level, the EPA expects that such offsetting emission reductions at the
state's affected EGUs from the application of other building blocks
will be available, so that the EPA will be able to finalize the state
goals as proposed. For example, a state's inability to meet the level
of emission reductions anticipated through use of one building block
may free up resources that the state could then devote to more
stringent implementation of another building block. This approach would
mean that overall, the same nationwide level of emission reductions as
proposed would be achieved. The EPA invites comment on this aspect of
the proposal.
    At this time, the EPA is not proposing CO2 emission
performance goals for either Indian country or U.S. territories. The
EPA does plan to establish CO2 emission goals for both
Indian country and territories in the future. The EPA plans to conduct
additional outreach before setting these goals.
    Issues related to the establishment of CO2 goals and CAA
section 111(d) plans for Indian country are discussed in Section V.D of
this preamble. As noted in that discussion, the EPA is aware of four
potentially affected power plants located in Indian country: The South
Point Energy Center, on Fort Mojave tribal lands within Arizona; the
Navajo Generating Station, on Navajo tribal lands within Arizona; the
Four Corners Power Plant, on Navajo tribal lands within New Mexico; and
the Bonanza Power Plant, on Ute tribal lands within Utah.\252\ Data for
these four power plants have been excluded from the data used to
compute the proposed state goals for Arizona, New Mexico, and Utah
discussed below.
---------------------------------------------------------------------------

    \252\ The South Point facility is an NGCC power plant, and the
Navajo, Four Corners, and Bonanza facilities are coal-fired power
plants.
---------------------------------------------------------------------------

    With respect to territories, the EPA is currently aware of
potentially affected EGUs in Puerto Rico, the U.S. Virgin Islands, and
Guam. The EPA requests comment on how the BSER would apply to these
territories, as well as to American Samoa or the Northern Mariana
Islands if potentially affected EGUs are subsequently identified in
those territories. In particular, the EPA solicits comment on
appropriate alternatives for territories that do not have access to
natural gas.\253\ Because the data sources we have used for purposes of
establishing renewable energy and demand-side energy efficiency targets
for states do not cover all the territories, we also solicit comment on
ways to determine appropriate renewable energy and demand-side energy
efficiency targets using other data sources.
---------------------------------------------------------------------------

    \253\ As noted in Section VI.C.5.d above, we are requesting
comment on whether heat rate improvements for non-coal fossil fuel-
fired EGUs should be part of the basis supporting the BSER, with
particular reference to the situation of geographically isolated
jurisdictions such as the U.S. territories.
---------------------------------------------------------------------------

    The remainder of this section addresses five sets of topics. First,
we discuss several issues related to the form of the goals. Second, we
describe the proposed state goals and the computation procedure. Third,
we discuss several types of state flexibility with respect to the
goals. Fourth, we describe the alternate set of goals offered for
comment and certain other approaches we considered. Finally, we discuss
the proposal's compatibility with the need to ensure a reliable,
affordable supply of electricity.
    Some of the topics addressed in this section are addressed in
greater detail in supplemental documents available in the docket for
this rulemaking, including the Goal Computation TSD and the Greenhouse
Gas Abatement Measures TSD. Specific topics addressed in the various
TSDs are noted throughout the discussion below.

B. Form of Goals

    The proposed goals are presented in the form of adjusted output-
weighted-average CO2 emission rates that the affected fossil
fuel-fired EGUs located in each state could achieve, on average,
through application of the measures

comprising the BSER (or alternative control methods). Several aspects
of this proposed form of goal are worth noting at the outset: The use
of an emission rate-based form (e.g., the quantity of CO2
per MWh of electricity generated), with the opportunity for the state
to adopt a mass-based form (e.g., a cap on the tonnage of
CO2 emissions); the use of output-weighted-average emission
rates for all affected EGUs in a state rather than nationally uniform
emission rates for all affected EGUs of particular types; the use of
adjustments to accommodate measures that reduce CO2
emissions by reducing the quantity of fossil fuel-fired generation
rather than by reducing the CO2 emission rate per MWh
generated by affected sources; the use of emission rates expressed in
terms of net rather than gross energy output; and the adjustability of
the goals based on the severability of the underlying building blocks.
    First, the EPA proposes to use an emission rate-based form for the
state-specific goals included in the guidelines, and to give each state
the opportunity to translate its rate-based goal to an equivalent mass-
based form for state plan purposes. Each of the two forms of goals
presents advantages, and states have expressed support for having the
flexibility to use either form. Defining emission performance levels in
a rate-based form provides flexibility to accommodate changes in the
overall quantities of electricity generated in response to increases in
electricity demand. Defining emission performance levels in a mass-
based form provides relative certainty as to the absolute emission
levels that would be achieved as well as relative simplicity in
accommodating and accounting for the emission impacts of a wide variety
of emission reduction strategies. In light of these respective
advantages, we propose to set an emission rate-based form of goal, and
to allow any state to translate the rate-based goal to an equivalent
mass-based emission performance level for state plan purposes. This
approach allows each state to maximize the advantages it considers
optimal and is consistent with the state flexibility principle that is
central to the EPA's development of this program.
    The second aspect noted above concerns the proposed choice of
state-specific output-weighted-average emission rates for all affected
EGUs in each state rather than nationally uniform emission rates for
particular types of affected EGUs. Here, the EPA's main consideration
has been to ensure that the proposed goals reflect opportunities to
manage CO2 emissions by shifting generation among different
types of affected EGUs. Specifically, because CO2 emission
rates differ widely across the fleet of affected EGUs, and because
transmission interconnections typically provide system operators with
choices as to which EGU should be called upon to produce the next MWh
of generation needed to meet demand, opportunities exist to manage
utilization of high carbon-intensity EGUs based on the availability of
less carbon-intensive generating capacity. For states and generators,
this means that CO2 emission reductions can be achieved by
shifting generation from EGUs with higher CO2 emission
rates, such as coal-fired EGUs, to EGUs with lower CO2
emission rates, such as NGCC units. Our analysis indicates that
shifting generation among EGUs offers opportunities to achieve large
amounts of CO2 emission reductions at reasonable costs.
These opportunities can be reflected in a goal established in the form
of an output-weighted-average emission rate for multiple affected EGU
types. Our approach is also consistent with the fact that the
proportions of different EGU types and hence the magnitudes of the
generation-shifting opportunities vary across states, and that CAA
section 111(d) calls for standards of performance to be established in
state plans rather than on a nationwide basis.
    The third aspect noted above regarding the proposed form of the
goals concerns the adjustments made to the output-weighted-average
emission rates in order to accommodate reduced utilization of affected
EGUs associated with measures such as increases in low- and zero-carbon
generating capacity and demand-side energy efficiency. We recognize
that these measures support reduced overall CO2 mass
emissions from affected EGUs through reductions in the quantity of
generation from affected EGUs, and not necessarily through reductions
in the weighted-average CO2 emission rates of affected EGUs.
Accordingly, we have constructed the emission rate goals in a manner
that is intended to account for these generation quantity-reducing
measures by making adjustments to the values used in the emission rate
computations. The specific adjustments are summarized below in the
context of the goal computation methodology and are described in
greater detail in the Goal Computation TSD. As described below in
Section VIII on state plans, we are proposing that a state choosing a
rate-based form of goal would be able to make analogous adjustments
when assessing monitored emission performance so that measures that
support avoided generation at affected EGUs could be used to help the
state meet the rate-based emission performance level reflected in its
plan. We note that adjustments of this nature are not necessary when a
plan's emission performance level is based on the mass of
CO2 emissions \254\ rather than on CO2 emission
rates, because the emission-reducing effects of reduced generation at
affected EGUs are evident in the EGUs' reported CO2 mass
emissions.
---------------------------------------------------------------------------

    \254\ We also recognize that even under a mass-based approach,
adjustments may be appropriate in some circumstances to address
interstate effects, such as when measures undertaken pursuant to one
state's plan are expected to be associated with decreases in fossil
fuel-fired generation and CO2 emissions in another state.
These issues are discussed below in Section VIII on state plans.
---------------------------------------------------------------------------

    The fourth aspect noted above concerns the proposed expression of
the goals in terms of net energy output \255\--that is, energy output
encompassing net MWh of generation measured at the point of delivery to
the transmission grid rather than gross MWh of generation measured at
the EGU's generator.\256\ The difference between net and gross
generation is the electricity used at a plant to operate auxiliary
equipment such as fans, pumps, motors, and pollution control devices.
Because improvements in the efficiency of these devices represent
opportunities to reduce carbon intensity at existing affected EGUs that
would not be captured in measurements of emissions per gross MWh, we
are proposing goals expressed in terms of net generation. Nearly all
EGUs already have in place the equipment necessary to determine and
report hourly net generation, and we believe that the proposed
reporting requirement would therefore not be burdensome. However, we
also recognize that at present EGUs report gross rather than net load
\257\ to us under 40 CFR Part 75, and that the proposed GHG standards
of performance for new EGUs are expressed in terms of gross generation
(although we sought comment on the use of net generation instead). We
therefore specifically seek comment on whether the goals and reporting
requirements for existing EGUs should be expressed in terms of

gross generation instead of net generation for consistency with
existing reporting requirements and with the proposed requirements
under the GHG standards of performance for new EGUs.
---------------------------------------------------------------------------

    \255\ As discussed below in Section VIII on state plans, we are
similarly proposing that states choosing a rate-based form of
emission performance level for their plans should establish a
requirement for affected EGUs to report hourly net energy output.
    \256\ For some EGUs, total net or gross energy output also
includes useful thermal output, in addition to either net or gross
electric energy output.
    \257\ Some EGUs report gross steam output instead of gross
electrical load.
---------------------------------------------------------------------------

    The final aspect noted above has to do with the severability of the
four building blocks, discussed in Section VI above, upon which the
goals are based. Because the building blocks can be implemented
independently of one another and the goals are the sum of the emission
reductions from all of the building blocks, if any of the building
blocks is found to be an invalid basis for the ``best system of
emission reduction . . . adequately demonstrated,'' the goals would be
adjusted to reflect the emissions reductions from the remaining
building blocks. As noted above, the state goals that would result from
any combination of the building blocks can be computed from data
included in the Goal Computation TSD and its appendices using the
methodology described below and in that TSD.
    We invite comment on all aspects of the proposed form of the goals.

C. Proposed Goals and Computation Procedure

    The EPA has developed proposed goals for state plans reflecting
application of the BSER, based on all four building blocks described
earlier, to pertinent data for each state. The goals are intended to
represent CO2 emission rates achievable by 2030 after a
2020-2029 phase-in period on an output-weighted-average basis
collectively by all of a state's affected EGUs, with certain
computation adjustments described below to reflect the potential to
achieve mass emission reductions by avoiding fossil fuel-fired
generation. For each state, in addition to the final goal, the EPA has
developed an interim goal that would apply during the 2020-2029 period
on a cumulative or average basis as the state progresses toward the
final goal. The proposed goals are set forth in Table 8 below, followed
by a description of the computation methodology. (The issue of how
states could demonstrate emission performance consistent with the
interim and final goals is addressed in Section VIII on state plans.)

                   Table 8--Proposed State \258\ Goals
  [Adjusted output-weighted-average pounds of CO2 per net MWh from all
                    affected fossil fuel-fired EGUs]
------------------------------------------------------------------------
                                                       Interim    Final
                        State                           goal      goal
------------------------------------------------------------------------
Alabama.............................................     1,147     1,059
Alaska..............................................     1,097     1,003
Arizona *...........................................       735       702
Arkansas............................................       968       910
California..........................................       556       537
Colorado............................................     1,159     1,108
Connecticut.........................................       597       540
Delaware............................................       913       841
Florida.............................................       794       740
Georgia.............................................       891       834
Hawaii..............................................     1,378     1,306
Idaho...............................................       244       228
Illinois............................................     1,366     1,271
Indiana.............................................     1,607     1,531
Iowa................................................     1,341     1,301
Kansas..............................................     1,578     1,499
Kentucky............................................     1,844     1,763
Louisiana...........................................       948       883
Maine...............................................       393       378
Maryland............................................     1,347     1,187
Massachusetts.......................................       655       576
Michigan............................................     1,227     1,161
Minnesota...........................................       911       873
Mississippi.........................................       732       692
Missouri............................................     1,621     1,544
Montana.............................................     1,882     1,771
Nebraska............................................     1,596     1,479
Nevada..............................................       697       647
New Hampshire.......................................       546       486
New Jersey..........................................       647       531
New Mexico *........................................     1,107     1,048
New York............................................       635       549
North Carolina......................................     1,077       992
North Dakota........................................     1,817     1,783
Ohio................................................     1,452     1,338
Oklahoma............................................       931       895
Oregon..............................................       407       372
Pennsylvania........................................     1,179     1,052
Rhode Island........................................       822       782
South Carolina......................................       840       772
South Dakota........................................       800       741
Tennessee...........................................     1,254     1,163
Texas...............................................       853       791
Utah *..............................................     1,378     1,322
Virginia............................................       884       810
Washington..........................................       264       215
West Virginia.......................................     1,748     1,620
Wisconsin...........................................     1,281     1,203
Wyoming.............................................     1,808     1,714
------------------------------------------------------------------------
* Excludes EGUs located in Indian country within the state.

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

    \258\ The EPA has not developed goals for Vermont and the
District of Columbia because current information indicates those
jurisdictions have no affected EGUs. Also, as noted above, the EPA
is not proposing goals for Indian country or U.S. territories at
this time.
---------------------------------------------------------------------------

    The proposed goals are expressed as adjusted output-weighted-
average emission rates for all affected EGUs in a state. As discussed
earlier in this section, a goal expressed as an unadjusted output-
weighted-average emission rate would fail to account for mass emission
reductions from reductions in the total quantity of fossil fuel-fired
generation associated with state plan measures that increase low- or
zero-carbon generating capacity or demand-side energy efficiency.
Accordingly, under the proposed goals, the emission rate computation
includes an adjustment designed to reflect those mass emission
reductions. The adjustment is made by estimating the annual net
generation associated with an achievable amount of qualifying new low-
carbon and zero-carbon generating capacity, as well as the annual
avoided generation associated with an achievable portfolio of demand-
side energy efficiency measures, and adding those MWh amounts to the
energy output from affected units that would have been used in an
unadjusted output-weighted-average emission rate computation.\259\
Mathematically, this adjustment has the effect of spreading the
measured CO2 emissions from the state's affected EGUs over a
larger quantity of energy output, thus resulting in an adjusted
emission rate lower than the unadjusted emission rate. (As discussed
below in Section VIII on state plans, we are proposing that a state
could make analogous adjustments to compliance measurement approaches
under its state plan, thereby enabling the state to adopt an emission
rate-based form of emission performance level while still being able to
rely on low- or zero-carbon capacity deployment programs and demand-
side energy efficiency as components of its plan.)
---------------------------------------------------------------------------

    \259\ In the case of new capacity that is not zero-carbon, an
adjustment would also be required to the emissions value used in
computing the weighted-average emission rate. This procedure is
discussed further in the Goal Computation TSD.
---------------------------------------------------------------------------

    The methodology used to compute each state's proposed goal is
summarized on a step-by-step basis below. The methodology is described
in more detail in the Goal Computation TSD, which includes a numerical
example illustrating the full procedure. The development of the data
inputs used in the computation procedure is discussed in Section VI
above and in the Greenhouse Gas Abatement Measures TSD.
    Step 1 (compilation of baseline data). On a state-by-state basis,
we obtained total annual quantities of CO2 emissions, net
generation (MWh), and capacity (MW) from reported 2012 data for all
affected EGUs.\260\ For each state,

we aggregated the 2012 data for all coal-fired steam EGUs as one group,
all oil- and gas-fired steam EGUs as a second group, and all NGCC units
as a third group. We aggregated the 2012 data for all remaining
affected EGUs (i.e., integrated gasification combined-cycle (IGCC)
units and any simple-cycle combustion turbines satisfying relevant
thresholds for qualification as affected EGUs) as a fourth, ``other''
group.\261\ To these totals for affected EGUs operating in 2012, we
added estimates for other EGUs not yet in operation in 2012 that are
affected EGUs for purposes of this emission guideline.\262\ Capacity
and emission rate data inputs for the post-2012 affected EGUs were
obtained from the NEEDS database maintained by the EPA for use with the
Integrated Planning Model (IPM). Generation data inputs for the post-
2012 affected EGUs were estimated based on the average 2012 utilization
rates for recently constructed EGUs of the same types; for example, we
estimated in this step that the post-2012 NGCC units would operate at a
55 percent utilization rate on average.
---------------------------------------------------------------------------

    \260\ EGUs whose capacity, fossil fuel combustion, or
electricity sales were insufficient to qualify them as affected EGUs
were not included in the goal computations. Most simple cycle
combustion turbines were excluded on this basis. See the
applicability criteria described in Section V.B. above.
    \261\ The emission and generation totals for the ``other'' group
also reflect the portion of affected cogeneration units' total
CO2 emissions and total energy output corresponding to
those units' useful thermal output.
    \262\ Assuming it meets other applicability criteria, an EGU
would be affected if it had commenced construction by January 8,
2014 (the data of Federal Register publication of the proposed GHG
NSPS for new EGUs).
---------------------------------------------------------------------------

    Step 2 (application of building block 1). The total CO2
emissions amount for the coal-fired steam EGU group in each state from
Step 1 was reduced by six percent, reflecting our assessment of the
average opportunity to reduce CO2 emission rates across the
existing fleet of coal-fired steam EGUs through heat rate improvements
that is technically achievable at a reasonable cost.
    Step 3 (application of building block 2). If the generation data
for the NGCC group in a state developed in Step 1 showed average annual
utilization below 70 percent of those units' maximum possible output,
and the generation data developed in Step 1 also included generation
from the coal-fired steam or oil/gas-fired steam EGU groups in that
state, the generation and emissions figures for the NGCC group were
increased, and the generation and emissions figures for the coal-fired
and oil/gas-fired steam EGU groups from Step 2 were proportionately
\263\ decreased, to reflect an estimated potential increase in
utilization of the NGCC group to a maximum of 70 percent. In this step,
the total (across all four groups) of the state's fossil fuel-fired
generation was maintained at the amount computed in Step 1, but to the
extent that in the analysis a portion of the total fossil generation
was shifted from the coal-fired and oil/gas-fired steam EGU groups,
which have higher CO2 emission rates, to the NGCC group,
which has a lower CO2 emission rate, the total (across all
four groups) of the state's CO2 emissions was reduced.\264\
---------------------------------------------------------------------------

    \263\ For example, if the data developed in Step 1 showed equal
quantities of MWh generated by the coal-fired steam EGU group and
the oil/gas-fired steam EGU group, then any overall reduction in the
MWh generated by these two groups due to a commensurate increase in
the MWh generated by the less carbon-intensive NGCC group would be
split equally between the coal-fired steam group and the oil/gas-
fired steam group.
    \264\ We did not estimate any change in utilization, generation,
or emissions for the state's ``other'' group of IGCC units and
simple-cycle combustion turbines in Step 3.
---------------------------------------------------------------------------

    Step 4 (application of building block 3). We estimated the total
quantities of generation from renewable generating capacity and from
under-construction or preserved nuclear capacity for each state using
the approaches described in Section VI.C.3 above. Separate estimates of
renewable generation were computed for each year of the plan period for
each state based on the state's 2012 renewable generation and a
regional growth factor. Nuclear generation was estimated as the amount
of under-construction and preserved nuclear capacity for each state
operated at a utilization rate of 90 percent, consistent with recent
industry-wide average utilization rates for nuclear units.
    Step 5 (application of building block 4). We estimated the total
MWh amount by which generation from each state's affected EGUs would be
cumulatively reduced in each year of the plan period associated with
implementation in that state of demand-side energy efficiency programs
resulting in annual incremental reductions in the state's electricity
usage (relative to usage absent those programs) of 1.5 percent each
year, as described in Section VI.C.4 above. Separate estimates were
developed for each year to reflect the fact that energy efficiency
programs that are implemented on an ongoing basis would be expected to
produce larger cumulative impacts on total annual electricity usage
over time. For states that are net importers of electricity, the
estimated reduction in the generation by the state's affected EGUs was
scaled down to reflect an expectation that a portion of the generation
avoided by the demand-side energy efficiency would occur at EGUs in
other states.
    Step 6 (computation of annual rates). We computed adjusted output-
weighted-average CO2 emission rates for each state by
dividing (1) the total CO2 emissions for the coal-fired
steam EGU, oil- and gas-fired steam EGU, NGCC unit, and ``other''
affected fossil EGU groups from Step 3 above by (2) the total of (a)
the total net energy output (expressed in MWh) for the four groups from
Step 1 above plus (b) the estimated annual net generation from
renewable and nuclear generating capacity from Step 4 above plus (c)
the estimated cumulative annual MWh amount saved through demand-side
energy efficiency from Step 5 above.\265\ We performed these
computations separately for each year from 2020 to 2029, using the
respective cumulative annual MWh savings figures developed in Steps 4
and 5.
---------------------------------------------------------------------------

    \265\ Expressed as a formula, the equation for the annual rate
computation is:
    [(Coal gen. x Coal emission rate) + (OG gen. x OG emission rate)
+ (NGCC gen. x NGCC emission rate) + ``Other'' emissions]/[Coal gen.
+ OG gen. + NGCC gen. + ``Other'' gen. + Nuclear gen. + RE gen. + EE
gen.]
    This formula and its elements are further explained in the Goal
Computation TSD, as well as in the text above.
---------------------------------------------------------------------------

    Step 7 (computation of interim and final goals). The final 2030
goal for each state is the annual rate computed for 2029 for the state
from Step 6 above. We computed the 2020-2029 interim goal for each
state as the simple average of the annual rates computed for each of
the years from 2020 to 2029 for the state from Step 6 above.
    It bears emphasis that the procedure described above is proposed to
be used only to determine state goals, and the particular data inputs
used in the procedure are not intended to represent specific
requirements that would apply to any individual EGU or to the
collection of EGUs in any state. The specific requirements applicable
to individual EGUs, to the EGUs in a given state collectively, or to
other affected entities in the state, would be based on the standards
of performance established through that state's plan. The details of
how states could attain emission performance levels consistent with the
goals through different state plan approaches that recognize emission
reductions achieved through all the building blocks are discussed
further in Section VIII on state plans.
    We invite comment on all aspects of the goal computation procedure.
(Note that we also invite comment on certain specific alternate data
inputs to the procedure in Section VI.C above.) We also specifically
invite comment on the state-specific historical data to which

the building blocks are applied in order to compute the state goals, as
well as the state-specific data used to develop the state-specific data
inputs for building blocks 3 and 4. These data are contained in the
Goal Computation TSD and the Greenhouse Gas Abatement Measures TSD.
    With respect to building block 2, we specifically request comment
on the following alternate procedure: In Step 3, to the extent that
generation from a state's NGCC group was increased consistent with the
NGCC utilization rate target, in order to maximize the resulting
emission reductions, we would decrease generation from the state's
coal-fired steam group first, and then decrease generation from the
state's oil/gas-fired steam group (instead of decreasing generation
from the coal-fired steam and oil/gas-fired steam groups
proportionately).
    With respect to building block 4, we specifically invite comment on
the alternative in Step 5 of scaling up the estimated reduction in the
generation by affected EGUs in net electricity-exporting states to
reflect an expectation that a portion of the generation avoided in
conjunction with the demand-side energy efficiency efforts of other,
net electricity-importing states would occur at those EGUs, analogous
to the proposed adjustment for net electricity-importing states
described in Step 5. We also request comment on the alternative of
making no adjustment in Step 5 for either net electricity-importing or
net electricity-exporting states. These alternatives are discussed in
the Goal Computation TSD.
    We also request comment on whether CO2 emission
reductions associated with other measures not currently included in any
of the four proposed building blocks should be included in the state
goals.

D. State Flexibilities

    As promulgated in the final rule following consideration of
comment, the state-specific goals will be binding emission guidelines.
States' ability to achieve emission performance levels consistent with
the binding goals is enhanced by several distinct types of flexibility:
(i) Choices as to the measures employed, including the timing of their
implementation; (ii) the ability to translate from a rate-based form of
goal to a mass-based form of goal; and (iii) the opportunity to pursue
multi-state plan approaches.
    First, a core flexibility provided under CAA section 111(d) is that
while states are required to establish standards of performance that
reflect the degree of emission limitation from application of the
control measures that the EPA identifies as the BSER, they need not
mandate the particular control measures the EPA identifies as the basis
for its BSER determination. In developing the building block data
inputs applied to each state's historical data to develop the goals,
the EPA targeted reasonably achievable rather than maximum performance
levels. The overall goals therefore represent reasonably achievable
emission performance levels that provide states with flexibility to
pursue some building blocks more extensively and others less
extensively than the degree reflected in the EPA's data inputs while
meeting the overall goals. States can also choose to include in their
plans other measures that reduce CO2 emissions at affected
EGUs but that are not included in the building blocks.
    Further, by allowing states to demonstrate emission performance by
affected EGUs on an average basis over a multi-year interim plan period
of as long as ten years, the EPA's proposed approach increases states'
flexibility to choose among alternative potential plan measures. For
example, by taking advantage of the multi-year flexibility, a state
could choose to rely more heavily in its plan on measures whose
effectiveness tends to grow over time, such as demand-side energy
efficiency programs. This flexibility could also help states address
concerns about stranded assets, for example, by enabling states to
defer imposition of requirements on EGUs that may be scheduled to
retire after 2020 but before 2029.
    The second type of flexibility noted above is that while the EPA is
proposing to establish goals in an emission rate-based form, we are
also proposing to provide states with the flexibility to translate the
rate-based goals to mass-based goals in order to accommodate states'
potential interest in having emission performance requirements measured
in absolute tons. For example, the northeastern and Mid-Atlantic states
that currently participate in the mass-based Regional Greenhouse Gas
Initiative (RGGI) may choose to develop state plans (or a multi-state
plan, as noted below) establishing mass-based emission performance
levels designed to be met at least in part through standards of
performance based on RGGI's existing market-based CO2
emission budget trading program. Because the use of mass-based plans
can simplify the process of accounting for the CO2 reduction
impacts of a variety of measures, the EPA believes the flexibility to
adopt mass-based emission performance levels can facilitate plan
development and could be attractive to states that do not already
participate in mass-based emission reduction programs as well.
    Third, the EPA's approach allows states to submit multi-state
plans. The EPA expects this flexibility to reduce the cost of achieving
the state goals and therefore expects it to be attractive to states.
For example, the RGGI-participating states could choose to submit a
multi-state mass-based plan that demonstrates emission performance by
affected EGUs on a multi-state basis. Additional states may also choose
to join a multi-state plan. The mechanics of translating rate-based
goals into mass-based goals and considerations related to multi-state
plans are discussed below in Section VIII on state plans.
    Some stakeholders have suggested that states themselves should be
allowed to quantify the level of emission reduction resulting from the
application of BSER or, if the EPA establishes goals, the states should
be allowed to adjust the goals or to treat the goals established by the
EPA as advisory rather than binding. Consistent with the existing
implementing regulations for CAA section 111(d) at 40 CFR part 60, this
quantification is the EPA's role.\266\ As discussed in the Legal
Memorandum, CAA section 111(d) directs the EPA to ``prescribe
regulations which shall establish a procedure similar to that provided
by [CAA section 110] under which each State shall submit'' a section
111(d) state plan. As noted in Section II.D of this preamble, the EPA
promulgated implementing regulations in 1975, and has revised parts of
them since. The regulations set out a multi-step process for the
development and approval of state plans, and assign responsibility for
the various steps in the process to the EPA or the states. The
regulations provide that the EPA is to promulgate an ``emission
guideline that reflects the application of the best system of emission
reduction (considering the cost of such reduction) that has been
adequately demonstrated for'' affected sources.\267\ In this manner,
the regulations make clear that the EPA determines the BSER. In this
rulemaking, as discussed above, the EPA identifies the BSER. In
addition, in this rulemaking, the EPA applies the BSER to each state,
and then, for each state, calculates the average emission rate that, in
the words of the regulations just quoted, ``reflects the application of

the [BSER].'' That average emission rate is the state goal.
---------------------------------------------------------------------------

    \266\ 40 CFR 60.22(b)(5). We do not propose to re-open that
portion of the implementing regulations in this rulemaking.
    \267\ Id.
---------------------------------------------------------------------------

    By the same token, because the state goals are an integral part of
the emission guidelines that the framework regulations authorize the
EPA to establish, the goals are binding, and the states, in their CAA
section 111(d) plans, must meet those goals and may not make them less
stringent. This matter, too, is resolved by the implementing
regulations.\268\ To reiterate, the proposed state goals represent the
level of performance that is achievable through application of the BSER
to the pertinent data for each individual state. States have the
opportunity to comment on the proposed BSER, the proposed methodology
for computing state goals based on application of the BSER, and the
state-specific data that is proposed for use in the computations. We
expect that the states will have an adequate opportunity to comment on
the state goals during the comment period. Once the final goals have
been promulgated, and adjusted as may be appropriate based on comments
to address any factual errors in the analysis, the states will be able
to meet them because they will represent the application of BSER to the
states' affected sources. In addition, states have several types of
flexibilities in developing their state plans: They have flexibility
regarding the selection of the measures upon which they choose to rely
and a 10-year time period over which to reach full implementation of
these measures, and they can use rate-based or mass-based approaches.
In addition, as we have noted, multi-state coordination offers states
an opportunity to achieve additional emission reductions and reduce
implementation costs. These flexibilities, discussed further in Section
VIII of this preamble, ensure that states will be able to achieve their
final CO2 emission performance goals and that no special
provision for state adjustment of goals outside the normal notice-and-
comment rulemaking process is warranted.\269\
---------------------------------------------------------------------------

    \268\ Id. We do not propose to re-open that portion of the
implementing regulations in this rulemaking.
    \269\ In the event that a state becomes concerned about its
ability to meet the goal that the EPA promulgates for it, the state
may submit to the EPA a petition for reconsideration, if that
petition is based on relevant information not available during the
comment period. See CAA section 307(d)(7)(B).
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E. Alternate Goals Offered for Comment and Other Approaches Considered

    In addition to the proposed state-specific emission rate-based
goals described above, the EPA has developed for public comment an
alternate set of goals reflecting less stringent application of the
building blocks and a shorter implementation period. The alternate
final goals represent emission performance that would be achievable by
2025, after a 2020-2024 phase-in period, with interim goals that would
apply during the 2020-2024 period on a cumulative or average basis as
states progress toward the final goals.
    Because the time period for implementation relates directly to the
emission reductions that are achievable and therefore what measures,
and at what level of stringency, constitute the BSER, the alternate
goals reflect several differences in data inputs from the proposed
goals. Specifically, a value of four percent (instead of six percent)
was used for the potential improvement in carbon intensity of coal-
fired EGUs in Step 2; a value of 65 percent (instead of 70 percent) was
used for the potential annual utilization rate of NGCC units in Step 3;
and a value of one percent (instead of 1.5 percent) was used for the
annual incremental electricity savings achievable through a portfolio
of demand-side energy efficiency programs in Step 5. (No change was
made to the data inputs regarding less carbon-intensive generating
capacity in Step 4.) As noted above, the alternate goals also reflect a
shortening of the proposed phase-in period from ten years (2020-2029)
to five years (2020-2024) to reflect an expectation that less stringent
goals could be achieved in less time. Steps 5, 6, and 7 of the goal
computation procedure therefore were performed for the span of years
from 2020 to 2024 rather than for the span from 2020 to 2029. The
alternate goals are set forth in Table 9 below.

                  Table 9--Alternate State \270\ Goals
  [Adjusted output-weighted-average pounds of CO2 per net MWh from all
                    affected fossil fuel-fired EGUs]
------------------------------------------------------------------------
                                                       Interim    Final
                        State                           goal      goal
------------------------------------------------------------------------
Alabama.............................................     1,270     1,237
Alaska..............................................     1,170     1,131
Arizona *...........................................       779       763
Arkansas............................................     1,083     1,058
California..........................................       582       571
Colorado............................................     1,265     1,227
Connecticut.........................................       651       627
Delaware............................................     1,007       983
Florida.............................................       907       884
Georgia.............................................       997       964
Hawaii..............................................     1,446     1,417
Idaho...............................................       261       254
Illinois............................................     1,501     1,457
Indiana.............................................     1,715     1,683
Iowa................................................     1,436     1,417
Kansas..............................................     1,678     1,625
Kentucky............................................     1,951     1,918
Louisiana...........................................     1,052     1,025
Maine...............................................       418       410
Maryland............................................     1,518     1,440
Massachusetts.......................................       715       683
Michigan............................................     1,349     1,319
Minnesota...........................................     1,018       999
Mississippi.........................................       765       743
Missouri............................................     1,726     1,694
Montana.............................................     2,007     1,960
Nebraska............................................     1,721     1,671
Nevada..............................................       734       713
New Hampshire.......................................       598       557
New Jersey..........................................       722       676
New Mexico *........................................     1,214     1,176
New York............................................       736       697
North Carolina......................................     1,199     1,156
North Dakota........................................     1,882     1,870
Ohio................................................     1,588     1,545
Oklahoma............................................     1,019       986
Oregon..............................................       450       420
Pennsylvania........................................     1,316     1,270
Rhode Island........................................       855       840
South Carolina......................................       930       897
South Dakota........................................       888       861
Tennessee...........................................     1,363     1,326
Texas...............................................       957       924
Utah *..............................................     1,478     1,453
Virginia............................................     1,016       962
Washington..........................................       312       284
West Virginia.......................................     1,858     1,817
Wisconsin...........................................     1,417     1,380
Wyoming.............................................     1,907     1,869
------------------------------------------------------------------------
* Excludes EGUs located in Indian country in the state.

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    \270\ See footnote accompanying Table 8 above.
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    The EPA recognizes that its approach to the alternate goals,
comprising less stringent requirements in each of the building blocks
to be achieved over a shorter compliance horizon, follows the logic of
including time as one of the functions of the BSER determination. At
the same time, we also recognize that the components of the alternate
goals may reflect an overly conservative approach. Specifically, the
alternate goals as set forth above may underestimate the extent to
which the key elements of the four building blocks--achieving heat rate
improvements at EGUs, switching generation to NGCC facilities,
fostering the penetration of renewable resources or improving year-to-
year end-use energy efficiency--can be achieved rapidly while
preserving reliability and remaining reasonable in cost. Accordingly,
we request comment on the alternate goals, particularly with respect to
whether any one or all of the building blocks in the alternate goals

can be applied at a greater level of stringency: Can the heat rate
improvement value be set at a level above four percent, even six
percent? Can NGCC capacity be dispatched at a utilization rate above 65
percent? Can annual incremental electricity savings be achieved at a
rate higher than one percent?
    It is worth noting that the EPA projects that the alternate goals
will achieve emission reductions equal to 23 percent below 2005 level
in 2025. The EPA's analysis shows that under the proposed goals
described in Section VII.C above, power sector emissions will be 29
percent below 2005 levels in 2025, suggesting that the kinds of changes
contemplated in the four building blocks, even as early as 2025, will
be yielding reductions far greater than the 23 percent projected for
the alternate goals as set forth above in this subsection.
    The EPA has considered other approaches to setting goals. In
particular, given the interconnected nature of the power sector and the
importance of opportunities for shifting generation among EGUs, we
considered whether goals should be set on a multi-state basis
reflecting the scope of existing regional transmission control areas.
We also considered whether goals should be set on a state-specific
basis, but regional rather than state-specific evaluations should be
used to assess the estimated opportunities to reduce utilization of the
most carbon-intensive EGUs by shifting generation to less carbon-
intensive EGUs. A potential advantage of using regional evaluations is
the ability to recognize additional emission reduction opportunities
that would be available at reasonable costs based on a more complete
representation of the capabilities of existing infrastructure to
accommodate shifts in generation among EGUs in multiple states. We
request comment on whether, and if so how, the EPA should incorporate
greater consideration of multi-state approaches into the goal-setting
process, and on the issue of whether, and if so how, the potential cost
savings associated with multi-state approaches should be considered in
assessing the reasonableness of the costs of state-specific goals.

F. Reliable Affordable Electricity

    Many stakeholders raised concerns that this regulation could affect
the reliability of the electric power system. The EPA agrees that
reliability must be maintained and in designing this proposed
rulemaking has paid careful attention to this issue. The EPA has met on
several occasions with staff and managers from the Department of Energy
and the Federal Energy Regulatory Commission to discuss our approach to
the rule and its potential impact on the power system. EPA staff and
managers have also had numerous discussions with state public utility
commissioners and their staffs to get their suggestions and advice
concerning this rule, including how to address reliability concerns.
    In addition, the EPA met with independent system operators several
times to discuss any potential impact of this rule on grid reliability.
The ISO/RTO Council, a national organization of electric grid
operators, offered analytic support to help states design programs that
do not compromise the regional bulk power system. They also offered to
help states develop regional approaches which may reduce costs and
strengthen the reliability of the electricity grid. Specifically, the
ISO/RTO Council has suggested that ISOs and RTOs could provide analytic
support to help states develop and implement their plans. The ISOs and
RTOs have the capability to model the system-wide effects of individual
state plans. Providing assistance in this way, they felt, would allow
states with borders that fall within an ISO or RTO footprint to assess
the system-wide impacts of potential state plan approaches. In
addition, as the state implements its plan, ISO/RTO analytic support
would allow the state to monitor the effects of its plan on the
regional electricity system. ISO/RTO analytic capability could help
states assure that their plans are consistent with region-wide system
reliability. The ISO/RTO Council suggested that the EPA ask states to
consult with the applicable ISO/RTO in developing their state plans.
The EPA agrees with this suggestion and encourages states with borders
that fall within one or more ISO or RTO footprints to consult with the
relevant ISOs/RTOs.
    The EPA has met with the U.S. Department of Agriculture as well to
discuss how we can address the concerns of small, relatively isolated
power generators in rural America and especially the electric
cooperatives. Many of these entities have special challenges, as they
may have small, older carbon-intensive assets and might have particular
challenges meeting carbon requirements.
    With all of this in mind, the EPA in determining the BSER looked
specifically at the reasonableness of the costs of control options in
part to ensure that the options would not have a negative effect on
system reliability. The BSER, including each of the building blocks,
was determined to be feasible at reasonable costs over the timeframe
proposed here. Further, under the Clean Air Act the states are given
the flexibility to design state plans that include any measure or
combination of measures to achieve the required emission limitations.
States are not required to use each of the measures that the EPA
determines constitute the BSER or use those measures to the same degree
or extent that the EPA determines is feasible at a reasonable cost.
Thus, each state has the flexibility to choose the most cost-effective
measures given that state's energy profile and economy, as long as the
state achieves the reductions necessary to meet its goal. Many market-
based approaches which states may choose reduce the costs of
compliance. They can allow certain units that are seldom used to remain
in operation if they are needed for reliability purposes. Multi-state
approaches also reduce costs and stress on the grid and so can help to
reduce any concern about electricity reliability.
    States may choose measures that would ease pressures on system
reliability. This is true for many demand-side management approaches,
including programs to encourage end-use energy efficiency, distributed
generation, and combined heat and power, which actually reduce demand
for centrally generated power and thus relieve pressure on the grid.
    The EPA is proposing a 10-year period over which to achieve the
full required CO2 reductions, and we would expect this to
further relieve any pressure on grid reliability. This relatively long
planning and implementation period provides states with substantial
flexibility regarding methods and timing of achieving emission
reductions.
    The EPA's supporting analysis for this rule includes an examination
of the effects of the rule on regional resource adequacy.\271\ The
EPA's analysis looked at the types of changes in the generation fleet
that were projected to occur through retirements, additional generation
and energy efficiency. The analysis did not raise concerns over
regional resource adequacy. The EPA further examined how the policy
options impacted the flows and transfers of electricity that occur to
meet reserve margins. None of the interregional changes in the policy
cases suggested that there would be increases in flows that would raise
significant concerns about grid congestion or grid management.
Moreover, the time

horizon for compliance with this rule will permit environmental and
reliability planners to coordinate these changes and address potential
concerns before they arise.
---------------------------------------------------------------------------

    \271\ See the Resource Adequacy and Reliability Analysis TSD,
available in the docket.
---------------------------------------------------------------------------

    The EPA concludes that the proposed rule will not raise significant
concerns over regional resource adequacy or raise the potential for
interregional grid problems. The EPA believes that any remaining local
issues can be managed through standard reliability planning processes.
The flexibility inherent in the rule is responsive to the CAA's
recognition that state plans for emission reduction can, and must, be
consistent with a vibrant and growing economy and reliable, affordable
electricity to support that economy. The EPA welcomes comments and
suggestions on this issue.

VIII. State Plans

A. Overview

    After the EPA establishes the state-specific rate-based
CO2 goals in the emission guidelines, as described in
Section VII above, each state must then develop, adopt, and submit its
state plan under CAA section 111(d). To do so, the state must first
determine the emission performance level it will include in its plan,
which entails deciding whether it will adopt the rate-based
CO2 goal set by the EPA or translate the rate-based goal to
a mass-based goal.
    The state must then establish an emission standard or set of
emission standards, and, perhaps other measures, along with
implementing and enforcing measures, that will achieve a level of
emission performance that is equal to or better than the level
specified in the state plan.
    The state must then adopt the state plan through certain
procedures, which include a state hearing. Within the time period
specified in the emission guidelines (from as early as June 30, 2016 to
as late as June 30, 2018, depending on the state's circumstances), the
state must submit its complete state plan to the EPA. The EPA then must
determine whether to approve or disapprove the plan. If a state does
not submit a plan, or if the EPA does not approve a state's plan, then
the EPA must establish a plan for the state.
    As discussed in Section V.D of this preamble, in the case of a
tribe that has one or more affected EGUs located in its area of Indian
country, if the EPA determines that a CAA section 111(d) plan is
necessary or appropriate, the EPA has the responsibility to establish a
CAA section 111(d) plan for that area of Indian country where affected
sources are located unless the tribe on whose lands an affected source
(or sources) is located seeks and obtains authority from the EPA to
establish a plan itself, pursuant to the Tribal Authority Rule.\272\
The agency is soliciting comment on aspects of such CAA section 111(d)
plans, as described in Section V.D of this preamble.
---------------------------------------------------------------------------

    \272\ See 40 CFR 49.1 to 49.11.
---------------------------------------------------------------------------

    This section is organized into six parts. First, we discuss the
types of plans that we propose states could submit. Second, we address
timing for plan implementation and achievement of state emission
performance goals for affected EGUs. Third, we discuss the proposed
state plan approvability criteria. Fourth, we summarize the proposed
components of an approvable state plan. Fifth, we address the proposed
process and timing for submittal of state plans. Sixth, we identify
several key considerations for states in developing and implementing
plans, including: Affected entities with obligations under a plan;
treatment of existing state programs; incorporation of renewable energy
(RE) and demand-side energy efficiency (EE) programs in certain plans;
quantification, monitoring, and verification of RE and demand-side EE
measures; reporting and recordkeeping for affected entities; treatment
of interstate effects; and projection of emission performance. Finally,
we discuss a number of additional factors that could help states meet
their CO2 emission performance goals, and we note certain
resources that are available to facilitate plan development and
implementation. Additional discussion of some of the topics covered in
this section can be found in the State Plan Considerations TSD and
Projecting EGU CO2 Emission Performance in State Plans TSD,
both of which are in the rulemaking docket.

B. Approach

    In this action, the EPA is proposing emission guidelines in the
form of state-specific CO2 emission performance goals. In
addition, the EPA is proposing guidelines for states to follow in
developing plans to establish and implement CO2 emission
standards for affected EGUs. The proposed plan guidelines include four
general plan approvability criteria, twelve required components for a
state plan to be approvable, the process and timing for state plan
submittal and review, and the process and timing for demonstrating
achievement of the CO2 goals. These are described below.
    The EPA recognizes that each state has different state policy
considerations--including varying emission reduction opportunities and
existing state programs and measures--and that the characteristics of
the electricity system in each state (e.g., utility regulatory
structure, generation mix, electricity demand) also differ. The agency
also anticipates--and supports--states' commitments to a wide range of
policy preferences that could encompass those of states like Kentucky,
West Virginia and Wyoming seeking to continue to feature significant
reliance on coal-based generation; states like Minnesota, Colorado,
California and the nine RGGI states seeking to build on actions and
policies they have already undertaken; and states like Washington and
Oregon seeking to integrate sustainable forestry and renewable energy
strategies. The proposed plan guidelines provide states with options
for establishing emission standards in a manner that accommodates a
diverse range of state approaches. Each state will have significant
flexibility to determine how to best achieve its CO2 goals
in light of its specific circumstances, including addressing concerns
particular to the state, such as employment transition issues, as it
designs and implements its plan over multiple years. As an example, the
RGGI states' implementation of their mass-based emission budget trading
program raises proceeds through allowance auctions and uses those
proceeds to advance programs promoting and expanding end-use energy
efficiency. States could address analogous priorities, such as
employment transition, through a similar mechanism.
    The proposed plan guidelines would also allow states to collaborate
and to develop plans that provide for demonstration of emission
performance on a multi-state basis, in recognition of the fact that
electricity is transmitted across state lines, and that state measures
may impact, and may be explicitly designed to reduce, regional EGU
CO2 emissions. The EPA also recognizes that multi-state
collaboration would likely offer lower-cost approaches to achieving
CO2 emission reductions. With this in mind, we are proposing
to provide states with additional time to submit complete plans if they
do so as part of a multi-state plan, and we solicit comment on other
potential mechanisms for fostering multi-state collaboration.
1. State Plan Approaches
a. Overview
    Although state CAA section 111(d) plans must assure that the
emission performance level is achieved through

reductions at the affected sources, we believe that different types of
state plans could be constructed that make use of the diversity of
measures available to achieve CO2 emission reductions. Based
on the EPA's outreach efforts, it is clear that states are considering
different types of plans.
    Three important issues in the design of state plans include: (1)
Whether the plan should require the affected EGUs to be subject to
emission limits that assure that the emission performance level is
achieved, or instead, whether the plan could rely on measures, such as
renewable energy (RE) or demand-side energy-efficiency (EE), to assure
the achievement of part of the emission performance level; (2) whether
the responsibility for all of the measures other than emission limits
should fall on the affected EGUs, or, instead, could fall on entities
other than affected EGUs; and (3) whether the fact that requiring all
measures relied on to achieve the emission performance level to be
included in the state plan renders those measures federally
enforceable. These issues and the EPA's proposed approach are addressed
in detail in the sections that follow.
    The EPA is proposing that all measures relied on to achieve the
emission performance level be included in the state plan, and that
inclusion in the state plan renders those measures federally
enforceable.
    In light of current state programs, and of stakeholder expressions
of concerns over the above-noted issues, including legal enforcement
considerations, with respect to those programs, the EPA is proposing to
authorize states either to submit plans that hold the affected EGUs
fully and solely responsible for achieving the emission performance
level, or to submit plans that rely in part on measures imposed on
entities other than affected EGUs to achieve at least part of that
level, as well as on measures imposed on affected EGUs to achieve the
balance of that level. The EPA requests comment on this proposed
approach, as opposed to the approach under which state plans simply
would be required to hold the affected EGUs fully and solely
responsible for achieving the emission performance level.
    In addition, the EPA is soliciting comment on several other types
of state plans that may assure the requisite level of emission
performance without rendering certain types of measures federally
enforceable and that limit the obligations of the affected EGUs.
b. Portfolio Approach
    In assessing the types of state plans to authorize, the EPA
reviewed existing state programs that reduce CO2 emissions
from fossil fuel-fired power plants. Existing state programs are
particularly informative for this purpose in light of the fact that CAA
section 111(d) gives states the primary responsibility for designing
their own state plans for submission to the EPA. Many of these existing
state programs, as summarized above, include measures such as renewable
energy (RE) and demand-side energy efficiency (EE) programs, which
impose responsibilities on a range of entities, including state
agencies, for assuring implementation of actions that result in reduced
utilization of, and therefore reduced emissions from, fossil fuel-fired
EGUs, and do not impose legal responsibilities for those emission
reductions on the EGUs themselves.
    In addition, during the EPA's extensive outreach efforts, many
stakeholders expressed concern over the extent of responsibility that
fossil fuel-fired EGUs would be required to bear for the required
emission reductions, in particular, those associated with RE and
demand-side EE measures. These stakeholders recommended that the EPA
authorize states to achieve emission reductions from RE and demand-side
EE measures by imposing requirements on entities other than fossil
fuel-fired EGUs, and without imposing legal responsibility for these
emission reductions on those EGUs.
    Accordingly, the EPA is proposing to authorize a state plan to
adopt what we refer to as a ``portfolio approach,'' in which the plan
would include emission limits for affected EGUs along with other
enforceable measures, such as RE and demand-side EE measures, that
reduce CO2 emissions from affected EGUs. Under this
approach, it would be all of the measures combined that would be
designed to achieve the required emission performance level for
affected EGUs as expressed in the state goal. Under this approach, the
emission limits enforceable against the affected EGUs would not, on
their own, assure, or be required to assure, achievement of the
emission performance level. Rather, the state plan would include
measures enforceable against other entities that support reduced
generation by, and therefore CO2 emission reductions from,
the affected EGUs. As noted, these other measures would be federally
enforceable because they would be included in the state plan. A
portfolio approach could be used for state plans that establish the
emission performance level on either an emission rate basis or a mass
emissions basis.
    In addition, a portfolio approach could either be what we refer to
as ``utility-driven'' or ``state-driven,'' depending on the utility
regulatory structure in a state. Under a utility-driven approach, a
state plan may include, for example, measures implemented consistent
with a utility integrated resource plan, including both measures that
directly apply to affected EGUs (e.g., repowering or retirement of one
or more EGUs) as well as RE and demand-side EE measures that avoid EGU
CO2 emissions.\273\ Under a state-driven approach, the
measures in a state plan would include emission standards for affected
EGUs, as well as requirements that apply to entities other than
affected EGUs, for example, renewable portfolio standards (RPS) or end-
use energy efficiency resource standards (EERS), both of which often
apply to electric distribution utilities.\274\
---------------------------------------------------------------------------

    \273\ In the case of a utility-driven portfolio approach, the
vertically integrated electric utility implementing portfolio
measures is also the owner and operator of affected EGUs.
    \274\ A state-driven portfolio approach is more likely in states
that have instituted electricity sector restructuring, where
electric utilities have typically been required by states to divest
electric generating assets.
---------------------------------------------------------------------------

c. Obligations on Affected EGUs
    The EPA is proposing to authorize state plans to adopt the
portfolio approach and is proposing to interpret the CAA as allowing
that approach, as described in more detail below. CAA section 111(d)(1)
would certainly allow state plans to require the affected EGUs to be
the sole entities legally responsible for achieving the emission
performance level. The EPA is also soliciting comment on whether it can
reasonably interpret CAA section 111(d)(1) to allow states to adopt
plans that require EGUs and other entities to be legally responsible
for actions required under the plan that will, in aggregate, achieve
the emission performance level.
    We note that some existing state programs, such as RGGI in the
northeastern states, do impose the ultimate responsibility on fossil
fuel-fired EGUs to achieve the required emission reductions, but are
also designed to work either concurrently, or in an integrated fashion,
with RE and demand-side EE programs that reduce the cost of meeting
those emission limitations. These existing programs offer a possible
precedent for another type of CAA section 111(d) state plan. Such a
plan approach could rely on CO2 emission standards
enforceable against affected EGUs--whether in the form of

emission rate or mass limits--to ensure achievement of the required
emission performance level, but also include enforceable or
complementary RE and demand-side EE measures that lower cost and
otherwise facilitate EGU emission reductions. Depending on the type of
plan, these RE and demand-side EE measures could either be enforceable
components of the plan (that is, the states could require affected EGUs
or other affected entities to invest in RE or in demand-side EE
programs) or be complementary to the plan. In this manner, RE and
demand-side EE measures could be a major component of a state's overall
strategy for reducing EGU CO2 emissions at a reasonable
cost.
    It should be noted that state plan approaches that impose legal
responsibility on the affected EGUs to achieve the full level of
required emission performance could incorporate RE and demand-side EE
measures regardless of whether the emission standards that those plans
apply to the affected EGUs take the form of an emission rate or a mass
limit. Plans with rate-based emission limits could incorporate
enforceable RE and demand-side EE measures by adjusting an EGU's
CO2 emission rate when demonstrating compliance through
either an administrative adjustment by the state or use of a tradable
credit approach. (These actions would need to be enforceable components
of a state plan to facilitate EGU compliance with emission rate limits
and ensure that actions are properly quantified, monitored, and
verified.) A state plan that imposes a mass limit on affected EGUs that
is sufficiently stringent to achieve the emission performance level
would not need to include RE or demand-side EE measures as an
enforceable component of the plan to assure the achievement of that
performance level. The mass limit itself would suffice. However, the
state may wish to implement RE and demand-side EE measures as a
complement to the plan to support achievement of the mass limit at
lesser cost.
d. Federal Enforceability
    Another concern expressed by some stakeholders is that including RE
and demand-side EE measures in state plans would render those measures
federally enforceable and thereby extend federal presence into areas
that, to date, largely have been the exclusive preserve of the state
and, in particular, state public utility commissions and the electric
utility companies they regulate. These stakeholders suggest that states
could rely on RE and demand-side EE programs as complementary measures
to reduce costs for, and otherwise facilitate, EGU emission limits
without including those measures in the CAA section 111(d) state plan.
Under this suggested approach, the EGU emission limits would be
federally enforceable, but RE and demand-side EE measures would serve
as complementary measures and would not be enforceable under federal
law; instead, they would remain enforceable under state law. According
to stakeholders, those types of state programs, particularly because
they are well-established, can be expected to achieve their intended
results. Thus, they suggest that the states could conclude that those
RE and demand-side EE measures would be beneficial in assuring the
achievement of the required emission performance level by the affected
EGUs specified in the CAA section 111(d) state plan, even without
including those measures in the plan.
e. Plans With State Commitments
    As another vehicle for approving CAA section 111(d) plans for
states that wish to rely on state RE and demand-side EE programs but do
not wish to include those programs in their state plans, the EPA
requests comment on what we refer to as a ``state commitment
approach.'' This approach differs from the proposed portfolio approach,
described above, in one major way: Under the state commitment approach,
the state requirements for entities other than affected EGUs would not
be components of the state plan and therefore would not be federally
enforceable. Instead, the state plan would include an enforceable
commitment by the state itself to implement state-enforceable (but not
federally enforceable) measures that would achieve a specified portion
of the required emission performance level on behalf of affected EGUs.
The agency requests comment on the appropriateness of this approach.
The agency also requests comment on the policy ramifications of the
following: Under this approach, the state programs upon which the state
bases its commitment may, in turn, rely on compliance by third parties,
and if those state programs fail to achieve the expected emission
reductions, the state could be subject to challenges--including by
citizen groups--for violating CAA requirements and, as a result, could
be held liable for CAA penalties.
    We also solicit comment on a variation of this state commitment
plan approach that is also designed to address stakeholder concerns,
noted above, about imposing sole legal responsibility on affected EGUs
for achieving the emission performance level. With this variation, the
state plan would in effect shift a portion of that responsibility to
the state, in the following manner: The state plan would impose the
full responsibility for achieving the emission performance level on the
affected EGUs, but the state would credit the EGUs with the amount of
emission reductions expected to be achieved from, for example, RE or
demand-side EE measures. The state would then assume responsibility for
that credited amount of emission reductions in the same manner as the
state commitment plan approach discussed above. We solicit comment on
whether, if the EPA were to conclude that CAA section 111(d) requires
state plans to include standards of performance applicable to affected
EGUs that achieve the emission performance level, this type of state
plan would meet that requirement while also assuring those EGUs an
important measure of support.
f. Legal Issues
    The EPA is proposing to interpret the relevant provisions in CAA
section 111 to authorize state plans that achieve emissions reductions
from affected EGUs by means of the portfolio approach. CAA section
111(d)(1) requires each state to submit a plan that ``(A) establishes
standards of performance for any existing source [for certain air
pollutants] . . . and (B) provides for the implementation and
enforcement of such standards of performance.'' CAA section 111(a)(1)
defines a ``standard of performance'' as ``a standard for emissions of
air pollutants which reflects the degree of emission limitation
achievable through the application of the best system of emission
reduction . . . adequately demonstrated.''
    These provisions make clear that emission limits that are
enforceable against affected EGUs appropriately belong in state plans
because they clearly are ``standards of performance.'' However, the
terms of CAA section 111(d)(1) do not explicitly address whether, in
addition to emission limits on affected EGUs, state plans may include
other measures for achieving the emission performance level. Nor do
they address whether entities other than affected EGUs may be subject
to requirements that contribute to reducing EGU emissions. Under the
U.S. Supreme Court's 1984 decision in Chevron U.S.A. Inc. v. NRDC,
where the statute leaves a gap, the agency has discretion to fashion an
interpretation

that is a reasonable construction of the statute.\275\
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    \275\ Chevron U.S.A., Inc. v. NRDC, 467 U.S. 837, 842-44 (1984).
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    The EPA is proposing to interpret the phrases ``standards of
performance for any existing source'' and ``the implementation and
enforcement of such standards of performance'' to encompass and allow
the various components of the portfolio approach. To the extent that a
portfolio approach contains measures that are not standards of
performance or do not implement or enforce such standards, the EPA is
proposing to interpret CAA section 111 as allowing state CAA section
111(d) plans to include measures that are neither standards of
performance nor measures that implement or enforce those standards,
provided that the measures reduce CO2 emissions from
affected sources. These measures would also be federally enforceable if
included in an approved plan.
    The EPA's proposed interpretation is based, in part, on CAA section
111(d)'s requirement that states set performance standards ``for''
affected sources. Although ``for'' could be read as meaning that the
standards must apply to affected sources, ``for'' is also reasonably
interpreted to have a more capacious meaning: Standards (such as EE and
RE standards) are reasonably considered to be ``for'' affected sources
if they would have an effect on affected sources by, for example,
causing reductions in affected EGUs' CO2 emissions by
decreasing the amount of generation needed from affected EGUs. Under
this interpretation, and depending on the specific provisions in the
state plan, renewable energy and demand-side energy efficiency
requirements would be ``for'' fossil fuel-fired EGUs where such
standards result in reduced CO2 emissions from fossil fuel-
fired EGUs, even if the standards do not apply directly to fossil fuel-
fired EGUs.
    The EPA also requests comment on another approach: Whether
``standards of performance for [affected sources]'' is reasonably read
to include the emission performance level (i.e., the state goal) on
grounds that the level is ``a standard for emissions'' because it is in
the nature of a requirement that concerns emissions and it is ``for''
the affected sources because it helps determine their obligations under
the plan.
    Moreover, where the specific measures in the portfolio approach are
not themselves a ``standard of performance,'' state plans may include
measures that implement or enforce a standard of performance. For
example, if the state's plan achieves the emission performance level
through rate-based emission limits applicable to the affected sources,
coupled with a crediting mechanism for RE and demand-side EE measures,
we propose that RE and demand-side EE measures may be included in the
plan as ``implement[ing]'' measures because they facilitate the
sources' compliance with their standards of performance. We solicit
comment on the extent to which measures such as RE and demand-side EE
may be considered ``implement[ing]'' measures in state plans if they
are not directly tied to emission reductions that affected sources are
required to make through emission limits, and if they are requirements
on entities other than the affected sources. In addition, the EPA
proposes to interpret CAA section 111(d)(1) to allow state plans to
include components of the portfolio approach that are measures that
would reduce emissions from affected sources, even if those measures
are neither ``standards of performance for existing sources'' nor
measures ``for the implementation and enforcement of such standards of
performance.'' There is no specific language in CAA section 111(d) or
elsewhere in the Act that prohibits states from including measures
other than performance standards and implementation and enforcement
measures, provided that they reduce emissions from affected EGUs.
    This interpretation is consistent with the principle of cooperative
federalism, which is one of the foundational principles of the Clean
Air Act and which supports providing flexibility to states to meet
environmental goals (provided minimum CAA statutory requirements are
met). This general principle, especially when combined with the
statutory directive that CAA section 111(d) regulations shall establish
procedures ``similar to that provided by section 110,'' supports an
interpretation of CAA section 111(d) that allows states sufficient
flexibility in meeting the state goal set under CAA section 111(d) to
include in their CAA section 111(d) plans other measures (i.e.,
measures that are neither performance standards nor measures that
enforce or implement performance standards). The EPA solicits comment
on all aspects of its proposed interpretation that states have this
flexibility in selecting measures for their state plans under CAA
section 111(d).
    An alternative interpretation of CAA section 111(d)(1) would
suggest that the responsibility to achieve the state's required
emission performance level must be assigned solely to affected EGUs. As
described elsewhere in this preamble, there are a number of state-level
CO2 programs that take this approach while still taking
advantage of low-cost reductions from RE and demand-side EE through the
use of complementary measures. This alternative interpretation would be
based on, for example: A determination that CAA section 111(d)(1) must
be read as precluding a state plan from including measures that are
neither standards of performance nor measures for the implementation or
enforcement of such standards; an interpretation that the state's
obligation to set performance standards ``for'' existing sources means
that the standards must apply to affected EGUs and not to other
entities; and an interpretation that measures ``for the implementation
and enforcement of such performance standards'' do not include measures
that are not intended or designed to assist affected EGUs in meeting
the performance standards. The EPA requests comment on whether it must
adopt this alternative interpretation. If so, the EPA also takes
comment on whether there is a way, nonetheless, to allow states to rely
on the portfolio approach to some extent and/or for some period of
time.
    We request comment on all of the interpretations discussed in this
section generally, and on all legal issues under CAA section 111(d)(1)
with respect to what measures can be included in a state plan and what
entities must be legally responsible for meeting those measures.
g. Ongoing Applicability of CAA Section 111(d) State Plan
    The EPA is proposing that an existing source that becomes subject
to requirements under CAA section 111(d) will continue to be subject to
those requirements even after it undertakes a modification or
reconstruction. Under this interpretation, a modified or reconstructed
source would be subject to both (1) the CAA section 111(d) requirements
that it had previously been subject to and (2) the modified source or
reconstructed source standard being promulgated under CAA section
111(b) simultaneously with this rulemaking. It should be noted that
this proposal applies to any existing source subject to any CAA section
111(d) plan, and not only existing sources subject to the CAA section
111(d) plans promulgated under this rulemaking.
    As noted above, a ``new source'' is defined under CAA section
111(a)(2) as ``any stationary source, the construction or modification
of which is commenced after,'' in general, a proposed or final CAA
section 111(b) rule becomes applicable to that source; and under

section 111(a)(6), an ``existing source'' is defined as ``any
stationary source other than a new source.'' Under these definitions,
an ``existing source'' that commences construction of a modification or
reconstruction after the EPA has proposed or finalized a CAA section
111(b) standard of performance applicable to it, becomes a ``new
source.'' However, CAA section 111(d) is silent on whether requirements
imposed under a CAA section 111(d) plan continue for a source that
ceases to be an existing source because it modifies or reconstructs.
Specifically, CAA section 111(d)(1) provides that ``each State shall
submit to the Administrator a state plan which (A) ``establishes
standards of performance for any existing source'' but does not say
whether, once the EPA has approved a state plan that establishes a
standard of performance for a given source, that standard is lifted if
the source ceases to be an existing source. Similarly, no other
provisions of CAA section 111 address whether the imposition of a CAA
section 111(b) standard on a modified or reconstructed source ends the
source's obligation to meet any applicable CAA section 111(d)
requirements.
    Because CAA section 111(d) does not address whether an existing
source that is subject to a CAA section 111(d) program remains subject
to that program even after it modifies or reconstructs, the EPA has
authority to provide a reasonable interpretation, under the Supreme
Court's decision in Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-844
(1984). The EPA's interpretation is that under these circumstances, the
source remains subject to the CAA section 111(d) plan, for two reasons.
The first is to assure the integrity of the CAA section 111(d) plan.
The EPA believes that many states will develop integrated plans that
include all of their EGUs, such as rate- or mass-based trading
programs. Uncertainty about whether units would remain in the program
could be very disruptive to the operation of the program. The second
reason is to avoid creating incentives for sources to seek to avoid
their obligations under a CAA section 111(d) plan by undertaking
modifications. The EPA is concerned that owners or operators of units
might have incentives to modify purely because of potential
discrepancies in the stringency of the two programs, which would
undermine the emission reduction goals of CAA section 111(d).
    The EPA invites comments on this interpretation of CAA section
111(d)(1), including whether this interpretation is supported by the
statutory text and whether this interpretation is sensible policy and
will further the goals of the statute. It should be noted that this
interpretation is severable from the rest of this rulemaking, so that
if the EPA revises this interpretation in the final rule or if the EPA
adopts this interpretation in the final rule but it is invalidated by a
Court, there would be no effect on the rest of this rulemaking.
2. Timing for Implementation and Achievement of Goals
    This section describes proposed state plan requirements related to
the timing of achieving emission performance goals, including
performance demonstrations, performance periods, and interim progress
milestones.
    As previously discussed, the goals are derived from application of
four ``building blocks.'' The EPA has based the application of some of
these measures to reduce CO2 emissions, particularly blocks
3 (expansion of cleaner generating capacity) and 4 (increasing demand-
side energy efficiency), on forward-looking, longer-term assumptions.
For example, the EPA expects technologies to reduce carbon emissions to
more fully develop over time and acknowledges the cumulative effects of
implementation of EE programs and addition of RE generating capacity
over time. Therefore, the EPA is not proposing to require each state to
meet its full, final goal immediately, but rather to meet it by 2030.
The EPA realizes, however, that states can achieve emission reductions
from those and other measures in the short-term. Therefore, the EPA is
proposing that states begin meeting interim goals, beginning in 2020.
The EPA also believes that timing flexibility in implementing measures
provides significant benefits that allow states to develop plans that
will help states achieve a number of goals, including: Reducing cost,
addressing reliability concerns, and addressing concerns about stranded
assets. Therefore, the EPA is also proposing to allow states
flexibility to define the trajectory of emission performance between
2020 and 2029, as long as the interim emission performance level is met
on a 10-year average or cumulative basis and the 2030 emission
performance level is achieved.
    Section VIII.B.1.a of this preamble provides an overview of the
proposals for state plan performance demonstrations and timing of
emission reductions. Subsequent subsections include proposals for the
start date for the interim goal performance period, the duration of the
performance periods for the final and interim goals, interim progress
milestone requirements, consequences if actual emission performance
does not meet the state goal, and out-year requirements for states to
maintain CO2 emission performance levels over time
consistent with the final goal. In Section VIII.B.2.f of this preamble,
the agency also requests comment on alternative requirements aimed at
continued emission performance improvement after 2029. In Section
VIII.B.2.g of this preamble, the EPA proposes flexibility for states to
change from mass-based to rate-based goals in different performance
periods and, in Section VIII.B.2.h, we solicit comment on planning
requirements that match the option of alternative, less stringent state
goals.
a. Performance Demonstrations and Timing of Emission Reductions
    As described previously, the agency is proposing final state-
specific goals (specified in Table 8) that represent emission rates to
be achieved by 2030, as well as interim goals, to be achieved on
average over the 10-year period from 2020-2029. The agency is also
proposing that emission performance levels consistent with the final
state-specific goals be maintained after 2030.
    This relatively long planning and implementation period provides
states with substantial flexibility regarding methods and timing of
achieving emission reductions. States may wish to make adjustments to
their implementation approaches along the way, or as conditions change
may need to make adjustments to ensure that their plans achieve the
goals as intended. As a result, the agency envisions that the EPA,
states, and affected entities will have an ongoing relationship in the
course of implementing this program.
    The EPA proposes that a state plan must demonstrate projected
achievement of the emission performance levels in the plan, and these
emission performance levels must be equivalent to or better than the
interim and final goals established by the EPA. Specifically, the state
plan must demonstrate that the projected emission performance of
affected EGUs in the state will be equivalent to or better than the
applicable interim goal during the 2020-2029 period, and equivalent to
or better than the applicable final goal during the year 2030. The
state plan must identify requirements that continue to apply after 2030
and are likely to maintain continued emission performance by affected
EGUs that meets the final goal; however, quantitative projections of
emission performance by affected EGUs

beyond 2030 would not be required by this rule under the proposed
approach. Instead, the EPA proposes that the state plan would be
considered to provide for maintenance of emission performance
consistent with the final goal if the plan measures used to demonstrate
achievement of the final goal by 2030 will continue in force and not
sunset.
    In addition to demonstrating that projected plan performance will
meet the interim and final state goals, the EPA proposes that state
plans must contain requirements for tracking actual plan performance
during implementation. For plans that do not include enforceable
requirements for affected EGUs that ensure achievement of the full
level of required emission performance and interim progress, the state
plans would be required to include periodic program implementation
milestones and emission performance checks, and include corrective
measures to be implemented if mid-course corrections are necessary. The
state plan would provide for continued tracking of emission performance
after 2030, and for corrective measures if the emission performance of
affected EGUs in the state did not continue to meet the 2030 final goal
during any three-year performance period.
    The rationale for this approach is that it would ensure that states
design their plans in a way that considers both the interim and final
goals. If only the interim goal were considered, a state plan might not
be sufficient to achieve the final goal.\276\
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    \276\ The 2020-2029 interim goal is expressed as a 10-year
average emission rate to provide states with flexibility in
designing their plans. Due to the potential for continued end-use
energy efficiency improvements, the 2029 four-building-block BSER-
based level is a more stringent level than the 2020-2029 average
four-building-block BSER-based level. The purpose of the final goal
is to ensure that each state ultimately achieves the emission
performance level for affected EGUs that is achievable by 2029.
Without the final goal, it is possible that a state could achieve
the 2020-2029 interim goal but not achieve the 2030 final goal.
---------------------------------------------------------------------------

    The agency requests comment on a second option in which, in
addition to submitting a plan demonstrating emission performance
through 2030, states would be required to make a second submittal in
2025 showing whether their plan measures would maintain the final-goal
level of emission performance over time (as further described below).
If not, the state submittal would be required to strengthen or add to
measures in the state plan to the extent necessary to maintain that
level of performance over time.
    The EPA also requests comment on whether 2025, or an earlier or
later year, would be the optimal year for a second plan submittal under
the second option.
b. Start Date for Performance Period for Interim Goal
    A performance period is a period for which the state plan must
demonstrate that the required emission performance level will be met.
The EPA proposes a start date of January 1, 2020, for the interim goal
plan performance period.\277\ This date would be the beginning of the
10-year period for which a state must demonstrate that the projected
emission performance level of affected EGUs in the state, on average,
will be equivalent to or better than the applicable interim goal. The
agency generally requests comment on the appropriate start date and
rationale.
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    \277\ The start date for a plan performance period must match
the start date of the corresponding state emission performance goal.
If a start date other than January 2020 were selected, the EPA would
recompute the state goals consistent with the selected start date.
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    In considering the start date, it is relevant to consider the due
dates for state plan submittals and the amount of time available for
program implementation by the start date. January 2020 is 3.5 years
from the proposed June 2016 deadline for initial plan submittals, 2.5
years from the proposed June 2017 extended deadline for complete plans
from states not participating in a multi-state plan, and 1.5 years from
the proposed June 2018 extended deadline for complete plans from states
participating in a multi-state plan. The EPA suggests that affected
entities may have greater lead time for compliance than might be
implied by the plan submittal dates referenced above. Affected entities
will have knowledge of state requirements as they are adopted, and the
state must adopt rules and requirements in advance of submitting its
complete plan to the EPA. Also, as explained in detail in subsection c,
states may choose a different emission performance improvement
trajectory from that which the EPA assumes for purposes of calculating
state goals, achieving lesser levels of performance in early years and
more in later years, provided, of course, that the interim 10-year
average requirement is met.
    The EPA proposes that a 2020 start date for the interim goal plan
performance period is achievable in light of the following additional
considerations. First, existing state programs will play a role in
helping to achieve this rule's proposed emission performance levels.
Second, in advance of this proposal, many states already were
contemplating design of strategies that would achieve CO2
emission reductions equivalent to those that could be required by CAA
section 111(d) emission guidelines. Third, for inclusion in the
building blocks, the EPA considered only those emission abatement
measures that are technically feasible and broadly applicable, and can
provide reductions in CO2 emissions from affected EGUs at
reasonable cost.
    For example, the EPA expects that many EGUs will meet their
requirements in part by implementing heat rate improvements, and those
actions may be undertaken promptly. The plant operations and
maintenance (O&M) and engineering solutions used to improve heat rates
at existing EGUs have long been commercially available and have been
implemented at EGUs for many years. Further, the relatively modest
capital costs (average $100/kW) and significant fuel savings associated
with a suite of heat rate improvement (HRI) methods result in this
measure being a low-cost approach to reducing CO2 emissions
from existing EGUs. HRI ``best practices'' (e.g., installation of
modern control systems, operator training, smart soot blowing) are the
least-cost HRI methods and can be applied quickly, without lengthy EGU
outages. The somewhat more costly HRI ``upgrades'' (e.g., steam turbine
upgrade, boiler draft fan/driver upgrade) may require modest EGU
outages to implement, but have also been applied on numerous EGUs to
improve or maintain performance. Drawing on the power sector's
extensive experience with HRI methods, and the many existing supply
chains already supporting these methods, the EPA expects that it would
be feasible to implement HRI projects (i.e., building block 1) by 2020.
    Dispatch changes, which are largely driven by the variable cost of
operating a given EGU, occur on an hourly basis in the power sector.
The average availability factor for NGCCs in the U.S. generally exceeds
85 percent, and can exceed 90 percent for selected groups.\278\ In
addition, the existing natural gas pipeline and electricity
transmission networks are already connected to every existing NGCC
facility, and can support aggregate operation of the NGCC fleet at 70
percent (or above) at the state level, or can be reasonably expected to
do so in the time frame for compliance with this rule. Therefore,
building block 2, which represents shifting of generation from steam
fossil EGUs to existing NGCCs, is a viable method for providing
CO2

emission reductions at existing EGUs by the 2020 compliance start date.
---------------------------------------------------------------------------

    \278\ Source: NERC, 2008-2012 Generating Unit Statistical
Brochure.
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    Building Block 3 is based on shifting generation from affected
fossil units to new renewable energy generating capacity, which is
added over time, and new or preserved nuclear capacity, all of which is
expected to be in place by 2020 (see the GHG Abatement Measures TSD for
more information).
    Finally, there is considerable experience with the states and the
power sector in designing and implementing demand-side energy
efficiency improvement strategies and programs. It is also well
accepted that such improvements can achieve reductions in
CO2 emissions from existing EGUs at a reasonable cost.
Building block 4 represents a feasible pathway for reducing utilization
of carbon-emitting EGUs by implementing improvements in demand-side
energy efficiency. This building block is based on a ``best practices''
scenario where all states achieve a level of performance--matching a
level achieved or committed to by twelve leading states--of 1.5 percent
annual incremental electricity savings as a percentage of retail sales.
For the best practices scenario, all states achieve this level of
performance no later than 2025, with leading states reaching this level
sooner. Each state's current level of performance is taken into
account, with states achieving lower levels of performance being
allowed more time to reach the best practice level.
c. Duration of Performance Periods for Final and Interim Goals
    The EPA recognizes that a state's circumstances and choice of
emission reduction strategies may affect the timing of CO2
emission performance improvement within a multi-year planning period.
States can be expected to select various combinations of measures and
those measures may vary in the time needed to reach full
implementation. The agency recognizes that certain emission reduction
measures and programs (e.g., heat rate improvements) are generally
easier to implement in the near term, while others (e.g., renewable
portfolio standards, demand-side energy efficiency programs) may
require several years to implement because of the time necessary to
establish the proper infrastructure if a state does not already have
such programs in place. Though some states have already implemented
such programs that are achieving results, other states may have to
establish them for the first time. New single and multi-state programs,
as well as existing single and multi-state programs that are adding or
revising measures, may need time for implementation to achieve the
required level of emission performance.
    As described in Section VII of the preamble, the EPA is proposing
state-specific CO2 emission performance goals in a multi-
year format to provide states with flexibility for the timing of
programs and measures that improve EGU emission performance, while
ensuring an overall level of performance consistent with application of
the BSER. Specifically, the agency is proposing the state-specific
goals (shown in Table 8) which represent emission rates to be achieved
by 2030 (final goal) and emission rates to be achieved on average over
the 2020-2029 period (the interim goal).
    The EPA proposes the following as the preferred option for the
final and interim goal performance periods. As further explained below,
this option reflects three main objectives: (1) Provide states with
timing flexibility during the interim goal period to accommodate
differences in state adoption processes and types of state programs,
(2) ensure that state plans are designed to achieve the final goal no
later than 2030, and (3) provide flexibility for year-to-year variation
in actual emission performance that may occur as the electricity system
responds to economic fluctuations.
    Interim goal--Projected plan performance demonstration: To be
approvable, a state plan must demonstrate that the emission performance
of affected EGUs will meet the interim emission performance level on
average over the 2020-2029 period.
    Interim goal--Actual plan performance check: In 2030, the emission
performance of affected EGUs during the period 2020-2029 must be
compared against the interim goal. (In addition, as described
separately below, interim emission performance checks will occur during
this 10-year period.)
    Final goal--Projected plan performance demonstration: To be
approvable, a state plan must demonstrate that the emission performance
of affected EGUs will meet the final emission performance level no
later than 2030, on a single-year basis.
    Final goal--Actual plan performance check: Starting at the end of
2032, emission performance of affected EGUs must be compared against
the final goal on a three-year rolling average basis (i.e., 2030-32,
2031-33, 2032-2034, etc.).
    This proposed approach provides a 10-year performance period for
the interim performance level. The 10-year period allows states
flexibility for timing of program implementation as the state ramps up
its programs to achieve the final performance level. Using the single
year 2030 as the projected year for achievement of the final goal
ensures that state plans are designed to achieve the final goal no
later than 2030; providing a multi-year time frame for projected plan
performance would inappropriately delay the requirement for a final-
goal level of performance that the EPA's analysis shows is achievable
at the end of the 10-year interim ramp-up period. Using 2030 also
avoids overlap with the interim goal performance period. The rolling
three-year performance periods for measuring actual plan performance
against the final goal performance level are proposed in light of year-
to-year variability in economic and other factors, such as weather,
that influence power system operation and affect EGU CO2
emissions. The choice of 2030-2032 avoids overlap with the 2020-2029
interim goal performance period.
    For a rate-based plan, 2020-2029 emission performance is an average
CO2 emission rate for affected EGUs representing cumulative
CO2 emissions for affected EGUs over the course of the 10-
year performance period divided by cumulative MWh energy output \279\
from affected EGUs over the 10-year performance period, with rate
adjustments for qualifying measures, such as end-use energy efficiency
and renewable energy measures, as described in Section VIII.F.3. For a
mass-based plan, 2020-2029 emission performance is total tons of
CO2 emitted by affected EGUs over the 10-year performance
period.
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    \279\ For EGUs that produce both electric energy output and
other useful energy output, there would also be a credit for non-
electric output, expressed in MWh.
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    The agency invites comment on this and other approaches to
specifying performance periods for state plans.
d. Program Implementation Milestones and Tracking of Emission
Performance
    The EPA recognizes the importance of ensuring that, during the
proposed 10-year performance period (2020-2029) for the interim goal, a
state is making steady progress toward achieving the required level of
emission performance. The EPA is proposing that certain types of state
plans be required to have program implementation milestones to ensure
interim progress, as well as periodic checks on overall emission
performance leading to corrective measures if necessary.
    Some types of plans are ``self-correcting'' in that they inherently

would assure interim performance and full achievement of the state
plan's required level of emission performance through requirements that
are enforceable against affected EGUs. One example is a state plan with
a rate-based emission performance level that requires affected EGUs
collectively to meet an emission rate consistent with the state's
required emission performance level, and allows EGUs to comply through
an emission rate averaging system. Another example is a plan that
includes measures or actions (e.g., emission limits that apply to
affected EGUs and ensure full plan performance) that take effect
automatically if the plan's required emission performance level is not
met, in accordance with a specified milestone. The EPA requests comment
on whether there are other types of state plans that should be
considered ``self-correcting.''
    The EPA proposes that self-correcting plans need not contain
interim milestones consisting of program implementation steps, because
these state plans inherently require both interim progress and
achievement of the full level of required emission performance in a
manner that is federally enforceable against affected EGUs. Annual
reporting of emission performance by the state, however, is required
for all types of plans.
    For plans that are not self-correcting, the EPA proposes that the
state plan must identify periodic program implementation milestones
(e.g., start of an end-use energy efficiency program, retirement of an
affected EGU, or increase in portfolio requirements under a renewable
portfolio standard) that are appropriate to the programs and measures
included in the plan. If, during plan implementation, a state were to
miss program implementation milestones in its plan, it would need to
report the delay to the EPA, explain the cause, and describe the steps
the state will take to accelerate subsequent implementation to achieve
the planned improvements in emission performance. Depending on the
severity of delay and the explanation, the EPA could ultimately
evaluate actions under CAA authorities to ensure timely program
implementation.
    In addition, we propose that the state and the EPA would track
state plan emission performance on an ongoing basis, with states
reporting performance data to the EPA annually by July 1. During the
interim performance period, beginning in 2022, the state would be
required each year to include a comparison of emission performance
achieved to performance projected in the state plan. Each comparison
would cover the preceding two-year period. The EPA may also approve
regular, periodic emission comparison checks with a different frequency
or comparison period to reflect the design of a state's programs (e.g.,
compliance periods for EGUs under an emission limit).
    A report and corrective measures would be required if an interim
emission check showed that actual emission performance of affected
entities was not within 10 percent of the performance projected in the
state plan (i.e., for a rate-based plan, if the average emission rate
of affected EGUs were 10 percent higher than plan projections, or for a
mass-based plan, if collective emissions of affected EGUs were 10
percent higher than plan projections). In that event, the state would
be required in its submission to explain reasons for the deviation
(e.g., energy efficiency program not working as effectively as
expected, prolonged extreme weather that had been unanticipated in
electricity demand projections) and specify the corrective measures
that will be taken to ensure that the required level of emission
performance in the plan will be met. The state also would be required
to implement those corrective measures as expeditiously as practical.
    The agency proposes that states be given a choice regarding when to
adopt into regulation the corrective measures that the state plan
identifies for implementation in the event that state plan performance
is deficient. First, the state could adopt corrective measures into
regulation prior to plan submittal in a manner that enables the state
to implement the measures administratively, without further legislation
or rulemaking, if a performance deficiency occurs during plan
implementation. This would expedite implementation of corrective
measures once a deficiency is discovered. Second, the state could elect
to wait to adopt into regulation the corrective measures identified in
the plan until after a plan performance deficiency is discovered. The
EPA proposes this choice in recognition of the fact that it may be
challenging for states to fully adopt corrective measures in advance to
address the possibility that their plan will not perform as projected.
However, if a state makes the latter choice, the EPA proposes that the
state must report the reasons for deficient performance and must
implement corrective measures if actual emission performance was
inferior to projected performance by eight percent or more (rather than
10 percent or more). The reason for the lower percentage trigger is to
identify a gradually developing deficiency in plan performance earlier
in time. Legislative and/or regulatory action to adopt corrective
measures after a deficiency is discovered will take significant time.
State processes to activate corrective measures should be triggered
earlier if corrective measures are not adopted in regulation and ready
to implement.
    The EPA alternatively requests comment on whether states should be
required to create legal authority and/or adopt regulations providing
for corrective measures in developing the state plan. The agency
requests comment generally on the conditions that should trigger
corrective measure requirements. The agency also solicits comment on
whether actual emission performance inferior to projected performance
by ten percent (for plans with corrective measures adopted into
regulation prior to complete plan submittal) is the appropriate trigger
for requiring a state to report the reasons for deficient performance
and to implement corrective measures. We are also soliciting comment on
the range of five percent to fifteen percent. For plans without
corrective measures adopted into regulation prior to complete plan
submittal, the agency solicits comment on whether the proposed eight
percent emission performance deviation trigger is appropriate. We also
solicit comment on the range of five percent to ten percent.
    The EPA proposes that the state will be required to compare actual
emission performance achieved during the entire 10-year interim
performance period (i.e., 2020-2029) against the interim goal. As noted
above, beginning after 2032, the EPA proposes that the state be
required to compare actual emission performance achieved against the
final goal on a rolling three-year average basis (e.g., 2030-32, 2031-
33, etc.). The EPA also requests comment on the milestone approach and
emission performance checks outlined above in the context of the
alternative 5-year performance period and the planning approach for
alternative state goals, which is described below.
e. Consequences if Actual Emission Performance Does Not Meet State Goal
    There are scenarios under which an approved state plan might fail
to achieve a level of emission performance by affected EGUs that meets
the state goal. Under some types of plans, a possible scenario is that
despite successful plan implementation, emissions under the plan turn
out to be higher than projected at the time of plan

approval because actual economic conditions vary from economic
assumptions used when projecting emission performance. State officials
have raised the possibility that achieved emission performance might
not meet projected performance if, for example, planned retirements of
EGUs were postponed because severe weather produced greater-than-
expected electricity generation needs. In addition, emissions could
theoretically exceed projections because affected entities under a
state plan did not fulfill their responsibilities, or because the state
did not fulfill its responsibilities.
    The EPA believes that the emission guidelines should specify the
consequences in the event that actual emission performance under a
state plan does not meet the applicable interim goal in 2020-2029, or
does not meet the applicable final goal in 2030-2032 or later, because
CAA section 111(d) is not specific on this point. The agency requests
comment on how the consequences should vary depending on the reasons
for a deficiency in performance.
    Specifically, the agency requests comment on whether consequences
should include the triggering of corrective measures in the state plan,
or plan revisions to adjust requirements or add new measures. The
agency also requests comment on whether corrective measures, in
addition to ensuring future achievement of the state goal, should be
required to achieve additional emission reductions to offset any
emission performance deficiency that occurred during a performance
period for the interim or final goal. This concept has been applied,
for example, in the Acid Rain Program under Title IV of the CAA; a
source that has sulfur dioxide emissions exceeding the emission
allowances that it holds at the end of the period for demonstrating
compliance is required subsequently to obtain additional emission
reductions to offset its excess emissions.\280\ The agency also
requests comment on the process for invoking requirements for
implementation of corrective measures in response to a state plan
performance deficiency.
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    \280\ CAA section 411(b).
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    The EPA further requests comment on whether the agency should
promulgate a mechanism under CAA section 111(d) similar to the SIP call
mechanism in CAA section 110. Under this approach, after the agency
makes a finding of the plan's failure to achieve the state goal during
a performance period, the EPA would require the state to cure the
deficiency with a new plan within a specified period of time (e.g., 18
months). If the state still lacked an approved plan by the end of that
time period, the EPA would have the authority to promulgate a federal
plan under CAA section 111(d)(2)(A).
f. Out-Year Requirements: Maintaining or Improving the Level of
Emission Performance Required by the Final Goal
    The agency is determining state goals for affected EGU emission
performance based on application of the BSER during specified time
periods. This raises the question of whether affected EGU emission
performance should only be maintained--or instead should be further
improved--once the final goal is met in 2030. This involves questions
of goal-setting as well as questions about state planning. In this
section, the EPA proposes that a state must maintain the required level
of performance, and requests comment on the alternative of requiring
continued improvement.
    The EPA believes that Congress either intended the emission
performance improvements required under CAA section 111(d) to be
permanent or, through silence, authorized the EPA to reasonably require
permanence. Other CAA section 111(d) emission guidelines set emission
limits to be met permanently. Therefore, the EPA is proposing that the
level of emission performance for affected EGUs represented by the
final goal should continue to be maintained in the years after 2030.
The EPA is proposing a mechanism for implementing this objective, and
is taking comment on an alternative option.
    As noted above, the EPA proposes that the state plan must
demonstrate that plan measures are projected to achieve the final
emission performance level by 2030. In addition, the state plan must
identify requirements that continue to apply after 2030 and are likely
to maintain affected EGU emission performance meeting the final goal;
however, quantitative projections of emission performance beyond 2030
would not be required under the proposed option. Instead, the EPA
proposes that the state plan would be considered to provide for
maintenance of emission performance consistent with the final goal if
the plan measures used to demonstrate projected achievement of the
final goal by 2030 will continue in force and not sunset.\281\ After
implementation, the state would be required to compare actual plan
performance against the final goal on a rolling three-year average
basis starting in 2030, and to implement corrective measures if
necessary.
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    \281\ This is straightforward for plans with EGU emission limits
that ensure the full level of performance required. For renewable
energy programs, the agency suggests that the state could continue
to require the renewable portfolio percentage level that was relied
upon to demonstrate projected achievement of the final goal
performance level in 2030. For plans that rely in part on end-use
energy efficiency programs and measures, the EPA requests comment on
what a state would need to require in its plan to show that
performance will be maintained after 2030. End-use energy efficiency
programs and measures often involve an annual energy savings
requirement or goal, and some types require additional monetary
expenditures each year to meet those savings requirements or goals.
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    The EPA also requests comment on an alternative approach to a
state's pre-implementation demonstration that the final-goal level of
performance will be maintained after 2030. Under this alternative, the
state plan would be required to include projections demonstrating that
emission performance would continue to meet the final goal for up to 10
years beyond 2030. This approach could be implemented through a second
round of state plan analysis and submittals in 2025 to make the
demonstration and strengthen or add measures if necessary. The EPA
generally requests comment on appropriate requirements to maintain the
emission performance of affected EGUs in years after 2030.
    The EPA also requests comment on whether we should establish BSER-
based state emission performance goals for affected EGUs that extend
further into the future (e.g., beyond the proposed planning period),
and if so, what those levels of improved performance should be. Under
this alternative, the EPA would apply its goal-setting methodology
based on application of the BSER in 2030 and beyond to a specified time
period and final date. The agency requests comment on the appropriate
time period(s) and final year for the EPA's calculation of state goals
that reflect application of the BSER under this approach.
    The EPA notes that CAA section 111(b)(1)(B) calls for the EPA, at
least every eight years, to review and, if appropriate, revise federal
standards of performance for new sources. This requirement provides for
regular updating of performance standards as technical advances provide
technologies that are cleaner or less costly. The agency requests
comment on the implications of this concept, if any, for CAA section
111(d).
g. State Flexibility To Choose Mass-Based and Rate-Based Goals After
2029
    The EPA proposes that states have flexibility to choose between a
rate-

based and mass-based performance level for each performance period. For
example, if a state plan used a mass-based performance level for the
2020-2029 period, the state plan may still use a rate-based performance
level for final goal performance periods, or vice versa.
    A state that adopted a mass-based performance level for 2020-2029
would have two options for addressing any perceived need for emissions
flexibility in light of anticipated electricity demand growth after
2029. The state either could adopt a rate-based performance level
consistent with the final goal, or could adopt a mass-based performance
level based on a translation of the rate-based final goal to a mass-
based goal.
h. Planning Approach for Alternative State Goals
    In Section VII, the EPA requests comment on alternative, five-year
state emission performance goals for affected EGUs shown in Table 9.
The alternative goals represent emission rates achievable on average
during the 2020-2024 period, as well as emission rates to be achieved
and maintained after 2024. These alternative goals are less stringent
than the proposed goals in Table 8.
    To accompany the alternative goals, the EPA requests comment on
another approach for state plan performance periods. This approach
would require state plans to demonstrate that the required interim
emission performance level will be met on average by affected EGUs
during the five-year 2020-2024 interim period, and that the alternative
final goal be met no later than 2025. After plan implementation, actual
emission performance would be compared with the alternative final goal
on a three-year rolling average basis, starting with 2025-2027, in
light of year-to-year variability in economic and other factors, such
as weather, that influence power system operation and affect EGU
CO2 emissions.
    In connection with the alternative state goals, for the years after