electricity demand at a given point in time, the variable costs of
available generating resources, and system constraints. This system of
security-constrained economic dispatch assures reliable and affordable
electricity. Electricity demand varies across geography and time in
response to numerous conditions, such that EGU owners and grid
operators are constantly responding to changes in demand and ``re-
dispatching'' to meet demand in the most reliable and cost-effective
manner possible. Since the enactment and implementation of Title IV of
the CAA Amendments of 1990, in regions where EGUs are subject to
market-based programs to limit emissions of pollutants such as
SO2 and NOX, the costs of emission allowances
have been factored directly into those EGUs' variable costs, like the
variable costs of operating pollution control devices, and have thereby
been accounted for in least-cost economic dispatch decisions by grid
operators. Similarly, operators of EGUs subject to CO2
emissions limits in RGGI now include the cost of RGGI CO2
allowances in those EGUs' variable costs,\124\ creating economic
incentives to replace generation at higher-emitting EGUs with
generation from lower-emitting sources to reduce CO2
emissions at the former through the process of least-cost economic
dispatch. As an alternate mechanism, permitting authorities can impose
limits on utilization or CO2 emissions at higher-emitting
EGUs, in which case grid operators and other market participants would
use the integrated electricity system to find other ways to meet the
demand for electricity services, either through demand-side energy
efficiency or through increased generation from lower-emitting EGUs. In
either case, whether implemented through economic mechanisms or permit
limitations, reducing emissions at high carbon-intensity EGUs is
technically feasible and can reduce overall power sector CO2
emissions because generation at such EGUs can be replaced by generation
at less carbon-intensive EGUs.
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    \124\ The PJM market monitor publishes breakdowns of wholesale
energy prices, including a CO2 emission allowance cost
component, based on analysis of the prices bid by the ``marginal''
EGUs. See Monitoring Analytics, 2013 State of the Market Report for
PJM at 103-05, tbls. 3-63 & 3-64 (2014), available at http://www.monitoringanalytics.com/reports/pjm_state_of_the_market/2013.shtml.
---------------------------------------------------------------------------

    We have also analyzed potential upstream net methane emissions
impact from natural gas and coal for the impacts analysis. This
analysis indicated that any net impacts from methane emissions are
likely to be small compared to the CO2 emissions reduction
impacts of shifting power generation from coal-fired steam EGUs to NGCC
units. Further information on our analysis of upstream impacts can be
found in Appendix 3A of the RIA.
b. Magnitude of Re-Dispatch
    Having identified replacing generation at higher-emitting EGUs with
generation at lower-emitting EGUs as a technically feasible
CO2 emissions reduction strategy, we next address the
quantity of replacement generation that may be relied upon at
reasonable costs. The U.S. electric generating fleet includes EGUs
employing a variety of generating technologies. EGUs using technologies
with relatively low variable costs, such as nuclear units, are for
economic reasons generally operated at their maximum output whenever
they are available. Renewable EGUs such as wind and solar units also
have low variable costs, but in any event are generally operated when
wind and sun conditions permit rather than at operators' discretion. In
contrast, fossil fuel-fired EGUs have higher variable costs and are
also relatively flexible. Fossil fuel-fired EGUs are therefore
generally the units that operators use to respond to intra-day and
intra-week changes in demand. Because of these typical characteristics
of the various EGU types, the primary re-dispatch opportunities among
existing units available to EGU owners and grid operators generally
consist of opportunities to shift generation among various fossil fuel-
fired units, in particular between coal-fired EGUs (as well as oil- and
gas-fired steam EGUs) and NGCC units. In the shortterm--that is, over
time intervals shorter than the time required to build a new EGU--
fossil fuel-fired units consequently tend to compete more with one
another than with nuclear and renewable EGUs. The amount of re-dispatch
from coal-fired EGUs to NGCC units that takes place as a result of this
competition is highly relevant to overall power sector GHG emissions,
because a typical NGCC unit produces less than half as much
CO2 per MWh of electricity generated as a typical coal-fired
EGU.
    In order to estimate the potential magnitude of the opportunity to
reduce power sector CO2 emissions through re-dispatch among
existing EGUs, the EPA first examined information on the design
capabilities and availability of NGCC units. This examination showed
that, although most NGCC units have historically been operated in
intermediate-duty roles for economic reasons, they are technically
capable of

operating in base-load roles at much higher annual utilization rates.
Average annual availability (that is, the percentage of annual hours
when an EGU is not in a forced or maintenance outage) for NGCC units in
the U.S. generally exceeds 85 percent, and can exceed 90 percent for
some groups.\125\
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    \125\ See, e.g., North American Electric Reliability Corp.,
2008-2012 Generating Unit Statistical Brochure--All Units Reporting,
http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx; Higher
Availability of Gas Turbine Combined Cycle, Power Engineering (Feb.
1, 2011), http://www.power-eng.com/articles/print/volume-115/issue-2/features/higher-availability-of-gas-turbine-combined-cycle.html.
---------------------------------------------------------------------------

    We also researched historical data to determine the utilization
rates that NGCC units have already been demonstrated capable of
sustaining. Over the last several years, EGU owners and grid operators
have engaged in considerable re-dispatch among various types of fossil
fuel-fired units relative to historical dispatch patterns, with NGCC
units increasing generation and many coal-fired EGUs reducing
generation. In fact, in April 2012, for the first time ever the total
quantity of electricity generated nationwide from natural gas was
approximately equal to the total quantity of electricity generated
nationwide from coal.\126\ These changes in generation patterns have
been driven largely by changes over time in the relative prices of
natural gas and coal, in addition to lower overall demand for
electricity. Although the relative fuel prices vary by location, as do
the recent patterns of re-dispatch, this trend holds across broad
regions of the U.S. In the aggregate, the historical data provide ample
evidence indicating that, on average, existing NGCC units can achieve
and sustain utilization rates higher than their present utilization
rates.
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    \126\ Today in Energy, EIA (June 6, 2012) (http://www.eia.gov/todayinenergy/detail.cfm?id=6990).
---------------------------------------------------------------------------

    The experience of relatively heavily used NGCC units provides an
additional indication of the degree of increase in average NGCC unit
utilization that is technically feasible. According to the historical
NGCC unit utilization rate data reported to the EPA, in 2012 roughly 10
percent of existing NGCC units operated at annual utilization rates of
70 percent or higher.\127\ In effect, these units were being dispatched
to provide base-load power. In addition to the 10 percent of NGCC units
that operated at a 70 percent utilization rate on an annual basis, some
NGCC units operated at high utilization rates for shorter, but still
sustained, periods of time in response to high cyclical demand. For
example, on a seasonal basis, a significant number of NGCC units have
achieved utilization rates between 50 and 80 percent; over the 2012
winter season (December 2011-February 2012) and summer season (June-
August 2012), about 16 percent and 19 percent of NGCC units,
respectively, operated at utilization rates of 70 percent or more
across these entire seasons.\128\ During the spring and fall periods
when electricity demand levels are typically lower, these units were
sometimes idled or operated at much lower capacity factors.
Nonetheless, the data clearly demonstrate that a substantial number of
existing NGCC units have proven the ability to sustain 70 percent
utilization rates for extended periods of time. We view this as strong
evidence that increasing the utilization rates of existing NGCC units
to 70 percent, not in every individual instance but on average, as part
of a comprehensive approach to reducing CO2 emissions from
existing high carbon-intensity EGUs, would be technically feasible.
---------------------------------------------------------------------------

    \127\ The corresponding percentages of NGCC units that in 2012
operated at annual utilization rates of at least 65 percent and at
least 75 percent were 16 percent and 6 percent, respectively.
    \128\ Air Markets Program Data (at http://ampd.epa.gov/ampd/).
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    For purposes of establishing state goals, historical (2012)
electric generation data are used to apply each building block and
develop each state's goal (expressed as an adjusted CO2
emission rate in lbs per MWh).\129\ In 2012, total electric generation
from existing NGCC units was 959 TWh.\130\ After the application of
NGCC re-dispatch toward a 70 percent target utilization rate, the total
generation from these existing sources is projected to be 1,390 TWh per
year. Adding in the NGCC units that had commenced construction before
January 8, 2014 (and are therefore existing sources for purposes of
this proposal) but were not yet in operation in 2012 increases the
projected total generation from the full set of existing NGCC units to
1,443 TWh per year.
---------------------------------------------------------------------------

    \129\ See Section VII for further explanation of how goals were
computed.
    \130\ For covered sources.
---------------------------------------------------------------------------

    Although producing over 1,400 TWh of generation in 2020 from
existing NGCC units is not actually required, because states may choose
other abatement measures to reach the state goals, the EPA nevertheless
believes that producing this quantity of generation from this set of
NGCC units is feasible. As a reference point, NGCC generation increased
by approximately 430 TWh (an 80 percent increase) between 2005 and
2012. The EPA calculates that NGCC generation in 2020 could increase by
approximately 50 percent from today's levels. This reflects a smaller
ramp-up rate in NGCC generation than has been observed from 2005 to
2012. We also expect an increase in NGCC generation of this amount
would not impair power system reliability. As we note in the TSD on
Resource Adequacy and Reliability, the level of potential re-dispatch
can be accommodated within the flexible compliance requirements of the
rule. Similar conclusions have been reached in recent studies of the
potential impact of emission reductions from existing power
plants.\131\
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    \131\ See Greenhouse Gas Emission Reductions From Existing Power
Plants: Options to Ensure Electric System Reliability (Analysis
Group, Inc., May 2014). Also see the Resource Adequacy Technical
Support Document.
---------------------------------------------------------------------------

    The EPA also examined the technical capability of the natural gas
supply and delivery system to provide increased quantities of natural
gas and the capability of the electricity transmission system to
accommodate shifting generation patterns. For several reasons, we
conclude that these systems would be capable of supporting the degree
of increased NGCC utilization needed for states to achieve the proposed
goals. First, the natural gas pipeline system is already supporting
national average NGCC utilization rates of 60 percent or higher during
peak hours, which are the hours when constraints on pipelines or
electricity transmission networks are most likely to arise. NGCC unit
utilization rates during the range of peak daytime hours from 10 a.m.
to 9 p.m. are typically 15 to 20 percentage points above their average
utilization rates (which have recently been in the range of 40 to 50
percent).\132\ Fleet-wide combined-cycle average monthly utilization
rates have reached 65 percent,\133\ showing that the pipeline system
can currently support these rates for an extended period. If the
current pipeline and transmission systems allow these utilization rates
to be achieved in peak hours and for extended periods, it is reasonable
to expect that similar utilization rates should also be possible in
other hours when constraints are typically less severe, and be reliably
sustained for other months of the year. The second consideration
supporting our view that natural gas and electricity system

infrastructure would be capable of supporting increased NGCC unit
utilization rates is the flexibility of the emission guidelines. The
state goals do not require any particular NGCC unit utilization rate to
be achieved in any hour or year of the initial plan period. Thus, even
if isolated natural gas or electricity system constraints were to limit
NGCC unit utilization rates in certain locations in certain hours, this
would not prevent an increase in NGCC generation overall across a state
or broader region and across all hours. The third consideration
supporting a conclusion regarding the adequacy of the infrastructure is
that pipeline and transmission planners have repeatedly demonstrated
the ability to methodically relieve bottlenecks and expand
capacity.\134\ Natural gas pipeline capacity has regularly been added
in response to increased gas demand and supply, such as the addition of
large amounts of new NGCC capacity from 2001 to 2003, or the delivery
to market of unconventional gas supplies since 2008. These pipeline
capacity increases have added significant deliverability to the natural
gas pipeline network to meet the potential demands from increased use
of existing NGCC units. Over a longer time period, much more
significant pipeline expansion is possible. In previous studies, when
the pipeline system was expected to face very large demands for natural
gas use by electric utilities about ten years ago, increases of up to
30 percent in total deliverability out of the pipeline system were
judged to be possible by the pipeline industry.\135\ There have been
notable pipeline capacity expansions over the past five years, and
substantial additional pipeline expansions are currently under
construction.\136\ Similarly, the electric transmission system is
undergoing substantial expansion.\137\ Further, as discussed below in
Sections VII.D and VIII of this preamble (on state flexibilities and
state plans, respectively), we believe the flexible nature of the
proposed goals provides time for infrastructure improvements to occur
should they prove necessary in some locations.\138\ Combining these
factors of currently observed average monthly NGCC utilization rates of
up to 65 percent, the flexibility of the emission guidelines, and the
availability of time to address any existing infrastructure
limitations, it is reasonable to conclude that the natural gas pipeline
system can reliably deliver sufficient natural gas supplies, and the
electric transmission system can reliably accommodate changed
generation patterns, to allow NGCC utilization to increase up to an
average annual utilization rate of 70 percent.
---------------------------------------------------------------------------

    \132\ EIA, Average utilization of the nation's natural gas
combined-cycle power plant fleet is rising, Today in Energy, July
9,2011, http://www.eia.gov/todayinenergy/detail.cfm?id=1730#; EIA,
Today in Energy, Jan. 15, 2014, http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent data).
    \133\ EIA, Electric Power Monthly, February, 2014. Table 6.7.A.
    \134\ See, e.g., EIA, Natural Gas Pipeline Additions in 2011,
Today in Energy; INGAA Foundation, Pipeline and Storage
Infrastructure Requirements for a 30 Tcf Market (2004 update); INGAA
Foundation, North American Midstream Infrastructure Through 2035--A
Secure Energy Future Report (2011).
    \135\ Pipeline and Storage Infrastructure Requirements for a 30
Tcf Market, INGAA Foundation, 1999 (Updated July, 2004); U.S. gas
groups confident of 30-tcf market, Oil and Gas Journal, 1999.
    \136\ For example, between 2010 and April 2014, 118 pipeline
projects with 44,107 MMcf/day of capacity (4,699 miles of pipe) were
placed in service, and between April 2014 and 2016 an additional 47
pipeline projects with 20,505 MMcf/day of capacity (1,567 miles of
pipe) are scheduled for completion. Energy Information
Administration, http://www.eia.gov/naturalgas/data.cfm.
    \137\ According to the Edison Electric Institute, member
companies are planning over 170 projects through 2024, with costs
totaling approximately $60.6 billion (this is only a portion of the
total transmission investment anticipated). Approxi- mately 75
percent of the reported projects (over 13,000 line miles) are high
voltage (345 kV and higher). http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_Project_lowres_bookmarked.pdf.
    \138\ See Section VII.D and Section VIII below for discussion of
timing flexibility.
---------------------------------------------------------------------------

    We recognize that re-dispatch does contemplate an associated
increase in natural gas production, consistent with the current trends
in the natural gas industry. The EPA expects the growth in NGCC
generation assumed in goal-setting to be feasible and consistent with
domestic natural supplies. Increases in the natural gas resource base
have led to fundamental changes in the outlook for natural gas. There
is general agreement that recoverable natural gas resources will be
substantially higher for the foreseeable future than previously
anticipated, exerting downward pressure on natural gas prices.
According to EIA, proven natural gas reserves have doubled between 2000
and 2012. Domestic production has increased by 32 percent over that
same timeframe (from 19.2 TCF in 2000 to 25.3 TCF in 2012). EIA's
Annual Energy Outlook for 2014 projects that production will further
increase to 29.1 TCF, as a result of increased supplies and favorable
market conditions. For comparison, NGCC generation growth of 450 TWh
(calculated in goal setting) would result in increased gas consumption
of roughly 3.5 TCF for the electricity sector, which is less than the
projected increase in natural gas production.
    The EPA notes that the assessments described above regarding the
ability of the electricity and natural gas industries to achieve the
levels of performance indicated for building block 2 in the state goal
computations are supported by analysis that has been conducted using
the Integrated Planning Model (IPM). IPM is a multi-regional, dynamic,
deterministic linear programming model of the U.S. electric power
sector that the EPA has used for over two decades to evaluate the
economic and emission impacts of prospective environmental policies. To
fulfill its purpose of producing projections related to the electric
power sector and its related markets--including least-cost capacity
expansion and electricity dispatch projections--that reflect industry
conditions in as realistic a manner as possible, IPM incorporates
representations of constraints related to fuel supply, transmission,
and unit dispatch. The model includes a detailed representation of the
natural gas pipeline network and the capability to project economic
expansion of the network based on pipeline load factors. At the EGU
level, IPM includes detailed representations of key operational
limitations such as turn-down constraints, which are designed to
account for the cycling capabilities of EGUs to ensure that the model
properly reflects the distinct operating characteristics of peaking,
cycling, and base load units.
    As described in more detail below, the EPA used IPM to assess the
costs of requiring increasing levels of re-dispatch from higher- to
lower-emitting EGUs, and to that end, the EPA developed a series of
modeling scenarios that explored shifting generation from existing
coal-fired EGUs to existing NGCC units on a 1:1 basis within defined
areas.\139\ By the nature of IPM's design, those scenarios necessarily
also require compliance with the constraints just described (as
implemented for any specific scenario). IPM was able to arrive at a
solution for scenarios reflecting average NGCC utilization rates of 65,
70, and 75 percent, while observing the market, technical, and
regulatory constraints embedded in the model. Such a result is
consistent with the EPA's determination that increasing the utilization
rates of existing NGCC units to 70 percent, not in every individual
instance but on average, as part of a comprehensive approach to
reducing CO2 emissions from existing high carbon-intensity
EGUs, would be technically feasible.
---------------------------------------------------------------------------

    \139\ See Chapter 3 of the Regulatory Impact Analysis for more
detail.
---------------------------------------------------------------------------

c. Cost of Re-Dispatch
    Having established the technical feasibility and quantification of
replacing incremental generation at

higher-emitting EGUs with generation at NGCC facilities as a
CO2 emissions reduction strategy, we next turn to the
question of cost. The cost of the power sector CO2 emission
reductions that can be achieved through re-dispatch among existing
fossil fuel-fired EGUs depends on the relative variable costs of
electricity production at EGUs with different degrees of carbon
intensity. These variable costs are driven by the EGUs' respective fuel
costs and by the efficiencies with which they can convert fuel to
electricity (i.e., their heat rates). Historically, natural gas has had
a higher cost per unit of energy content (e.g., MMBtu) than coal in
most locations, but for NGCC units this disadvantage in fuel cost per
MMBtu relative to coal-fired EGUs is typically offset in significant
part, and sometimes completely, by a heat rate advantage.
    The EPA has conducted two sets of extensive analyses to help inform
the development of the state-specific emission goals described in this
proposal, including analyses of the opportunity to reduce
CO2 emissions through re-dispatch. The first set was a
dispatch-only set that provided a framework for understanding the
broader economic and emissions implications of shifting generation to
NGCC units from more carbon-intensive EGUs without consideration of
emission reduction measures reflected in the other building blocks. The
second set included additional refinements and more closely reflected
all the characteristics of the proposed goals that were used as the
basis for assessing the costs and benefits of the overall
proposal.\140\ Both sets of analyses were conducted using IPM.
---------------------------------------------------------------------------

    \140\ See Regulatory Impact Analysis for more detail.
---------------------------------------------------------------------------

    The first set--the dispatch-only analyses--explored the magnitude
and cost of potential opportunities to shift generation from existing
coal-fired EGUs to existing NGCC units within defined areas. The
purpose of analyzing these scenarios was to understand and demonstrate
to what extent existing NGCC units could increase their dispatch at
reasonable costs and without significant impacts on other economic
variables such as the prices of natural gas and electricity. To
evaluate how EGU owners and grid operators could respond to a state
plan's possible requirements, signals, or incentives to re-dispatch
from more carbon-intensive to less carbon-intensive EGUs, the EPA
analyzed a series of scenarios in which the fleet of NGCC units
nationwide was required, on average, to achieve a specified annual
utilization rate.\141\ Specifically, the scenarios required average
NGCC unit utilization rates of at least 65, 70, and 75 percent,
respectively. For each scenario, we identified the set of dispatch
decisions that would meet electricity demand at the lowest total cost,
subject to all other specified operating and reliability constraints
for the scenario, including the specified average NGCC unit utilization
rate. Further, we allowed re-dispatch to occur exclusively within a
region's existing fleet.\142\
---------------------------------------------------------------------------

    \141\ The utilization rate constraint applied on average to all
NGCC units nationwide and did not apply to individual NGCC units or
to the fleets of NGCC units within individual states.
    \142\ To best reflect the integrated nature of the electric
power sector, the EPA defined six regions for this analysis, the
borders of which are informed by North American Electric Reliability
(NERC) regions and Regional Transmission Organizations (RTOs). See
Chapter 3 of the Regulatory Impact Analysis for more detail.
---------------------------------------------------------------------------

    The costs and economic impacts of the various scenarios were
evaluated by comparing the total costs and emissions from each scenario
to the costs and emissions from a business-as-usual scenario. For the
scenario reflecting a 70 percent NGCC utilization rate, comparison to
the business-as-usual case indicates that the average cost of the
CO2 reductions achieved over the 2020-2029 period was $30
per metric ton of CO2.\143\ We view these estimated costs as
reasonable and therefore as supporting the use of a 70 percent
utilization rate target for purposes of quantifying the emission
reductions achievable at a reasonable cost through the application of
the BSER.
---------------------------------------------------------------------------

    \143\ The analogous costs for the scenarios with 65 and 75
percent NGCC utilization rates were $21 and $40 per metric ton of
CO2, respectively. For further detail on cost
methodology, data inputs, and results, refer to Chapter 3 of the GHG
Abatement Measures TSD.
---------------------------------------------------------------------------

    However, we also note that the costs just described are higher than
we would expect to actually occur in real-world compliance with this
proposal's goals. One reason for this is that the 70 percent
utilization rate in the scenario exaggerates the stringency with which
building block 2 is actually reflected in each of the state goals:
While the goal computation procedure uses 70 percent as a target NGCC
utilization rate for all states, for only 29 states do the goals
actually reflect reaching that target NGCC utilization, with the result
that the average NGCC utilization rate reflected in the computed state
goals is only 64 percent.\144\ Also, at least some states may be able
to achieve additional emission reductions through other components of
the BSER, and those other components may be relatively inexpensive. The
dispatch-only analyses were focused on evaluating the potential impacts
of re-dispatch in particular, and as a result, they reflect an
assumption that even in a state where re-dispatch might be relatively
expensive compared to other available CO2 emission reduction
measures that are part of the BSER, the state plan would rely on re-
dispatch to the same extent as the plans of other states. In practice,
under these circumstances, states would have flexibility to choose
among alternative CO2 reduction strategies that were part of
the BSER, instead of relying on re-dispatch to the maximum extent.
---------------------------------------------------------------------------

    \144\ For further explanation of the state goal computation
methodology, see Section VII of the preamble and the Goal
Computation TSD.
---------------------------------------------------------------------------

    The EPA also analyzed dispatch-only scenarios where shifting of
generation among EGUs was limited by state boundaries. In these
scenarios with less re-dispatch flexibility, the cost of achieving the
quantity of CO2 reductions corresponding to a nationwide
average NGCC unit utilization of 70 percent was $33 per metric ton.
Combining the results of the modeling with the factors likely to be
present in the real world reinforces the support we expressed above for
the 70 percent utilization rate. We remain concerned, however, that
higher NGCC utilization rates could be harder to sustain and could
exert further upward pressure on prices.
    We invite comment on whether the regional or state scenarios should
be given greater weight in establishing the appropriate degree of re-
dispatch to incorporate into the state goals for CO2
emission reductions, and in assessing costs.
    We also conclude from our analyses that the extent of re-dispatch
estimated in this building block can be achieved without causing
significant economic impacts. For example, in both of the 70 percent
NGCC unit utilization rate scenarios--with re-dispatch limited to
regional and state boundaries, respectively--delivered natural gas
prices were projected to increase by an average of no more than ten
percent over the 2020-2029 period, which is well within the range of
historical natural gas price variability.\145\ Projected wholesale
electricity price increases over the same period were less than seven
percent in both cases, which similarly is well within the range of
historical electric price variability.\146\

We view these projected impacts as not unreasonable and as supporting
use of a 70 percent NGCC utilization rate target for purposes of
quantifying the emission reductions achievable through application of
the BSER.
---------------------------------------------------------------------------

    \145\ According to EIA data, year-to-year changes in natural gas
prices at Henry Hub averaged 29.9 percent over the period from 2000
to 2013.  http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm.
    \146\ For example, year-on-year changes in PJM wholesale
electricity prices averaged 19.5 percent over the period from 2000
to 2013. Ventyx Velocity Suite, ISO real-time data for all hours.
Price variability for other eastern ISO regions (NYISO, ISO-NE., and
Midcontinent ISO) was similar. Id.
---------------------------------------------------------------------------

    However, for the same reasons discussed above with respect to
estimated costs per ton of CO2, in actual implementation we
again expect that the economic impacts shown in these scenarios,
including natural gas price impacts, are likely overstated compared to
the impacts that would actually occur in real-world compliance with
this rule's proposed goals. Consistent with this expectation, the
comprehensive analyses used to assess the compliance costs and benefits
of this proposal, which reflect a more complete representation of the
additional flexibility available to states, show significantly smaller
economic impacts. These analyses are discussed in Section X below.
    Based on the analyses summarized above, the EPA proposes that for
purposes of establishing state goals, a reasonable estimate regarding
the degree of mass emission reductions achievable at fossil fuel-fired
steam EGUs can be determined based on the degree to which electricity
generation could be shifted from more carbon-intensive EGUs to less
carbon-intensive EGUs within the state at reasonable cost through re-
dispatch. The increment of emission reductions incorporated in this
component of our proposed BSER determination is commensurate with an
annual utilization rate for the state's NGCC units of up to 70 percent,
on average across all the NGCC units in the state.
    For purposes of the alternative set of goals on which we are
seeking comment, we have used the less stringent target of a 65 percent
average utilization rate for NGCC units. In 2012, approximately 16
percent of existing NGCC plants larger than 25 megawatts had
utilization rates equal to or higher than this level. Also, as noted
earlier, average NGCC utilization nationwide is already over 60 percent
in some peak hours. We therefore view 65 percent as a reasonable lower-
bound estimate of an achievable average NGCC utilization rate, and we
would expect the costs and economic impacts from re-dispatch associated
with a 65 percent NGCC utilization target to be lower than the costs
and impacts associated with the 70 percent utilization target. Our cost
analysis indicated that CO2 emission reductions consistent
with a 65 percent average NGCC utilization rate could be achieved at a
cost of $21 per metric ton.
    As discussed above, in addition to analyzing the impacts of using
the proposed 70 percent target utilization rate for existing NGCC
units, the EPA has also performed preliminary analysis of the impacts
of using a target utilization rate for existing NGCC units of 75
percent. That analysis showed that CO2 emission reductions
consistent with a 75 percent target utilization rate could be achieved
at a cost of $40 per metric ton.\147\ We invite comment on whether we
should consider options for a target utilization rate for existing NGCC
units greater than the proposed 70 percent target utilization rate.
---------------------------------------------------------------------------

    \147\ For further analysis related to the use of a 75 percent
target utilization rate for NGCC units, see chapter 3 of the GHG
Abatement Measures TSD.
---------------------------------------------------------------------------

    We invite comment on these proposed findings and on all other
issues raised by the discussion above and the related portions of the
Greenhouse Gas Abatement Measures TSD.
3. Building Block 3--Using an Expanded Amount of Less Carbon-Intensive
Generating Capacity
    The third element of the foundation for the EPA's BSER
determination for reducing CO2 emissions at affected fossil
fuel-fired EGUs also goes to the achievement of reductions in mass
emissions, but in this case the reductions would occur at all affected
EGUs, and entails an analysis of the extent to which generation at the
affected EGUs can be replaced by using an expanded amount of lower-
carbon generating capacity to produce replacement generation. Below we
discuss two types of generating capacity that can play this role:
Renewable generating capacity and new and preserved nuclear capacity.
a. Renewable Generating Capacity
    Renewable electricity (RE) generating technologies are a well-
established part of the U.S. power sector. In 2012, electricity
generated from renewable technologies, including conventional
hydropower, represented 12 percent of total U.S. electricity
generation, up from 9 percent in 2005. More than half the states have
established renewable portfolio standards (RPS) that require minimum
proportions of electricity sales to be supplied with generation from
renewable generating resources.\148\ Production of this renewable
generation replaces predominantly fossil fuel-fired generation and
thereby avoids the CO2 emissions from that replaced
generation. The EPA believes that renewable electricity generation is a
proven way to assure reductions of CO2 emissions at affected
EGUs at a reasonable cost.\149\
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    \148\ Database of State Incentives for Renewables & Efficiency
(DSIRE), http://www.dsireusa.org/summarymaps/index.cfm?ee=0&RE=0.
    \149\ For discussion of how states and sources might use RE in
state plans, see Section VIII below.
---------------------------------------------------------------------------

1. Proposed Quantification of Renewable Energy Generation
    To estimate the CO2 emission reductions from affected
EGUs achievable based on increases in renewable generation, the EPA has
developed a ``best practices'' scenario for renewable energy generation
based on the RPS requirements already established by a majority of
states. The EPA views the existing RPS requirements as a reasonable
foundation upon which to develop such a scenario for two principal
reasons. First, in establishing the requirements, states have already
had the opportunity to assess those requirements against a range of
policy objectives including both feasibility and costs. These prior
state assessments therefore support the feasibility and cost of the
best practices scenario as well. Second, renewable resource development
potential varies by region, and the RPS requirements developed by the
states necessarily reflect consideration of the states' own respective
regional contexts.\150\
---------------------------------------------------------------------------

    \150\ The EPA recognizes that individual RPS policies vary in
their specification of where qualifying RE generation must occur.
However, the EPA believes the regional structure of this estimation
exercise supports a broad interpretation of RPS requirements across
states within a region as a proxy for reasonable-cost RE generation
potential within the same region.
---------------------------------------------------------------------------

    The EPA has not assumed any specific type of renewable generating
technology for the best practices scenario. Also, the scenario is not
an EPA forecast of renewable capacity development and neither
establishes RPS requirements that any state must meet nor makes any
determinations regarding allowable RE compliance measures. Rather, it
represents a level of renewable resource development for individual
states--with recognition of regional differences--that we view as
reasonable and consistent with policies that a majority of states have
already adopted based on their own policy objectives and assessments of
feasibility and cost.
    As noted above, renewable resource potential varies regionally.
This geographic pattern is reflected in the existing RPS requirements
of the various states. Recognizing this pattern, the EPA has grouped
the states into six regions for purposes of developing the best

practices scenario.\151\ By comparing each state to a set of neighbors
rather than to a single national standard, we are able to take regional
variation into account while still maintaining a level of rigor for the
scenario's targets. The regional structure is informed by North
American Electric Reliability Corporation (NERC) regions and Regional
Transmission Organizations (RTOs), with adjustments to align regional
borders with state borders and to group Florida and Texas with
neighboring states.\152\ This structure accounts for similar power
system characteristics as well as geographic similarities in RE
potential. The grouping of states into the six regions is shown in
Table 5 below.
---------------------------------------------------------------------------

    \151\ Given their unique locations, Alaska and Hawaii are not
grouped with other states into these regions. As a conservative
approach to estimating RE generation potential in Alaska and Hawaii,
the EPA has developed RE generation targets for each of those states
based on the lowest values for the six regions evaluated here.
    \152\ The regions are the same as those used in regional
modeling of this rule; see the Regulatory Impact Analysis for more
information on the regional modeling.

                         Table 5--Regions for Development of Best Practices RPS Scenario
----------------------------------------------------------------------------------------------------------------
                         Region                                                   States
----------------------------------------------------------------------------------------------------------------
East Central...........................................  Delaware, District of Columbia*, Maryland, New Jersey,
                                                          Ohio, Pennsylvania, Virginia, West Virginia.
North Central..........................................  Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri,
                                                          North Dakota, South Dakota, Wisconsin.
Northeast..............................................  Connecticut, Maine, Massachusetts, New Hampshire, New
                                                          York, Rhode Island, Vermont*.
South Central..........................................  Arkansas, Kansas, Louisiana, Nebraska, Oklahoma, Texas.
Southeast..............................................  Alabama, Florida, Georgia, Kentucky, Mississippi, North
                                                          Carolina, South Carolina, Tennessee.
West...................................................  Arizona, California, Colorado, Idaho, Montana, Nevada,
                                                          New Mexico, Oregon, Utah, Washington, Wyoming.
----------------------------------------------------------------------------------------------------------------
* Because Vermont and the District of Columbia lack affected sources, no goals are being proposed for these
  jurisdictions.

    The best practices scenario for each state consists of increasing
annual levels of RE generation estimated based on application of an
annual RE growth factor to the state's historical RE generation,
subject to a maximum RE generation target. The annual RE growth factors
and maximum RE generation targets were developed separately for each of
the six regions. Our procedure for determining these elements is
described in the Greenhouse Gas Abatement Measures TSD and summarized
below.
    The EPA first quantified the amount of renewable generation in 2012
in each state. The EPA then summed these amounts for all states in each
region to determine a regional starting level of renewable generation
prior to implementation of the best practices scenario. Hydropower
generation is excluded from this existing 2012 generation for purposes
of quantifying BSER-related RE generation potential because building
the methodology from a baseline that includes large amounts of existing
hydropower generation could distort regional targets that are later
applied to states lacking that existing hydropower capacity. The
exclusion of pre-existing hydropower generation from the baseline of
this target-setting framework does not prevent states from considering
incremental hydropower generation from existing facilities (or later-
built facilities) as an option for compliance with state goals.
    Next, the EPA estimated the aggregate target level of RE generation
in each of the six regions assuming that all states within each region
can achieve the RE performance represented by an average of RPS
requirements in states within that region that have adopted such
requirements. For this purpose, the EPA averaged the existing RPS
percentage requirements that will be applicable in 2020 and multiplied
that average percentage by the total 2012 generation for the region. We
also computed each state's maximum RE generation target in the best
practices scenario as its own 2012 generation multiplied by that
average percentage. (For some states that already have RPS requirements
in place, these amounts are less than their RPS targets for 2030.)
    For each region we then computed the regional growth factor
necessary to increase regional RE generation from the regional starting
level to the regional target through investment in new RE capacity,
assuming that the new investment begins in 2017, the year following the
initial state plan submission deadline,\153\ and continues through
2029. This regional growth factor is the growth factor used for each
state in that region to develop the best practices scenario.
---------------------------------------------------------------------------

    \153\ See Section VIII below for further discussion of timing
requirements for state plan submittals.
---------------------------------------------------------------------------

    Finally, we developed the annual RE generation levels for each
state. To do this, we applied the appropriate regional growth factor to
that state's initial RE generation level, starting in 2017, but
stopping at the point when additional growth would cause total RE
generation for the state to exceed the state's maximum RE generation
target. For computation of the proposed state goals discussed in
Section VII.C below, we used the annual amounts for the years 2020
through 2029. For computation of the alternate state goals discussed in
Section VII.E below, on which we are seeking comment, we used the
annual amounts for the years 2020 through 2024.
    Alaska and Hawaii are treated as separate regions. Their RE targets
are based on the lowest regional RE target among the continental U.S.
regions and their growth factors are based upon historical growth rates
in their own RE generation. We invite comment regarding the treatment
of Alaska and Hawaii as part of this method.
    For details on the regional targets and growth factors applied,
please refer to Chapter 4 of the GHG Abatement Measures TSD.
    The cumulative RE amounts for each state, represented as
percentages of total generation, are shown in Table 6.

                         Table 6--State RE Generation Levels for State Goal Development
                                     [Percentage of annual generation]\154\
----------------------------------------------------------------------------------------------------------------
                                                          Proposed goals                  Alternate goals
                                       2012      ---------------------------------------------------------------
              State                  (percent)    Interim  level   Final  level   Interim  level   Final  level
                                                   *  (percent)      (percent)     *  (percent)      (percent)
----------------------------------------------------------------------------------------------------------------
Alabama.........................               2               6               9               4               5
Alaska..........................               1               2               2               1               1
Arizona.........................               2               3               4               3               3
Arkansas........................               3               5               7               4               5
California......................              15              20              21              20              21
Colorado........................              12              19              21              17              19
Connecticut.....................               2               5               9               4               5
Delaware........................               2               7              12               4               5
Florida.........................               2               6              10               4               6
Georgia.........................               3               8              10               6               7
Hawaii..........................               9              10              10              10              10
Idaho...........................              16              21              21              21              21
Illinois........................               4               7               9               6               7
Indiana.........................               3               5               7               4               5
Iowa............................              25              15              15              15              15
Kansas..........................              12              19              20              19              20
Kentucky........................               0               1               2               1               1
Louisiana.......................               2               5               7               4               4
Maine...........................              28              25              25              25              25
Maryland........................               2              10              16               6               8
Massachusetts...................               5              15              24              11              13
Michigan........................               3               6               7               5               6
Minnesota.......................              18              15              15              15              15
Mississippi.....................               3               8              10               6               8
Missouri........................               1               2               3               2               2
Montana.........................               5               8              10               6               7
Nebraska........................               4               8              11               6               7
Nevada..........................               8              14              18              12              14
New Hampshire...................               7              19              25              15              19
New Jersey......................               2               8              16               5               7
New Mexico......................              11              18              21              16              18
New York........................               4              11              18               8              10
North Carolina..................               2               7              10               5               6
North Dakota....................              15              15              15              15              15
Ohio............................               1               6              11               4               5
Oklahoma........................              11              19              20              18              20
Oregon..........................              12              19              21              17              19
Pennsylvania....................               2               9              16               5               7
Rhode Island....................               1               4               6               3               3
South Carolina..................               2               7              10               5               6
South Dakota....................              24              15              15              15              15
Tennessee.......................               1               3               6               2               3
Texas...........................               8              16              20              13              15
Utah............................               3               5               7               4               5
Virginia........................               3              12              16               9              12
Washington......................               7              12              15              10              11
West Virginia...................               2               8              14               5               6
Wisconsin.......................               5               8              11               7               8
Wyoming.........................               9              15              19              13              14
----------------------------------------------------------------------------------------------------------------

    The EPA notes that for some states, the RE generation targets
developed using the proposed approach are less than those states'
reported RE generation amounts for 2012. We invite comment on whether
the approach for quantifying the RE generation component of each
state's goal should be modified to include a floor based on reported
2012 RE generation in that state.
---------------------------------------------------------------------------

    \154\ Vermont and the District of Columbia are excluded from
this table because we are not proposing goals for those
jurisdictions.
---------------------------------------------------------------------------

    This approach to quantification of a state's RE generation target
does not explicitly account for the amount of fossil fuel-fired
generation in that state. Without such an accounting, the application
of this approach could yield, for a given state, an increase in RE
generation that exceeds the state's reported 2012 fossil fuel-fired
generation.\155\ The EPA invites comment on whether this approach
should be modified so that the difference between a state's RE
generation target and its 2012 level of corresponding RE generation
does not exceed the state's

reported 2012 fossil fuel-fired generation.\156\
---------------------------------------------------------------------------

    \155\ In this proposed RE approach, this situation only occurs
with the RE targets quantified for the state of Washington.
    \156\ For example, for the state of Washington the proposed
approach yields a final RE generation target of 17.7 TWh,
representing an increase of 9.5 TWh over Washington's reported 2012
RE generation (excluding hydropower) of 8.2 TWh. By comparison,
Washington's 2012 reported fossil fuel-fired generation was 9.4 TWh.
(The 2012 reported RE and fossil fuel-fired generation amounts for
all states are included in the Goal Computation TSD.) If the
limitation described in the text were applied to Washington, the
state's incremental quantified RE generation would be limited to 9.4
TWh, with the result that the state's final RE generation target
would be 17.6 TWh instead of 17.7 TWh.
---------------------------------------------------------------------------

    We note that with the exception of hydropower, the RE generation
levels represent total amounts of RE generation, rather than
incremental amounts above a particular baseline level. As a result,
this RE generation can be supplied by any RE capacity regardless of its
date of installation. This approach is therefore focused on quantifying
the fulfillment of each state's potential for the deployment of RE as
part of BSER using a methodology that does not require discriminating
between RE capacity that was installed before or after any given date.
Under this approach, states in a given region where a higher proportion
of total generation has already been achieved from renewable resources
are assumed to have less opportunity for deployment of additional
renewable generation as part of the BSER framework informing state
goals, in comparison to states in that region where the proportion of
total generation achieved from renewable resources to date has been
lower. That being said, the assumptions of RE generation used to
develop the state goals do not impose any specific RE generation
requirements on any state; they are only used to inform the
quantification of state goals to which states may respond with whatever
emission reduction measures are preferred.
    With regard to hydropower, we seek comment regarding whether to
include 2012 hydropower generation from each state in that state's
``best practices'' RE quantified under this approach, and whether and
how the EPA should consider year-to-year variability in hydropower
generation if such generation is included in the RE targets quantified
as part of BSER. Chapter 4 of the GHG Abatement Measures TSD presents
state RE targets both with and without the inclusion of each state's
2012 hydropower generation.
2. Cost of CO2 Emission Reductions From RE Generation
    The EPA believes that RE generation at the levels represented in
the best practices scenario can be achieved at reasonable costs.
According to an EPA analysis based on EIA levelized costs, the cost to
reduce emissions through RE ranges from $10 to $40 per metric ton of
CO2.\157\ Analysis of RE development in response to state
RPS policies also finds historical and projected costs of RPS-driven RE
deployment to be modest. One comparative analysis that ``synthesize[d]
and analyze[d] the results and methodologies of 28 distinct state or
utility-level RPS cost impact analyses'' projected the median change in
retail electricity price to be $0.0004 per kilowatt-hour (a 0.7 percent
increase), the median monthly bill impact to be between $0.13 and
$0.82, and the median CO2 reduction cost to be $3 per metric
ton.\158\ This finding has been confirmed with more recent RPS cost
data, including a report that determined 2010-2012 retail electricity
price impacts due to state RPS policies to be less than two percent,
with only two states experiencing price impacts of greater than three
percent.\159\ Additionally, the National Renewable Energy Laboratory
has projected low incremental costs for a range of scenarios reflecting
significant increases in RE penetration, including scenarios that
increase RE penetration to a range of 30 to 40 percent of national
generation, levels higher than those projected in our best practices
scenario.\160\
---------------------------------------------------------------------------

    \157\ This analysis is based upon EIA's AEO 2014 Estimated
Levelized Costs of Electricity for New Generation Sources, available
at http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
    \158\ Chen et al., ``Weighing the Costs and Benefits of State
Renewable Portfolio Standards: A Comparative Analysis of State-Level
Policy Impact Projections,'' Lawrence Berkeley National Laboratory,
March 2007, available at http://emp.lbl.gov/publications/weighing-costs-and-benefits-state-renewables-portfolio-standards-comparative-analysis-s.
    \159\ Galen Barbose, ``Renewables Portfolio Standards in the
United States: A Status Update,'' Lawrence Berkeley National Lab,
November 2013. Also to be published in Heeter et al., ``Estimating
the Costs and Benefits of Complying with Renewable Portfolio
Standards: Reviewing Experience to Date'' [review draft title].
UNPUBLISHED. National Renewable Energy Laboratory and Lawrence
Berkeley National Laboratory.
    \160\ NREL, ``Renewable Electricity Futures Study'', NREL/TP-
6A20-52409, 2012, http://www.nrel.gov/analysis/re_futures/.
---------------------------------------------------------------------------

    While RPS requirements will continue to grow over time, the EPA
does not expect this anticipated expansion to fall outside the
historical norms of deployment or to create unusual pressure for cost
increases. Full compliance with current RPS goals through 2035 would
require approximately 4 to 4.5 GW of new renewable capacity per year.
Average deployment of RPS-supported renewable capacity from 2007 to
2012 exceeded 6 GW per year.\161\ In addition, recent improvements in
RPS compliance rates indicate to the EPA the reasonableness of current
RPS growth trajectories. Weighted average compliance rates among all
states have improved in each of the past three reported years (2008-
2011) from 92.1 percent to 95.2 percent despite a 40 percent increase
in RPS obligations during this period.\162\
---------------------------------------------------------------------------

    \161\ Galen Barbose, ``Renewables Portfolio Standards in the
United States: A Status Update,'' Lawrence Berkeley National
Laboratory, November 2013.
    \162\ http://emp.lbl.gov/rps, retrieved March 2014. The RPS
compliance measure cited is inclusive of credit multipliers and
banked RECs utilized for compliance, but excludes alternative
compliance payments, borrowed RECs, deferred obligations, and excess
compliance. This estimate does not represent official compliance
statistics, which vary in methodology by state.
---------------------------------------------------------------------------

    We invite comment on this approach to treatment of renewable
generating capacity as a basis for the best system of emission
reduction adequately demonstrated and for quantification of state
goals.
3. Alternative Approach to Quantification of RE Generation
    Additionally, the EPA is soliciting comment on an alternative
approach to quantification of renewable generation to support the BSER.
Unlike the proposed RE scenario described above that relies on a
regional application of state RPS commitments, the alternative
methodology relies on a state-by-state assessment of RE technical and
market potential. The alternative approach is based on two sources of
information: A metric representing the degree to which the technical
potential of states to develop RE generation has already been realized,
and IPM modeling of RE deployment at the state level under a scenario
that reflects a reduced cost of building new renewable generating
capacity.
    The metric measuring realization of RE technical potential in a
state compares each state's existing renewable generation by technology
type with the technical potential for that technology in that state as
assessed by the National Renewable Energy Laboratory (NREL).\163\ This
comparison yields, for each state and for each RE technology, a
proportion of renewable generation technical potential that has been
achieved and can be represented as an RE development rate. For example,
if

a given state has 500 MWh of solar generation in 2012 while NREL
assesses that state's solar generation technical potential at 5,000
MWh/year, then that state's solar RE development rate would be ten
percent. The EPA then considers the range of RE development rates
across states in order to define a benchmark RE development rate for
each technology.
---------------------------------------------------------------------------

    \163\ Lopez et al., NREL, ``U.S. Renewable Energy Technical
Potentials: A GIS-Based Analysis,'' (July 2012).
---------------------------------------------------------------------------

    While a benchmark RE development rate offers a useful metric to
quantify the proportion of RE generation that would bring all states up
to a designated proportion of RE generation that has been achieved in
practice by certain states to date, such a metric does not explicitly
take into account the cost that would be faced to reach the benchmark
RE development rate in each state. In order to take this cost into
account, for this alternative approach the EPA has paired the benchmark
RE development rates described above with IPM modeling of RE deployment
at the state level, based on a scenario reflecting a reduced cost of
building new renewable generating capacity. The cost reduction for new
RE generating capacity is intended to represent the avoided cost of
other actions that could be taken instead to reduce CO2
emissions from the power sector. In the Alternative RE Approach TSD,
available in the docket, we show the RE deployment levels modeled using
a cost reduction of up to $30 per MWh, a level that is consistent with
the cost range of $10 to $40 per metric ton of avoided CO2
emissions estimated for the proposed RE scenario described above.\164\
---------------------------------------------------------------------------

    \164\ Additional detail regarding this modeling and approach is
provided in the Alternative RE Approach TSD.
---------------------------------------------------------------------------

    Under this alternative RE approach, the EPA would quantify RE
generation for each technology in each state as the lesser of (1) that
technology's benchmark rate multiplied by the technology's in-state
technical potential, or (2) the IPM-modeled market potential for that
specific technology. For example, if the benchmark RE development rate
for solar generation is determined to be 12 percent, and the
hypothetical state described above has a solar generation technical
potential of 5,000 MWh/year, then the benchmark RE development level of
generation for that state would be 600 MWh/year. If the IPM-modeled
market potential for solar generation in that state is 750 MWh/year,
then this approach would quantify solar generation for that state as
the benchmark RE development level (600 MWh/year) because it is the
lesser amount of those two measures.
    Having quantified an amount of RE generation from each RE
technology in each state, the EPA would then determine for each state a
total level of RE generation that equals the sum of the generation
quantified for each of the assessed RE technologies in that state. If
the EPA were to adopt this alternative approach for quantifying RE in
BSER, these total levels of RE generation for each state would be
incorporated in state goals in place of the RE generation levels
quantified using the proposed approach described above. Further
methodological detail and state-level RE targets for this alternative
approach are provided in the Alternative RE Approach TSD in the docket.
    We invite comment on this alternative approach to quantification of
RE generation to support the BSER. We note that the three specific
requests for comment made above with respect to the proposed
quantification approach--addressing, first, the possibility of a floor
based on 2012 RE generation, second, the possibility of a limitation
based on 2012 fossil fuel-fired generation and, third, the treatment of
hydropower generation--apply to this alternative approach as well.\165\
---------------------------------------------------------------------------

    \165\ The Alternative RE Approach TSD presents the
quantification of hydropower generation under the alternative
approach, as well as the resulting state RE targets both with and
without hydropower generation included.
---------------------------------------------------------------------------

    Finally, the EPA notes that the alternative RE approach described
above is one of a number of possible methodologies for using technical
and economic renewable energy potential to quantify RE generation for
purposes of state goals. The EPA invites comment on other possible
techno-economic approaches. For example, a conceptual framework for
another techno-economic approach is provided in the Alternative RE
Approach TSD.
b. New and Preserved Nuclear Capacity
    Nuclear generating capacity facilitates CO2 emission
reductions at fossil fuel-fired EGUs by providing carbon-free
generation that can replace generation at those EGUs. Because of their
relatively low variable operating costs, nuclear EGUs that are
available to operate typically are dispatched before fossil fuel-fired
EGUs. Increasing the amount of nuclear capacity relative to the amount
that would otherwise be available to operate is therefore a technically
viable approach to support reducing CO2 emissions from
affected fossil fuel-fired EGUs.
1. Proposed Quantification of Nuclear Generation
    One way to increase the amount of available nuclear capacity is to
build new nuclear EGUs. However, in addition to having low variable
operating costs, nuclear generating capacity is also relatively
expensive to build compared to other types of generating capacity, and
little new nuclear capacity has been constructed in the U.S. in recent
years; instead, most recent generating capacity additions have
consisted of NGCC or renewable capacity. Nevertheless, five nuclear
EGUs at three plants are currently under construction: Watts Bar 2 in
Tennessee, Vogtle 3-4 in Georgia, and Summer 2-3 in South Carolina. The
EPA believes that since the decisions to construct these units were
made prior to this proposal, it is reasonable to view the incremental
cost associated with the CO2 emission reductions available
from completion of these units as zero for purposes of setting states'
CO2 reduction goals (although the EPA acknowledges that the
planning for those units likely included consideration of the
possibility of future regulation of CO2 emissions from
EGUs). Completion of these units therefore represents an opportunity to
reduce CO2 emissions from affected fossil fuel-fired EGUs at
a very reasonable cost. For this reason, we are proposing that the
emission reductions achievable at affected sources based on the
generation provided at the identified nuclear units currently under
construction should be factored into the state goals for the respective
states where these new units are located. However, the EPA also
realizes that reflecting completion of these units in the goals has a
significant impact on the calculated goals for the states in which
these units are located. If one or more of the units were not completed
as projected, that could have a significant impact on the state's
ability to meet the goal. We therefore take comment on whether it is
appropriate to reflect completion of these units in the state goals and
on alternative ways of considering these units when setting state
goals.
    Another way to increase the amount of available nuclear capacity is
to preserve existing nuclear EGUs that might otherwise be retired. The
EPA is aware of six nuclear EGUs at five plants that have retired or
whose retirements have been announced since 2012: San Onofre Units 2-3
in California, Crystal River 3 in Florida, Kewaunee in Wisconsin,
Vermont Yankee in Vermont, and Oyster Creek in New Jersey. While each
retirement decision

is based on the unique circumstances of that individual unit, the EPA
recognizes that a host of factors--increasing fixed operation and
maintenance costs, relatively low wholesale electricity prices, and
additional capital investment associated with ensuring plant security
and emergency preparedness--have altered the outlook for the U.S.
nuclear fleet in recent years. Reflecting similar concern for these
challenges, EIA in its most recent Annual Energy Outlook has projected
an additional 5.7 GW of capacity reductions to the nuclear fleet. EIA
describes the projected capacity reductions--which are not tied to the
projected retirement of any specific unit--as necessary to recognize
the ``continued economic challenges'' faced by the higher-cost nuclear
units.\166\ Likewise, without making any judgment about the likelihood
that any individual EGU will retire, we view this 5.7 GW, which
comprises an approximately six percent share of nuclear capacity, as a
reasonable proxy for the amount of nuclear capacity at risk of
retirement.
---------------------------------------------------------------------------

    \166\ Jeffrey Jones and Michael Leff, EIA, ``Implications of
accelerated power plant retirements,'' (April 2014).
---------------------------------------------------------------------------

2. Cost of CO2 Emission Reductions From Nuclear Generation
    We have determined that, based on available information regarding
the cost and performance of the nuclear fleet, preserving the operation
of at-risk nuclear capacity would likely be capable of achieving
CO2 reductions from affected EGUs at a reasonable cost. For
example, retaining the estimated six percent of nuclear capacity that
is at risk for retirement could support avoiding 200 to 300 million
metric tons of CO2 over an initial compliance phase-in
period of ten years.\167\ According to a recent report, nuclear units
may be experiencing up to a $6/MWh shortfall in covering their
operating costs with electricity sales.\168\ Assuming that such a
revenue shortfall is representative of the incentive to retire at-risk
nuclear capacity, one can estimate the value of offsetting the revenue
loss at these at-risk nuclear units to be approximately $12 to $17 per
metric ton of CO2. The EPA views this cost as reasonable. We
therefore propose that the emission reductions supported by retaining
in operation six percent of each state's historical nuclear capacity
should be factored into the state goals for the respective states.\169\
---------------------------------------------------------------------------

    \167\ Assuming replacement power for at-risk nuclear capacity is
sourced from new NGCC capacity at 800 lbs/MWh or the power system at
1127 lbs CO2/MWh (average 2020 power sector emissions
intensity as projected in the EPA's IPM Base Case).
    \168\ ``Nuclear * * * The Middle Age Dilemma?'' Eggers, et al.,
Credit Suisse, February 2013.
    \169\ A state's historical nuclear fleet is defined as all units
in commercial operation as of May 2014 with no current plans to
retire.
---------------------------------------------------------------------------

    For purposes of goal computation, generation from under-
construction and preserved nuclear capacity is based on an estimated 90
percent average utilization rate for U.S. nuclear units, consistent
with long-term average annual utilization rates observed across the
nuclear fleet. The methodology for taking this generation into account
for purposes of setting state emission rate goals is described below in
Section VII on state goals and in the Goal Computation TSD.
    We invite comment on all aspects of the approach discussed above.
In addition, we specifically request comment on whether we should
include in the state goals an estimated amount of additional nuclear
capacity whose construction is sufficiently likely to merit evaluation
for potential inclusion in the goal-setting computation. If so, how
should we do so--for example, according to EGU owners' announcements,
the issuance of permits, projections of new construction by the EPA or
another government agency, or commercial projections? What specific
data sources should we consider for those permits or projections?
4. Building Block 4--Demand-Side Energy Efficiency
    The fourth element of the foundation for the EPA's BSER
determination for reducing CO2 emissions at affected fossil
fuel-fired EGUs also supports reduced mass emissions at all affected
EGUs, and entails an analysis of the extent to which generation
reductions at the affected EGUs can be supported by reducing the demand
for generation at those EGUs through measures that reduce the overall
quantity of generation demanded by end-users.\170\
---------------------------------------------------------------------------

    \170\ Electricity end-users and electricity end-use referred to
throughout this subsection include the residential, commercial and
industrial sectors.
---------------------------------------------------------------------------

a. Benefits of Demand-Side Energy Efficiency
    Reducing demand for generation at affected EGUs through policies to
improve demand-side energy efficiency is a proven basis for reducing
CO2 emissions at those EGUs. Every state has established
demand-side energy efficiency policies, and many stakeholders
emphasized the success of these policies in reducing electricity
consumption by large amounts. For example, data reported to the U.S.
Energy Information Administration (EIA) show that in 2012 California
and Minnesota avoided 12.5 percent and 13.1 percent of their
electricity demand, respectively, through their demand-side efficiency
programs.\171\ Additionally, multiple studies have found that
significant improvements in end-use energy efficiency can be realized
at less cost than the savings from avoided power system costs.\172\
Increased investment in demand-side energy efficiency is being
supported by efforts at the federal, state, and local levels of
government as well as corporate efforts. Many stakeholders urged the
inclusion of demand-side energy efficiency policies as compliance
options under the CAA section 111(d) guidelines.
---------------------------------------------------------------------------

    \171\ Energy Information Administration Form 861, 2012,
available at http://www.eia.gov/electricity/data/eia861/.
    \172\ See, e.g., Electric Power Research Institute, U.S. Energy
Efficiency Potential Through 2035 (Final Report, April 2014); Wang,
Yu and Marilyn A. Brown, Policy Drivers for Improving Electricity
End-Use Efficiency in the U.S.: An Economic-Engineering Analysis
(Energy Efficiency, 2014).
---------------------------------------------------------------------------

    By reducing electricity consumption, energy efficiency avoids
greenhouse gas emissions associated with electricity generation.
Because fossil fuel-fired EGUs typically have higher variable costs
than other EGUs (such as nuclear and renewable EGUs), their generation
is typically the first to be replaced when demand is reduced.
Consequently, reductions in the utilization of fossil fuel-fired EGUs
can be supported by reducing electricity consumption and, by the same
token, reductions in electricity consumption avoid the CO2
emissions associated with the avoided generation. In this manner, in
2011, state demand-side energy efficiency programs are estimated to
have reduced CO2 emissions by 75 million metric tons.\173\
And when integrated into a comprehensive approach for addressing
CO2 emissions, demand-side energy efficiency improvements
offer even more potential to improve the carbon profile of the
electricity supply system. For example, if incentives exist to shift
generation to lower carbon-intensity EGUs, and those EGUs are fully
utilized, reducing demand can support further reductions in carbon
intensity. This potential effect reinforces the appropriateness of
incorporating demand-side efficiency improvements into a comprehensive
approach to address power sector CO2 emissions. In addition,
by supporting reductions in fossil fuel usage at EGUs, demand-side

energy efficiency supports not only reduced CO2 emissions
and carbon intensity of the power sector, but also reduced criteria
pollutant emissions, cooling water intake and discharge, and solid
waste production associated with fossil fuel combustion. By reducing
electricity usage significantly, energy efficiency also commonly
reduces the bills of electricity customers.
---------------------------------------------------------------------------

    \173\ Innovation, Electricity, Efficiency (an Institute of the
Edison Foundation), Summary of Customer-Funded Electric Efficiency
Savings, Expenditures, and Budgets (2011-2012) (March 2013),
available at http://www.edisonfoundation.net/iei/ourwork/Pages/issuebriefs.aspx.
---------------------------------------------------------------------------

b. ``Best Practices'' for Demand-Side Energy Efficiency
    To estimate the potential CO2 reductions at affected
EGUs that could be supported by implementation of demand-side energy
efficiency policies as a part of state goals, the EPA developed a
``best practices'' demand-side energy efficiency scenario. This
scenario provides an estimate of the potential for sources and states
to implement policies that increase investment in demand-side energy
efficiency technologies and practices at reasonable costs. It does not
represent an EPA forecast of business-as-usual impacts of state energy
efficiency policies or an EPA estimate of the full potential of end-use
energy efficiency available to the power system, but rather represents
a feasible policy scenario showing the reductions in fossil fuel-fired
electricity generation resulting from accelerated use of energy
efficiency policies in all states consistent with a level of
performance that has already been achieved or required by policies
(e.g., energy efficiency resource standards) of the leading states. The
data and methodology used to develop the best practices scenario are
summarized below.
    We have not assumed any particular type of demand-side energy
efficiency policy. States with leading energy efficiency performance
have employed a variety of strategies that are implemented by a range
of entities including investor-owned, municipal and cooperative
electric utilities as well as state agencies and third-party
administrators. These include energy efficiency programs,\174\ building
energy codes, state appliance standards (for appliances without federal
standards), tax credits, and benchmarking requirements for building
energy use.\175\ Energy efficiency policies are designed to accelerate
the deployment of demand-side energy efficiency technologies,
practices, and measures by addressing market barriers and market
failures that limit their adoption. Some states have adopted energy
efficiency resource standards \176\ (EERS) to drive investment in
energy efficiency programs; some have relied on other strategies; most
states are using multiple policy approaches. Based on historical data
on energy efficiency program savings and analysis of the requirements
of existing state energy efficiency policies, twelve leading states
have either achieved--or have established requirements that will lead
them to achieve--annual incremental savings rates of at least 1.5
percent of the electricity demand that would otherwise have
occurred.\177\ The 1.5 percent savings rate is inclusive of, not
additional to, existing state energy efficiency requirements. These
savings levels are realized exclusively through the adoption and
implementation of energy efficiency programs. The energy savings data
underpinning these analyses are derived from energy efficiency program
reports required by state public utility commissions and other entities
with a similar oversight role.\178\ These state commissions define and
oversee the analysis and reporting requirements for energy efficiency
programs as part of their role of overseeing rates for utility
customers in their states. One typical requirement is the application
of recognized evaluation, measurement, and validation (EM&V) protocols
that specify industry-preferred approaches and methodologies for
estimating savings from efficiency programs.\179\
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    \174\ Energy efficiency programs are driven by a variety of
state policies including energy efficiency resource standards,
requirements to acquire all cost-effective energy efficiency,
integrated resource planning requirements, and demand-side
management plans and budgets. Funding for energy efficiency programs
is provided through a variety of mechanisms as well, including per
kilowatt-hour surcharges and proceeds from forward capacity market
and emission allowance auctions. The programs are implemented by a
range of entities including investor-owned, municipal, and
cooperative electric utilities, state agencies, and designated
third-party administrators. All end-use sectors (residential,
commercial, and industrial) are targeted by energy efficiency
programs and numerous strategies are employed, including targeted
rebates for high-efficiency appliances; energy audits with
recommendations for cost-effective, energy-saving upgrades; and
processes to certify energy efficiency service providers.
    \175\ See the appendix to the State Plan Considerations TSD for
descriptions of the full array of demand-side energy efficiency
policies currently employed by states.
    \176\ EERS establish specific, long-term targets for energy
savings that utilities or non-utility program administrators must
meet through customer energy efficiency programs. EERS, as well as
requirements that utilities acquire all cost-effective energy
efficiency, have been the most impactful state energy efficiency
strategies in recent years.
    \177\ The historical data used are reported to the Energy
Information Administration through Form EIA-861. The analysis and
summary of state energy efficiency policies is from the American
Council for an Energy-Efficient Economy (ACEEE), State EERS Activity
Policy Brief (February 24, 2014). See the Greenhouse Gas Abatement
Measures TSD for more information.
    \178\ E.g., energy efficiency programs operated by municipal and
cooperative utilities may report their program results to their
Boards of Directors rather than to a state utility commission.
    \179\ See the EM&V section of the State Plan TSD for more
information on EE program evaluation.
---------------------------------------------------------------------------

    While EM&V data reflect documented electricity savings from energy
efficiency programs, they typically do not account for potential
electricity savings available from additional state-implemented
policies for which EM&V protocols are less consistently required or
applied, such as building energy codes. Thus, we consider the 1.5
percent annual incremental savings \180\ rate to be a reasonable
estimate of the energy efficiency policy performance that is already
achieved or required by leading states and that can be achieved at
reasonable costs by all states given adequate time. If we were to
capture the potential for additional policies, such as the adoption and
enforcement of state or local building energy codes, to contribute
additional reductions in electricity demand beyond those resulting from
energy efficiency programs, we could reasonably increase the targeted
annual incremental savings rate beyond 1.5 percent.
---------------------------------------------------------------------------

    \180\ This incremental savings rate and all others discussed in
this subsection represent net, rather than gross, energy savings.
Gross savings are the changes in energy use (MWh) that result
directly from program-related actions taken by program participants,
regardless of why they participated in a program. Net savings refer
to the changes in energy use that are directly attributable to a
particular energy efficiency program after accounting for free-
ridership, spillover, and other factors.
---------------------------------------------------------------------------

    For states where EE program experience is more limited, reaching a
best-practices level of performance requires undertaking a set of
activities that takes some time to plan, implement, and evaluate. For
the best practices scenario, we have therefore estimated that each
state's annual incremental savings rate increases from its 2012 annual
saving rate \181\ to a rate of 1.5 percent over a period of years
starting in 2017. (Thus, the goal for each state differs to reflect the
assumption that in a state already close to a 1.5 percent annual
incremental savings rate, energy efficiency programs can be expanded to
reach that rate sooner than in a state that is further from that rate.)
The pace at which states are estimated to increase their savings rate
level is 0.2 percent per year. This rate is consistent with past
performance and future requirements of leading states.\182\ For states
already at or above the 1.5 percent

annual incremental savings rate (based on 2012 reported data), we
estimate that they would realize a 1.5 percent rate in 2017 and
maintain that rate through 2029. For all states we assume the initial
savings rate (the lower of their 2012 value or 1.5 percent) is realized
in 2017 and increases each year by 0.2 percent until the target rate of
1.5 percent is achieved \183\ and is then maintained at that level
through 2029. The savings from energy efficiency programs are
cumulative, meaning that, in simplified terms, a state in which a
sustained program is implemented with a 1.5 percent annual incremental
savings rate could expect cumulative annual savings of approximately
1.5 percent after the first year, 3.0 percent after the second year,
4.5 percent after the third year, and so on. Savings from the first
year would drop off at the end of the average life of the energy
efficiency program portfolio (typically about ten years). Accordingly,
we have projected the cumulative annual savings for each state that
would be achieved for the period 2020 to 2029 based on the state's
reaching and then sustaining the best practices annual incremental
savings rate through 2029. These values, for each state and for each
year (2020-2029), are used in the procedure for computing the state
goals described in Section VII.C below.
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    \181\ 2012 is the most recent year for energy efficiency program
incremental savings data reported using EIA Form 861.
    \182\ See the Greenhouse Gas Abatement Measures TSD for more
information.
    \183\ For example, a state with a reported savings rate of 0.5%
in 2012 is assumed to realize a 2017 savings rate of 0.5% and their
savings rates for 2018, 2019, 2020, 2021 and 2022 are calculated to
be 0.7%, 0.9%, 1.1%, 1.3%, and 1.5%, respectively. By this method,
all states have reached the 1.5% target rate by 2017 at the earliest
and by 2025 at the latest.
---------------------------------------------------------------------------

    As discussed in Section VII.E below, the EPA is also taking comment
on a less stringent alternative for setting state goals. Under this
alternative, the demand-side energy efficiency requirement uses 1.0
percent (rather than 1.5 percent) annual incremental savings as
representative of the best-practices level of performance. In addition,
the pace at which incremental savings levels are increased from their
historical levels is relaxed slightly to 0.15 percent per year (rather
than 0.2 percent). The 1.0 percent rate of savings is a level of
performance that has been achieved--or that established state
requirements will cause to be achieved--by 20 states.\184\ As is done
with the more stringent goal-setting approach for energy efficiency,
the cumulative percentages for each state are derived and multiplied by
the state's 2012 historical electricity sales as reflected in the EIA
detailed state data, in this case for the period from 2020 to 2024.
---------------------------------------------------------------------------

    \184\ See the Greenhouse Gas Abatement Measures TSD for more
information.
---------------------------------------------------------------------------

    The state-specific cumulative annual electricity saving data inputs
for both the proposed approach and the less stringent alternative are
discussed in the Greenhouse Gas Abatement Measures TSD and summarized
in Table 7.

Table 7--Demand-Side Energy Efficiency State Goal Development: Cumulative Annual Electricity Savings (Percentage
                          of Annual Sales) Resulting From Best Practices Scenario \185\
----------------------------------------------------------------------------------------------------------------
                                                   1.5% Savings target scenario    1.0% Savings target scenario
                      State                      ---------------------------------------------------------------
                                                       2020            2029            2020            2024
----------------------------------------------------------------------------------------------------------------
Alabama.........................................             1.4             9.5             1.1             3.9
Alaska..........................................             1.2             9.5             0.9             3.7
Arizona.........................................             5.2            11.4             3.5             6.0
Arkansas........................................             1.5             9.7             1.2             4.1
California......................................             5.0            11.6             3.6             6.1
Colorado........................................             3.9            11.0             3.3             5.9
Connecticut.....................................             4.7            11.9             3.6             6.3
Delaware........................................             1.1             9.5             0.9             3.6
Florida.........................................             2.0            10.0             1.8             4.7
Georgia.........................................             1.8             9.8             1.5             4.4
Hawaii..........................................             1.3             9.5             1.0             3.8
Idaho...........................................             3.8            11.1             3.5             5.9
Illinois........................................             4.4            11.6             3.5             6.2
Indiana.........................................             3.2            11.1             2.9             5.7
Iowa............................................             4.7            11.7             3.6             6.0
Kansas..........................................             1.2             9.5             0.9             3.7
Kentucky........................................             1.9            10.0             1.6             4.6
Louisiana.......................................             1.1             9.3             0.9             3.6
Maine...........................................             5.4            12.1             3.6             6.3
Maryland........................................             4.2            11.5             3.5             6.1
Massachusetts...................................             4.4            11.8             3.6             6.2
Michigan........................................             4.6            11.8             3.6             6.2
Minnesota.......................................             4.8            11.7             3.6             6.2
Mississippi.....................................             1.4             9.6             1.1             3.9
Missouri........................................             1.6             9.9             1.3             4.2
Montana.........................................             3.4            10.9             3.0             5.7
Nebraska........................................             2.2            10.4             1.9             4.9
Nevada..........................................             3.0            10.7             2.7             5.5
New Hampshire...................................             2.8            11.0             2.6             5.5
New Jersey......................................             1.3             9.6             1.0             3.7
New Mexico......................................             3.1            10.6             2.8             5.5
New York........................................             4.4            11.8             3.5             6.2
North Carolina..................................             2.4            10.3             2.1             5.0
North Dakota....................................             1.4             9.7             1.1             4.0
Ohio............................................             4.2            11.6             3.5             6.1
Oklahoma........................................             1.9            10.0             1.6             4.5
Oregon..........................................             4.7            11.4             3.6             6.1
Pennsylvania....................................             4.7            11.7             3.6             6.2

Rhode Island....................................             3.9            11.6             3.4             6.1
South Carolina..................................             2.3            10.2             2.0             4.9
South Dakota....................................             1.6             9.9             1.3             4.2
Tennessee.......................................             2.2            10.3             1.9             4.9
Texas...........................................             1.8             9.9             1.5             4.4
Utah............................................             3.6            11.0             3.2             5.8
Virginia........................................             1.2             9.3             1.0             3.7
Washington......................................             4.2            11.3             3.5             6.0
West Virginia...................................             1.8            10.1             1.5             4.4
Wisconsin.......................................             4.7            11.8             3.6             6.2
Wyoming.........................................             1.6             9.7             1.3             4.2
----------------------------------------------------------------------------------------------------------------

c. Costs of Demand-Side Energy Efficiency
    The EPA expects implementation of demand-side energy efficiency
policies as reflected in the best practices scenario to be achievable
at reasonable costs. The EPA finds support for the reasonableness of
the costs of this building block from two perspectives. First, the
specific savings levels represented by this building block were
developed based upon the experience and success of states in developing
and implementing energy efficiency policies that they undertake
primarily for the purpose of providing economic benefits to electricity
consumers in their state. Secondly, even with notably conservative
assumptions about the costs of achieving the levels of electricity
savings associated with this building block, the EPA's analysis of the
power sector indicates that the costs are reasonable.
    The processes by which states develop funding for energy efficiency
programs typically require the application of cost-effectiveness tests
to ensure that adopted program portfolios lead to lower costs than the
use of generation sources that would otherwise be required to meet the
associated electricity service demands. Indeed, a major reason for the
widespread presence and rapid growth of demand-side energy efficiency
programs is the strong evidence of the reasonableness of their costs
even before the additional benefit of CO2 reductions is
considered.\186\ Independent studies have found that end-users' needs
for energy-dependent services (e.g., heating, cooling, lighting, motor
output, and information and entertainment services) frequently can be
satisfied at lower cost by improving the efficiency of electricity
consumption rather than by increasing the supply of electricity.\187\
These factors indicate that the cost of CO2 reductions
achieved through implementation of demand-side energy efficiency at the
levels reflected in the best practices scenario are likely to be very
reasonable, typically resulting in reductions in average electricity
bills across all end-use sectors.\188\ Because demand-side energy
efficiency costs are incurred at the time of investment, while the cost
savings (from lower electricity usage) are realized over the life of
these investments (typically about 10 years), bill reductions are
greater in later years, but provide substantial payback over the
investment period.
---------------------------------------------------------------------------

    \185\ Vermont and the District of Columbia are excluded from
this table because we are not proposing goals for those
jurisdictions.
    \186\ Some states do include a valuation of CO2
benefits as part of their evaluations of cost effectiveness.
    \187\ E.g., Electric Power Research Institute, U.S. Energy
Efficiency Potential Through 2035 (Final Report, April 2014);
Northwest Power and Conservation Council, Sixth Northwest
Conservation and Electric Power Plan (Feb. 2010), available at
http://www.nwcouncil.org/energy/powerplan/6/plan/.
    \188\ As described below and in the Goal Computation TSD, in the
case of a state that is a net importer of electricity, the proposed
goal computation procedure includes an adjustment to account for the
possibility that some of the generation and emissions avoided due to
the state's demand-side energy efficiency programs may occur at EGUs
in other states. Given the extremely low cost of CO2
emission reductions achievable through demand-side energy efficiency
programs, implementation of such programs is likely to reduce
CO2 emissions at reasonable cost even for a state whose
own affected EGUs achieve only part of the CO2 emission
reduction benefit from the state's demand-side energy efficiency
efforts.
---------------------------------------------------------------------------

    Another approach to evaluating the reasonableness of the costs
associated with this building block is to compare the demand-side
energy efficiency costs to the avoided power system costs as
represented within the EPA's modeling of the power sector. The costs
associated with the best practices scenario were estimated based upon a
synthesis of data and analysis of the factors that impact energy
efficiency program costs as calculated using an engineering-based,
bottom-up approach that is standard for state and utility analysis of
these policies. These factors include the average energy efficiency
program costs per unit of first-year energy savings ($/MWh), the ratio
of program to participant costs, and the lifetimes of energy efficiency
measures across the full portfolio of programs. In addition, the EPA
has included a cost escalation factor to represent the possibility of
increased costs associated with higher levels of incremental energy
savings rates and the national scope of the best practices scenario.
The EPA has taken a conservative approach to each of these factors,
selecting values that are at the higher-cost end of reasonable ranges
of estimated values. The combination of these factors is reflected in
the value the EPA has derived for the levelized cost per MWh of saved
energy. This value includes both the program costs paid by utilities
for implementing energy efficiency programs and the amounts that
program participants pay for their own energy efficiency improvements
beyond the program costs. These costs are levelized across the measure
lifetimes of a full portfolio of energy efficiency programs. This
analysis provides a levelized cost of saved energy (LCOSE) range of
$85/MWh to $90/MWh ($2011) over the 2020 to 2030 period. This range of
LCOSE is notably conservative (leading to higher costs) in comparison
with most utility and state analysis. For example, a 2014 analysis by
the American Council for an Energy-Efficient Economy (ACEEE) surveyed
program and participant cost results across seven states and found a
comparable LCOSE value of $54/MWh (2011$).\189\
---------------------------------------------------------------------------

    \189\ American Council for an Energy-Efficient Economy (ACEEE),
The Best Value for America's Energy Dollar: A National Review of the
Cost of Utility Energy Efficiency Programs (Report No. U1402, March
2014).

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

    To estimate the reductions in power system costs and CO2
emissions associated with the best-practices level of demand-side
energy efficiency described above, the EPA analyzed a scenario
incorporating the resulting reduction in electricity demand and
compared the results with the business-as-usual scenario. Both analyses
were conducted using the Integrated Planning Model (IPM) described
previously. Combining the resulting power system cost reductions with
the energy efficiency cost estimates associated with the best practices
scenario, the EPA derived net cost impacts for 2020, 2025, and 2030.
Dividing these net cost impacts by the associated CO2
reductions for each year, the EPA found that the average cost of the
CO2 reductions achieved ranged from $16 to $24 per metric
ton of CO2. The EPA views these estimated costs as
reasonable. Together with the history of demonstrated successful state
implementation of demand-side energy efficiency programs at reasonable
costs discussed above, this analysis supports the reasonableness of the
level of demand-side energy efficiency represented by the best
practices scenario and, by extension, the reasonableness of the
emission reductions at affected EGUs that can be achieved consistent
with achievement of that level of demand-side energy efficiency.
    Further details regarding the data and methodology used to evaluate
the potential for demand-side energy efficiency programs to substitute
for generation at affected EGUs and thereby facilitate reductions of
power sector CO2 emissions at reasonable costs are provided
in the Greenhouse Gas Abatement Measures TSD. We invite comment on all
aspects of our data and methodology as discussed above and in the TSD,
as well as on the level of reductions we propose to define as best
practices suitable for representation consistent with the best system
of emission reduction and the level reflected in the less stringent
scenario. We also specifically invite comment on several issues: (1)
Increasing the annual incremental savings rate to 2.0 percent and the
pace of improvement to 0.25 percent per year to reflect an estimate of
the additional electricity savings achievable from state policies not
reflected in the 1.5 percent rate and the 0.20 percent per year pace of
improvement, such as building energy codes and state appliance
standards, (2) alternative approaches and/or data sources (i.e., other
than EIA Form 861) for determining each state's current level of annual
incremental electricity savings, and (3) alternative approaches and/or
data sources for evaluating costs associated with implementation of
state demand-side energy efficiency policies.
5. Potential Emission Reduction Measures Not Used To Set Proposed Goals
    There are four additional potential measures for reducing, or
supporting reduced, GHG emissions from EGUs that the EPA does not
propose to consider part of the best system of emission reduction
adequately demonstrated for existing EGUs at this time and therefore
has not used for goal-setting purposes, but that merit discussion here:
Fuel switching at individual EGUs, carbon capture and storage (CCS),
using expanded amounts of less carbon-intensive new NGCC capacity to
provide replacement generation, and heat rate improvements at affected
EGUs other than coal-fired steam EGUs.
a. Fuel Switching at Individual Units
    One technically feasible approach for reducing CO2
emissions per MWh of generation from an EGU designed for coal-fired
generation is to substitute natural gas for some or all of the coal.
Most existing coal-fired steam EGU boilers can be modified to switch to
100 percent gas input or to co-fire gas with coal in any desired
proportion. For certain individual EGUs, switching to or co-firing with
gas may be an attractive option for reducing CO2 emissions.
    Changing the type of fuel burned at a steam EGU typically requires
certain plant modifications (e.g., new burners) and may have some
negative impact on the net efficiencies of the boiler and the overall
generation process. If the plant lacks existing gas pipeline
infrastructure capable of delivering the necessary quantities of
natural gas to the boiler, installation of a new pipeline lateral would
also be required.
    The capital costs of plant modifications required to switch a coal-
fired EGU completely to natural gas are roughly $100-300/kW, excluding
pipeline costs. For plants that require additional pipeline capacity,
the capital cost of constructing new pipeline laterals is approximately
$1 million per mile of pipeline built. Offsetting these capital costs,
conversion to 100 percent gas input would typically reduce the EGU's
fixed operating and maintenance costs by about 33 percent due mainly to
certain equipment retirements and a reduction in staffing, while non-
fuel variable costs would be reduced by about 25 percent due to reduced
maintenance and waste disposal costs. However, in most cases, the most
significant cost change associated with switching from coal to gas in a
coal-fired boiler is likely to be the difference in fuel cost. Using
EIA's projections of future coal and natural gas prices, switching a
steam EGU's fuel from coal to gas typically would more than double the
EGU's fuel cost per MWh of generation.
    The CO2 reduction potential of natural gas co-firing or
conversion is due largely to the different carbon intensities of coal
and natural gas and is directly related to the proportion of gas
burned. Greater reductions in the CO2 emission rate are
achieved at higher proportions of gas usage. For example, at ten
percent gas co-firing, the net emission rate (e.g., pounds of
CO2 per net MWh of generation) of a typical steam EGU
previously burning only coal would decrease by approximately four
percent. At 100 percent gas burn, the net emission rate of a typical
steam EGU previously burning only coal would decrease by approximately
40 percent.
    For a typical base-load coal-fired EGU, and reflecting EIA's
projected future natural gas and coal prices, the average cost of
CO2 reductions achieved through gas conversion or co-firing
ranges from $83 per metric ton to $150 per metric ton. The low end of
the range of CO2 reduction costs represents a 100 percent
switch to gas, because in instances where a combination of coal and gas
is burned, the EGU would continue to bear the fixed costs associated
with equipment needed for coal combustion, raising the cost per ton of
CO2 reduced.
    The EPA's economic analysis suggests that there are more cost
effective opportunities for coal-fired utility boilers to reduce their
CO2 emissions than through natural gas conversion or co-
firing. As a result, the EPA has not proposed at this time to include
this option in the BSER and has not incorporated implementation of the
option into the proposed state goals. However, the EPA believes that
there are a number of factors that warrant further consideration in
determining whether the option should be included. First, the EPA is
aware that a number of utilities have reworked some of their coal-fired
units to allow for some level of natural gas co-firing (and in some
cases have converted the units to fire entirely on natural gas).
Second, the EPA is aware of several possible reasons beyond reduction
of CO2 emissions that may make natural gas co-firing
economically attractive in some circumstances. One example is that
natural gas reburn strategies that involve

co-firing with 10 to 20 percent natural gas can be an effective control
strategy for NOX emissions and, thus, can offset operational
(and in some cases, capital) costs associated with other NOX
controls such as selective catalytic reduction (SCR) or selective non-
catalytic reduction (SNCR). A second example suggested by some vendors
is that the capability to burn natural gas in a coal-fired boiler can
improve economics because it allows the boiler to operate more
effectively at lower loads. A third example, applicable to units that
run infrequently but may be needed for reliability purposes, is that
converting to or co-firing with natural gas may be more economically
attractive than either installing non-CO2 emission controls
or taking other measures, such as transmission upgrades, that could
become necessary if the unit were retired. Finally, beyond the reasons
just described explaining why EGU owners may find natural gas co-firing
to be cost-effective, there are also potentially significant health co-
benefits associated with burning natural gas instead of coal.
    We solicit comment on whether natural gas co-firing or conversion
should be part of the BSER. We also request comment regarding whether,
and, if so, how, we should consider the co-benefits of natural gas co-
firing in making that determination.
b. Carbon Capture and Storage
    Another possible approach for reducing CO2 emissions
from existing fossil fuel-fired EGUs is through the application of
carbon capture and storage \190\ technology (CCS). In the recently
proposed standards of performance for new fossil fuel-fired EGUs (79 FR
1430), the EPA proposed to find that the best system of emission
reduction for new fossil fuel-fired boilers and IGCC units is partial
application of CCS. In that proposal, the EPA found that, for new
units, partial CCS has been adequately demonstrated, it is technically
feasible, it can be implemented at costs that are not unreasonable, it
provides meaningful emission reductions, and its implementation will
serve to promote further development and deployment of the technology.
The EPA also noted in the proposal that most of the relatively few new
boiler and IGCC EGU projects currently under development are already
planning to implement CCS, and, as a result, the proposed standard
would not have a significant impact on nationwide energy prices.
---------------------------------------------------------------------------

    \190\ This is also sometimes referred to as ``carbon capture and
sequestration.''
---------------------------------------------------------------------------

    In contrast, the EPA did not identify full or partial CCS as the
BSER for new natural gas-fired stationary combustion turbines, noting
technical challenges to implementation of CCS at NGCC units as compared
to implementation at new solid fossil fuel-fired sources. The EPA also
noted that, because virtually all new fossil fuel-fired power projects
are projected to use NGCC technology, requiring full or partial CCS
would have a greater impact on the price of electricity than requiring
CCS at the few projected coal plants, and the larger number of NGCC
projects would make a CCS requirement difficult to implement in the
short term.
    Partial CCS has been demonstrated at existing EGUs. It has been
demonstrated at a pilot-scale at Southern Company's Plant Barry, it is
being installed for large-scale demonstration at NRG's W.A. Parish
facility, and it is expected soon to be applied at a commercial scale
as a retrofit at SaskPower's Boundary Dam plant in Canada. However, the
EPA expects that the costs of integrating a retrofit CCS system into an
existing facility would be substantial. For example, some existing
sources have a limited footprint and may not have the land available to
add a CCS system. Moreover, there are a large number of existing
fossil-fired EGUs. Accordingly, the overall costs of requiring CCS
would be substantial and would affect the nationwide cost and supply of
electricity on a national basis.
    For the reasons just described, based on the information available
at this time, the EPA does not propose to find that CCS is a component
of the best system of emission reduction for CO2 emissions
from existing fossil fuel-fired EGUs. The EPA does solicit comment on
all aspects of applying CCS to existing fossil fuel-fired EGUs (in
either full or partial configurations), but does not expect to finalize
CCS as a component of the BSER in this rulemaking. It should be noted,
however, that in light of the fact that several existing fossil-fired
EGUs are currently being retrofitted with CCS, the implementation of
partial CCS may be a viable GHG mitigation option at some facilities,
and as a result, emission reductions achieved through use of the
technology could be used to help meet the emission performance level
required under a state plan.
    Additional discussion can be found in the Greenhouse Gas Abatement
Measures TSD.
c. New NGCC Capacity
    In Section VI.C.2 above, we discussed the opportunity to reduce
CO2 emissions by replacing generation at high carbon-
intensity affected EGUs with lower-carbon generation from existing NGCC
units.\191\ From a technical perspective, the same potential would
exist to replace high-emitting generation with generation from
additional NGCC capacity that may be built in the future; the analysis
above regarding the feasibility of policies to increase utilization
rates of existing NGCC units on average to 70 percent applies equally
to new NGCC units.\192\ We view the opportunity to reduce
CO2 emissions at affected EGUs by means of addition and
operation of new NGCC capacity as clearly feasible.
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    \191\ For purposes of this proposal, NGCC units that have
commenced construction as of January 8, 2014 are ``existing'' units.
    \192\ Whether and to what extent adding new NGCC capacity is
likely to lead to CO2 reductions depends on what
incentives would exist to operate that new capacity in preference to
operation of more carbon-intensive existing EGUs. Because the
proposed state goals also reflect the opportunity to reduce
utilization of high carbon-intensity EGUs by shifting generation to
less carbon-intensive EGUs, we believe that in the context of a
comprehensive state plan, the necessary incentives would likely
exist, in which case adding new NGCC capacity would tend to reduce
CO2 emissions.
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    In addition, we note that our compliance modeling for this proposal
suggests that the construction and operation of new NGCC capacity will
be undertaken as method of responding to the proposal's requirements.
    However, compared to the opportunity to reduce CO2
emissions at affected EGUs by means of re-dispatch to existing NGCC
capacity, the parallel opportunity involving new NGCC capacity would be
more costly for several reasons. The first reason is the additional
cost associated with additional usage of natural gas. As noted in the
discussion of building block 2 above, the EPA analyzed costs associated
with several different target utilization rates for existing NGCC units
and that analysis showed higher costs of CO2 reductions at
higher target NGCC utilization rates.
    The second reason that emission reductions from the use of new NGCC
capacity would be more costly is that there would be capital investment
costs. Some amount of new NGCC capacity (beyond the units that were
already under construction as of January 8, 2014 and are ``existing''
units for purposes of this proposal) would likely be built to meet
perceived electricity market demand or to replace less economic
capacity regardless of this proposal. The costs of achieving
CO2 emission reductions through re-dispatch to these new
NGCC units and through re-dispatch to existing NGCC units would be
comparable (ignoring consideration

of the cost impacts just discussed related to increases in overall gas
usage). However, in the case of any new NGCC units that would not have
been built if not for this proposal, and that were built in part for
the purpose of achieving CO2 reductions at affected EGUs,
some portion of their construction or fixed operating costs would also
be attributable to the CO2 reduction opportunity, increasing
to some extent the cost of the CO2 reductions at affected
EGUs achieved through re-dispatch to those new NGCC units.
    The third reason relates to the costs of pipeline infrastructure
expansion, and in particular the unevenly distributed nature of those
costs. While expanded use of existing NGCC capacity to achieve
CO2 emission reductions can be expected to rely largely on
existing pipeline infrastructure with incremental capacity expansions,
use of new NGCC capacity--if required in all states--could require
substantially greater pipeline infrastructure investments to serve some
states than others.
    Taken together, the EPA believes the cost considerations just
described indicate a higher cost for CO2 reductions
achievable from re-dispatch to new NGCC capacity than from other
options, at least for states with limited natural gas pipeline
infrastructure, and we therefore do not propose to include this option
in state goals.
    While the EPA is not proposing that new NGCC capacity is part of
the basis supporting the BSER, we recognize that there are a number of
new NGCC units being proposed and that many modeling efforts suggest
that development of new NGCC capacity would likely be used as a
CO2 emission mitigation strategy. Therefore, we invite
comment on whether we should consider construction and use of new NGCC
capacity as part of the basis supporting the BSER. Further, we take
comment on ways to define appropriate state-level goals based on
consideration of new NGCC capacity.
d. Assessment of Heat Rate Improvement Opportunities at Oil-Fired Steam
EGUs, Gas-Fired Steam EGUs, NGCC Units, and Simple-Cycle Combustion
Turbine Units
    The EPA assessed opportunities to improve heat rates at affected
EGUs other than coal-fired steam units. This assessment, which is
documented in a Technical Memorandum included as an appendix to the GHG
Abatement Measures TSD, considers the potential extent of heat rate
improvements and CO2 reductions that could be reasonably
available from oil-fired steam EGUs, gas-fired steam EGUs, NGCC units,
and simple-cycle combustion turbine units. For these non-coal
technologies, the total additional potential CO2 reductions
achievable through heat rate improvements appear relatively small
compared to the potential CO2 reductions achievable through
heat rate improvements at coal-fired steam EGUs. For this reason, the
EPA does not propose to include heat rate improvement opportunities at
these other fossil fuel-fired units as an element of the BSER for
CO2 emissions from affected EGUs at this time. However, we
are aware that the proportion of total generation provided from EGUs
such as oil-fired steam EGUs or gas-fired steam EGUs varies by
location, and may be relatively large in geographically isolated areas
such as islands. We therefore invite comment on whether heat rate
improvements for some of the EGU types discussed above should be
identified as a basis for supporting the BSER, with particular
reference to U.S. territories.
    Finally, the EPA expects that for some individual oil/gas-fired
steam EGUs and NGCC units attractive heat rate improvement
opportunities will exist. We note that under the proposed flexible
approach to state plans described later in this preamble,
CO2 reductions achieved through such opportunities could be
used to help meet state goals, regardless of whether these measures are
used as a basis to support the BSER.

D. Potential Combinations of the Building Blocks as Components of the
Best System of Emission Reduction

    This subsection summarizes the EPA's examination of combinations of
the building blocks as components of the BSER, comparing the merits of
a potential BSER that comprises only building blocks 1 and 2 with the
merits of a BSER that comprises all four building blocks--the preferred
option in this proposal. (A more detailed discussion of how we
evaluated each option against the criteria to be considered for the
BSER follows in Section VI.E.) \193\
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    \193\ For convenience, the discussion in this Section VI.D is
based on our proposal to identify the BSER as consisting of the
building blocks themselves. The points made in this discussion are
also relevant for our alternative proposal to identify the BSER as
consisting of building block 1 coupled with reduced utilization of
the affected EGUs in specified amounts.
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1. Reasons for Considering Combinations of Building Blocks
    As previously described, the building blocks can be summarized as
follows:
    Building block 1: Reducing the carbon intensity of generation at
individual affected EGUs through heat rate improvements.
    Building block 2: Reducing emissions from the most carbon-intensive
affected EGUs in the amount that results from substituting generation
at those EGUs with generation from less carbon-intensive affected EGUs
(including NGCC units under construction).
    Building block 3: Reducing emissions from affected EGUs in the
amount that results from substituting generation at those EGUs with
expanded low- or zero-carbon generation.
    Building block 4: Reducing emissions from affected EGUs in the
amount that results from the use of demand-side energy efficiency that
reduces the amount of generation required.
    The EPA initially considered a BSER comprising only strategies
within building block 1. As described earlier in Section VI.B, the EPA
concluded that certain strategies within building block 1--specifically
heat rate improvements at individual coal-fired steam EGUs--should be a
component of the BSER determination, as they are technically feasible
and can be implemented at a reasonable cost. However, the EPA further
concluded that, while heat rate improvements qualify as a system of
emission reduction, they are not in themselves the BSER as there are
additional strategies that can be utilized in combination with building
block 1 that are technically feasible, can be implemented at reasonable
cost, and result in greater emission reductions than would be achieved
through building block 1 strategies alone. The EPA is also concerned
that if the measures that improve heat rates at coal-fired steam EGUs
in building block 1 are implemented in isolation, without additional
measures that reduce overall electricity demand or encourage
substitution of less carbon-intensive generation for more carbon-
intensive generation, the resulting increased efficiency of coal-fired
steam units would provide incentives to operate those EGUs more,
leading to smaller overall reductions in CO2 emissions.
Further, in listening sessions and other outreach meetings, the EPA
learned that states and other sources were already implementing and
pursuing strategies in the other building blocks for the purpose, at
least in part, of reducing CO2 emissions.
2. A Combination of Building Blocks 1 and 2 as the Best System of