final plan performance periods, both plans would functionally be
meeting an aggregated multi-state mass-based goal (or aggregated mass-
based CO2 goal plus new source CO2 emission
complement), but without formally aggregating the goal (or aggregated
mass-based CO2 goal plus new source CO2 emission
complement). CO2 emissions from affected EGUs in both states
could not exceed the total combined CO2 emission budgets
under the emission standards in the two states. A net ``import'' of
CO2 allowances from one state would mean that allowable
CO2 emissions in the other net ``exporting'' state are less
than that state's established emission budget. On a multi-state basis,
CO2 emissions from affected EGUs could not exceed the sum of
the states' emission budgets.
    Under this approach, if the emission budget for the mass-based
emission standard in each plan is equal to or lower than the state's
mass-based CO2 goal (or aggregated mass-based CO2
goal plus new source CO2 emission complement, if
applicable), compliance by affected EGUs with the mass emission
standard in a state \927\ would ensure that cumulatively the mass
CO2 goals (or mass-based CO2 goals plus new
source CO2 emission complements) of the linked states are
achieved. As a result, achievement of an individual state's mass
CO2 goal (or mass-based CO2 goal plus new source
CO2 emission complement) would be assessed by the EPA based
on compliance by affected EGUs with the mass-based emission standards
in the state plan, rather than reported CO2 emissions by
affected EGUs in the state.\928\
---------------------------------------------------------------------------

    \927\ Compliance by an affected EGU with the emission standard
is demonstrated based on surrender to the state of a number of
CO2 allowances equal to its reported CO2
emissions.
    \928\ This approach is warranted because under such linked
programs, CO2 emissions from affected EGUs in one state
that exceed a state's mass CO2 goal (or mass-based
CO2 goal plus new source CO2 emission
complement) would be accompanied by CO2 emissions from
affected EGUs in another linked state that are below that state's
mass CO2 goal (or mass-based CO2 goal plus new
source CO2 emission complement).
---------------------------------------------------------------------------

    The same accounting approach will apply for such plans in all
cases, even if the state is linked to another state emission budget
trading program that includes a broader set of emission sources (e.g.,
sources beyond affected EGUs, or beyond affected EGUs plus applicable
new fossil fuel-fired EGUs), as described below. In all cases, where a
state plan includes an emission budget trading program that applies
only to affected EGUs (or beyond affected EGUs plus applicable new
fossil fuel-fired EGUs), and includes compliance timeframes that align
with plan performance periods, achievement of a state mass
CO2 goal (or mass-based CO2 goal plus new source
CO2 emission complement) will be assessed by the EPA based
on whether affected EGUs comply with the mass-based emission standard,
rather than reported CO2 emissions from affected EGUs.
    (2) Links with emission budget trading programs that include a
broader set of emission sources. State plans may involve emission
budget trading programs that include affected EGUs, applicable new
fossil fuel-fired EGUs if a plan includes a new source CO2
emission complement, and other non-affected emission sources.\929\
---------------------------------------------------------------------------

    \929\ This may apply under both an emission standards plan and a
state measures plan. Section VIII.J.2.a describes how state plan
submissions must include as requirements, or describe as part of
supporting documentation, relevant aspects of such emission budget
trading programs.
---------------------------------------------------------------------------

    Generally, such plans must demonstrate that the mass-based
CO2 goal for affected EGUs (or mass-based CO2
goal plus new source CO2 emission complement) in a state
will be achieved, as a result of implementation of the emission budget
trading program.\930\ Where a program includes other non-affected
emission sources (i.e., non-affected emission sources that are not
subject to a new source CO2 emission complement) and is
linked with other programs,\931\ the state plan submittal must include
a demonstration that the mass-based CO2 goal (or mass-based
CO2 goal plus new source CO2 emission complement)
will be achieved, considering the emission allowance links with other
programs. The EPA, in determining the approvability of each state's
plan under this approach, would evaluate the linkages between plans.
Specifically, the EPA would evaluate whether the linkages would enable
the affected EGUs (or affected EGUs in conjunction with applicable new
fossil fuel-fired EGUs) in each participating state to meet the state's
applicable mass-based CO2 goal (or mass-based CO2
goal plus new source CO2 emission complement).
---------------------------------------------------------------------------

    \930\ Under a program that applies to affected EGUs and other
emission sources, compliance by affected EGUs with the emission
standard--a requirement to surrender emission allowances equal to
reported emissions--will not assure that a state's CO2
mass goal (or mass-based CO2 goal plus new source
CO2 emission complement) is achieved. As a result, a
further demonstration is required in the plan that compliance by
affected EGUs with the program will result in CO2
emissions from affected EGUs that are at or below a state's
CO2 mass goal (or mass-based CO2 goal plus new
source CO2 emission complement).
    \931\ Section VIII.J.2.a describes how state plan submittals
must include as requirements, or describe as part of supporting
documentation, relevant aspects of such emission budget trading
programs.
---------------------------------------------------------------------------

    During plan implementation, the EPA would assess whether the
affected EGUs in a state achieved the state's mass-based CO2
goal (or mass-based CO2 goal plus new source CO2
emission complement) as follows. Reported CO2

emissions from affected EGUs under such plans must be at or below a
state's mass-based CO2 emission goal (or mass-based
CO2 goal plus new source CO2 emission complement)
during an identified plan performance period, with the following state
accounting adjustments for net ``import'' and net ``export'' of
---------------------------------------------------------------------------
CO2 allowances:

     Net ``imports'' of CO2 allowances: Reported
CO2 emissions from affected EGUs in a state may exceed
the state CO2 mass goal (or mass-based CO2
goal plus new source CO2 emission complement) during an
identified plan performance period in the amount of an adjustment
for the net ``imported'' CO2 allowances during the plan
performance period. The adjustment represents the CO2
emissions (in tons) equal to the number of net ``imported''
CO2 allowances. Under this adjustment, such allowances
must be issued by a state with an emission budget trading program
that only applies to affected EGUs (or affected EGUs plus applicable
new fossil fuel-fired EGUs). Net ``imports'' of allowances are
determined through review of tracking system compliance accounts.
     Net ``exports'' of CO2 allowances: Reported
CO2 emissions from affected EGUs in a state during an
identified plan performance period must be equal to or less than the
CO2 mass goal (or mass-based CO2 goal plus new
source CO2 emission complement) minus an adjustment for
the ``exported'' CO2 allowances during the plan
performance period. The adjustment represents CO2
emissions (in tons) equal to the number of net ``exported''
CO2 allowances. Net ``exports'' of allowances are
determined through review of tracking system compliance accounts.

    Where CO2 emissions from affected EGUs exceed these
levels (based on reported CO2 emissions with applied plus or
minus adjustments for net CO2 allowance ``imports'' or
``exports'') over the 8-year interim period or during any final plan
reporting period, or by 10 percent or more during the interim step 1 or
step 2 periods, a state would be considered to, in the case of the
interim and final periods, not have met its CO2 mass goal
during an identified plan performance period, and in the case of the
interim step periods, to not be on course to meet the final goal. As a
result, under a state measures state plan, implementation of the
backstop federally enforceable emission standards for affected EGUs in
the state plan would be triggered.
    A net transfer of CO2 allowances during a plan
performance period represents the net number of CO2
allowances (issued by a respective state) that are transferred from the
compliance accounts of affected EGUs in that state to the compliance
accounts of affected EGUs in another state.\932\ This net transfer is
determined based on compliance account holdings at the end of the plan
performance period.\933\ For example, assume two states, State A and
State B, with emission budgets of 1,000 tons of CO2. Each
state issues 1,000 CO2 allowances. At the end of a plan
performance period, affected EGUs in State A collectively hold 500
CO2 allowances in their compliance accounts that were issued
by State A. Affected EGUs in State B collectively hold in their
compliance accounts 500 CO2 allowances issued by State A and
1,000 CO2 allowances issued by State B. In this simplified
example, a net transfer of 500 CO2 allowances has occurred
between State A and State B. State A has ``exported'' 500
CO2 allowances to State B, while State B has ``imported''
500 CO2 allowances from state A.
---------------------------------------------------------------------------

    \932\ A net transfer metric is applied as of the end of the plan
performance period. This net accounting as of a specified date is
necessary because multiple individual allowance transfers may occur
among accounts during a plan performance period, representing normal
trading activity. In addition, net transfers are based on compliance
account holdings, because these represent the CO2
allowances directly available at that point in time for use by an
affected EGU for complying with its emission limit. Emission budget
trading programs typically allow non-affected entities to hold
allowances in general accounts. These parties are free to hold and
trade CO2 allowances, providing market liquidity. General
account holdings are not assessed as part of a periodic state net
transfer accounting, as these allowances may subsequently be
transferred to other accounts in multiple states and do not
represent allowances currently held by an affected EGU that can be
used for complying with its emission limit.
    \933\ Compliance account holdings, as used here, refer to the
number of CO2 allowances surrendered for compliance
during a plan performance period, as well as any remaining
CO2 allowances held in a compliance account as of the end
of a plan performance period.
---------------------------------------------------------------------------

K. Additional Considerations and Requirements for Rate-Based State
Plans

    This section discusses considerations and requirements for rate-
based state plans. This section discusses eligibility, accounting, and
quantification and verification requirements (EM&V) for the use of
CO2 emission reduction measures that provide substitute
generation for affected EGUs or avoid the need for generation from
affected EGUs in rate-based state plans. These measures may be used to
adjust the CO2 emission rate of an affected EGU under a
rate-based state plan. This adjustment may occur when an affected EGU
is demonstrating compliance with a rate-based emission standard, or
when a state is demonstrating achievement of the CO2
emission performance rates or applicable rate-based state
CO2 emission goal in the emission guidelines. This section
also discusses requirements for state plans that include rate-based
emission trading programs, including approaches and requirements for
coordination among such programs where states retain individual state
rate-based CO2 emission goals.
1. Adjustments to CO2 Emission Rates in Rate-Based State
Plans
    Section VIII.K.1.a below describes the basic accounting method for
adjusting a CO2 emission rate, as well as eligibility
requirements for measures that may be used for adjusting a
CO2 emission rate. Section VIII.K.1.b addresses measures
that may not be used to adjust the CO2 emission rate of an
affected EGU in a state plan, and explains the basis for this
exclusion. Section VIII.K.1.c addresses measures that reduce
CO2 emissions outside the electric power sector. Such
measures may not be counted under either a rate-based or mass-based
state plan.
    a. Measures taken to adjust the CO2 emission rate of an affected
EGU. This section describes how measures that substitute for generation
from affected EGUs or avoid the need for generation from affected EGUs
may be used in a state plan to adjust the CO2 emission rate
of an affected EGU. This section discusses the required accounting
method for adjusting a CO2 emission rate, as well as general
eligibility requirements that apply to different categories of measures
that may be used to adjust a CO2 emission rate. Where
relevant, this section also discusses additional specific accounting
methods and other relevant requirements that apply to different
categories of measures.
    A CO2 emission rate adjustment may be applied in
different rate-based state plan contexts. For example, in a rate-based
emission trading program, adjustments may be applied through the use of
ERCs.\934\ Regardless of the type of plan in which an adjustment is
applied, the same basic accounting and general eligibility requirements
described in this section will apply.
---------------------------------------------------------------------------

    \934\ ERCs may be issued for the measures presented in this
section, as well as to affected EGUs that emit at a CO2
emission rate below their assigned emission rate limit. ERC issuance
and trading is discussed in detail in section VIII.K.2. That section
addresses the accounting method for ERC issuance to affected EGUs
that perform below their assigned CO2 emission rate.
---------------------------------------------------------------------------

    As discussed in this section, a wide range of actions may be taken
to adjust the reported CO2 emission rate of an affected EGU
in order to meet a rate-based emission standard and/or demonstrate
achievement of a state CO2 rate-based emissions goal. All of
the measures described in this section will substitute for generation
from affected EGUs or avoid the need for generation

from affected EGUs, thereby reducing CO2 emissions. This
includes incremental NGCC and RE measures included in the EPA's
determination of the BSER, as well as other measures that were not
included in the determination of the BSER, such as other RE resources,
demand-side EE, CHP, WHP, electricity transmission and distribution
improvements, nuclear energy, and international RE imports connected to
the grid in the contiguous U.S., as discussed elsewhere in this
preamble.
    The EPA believes that the broad categories of measures listed in
this section address the wide range of actions that are available to
reduce CO2 emissions from affected EGUs under a rate-based
state plan. However, the actions that a state could include in a rate-
based state plan are not necessarily limited to those described in this
section. Other specific actions not listed here may be incorporated in
a state plan, provided they meet the general eligibility requirements
listed in this section, as well as the other relevant requirements in
the emission guidelines.\935\ Nor are states required to include in
their plans all of the actions that are described in this section.
---------------------------------------------------------------------------

    \935\ These requirements are discussed in section VIII.D.
---------------------------------------------------------------------------

    This section discusses the basic accounting method for adjusting
the reported CO2 emission rate of an affected EGU, through
the use of measures that substitute for or avoid generation from
affected EGUs. That method is based on adding MWh from such measures to
the denominator of an affected EGU's reported CO2 emission
rate (lb CO2/MWh). Those additional MWh are based on
quantified and verified electricity generation or electricity savings
from eligible measures, and in the case of an affected EGU's compliance
with its emission standard, are reflected in ERCs. This section also
addresses eligibility requirements for resources that are used to
adjust an affected EGU's CO2 emission rate.
    (1) General accounting approach for adjusting a CO2 emission rate.
    In this final rule, the reported CO2 emission rate of an
affected EGU may be adjusted based on quantified and verified MWh from
qualifying zero-emitting and low-emitting resources, as described in
sections VIII.K.1.a.(2)-(10) below. These MWh are added to the
denominator of an affected EGU's reported CO2 emission rate,
resulting in a lower adjusted CO2 emission rate.
    The measures described in these sections reduce mass CO2
emissions from affected EGUs by substituting zero- or low-emitting
generation for generation from affected EGUs, or by avoiding the need
for generation altogether (in the case of resources that lower
electricity demand through improved demand-side EE and DSM). In both of
these cases, generation from an affected EGU is replaced, through
substitute generation or a reduction in electricity demand. To the
extent that qualifying zero-emitting and low-emitting resources result
in reduced generation and CO2 emissions from an individual
affected EGU, those emission impacts are reflected in lower reported
CO2 emissions and a reduction in MWh generation from the
affected EGU. However, while there will be a reduction in
CO2 emissions at the affected EGU, the fact that both
CO2 emissions and MWh generation are reduced means that such
impacts do not alter the reported CO2 emission rate of the
affected EGU. As a result, the MWh of replacement generation must be
added to the denominator of the reported CO2 emission rate
in order to represent those impacts in the form of an adjusted
CO2 emission rate. In this manner, adding MWh from these
resources to the denominator of an affected EGU's CO2
emission rate allows mass CO2 emission reductions from these
measures to be fully reflected in an adjusted CO2 emission
rate.
    The following provides a simple calculation example of how MWh of
replacement generation added to the denominator of an affected EGU's
reported CO2 emission rate results in a lower adjusted
CO2 emission rate. Assume an affected EGU with
CO2 emissions of 200,000 lb and electric generation of 100
MWh during a reporting period. The affected EGU's reported
CO2 emission rate is 2,000 lb/MWh (200,000 lb
CO2/100 MWh = 2,000 lb/MWh). When complying with its rate-
based emission limit, the affected EGU submits 10 ERCs, representing 10
MWh of replacement generation.\936\ Adding 10 MWh of replacement
generation to the reported MWh generation of the affected EGU results
in an adjusted CO2 emission rate of 1,818 lb CO2/
MWh (200,000 lb CO2/110 MWh = 1,818 lb CO2/MWh).
---------------------------------------------------------------------------

    \936\ Requirements for the issuance of ERCs and a further
discussion of how ERCs are used in compliance with rate-based
emission limits are addressed in section VIII.K.2.
---------------------------------------------------------------------------

    In the case of rate-based CO2 emission standards, an
affected EGU demonstrates compliance with the emission standards if the
affected EGU's adjusted CO2 emission rate calculated in the
aforementioned manner is less than or equal to the applicable
CO2 emission standard rate.\937\ The CO2 emission
performance rates or rate-based CO2 goal in the emission
guidelines are met if the adjusted CO2 emission rate of
affected EGUs in a state is at or below the specified CO2
emission rate in a state plan that applies for an identified plan
performance period.
---------------------------------------------------------------------------

    \937\ Any ERCs used to adjust a CO2 emission rate
must meet requirements in the emission guidelines.
---------------------------------------------------------------------------

    Numerous commenters requested that the EPA ensure consistency
between goal-setting calculations and the methodology used to
demonstrate achievement of a CO2 emission rate under a state
plan. This approach for adjusting a CO2 emission rate
corresponds with how RE, one of the components of the BSER that
involves adjustment of a CO2 emission rate, is represented
in the CO2 emission performance rates in the emission
guidelines. Specifically, in the calculation of final CO2
emission performance rates, the MWhs of RE are reflected in two
adjustments of the rate: A reduction of CO2 emissions from
affected EGUs in the numerator and a one-to-one replacement of affected
EGU generation in the denominator, where it is assumed that replaced
generation from an affected EGU is subtracted from the denominator and
the same number of zero-emitting MWh are added.\938\
---------------------------------------------------------------------------

    \938\ For a detailed discussion of this method, see Section
VI.C.3. Form of the Performance Rates, in the Equation section.
---------------------------------------------------------------------------

    When demonstrating achievement of a CO2 emission
performance rate, the reported CO2 emissions already reflect
the actual emission reductions from the deployment of qualifying zero-
emitting and low-emitting resources across the regional grid; a further
adjustment of CO2 emissions would double count
CO2 emissions impacts across the grid. Consistent with the
EPA's calculation of the CO2 emission performance rates and
state rate-based CO2 goals in the emission guidelines, the
zero-emitting MWhs (from substitute generation or a reduction in
electricity demand) must still be added to the denominator of a
reported CO2 emission rate to calculate an adjusted
CO2 emission rate that appropriately reflects the replaced
generation. Thus, the resultant rate, where the numerator reflects
CO2 emission reductions from qualifying measures, and the
denominator reflects replaced generation, is consistent with the goal-
setting calculation.
    Several commenters suggested that the EPA consider the regional
nature of the electricity grid and how RE and demand-side EE impacts
generation and CO2 emissions across the grid when accounting
for the impacts of RE and

demand-side EE measures in a rate-based plan approach. This MWh
accounting structure corresponds with the regional treatment of RE
resources in the BSER that provide substitute generation in the EPA-
calculated CO2 emission performance rates in the emission
guidelines. Consistent with assumptions used in calculating the
CO2 emission performance rates in the emission guidelines,
affected EGUs and states can take full credit for the MWh resulting
from eligible measures they are responsible for deploying, no matter
where those measures are implemented. CO2 emission
reductions from the eligible measures may occur across the region;
however, an affected EGU or a state may only take credit for avoided
CO2 emissions at that affected EGU or set of EGUs in
question, as reflected in the reported stack CO2 emissions
of affected EGUs.
    Because of the separate accounting of MWhs and CO2
emissions, with emission impacts inherent in reported stack
CO2 emissions and zero-emitting MWh impacts requiring
explicit adjustments, the accounting method corresponds with the use of
MWh-denominated ERCs in the rate-based emission trading framework
specified in this rule. The accounting method only requires a
quantification of the MWh generated or avoided by an eligible measure,
and thus credits or adjustments can be denominated in MWh and do not
need to represent an approximation of the CO2 emission
reductions that result from those MWhs. This creates a crediting system
or rate adjustment process that is simpler to implement than one that
requires an approximation of avoided CO2 emissions.
    The MWh accounting method also creates a crediting system or rate
adjustment process that is indifferent to the rate-based CO2
emission goals of individual states, or the specific CO2
emission rate standards that states may apply, and the relative
stringency of those goals or standards. Use of ERCs in rate-based
emission trading programs is addressed in detail in section VIII.K.2.
As a result, the MWh accounting method addresses interstate effects,
because it inherently accounts for how generation replacement and
CO2 emission reduction impacts may cross state borders. For
example, if the accounting method was informed by avoided
CO2 emission rates, it could create perverse incentives for
development of zero- or low-emitting resources in states that result in
the greatest calculated estimate of CO2 emission reductions
for each replacement MWh. Instead, this accounting method is
indifferent to avoided CO2 emission rates and creates the
same number of zero-emitting credits or adjustment for each MWh of
energy generation or savings, wherever they occur. For a detailed
discussion on how the accounting method addresses interstate effects,
see section VIII.L.
    (2) General eligibility requirements for resources used to adjust a
CO2 emission rate.
    The EPA is finalizing certain general eligibility requirements for
resources used to adjust a CO2 emission rate. These
requirements align eligibility with certain factors and assumptions
used in establishing the BSER, and by extension, application of the
BSER to the performance levels established for affected EGUs in the
emission guidelines, as well as state rate and mass CO2
goals. As a result, the requirements ensure that measures that may be
used in a state plan are treated consistently (to the extent possible)
with the EPA's assessment of the BSER.\939\ These general requirements
also address potential interactions among rate and mass plans, as
discussed more fully in section VIII.L.
---------------------------------------------------------------------------

    \939\ For example, eligibility requirements include installation
dates for eligible RE measures that may be used in a state plan.
These dates generally align with the dates used for broadly defining
incremental RE resources that were considered in establishing the
BSER.
---------------------------------------------------------------------------

    As discussed in the sections that follow, the general eligibility
criteria address:

     The date from which eligible measures may be installed
(e.g., installation of RE generating capacity and installation of EE
measures);
     the date from which MWh from eligible measures may be
counted, and applied toward adjusting a CO2 rate; and
     the need to demonstrate that eligible measures replace
or avoid generation from affected EGUs.

    (a) Eligibility date for installation of RE/EE and other measures
and MWh generation and savings.
    Incremental emission reduction measures, such as RE and demand-side
EE, can be recognized as part of state plans, but only for the emission
reductions they provide during a plan performance period. Specifically,
this means that measures installed in any year after 2012 are
considered eligible measures under this final rule, but only the
quantified and verified MWh of electricity generation or electricity
savings that they produce in 2022 and future years may be applied
toward adjusting a CO2 emission rate. For example, MWh
generation in 2022 from a wind turbine installed in 2013 may be applied
toward adjusting a CO2 emission rate. This 2012 date applies
to all eligible measures that are used to adjust a CO2
emission rate under a state plan. For example, eligible measures, such
as CHP, nuclear power and DSM, also must be installed after 2012, but
only their generation or savings produced in 2022 and after can be used
to adjust a CO2 emission rate.
    As discussed in section VIII.C.2.a, a MWh of generation or savings
that occurs in 2022 or a subsequent year may be carried forward (or
``banked'') and applied in a future year. For example, a MWh of RE
generation that occurs in 2022 may be applied to adjust a
CO2 emission rate in 2023 or future years, without
limitation.\940\ These MWh may be banked from the interim to final
periods.
---------------------------------------------------------------------------

    \940\ Similarly, as discussed in section VIII.C.2.b.(2).(a),
allowances may be banked in a mass-based trading program.
---------------------------------------------------------------------------

    This eligibility date criterion is consistent with the date of
installation for ``incremental'' RE capacity that is included in the
BSER building block 3, which is the basis for RE MWh incorporated in
the CO2 emission performance rates for affected EGUs in the
emission guidelines. For more information on RE in the BSER, see
section V.E.
    Many commenters asserted that proposed state goals did not
sufficiently account for actions states take that reduce CO2
emissions prior to the first plan performance period, and therefore
requested that MWhs of electricity generation or electricity savings
that occur prior to the first plan performance period be eligible to
apply toward adjusting the CO2 emission rates of affected
EGUs. The EPA recognizes the importance of early state action as the
basis for significant CO2 emission reductions and as a key
part of enabling state plans to achieve the CO2 emission
performance levels or state CO2 goals. The ability to count
eligible measures installed in 2013 and subsequent years for the MWhs
they generate during a plan performance period provides significant
recognition for early action, corresponding with the BSER framework
that is based on cost-effective actions that many sources are already
doing, while still conforming to CO2 performance rates and
state goals that are forward-looking. In order to provide additional
incentives for early investment in RE and demand-side EE, the EPA is
also establishing the CEIP, as discussed in section VIII.B.2. ERCs
distributed by states and the EPA through this program may also be used
by affected EGUs to demonstrate compliance with an emission standard,

and may be banked from the interim to final periods.
    Commenters' concerns about treatment of early actions are further
addressed by changes from proposal to the BSER assumptions and the
methodology used by the EPA to establish the CO2 emission
performance levels and rate-based state CO2 goals in the
emission guidelines. The specifics of these changes are addressed in
section V.A.3. Three examples of those changes are provided below.
    First, affected EGUs that have maximized their CO2
emission reduction opportunities available through early action will be
better positioned to meet the BSER CO2 emission performance
rates or state goal applied to affected EGUs in their state. For
example, a steam generating unit that has already reduced its
CO2 emission rate through a heat rate improvement may have a
CO2 emission rate of 2,000 lb/MWh whereas its rate was 2,100
lb/MWh prior to the improvement. Therefore, it has less distance to
cover to meet its CO2 emission performance rate.
    Second, generation from existing RE capacity installed prior to
2013 has been excluded from the EPA's calculation of the CO2
emission performances rates in the emission guidelines. That RE
generating capacity will still provide zero-emitting generation to the
grid meeting demand that will not need to be addressed by existing
affected EGUs and will better position states and affected EGUs to meet
the CO2 performances rates or state rate- or mass-based
CO2 goals.
    Third, commenters expressed concern that demand-side EE targets as
part of proposed state goals reflected an assumption of installation of
increased EE measures starting in 2017, which seemed to be an implicit
requirement to take action prior to the performance period. Because
demand-side EE is not used in calculating the CO2 emission
performance rates in the final emission guidelines, this is no longer a
concern. Furthermore, eligible demand-side EE actions that occur after
2012 can be applied toward adjusting the CO2 emission rates
of affected EGUs, providing a significant compliance option that is not
assumed in emission performance rates or state goals.
    (b) Demonstration that measures substitute for grid generation.
    Eligible measures must be grid-connected. This eligibility
criterion aligns incremental NGCC generation in building block 2. It
also aligns with RE generation in building block 3 of the BSER, which
substitutes for the need for generation from affected EGUs.
    All EE measures must result in electricity savings at a building,
facility, or other end-use location that is connected to the
electricity grid. EE measures only avoid electric generation from grid-
connected EGUs if the electrical loads where the efficiency
improvements are made are interconnected to the grid.
    Commenters sought clarity on this issue, so the EPA is providing
this requirement as part of the final rule. Some commenters advocated
for the inclusion of measures that were not grid connected as eligible
resources, arguing that some of these measures substituted for non-
affected EGUs and resulted in reductions in CO2 emissions.
However, eligible measures must be able to substitute for generation
from affected EGUs as defined under this rule, and thus must be tied to
the electrical grid.
    (c) Geographic eligibility.
    All eligible emission reduction measures, including RE generation
and demand-side EE, may occur in any state, with certain limitations,
as described below. To the extent these measures are tied to a state
plan,\941\ these measures may be used to adjust a CO2
emission rate, regardless of whether the associated generation or
electricity savings occur inside or outside the state.\942\ This
approach is generally consistent with the approach used in building
block 3 of the BSER, which reflects regionally available RE. It also
recognizes that emission reduction measures have impacts on electricity
generation across the electricity system, both within and beyond a
state's borders. A more in-depth discussion of the basis for treatment
of in-state and out-of-state measures is provided in section VIII.L.
---------------------------------------------------------------------------

    \941\ As used here, a measure is ``tied to a state plan'' if it
is issued an ERC under approved procedures in a rate-based emission
standards plan or represents quantified and verified MWh energy
generation or energy savings achieved by an approved state measure
in a state measures plan.
    \942\ For example, under a rate-based emission standard with
credit trading, ERCs may be issued for qualifying actions that occur
both inside and outside the state, provided the measures meet
requirements of EPA-approved state regulations and the provider
applies to the state for the issuance of ERCs. Similarly, under a
state measures plan, a state might include state requirements such
as an RPS, where compliance with the RPS can be met through out-of-
state RE generation.
---------------------------------------------------------------------------

    State plans must demonstrate that emission standards and state
measures (if applicable) are non-duplicative. Given the geographic
eligibility approach described here, this includes a demonstration that
a state plan does not allow recognition of a MWh, for use in adjusting
the CO2 emission rate of an affected EGU, if the MWh is
being or has been used for such a purpose under another state plan.
Discussion of how such a demonstration can be made in the context of a
rate-based emission trading program is in section VIII.D.2.b.
    The EPA received many comments on the treatment of in-state and
out-of-state RE and demand-side EE. Most commenters recommended
crediting of both in-state and out-of-state RE and demand-side EE
measures, similar to the final rule approach for eligible emission
reductions measures. Commenters argued that this approach makes sense
based on the nature of the interconnected electricity grid and allows
states and utilities to fully account for their RE and demand-side EE
efforts, whether that RE or EE, and its related impacts, occurs inside
or outside of their state. Some commenters expressed concerns that, at
proposal, states with significant RE resources had large amounts of
existing RE capacity included in their state CO2 goals, but
that RE was functionally credited to other states for use in meeting
their goals because it was associated with measures (such as an RPS)
likely to be included in another state's plan. This concern has been
addressed through changes in the BSER RE assumptions in the final rule.
This includes regionalization of the RE building block, and removal of
existing RE capacity constructed prior to 2012 from the building block.
The result of these changes is that the RE incorporated in the BSER is
more equally shared across states.
    (i) Measures that occur in states with mass-based plans.
    As discussed above, eligible measures for adjusting the
CO2 emission rate of an affected EGU may occur in any state,
with certain conditions. This includes a condition that applies to
eligible measures that occur in a state with an EPA-approved plan that
is meeting a state mass-based CO2 goal. Eligible measures
that could be used to adjust a CO2 emission rate under a
rate-based state plan which are located in a state with a mass-based
plan are restricted from being counted under another state's rate-based
plan. An exception is made for RE measures that occur in such mass-
based states, because of its unique role in BSER. RE measures must meet
additional eligibility criteria in order to be used to adjust the
CO2 emission rate of an affected EGU in a state with a rate-
based plan. This exception only applies to RE; other emission reduction
measures that were not included in the determination of the BSER
located in mass-based states, including demand-side EE, are restricted
from ERC issuance in rate-based states.

    These criteria are intended to address the fact that eligible
measures should lead to substitution of generation from affected EGUs,
with related impacts on CO2 emissions from affected EGUs.
Where states with mass-based plans implement mass-based CO2
emission standards, CO2 emissions reductions from affected
EGUs must occur in order to comply with these emission standards and,
unlike the rate-based approach, zero- and low-emitting MWhs do not play
a specified role in demonstrating that the mass-based standards have
been met.\943\ Since they are not counted in the mass-based
demonstration, eligible measures located in mass-based states could be
used in a state with a rate-based plan to adjust the CO2
emission rate of affected EGUs. Such adjustments would obviate the need
for comparable CO2 emission reductions at affected EGUs in
the rate-based state or the use of other measures to make a rate
adjustment. In this scenario, to the extent that eligible measures
substitute solely for generation from affected EGUs in a state with
mass-based emission limits, and are also used to adjust the reported
CO2 emission rate of affected EGUs in a rate-based state, no
incremental CO2 emissions reductions would occur in the
rate-based state as a result of the eligible measures.\944\ The result
would be forgone CO2 emission reductions that would
otherwise occur across the two states. These dynamics are further
addressed in section VIII.L.
---------------------------------------------------------------------------

    \943\ Where such measures substitute for generation from
affected EGUs subject to a mass CO2 emission limit, such
measures reduce the cost of meeting those mass emission limits, but
do not result in incremental CO2 emission reductions.
    \944\ As used here, incremental emission reductions refers to
emission reductions that are above and beyond what would be achieved
solely through compliance with the emission standards in the mass-
based state.
---------------------------------------------------------------------------

    For RE measures located in a mass-based state to have some or all
of its generation counted under a rate-based plan in another state, it
must be demonstrated that the generation was delivered to the grid to
meet electricity load in a state with a rate-based plan.\945\ Some
examples of documentation that can serve as a demonstration include a
power delivery contract or power purchase agreement. The EPA is giving
states flexibility regarding the nature of this demonstration, but a
state plan must describe the nature of the required demonstration and
have it be approved by the EPA.
---------------------------------------------------------------------------

    \945\ This does not need to necessarily be the state where the
MWh of energy generation from the measure is used to adjust the
CO2 emission rate of an affected EGU.
---------------------------------------------------------------------------

    Under an emission standards plan, this demonstration must be made
by the provider of the RE measure seeking ERC issuance under the rate-
based emission standards in a rate-based state, as part of the
eligibility application for the measure.\946\ The rate-based state must
include in its state plan provisions that describe a sufficient
demonstration of geographic eligibility for the RE generation under
rate-based emission standards.
---------------------------------------------------------------------------

    \946\ Requirements for ERC issuance are addressed in section
VIII.K.2.
---------------------------------------------------------------------------

    Further examples of eligible demonstrations and how they should be
outlined in state plans are provided in section VIII.L.
    (ii) Measures that occur in states, including areas of Indian
country, that do not have affected EGUs.
    States, including areas of Indian country, that do not have any
affected EGUs within their borders may be providers of credits for
generation from zero- or low-emitting resources to adjust
CO2 emission rates. In its supplemental proposal for the
proposed rulemaking, the EPA sought comment on whether or not
jurisdictions without affected fossil fuel generation units subject to
the proposed emission guidelines should be authorized to participate in
state plans. Commenters were supportive of allowing those jurisdictions
without affected EGUs the opportunity to participate in state plans.
CO2 reduction measures in areas without affected EGUs have
the potential to provide cost-effective opportunities to reduce
emissions and should be available on a voluntary basis to affected
EGUs. Commenters noted that some tribes, for example, have many
untapped RE resources that could be developed, and they should be able
to realize the benefits of contributing to a state plan. Commenters
stated that because of the integrated nature of the U.S. electricity
grid, it is appropriate to allow all jurisdictions with the ability to
contribute to and benefit from CO2 emission reductions or
CO2 emission rate adjustments.
    For participating states, they must adhere to EM&V standards,
installation dates, and any other criteria that apply to all states.
Section VIII.K.3 below identifies and discusses the EM&V requirements
used to quantify MWh savings from generation from zero- or low-emitting
sources.
    States, including areas of Indian country, that do not have any
affected EGUs may provide ERCs to adjust CO2 emissions
provided they are connected to the contiguous U.S. grid and meet the
other requirements for eligibility. To qualify for ERCs from zero or
low-emitting resources, it must be demonstrated that the generation was
delivered to the grid to meet electricity load in a state with a rate-
based plan.\947\ Some examples of documentation that can serve as a
demonstration include a power delivery contract or power purchase
agreement. The EPA is giving states flexibility regarding the nature of
this demonstration, but a state plan must describe the nature of the
required demonstration and have it be approved by the EPA.
---------------------------------------------------------------------------

    \947\ This does not need to necessarily be the state where the
MWh of energy generation from the measure is used to adjust the
CO2 emission rate of an affected EGU.
---------------------------------------------------------------------------

    In addition to generation from zero- or low-emitting resources,
demand-side EE resources in areas of Indian country located within the
borders of states with rate-based emission standards for affected EGUs
may also be issued ERCs. In these instances, the area of Indian country
is located within the rate-based service area subject to a rate-based
state plan. The ERCs from demand-side EE resources must meet the
eligibility requirements to adjust a CO2 emission rate,
including installation date and EM&V requirements described below in
section VIII.K.3. If the area of Indian country is located within the
borders of a state that is meeting a mass-based CO2 goal,
then the demand-side EE resources are not eligible to be issued ERCs.
Similarly, demand-side EE resources in any state with a mass-based
CO2 goal are not eligible to provide ERCs.
    Non-contiguous states and territories may not be providers of ERCs
to the contiguous U.S. states. As discussed previously in section
VII.F, we have not set CO2 emission performance goals for
Alaska, Hawaii, Guam, or Puerto Rico in this final rule at this time.
    (iii) Measures that occur outside the U.S.
    The EPA will work with states using the rate-based approach that
are interested in allowing the use of RE from outside the U.S. to
adjust CO2 emission rates. In these cases, all conditions
for creditable domestic RE must be met, including that RE resources
must be incremental and installed after 2012, and all EM&V standards
must be met. In addition, the country generating the ERCs must be
connected to the U.S. grid, and there must be a power purchase
agreement or other contract for delivery of the power with an entity in
the U.S. RE generation capacity outside the U.S. that existed prior to
2012 but was not exported to the U.S. is not considered new or
incremental generation and, therefore,

not eligible for adjusting CO2 emission rates under this
rule. For example, a new transmission interconnection to existing RE in
Canada would not be considered incremental, but a new interconnection
to RE where the RE was built after 2012 would be considered
incremental. See below in section VIII.K.1.a.(3) for more specifics
regarding the use of incremental hydroelectric power in a rate-based
approach.
    The EPA received comments encouraging the use of international
zero-emitting electricity imports in state plans, particularly
hydroelectric power from Canada. Canada currently provides states such
as Minnesota and Wisconsin with RE through existing grid connections.
New projects are in various stages of development to increase
generating capacity, which could be called upon as a base load resource
to supplement variable forms of RE generation. Commenters said that the
EPA should permit the use of all incremental hydropower--both domestic
and international--towards EGU CO2 emission rate adjustments
providing that double-counting can be prevented; and the EPA
acknowledges this may be allowable, as long as the specified criteria
have been met.
    (3) RE.
    RE measures may be used to adjust a CO2 emission rate,
provided they meet the general eligibility requirements outlined above
and the MWh electricity generation is properly quantified and
verified.\948\ As used in this section, RE includes electric generating
technologies using RE resources, such as wind, solar, geothermal,
hydropower, biomass and wave and tidal power. A capacity uprate at an
existing RE facility (i.e., an uprate to generating capacity originally
installed as of 2012 or earlier) is eligible to adjust a CO2
emission rate. The capacity uprate must occur after 2012. Such uprates
to capacity represent incremental capacity added after 2012.
---------------------------------------------------------------------------

    \948\ All state plans must demonstrate that measures included in
the plan are quantifiable and verifiable. See section VIII.K.2 for
discussion of requirements for the issuance of ERCs, and section
VIII.K.3 for discussion of EM&V requirements for use of RE relied on
in a state plan.
---------------------------------------------------------------------------

    Quantification and accounting criteria for incremental RE (and
nuclear generation) are as follows. The incremental generating capacity
(in nameplate MW) is divided by the total uprated generating capacity
(in nameplate MW) and then multiplied by generation output (in MWh)
from the uprated generator. For example, if a hydroelectric power plant
expands generating nameplate capacity from 100 MW to 125 MW and
generation output increased to 1,000 MWh, then 200 MWh ((25 MW/125 MW)
* 1,000 MWh) is eligible for use in adjusting a CO2 emission
rate, regardless of the overall level of generation for the
period.\949\
---------------------------------------------------------------------------

    \949\ For example, the overall generation from the uprated
hydroelectric power plant may be higher or lower than generation
levels that occurred at the plant prior to the capacity uprate.
---------------------------------------------------------------------------

    Many commenters supported using RE deployment as measures to adjust
the CO2 emission rate of affected EGUs. Some commenters
specifically agreed with the EPA's determination that only new and
incremental RE (including hydropower) should be used to adjust
CO2 emission rates. Those commenters objected to counting
existing RE that are already embedded in the baseline emissions and
generation mix. A significant number of commenters supported the
integration of RE into a rate-based credit trading system.
    Certain additional requirements apply for hydropower and biomass
(including waste-to-energy) RE, as described below.
    (a) Hydroelectric power.
    Consistent with other types of RE, new hydroelectric power
generating capacity installed after 2012 is eligible for use in
adjusting a CO2 emission rate.
    Relicensed facilities are considered existing capacity and,
therefore, are not eligible for use in adjusting a CO2
emission rate, unless there is a capacity uprate as part of the
relicensed permit. In such a case, only the incremental capacity is
eligible for use in adjusting a CO2 emission rate.
    The EPA noted that many commenters preferred that generation from
hydropower displace generation from fossil sources. One commenter
suggested that existing zero-emitting sources, including hydropower, do
not reduce emissions from existing fossil generation, but that new or
uprated zero-emitting sources would, because of their low variable
rate, reduce fossil emissions. Several commenters recommended allowing
incremental generation from new or uprated zero-emitting sources,
including hydropower, be available for compliance.
    (b) Biomass.
    RE generating capacity installed after 2012 that uses qualified
biomass as a fuel source is eligible for use in adjusting a
CO2 emission rate.\950\ As discussed in section VIII.I.2.c.,
if a state intends to allow for the use of biomass as a compliance
option for an affected EGU to meet a CO2 emission standard,
a state must propose qualified biomass feedstocks and treatment of
biogenic CO2 emissions in its plan, along with supporting
analysis and quality control measures, and the EPA will review the
appropriateness and basis for such determinations in the course of its
review of a state plan. Where an RE generating unit uses qualified
biomass, as designated in an approved state plan, MWh generation from
the unit could be used to adjust the reported CO2 emission
rate of an affected EGU. Total MWh generation from an RE generating
unit that uses qualified biomass must be prorated based on either the
heat input supplied from qualified biomass as a proportion of total
heat input or on the proportion of biogenic CO2 emissions
compared to total stack CO2 emissions from the RE generating
unit. Either approach must incorporate the approved valuation of
biogenic CO2 emissions from qualified biomass in the plan
(i.e., the proportion of biogenic CO2 emissions from use of
qualified biomass feedstock that would not be counted).
---------------------------------------------------------------------------

    \950\ As with other RE, only generating capacity installed after
2012 would be eligible for use in adjusting a CO2
emission rate.
---------------------------------------------------------------------------

    Section VIII.K describes the requirements and procedures for EM&V,
and discusses how all eligible resources must demonstrate how they will
quantify and verify MWh savings using best-practice EM&V approaches.
One way to make this demonstration for eligible resources could be to
use the presumptively approvable EM&V approaches that are included in
the final model trading rule.
    (c) Waste-to-energy.
    Qualified biomass may include the biogenic portion of MSW combusted
in a waste-to-energy facility.\951\ With regard to assessing qualified
biomass proposed in state plans, the EPA generally acknowledges the
CO2 emissions and climate policy benefits of waste-derived
biomass, which includes biogenic MSW inputs to waste-to-energy
facilities. The process and considerations for the use of biomass in
state plans are discussed in section VIII.I.2.c.
---------------------------------------------------------------------------

    \951\ As with other RE, only generating capacity installed after
2012 would be eligible for use in adjusting a CO2
emission rate.
---------------------------------------------------------------------------

    MSW can be directly combusted in waste-to-energy facilities to
generate electricity as an alternative to landfill disposal. In the
U.S., almost all incineration of MSW occurs at waste-to-energy
facilities or industrial facilities where the waste is combusted and
energy is recovered.\952\ Total MSW generation in 2012 was 251 million
tons, but of that total volume generated, almost 87 million tons were
recycled

and composted.\953\ Increasing demand for electricity generated from
waste-to-energy facilities could increase competition for and
generation of waste stream materials--including discarded organic waste
materials--which could work against programs promoting waste reduction
or cause diversion of these materials from existing or future efforts
promoting composting and recycling. The EPA and many states have
recognized the importance of integrated waste materials management
strategies that emphasize a hierarchy of waste prevention, starting
with waste reduction programs as the highest priority and then focusing
on all other productive uses of waste materials to reduce the volume of
disposed waste materials.\954\ For example, Oregon and Vermont have
strategies that emphasize waste prevention, followed by reuse, then
recycling and composting materials prior to treatment and
disposal.\955\
---------------------------------------------------------------------------

    \952\ 2014 Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2012. http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html.
    \953\ http://www.epa.gov/osw/nonhaz/municipal/pubs/2012_msw_fs.pdf.
    \954\ http://www.epa.gov/wastes/nonhaz/municipal/hierarchy.htm.
    \955\ http://www.anr.state.vt.us/dec/wastediv/WastePrevention/main.htm.
---------------------------------------------------------------------------

    Information in the revised Framework for Assessing Biogenic
CO2 Emissions from Stationary Sources and other technical
studies and tools (e.g., EPA Waste Reduction Model, EPA Decision
Support Tool) should assist both states and the EPA in assessing the
role of biogenic feedstocks used in waste-to-energy processes, where
use of such feedstocks is included in a state plan.\956\
---------------------------------------------------------------------------

    \956\ http://epa.gov/epawaste/conserve/tools/warm/Warm_Form.html, https://mswdst.rti.org/.
---------------------------------------------------------------------------

    When developing their plans, states planning to use waste-to-energy
as an option for the adjustment of a CO2 emission rate
should assess both their capacity to strengthen existing or implement
new waste reduction, reuse, recycling and composting programs, and
measures to minimize any potential negative impacts of waste-to-energy
operations on such programs. States must include that information in
their plan submissions. The EPA will reject as qualified biomass any
proposed waste-to-energy component of state plans if states do not
include information on their efforts to strengthen existing or
implement new waste reduction as well as reuse, recycling and
composting programs, and measures to minimize any potential negative
impacts of waste-to-energy operations on such programs. Only electric
generation at a waste-to-energy facility that is related to the
biogenic fraction of MSW and that is added after 2012 is eligible for
use in adjusting a CO2 emission rate.
    A state plan must include a method for determining the proportion
of total MWh generation from a waste-to-energy facility that is
eligible for use in adjusting a CO2 emission rate. The EPA
will evaluate the method as part of its evaluation of the approvability
of the state plan. Measuring the proportion of biogenic to fossil
CO2 emissions can be performed through sampling and testing
of the biogenic fraction of the MSW used as fuel at a waste-to-energy
facility (e.g., via ASTM D-6866-12 testing or other methods--ASTM,
2012; Bohar, et al. 2010), or based on the proportion of biogenic
CO2 emissions to total CO2 emissions from the
facility. For an example of the former method, if the biogenic fraction
of MSW is 50 percent by input weight, only the proportion of MWh output
attributable to the biogenic portion of MSW at the waste-to-energy
facility may be used to adjust an affected EGU CO2 emission
rate. Alternatively, as an example of the latter method, if biogenic
CO2 emissions represent 50 percent of total reported
CO2 emissions, a facility would need to estimate the
fraction of biogenic to fossil MSW utilized and the net energy output
of each component (based on relative higher heating values) to
determine the percent of the MWh output from the waste-to-energy
facility that may be used to adjust an affected EGU's CO2
emission rate. Section VIII.K describes the requirements and procedures
for EM&V, and discusses how all eligible resources must demonstrate how
they will quantify and verify MWh savings using best-practice EM&V
approaches. One way to make this demonstration for eligible resources
could be to use the presumptively approvable EM&V approaches that are
included in the final model trading rule.
    The EPA received multiple comments supporting the use of waste-to-
energy as part of state plans. Some commenters expressed concern that
non-biogenic materials, such as plastics and metal, would be
incinerated along with biogenic materials. As discussed above, only
electric generation related to the biogenic fraction of MSW at a waste-
to-energy facility added after 2012 is eligible for use in adjusting a
CO2 emission rate. The EPA also received comments that
expressed concern about the potential negative impacts on recycling and
waste reduction efforts, while other commenters asserted that waste-to-
energy practices encourage recycling programs. Some commenters also
expressed concern about what treatment would be approvable for
emissions from waste-to-energy practices. As discussed above, potential
negative impacts from waste-to-energy production on recycling, waste
reduction, and composting programs should be evaluated and efforts to
mitigate negative impacts must be discussed in the supporting
documentation of state plans.
    (4) DSM.
    Avoided MWh that result from DSM may be used to adjust a
CO2 emission rate. Eligible DSM actions are those that are
zero-emitting and avoid, rather than shift, the use of electricity by
an electricity end-user.\957\ The MWh that may be used for such an
adjustment are determined based on the MW of demand reduction
multiplied by the hours during which such a demand reduction is
achieved (MW of demand reduction x hours = MWh avoided). DSM measures
must be appropriately quantified and verified, in accordance with
requirements in the emission guidelines, as discussed in section
VIII.K.3.
---------------------------------------------------------------------------

    \957\ An example is a utility direct load control program, such
as those where customer air conditioning units are cycled during
periods of peak electricity demand. Actions that shift electricity
demand from one time of day to another, without reducing net
electricity use, are not eligible, as these measures do not avoid
electricity use from the grid. Use of emitting generators as a DSM
measure is also not eligible.
---------------------------------------------------------------------------

    (5) Energy storage.
    Energy storage may not be directly recognized as an eligible
measure that can be used to adjust a CO2 emission rate,
because storage does not directly substitute for electric generation
from the grid or avoid electricity use from the grid.\958\ The electric
generation that is input to an energy storage unit may be used to
adjust a CO2 emission rate, but the output from the energy
storage unit may not.\959\ However, energy storage can be used as an
enabling measure that facilitates greater use of RE, which can be used
to adjust a CO2 emission rate. For example, utility scale
energy storage may be used to facilitate greater grid penetration of RE
generating capacity and can also be used to store RE generation that
may have otherwise been shed in times of excess generating capacity.
Likewise, on-site energy storage at an electricity end-user can

enable greater use of RE to meet on-site electricity demand.\960\
---------------------------------------------------------------------------

    \958\ Energy storage depends on a generation source, either from
a utility-scale EGU (e.g., a fossil EGU, a wind turbine, etc.) or a
distributed generation source at an electricity end-user (e.g., a PV
system installed at a building).
    \959\ This approach focuses on counting the qualifying electric
generation, which may be an input to an energy storage unit.
Counting both the generation input to energy storage and the output
from the energy storage unit would be a form of double counting. The
electric generation that is stored may be counted; the subsequent
output from the storage unit may not.
    \960\ For example, battery storage at a building with solar PV
can enable the PV system to meet the building's entire electrical
load, by storing energy during times of peak PV system output for
later use when the sun is not shining.
---------------------------------------------------------------------------

    The EPA received multiple comments regarding the overall merits of
energy storage. Consistent with the discussion above, the majority of
commenters observed that storage technology enables greater grid
penetration of RE and supports more efficient and effective operations
of both RE and fossil-fuel plants. Commenters further noted that energy
storage can provide RE to the grid when it is most needed, while
simultaneously taking pressure off fossil-fuel plants to respond to
sudden shifts in demand. Despite broad acknowledgment of the benefits
of storage, public comments underscore its indirect and supporting role
in providing zero-emission MWh to the grid (consistent with the EPA's
decision to exclude energy storage as an eligible measure that can be
used to adjust a CO2 emission rate).
    (6) Transmission and distribution (T&D) measures.
    Electricity T&D measures that improve the efficiency of the T&D
system and/or reduce electricity use may be used to adjust a
CO2 emission rate. This includes T&D measures that reduce
losses of electricity during delivery from a generator to an end-user
(sometimes referred to as ``line losses'' \961\) and T&D measures that
reduce electricity use at the end-user, such as conservation voltage
reduction (CVR).\962\ The EPA received many comments in support of
advanced energy technologies, including energy storage and transmission
and distribution upgrades, and including these technologies in the
suite of potential measures that states could consider for emission
rate adjustments in their state plans. Comments pointed out that in
addition to helping achieve emission standards, T&D efficiency
improvements make the grid more robust and flexible, as well as
delivering environmental benefits. In many parts of the country, grid
operators, transmission planners, transmission owners and regulators
are already taking steps to expand and modernize T&D networks.
Commenters suggested that the EPA clarify the eligibility and criteria
under which such measures would be permitted in a state plan.
---------------------------------------------------------------------------

    \961\ T&D system losses (or ``line losses'') are typically
defined as the difference between electricity generation to the grid
and electricity sales. These losses are the fraction of electricity
lost to resistance along the T&D lines, which varies depending on
the specific conductors, the current, and the length of the lines.
The Energy Information Administration (EIA) estimates that national
electricity T&D losses average about 6 percent of the electricity
that is transmitted and distributed in the U.S. each year.
    \962\ Volt/VAR optimization (VVO) refers to coordinated efforts
by utilities to manage and improve the delivery of power in order to
increase the efficiency of electricity distribution. VVO is
accomplished primarily through the implementation of smart grid
technologies that improve the real-time response to the demand for
power. Technologies for VVO include load tap changers and voltage
regulators, which can help manage voltage levels, as well as
capacitor banks that achieve reductions in transmission line loss.
VVO efforts are often closely related to CVR, which are actions
taken to reduce initial delivered voltage levels in feeder
transmission lines while remaining within the 114 volt to 126 volt
range (for normal 120-volt service) required at the customer meter,
per the ANSI C84.1 standards.
---------------------------------------------------------------------------

    To be eligible, T&D measures must be installed after 2012. This
general eligibility requirement is discussed above in section
VIII.K.1.a. The MWh of avoided losses or reduction in end-use that
result from T&D measures must be appropriately quantified and verified,
as discussed in section VIII.K.3.
    (7) Demand-side EE, including water system efficiency.
    Demand-side EE measures may be used to adjust a CO2
emission rate, provided they meet the general eligibility requirements
outlined above and the MWh electricity savings are properly quantified
and verified.\963\ As used in this section, demand-side EE may include
a range of eligible measures, provided that the measures can be
quantified and verified in accordance with the EM&V requirements in the
emission guidelines, which are addressed in section VIII.K.3. Examples
of demand-side EE measures include, but are not limited to, EE measures
that reduce electricity use in residential and commercial buildings,
industrial facilities, and other grid-connected equipment. Water
efficiency programs that improve EE at water and wastewater treatment
facilities also provide demand-side EE savings opportunities. EE
measures, for the purposes of this section, may consist of EE measures
installed as the result of individual EE projects, such as those
implemented by energy service companies, as well as multiple EE
measures installed through an EE deployment program (e.g. appliance
replacement and recycling programs, and behavioral programs)
administered by electric utilities, state entities, and other private
and non-profit entities.\964\ EE measures, for the purposes of this
section, may also consist of state or local requirements that result in
electricity savings, such as building energy codes and state appliance
and equipment standards. Other interventions that result in electricity
savings may also be considered an EE measure for the purposes of this
section, provided the intervention can be specified and quantified and
verified in accordance with EM&V requirements in the emission
guidelines.
---------------------------------------------------------------------------

    \963\ All state plans must demonstrate that measures included in
the plan are quantifiable and verifiable. See section VIII.K.2 for
discussion of requirements for the issuance of ERCs, and section
VIII.K.3 for discussion of EM&V requirements for use of demand-side
EE relied on in a state plan.
    \964\ EE programs may also be implemented by other entities.
Eligible EE measures that are deployed through EE programs are not
limited to those EE measures deployed through EE programs
administered by the types of entities listed here.
---------------------------------------------------------------------------

    Numerous commenters expressed support for including demand-side EE
as an eligible measure states and affected EGUs can use to meet the
emission guidelines. Commenters touted the value of demand-side EE as a
resource that delivers energy savings, lowers bills, creates jobs and
reduces CO2 emissions. Commenters called for the EPA to
allow for the use of a broad range of demand-side EE measures to meet
the emission guidelines, including, but not limited to, utility and
non-utility EE deployment programs; energy savings performance
contracts; measures that reduce electricity use in residential and
commercial buildings, industrial facilities and other grid-connected
equipment; state and local requirements that result in electricity
savings, such as building energy codes and state appliance and
equipment standards; appliance replacement and recycling programs; and
behavioral programs. The EPA also received comments supporting the use
of water sector EE programs and projects. Commenters identified water
and wastewater utilities as particularly well-suited for participating
in EE programs and providing a source of electricity savings.
Investments such as replacing pumps and other aging equipment and
repairing leaks can result in greater EE. The EPA agrees that these
electricity savings should be eligible for adjustments to
CO2 emission rates at affected EGUs.
    (8) Nuclear power.
    As is discussed in section V.A.3, upon consideration of comments
received, the EPA has not included nuclear generation from either
existing or under construction units in the determination of the BSER.
In addition to comments received on the provisions for determining the
BSER, the EPA also received comments requesting that the EPA allow all
generation from nuclear generating units to be recognized as an

eligible measure that can be used to adjust a CO2 emission
rate. Commenters also recommended that the EPA consider nuclear
generating units and RE generating units in a consistent manner for
CO2 emission rate adjustments in state plans. We agree with
comments that nuclear generation and RE should be treated consistently
when it comes to CO2 emission rate adjustments.
    The EPA has determined that generation from new nuclear units and
capacity uprates at existing nuclear units will be eligible for use in
adjusting a CO2 emission rate, just like new and uprated
capacity RE. However, consistent with the reasons discussed for not
including the preservation of existing nuclear capacity in the BSER--
namely, that such preservation does not actually reduce existing levels
of CO2 emissions from affected EGUs--preserving generation
from existing nuclear capacity is not eligible for use in adjusting a
CO2 emission rate.
    In contrast, any incremental zero-emitting generation from new
nuclear capacity would be expected to replace generation from affected
EGUs and, thereby, reduce CO2 emissions; and the continued
commitment of the owner/operators to completion of the new units and
improving the efficiency of existing units through uprates can play a
key role in state plans. Therefore, consistent with treatment of other
low- and zero-emitting generation, new nuclear power generating
capacity installed after 2012 and incremental generation resulting from
nuclear uprates after 2012 are measures eligible for adjusting a
CO2 emission rate. However, existing nuclear units (i.e.,
those that originally commenced operation in 2012 or earlier years)
that receive operating license extensions are not eligible for use in
adjusting a CO2 emission rate, except where such units
receive a capacity uprate as a result of the relicensing process. Only
the incremental capacity from the uprate is eligible for use to adjust
a CO2 emission rate.
    Applicable generation (in MWh) from incremental nuclear power is
determined in the same manner as that described for incremental RE
above.
    (9) Combined heat and power (CHP) units.
    Electric generation from non-affected CHP units \965\ may be used
to adjust the CO2 emission rate of an affected EGU, as CHP
units are low-emitting electric generating resources that can replace
generation from affected EGUs. Electrical generation from non-affected
CHP units that meet the eligibility criteria under section VIII.K.1.a
can be used to adjust the reported CO2 emission rate of an
affected EGU.
---------------------------------------------------------------------------

    \965\ The accounting considerations described in this section
are for a ``topping cycle'' CHP unit. A topping cycle CHP unit
refers to a configuration where fuel is first used to generate
electricity and then heat is recovered from the electric generation
process to provide additional useful thermal and/or mechanical
energy. A CHP unit can also be configured as a ``bottoming cycle''
unit. In a bottoming cycle CHP unit, fuel is first used to provide
thermal energy for an industrial process and the waste heat from
that process is then used to generate electricity. Some waste heat
power (WHP) units are also bottoming cycle units and the accounting
treatment for bottoming cycle CHP units is provided with the WHP
description below.
---------------------------------------------------------------------------

    Where a state plan provides for the use of electrical generation
from eligible non-affected CHP units to adjust the reported
CO2 emission rate of an affected EGU, the state plan must
provide a required calculation method for determining the MWh that may
be used to adjust the CO2 emission rate. This proposed
accounting method must adequately address the considerations discussed
below. The EPA will review whether a state's proposed accounting method
for electric generation from eligible non-affected CHP units is
approvable per the requirements of the final emission guidelines, as
part of its overall plan review of the rate-based emission standards
and implementing and enforcing measures in the state plan. The EPA
notes that the proposed model rule for a rate-based emission trading
program includes a proposed accounting method for non-affected CHP
units. The accounting method provided in a final model rule could be a
presumptively approvable accounting approach.
    The proposed accounting method in a state plan must address the
following considerations. The accounting approach proposed in a state
plan must take into account the fact that a non-affected CHP unit is a
fossil fuel-fired emission source, as well as the fact that the
incremental CO2 emissions related to electrical generation
from a non-affected CHP unit are typically very low. In accordance with
these considerations, a non-affected CHP unit's electrical MWh output
that can be used to adjust the reported CO2 emission rate of
an affected EGU should be prorated based on the CO2 emission
rate of the electrical output associated with the CHP unit (a CHP
unit's ``incremental CO2 emission rate'') compared to a
reference CO2 emission rate. This ``incremental
CO2 emission rate'' related to the electric generation from
the CHP unit would be relative to the applicable CO2
emission rate for affected EGUs in the state and would be limited to a
value between 0 and 1.
    This low CO2 emission rate for electrical generation
from a non-affected CHP unit is a product of both the fact that CHP
units are typically very thermally efficient and the fact that a
portion of the CO2 emissions from a non-affected CHP unit
would have occurred anyway from an industrial boiler used to meet the
thermal load in the absence of the CHP unit. In contrast, the CHP unit
also provides the benefit of electricity generation while resulting in
very low incremental CO2 emissions beyond what would have
been emitted by an industrial boiler. As a result, the accounting
method proposed in a state plan should not presume that CO2
emission reductions occur outside the electric power sector, but
instead only would account for the CO2 emissions related to
the electrical production from a CHP unit that is used to substitute
for electrical generation from affected EGUs.
    Non-affected CHP units can use qualified biomass fuels. As
described in section VIII.I.2.c, states must submit state plan
requirements regarding qualified biomass feedstocks and treatment of
biogenic CO2 emissions in state plans, along with supporting
analysis and quality control measures, and the EPA would review the
appropriateness and basis for such determinations in the course of its
review of the approvability of a state plan. Considerations for
qualified biomass included in state plans are discussed in section
VIII.I.2.c, while accounting requirements for RE using biomass are
provided in section VIII.K.1.a.(3)(b).
    Most comments received on CHP recommended that the EPA explicitly
describe how CHP can be accounted for in a state plan. Commenters
described the CO2 emission reductions achieved through CHP's
thermal efficiency and the precedent set in other federal and state
rules that have included CHP as a compliance option. Some commenters
pointed out that without such a description, states would not be able
to readily take advantage of the CO2 emission reductions
that result from the use of CHP.
    (10) WHP.
    WHP units that meet the eligibility criteria under section VIII.K.1
may be used to adjust the CO2 emission rate of an affected
EGU. There are several types of WHP units. There are units, also
referred to as bottoming cycle CHP units, where the fuel is first used
to provide thermal energy for an industrial process and the waste heat
from that process is then used to generate

electricity.\966\ There are also WHP facilities where the waste heat
from the initial combustion process is used to generate additional
power. Under both configurations, unless the WHP unit supplements waste
heat with fossil fuel use, there is no additional fossil fuel used to
generate this additional power. As a result, there are no incremental
CO2 emissions associated with that additional power
generation. As a result, the incremental electric generation output
from the WHP facilities could be considered zero-emitting, for the
purposes of meeting the emission guidelines, and the MWh of electrical
output could be used to adjust the CO2 emission rate of an
affected EGU.\967\ The MWh of electrical output from a WHP unit that
can be recognized may not exceed the MWh of industrial or other thermal
load that is being met by the WHP unit, prior to the generation of
electricity.\968\ Most commenters that addressed WHP noted the benefits
of WHP at the same time that they discussed the benefits of CHP. The
commenters reflected that WHP is another potential compliance option
and requested it be discussed explicitly as a compliance option that
can be used to meet the emission guidelines. The comments discussed WHP
benefits but did not elaborate on a preferred accounting method for MWh
of electrical generation from WHP that could be used to adjust the
CO2 emission rate of an affected EGU.
---------------------------------------------------------------------------

    \966\ In such a configuration, the waste heat stream could also
be generated from a mechanical process, such as at natural gas
pipeline compressors.
    \967\ This only applies where no additional fossil fuel is used
to supplement the use of waste heat in a WHP facility. Where fossil
fuel is used to supplement waste heat in a WHP application, MWh of
electrical generation that can be used to adjust the CO2
emission rate of an affected EGU must be prorated based on the
proportion of fossil fuel heat input to total heat input that is
used by the WHP unit to generate electricity.
    \968\ This limitation prevents oversizing the thermal output of
a WHP unit to exceed the useful industrial or other thermal load it
is meeting, prior to generation of electricity.
---------------------------------------------------------------------------

    b. Measures that may not be used to adjust a CO2
emission rate.
    This section addresses measures that may not be used to adjust a
CO2 emission rate. New, modified, and reconstructed EGUs
covered under the CAA section 111(b) final Standards of Performance for
Greenhouse Gas Emissions from New Stationary Sources: Electric Utility
Generating Units rule are not approvable sources of electric generation
for adjusting the CO2 emission rate of an affected EGU under
a rate-based state plan. As discussed earlier in section VII.D of this
preamble, a key concern under this rule is leakage to new units that
are not covered by the emission guidelines. Emissions leakage, or
increased CO2 emissions due to increased utilization of
unaffected sources, is contradictory to objectives of this rule and
should, therefore, be minimized. Allowing affected EGUs to adjust their
emission rates as a result of lower-emitting new NGCC units not covered
under this section 111(d) rule would not mitigate leakage concerns, and
could even exacerbate the situation. Consequently, new EGUs covered
under the CAA section 111(b) rule are not allowable measures in state
plans because the EPA believes it would result in increased emission
leakage.
    The EPA received comments both supporting and opposing the use of
new NGCC units in state plans. In addition to leakage concerns,
commenters expressed concern with the potential incentives created by
including new NGCC capacity in the BSER or as a compliance mechanism in
state plans. Some commenters suggested that including new NGCC capacity
in the BSER or for compliance would distort market incentives to build
new NGCC units, particularly if new units were allowed to generate ERCs
that could be sold to affected EGUs. These commenters suggested that
the additional incentive for new NGCC units could make existing NGCC
units less competitive. Other commenters suggested that including new
NGCC capacity in state plans would promote generation from new
CO2-emitting units at the expense of new zero-emitting
units, increasing overall emissions within a state. This effect would
be exacerbated if state plans allowed new NGCC units to be treated as
``zero-emitting'' for purposes of compliance--as suggested by other
commenters. In addition, commenters expressed concern that the EPA's
inclusion of new NGCC capacity in setting the BSER or in compliance
could negatively impact ratepayers over the long-term by sending the
wrong signal to industry and resulting in stranded assets if, in the
future, carbon emissions become more expensive or the EPA proposes to
incorporate sources built under the forthcoming section 111(b) standard
into the section 111(d) program. Commenters also expressed concern that
including generation from new NGCC units could create unreasonable
uncertainty, given limitations on the ability to accurately project new
NGCC builds, could create undue pressure on natural gas prices, and
could create unfair disparities in the compliance opportunities
afforded different states. In light of the emissions leakage concerns,
and in consideration of these comments, the EPA is not allowing
shifting generation to new NGCC units to be used as a measure for
adjusting CO2 emission rates for affected EGUs in rate-based
state plans.
    In addition, other new and existing non-affected fossil fuel-fired
EGUs that are not subject to CAA section 111(b) or 111(d), such as
simple cycle combustion turbines, may not be used to adjust the
CO2 emission rate of an affected EGU. While generation from
such units could substitute for generation from affected EGUs, the EPA
has determined that additional incentives for such generation, in the
form of an explicit adjustment to the CO2 rate of an
affected EGU, are not necessary or warranted. Providing for such an
adjustment could create perverse incentives for the construction of new
simple cycle combustion turbines that are not subject to the
applicability criteria of the final Standards of Performance for
Greenhouse Gas Emissions from New Stationary Sources: Electric Utility
Generating Units rule. These units could provide only limited
adjustment credit, as operation beyond a certain capacity factor
threshold would trigger applicability under CAA section 111(b).
Further, providing for the ability to generate adjustment credits would
provide incentives for construction of less efficient fossil generating
capacity than would likely otherwise be constructed (e.g., addition of
a simple cycle combustion turbine rather than a NGCC unit). In
addition, providing for the ability to generate adjustment credits
could create perverse incentives for the continued operation of less
efficient existing fossil generating capacity. Such outcomes run
counter to the objectives of this final rule.
    c. Measures that reduce CO2 emissions outside the
electric power sector.
    Measures that reduce CO2 emissions outside the electric
power sector may not be counted toward meeting a CO2
emission performance level for affected EGUs or a state CO2
goal, under either a rate-based or mass-based approach, because all of
the emission reduction measures included in the EPA's determination of
the BSER reduce CO2 emissions from affected EGUs. Examples
of measures that may not be counted toward meeting a CO2
emission performance level for affected EGUs or a state CO2
goal include GHG offset projects representing emission reductions that
occur in the forestry and agriculture sectors,\969\ direct air capture,

and crediting of CO2 emission reductions that occur in the
transportation sector as a result of vehicle electrification.
---------------------------------------------------------------------------

    \969\ We note, however, that the final emission guidelines allow
state measures like emission budget trading programs to include out-
of-sector GHG offsets. For example, both the California and RGGI
programs allow for the use of allowances awarded to GHG offset
projects to be used to meet a specified portion of an affected
emission source's compliance obligation. The RGGI program contains a
cost containment allowance reserve that makes available additional
allowances up to a certain amount, at specified allowance price
triggers.
---------------------------------------------------------------------------

2. Requirements for Rate-Based Emission Trading Approaches
    As made clear in the proposal,\970\ all emission standards in a
state plan must be quantifiable, verifiable, enforceable, non-
duplicative and permanent.\971\ This requirement is applicable to
emission standards that include a rate-based emission trading program.
The State Plan Considerations TSD for the proposal also explained that
in order to ensure a plan is enforceable, a state plan must: identify
in its plan the entity or entities responsible for meeting compliance
and other enforceable obligations under the plan; include mechanisms
for demonstrating compliance with plan requirements or demonstrating
that other binding obligations are met; and provide a mechanism(s) for
legal action if affected EGUs are not in compliance with plan
requirements or if other entities fail to meet enforceable plan
obligations. A state plan using a rate-based emission trading approach
must therefore include rate-based emission standards for affected EGUs
along with related implementation and compliance requirements and
mechanisms.\972\ These related requirements include those applicable to
rate-based emission standards more broadly: CO2 emission
monitoring, reporting, and recordkeeping requirements for affected
EGUs, including requirements for monitoring and reporting of useful
energy output. By satisfactorily addressing these requirements, state
plans including a rate-based emission trading program will be able to
meet the statutory requirements of CAA section 111(d) regarding the
need for state plans to provide for the implementation and enforcement
of emission standards, as well as meet the requirement that each
emission standard be quantifiable, verifiable, non-duplicative,
permanent, and enforceable with respect to each affected EGU.
---------------------------------------------------------------------------

    \970\ 79 FR 34830, 34913.
    \971\ These requirements are described in detail in section
VIII.D.2.
    \972\ As described below, these requirements would likely be
provided in a state plan in the form of state regulations, but could
potentially be provided in another form.
---------------------------------------------------------------------------

    The EPA also specifically proposed that for state plans that rely
on measures that avoid EGU CO2 emissions, such as RE and
demand-side EE measures, the state will also need to include
quantification, monitoring, and verification provisions in its plan for
these measures. The EPA is finalizing requirements specific to rate-
based emission trading programs as requirements the EPA has determined
are necessary to assure the integrity of a rate-based approach that
includes an emission trading program, and therefore assures a state
plan using such an approach appropriately provides for the
implementation and enforcement of rate-based emission standards in
accordance with CAA section 111(d).\973\ These specific requirements
for a rate-based emission trading program include provisions for
issuance of ERCs by the state and/or its designated agent; provisions
for tracking ERCs, from issuance through submission for compliance; and
the administrative process for submission of ERCs by the owner or
operator of an affected EGU to the state, in order to adjust its
reported CO2 emission rate when demonstrating compliance
with a rate-based emission standard.\974\ These requirements must be
submitted for inclusion in the federally enforceable plan, per the
statutory requirement that states provide for the implementation and
enforcement of emission standards. A rate-based trading program would
provide for the implementation and enforcement of rate-based emission
standards for a state plan that allows its affected EGUs to adjust a
rate by the use of an ERC.
---------------------------------------------------------------------------

    \973\ By ``integrity of a rate-based emission trading program'',
the EPA is referring to elements in the design and administration of
a program necessary to assure that emission standards implemented
using a rate-based emission trading approach are quantifiable,
verifiable, enforceable, non-duplicative, and permanent.
    \974\ See section VIII.K.1 for a discussion of the accounting
method used to adjust a CO2 emission rate.
---------------------------------------------------------------------------

    The EPA will review a state plan submittal including a rate-based
emission trading program to assure that the plan contains the
requirements necessary to assure the integrity of a rate-based
approach, and therefore provide for the implementation and enforcement
of rate-based emission standards. These requirements are discussed in
more detail in this section.
    The EPA also notes it is proposing model rules for both mass-based
and rate-based emission trading programs. State plans that include the
finalized model rule for a rate-based emission trading program could be
presumptively approvable as meeting the requirements of CAA section
111(d) and these emission guidelines. The EPA would evaluate the
approvability of such plans through independent notice and comment
rulemaking.
    A state may issue ERCs to an affected EGU that performs at a
CO2 emission rate below a specified CO2 emission
rate, as well as to providers of qualifying measures that provide
substitute generation for affected EGUs or avoid the need for
generation from affected EGUs. This latter category includes providers
of qualifying RE and demand-side EE measures, as well as other types of
measures, as discussed in section VIII.K.1.a.\975\
---------------------------------------------------------------------------

    \975\ As used in this section, the term ``EE program'' refers to
an EE deployment program. An EE program involves deployment of
multiple EE measures or EE projects, such as utility- or state-
administered EE incentive programs that accelerate the deployment of
EE technologies and practices. As used in this section, the term
``EE/RE project'' refers to a discrete EE project (e.g., an EE
upgrade to a commercial building or set of buildings) or a RE
generator (e.g., a single wind turbine or group of turbines).
---------------------------------------------------------------------------

    ERCs may be used by an affected EGU to adjust its reported
CO2 emission rate when demonstrating compliance with a rate-
based emission standard. This adjustment is made by adding MWh to the
denominator of an affected EGU's reported CO2 emission rate,
in the amount of submitted ERCs, resulting in a lower adjusted rate. To
demonstrate compliance with a rate-based emission standard, an affected
EGU would report its CO2 lb/MWh emission rate to the state
regulatory body, and would also surrender to the state any ERCs it
wishes to use to adjust its reported emission rate. The state regulator
would then cancel the submitted ERCs. The affected EGU would add the
MWh the ERCs represent to the denominator of its reported
CO2 lb/MWh emission rate to demonstrate compliance with its
emission standard. The state regulator could facilitate its evaluation
of the affected EGU's compliance (as well as evaluation by the affected
EGU, the EPA, and others) by providing functionality in its tracking
system to run such compliance calculations. If the affected EGU's
adjusted CO2 emission rate is equal to or lower than its
applicable emission rate standard, the affected EGU would be in
compliance.
    a. Issuance of ERCs to affected EGUs.
    ERCs may be issued to affected EGUs that emit below a specified
CO2 emission rate, as discussed below. For issuance of ERCs
to affected EGUs, the state plan must specify the accounting method and
administrative process for ERC issuance. This includes the

calculation method for determining the number of ERCs to be issued to
an affected EGU, based on reported CO2 emissions and MWh
energy output, in comparison to a reference CO2 emission
rate. The reference rate is a specified CO2 lb/MWh emission
rate that an affected EGU's reported CO2 emission rate is
compared to, when determining the amount of ERCs that may be issued to
an affected EGU.
    Following determination of the number of ERCs an affected EGU is
eligible to receive, based on an affected EGU's reported CO2
emission rate compared to a specified reference rate, the state
regulatory body would issue those ERCs into a tracking system account
held by the owner or operator of the affected EGU. Tracking system
requirements are addressed below at section VIII.K.2.c.
    The accounting method that may be applied in a state plan differs
depending on whether a state plan includes a single rate-based emission
standard that applies to all affected EGUs (e.g., if a plan is designed
to meet a state rate-based CO2 goal) or separate rate-based
emission standards that apply to subcategories of affected EGUs, namely
fossil fuel-fired electric utility steam generating units and
stationary combustion turbines. In both cases, ERCs are issued in MWh,
based on the difference between an affected EGU's reported
CO2 emission rate (in CO2 lb/MWh) and a specified
CO2 lb/MWh emission rate that the reported rate is compared
to (referred to as a ``reference rate''). The reference rate may be an
affected EGU's assigned CO2 emission limit rate or another
CO2 emission rate, as described below. Where an affected
EGU's reported CO2 emission rate is lower than the specified
reference CO2 emission rate, ERCs may be issued.
    Where a state plan includes emission standards in the form of a
single rate-based emission standard that applies to all affected EGUs,
the reference rate is the CO2 emission rate limit for
affected EGUs. In this instance, ERCs may be issued based on an
affected EGU's reported CO2 emission rate as a proportion of
the emission limit rate. For example, if the emission rate limit is
2,000 lb CO2/MWh and the affected EGU emits at a rate of
1,000 lb CO2/MWh, 0.5 MWh would be awarded for every MWh
generated by the affected EGU. ERCs would be issued to affected EGUs in
whole MWh increments. The calculation method is as follows:
    ERCs \976\ = reported MWh by affected EGU \977\ x ((CO2
emission rate limit for affected EGUs \978\--affected EGU reported
CO2 emission rate \979\)/CO2 emission rate limit
for affected EGUs)
---------------------------------------------------------------------------

    \976\ For all calculations in this section, where the result is
a negative value, no ERCs would be issued.
    \977\ This term represents the reported MWh by the affected EGU
on an annual basis.
    \978\ This term represents the ``reference rate.''
    \979\ This term represents the annual reported CO2
emission rate of the affected EGU.
---------------------------------------------------------------------------

    For the example above, the calculation is as follows:

    ERCs = MWh reported x (2,000-1,000)/2,000 = MWh reported x 0.5

    If the affected EGU in this example generated 1,000,000 MWh,
500,000 ERCs would be issued.
    Where a state plan includes separate emission standards for
subcategories of affected EGUs, specifically affected fossil fuel-fired
electric utility steam generating units and stationary combustion
turbines, the reference rate differs for affected fossil fuel-fired
electric utility steam generating units and stationary combustion
turbines. Additionally, if the state plan applies emission standards
for its affected EGUs that are equal to the subcategorized
CO2 emission performance rates there is a unique opportunity
for the adjustment of an affected EGU's emission rate using ERCs that
are generated as a result of building block 2 incremental NGCC unit
operation. The EPA is requiring state plans to account for incremental
NGCC generation in ERC generation if a state plan applies the
subcategorized CO2 emission performance rates to its
affected EGUs as emission standards. Additionally, the EPA is requiring
that a NGCC unit is not able to use ERCs generated by it or any other
NGCC unit's building block 2 incremental generation.
    For affected steam generating units, the reference CO2
emission rate is the assigned CO2 emission rate limit for
steam generating units, and the following accounting method for
generating ERCs applies:
    ERCs \980\ = reported MWh x ((steam generating unit CO2
emission rate limit \981\--steam generating unit reported
CO2 emission rate)/steam generating unit CO2
emission rate limit).
---------------------------------------------------------------------------

    \980\ For all calculations in this section, where the result is
a negative value, no ERCs would be issued.
    \981\ The ``reference rate.''
---------------------------------------------------------------------------

    For an affected NGCC stationary combustion turbine in a
subcategorized rate-based emission trading program, the following
equation provides a required accounting method for generating ERCs
based on operation with respect to the NGCC unit's emission standard:
    ERCs = NGCC unit's reported MWh--((NGCC unit's CO2
emission standard \982\--NGCC unit's reported CO2 emission
rate)/NGCC unit's CO2 emission standard)
---------------------------------------------------------------------------

    \982\ The ``reference rate.''
---------------------------------------------------------------------------

    According to this equation, ERC issuance is assessed based on the
difference between the CO2 emission rate standard for the
NGCC unit \983\ and the reported CO2 emission rate of the
affected NGCC unit. In other words, affected NGCC stationary combustion
turbines earn ERCs for generation when they perform at an emission rate
better than the reference rate for stationary combustion turbines,
similarly to how affected steam units can earn ERCs.
---------------------------------------------------------------------------

    \983\ This is the CO2 emission performance rate for
affected stationary combustion turbines in the emission guidelines.
---------------------------------------------------------------------------

    In a subcategorized rate-based emission trading program, a state
must use the incremental operation of an affected NGCC unit quantified
for building block 2 to allow a NGCC unit to generate ERCs based on its
expected incremental generation.
    A state plan that provides for the use of ERCs issued based on
incremental affected NGCC generation must provide a required
calculation method that allows for issuance of ERCs based on the
ability of incremental generation from affected stationary combustion
turbines to substitute for generation from affected steam generating
units (as represented in building block 2), while also respecting the
fact that affected stationary combustion turbines must also meet an
assigned CO2 emission rate limit for the entirety of its MWh
energy output. This accounting method must reflect the application of
the BSER, as described in section V, and the accounting method must not
create incentives to rearrange dispatch between existing NGCC units to
generate additional ERCs without changing the overall level of NGCC
generation.
    The EPA will review whether a state's accounting method is
approvable per the requirements of the statute and this final rule as
part of its overall plan review of the rate-based emission standards
and implementing and enforcing measures in the state plan. The EPA
notes that the proposed model rule for a rate-based emission trading
program includes a proposed accounting method and takes comments on
alternatives. The accounting method provided in a final model rule
could be a presumptively approvable approach for issuance of ERCs based
on the ability of incremental generation from affected stationary
combustion turbines to

substitute for generation from affected steam generating units. A
state's accounting requirements for generation of ERCs based on
incremental affected NGCC generation must maintain consistency with the
EPA's application of the BSER when calculating CO2 emission
performance rates for affected stationary combustion turbine and steam
generating units. In particular, a state's accounting method must
maintain consistency of accounting in a state rate-based CO2
emission standard with the EPA's application of building block 2 in
calculating CO2 emission performance rates for affected
fossil fuel-fired electric utility steam generating units and
stationary combustion turbines, which is based on use of incremental
generation from affected stationary combustion turbine to replace
generation from affected steam generating units.
    b. Issuance of ERCs for RE, demand-side EE, and other measures.
    ERCs may be issued for qualifying measures.\984\ For issuance of
ERCs for qualifying measures, state plan requirements for ERC issuance
must include a two-step process. In the first step of the process, a
potential ERC provider submits an eligibility application for a
qualifying program or project \985\ to the administering state
regulator (or its agent \986\). The state regulator reviews the
application to determine whether, in this example, an EE/RE program or
project meets eligibility requirements for the issuance of ERCs.\987\
An eligibility application must include a description of the program or
project, a projection of the MWh generation or energy savings
anticipated over the life of the program or project, and an EM&V plan
that meets state plan requirements. The EM&V plan must describe how MWh
of RE generation or energy savings resulting from the program or
project will be quantified and verified.\988\ A state, in its emission
standard regulations, must include requirements for EM&V plans that are
consistent with the requirements in the emission guidelines for EE/RE
measures and other eligible measures, as discussed in sections VIII.K.1
and VIII.K.3.
---------------------------------------------------------------------------

    \984\ Qualifying measures that can be used to adjust the
CO2 emission rate of an affected EGU are discussed at
section VIII.K.1, and include incremental NGCC, RE, demand-side EE,
and other measures, such as DSM, CHP and incremental nuclear
generation.
    \985\ For example, for an EE/RE program or project, as described
in this section for illustrative purposes. The requirements
described in this section for EE/RE programs and projects also apply
for all other eligible qualifying measures discussed in section
VIII.K.1.
    \986\ As used here, an agent is a party acting on behalf of the
state, based on authority vested in it by the state, pursuant to the
legal authority of the state. A state could designate an agent to
provide certain limited administrative services, or could choose to
vest an agent with greater authority. Where an agent issues an ERC
on behalf of the state, such issuance would have the same legal
effect as issuance of an ERC by the state.
    \987\ The entity implementing the EE/RE program or project
(referred to in the preamble as a ``provider'') would submit the
application. This is the identified entity to which ERCs would
ultimately be issued, to a tracking system account held by the
entity. Such entities could include a wide variety of parties that
implement EE/RE programs and projects, including owners or operators
of affected EGUs, electric distribution companies, independent power
producers, energy service companies, administrators of state EE
programs, and administrators of industrial EE programs, among
others.
    \988\ The verification process includes confirmation that
quantified MWh are non-duplicative and permanent (i.e., are not
being used in any other state plan to demonstrate compliance with an
emission standard or achievement of an emission performance rate or
state CO2 emission goal).
---------------------------------------------------------------------------

    The EPA has determined that state requirements for an eligibility
application must include review of the application by an independent
verifier, approved by the state as eligible per the requirements of the
final emission guidelines to provide such verification, prior to
submittal. This requirement builds on the approach used for assessing
GHG offset projects, both in international emission trading programs
and the GHG emission budget trading programs implemented by California
and the RGGI participating states.\989\ An assessment by an independent
verifier would be included as a component of an eligibility
application.
---------------------------------------------------------------------------

    \989\ Information about the verification process for GHG offsets
under the RGGI program, including verifier accreditation
requirements and access to relevant documents, is available at
http://www.rggi.org/market/offsets/verification. Similar information
about the verification process for GHG offsets under the California
program is available at http://www.arb.ca.gov/cc/capandtrade/offsets/verification/verification.htm.
---------------------------------------------------------------------------

    The EPA has determined that independent verification requirements
are necessary to ensure the integrity of state rate-based emission
trading programs included in a state plan, given the wide range of
eligible measures that may generate ERCs and the broad geographic
locations in which those measures may occur. Inclusion of an
independent verification component provides technical support for state
regulatory bodies to ensure that eligibility applications and M&V
reports are thoroughly reviewed prior to issuance of ERCs. Inclusion of
an independent verification component is also consistent with similar
approaches required by state PUCs for the review of demand-side EE
program results and GHG offset provisions included in state GHG
emission budget trading programs.
    State plans with rate-based emission trading programs must include
requirements regarding the qualification status of an independent
verifier. An independent verifier is a person (including any company,
any corporate parent or subsidiary, any contractors or subcontractors,
and the actual person) who has the appropriate technical and other
qualifications to provide verification reports. The independent
verifier must not have, or have had, any direct or indirect financial
or other interest in the subject of its verification report or ERCs
that could impact its impartiality in performing verification services.
State plans must require that a person be approved by the state as an
independent verifier, as defined by this final rule, as eligible to
perform the verifications required under the approved state plan. State
plans must also include a mechanism to temporarily or permanently
revoke the qualification status of an independent verifier, such that
it can no longer provide verification services related to an
eligibility application or M&V report for at least the duration of the
period it does not meet the qualification requirements for independent
verifiers in an approved state plan. The EPA's proposed model rate-
based emission trading rule contains provisions addressing
accreditation and conflicts of interest for independent verifiers.
State plans that adopt the finalized model rule could be presumptively
approvable with respect to these requirements regarding independent
verifiers.
    The state's eligibility requirements and application procedures
must ensure that only eligible actions may generate ERCs and that
documentation is submitted only once for each program or project, and
to only one state program.\990\ These provisions will ensure that
actions that are eligible for the issuance of ERCs are ``non-
duplicative.'' \991\ The tracking system used to administer a state's
rate-based emission trading system must provide transparent,
electronic, public access to information about program and project
eligibility applications, including EM&V plans, and regulatory approval
status.
---------------------------------------------------------------------------

    \990\ This includes ensuring that multiple parties do not submit
an eligibility application for the same EE program or project, or
for the same RE generator.
    \991\ Emission standards must be ``non-duplicative'' as
described in section VIII.D.2.
---------------------------------------------------------------------------

    In the second step of the process, following implementation of the
RE/EE program or project (as described in this example) that was
approved in step one, the RE/EE provider periodically submits a M&V
report to the state regulatory body documenting the results of the

program or project in MWh of electric generation or energy
savings.\992\ These results are quantified according to the EM&V plan
that was approved as part of step one. These results are verified by an
accredited independent verifier, and its verification assessment must
be included as part of the M&V report submitted to the state regulatory
body. The administering state regulator (or its agent) then reviews the
M&V report, and determines the number of ERCs (if any) that should be
issued, based on the report. Finally, the state regulatory body (or its
agent) issues ERCs to the provider of the approved program or project.
These ERCs are issued to the tracking system account held by the
program or project provider.
---------------------------------------------------------------------------

    \992\ State rate-based emission trading program regulations must
specify the frequency for submission of M&V reports for approved
qualified measures that have been deemed eligible to generate ERCs.
These reporting periods should be annual, but a state could consider
shorter or longer periods, depending on the type of ERC resource.
---------------------------------------------------------------------------

    State plan requirements must ensure that only one ERC is issued for
each verified MWh. This is addressed through registration in the
tracking system of programs and projects that have been qualified for
the issuance of ERCs, to ensure that documentation is submitted only
once for each RE/EE action, and to only one state program.\993\ The
tracking system must provide transparent electronic public access to
submitted M&V reports and regulatory approvals related to such
reports.\994\ Such reports are the basis for issuance of ERCs.
---------------------------------------------------------------------------

    \993\ EE/RE programs and projects, and other eligible measures,
with an approved eligibility application would be designated in a
tracking system as qualified programs or projects. Qualified
programs and projects may be issued ERCs, based on approved M&V
reports.
    \994\ This must include electronic Internet access to such
information in the tracking system.
---------------------------------------------------------------------------

    c. Tracking system requirements.
    State requirements must include provisions to ensure that ERCs
issued to any eligible entity are properly tracked from issuance to
submission by affected EGUs for compliance (where ERCs are
``surrendered'' by the owner or operator of an affected EGU and
``retired'' or ``cancelled''), to ensure they are only used once to
meet a regulatory obligation. This is addressed through specified
requirements for tracking system account holders, ERC issuance, ERC
transfers among accounts, compliance true-up for affected EGUs,\995\
and an accompanying tracking system that meets requirements specified
in the emission trading program regulations. Each issued ERC must have
a unique identifier (e.g., serial number) and the tracking system must
provide for traceability of issued ERCs back to the program or project
for which they were issued.
---------------------------------------------------------------------------

    \995\ ``Compliance true-up'' refers to ERC submission by an
owner or operator of an affected EGU to adjust a reported
CO2 emission rate, and determination of whether the
adjusted rate is equal to or lower than the applicable rate-based
emission standard.
---------------------------------------------------------------------------

    The EPA received a number of comments from states and stakeholders
about the value of the EPA's support in developing and/or administering
tracking systems to support state administration of rate-based emission
trading systems. This could include regional systems and/or a national
system. The EPA is exploring options for providing such support and is
conducting an initial scoping assessment of tracking system support
needs and functionality.
    d. Effect of improperly issued ERCs.
    Because the goal of this rulemaking is the actual reduction of
CO2 emissions, it is fundamental that ERCs represent the MWh
of energy generation or savings they purport to represent. To this end,
only valid ERCs that actually meet the standards articulated in this
rule may be used to satisfy any aspect of compliance by an affected EGU
with emission standards. Despite safeguards included in the structure
of ERC issuance and tracking systems, such as the review of eligibility
applications and M&V reports, and state issuance of ERCs, ERCs may be
issued that do not, in fact, represent eligible zero-emission MWh as
required in the emission guidelines. A variety of situations may result
in such improper ERC issuance, ranging from simple paperwork errors to
outright fraud.
    An approvable state plan that allows affected EGUs to comply with
their emission standards in part through reliance on ERCs must include
provisions making clear that an affected EGU may only demonstrate
compliance with an ERC that represents the one MWh of actual energy
generation or savings that it purports to represent and otherwise meets
the emission guidelines.
    e. Banking of ERCs.
    ERCs issued in 2022 or a subsequent year may be carried forward (or
``banked'') and used for demonstrating compliance in a future
year.\996\ For example, an ERC issued for a MWh of RE generation that
occurs in 2022 may be applied to adjust a CO2 emission rate
in 2023 or future years without limitation. ERCs may be banked from the
interim plan performance period to the final plan performance period.
Banking provides a number of advantages while ensuring that the same
output-weighted average CO2 emission rates of the interim
and final state CO2 goals are achieved over the course of a
state plan. Banking provisions have been used extensively in rate-based
environmental programs and mass-based emission budget trading
programs.\997\ This is because banking reduces the cost of attaining
the requirements of the regulation. The EPA has determined that the
same rationale and outcomes apply under a CO2 emission rate
approach, in that allowing banking will reduce compliance costs.
Banking encourages additional emission reductions in the near-term if
economic to meet a long-term emission rate constraint, which is
beneficial due to social preferences for environmental improvements
sooner rather than later.\998\ State plans must specify whether the
state is allowing or restricting the banking of ERCs between compliance
periods for affected EGUs. State plans must also prohibit borrowing of
any ERCs from future compliance periods by affected EGUs or eligible
resources.
---------------------------------------------------------------------------

    \996\ States also have the option to participate in the CEIP,
under which they can issue ERCs for MWh generation or savings that
occur in 2020-2021 for measures implemented following submission of
a final state plan, and receive matching ERCs from a federal pool.
See section VIII.B.2 for a detailed discussion. The ERCs issued
under this program can also be banked during and between the interim
and final compliance period.
    \997\ Banking under mass-based emission budget trading programs,
and the rationale for banking provisions, is addressed below in
section VIII.J.2.c.
    \998\ The absence of banking creates an incentive to defer both
relatively low-cost and higher-cost CO2 emission
reduction actions until a later period when emission rate limits
become more stringent, rather than incentives to undertake the low-
cost activities sooner in order to further delay the high cost
actions. Under a rate-based emission trading program, banking will
encourage ERC providers to generate larger numbers of ERCs in early
years of a plan performance period, in anticipation of rising ERC
prices over time, when demand for ERCs is expected to increase as
rate-based CO2 emission standards become more stringent.
---------------------------------------------------------------------------

    f. Considerations for ERC issuance.
    The EPA notes that state-administered and state-overseen EE
programs, such as those administered by state-regulated electric
distribution utilities, could play a key role in supplying energy
savings to a rate-based emission trading system in the form of ERCs.
These programs have been the primary means for delivering EE programs
and energy savings at scale, and also allow for a state to conduct a
portfolio planning process to guide EE program design and focus in a
manner that best provides multiple benefits to electricity ratepayers
in a state. Such portfolio planning processes typically treat EE as an
energy resource comparable to electricity generation.

    The EPA also notes that non-ERC certificates may be issued by
states and other bodies for MWh of energy generation and energy savings
that are used to meet other state regulatory requirements, such as
state RPS and EERS, or by individuals to make environmental or other
claims in voluntary markets.
    The EPA defines an ERC in the emission guidelines as a tradable
compliance instrument that represents a zero-emission MWh (for the
purposes of meeting the emission guidelines) from a qualifying measure
that may be used to adjust the reported CO2 emission rate of
an affected EGU subject to a rate-based emission standard in an
approved state plan under CAA section 111(d). The sole purpose of an
ERC is for use by an affected EGU in demonstrating compliance with a
rate-based emission standard in such an approved state plan.
    An ERC is issued separately from any other instruments that may be
issued for a MWh of energy generation or energy savings from a
qualifying measure. Such other instruments may be issued for use in
meeting other regulatory requirements (e.g., such as state RPS and EERS
requirements) or for use in voluntary markets. An ERC may be issued
based on the same data and verification requirements used by existing
REC and EEC tracking systems for issuance of RECs and EECs.
    The EPA notes that the definitions of other instruments, such as
RECs, differ (as established under state statute, regulations, and PUC
orders) and that requirements under state regulatory programs that use
such instruments, such as state RPS, also differ. As a result, states
may want to assess, when developing their state plan, how such existing
instruments may interact with ERCs. For example, a state may want to
assess how issuance of ERCs pursuant to a state plan may interact with
compliance with a state RPS by entities affected under relevant state
RPS regulations or PUC orders. The interaction of other instruments and
ERCs may also impact existing or future arrangements in the private
marketplace. Actions taken by states, separate from the design of their
state plan, could address a number of these potential interactions. For
example, state RPS regulations that specify a REC for a MWh of RE
generation, and the attributes related to that MWh, may or may not
explicitly or implicitly recognize that the holder of the REC is also
entitled to the issuance of an ERC for a MWh of electricity generation
from the eligible RE resource. This could impact existing and future RE
power purchase agreements or REC purchase agreements. Such interactions
among existing instruments and ERCs could also impact how marketing
claims are made in the voluntary RE market. How a state might choose to
address these potential interactions will depend on a number of
factors, including the utility regulatory structure in the state,
existing statutory and regulatory requirements for state RPS, and
existing RE power purchase agreements and REC contracts.
    g. Program review.
    The EPA is requiring that states periodically review the
administration of their rate-based emission trading programs. The
results of these program reviews must be submitted by states to the EPA
as part of their required reports on the implementation of their state
plans, as described in sections VIII.D.a.(5) and VIII.D.2.b.(4), and
must be made publicly available. Such a review submitted as part of a
required state report provides for the implementation of rate-based
emission standards per the requirements of CAA section 111(d)(2). For a
rate-based emission trading program, the review must cover the
reporting period addressed in the state's periodic reports to the EPA
on plan implementation.
    The program review must address all aspects of the administration
of a state's rate-based emission trading program, including the state's
evaluations and regulatory decisions regarding eligibility applications
for ERC resources and M&V reports (and associated EM&V activities), and
the state's issuance of ERCs. The program review must assess whether
the program is being administered properly in accordance with the