circumstances in which part of a power delivery within one balancing
area flows on transmission lines in adjoining areas, or part of a power
delivery between two balancing areas flows over the transmission
facilities of a third area.'' \391\ The interconnections are the
``complex machines'' within which EGUs plan, coordinate, and operate,
manifesting a degree of both long-term and real-time interdependence
that is unique to this industry. We concluded that, absent a compelling
reason to adopt a smaller regional scale for evaluation of
CO2 emission reduction opportunities for the electric power
sector--which we have not found, as discussed below--the
interconnections should be the regions used for evaluation of the BSER
for CO2 emission reductions from the electric power sector
because of the fundamental characteristics of electricity, the
industry's basic interconnected physical infrastructure, and the
interdependence of the affected EGUs within each interconnection.
---------------------------------------------------------------------------

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

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

The report noted that to ensure the reliable operation of the bulk
power system, entities must identify a plan for IROLs to avoid
cascading outages. ``In order to ensure the reliable operation of the
BPS, entities are required to identify and plan for IROLs, which are
SOLs that, if violated, can cause instability, uncontrolled separation,
and cascading outages. Once an IROL is identified, system operators are
then required to create plans to mitigate the impact of exceeding such
a limit to maintain system reliability.'' \394\
---------------------------------------------------------------------------

    \392\ For example, the Eastern Interconnection has Reliability
Standard IRO-006-EAST-1, Transmission Loading Relief Procedure for
the Eastern Interconnection, available at http://www.nerc.com/files/IRO-006-EAST-1.pdf (providing an ``Interconnection-wide transmission
loading relief procedure (TLR) for the Eastern Interconnection that
can be used to prevent and/or mitigate potential or actual System
Operating Limit (SOL) and Interconnection Reliability Operating
Limit (IROL) exceedances to maintain reliability of the Bulk
Electric System (BES).'').
    \393\ FERC-NERC, Arizona-Southern California Outages on
September 8, 2011: Causes and Recommendations (Apr. 2012), available
at http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nerc-report.pdf.
    \394\ FERC-NERC, Arizona-Southern California Outages on
September 8, 2011: Causes and Recommendations, at 97 (Apr. 2012),
available at http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nerc-report.pdf.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    \420\ For example, according to a DOE/NETL study, the relative
amount of water consumption for a new pulverized coal plant is 2.5
times the consumption for a new NGCC unit of similar size. ``Cost
and Performance Baseline for Fossil Energy Plants: Volume 1:
Bituminous Coal and Natural Gas to Electricity,'' Rev 2a, September
2013, National Energy Technology Laboratory Report DOE/NETL-2010/
1397. EPA believes the difference would on average be even more
pronounced when comparing existing coal and NGCC units.
---------------------------------------------------------------------------

    It should be observed that, by definition of the elements of this
building block, the shifts in generation taking place under building
block 2 occur entirely among existing EGUs subject to this
rulemaking.\421\ Through application of this building block considered
in isolation, some affected EGUs--mostly coal-fired steam EGUs--would
reduce their generation and CO2 emissions, while other
affected EGUs--NGCC units--would increase their generation and
CO2 emissions. However, because for each MWh of generation,
NGCC units produce fewer CO2 emissions than coal-fired steam
EGUs, the total quantity of CO2 emissions from all affected
EGUs in aggregate would decrease without a reduction in total
electricity generation. In the context of the integrated electricity
system, where the operation of affected EGUs of multiple types is
routinely coordinated to provide a highly substitutable service, and in
the context of CO2 emissions, where location is not a
consideration (in contrast with other pollutants), a measure that takes
advantage of that integration to reduce CO2 emissions from
the overall set of affected EGUs is readily understood as a means to
implement a ``system of emission reduction'' for CO2
emissions at affected EGUs even if the measure would increase
CO2 emissions from a subset of those affected EGUs. Indeed,
some industry participants are already moving in this direction for
this purpose (while other participants are moving in the same direction
for other purposes). Standards of performance that incorporate
emissions trading can facilitate the implementation of such a
``system'' and such approaches have already been used in the
electricity industry to address CO2 as well as other
pollutants, as discussed above.
---------------------------------------------------------------------------

    \421\ For purposes of this rulemaking, ``existing'' EGUs include
units under construction as of January 8, 2014, the date of
publication in the Federal Register of the proposed carbon pollution
standards for new fossil fuel-fired EGUs.
---------------------------------------------------------------------------

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

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

the public health and welfare risks and impacts associated with such
climate change, as described in Section II.A. The EPA focused on public
health and welfare impacts within the U.S., but the impacts in other
world regions strengthen the case for action because impacts in other
world regions can in turn adversely affect the U.S. or its citizens. In
looking at whether costs were reasonable, the EPA also considered that
EGUs are by far the largest emitters of GHGs among stationary sources
in the U.S., as more fully set forth in section II.B.
    As described in sections V.C. through V.E. and the GHG Mitigation
Measures TSD, the EPA has determined that the cost of each of the three
building blocks is reasonable. In summary, these cost estimates are $23
per ton of CO2 reductions for building block 1, $24 per ton
for building block 2, and $37 per ton for building block 3. The EPA
estimates that, together, the three building blocks are able to achieve
CO2 reductions at an average cost of $30 per ton, which the
EPA likewise has determined is reasonable. The $30 per ton estimate is
an average of the estimates for each building block, weighted by the
total estimated cumulative CO2 reductions for each of these
building blocks over the 2022-2030 period. While it is possible to
weight each building block by other amounts, the EPA believes that
weighting by cumulative CO2 reductions best reflects the
average cost of total reduction potential across the three building
blocks. The EPA considers each of these cost levels reasonable for
purposes of the BSER established for this rule.
    The EPA views the weighted average cost estimate as a
conservatively high estimate of the cost of deploying all three
building blocks simultaneously. The simultaneous application of all
three building blocks produces interactive dynamics, some of which
could increase the cost and some of which could decrease the cost
represented in the individual building blocks. For example, one dynamic
that would tend to raise costs (and whose omission would therefore make
the weighted average understate costs) is that the emission reduction
measures associated with building blocks 2 and 3 both prioritize the
replacement of higher-cost generation (from affected steam EGUs in the
case of building block 2 and from all affected EGUs in the case of
building block 3). The EPA recognizes that the increased magnitude of
generation replacement when building blocks 2 and 3 are implemented
together necessitates that some of the generation replacement will
occur at more efficient affected EGUs, at a relatively higher cost;
however, this is a consequence of the greater emission reductions that
can be achieved by combining building blocks, not an indication that
any individual building block has become more expensive because of the
combined deployment.
    Also, the EPA recognizes that when building block 1 is combined
with the other building blocks, the combination has the potential to
raise the cost of the portion of the overall emission reductions
achievable through heat rate improvements relative to the cost of those
same reductions if building block 1 were implemented in isolation
(assuming for purposes of this discussion that the rebound effect is
not an issue and that the affected steam EGUs would in fact reduce
their emissions if building block 1 were implemented in
isolation).\422\ However, we believe that the cost of emission
reductions achieved through heat rate improvements in the context of a
three-building block BSER will remain reasonable for two reasons.
First, as discussed in section V.C. below, even when conservatively
high investment costs are assumed, the cost of CO2 emission
reductions achievable through heat rate improvements is low enough that
the cost per ton of CO2 emission reductions will remain
reasonable even if that cost is substantially increased. Second,
although under a BSER encompassing all three building blocks the volume
of coal-fired generation will decrease, that decrease is unlikely to be
spread uniformly among all coal-fired EGUs. It is more likely that some
coal-fired EGUs will decrease their generation slightly or not at all
while others will decrease their generation by larger percentages or
cease operations altogether. We would expect EGU owners to take these
changes in EGU operating patterns into account when considering where
to invest in heat rate improvements, with the result that there will be
a tendency for such investments to be concentrated in EGUs whose
generation output is expected to decrease the least. This enlightened
bias in spending on heat rate improvements--that is, focusing
investments on EGUs where such improvements will have the largest
impacts and produce the highest returns, given consideration of
projected changes in dispatch patterns--will tend to mitigate any
deterioration in the cost of CO2 emission reductions
achievable through heat rate improvements.
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    \422\ If an EGU produces less generation output, then an
improvement in that EGU's heat rate and rate of CO2
emissions per unit of generation produces a smaller reduction in
CO2 emissions. If the investment required to achieve the
improvement in heat rate and emission rate is the same regardless of
the EGU's generation output, then the cost per unit of
CO2 emission reduction will be higher when the EGU's
generation output is lower. Commenters have also stated that
operating at lower capacity factors may cause units to experience
deterioration in heat rates.
---------------------------------------------------------------------------

    In contrast with those prior examples, combining the building
blocks also produces interactive dynamics that significantly reduce the
cost for CO2 reductions represented in the individual
building blocks (and whose omission would therefore make the weighted
average overstate costs). Foremost among these dynamics is the
stabilization of wholesale power prices. When assessed individually,
building blocks 2 and 3 have opposite impacts on wholesale power
prices, although in each case, the direction of the wholesale power
price impact corresponds to an increasing cost of that building block
in isolation. For example, building block 2 promotes more utilization
of existing NGCC capacity, which (assessed on its own) would increase
natural gas consumption and therefore price, in turn raising wholesale
power prices (which are often determined by gas-fired generators as the
power supplier on the margin); this dynamic puts upward pressure on the
cost of achieving CO2 reductions through shifting generation
from steam EGUs to NGCC units.\423\ Meanwhile, building block 3
increases RE deployment; because RE generators have very little
variable cost, an increase in RE generation replaces other supply with
higher variable cost, which would yield lower wholesale power prices.
Lower wholesale power prices would make further RE deployment less
competitive against generation from existing emitting sources; while
this dynamic would generally reduce electricity prices to consumers, it
also puts upward pressure on the cost of achieving CO2
reductions through increased RE deployment.\424\ Applying building
blocks 2 and 3 together produces significantly more CO2
reductions at a relatively lower cost because the countervailing nature
of these wholesale power price dynamics mitigates the primary cost
drivers for each building block.\425\
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    \423\ The EPA's cost-effectiveness estimate of $24 per ton for
building block 2 reflects these market dynamics.
    \424\ The EPA's cost-effectiveness estimate of $37 per ton for
building block 3 reflects these market dynamics.
    \425\ Notwithstanding the interactive dynamics that improve the
cost effectiveness of emission reductions when building blocks 2 and
3 are implemented together, we also consider each of these building
blocks to be independently of reasonable cost, so that either
building block 2 or 3 alone, or combinations of the building blocks
that include either but not both of these two building blocks, could
be the BSER if a court were to strike down the other building block,
as discussed in section V.A.7. below. (We also note in section
V.A.7. that a combination of building blocks 2 and 3 without
building block 1 could be the BSER if a court were to strike down
building block 1.)

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

    The EPA believes the dynamics tending to cause the weighted average
above to overstate costs of the combination of building blocks are
greater than the dynamics tending to cause costs to be understated, and
that the weighted average costs are therefore conservatively high.
Analysis performed by the EPA at an earlier stage of the rulemaking
supports this conclusion. At proposal, the EPA evaluated the cost of
increasing NGCC utilization (building block 2) and deploying
incremental RE generation (building block 3) independently, as well as
the cost of simultaneously increasing NGCC utilization and incremental
RE generation. The average cost (in dollars per ton of CO2
reduced) was less for the combined building block scenario, showing
that the net outcome of the interactivity effects described above is a
reduction in cost per ton when compared to cost estimates that do not
incorporate this interactivity.\426\
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    \426\ Specifically, at proposal the EPA quantified the average
cost, in dollar per ton of CO2 reduced, of building
blocks 1, 2, and 3 ($22.5 per ton) to be less than the cost of
either building block 2 ($28.9 per ton) or building block 3 ($23.4
per ton) alone.
---------------------------------------------------------------------------

    A final reason why the EPA considers the weighted-average cost
above conservatively high is that simply combining the building blocks
at their full individual stringencies overstates the stringency of the
BSER. As discussed in section V.A.3.f and section VI, the BSER reflects
the combined degree of emission limitation achieved through application
of the building blocks in the least stringent region. By definition, in
the other two regions, the BSER is less stringent than the simple
combination of the three building blocks whose stringency is
represented in the weighted-average cost above.
    The cost estimates for each of the three building blocks cited
above--$23, $24, and $37 per ton of CO2 reductions from
building blocks 1, 2, and 3, respectively--are each conservatively high
for the reasons discussed in section V.C., V.D., and V.E. below.
Likewise, the $30 per ton weighted-average cost of all three building
blocks is a conservatively high estimate of the cost of the combination
of the three individual building block costs, as described above. While
conservatively high, and especially so in the case of the $30 per ton
weighted-average cost, these estimates fall well within the range of
costs that are reasonable for the BSER for this rule.
    In assessing cost reasonableness for the BSER determination for
this rule, the EPA has compared the estimated costs discussed above to
two types of cost benchmark. The first type of benchmark comprises
costs that affected EGUs incur to reduce other air pollutants, such as
SO2 and NOX. In order to address various
environmental requirements, many coal-fired EGUs have been required to
decide between either shutting down or installing and operating flue
gas desulfurization (FGD) equipment--that is, wet or dry scrubbers--to
reduce their SO2 emissions. The fact that many of these EGUs
have chosen scrubbers in preference to shutting down is evidence that
scrubber costs are reasonable, and we believe that the cost of these
controls can reasonably serve as a cost benchmark for comparison to the
costs of this rule. We estimate that for a 300-700 MW coal-fired steam
EGU with a heat rate of 10,000 Btu per kWh and operating at a 70
percent utilization rate, the annualized costs of installing and
operating a wet scrubber are approximately $14 to $18 per MWh and the
annualized costs of installing and operating a dry scrubber are
approximately $13 to $16 per MWh.\427\
---------------------------------------------------------------------------

    \427\ For details of these computations, see the memorandum
``Comparison of building block costs to FGD costs'' available in the
docket.
---------------------------------------------------------------------------

    In comparison, we estimate that for a coal-fired steam EGU with a
heat rate of 10,000 Btu per kWh, assuming the conservatively high cost
of $30 per ton of CO2 removed through the combination of all
three building blocks, the cost of reducing CO2 emissions by
the amount required to achieve the uniform CO2 emission
performance rate for steam EGUs of 1,305 lbs. CO2 per MWh
would be equivalent to approximately $11 per MWh. The comparable costs
for achieving the required emission performance rate for steam EGUs
through use of the individual building blocks range from $8 to $14 per
MWh. For an NGCC unit with a heat rate of 7,800 Btu per kWh, assuming a
conservatively high cost of $37 per ton of CO2 removed
through the use of building block 3,\428\ the cost of reducing
CO2 emissions by the amount required to achieve the uniform
CO2 emission performance rate for NGCC units of 771 lbs.
CO2 per MWh would be equivalent to approximately $3 per
MWh.\429\ These estimated CO2 reduction costs of $3 to $14
per MWh to achieve the CO2 emission performance rates are
either less than the ranges of $14 to $18 and $13 to $16 per MWh to
install and operate a wet or dry scrubber, or in the case of
CO2 emission reductions at a steam unit achieved through
building block 3, near the low end of the ranges of scrubber costs.
This comparison demonstrates that the costs associated with the BSER in
this rule are reasonable compared to the costs that affected EGUs
commonly face to comply with other environmental requirements.
---------------------------------------------------------------------------

    \428\ The comparison for an NGCC unit considers only building
block 3 because building blocks 1 and 2 do not apply to NGCC units.
    \429\ For details of these computations, see the memorandum
``Comparison of building block costs to FGD costs'' available in the
docket.
---------------------------------------------------------------------------

    The second type of benchmark comprises CO2 prices that
owners of affected EGUs use for planning purposes in their IRPs.
Utilities subject to requirements to prepare IRPs commonly include
assumptions regarding future environmental regulations that may become
effective during the time horizon covered by the IRP, and assumptions
regarding CO2 regulations are often represented in the form
of assumed prices per ton of CO2 emitted or reduced. A
survey of the CO2 price assumptions from 46 recent IRPs
shows a range of CO2 prices in the IRPs' reference cases of
$0 to $30 per ton, and a range of CO2 prices in the IRPs'
high cases from $0 to $110 per ton.\430\ In comparison, the
conservatively high, weighted-average cost of $30 per ton removed
described above is at the high end of the range of reference case
assumptions but at the low end of the range of the high case
assumptions. The costs of the individual building blocks are likewise
well within the range of the high case assumptions, and either at or
slightly above the high end of the reference case assumptions. This
comparison demonstrates that the costs associated with the BSER in this
rule are reasonable compared to the expectations of the industry for
the potential costs of CO2 regulation.
---------------------------------------------------------------------------

    \430\ See Synapse Energy Economics Inc., 2015 Carbon Dioxide
Price Forecast (March 3, 2015) at 25-28, available at http://www.synapse-energy.com/sites/default/files/2015%20Carbon%20Dioxide%20Price%20Report.pdf.
---------------------------------------------------------------------------

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

section 111. Given EGUs' large contribution to U.S. GHG emissions, any
attempt to address the serious public health and environmental threat
of climate change must necessarily include significant emission
reductions from this sector. The agency would therefore consider even
relatively high costs--which these are not--to be reasonable. Imposing
only the lower cost reduction measures in building block 1 would not
achieve sufficient reductions given the scope of the problem and EGUs'
contribution to it. While the EPA also considered measures such as CCS
retrofits for all fossil-fired EGUs or co-firing at all steam units,
the EPA determined that these costs were too high when considered on a
sector-wide basis. Furthermore, the EPA has not identified other
measures available under section 111 that are less costly and would
achieve emission reductions that are commensurate with the scope of the
problem and EGUs' contribution to it. Thus, the EPA determined that the
costs of the measures in building blocks 1, 2 and 3, individually or in
combination, are reasonable because they achieve an appropriate balance
between cost and amount of reductions given the other potential control
measures under section 111.
    As required under Executive Order 12866, the EPA conducts benefit-
cost analyses for major Clean Air Act rules.\431\ While benefit-cost
analysis can help to inform policy decisions, as permissible and
appropriate under governing statutory provisions, the EPA does not use
a benefit-cost test (i.e., a determination of whether monetized
benefits exceed costs) as the sole or primary decision tool when
required to consider costs or to determine whether to issue regulations
under the Clean Air Act, and is not using such a test here.\432\
Nonetheless, the EPA observes that the costs of the building block 1, 2
and 3 measures, both individually and combined as discussed in this
section above, are less than the central estimates of the social cost
of carbon. Developed by an interagency workgroup, the social cost of
carbon (SC-CO2) is an estimate of the monetary value of
impacts associated with marginal changes in CO2 emissions in
a given year.\433\ It is typically used to assess the avoided damages
as a result of regulatory actions (i.e., benefits of rulemakings that
lead to an incremental reduction in cumulative global CO2
emissions).\434\ The central values for the SC-CO2 range
from $40 per short ton in 2020 to $48 per short ton in 2030.\435\ The
weighted-average cost estimate of $30 per ton is well below this range.
---------------------------------------------------------------------------

    \431\ The EPA's regulatory impact analysis for this rule, which
appropriately includes a representation of the flexibility available
under the rule to comply using a combination of BSER and non-BSER
measures (such as demand-side energy efficiency) is discussed in
section XI of the preamble.
    \432\ See memo entitled ``Consideration of Costs and Benefits
Under the Clean Air Act'' available in the docket.
    \433\ Estimates are presented in the Technical Support Document:
Technical Update of the Social Cost of Carbon for Regulatory Impact
Analysis Under Executive Order 12866 (May 2013, Revised July 2015),
Interagency Working Group on Social Cost of Carbon, with
participation by Council of Economic Advisers, Council on
Environmental Quality, Department of Agriculture, Department of
Commerce, Department of Energy, Department of Transportation,
Environmental Protection Agency, National Economic Council, Office
of Energy and Climate Change, Office of Management and Budget,
Office of Science and Technology Policy, and Department of Treasury
(May 2013, Revised July 2015). Available at: https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf> Accessed 7/11/2015.
    \434\ The SC-CO2 estimates do not include all
important damages because of current modeling and data limitations.
The 2014 IPCC report observed that SC-CO2 estimates omit
various impacts that would likely increase damages. See IPCC, 2014:
Climate Change 2014: Impacts, Adaptation, and Vulnerability.
Contribution of Working Group II to the Fifth Assessment Report of
the Intergovernmental Panel on Climate Change. Cambridge University
Press, Cambridge. https://www.ipcc.ch/report/ar5/wg2/.
    \435\ The 2010 and 2013 TSDs present SC-CO2 in 2007$
per metric ton. The unrounded estimates from the current TSD were
adjusted to (1) 2011$ using GDP Implicit Price Deflator (1.061374),
http://www.bea.gov/iTable/index_nipa.cfm and (2) short tons using
the conversion factor of 0.90718474 metric tons in a short ton.
These estimates were rounded to two significant digits.
---------------------------------------------------------------------------

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

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

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

    As noted, the building blocks include several features that assure
that affected EGUs may implement them. The building blocks may be
implemented through a range of methods, including through the purchase
of ERCs and emission trading. In addition, the building blocks
incorporate ``headroom.'' Moreover, the source subcategory-specific
emission performance rates apply on an annual or longer basis, so that
short-term issues need not jeopardize compliance. In addition, we
quantify the emission performance rates based on the degree of emission
limitation achievable by affected EGUs in the region where application
of the combined building blocks results in the least stringent emission
rate. Because the means to implement the building blocks are widely
available and because of the just-noted flexibilities and approaches to
the emission performance rates, all types of affected steam generating
units, operating throughout the lower-48 states and under all types of
regulatory regimes, are able to implement building blocks 1, 2 and 3
and thereby achieve the emission performance rate for fossil steam
units, and all types of NGCC units operating in all states under all
types of regulatory requirements are able to implement building block 3
and thereby achieve the emission performance rate for NGCC units.\437\
---------------------------------------------------------------------------

    \437\ We discuss the ability of affected EGUs to implement the
building blocks in more detail in sections V.C., V.D., and V.E. and
the accompanying support documents.
---------------------------------------------------------------------------

    Commenters have raised questions about whether particular
circumstances could arise, such as the sudden loss of certain
generation assets, that would cause the implementation of the building
blocks to cause reliability problems, and have cautioned that these
circumstances could preclude implementation of the building blocks and
thus achievement of the emission performance rates. Commenters have
also raised concerns about whether affected EGUs with limited remaining
useful lives can implement the building blocks and achieve the emission
performance rates. We address those concerns in section VIII, where we
authorize state plans to include a reliability mechanism and discuss
affected EGUs with limited remaining useful lives. Accordingly, we
conclude that the source subcategory-specific emission performance
standards are achievable in accordance with the case law.
5. Actions Under the BSER That Sources Can Take To Achieve Standards of
Performance
    Based on the determination of the BSER described above, the EPA has
identified a performance rate of 1305 lbs. per net MWh for affected
steam EGUs and a performance rate of 771 lbs. per net MWh for affected
stationary combustion turbines. The computations of these performance
rates and the determinations of state goals reflecting these rates are
described in sections VI and VII of the preamble, respectively.
    Under section 111(d), states determine the standards of performance
for individual sources. The EPA is authorizing states to express the
standards of performance applicable to affected EGUs as either emission
rate-based limits or mass-based limits. As described above, the sets of
actions that sources can take to comply with these standards implement
or apply the BSER and, in that sense, may be understood as part of the
BSER.
    A source to which a state applies an emission rate-based limit can
achieve the limit through a combination of the following set of
measures (to the extent allowed by the state plan), all of which are
components of the BSER, again, in the sense that they implement or
apply it:
     Reducing its heat rate (building block 1).
     Directly investing in, or purchasing ERCs created as a
result of, incremental generation from existing NGCC units (building
block 2).
     Directly investing in, or purchasing ERCs created as a
result of, generation from new or uprated RE generators (building
block 3).
     Reducing its utilization, coupled with direct
investment in or purchase of ERCs representing building blocks 2 and
3 as indicated above.
     Investing in surplus emission rate reductions at other
affected EGUs through the purchase or other acquisition of rate-
based emission credits.

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

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

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

of measures not in the BSER that can help sources achieve the standards
of performance.
    a. Use of BSER measures to achieve an emission rate-based standard.
Under an emission-rate based form of performance standards, compliance
is nominally determined through a comparison of the affected EGU's
emission rate to the emission rate standard. The emissions-reducing
impact of BSER measures that reduce CO2 emissions through
reductions in the quantity of generation rather than through reductions
in the amount of CO2 emitted per unit of generation would
not be reflected in an affected EGU's emission rate computed solely
based on measured stack emissions and measured electricity generation
but can readily be reflected in an emission rate computation by
averaging ERCs acquired by the affected EGU into the rate computation.
    In section VIII.K, we discuss the processes for issuance and use of
ERCs that can be included in the emission rate computations that
affected EGUs perform to demonstrate compliance with an emission rate
standard. This ERC mechanism is analogous to the approach the EPA has
used to reflect building blocks 2 and 3 in the uniform emission rates
representing the BSER, as discussed in section VI below. As summarized
below and as discussed in greater detail in section VIII.K, the
existence of a clearly feasible path for usage of ERCs ensures that
emission reductions achievable through implementation of the measures
in building blocks 2 and 3 are available to assist all affected EGUs in
achieving compliance with standards of performance based on the BSER.
    (1) Building block 1.
    The owner/operator of an affected steam EGU can take steps to
reduce the unit's heat rate, thereby lowering the unit's CO2
emission rate. Examples of actions in this category are included in
section V.C. below and in the GHG Mitigation Measures TSD for the CPP
Final Rule. Any type of owner/operator can take advantage of this
measure.
    (2) Building block 2.
    The owner/operator of an affected EGU can average the EGU's
emission rate with ERCs issued on the basis of incremental generation
from an existing NGCC unit. As permitted under the EGU's state's
section 111(d) plan, the owner/operator of the affected EGU could
accomplish this through either common ownership of the NGCC unit, a
bilateral transaction with the owner/operator of the NGCC unit, or a
transaction for ERCs through an intermediary, which could but need not
involve an organized market.\438\ As discussed earlier, based on
observation of market behavior both inside and outside the electricity
industry, we expect that intermediaries will seek opportunities to
participate in such transactions and that organized markets are likely
to develop as well if section 111(d) plans authorize the use of ERCs.
While the opportunity to acquire ERCs through common ownership of NGCC
facilities might not extend to owner/operators of single EGUs or small
fleets, all owner/operators would have the ability to engage in
bilateral or intermediated purchase transactions for ERCs just as they
can engage in transactions for other kinds of goods and services.
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    \438\ Each of these methods of implementing building block 2
meets the criteria for the BSER in that (i) as we discuss in section
V.D. and supporting documents, each of these methods is adequately
demonstrated;(ii) the costs of each of these methods on a source-by-
source basis are reasonable, as discussed above; and (iii) none of
these methods causes adverse energy impacts or non-quality
environmental impacts.
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    In section VIII.K below, the EPA sets out the minimum criteria that
must be satisfied for generation and issuance of a valid ERC based upon
incremental electricity generation by an existing NGCC unit. Those
criteria generally concern ensuring that the physical basis for the
ERC--i.e., qualifying generation by an existing NGCC unit and the NGCC
unit CO2 emissions associated with that qualifying
generation--is adequately monitored and that there is an adequate
administrative process for tracking credits to avoid double-counting.
In the case of ERCs related to building block 2, the monitoring
criteria would generally be satisfied by standard 40 CFR part 75
monitoring.
    The owner/operator of an affected steam EGU would use the ERCs it
has acquired for compliance--whether acquired through ownership of NGCC
capacity, a bilateral transaction, or an intermediated transaction--by
adding the ERCs to its measured net generation when computing its
CO2 emission rate for purposes of demonstrating compliance
with its emission rate-based standard of performance.
    (3) Building block 3.
    The owner/operator of an affected EGU can average the EGU's
emission rate with ERCs issued on the basis of generation from new
(i.e., post-2012) RE generating capacity, including both newly
constructed capacity and new uprates to existing RE generating
capacity. As permitted under the EGU's state's section 111(d) plan, the
owner/operator of the affected EGU could accomplish this through either
common ownership of the RE generating capacity, a bilateral transaction
with the owner/operator of the RE generating capacity, or a transaction
for ERCs through an intermediary, which could, but need not, involve an
organized market.\439\ As discussed earlier, based on observation of
market behavior both inside and outside the electricity industry, we
expect that intermediaries will seek opportunities to participate in
such transactions and that organized markets are likely to develop as
well if section 111(d) plans authorize the use of ERCs. While the
opportunity to acquire ERCs through common ownership of RE generating
facilities might not extend to owner/operators of single EGUs or small
fleets, all owner/operators would have the ability to engage in
bilateral or intermediated purchase transactions for ERCs just as they
can engage in transactions for other kinds of goods and services.
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    \439\ As with building block 2, each of these methods of
implementing building block 3 meets the criteria for the BSER in
that (i) as we discuss in section V.E. and supporting documents,
each of these methods is adequately demonstrated; (ii) the costs of
each of these methods on a source-by-source basis are reasonable, as
discussed above; and (iii) none of these methods causes adverse
energy impacts or non-quality environmental impacts.
---------------------------------------------------------------------------

    In section VIII.K below, the EPA sets out the minimum criteria that
must be satisfied for generation and issuance of a valid ERC based upon
generation from new RE generating capacity. Those criteria generally
concern assuring that the physical basis for the ERC--i.e., generation
by qualifying new RE capacity--is adequately monitored and that there
is an adequate administrative process for tracking credits to avoid
double-counting.\440\
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    \440\ The possible use of types of RE generating capacity that
are not included in the BSER is discussed in section V.A.6. and
section VIII of the preamble.
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    As with building block 2, the owner/operator of an affected EGU
would use the ERCs it has acquired for compliance--whether acquired
through ownership of qualifying RE generating capacity, a bilateral
transaction, or an intermediated transaction--by adding the ERCs to its
measured net generation when computing its CO2 emission rate
for purposes of demonstrating compliance with its emission rate-based
standard of performance.
    (4) Reduced generation.
    The owner/operator of an affected EGU can reduce the unit's
generation and reflect that reduction in the form of a lower emission
rate provided that the owner/operator also acquires some amount of ERCs
to use in computing the unit's emission rate for purposes of
demonstrating compliance. As

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

allowances it already holds for purposes of demonstrating compliance