdependent
affected EGUs actually carry out planning and operations in order to
meet electricity demand. We have already discussed the relevance of the
interconnected system and the interdependent operations of EGUs as
factors supporting consideration of building blocks 2 and 3 as elements
of the BSER for this pollutant and this industry, and these same
factors support quantifying the emission reductions achievable through
building blocks 2 and 3 on a regionalized basis. Because it better
reflects how the industry works, a regionalized approach also better
represents the full scope of emission reduction opportunities available
to individual affected EGUs through the normal transactional processes
of the industry, which do not stop at state borders but rather extend
throughout these interconnected regions. With respect to building block
1, which comprises types of emission reduction measures that in other
rulemakings under CAA section 111 would typically be evaluated on a
nationwide basis, for this rule, as discussed in section V.C. below, we
are quantifying the emission reductions achievable through building

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