titled, Hydrogen in Combustion Turbine Electric Generating Units. Both
documents are included in the rulemaking docket.

F. Recent Changes in the Power Sector

1. Overview
    The electric power sector is experiencing a prolonged period of
transition and structural change. Since the generation of electricity
from coal-fired power plants peaked nearly two decades ago, the power
sector has changed at a rapid pace. Today, natural gas-fired power
plants provide the largest share of net generation, coal-fired power
plants provide a significantly smaller share than in the recent past,
renewable energy provides a steadily increasing share, and as new
technologies enter the marketplace, power producers continue to replace
aging assets with more efficient and lower cost alternatives.
    These developments have significant implications for the types of
controls that the EPA proposes to determine qualify as the BSER for
different types of fossil fuel-fired EGUs. For example, many utilities
and power plant operators have announced plans to voluntarily cease
operating coal-fired power plants in the near future, in some cases
after operating them at low levels for a several-year period. Industry
stakeholders have requested that the EPA structure this rule to avoid
imposing costly control obligations on coal-fired power plants that
have announced plans to voluntarily cease operations, and the EPA
proposes to accommodate those requests. In addition, the EPA recognizes
that utilities and power plant operators are building new natural gas-
fired combustion turbines with plans to operate them at varying levels
of utilization, in coordination with other existing and expected new
energy sources. These patterns of operation are important for the type
of controls that the EPA is proposing as the BSER for these turbines.
    This section discusses the recent trends in the power sector. It
also includes a summary of the provisions and incentives included in
recent Federal legislation that will impact the power sector as well as
State actions and commitments by power producers to reduce GHG
emissions. The section

concludes with projections of future trends in power sector generation.

2. Broad Trends Within the Power Sector

    For more than a decade, the power sector has experienced
substantial transition and structural change, both in terms of the mix
of generating capacity and in the share of electricity generation
supplied by different types of EGUs. These changes are the result of
multiple factors, including normal replacements of older EGUs; changes
in electricity demand across the broader economy; growth and regional
changes in the U.S. population; technological improvements in
electricity generation from both existing and new EGUs; changes in the
prices and availability of different fuels; State and Federal policy;
the preferences and purchasing behaviors of end-use electricity
consumers; and substantial growth in electricity generation from
renewable sources.
    One of the most important developments of this transition has been
the evolving economics of the power sector. Specifically, the existing
fleet of coal-fired EGUs continues to age and become more costly to
maintain and operate. At the same time, the supply and availability of
natural gas has increased significantly, and its price has held
relatively low. For the first time, in April 2015, natural gas
surpassed coal in monthly net electricity generation and since that
time has maintained its position as the primary fossil fuel for base
load energy generation, for peaking applications, and for balancing
renewable generation.\76\ Additionally, there has been increased
generation from investments in zero- and low-GHG emission energy
technologies spurred by technological advancements, declining costs,
State and Federal policies, and most recently, the IIJA and the IRA.
For example, the IIJA provides investments and other policies to help
commercialize, demonstrate, and deploy technologies such as small
modular nuclear reactors, long-duration energy storage, regional clean
hydrogen hubs, carbon capture and storage and associated
infrastructure, advanced geothermal systems, and advanced distributed
energy resources (DER) as well as more traditional wind and solar
resources. The IRA provides numerous tax and other incentives to
directly spur deployment of clean energy technologies. Particularly
relevant to these proposals, the incentives in the IRA,\77\ which are
discussed in detail later in this section of the preamble, support the
expansion of technologies, such as CCS and hydrogen technologies, that
reduce GHG emissions from fossil-fired units.
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    \76\ U.S. Energy Information Administration (EIA). Monthly
Energy Review and Short-Term Energy Outlook, March 2016. https://www.eia.gov/todayinenergy/detail.php?id=25392.
    \77\ U.S. Department of Energy (DOE). August 2022. The Inflation
Reduction Act Drives Significant Emissions Reductions and Positions
America to Reach Our Climate Goals. https://www.energy.gov/sites/default/files/2022-08/8.18%20InflationReductionAct_Factsheet_Final.pdf.
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    The ongoing transition of the power sector is illustrated by a
comparison of data between 2010 and 2021. In 2010, approximately 70
percent of the electricity provided to the U.S. grid was produced
through the combustion of fossil fuels, primarily coal and natural gas,
with coal accounting for the largest single share. By 2021, fossil fuel
net generation was approximately 60 percent, less than the share in
2010 despite electricity demand remaining relatively flat over this
same time period. Moreover, the share of fossil generation supplied by
coal-fired EGUs fell from 46 percent in 2010 to 23 percent in 2021
while the share supplied by natural gas-fired EGUs rose from 23 to 37
percent during the same period. In absolute terms, coal-fired
generation declined by 51 percent while natural gas-fired generation
increased by 64 percent. This reflects both the increase in natural gas
capacity as well as an increase in the utilization of new and existing
gas-fired EGUs. The combination of wind and solar generation also grew
from 2 percent of the electric power sector mix in 2010 to 12 percent
in 2021.\78\
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    \78\ U.S. Energy Information Administration (EIA). Annual Energy
Review, table 8.2b Electricity net generation: electric power
sector. https://www.eia.gov/totalenergy/data/annual/.
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    The broad trends throughout the power sector can also be seen in
the number of commitments and announced plans of many EGU owners and
operators across the industry to decarbonize--spanning all types of
companies in all locations. Moreover, State governments, which
traditionally regulate investment decisions regarding electricity
generation, have implemented their own policies to reduce GHG emissions
from power generation.
    Additional analysis of the utility power sector, including
projections of future power sector behavior and the impacts of these
proposed rules, is discussed in more detail in section XV of this
preamble, in the accompanying RIA, and in the Power Sector Trends
technical support document (TSD). The latter two documents are
available in the rulemaking docket. Consistent with analyses done by
other energy modelers, the RIA and TSD demonstrate that the sector
trend of moving away from coal-fired generation is likely to continue
and that non-emitting technologies may eventually displace certain
natural gas-fired combustion turbines.
3. Trends in Coal-Fired Generation
    Coal-fired steam generating units have historically been the
nation's foremost source of electricity, but coal-fired generation has
declined steadily since its peak approximately 20 years ago.\79\
Construction of new coal-fired steam generating units was at its
highest between 1967 and 1986, with approximately 188 GW (or 9.4 GW per
year) of capacity added to the grid during that 20-year period.\80\ The
peak annual capacity addition was 14 GW, which was added in 1980. These
coal-fired steam generating units operated as base load units for
decades. However, beginning in 2005, the U.S. power sector--and
especially the coal-fired fleet--began experiencing a period of
transition that continues today. Many of the older coal-fired steam
generating units built in the 1960s, 1970s, and 1980s have retired and/
or have experienced significant reductions in net generation due to
cost pressures and other factors. Some of these coal-fired steam
generating units repowered with combustion turbines and natural
gas.\81\ And with no new coal-fired steam generating units commencing
construction in more than a decade--and with the EPA unaware of any
plans by any companies to construct a new coal-fired EGU--much of the
fleet that remains is aging, expensive to operate and maintain, and
increasingly uncompetitive relative to other sources of generation in
many parts of the country.
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    \79\ U.S. Energy Information Administration (EIA). Today in
Energy. Natural gas expected to surpass coal in mix of fuel used for
U.S. power generation in 2016. March 2016. https://www.eia.gov/todayinenergy/detail.php?id=25392.
    \80\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form EIA-860M, Inventory of Operating
Generators and Inventory of Retired Generators, March 2022. https://www.eia.gov/electricity/data/eia860m/.
    \81\ U.S. Energy Information Administration (EIA). Today in
Energy. More than 100 coal-fired plants have been replaced or
converted to natural gas since 2011. August 2020. https://www.eia.gov/todayinenergy/detail.php?id=44636.
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    Since 2010, the power sector's total installed capacity \82\ has
increased by

144 GW (14 percent), while coal-fired steam generating unit capacity
has declined by 107 GW. This reduction in coal-fired steam generating
unit capacity was offset by an increase in total installed wind
capacity of 93 GW, natural gas capacity of 84 GW, and an increase in
utility-scale solar capacity of 60 GW during the same period.
Additionally, significant amounts of DER solar (33 GW) were also added.
Two-thirds or more of these changes were in the most recent 6 years of
this period. From 2015-2021, coal capacity was reduced by 70 GW and
this reduction in capacity was offset by a net increase of 60 GW of
wind capacity, 52 GW of natural gas capacity, and 47 GW of utility-
scale solar capacity. Additionally, 23 GW of DER solar were also added
from 2015 to 2021.
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    \82\ This includes generating capacity at EGUs primarily
operated to supply electricity to the grid and combined heat and
power (CHP) facilities classified as Independent Power Producers and
excludes generating capacity at commercial and industrial facilities
that does not operate primarily as an EGU. Natural gas information
reflects data for all generating units using natural gas as the
primary fossil heat source unless otherwise stated. This includes
combined cycle, simple cycle, steam, and miscellaneous (<1 percent).
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    At the end of 2021, there were more than 500 EGUs totaling 212 GW
of coal-fired capacity remaining in the U.S. Although much of the fleet
of coal-fired steam generating units has historically operated as base
load, there can be notable differences in design and operation across
various facilities. For example, coal-fired steam generating units
smaller than 100 MW comprise 18 percent of the total number of coal-
fired units, but only 2 percent of total coal-fired capacity.\83\
Moreover, average annual capacity factors for coal-fired steam
generating units have declined from 67 to 49 percent since 2010,\84\
indicating that a larger share of units are operating in non-base load
fashion.
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    \83\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v6. October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
    \84\ U.S. Energy Information Administration (EIA). Electric
Power Annual 2021, table 1.2.
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    Older power plants also tend to become uneconomic over time as they
become more costly to maintain and operate,\85\ especially when
competing for dispatch against newer and more efficient generating
technologies that have lower operating costs. The average coal-fired
power plant that retired between 2015 and 2021 was more than 50 years
old, and 65 percent of the remaining fleet of coal-fired steam
generating units will be 50 years old or more within a decade.\86\ To
further illustrate this trend, the existing coal-fired steam generating
units older than 40 years represent 71 percent (154 GW) \87\ of the
total remaining capacity. In fact, more than half (118 GW) of the coal-
fired steam generating units still operating have already announced
retirement dates prior to 2040.\88\ As discussed further in this
section, projections anticipate that this trend will continue.
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    \85\ U.S. Energy Information Administration (EIA). U.S. coal
plant retirements linked to plants with higher operating costs.
December 2019. https://www.eia.gov/todayinenergy/detail.php?id=42155.
    \86\ eGRID 2020 (January 2022 release from EPA eGRID website).
Represents data from generators that came online between 1950 and
2020 (inclusive); a 71-year period. Full eGRID data includes
generators that came online as far back as 1915.
    \87\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form-860M, Inventory of Operating Generators
and Inventory of Retired Generators. August 2022. https://www.eia.gov/electricity/data/eia860m/.
    \88\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v6. October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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    The reduction in coal-fired generation by electric utilities is
also evident in data for annual U.S. coal production, which reflects
reductions in international demand as well. In 2008, annual coal
production peaked at nearly 1,200 million short tons (MMst) followed by
sharp declines in 2015 and 2020.\89\ In 2015, less than 900 MMst were
produced, and in 2020, the total dropped to 535 MMst, the lowest output
since 1965.
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    \89\ U.S. Energy Information Administration (EIA). Annual Coal
Report. Table ES-1. October 2022. https://eia.gov/coal/annual/pdf/tableES1.pdf.
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4. Trends in Natural Gas-Fired Generation
    In the lower 48 states, most combustion turbine EGUs burn natural
gas, and some have the capability to fire distillate oil as backup for
periods when natural gas is not available, such as when residential
demand for natural gas is high during the winter. Areas of the country
without access to natural gas often use distillate oil or some other
locally available fuel. Combustion turbines have the capability to burn
either gaseous or liquid fossil fuels, including but not limited to
kerosene, naphtha, synthetic gas, biogases, liquified natural gas
(LNG), and hydrogen.
    Natural gas consists primarily of methane, and after the raw gas is
extracted from the ground, it is processed to remove impurities and to
separate the methane from other gases and natural gas liquids to
produce pipeline quality gas.\90\ This gas is sent to intermediate
storage facilities prior to being piped through transmission feeder
lines to a distribution network on its path to storage facilities or
end users. During the past 20 years, advances in hydraulic fracturing
(i.e., fracking) and horizontal drilling techniques have opened new
regions of the U.S. to gas exploration.
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    \90\ U.S. Energy Information Administration (EIA). Natural Gas
Explained. December 2022. https://www.eia.gov/energyexplained/natural-gas/.
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    According to the U.S. Energy Information Administration (EIA),
annual natural gas marketed production in the U.S. remained consistent
at approximately 20 trillion cubic feet (Tcf) from the 1970s to the
early 2000s. However, since 2005, annual natural gas marketed
production has steadily increased and approached 35 Tcf in 2021, which
is an average of approximately 94.6 billion cubic feet per day.\91\
Thirty-four states produce natural gas with Texas (24.6 percent),
Pennsylvania (21.8 percent), Louisiana (9.9 percent), West Virginia
(7.4 percent), and Oklahoma (6.7 percent) accounting for approximately
70 percent of total production. Natural gas production exceeded
consumption in the U.S. for the first time in 2017.
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    \91\ U.S. Energy Information Administration (EIA). Natural gas
explained. Where our natural gas comes from. https://www.eia.gov/energyexplained/natural-gas/where-our-natural-gas-comes-from.php.
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    As the production of natural gas has increased, the annual average
price has declined during the same period.\92\ In 2008, U.S. natural
gas prices peaked at $13.39 per million British thermal units ($/MMBtu)
for residential customers. By 2020, the price was $10.45/MMBtu. The
decrease in average annual natural gas prices can also been seen in
city gate prices (i.e., a point or measuring station where natural gas
is transferred from long-distance pipelines to a local distribution
company), which peaked in 2008 at $8.85/MMBtu. By 2020, city gate
prices were $3.30/MMBtu. An equivalent $/MMBtu basis is a common way to
compare natural gas and coal fuel prices. For example, the price of
Henry Hub natural gas in July 2022 was $7.39/MMBtu while the spot price
of Central Appalachian coal was $7.25/MMBtu for the same month.
However, this method of fuel price comparison based on equivalent
energy content does not reflect differences in energy conversion
efficiency (i.e., heat rate) and other factors among different types of
generators. Because natural gas-fired combustion turbines are more
efficient than coal-fired steam units, any fuel cost comparison should
include an efficiency basis (dollar per megawatt-hour) to the
equivalent energy content. For illustrative purposes, an EIA comparison
based on this method showed that the Henry Hub natural gas

price in July 2022 was $59.18/MWh and the price for Central Appalachian
coal was $78.25/MWh for the same month.\93\
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    \92\ U.S. Energy Information Administration (EIA). Natural Gas
Annual, September 2021. https://www.eia.gov/energyexplained/natural-gas/prices.php.
    \93\ U.S. Energy Information Administration (EIA). Electric
Monthly Update. September 23. 2022. Report derived from Bloomberg
Energy. EIA notes that the competition between coal and natural gas
to produce electricity is complex, involving delivered prices and
emission costs, the terms of fuel supply contracts, and the workings
of fuel markets.
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    There has been significant expansion of the natural gas-fired EGU
fleet since 2000, coinciding with efficiency improvements of combustion
turbine technologies, increased availability of natural gas, increased
demand for flexible generation to support the expanding capacity of
renewable energy resources, and declining costs for all three elements.
According to data from EIA, annual capacity additions for natural gas-
fired EGUs peaked between 2000 and 2006, with more than 212 GW added to
the grid during this period. Of this total, approximately 147 GW (70
percent) were combined cycle capacity and 65 GW were simple cycle
capacity.\94\ From 2007 to 2021, more than 125 GW of capacity were
constructed and approximately 78 percent of that total were combined
cycle EGUs. This figure represents an average of almost 4.2 GW of new
combustion turbine generation capacity per year. In 2021, the net
summer capacity of combustion turbine EGUs totaled 413 GW, with 281 GW
being combined cycle generation and 132 GW being simple cycle
generation.
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    \94\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form EIA-860M, Inventory of Operating
Generators and Inventory of Retired Generators, July 2022. https://www.eia.gov/electricity/data/eia860m/.
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    This trend away from coal to natural gas is also reflected in
comparisons of annual capacity factors, sizes, and ages of affected
EGUs. For example, the annual average capacity factors for natural gas-
fired units increased from 28 to 37 percent between 2010 and 2021. And
compared with the fleet of coal-fired steam generating units, the
natural gas fleet is generally smaller and newer. While 67 percent of
the coal-fired steam generating unit fleet capacity is over 500 MW per
unit, 75 percent of the gas fleet is between 50 and 500 MW per unit. In
terms of the age of the generating units, nearly 50 percent of the
natural gas capacity has been in service less than 15 years.\95\
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    \95\ National Electric Energy Data System (NEEDS) v.6.
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    As explained in greater detail later in this preamble and in the
accompanying RIA, future capacity projections for natural gas-fired
combustion turbines differ from those highlighted in recent historical
trends. The largest source of new generation is from renewable energy
and projections show that total natural gas-fired combined cycle
capacity is likely to decline after 2030 in response to increased
generation from renewables, energy storage, and other technologies, as
discussed in section IV.I. Approximately, 86 percent of capacity
additions in 2023 are expected to be from non-emitting generation
resources including solar, wind, nuclear, and energy storage.\96\ The
IRA is likely to accelerate this trend, which is also expected to
impact the operation of certain combustion turbines. For example, as
the electric output from additional non-emitting generating sources
fluctuates daily and seasonally, flexible low and intermediate load
combustion turbines will be needed to support these variable sources
and provide reliability to the grid. This requires the ability to start
and stop quickly and change load more frequently.
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    \96\ U.S. Energy Information Administration (EIA). Today in
Energy. More than half of new U.S. electric-generating capacity in
2023 will be solar. February 2023. https://www.eia.gov/todayinenergy/detail.php?id=55419.
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5. Trends in Renewable Generation
    Renewable sources of electric generation--especially solar and
wind--have expanded in the U.S. during the past decade. This growth has
coincided with a reduction in the costs of the technologies, supportive
State and Federal policies, and increased consumer demand for low-GHG
electricity. In 2021, renewable energy sources produced approximately
20 percent of the nation's net generation, led by wind (9.2 percent),
hydroelectric (6.3 percent), solar (2.8 percent), and other sources
such as geothermal and biomass (1.7 percent).\97\
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    \97\ U.S. Energy Information Administration (EIA). Monthly
Energy Review, table 7.2B Electricity Net Generation: Electric Power
Sector, May 2022. https://www.eia.gov/totalenergy/data/monthly/.
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    The costs of renewable energy sources have fallen over time due to
technological advances, improvements in performance, and increased
demand for clean energy. For example, the unsubsidized average
levelized cost of wind energy from 1988 to 1999 was $106/MWh and has
since declined to $32/MWh in 2021.\98\ The average levelized cost of
energy for utility-scale solar photovoltaics has fallen from $227/MWh
in 2010 to $33/MWh in 2021.\99\ And the National Renewable Energy
Laboratory (NREL) has documented cost decreases of 64, 69, and 82
percent, respectively, for residential-, commercial-, and utility-scale
solar installations since 2010.\100\ Local, State, and Federal
incentives and tax credits have further reduced the cost of renewable
energy resources.
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    \98\ U.S. Department of Energy (DOE), Land-Based Wind Market
Report: 2022 Edition, 2022. https://www.energy.gov/eere/wind/articles/land-based-wind-market-report-2022-edition.
    \99\ Lawrence Berkeley National Laboratory (LBNL), Utility-Scale
Solar Technical Brief, 2022 Edition, September 2022. https://emp.lbl.gov/utility-scale-solar.
    \100\ https://www.nrel.gov/news/program/2021/documenting-a-decade-of-cost-declines-for-pv-systems.html.
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    During the past 15 years, more than 122 GW of wind (primarily
onshore) and 61 GW of solar capacity have been constructed, which
represent a tripling of wind capacity and a 20-fold increase in solar
capacity.\101\ Prior to 2007, no more than 2.6 GW of new wind capacity
was built in any year, and the wind capacity added from 2000 to 2006
averaged 1.2 GW per year. In 2007, the nation added 5.3 GW of total
wind capacity and the annual average was 7.2 GW through 2019. Wind
capacity additions peaked in the past 2 years at a total of nearly 29
GW. For solar, the pattern of expansion is similar. For example, from
2000 to 2006, a total of 11 MW of new solar capacity was constructed,
and from 2007 to 2011, total capacity additions increased to 1.2 GW.
However, from 2012 to 2019, more than 36 GW of solar capacity was built
(an average of 4.5 GW per year). And in 2020 and 2021, new solar
capacity totaled of 24 GW. In terms of the net operating share of
summer capacity in 2021, wind produced 46 percent of all renewable
energy while solar generated 21 percent. The remaining electricity
generated from renewables included 28 percent from hydroelectric and 5
percent from other sources that include geothermal systems, biogases/
biomethane from landfills, woody materials and other biomass, and
municipal solid waste.
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    \101\ U.S. Energy Information Administration (EIA), Electric
Generators Inventory, Form-860M, Inventory of Operating Generators
and Inventory of Retired Generators, July 2022. https://www.eia.gov/electricity/data/eia860m/.
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    There are also emerging technologies such as battery storage that
have demonstrated the ability to further support the development and
integration of renewable energy to the grid by balancing variable
supply and demand resources. At the end of 2021, there were 331 large-
scale battery storage systems operating in the U.S. with a combined
capacity of 4.8 GW

(10.7 GWh).\102\ In terms of small-scale battery storage, there were
781 MW of reported capacity in 2021, mostly in California.\103\ Energy
storage costs declined 72 percent between 2015 and 2019,\104\ and
declining costs have led to additional capacity being installed at each
facility, and this increases the duration of each system when operating
at maximum output. With 20.8 GW of grid storage already announced for
2023-2025, EIA expects that capacity will more than triple from 7.8 GW
in late 2022 to approximately 30 GW by the end of 2025.\105\
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    \102\ U.S. Energy Information Administration (EIA). Annual
Electric Generator Report, 2021 Form EIA-860. https://www.eia.gov/electricity/data/eia860/.
    \103\ U.S. Energy Information Administration (EIA). Annual
Electric Power Industry Report, 2021 Form EIA-861. https://www.eia.gov/electricity/data/eia861/.
    \104\ U.S. Energy Information Administration (EIA). Annual
Electric Generator Report, 2019 Form EIA-860. https://www.eia.gov/analysis/studies/electricity/batterystorage/.
    \105\ U.S. Energy Information Administration (EIA). Today in
Energy. U.S. battery storage capacity will increase significantly by
2025. December 2022. https://www.eia.gov/todayinenergy/detail.php?id=54939.
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6. Trends in Nuclear Generation
    The U.S. power sector continues to rely on nuclear sources of
energy for a consistent portion of net generation. Since 1990, nuclear
energy has provided about 20 percent of the nation's electricity, and
92 reactors were operating at 54 nuclear power plants in 28 states in
2022.\106\
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    \106\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form-860M, Inventory of Operating Generators
and Inventory of Retired Generators. August 2022. https://www.eia.gov/electricity/data/eia860m/.
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    It should be noted that despite the consistent output from nuclear
power plants over time, the number of operating reactors has recently
declined. The average retirement age for a nuclear reactor is 44 years
and the average age of the remaining nuclear fleet is currently 42
years, although age is only one consideration for determining when a
nuclear plant may retire. For example, nuclear generating units at
Dominion Generation's Surry plant, Florida Power & Light's Turkey Point
plant, and Constellation Energy's Peach Bottom plant applied to the
Nuclear Regulatory Commission (NRC) for second 20-year license renewals
and subsequent renewed licenses were granted for six units, although
four of the six units have not had their license terms extended beyond
the periods of their first renewed licenses and are undergoing further
environmental review.\107\ Others who have applied to the NRC for a
second 20-year license renewal include Dominion for its North Anna
units 1 and 2; NextEra Energy for its Point Beach units 1 and 2; Duke
Energy Carolinas for its Oconee units 1, 2, and 3; Florida Power &
Light for its St. Lucie units 1 and 2; and Northern States Power
Company for its Monticello unit 1. If granted, these additional
licenses would also extend the lifespans of these units well past the
42-year average. Recent State and Federal policies, including the DOE's
$6 billion Civilian Nuclear Credit program enacted by the IIJA and the
45U tax credit (discussed below), are intended to support the continued
operation of existing nuclear power plants.
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    \107\ U.S. Nuclear Regulatory Commission (NRC). Status of
Subsequent License Renewal Applications. April 2023. https://www.nrc.gov/reactors/operating/licensing/renewal/subsequent-license-renewal.html.
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    There is also interest in the next generation of nuclear
technologies. Small modular nuclear reactors, which can provide both
firm dispatchable power and load-following capabilities to balance
greater volumes of variable renewable generation, could play a role in
future energy generation. The NRC has issued a final rule certifying
the first small modular reactor design.\108\ Expectations with respect
to output from advanced nuclear generation vary, from negligible on the
low end to as high as between 1,400 and 3,600 terawatt-hours per year
by 2050.\109\ According to one survey by the Nuclear Energy Institute,
utilities are currently considering building more than 90 GW of small
modular nuclear reactors by 2050.\110\
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    \108\ 88 FR 3287 (January 19, 2023).
    \109\ Stein, A., Messinger, J., Wang, S., Lloyd, J., McBride,
J., Franovich, R. (July 6, 2022). ``Advancing Nuclear Energy:
Evaluating Deployment, Investment, and Impact in America's Clean
Energy Future.'' Breakthrough Institute. https://thebreakthrough.imgix.net/Advancing-Nuclear-Energy_v3-compressed.pdf.
    \110\ Derr, E. (July 29, 2022). Energy Studies and Models Show
Advanced Nuclear as the Backbone of Our Carbon-Free Future. Nuclear
Energy Institute (NEI). https://www.nei.org/news/2022/studies-and-models-show-demand-for-adv-nuclear.
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G. GHG Emissions From Fossil Fuel-Fired EGUs

    The principal GHGs that accumulate in the Earth's atmosphere above
pre-industrial levels because of human activity are CO2,
CH4, N2O, HFCs, PFCs, and SF6. Of
these, CO2 is the most abundant, accounting for 80 percent
of all GHGs present in the atmosphere. This abundance of CO2
is largely due to the combustion of fossil fuels by the transportation,
electricity, and industrial sectors.\111\
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    \111\ U.S. Environmental Protection Agency (EPA). Overview of
greenhouse gas emissions. July 2021. https://www.epa.gov/ghgemissions/overview-greenhouse-gases#carbon-dioxide.
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    The amount of CO2 emitted from fossil fuel-fired EGUs
depends on the carbon content of the fuel and the size and efficiency
of the EGU. Different fuels emit different amounts of CO2 in
relation to the energy they produce when combusted. The amount of
CO2 produced when a fuel is burned is a function of the
carbon content of the fuel. The heat content, or the amount of energy
produced when a fuel is burned, is mainly determined by the carbon and
hydrogen content of the fuel. For example, in terms of pounds of
CO2 emitted per million British thermal units of energy
produced, when combusted, natural gas is the lowest compared to other
fossil fuels at 117 lb CO2/MMBtu.112 113 The
average for coal is 216 lb CO2/MMBtu, but varies between 206
to 229 lb CO2/MMBtu by type (e.g., anthracite, lignite,
subbituminous, and bituminous).\114\ The value for petroleum products
such as diesel fuel and heating oil is 161 lb CO2/MMBtu.
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    \112\ Natural gas is primarily CH4, which has a
higher hydrogen to carbon atomic ratio, relative to other fuels, and
thus, produces the least CO2 per unit of heat released.
In addition to a lower CO2 emission rate on a lb/MMBtu
basis, natural gas is generally converted to electricity more
efficiently than coal. According to EIA, the 2020 emissions rate for
coal and natural gas were 2.23 lb CO2/kWh and 0.91 lb
CO2/kWh, respectively. www.eia.gov/tools/faqs/faq.php?id=74&t=11.
    \113\ Values reflect the carbon content on a per unit of energy
produced on a higher heating value (HHV) combustion basis and are
not reflective of recovered useful energy from any particular
technology.
    \114\ Energy Information Administration (EIA). Carbon Dioxide
Emissions Coefficients. https://www.eia.gov/environment/emissions/co2_vol_mass.php.
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    The EPA prepares the official U.S. Inventory of Greenhouse Gas
Emissions and Sinks \115\ (the U.S. GHG Inventory) to comply with
commitments under the United Nations Framework Convention on Climate
Change (UNFCCC). This inventory, which includes recent trends, is
organized by industrial sectors. It presents total U.S. anthropogenic
emissions and sinks \116\ of GHGs, including CO2 emissions,
for the years 1990-2020.
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    \115\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2021. https://cfpub.epa.gov/ghgdata.
    \116\ Sinks are a physical unit or process that stores GHGs,
such as forests or underground or deep-sea reservoirs of carbon
dioxide.
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    According to the latest inventory, in 2021, total U.S. GHG
emissions were 6,340 million metric tons of carbon dioxide equivalent
(MMT CO2e). The transportation sector (28.5 percent) was the
largest contributor to total U.S. GHG emissions, followed by the power
sector (25.0 percent) and industrial sources

(23.5 percent). In terms of annual CO2 emissions, the power
sector was responsible for 30.6 percent (1,541 MMT CO2e) of
the nation's 2021 total.
    CO2 emissions from the power sector have declined by 36
percent since 2005 (when the power sector reached annual emissions of
2,400 MMT CO2, its historical peak to date).\117\ The
reduction in CO2 emissions can be attributed to the power
sector's ongoing trends away from carbon-intensive coal-fired
generation and toward more natural gas-fired and renewable sources. In
2005, CO2 emissions from coal-fired EGUs alone measured
1,983 MMT.\118\ This total dropped to 1,351 MMT in 2015 and reached 974
MMT in 2019, the first time since 1978 that coal-fired CO2
emissions were below 1,000 MMT. In 2020, emissions of CO2
from coal-fired EGUs measured 788 MMT before rebounding in 2021 to 909
MMT due to increased demand. By contrast, CO2 emissions from
natural gas-fired generation have almost doubled since 2005, increasing
from 319 MMT to 613 MMT in 2021, and CO2 emissions from
petroleum products (i.e., distillate fuel oil, petroleum coke, and
residual fuel oil) declined from 98 MMT in 2005 to 18 MMT in 2021.
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    \117\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2020. https://cfpub.epa.gov/ghgdata/inventoryexplorer/#electricitygeneration/entiresector/allgas/category/all.
    \118\ U.S. Energy Information Administration (EIA). Monthly
Energy Review, table 11.6. September 2022. https://www.eia.gov/totalenergy/data/monthly/pdf/sec11.pdf.
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    When the EPA finalized the Clean Power Plan (CPP) in October 2015,
the Agency projected that, as a result of the CPP, the power sector
would reduce its annual CO2 emissions to 1,632 MMT by 2030,
or 32 percent below 2005 levels (2,400 MMT).\119\ Instead, even in the
absence of Federal regulations for existing EGUs, annual CO2
emissions from sources covered by the CPP had fallen to 1,540 MMT by
the end of 2021, a nearly 36 percent reduction below 2005 levels. The
power sector achieved a deeper level of reductions than forecast under
the CPP and approximately a decade ahead of time. By the end of 2015,
several months after the CPP was finalized, those sources already had
achieved CO2 emission levels of 1,900 MMT, or approximately
21 percent below 2005 levels. However, progress in emission reductions
is not uniform across all states and so Federal policies play an
essential role. As discussed earlier in this section, the power sector
remains a leading emitter of CO2 in the U.S., and, despite
the emission reductions since 2005, current CO2 levels
continue to endanger human health and welfare. Further, as sources in
other sectors of the economy turn to electrification to decarbonize,
future CO2 reductions from fossil fuel-fired EGUs have the
potential to take on added significance and increased benefits.
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    \119\ 80 FR 63662 (October 23, 2015).
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The Legislative, Market, and State Law Context

Recent Legislation Impacting the Power Sector
    On November 15, 2021, President Biden signed the IIJA \120\ (also
known as the Bipartisan Infrastructure Law), which allocated more than
$65 billion in funding via grant programs, contracts, cooperative
agreements, credit allocations, and other mechanisms to develop and
upgrade infrastructure and expand access to clean energy technologies.
Specific objectives of the legislation are to improve the nation's
electricity transmission capacity, pipeline infrastructure, and
increase the availability of low-GHG fuels. Some of the IIJA programs
\121\ that will impact the utility power sector include: $16.5 billion
to build and upgrade the nation's electric grid; $6 billion in
financial support for existing nuclear reactors that are at risk of
closing and being replaced by high-emitting resources; and more than
$700 million for upgrades to the existing hydroelectric fleet. The IIJA
established the Carbon Dioxide Transportation Infrastructure Finance
and Innovation Program to provide flexible Federal loans and grants for
building CO2 pipelines designed with excess capacity,
enabling integrated carbon capture and geologic storage. The IIJA also
allocated $21.5 billion to fund new programs to support the
development, demonstration, and deployment of clean energy
technologies, such as $8 billion for the development of regional clean
hydrogen hubs. Other clean energy technologies with IIJA funding
include carbon capture, geologic sequestration, direct air capture,
grid-scale energy storage, and advanced nuclear reactors. States,
Tribes, local communities, utilities, and others are eligible to
receive funding.
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    \120\ https://www.congress.gov/bill/117th-congress/house-bill/3684/text.
    \121\ https://gfoaorg.cdn.prismic.io/gfoaorg/0727aa5a-308f-4ef0-addf-140fd43acfb5_BUILDING-A-BETTER-AMERICA-V2.pdf.
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    The IRA, which President Biden signed on August 16, 2022,\122\ has
the potential for even greater impacts on the electric power sector.
With an estimated $369 billion in Energy Security and Climate Change
programs over the next 10 years, covering grant funding and tax
incentives, the IRA provides significant investments in non GHG-
emitting generation. For example, one of the conditions set by Congress
for the expiration of the Clean Electricity Production Tax Credits of
the IRA, found in section 13701, is a 75 percent reduction in GHG
emissions from the power sector below 2022 levels. The IRA also
contains the Low Emission Electricity Program (LEEP) with funding
provided to the EPA with the objective to reduce GHG emissions from
domestic electricity generation and use through promotion of
incentives, tools to facilitate action, and use of CAA regulatory
authority. In particular, CAA section 135, added by IRA section 60107,
requires the EPA to conduct an assessment of the GHG emission
reductions expected to occur from changes in domestic electricity
generation and use through fiscal year 2031 and, further, provides the
EPA $18 million ``to ensure that reductions in [GHG] emissions are
achieved through use of the existing authorities of [the Clean Air
Act], incorporating the assessment. . ..'' CAA section 135(a)(6).
---------------------------------------------------------------------------

    \122\ https://www.congress.gov/bill/117th-congress/house-bill/5376/text..
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    The IRA's provisions also demonstrate an intent to support
development and deployment of low-GHG emitting technologies in the
power sector through a broad array of additional tax credits, loan
guarantees, and public investment programs. These provisions are aimed
at reducing emissions of GHGs from new and existing generating assets,
with tax credits for carbon capture, utilization, and storage (CCUS)
and clean hydrogen production providing a pathway for the use of coal
and natural gas as part of a low-GHG electricity grid. Finally, with
provisions such as the Methane Emissions Reduction Program, Congress
demonstrated a focus on the importance of actions to address methane
emissions from petroleum and natural gas systems.
    To assist states and utilities in their decarbonizing efforts, and
most germane to these proposed rulemakings, the IRA increased the tax
credit incentives for capturing and storing CO2, including
from industrial sources, coal-fired steam generating units, and natural
gas-fired stationary combustion turbines. The increase in credit
values, found in section 13104 (which revises IRC section 45Q), is 70
percent, equaling $85/metric ton for CO2 captured and
securely stored in geologic formations and $60/metric ton for
CO2 captured and utilized or securely stored incidentally in
conjunction with

enhanced oil recovery (EOR).\123\ The CCUS incentives include 12 years
of credits that can be claimed at the higher credit value beginning in
2023 for qualifying projects. These incentives will significantly cut
costs and are expected to accelerate the adoption of CCS in the utility
power and other industrial sectors. Specifically for the power sector,
the IRA requires that a qualifying carbon capture facility have a
CO2 capture design capacity of not less than 75 percent of
the baseline CO2 production of the unit and that
construction must begin before January 1, 2033. Tax credits under 45Q
can be combined with other tax credits, in some circumstances, and with
State-level incentives, including California's low carbon fuel standard
which is a market-based program with fuel-specific carbon intensity
benchmarks.\124\ The magnitude of this incentive is driving investment
and announcements, evidenced by the increased number of permit
applications for geologic sequestration.
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    \123\ 26 U.S.C. 45Q.
    \124\ Global CCS Institute. (2019). The LCFS and CCS Protocol:
An Overview for Policymakers and Project Developers. Policy report.
https://www.globalccsinstitute.com/wp-content/uploads/2019/05/LCFS-and-CCS-Protocol_digital_version-2.pdf.
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    The new provisions in section 13204 (IRC section 45V) codify
production tax credits for `clean hydrogen' as defined in the
provision. The value of the credits earned by a project is tiered (four
different tiers) and depends on the estimated GHG emissions of the
hydrogen production process from well-to-gate. The credits range from
$3/kg H2 for 0.0 to 0.45 kilograms of CO2-
equivalent emitted per kilogram of low-GHG hydrogen produced (kg
CO2e/kg H2) down to $0.6/kg H2 for 2.5
to 4.0 kg CO2e/kg H2 (assuming wage and
apprenticeship requirements are met). Projects with GHG emissions
greater than 4.0 kg CO2e/kg H2 are not eligible.
According to the DOE, current costs for hydrogen produced from
renewable energy are approximately $5/kg H2.\125\ These
production costs could decline by 2025 to between $2.5 and $2.7/kg
H2 (not including the production tax credits).\126\
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    \125\ U.S. Department of Energy (DOE). Hydrogen and Fuel Cell
Technologies Office. Hydrogen Shot. https://www.energy.gov/eere/fuelcells/hydrogen-shot.
    \126\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen, March 2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
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    The clean hydrogen production tax credit is expected to incentivize
the production of low-GHG hydrogen and ultimately exert downward
pressure on costs.\127\ Low-cost and widely available low-GHG hydrogen
has the potential to become a material decarbonization lever in the
power sector as the use of low-GHG hydrogen in stationary combustion
turbines reduces direct GHG emissions as hydrogen releases no
CO2 when combusted. The tiered eligibility requirements for
the clean hydrogen production tax credit also incentivize the lowest-
GHG emissions production processes.
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    \127\ Larsen, J., King, B., Kolus, H., Dasari, N., Hiltbrand,
G., Herndon, W. (August 12, 2022). A Turning Point for US Climate
Progress: Assessing the Climate and Clean Energy Provisions in the
Inflation Reduction Act. Rhodium Group. https://rhg.com/research/climate-clean-energy-inflation-reduction-act/.
---------------------------------------------------------------------------

    Both IRC 45Q and 45V are eligible for additional provisions that
increase the value and usability of the credits. Certain tax-exempt
entities, such as electric co-ops, may use direct pay for the full 12-
or 10-year lifetime of the credits to monetize the credits directly as
cash refunds rather than through tax equity transactions. Tax-paying
entities may elect to have direct payment of 45Q or 45V credits for
five consecutive years. Tax-paying entities may also elect to transfer
credits to unrelated taxpayers, enabling direct monetization of the
credits again without relying on tax equity transactions.
    The production tax credit is not the only provision in the IRA
designed to incentivize low-GHG hydrogen. Projects may also access an
investment tax credit (ITC) under IRC section 48. For example,
manufacturers of clean hydrogen production equipment, like
electrolyzers, may apply under IRC section 48C (the Advanced
Manufacturing Tax Credit). And the manufacturing facility for
electrolyzers could receive credits under section 48C while the
resulting hydrogen production facility could then earn credits under
section 45V (this form of stacking is allowed by statute). However, the
same project may not claim ITC credits under section 48C while claiming
PTC credits under section 45V. Projects may not generally combine
credits from IRC section 45V with credits in IRC section 45Q. Hydrogen
production tax credits became available in January 2023 for eligible
new projects. Entities that commence construction between 2023 and 2032
can claim credits for the first 10 years of production.
    The magnitude of this incentive--combined with those in the IIJA
such as the $8 billion for regional hydrogen hubs and $1.5 billion for
electrolyzer advancement--should accelerate the production of low-GHG
hydrogen for use in a broad range of applications across many sectors,
including the utility power sector.\128\
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    \128\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen, March 2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
---------------------------------------------------------------------------

    Many of the IRA tax credit incentives are directed toward low- and
zero-emission electric generation. They are designed to lower costs and
market barriers to bring new zero-emitting generation and energy
storage capacity online, to retain existing zero-emitting generators,
and the energy efficiency tax credits are designed to reduce
electricity demand. These financial tools have been used historically
and shown to be a principal policy driver, buttressed by State
renewable and clean energy standards, for incentivizing deployment of
low- and zero-emitting generation.129 130
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    \129\ Impacts of Federal Tax Credit Extensions on Renewable
Deployment and Power Sector Emissions, National Renewable Energy
Laboratory (NREL), February 2016.
    \130\ A Retrospective Assessment of Clean Energy Investments in
the Recovery Act, February 2016, U.S. Executive Office of the
President, Memorandum.
---------------------------------------------------------------------------

    For example, the IRA expanded and extended the existing section
13101 (IRC section 45) production tax credits for new solar, wind,
geothermal, and other eligible zero- or low-GHG emissions energy
sources. The production tax credit (PTC) provides credits in a 10-year
stream for each MWh of clean energy produced. The IRA indexed the PTC
on inflation, increasing the credit amount to $27.50/MWh for facilities
meeting certain wage and apprenticeship requirements. For context, the
energy price in the nation's largest wholesale energy market, PJM,\131\
is typically between $20/MWh and $90/MWh depending on timing, load, and
transmission congestion.
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    \131\ PJM Interconnection LLC (PJM) is a regional transmission
organization (RTO) serving all or parts of Delaware, Illinois,
Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina,
Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the
District of Columbia.
---------------------------------------------------------------------------

    In parallel, the existing investment tax credits in section 13101
(IRC section 48) were also expanded and extended in the IRA. Taxpayers
must elect between the ITC and the PTC for each applicable project. The
ITC enables taxpayers to recoup up to 30 percent of project costs for
technologies such as solar, geothermal, fiberoptic solar, fuel cells,
microturbines, small wind, offshore wind, combined heat and power
(CHP), and waste energy recovery for investments meeting certain wage
and apprenticeship requirements. There are also a range of bonus
credits available

if certain criteria are met, for example for meeting domestic content
and energy communities' requirements with each earning an additional 10
percent credit. The IRA expanded eligibility to include storage
technologies as well as some non-storage technologies.
    The IRA also tied the availability of tax credits explicitly to
reductions of GHG emissions from the power sector. Sections 13701 and
13702 enacted technology-neutral production and investment tax credits
for projects placed in service after 2025 that have GHG emissions rates
of zero or less. These credits are available until the phaseout is
triggered when the power sector's GHG emissions fall below 25 percent
of 2022 levels.
    Following State practices, Congress also included a zero-emission
nuclear power production credit in the IRA to ensure existing in-
service nuclear generators are retained for their contribution to base
load zero-carbon emitting electricity. When labor and apprenticeship
requirements are met, the credit price is $15/MWh. The credit amount
declines when gross receipts of services provided with electricity rise
above a specified level. The program begins in 2024 with credit streams
available for nine years. This PTC is complementary to the $6 billion
for nuclear advancements the IIJA authorized and appropriated to the
DOE. New nuclear plants, including small modular reactors, would be
eligible for either the technology-neutral Clean Electricity Production
or Investment Credit (IRC section 45Y and 48E).
    In the evaluation of these proposed actions, many of the
technologies that receive investment under recent Federal legislation
are not directly considered, as the EPA has not evaluated the new
generation technologies that entities could employ as alternatives to
fossil fuel-fired EGUs in its assessment of the BSER. As the discussion
of that assessment will make clear later in this preamble, the EPA's
inquiry has focused on ``measures that improve the pollution
performance of individual sources.'' \132\ However, these overarching
incentives and policies are important context for this rulemaking.
---------------------------------------------------------------------------

    \132\ West Virginia v. EPA, 142 S. Ct. 2587, 2615 (2022).
---------------------------------------------------------------------------

    The following section (section IV.E.2) includes a review of
integrated resource plans (IRPs) filed by public utilities that
prioritize GHG reductions. IRPs demonstrate how utilities plan to meet
future forecasted energy demand while ensuring reliable and cost-
effective service. These IRPs demonstrate that most power companies
intend to meet their GHG reduction targets by retiring aging coal-fired
steam generating EGUs and replacing them with a combination of
renewable resources, energy storage, other non-emitting technologies,
and natural gas-fired combustion turbines. Many IRPs further
demonstrate the realization of power companies that to meet their GHG
reduction targets, their natural gas-fired assets will need to occupy a
much smaller GHG footprint through a combination of hydrogen, CCS, and
reduced utilization. The IRA is designed to encourage this trend. For
example, in addition to the provisions outlined above, including the 10
percent bonus value applied in `energy communities' that include
fossil-related properties, the IRA created grant and loan funding
sources for hard-to-abate energy assets. Section 22004 of the IRA
authorizes $9.7 billion in financing for rural electric co-operatives
and providers to invest in cleaner technologies to achieve GHG
reductions across rural electric systems while buttressing resilience
and reliability. Additionally, section 50144 of the IRA, known as the
Energy Infrastructure Reinvestment Financing provision, provides $5
billion for backing $250 billion in low-cost loans for utilities to
repower, repurpose, or replace existing infrastructure that has ceased
operations, or to enable operating energy infrastructure to reduce air
pollution or GHG emissions. The financing in this provision enables a
utility to repurpose an existing fossil site, such as a retired coal-
fired power plant, or add CCS, renewable generation, or hydrogen
capability to an operating coal- or natural gas-fired power plant and
retain community jobs while reducing GHG emissions.
2. Commitments by Utilities To Reduce GHG Emissions
    The broad trends away from coal-fired generation and toward lower-
emitting generation are reflected in the recent actions and announced
plans of many utilities across the industry. As highlighted later in
this section, through planning documents, IRPs, filings with State and
local public utility commissions, and news releases, many utilities
have made public commitments to voluntarily cease operating coal-fired
generation and move toward zero- and low-GHG energy generation. Many
utilities and other power generators have announced plans to increase
their renewable energy holdings and continue reducing GHG emissions,
regardless of any potential Federal regulatory requirements. For
example, 50 power producers that are members of the Edison Electric
Institute have announced CO2 reduction goals, two-thirds of
which include net-zero carbon emissions by 2050.\133\ This trend is not
unique to the largest owner-operators of coal-fired EGUs; smaller
utilities, public power cooperatives, and municipal entities are also
contributing to these changes.
---------------------------------------------------------------------------

    \133\ See Comments of Edison Electric Institute to EPA's Pre-
Proposal Docket on Greenhouse Gas Regulations for Fossil Fuel-fired
Power Plants, Docket ID No. EPA-HQ-OAR-2022-0723, November 18, 2022
(``Fifty EEI members have announced forward-looking carbon reduction
goals, two-third of which include a net-zero by 2050 or earlier
equivalent goal, and members are routinely increasing the ambition
or speed of their goals or altogether transforming them into net-
zero goals.'').
---------------------------------------------------------------------------

    Some of the largest electric utilities that have publicly announced
near- and long-term GHG reduction commitments, many with emission
reduction targets of at least 80 percent (relative to 2005 levels
unless otherwise noted), include:
     Xcel Energy: 80 percent reduction in CO2
emissions by 2030 and 100 percent carbon-free by 2050. This includes a
commitment to close or repower all remaining coal-fired EGUs by
2030.\134\
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    \134\ Xcel Energy is based in Minnesota with operations in
Colorado, Michigan, New Mexico, North Dakota, South Dakota, Texas,
and Wisconsin. 2018 Integrated Resource Plan at https://www.xcelenergy.com/staticfiles/xe-responsive/Company/Rates%20&%20Regulations/Resource%20Plans/2018-SPS-NM-Integrated-Resource-Plan.pdf.
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     DTE Energy: 65 percent reduction in CO2
emissions by 2028, 90 percent reduction by 2040, and net-zero carbon
emissions by 2050.\135\
---------------------------------------------------------------------------

    \135\ DTE Energy is based in Michigan. Our Bold Goal for
Michigan's Clean Energy Future at https://dtecleanenergy.com/.
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     Ameren Energy: 60 percent reduction in CO2 by
2030, 85 percent reduction by 2040, and net-zero carbon emissions by
2045.\136\
---------------------------------------------------------------------------

    \136\ Ameren is based in Illinois and Missouri. 2022 Integrated
Resource Plan at https://www.ameren.com/missouri/company/environment-and-sustainability/integrated-resource-plan.
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     Consumers Energy: 60 percent reduction in CO2
by 2025 and net-zero carbon emissions by 2040. This includes the
retirement of all coal-fired units by 2025.\137\
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    \137\ Consumers Energy is based in Michigan. Integrated Resource
Plan at https://s26.q4cdn.com/888045447/files/doc_presentations/2021/06/2021-Integrated-Resource-Plan.pdf.
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     Southern Company: 50 percent reduction in CO2
by 2030 (relative to 2007 levels) and net-zero carbon emissions by
2050.\138\
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    \138\ Southern Company is based in Georgia with operations in
Alabama and Mississippi. https://www.southerncompany.com/sustainability/net-zero-and-environmental-priorities/net-zero-transition.html.
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     Duke Energy: 70 percent reduction in CO2 by
2030 and net-zero carbon

emissions by 2050. All coal-fired units will retire by 2035.\139\
---------------------------------------------------------------------------

    \139\ Duke Energy is based in North Carolina with operations in
South Carolina, Florida, Indiana, Ohio, and Kentucky. NC IRP Fact
Sheet at https://p-scapi.duke-energy.com/-/media/pdfs/our-company/202296-nc-irp-fact-sheet.pdf.
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     Minnesota Power (Allete Inc.): 70 percent renewable energy
by 2030, 80 percent reduction in CO2 and coal-free by 2035,
and 100 percent carbon-free by 2050.\140\
---------------------------------------------------------------------------

    \140\ Allete Energy is based in Minnesota with operations in
Wisconsin and North Dakota. Integrated Resource Plan at: https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId=%7b70795F77-0000-C41E-A71C-FD089119967C%7d&documentTitle=20212-170583-01.
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     First Energy: 30 percent reduction in CO2 by
2030 (relative to 2019 levels) and net-zero carbon emissions by
2050.\141\
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    \141\ First Energy is based in Ohio with operations in
Pennsylvania, West Virginia, and New Jersey. https://www.firstenergycorp.com/content/dam/environmental/files/climate-strategy.pdf.
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     American Electric Power: 80 percent reduction in
CO2 by 2030 and net-zero carbon emissions by 2045.\142\
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    \142\ American Electric Power (AEP) is based in Ohio with
operations in Arkansas, Indiana, Kentucky, Louisiana, Michigan,
Oklahoma, Tennessee, Texas, Virginia, and West Virginia. Clean
Energy Future at https://www.aep.com/about/ourstory/cleanenergy.
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     Alliant Energy: 50 percent reduction in CO2 by
2030 and net-zero carbon emissions by 2050; will retire final coal-
fired EGU by 2040.\143\
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    \143\ Alliant Energy has operations in Iowa and Wisconsin. See
Our Sustainable Energy Plan at https://www.alliantenergy.com/cleanenergy/ourenergyvision/poweringwhatsnext/sustainableenergyplan.
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     Tennessee Valley Authority: 70 percent reduction in
CO2 by 2030, 80 percent reduction by 2035, and net-zero
carbon emissions by 2050.\144\
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    \144\ Tennessee Valley Authority (TVA) is based in Tennessee
with operations in Alabama, Georgia, Kentucky, Mississippi, North
Carolina, and Virginia. See https://www.tva.com/newsroom/press-releases/tva-charts-path-to-clean-energy-future.
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     NextEra Energy: 70 percent reduction in CO2 by
2025, 82 percent reduction by 2030, 87 percent reduction by 2035, 94
percent reduction by 2040, and carbon-free by 2045.\145\
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    \145\ NextEra Energy. See https://newsroom.nexteraenergy.com/2022-06-14-NextEra-Energy-sets-industry-leading-Real-Zero-TM-goal-to-eliminate-carbon-emissions-from-its-operations,-leverage-low-cost-renewables-to-drive-energy-affordability-for-customers.
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    The geographic footprint of zero or net-zero carbon commitments
made by utilities, their parent companies, or in response to a State
clean energy requirement, covers portions of 47 states and includes 75
percent of U.S. customer accounts.\146\ These statements are often made
as part of long-term planning processes with considerable stakeholder
involvement, including regulators.
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    \146\ Smart Electric Power Alliance Utility Carbon Tracker. See
https://sepapower.org/utility-transformation-challenge/utility-carbon-reduction-tracker/. Accessed January 12, 2023.
---------------------------------------------------------------------------

3. State Actions To Reduce Power Sector GHG Emissions
    States across the country have taken the lead in efforts to reduce
GHG emissions from the power sector. These actions include commitments
that require utilities to expand renewable and clean energy production
through the adoption of renewable portfolio standards (RPS) and clean
energy standards (CES), as well as other measures tailored to
decarbonize State power systems enacted in specific legislation.
    Twenty-nine states and the District of Columbia have enforceable
RPS.\147\ RPS require a percentage of electricity that utilities sell
to come from eligible renewable sources like wind and solar rather than
from fossil fuel-based sources like coal and natural gas. Fifteen
states have RPS targets that are at or well above 50 percent. Eight of
these states--California, Illinois, Massachusetts, Maryland, Minnesota,
New Jersey, Nevada, and Oregon--have targets ranging from 50 percent to
just below 70 percent. Four states--Maine, New Mexico, New York, and
Vermont--have RPS targets greater than or equal to 70 percent but below
100 percent, and three states--Hawaii, Rhode Island, and Virginia plus
the District of Columbia--have 100 percent RPS requirements. Most of
these ambitious targets fall during the next decade. Ten states and the
District of Columbia have final targets that mature between 2025 and
2033, while the remaining five states impose peak requirements between
2040 and 2050. Resources that are eligible under an RPS vary by State
and are determined by the State's existing energy production and
possibility for renewable energy development. For example, Colorado's
RPS includes a range of resources such as solar, wind, emissions-
neutral coal mine methane and other sources as qualifying renewable
energy sources. Hawaii's includes, but is not limited to, solar, wind,
and energy produced from falling water, ocean water, waves, and water
currents. RPS in some other states include landfill gas, animal wastes,
CHP, and energy efficiency.\148\
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    \147\ DSIRE, Renewable Portfolio Standards and Clean Energy
Standards (2022). https://ncsolarcen-prod.s3.amazonaws.com/wp-content/uploads/2022/11/RPS-CES-Nov2022.pdf.
    \148\ NCSL (2021). State Renewable Portfolio Standards and
Goals. https://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx.
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    States are also shifting their generating fleets away from fossil
fuel generating resources through the adoption of CES. A CES requires a
percentage of retail electricity to come from sources that are defined
as clean. Unlike an RPS, which defines eligible generation in terms of
the renewable attributes of its energy source, CES eligibility is based
on the GHG emission attributes of the generation itself, typically with
a zero or net-zero carbon emissions requirement. Twenty-one states have
adopted some form of clean energy requirement or goal with 17 of those
states setting 100 percent targets. In nearly all cases, the CES
applies in addition to the State's other RPS requirements. Seven
states, including California, Colorado, Minnesota, New York,
Washington, Oregon, and Arizona, have a zero or net-zero carbon
emissions requirement with most target dates falling in 2040, 2045, or
2050. Two states--New Mexico and Massachusetts--have 80 percent clean
energy requirements that must be met in 2045 and 2050, respectively.
Ten additional states, including Connecticut, New Jersey, Nevada,
Wisconsin, Illinois, Maine, North Carolina, Nebraska, Louisiana, and
Michigan, have 100 percent clean energy goals with target dates falling
in either 2040 or 2050. Like an RPS, CES resource eligibility can vary
from State to State. One key difference between an RPS and a CES is the
extent to which a CES can allow for resources like nuclear and CCS-
enabled coal and natural gas, which are not renewable but have low or
zero direct GHG emission attributes that make them CES eligible.
    In addition, states across the U.S. have announced specific
legislation aimed at reducing GHG emissions. In California, Senate Bill
32, passed in 2016, was a landmark legislation that requires California
to reduce its economy-wide GHG emissions to 1990 levels by 2020, 40
percent below 1990 levels by 2030, and 80 percent below 1990 levels by
2050. Senate Bill 100, passed in 2018, requires California to procure
60 percent of all electricity from renewable sources by 2030 and plan
for 100 percent from carbon-free sources by 2045. Senate Bills 605 and
1383, passed in 2016, require a reduction in emissions of short-lived
climate pollutants like methane by 40 to 50 percent below 2013 levels
by 2030.\149\ Achieving California's established goal

of carbon-free electricity by 2045 requires emissions to be balanced by
carbon sequestration, capture, or other technologies. Senate Bill 905,
passed in 2022, requires the California Air Resources Board to
establish programs for permitting CCS projects.\150\ Senate Bill 905,
also passed in 2022, prevents the use of captured CO2 for
enhanced oil recovery within California.
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    \149\ Berkeley Law. California Climate Policy Dashboard. https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
    \150\ Berkeley Law. California Climate Policy Dashboard. https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
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    In New York, The Climate Leadership and Community Protection Act,
passed in 2019, sets several climate targets. The most important goals
include an 85 percent reduction in GHG emissions by 2050, 100 percent
zero-emission electricity by 2040, and 70 percent renewable energy by
2030. Other targets include 9,000 MW of offshore wind by 2035, 3,000 MW
of energy storage by 2030, and 6,000 MW of solar by 2025.\151\
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    \151\ New York State. Our Progress. https://climate.ny.gov/Our-Progress.
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    Washington State's Climate Commitment Act sets a target of reducing
GHG emissions by 95 percent by 2050. The State is required to reduce
emissions to 1990 levels by 2020, 45 percent below 1990 levels by 2030,
70 percent below 1990 levels by 2040, and 95 percent below 1990 levels
by 2050. This also includes achieving net-zero emissions by 2050.\152\
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    \152\ Department of Ecology Washington State. Greenhouse Gases.
https://ecology.wa.gov/Air-Climate/Climate-change/Tracking-greenhouse-gases.
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    In addition to the prevalence of State RPS and CES programs
outlined above, several states developed regulatory programs to retain
nuclear power plants to preserve the significant amount of zero-
emission output the plants provide, especially as many nuclear plants
face downward economic pressures resulting from ultra-low natural gas
spot prices combined with increasing NGCC capacity. Between 2016 and
2021, New York, New Jersey, Connecticut, and Illinois took action to
retain their nuclear power stations by providing State-level financial
incentives. Retention of nuclear power plants is another strategy that
some states have used to ensure an increasing market share for zero-
emission electricity generation. As discussed earlier, the IRA included
a zero-emission nuclear power production credit in section 13105, also
referred to as IRC section 45U.\153\
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    \153\ http://uscode.house.gov/view.xhtml?req=(title:26%20section:45U%20edition:prelim).
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    In the past two years, State actions have generally increased their
decarbonization ambitions. For example, legislation in Illinois and
North Carolina requires a transition away from GHG-emitting generation.
Illinois' Climate and Equitable Jobs Act, which became law on September
25, 2021, requires all private coal-fired or oil-fired power plants to
reach zero carbon emissions by 2030, municipal coal-fired plants to
reach zero carbon emissions by 2045, and natural gas-fired plants to
reach zero carbon emissions by 2045.\154\ On October 13, 2021, North
Carolina passed House Bill 951 that required the North Carolina
Utilities Commission to ``take all reasonable steps to achieve a
seventy percent (70%) reduction in emissions of carbon dioxide
(CO2) emitted in the State from electric generating
facilities owned or operated by electric public utilities from 2005
levels by the year 2030 and carbon neutrality by the year 2050.'' \155\
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    \154\ State of Illinois General Assembly. Public Act 102-0662:
Climate and Equitable Jobs Act. 2021. https://www.ilga.gov/legislation/publicacts/102/PDF/102-0662.pdf.
    \155\ General Assembly of North Carolina, House Bill 951 (2021).
https://www.ncleg.gov/Sessions/2021/Bills/House/PDF/H951v5.pdf.
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1. Projections of Power Sector Trends

    Projections for the U.S. power sector--based on the landscape of
market forces in addition to the known actions of Congress, utilities,
and states--have indicated that the ongoing transition will continue
for specific fuel types and EGUs. The EPA's Power Sector Modeling
Platform v6 Using the Integrated Planning Model post-IRA 2022 reference
case (i.e., the EPA's projections of the power sector, which includes
representation of the IRA absent further regulation), provides
projections out to 2050 on future outcomes of the electric power
sector. For more information on the details of this modeling, see the
model documentation.\156\
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    \156\ U.S. Environmental Protection Agency. Post-IRA 2022
Reference Case EPA's Power Sector Modeling Platform v6 Using IPM.
April 2023. https://www.epa.gov/power-sector-modeling/post-ira-2022-reference-case.
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    Since the passage of the IRA in August 2022, the EPA has engaged
with many external partners, including other governmental entities,
academia, non-governmental organizations (NGOs), and industry, to
understand the impacts that the IRA will have on power sector GHG
emissions. In addition to engaging in several workgroups, the EPA has
contributed to two separate journal articles that include multi-model
comparisons of IRA impacts across several state-of-the-art models of
the U.S. energy system and electricity sector 157 158 and
participated in public events exploring modeling assumptions for the
IRA.\159\ The EPA plans to continue collaborating with stakeholders,
conducting external engagements, and using information gathered to
refine modeling of the IRA. As such, the EPA is soliciting comment on
power sector modeling of the IRA, including the assumptions and
potential impacts, including assumptions about growth in electric
demand, rates at which renewable generation can be built, and cost and
performance assumptions about all relevant technologies, including
carbon capture, renewables, energy storage and other generation
technologies.
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    \157\ Bistline, et al. (2023). ``Emissions and Energy System
Impacts of the Inflation Reduction Act of 2022,'' Under Review.
    \158\ Bistline, et al. (2023). ``Power Sector Impacts of the
Inflation Reduction Act of 2022,'' In Preparation.
    \159\ Resource for the Future (2023). ``Future Generation:
Exploring the New Baseline for Electricity in the Presence of the
Inflation Reduction Act.'' https://www.rff.org/events/rff-live/future-generation-exploring-the-new-baseline-for-electricity-in-the-presence-of-the-inflation-reduction-act/.
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    While much of the discussion below focuses on the EPA's post-IRA
2022 reference case, many other analyses show similar trends,\160\ and
these trends are consistent with utility IRPs and public GHG reduction
commitments, as well as State actions, both of which were described in
the previous sections.
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    \160\ A wide variety of modeling teams have assessed baselines
with IRA. The baseline estimated here is generally in line with
these other estimates. Bistline, et al. (2023). ``Power Sector
Impacts of the Inflation Reduction Act of 2022,'' In Preparation.
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1. Projections for Coal-Fired Generation
    In the post-IRA 2022 reference case, coal-fired steam EGU capacity
is projected to fall from 210 GW in 2021 \161\ to 44 GW in 2035, of
which 11 GW includes retrofit CCS. Generation from coal-fired steam
generating units is projected to also fall from 898 thousand GWh in
2021 \162\ to 120 thousand GWh by 2035. This change in generation
reflects the anticipated continued decline in projected coal-fired
steam generating unit capacity as well as a steady decline in annual
operation of those EGUs that remain online, with capacity factors
falling from approximately 41 percent in 2021 to 15 percent in 2035. By
2050, coal-fired steam generating unit capacity is projected to
diminish further, with only 10 GW, or less than 5 percent of 2021

capacity (and approximately 3 percent of the 2010 capacity), still in
operation across the continental U.S. These projections are driven by
the eroding economic opportunities for coal-fired steam generating
units to operate, the continued aging of the fleet of coal-fired steam
generating units, and the continued availability and expansion of low-
cost alternatives, like natural gas, renewable technologies, and energy
storage.
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    \161\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 4.3. November 2022. https://www.eia.gov/electricity/annual/.
    \162\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/.
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    In 2020, there was a total of 1,439 million metric tons of
CO2 from the power sector with coal-fired sources
contributing to over half of those emissions. In the post-IRA 2022
reference case, power sector related CO2 emission are
projected to fall to 608 million metric tons by 2035, of which 8
percent is projected to come from coal-fired sources in 2035.
2. Projections for Natural Gas-Fired Generation
    As described in the post-IRA 2022 reference case, natural gas-fired
capacity is expected to continue to buildout during the next decade
with 61 GW of new capacity projected to come online by 2035 and 309 GW
of new capacity by 2050. By 2035, the new natural gas capacity is
comprised of 24 GW of simple cycle combustion turbines and 37 GW of
combined cycle combustion turbines. By 2050, most of the incremental
new capacity is projected to come just from simple cycle combustion
turbines. This also represents a higher rate of new simple cycle
combustion turbine builds compared to the reference periods (i.e.,
2000-2006 and 2007-2021) discussed previously in this section.
    It should be noted that despite this increase in capacity, both
overall generation and emissions from the natural gas-fired capacity
are projected to decline. Generation from natural gas units is
projected to fall from 1,579 thousand GWh in 2021 \163\ to 1,402
thousand GWh by 2035. Power sector related CO2 emissions
from natural gas-fired EGUs were 615 million metric tons in 2021.\164\
By 2035, emission levels are projected to reach 527 million metric
tons, 93 percent of which comes from NGCC sources.
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    \163\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/.
    \164\ U.S. Environmental Protection Agency, Inventory of U.S.
Greenhouse Gas Emission Sources and Sinks. February 2023. https://www.epa.gov/system/files/documents/2023-02/US-GHG-Inventory-2023-Main-Text.pdf.
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    The decline in generation and emissions is driven by a projected
decline in NGCC capacity factors. In model projections, NGCC units have
a capacity factor early in the projection period of 64 percent, but by
2035, capacity factor projections fall to 50 percent as many of these
units switch from base load operation to more intermediate load
operation to support the integration of variable renewable energy
resources. Natural gas simple cycle combustion turbine capacity factors
also fall, although since they are used primarily as a peaking resource
and their capacity factors are already below 10 percent annually, their
impact on generation and emissions changes are less notable.
    Some of the reasons for this continued growth in natural gas-fired
capacity include anticipated sustained lower fuel costs and the greater
efficiency and flexibility offered by combustion turbines. Simple cycle
combustion turbines operate at lower efficiencies but offer fast
startup times to meet peaking load demands. In addition, combustion
turbines, along with energy storage technologies, support the expansion
of renewable electricity by meeting demand during peak periods and
providing flexibility around the variability of renewable generation
and electricity demand. In the longer term, as renewables and battery
storage grow, they are anticipated to outcompete the need for natural
gas-fired generation and the overall utilization of natural gas-fired
capacity is expected to decline.
3. Projections for Renewable Generation
    The EIA's Short-Term Energy Outlook (STEO) suggests that the U.S.
will continue its expansion of wind and solar renewable capacity with
most of the growth in electricity capacity additions in the next 2
years to come from renewable energy sources.\165\ The EIA projects
utility-scale solar capacity to grow by approximately 29 GW in 2023 and
by 35 GW in 2024 wind generating capacity to grow by 7 GW in 2023 and
by 7.5 GW in 2024. These increases in new renewable capacity will
continue to reduce the demand for fossil fuel-fired generation.
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    \165\ U.S. Energy Information Administration (EIA). Short-Term
Energy Outlook, March 2023. https://www.eia.gov/outlooks/steo/.
---------------------------------------------------------------------------

    In the post-IRA 2022 reference case projections, shows that this
short-term trend in renewable capacity is expected to continue. Non-
hydroelectric utility-scale renewable capacity is projected to increase
from 209 GW in 2021 to 668 GW by 2035 and then to 1,293 GW by 2050.
This capacity growth is comprised mostly of wind and solar. The post-
IRA 2022 reference case shows projections of 399 GW of wind capacity by
2035 and 748 GW by 2050. Utility-scale solar capacity has a similar
trajectory with 263 GW by 2035 and 539 GW by 2050 and small-scale or
distributed solar capacity (e.g., rooftop solar) similarly increases
from 33 GW in 2021 to 198 GW in 2050.\166\ In total, non-hydroelectric
utility-scale renewable generation is projected to produce 45 percent
of electricity generation by 2035 in the post-IRA 2022 reference case.
---------------------------------------------------------------------------

    \166\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 4.3. November 2022. https://www.eia.gov/electricity/annual/.
---------------------------------------------------------------------------

4. Projections for Energy Storage
    According to EIA, the capacity of battery energy storage is
expected to increase by 10 times between 2019 and 2023, of which 6 GW
of battery storage capacity is planned to be co-located with solar
generation.\167\ The benefit of paring energy storage systems with
solar capacity deployment is that the batteries can recharge throughout
the middle of the day when surplus energy is available. Then this
stored energy can be discharged during peak hours, supporting grid
reliability and potentially displacing higher emitting generation. This
also reduces curtailment of renewable energy when generation exceeds
demand.
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    \167\ U.S. Energy Information Administration (EIA). Preliminary
Monthly Electric Generator Inventory, December 2020 Form EIA-860M.
https://www.eia.gov/analysis/studies/electricity/batterstorage/.
---------------------------------------------------------------------------

    The build out of energy storage is projected to continue in the
long-term, enabling the integration of renewable technologies with
lower emission consequences. The post-IRA 2022 reference case shows
projections of 97 GW of energy storage to be available on the grid by
2035 and 152 GW by 2050.
5. Projections for Nuclear Energy
    The post-IRA 2022 reference case shows a steady decline in nuclear
generating capacity, dropping from 96 GW in 2021 to 84 GW or by 12
percent by 2035. In the short-term, capacity reductions are expected to
be delayed in part due to programs passed as part of the IIJA and IRA.
These acts, along with several State programs, support the continued
use of existing nuclear facilities by providing payments that

will likely keep reactors in affected regions profitable for the next
5-10 years.168 169 After 2035, the EPA projects nuclear
capacity retirements to occur as EGUs begin to age out of operation,
and by 2050, the nuclear fleet is projected to reduce by more than
half, to 45 GW. However, breakthrough technologies like small modular
reactors, if successful, could result in higher levels of nuclear
capacity than discussed here. For example, output from advanced nuclear
generation could range from negligible to as high as 3,600 terawatt-
hours per year by 2050.\170\
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    \168\ ``Constellation Making Major Investments in Two Illinois
Nuclear Plants to Increase Clean Energy Output.'' Constellation
Energy Corporation. February 21, 2023. https://www.constellationenergy.com/newsroom/2023/Constellation-Making-Major-Investment-in-Two-Illinois-Nuclear-Plants-to-Increase-Clean-Energy-Output.html.
    \169\ Singer, S. (February 22, 2023). PSEG to consider nuclear
plant investments, capitalizing on the IRA's production tax credits,
CEO says. Utility Dive. https://www.utilitydive.com/news/pseg-ira-nuclear-production-tax-credits/643221/.
    \170\ ``Advancing Nuclear Energy Evaluating Deployment,
Investment, and Impact in America's Clean Energy Future''
Breakthrough Institute, July 6, 2022.
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V. Statutory Background and Regulatory History for CAA Section 111

A. Statutory Authority To Regulate GHGs From EGUs Under CAA Section 111

    The EPA's authority for and obligation to issue these proposed
rules is CAA section 111, which establishes mechanisms for controlling
emissions of air pollutants from new and existing stationary sources.
CAA section 111(b)(1)(A) requires the EPA Administrator to promulgate a
list of categories of stationary sources that the Administrator, in his
or her judgment, finds ``causes, or contributes significantly to, air
pollution which may reasonably be anticipated to endanger public health
or welfare.'' The EPA has the authority to define the scope of the
source categories, determine the pollutants for which standards should
be developed, and distinguish among classes, types, and sizes within
categories in establishing the standards.
1. Regulation of Emissions From New Sources
    Once the EPA lists a source category, the EPA must, under CAA
section 111(b)(1)(B), establish ``standards of performance'' for
emissions of air pollutants from new sources (including modified and
reconstructed sources) in the source category. Under CAA section
111(a)(2), a ``new source'' is defined as ``any stationary source, the
construction or modification of which is commenced after the
publication of regulations (or, if earlier, proposed regulations)
prescribing a standard of performance under this section, which will be
applicable to such source.'' Under CAA section 111(a)(3), a
``stationary source'' is defined as ``any building, structure,
facility, or installation which emits or may emit any air pollutant.''
Under CAA section 111(a)(4), ``modification'' means any physical change
in, or change in the method of operation of, a stationary source which
increases the amount of any air pollutant emitted by such source or
which results in the emission of any air pollutant not previously
emitted. While this provision treats modified sources as new sources,
EPA regulations also treat a source that undergoes ``reconstruction''
as a new source. Under the provisions in 40 CFR 60.15,
``reconstruction'' means the replacement of components of an existing
facility such that: (1) The fixed capital cost of the new components
exceeds 50 percent of the fixed capital cost that would be required to
construct a comparable entirely new facility; and (2) it is
technologically and economically feasible to meet the applicable
standards. Pursuant to CAA section 111(b)(1)(B), the standards of
performance or revisions thereof shall become effective upon
promulgation.
    The standards of performance for new sources are referred to as new
source performance standards, or NSPS. The NSPS are national
requirements that apply directly to the sources subject to them.
    In setting or revising a performance standard, CAA section
111(a)(1) provides that performance standards are to reflect ``the
degree of emission limitation achievable through the application of the
best system of emission reduction which (taking into account the cost
of achieving such reduction and any nonair quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.'' The term ``standard of
performance'' in CAA 111(a)(1) makes clear that the EPA is to determine
both the ``best system of emission reduction . . . adequately
demonstrated'' (BSER) for the regulated sources in the source category
and the ``degree of emission limitation achievable through the
application of the [BSER].'' West Virginia v. EPA, 142 S. Ct. 2587,
2601 (2022). To determine the BSER, the EPA first identifies the
``system[s] of emission reduction'' that are ``adequately
demonstrated,'' and then determines the ``best'' of those systems,
``taking into account'' factors including ``cost,'' ``nonair quality
health and environmental impact,'' and ``energy requirements.'' The EPA
then derives from that system an ``achievable'' ``degree of emission
limitation.'' The EPA must then, under CAA section 111(b)(1)(B),
promulgate ``standard[s] for emissions''--the NSPS--that reflect that
level of stringency.
2. Regulation of Emissions From Existing Sources
    When the EPA establishes a standard for emissions of an air
pollutant from new sources within a category, it must also, under CAA
section 111(d), regulate emissions of that pollutant from existing
sources within the same category, unless the pollutant is regulated
under the National Ambient Air Quality Standards (NAAQS) program, under
CAA sections 108-110, or the National Emission Standards for Hazardous
Air Pollutants (NESHAP) program, under CAA section 112. See CAA section
111(d)(1)(A)(i) and (ii); West Virginia, 142 S. Ct. at 2601.
    CAA section 111(d) establishes a framework of ``cooperative
federalism for the regulation of existing sources.'' American Lung
Ass'n, 985 F.3d at 931. CAA sections 111(d)(1)(A)-(B) require ``[t]he
Administrator . . . to prescribe regulations'' that require ``[e]ach
state . . . to submit to [EPA] a plan . . . which establishes standards
of performance for any existing stationary source for'' the air
pollutant at issue, and which ``provides for the implementation and
enforcement of such standards of performance.'' CAA section 111(a)(6)
defines an ``existing source'' as ``any stationary source other than a
new source.''
    To meet these requirements, the EPA promulgates ``emission
guidelines'' that identify the BSER and the degree of emission
limitation achievable through the application of the BSER. Each State
must then establish standards of performance for its sources that
reflect that level of stringency. However, the states need not compel
regulated sources to adopt the particular components of the BSER
itself. The EPA's emission guidelines must also permit a State, ``in
applying a standard of performance to any particular source,'' to
``take into consideration, among other factors, the remaining useful
life of the existing source to which such standard applies.'' 42 U.S.C.
7411(d)(1). Once a State receives the EPA's approval of its plan, the
provisions in the plan become federally enforceable against the source,
in the same manner as the provisions of an approved State
Implementation Plan (SIP) under the Act. If a State elects not to
submit a plan or submits a plan that

the EPA does not find ``satisfactory,'' the EPA must promulgate a plan
that establishes Federal standards of performance for the State's
existing sources. CAA section 111(d)(2)(A).
3. EPA Review of Requirements
    CAA section 111(b)(1)(B) requires the EPA to ``at least every 8
years, review and, if appropriate, revise'' new source performance
standards. However, the Administrator need not review any such standard
if the ``Administrator determines that such review is not appropriate
in light of readily available information on the efficacy'' of the
standard. Id. When conducting a review of an NSPS, the EPA has the
discretion and authority to add emission limits for pollutants or
emission sources not currently regulated for that source category. CAA
section 111 does not by its terms require the EPA to review emission
guidelines for existing sources, but the EPA retains the authority to
do so. See 81 FR 59276, 59277 (August 29, 2016) (explaining legal
authority to review emission guidelines for municipal solid waste
landfills).

B. History of EPA Regulation of Greenhouse Gases From Electricity
Generating Units Under CAA Section 111 and Caselaw

    The EPA has listed more than 60 stationary source categories under
CAA section 111(b)(1)(A). See 40 CFR part 60, subparts Cb-OOOO. In
1971, the EPA listed fossil fuel-fired EGUs (which includes natural
gas, petroleum, and coal) that use steam-generating boilers in a
category under CAA section 111(b)(1)(A). See 36 FR 5931 (March 31,
1971) (listing ``fossil fuel-fired steam generators of more than 250
million Btu per hour heat input''). In 1977, the EPA listed fossil
fuel-fired combustion turbines, which can be used in EGUs, in a
category under CAA section 111(b)(1)(A). See 42 FR 53657 (October 3,
1977) (listing ``stationary gas turbines'').
    In 2015, the EPA promulgated two rules that addressed
CO2 emissions from fossil fuel-fired EGUs. The first
promulgated standards of performance for new fossil fuel-fired EGUs.
``Standards of Performance for Greenhouse Gas Emissions From New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units; Final Rule,'' (80 FR 64510; October 23, 2015) (2015
NSPS). The second promulgated emission guidelines for existing sources.
``Carbon Pollution Emission Guidelines for Existing Stationary Sources:
Electric Utility Generating Units; Final Rule,'' (80 FR 64662; October
23, 2015) (Clean Power Plan, or CPP).
1. 2015 NSPS
    In 2015, the EPA promulgated an NSPS to limit emissions of GHGs,
manifested as CO2, from newly constructed, modified, and
reconstructed fossil fuel-fired electric utility steam generating
units, i.e., utility boilers and IGCC EGUs, and newly constructed and
reconstructed stationary combustion turbine EGUs. These final standards
are codified in 40 CFR part 60, subpart TTTT.
    In promulgating the NSPS for newly constructed fossil fuel-fired
steam generating units, the EPA determined the BSER to be a new, highly
efficient, supercritical pulverized coal (SCPC) EGU that implements
post-combustion partial CCS technology. The EPA concluded that CCS was
adequately demonstrated (including being technically feasible) and
widely available and could be implemented at reasonable cost. The EPA
identified natural gas co-firing and IGCC technology (either with
natural gas co-firing or implementing partial CCS) as alternative
methods of compliance.
    The 2015 NSPS included standards of performance for steam
generating units that undergo a ``reconstruction'' as well as units
that implement ``large modifications,'' (i.e., modifications resulting
in an increase in hourly CO2 emissions of more than 10
percent). The 2015 NSPS did not establish standards of performance for
steam generating units that undertake ``small modifications'' (i.e.,
modifications resulting in an increase in hourly CO2
emissions of less than or equal to 10 percent), due to the limited
information available to inform the analysis of a BSER and
corresponding standard of performance.
    The 2015 NSPS also finalized standards of performance for newly
constructed and reconstructed stationary combustion turbine EGUs. For
newly constructed and reconstructed base load natural gas-fired
stationary combustion turbines, the EPA finalized a standard based on
efficient NGCC technology as the BSER. For newly constructed and
reconstructed non-base load natural gas-fired stationary combustion
turbines and for both base load and non-base load multi-fuel-fired
stationary combustion turbines, the EPA finalized a heat input-based
standard based on the use of lower emitting fuels (referred to as clean
fuels in the 2015 NSPS). The EPA did not promulgate final standards of
performance for modified stationary combustion turbines due to lack of
information. These standards remain in effect today.
    The EPA received six petitions for reconsideration of the 2015
NSPS. On May 6, 2016 (81 FR 27442), the EPA denied five of the
petitions on the basis they did not satisfy the statutory conditions
for reconsideration under CAA section 307(d)(7)(B), and deferred action
on one petition that raised the issue of the treatment of biomass.
    Multiple parties also filed petitions for judicial review of the
2015 NSPS in the D.C. Circuit. These cases have been briefed and, on
the EPA's motion, are being held in abeyance while the Agency reviews
the rule and considers whether to propose revisions to it.
    In the 2015 NSPS, the EPA noted that it was authorized to regulate
GHGs from the fossil fuel-fired EGU source categories because it had
listed those source categories under CAA section 111(b)(1)(A). The EPA
added that CAA section 111 did not require it to make a determination
that GHGs from EGUs contribute significantly to dangerous air pollution
(a pollutant-specific significant contribution finding), but in the
alternative, the EPA did make that finding. It explained that
``[greenhouse gas] air pollution may reasonably be anticipated to
endanger public health or welfare,'' 80 FR 64530 (October 23, 2015) and
emphasized that power plants are ``by far the largest emitters'' of
greenhouse gases among stationary sources in the U.S. Id. at 64522. In
American Lung Ass'n v. EPA, 985 F.3d 977 (D.C. Cir. 2021), the court
held that even if the EPA were required to determine that
CO2 from fossil fuel-fired EGUs contributes significantly to
dangerous air pollution--and the court emphasized that it was not
deciding that the EPA was required to make such a pollutant-specific
determination--the determination in the alternative that the EPA made
in the 2015 NSPS was not arbitrary and capricious and, accordingly, the
EPA had a sufficient basis to regulate greenhouse gases from EGUs under
CAA section 111(d) in the ACE Rule. The EPA is not reopening or
soliciting comment on any of those determinations in the 2015 NSPS
concerning its rational basis to regulate GHG emissions from EGUs or
its alternative finding that GHG emissions from EGUs contribute
significantly to dangerous air pollution.
2. 2018 Proposal To Revise the 2015 NSPS
    In 2018, the EPA proposed to revise the NSPS for new, modified, and
reconstructed fossil fuel-fired steam generating units and IGCC units.
``Review of Standards of Performance

for Greenhouse Gas Emissions From New, Modified, and Reconstructed
Stationary Sources: Electric Utility Generating Units; Proposed Rule,''
(83 FR 65424; December 20, 2018) (2018 NSPS Proposal). The EPA proposed
to revise the NSPS for newly constructed units, based on a revised BSER
of a highly efficient SCPC, without partial CCS. The EPA also proposed
to revise the NSPS for modified and reconstructed units. The EPA has
not taken further action on this proposed rule.\171\
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    \171\ In the 2018 NSPS Proposal, the EPA solicited comment on
whether it is required to make a determination that GHGs from a
source category contribute significantly to dangerous air pollution
as a predicate to promulgating a NSPS for GHG emissions from that
source category for the first time. 83 FR 65432 (December 20, 2018).
The EPA subsequently issued a final rule that provided that it would
not regulate GHGs under CAA section 111 from a source category
unless the GHGs from the category exceed 3 percent of total U.S. GHG
emissions, on grounds that GHGs emitted in a lesser amount do not
contribute significantly to dangerous air pollution. 86 FR 2652
(January, 13 2021). Shortly afterwards, the D.C. Circuit granted an
unopposed motion by the EPA for voluntary vacatur and remand of the
final rule. California v. EPA, No. 21-1035, doc. 1893155 (D.C. Cir.
April 5, 2021).
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3. Clean Power Plan
    With the promulgation of the 2015 NSPS, the EPA also incurred a
statutory obligation under CAA section 111(d) to issue emission
guidelines for GHG emissions from existing fossil fuel-fired steam
generating EGUs and stationary combustion turbine EGUs, which the EPA
initially fulfilled with the promulgation of the CPP. See 80 FR 64662
(October 23, 2015). The EPA first determined that the BSER included
three types of measures: (1) Improving heat rate (i.e., the amount of
fuel that must be burned to generate a unit of electricity) at coal-
fired steam plants; (2) substituting increased generation from lower-
emitting NGCC plants for generation from higher-emitting steam plants
(which are primarily coal-fired); and (3) substituting increased
generation from new renewable energy sources for generation from fossil
fuel-fired steam plants and combustion turbines. See 80 FR 64667
(October 23, 2015). The latter two measures are known as ``generation
shifting'' because they involve shifting electricity generation from
higher-emitting sources to lower-emitting ones. See 80 FR 64728-29
(October 23, 2015).
    The EPA based this BSER determination on a technical record that
evaluated generation-shifting, including its cost-effectiveness,
against the relevant statutory criteria for BSER and on a legal
interpretation that the term ``system'' in CAA section 111(a)(1) is
sufficiently broad to encompass shifting of generation from higher-
emitting to lower-emitting sources. See 80 FR 64720 (October 23, 2015).
The EPA then determined the ``degree of emission limitation achievable
through the application of the [BSER],'' CAA section 111(a)(1),
expressed as emission performance rates. See 80 FR 64667 (October 23,
2015). The EPA explained that a State would ``have to ensure, through
its plan, that the emission standards it establishes for its sources
individually, in the aggregate, or in combination with other measures
undertaken by the [S]tate, represent the equivalent of'' those
performance rates (80 FR 64667; October 23, 2015). Neither states nor
sources were required to apply the specific measures identified in the
BSER (80 FR 64667; October 23, 2015), and states could include trading
or averaging programs in their State plans for compliance. See 80 FR
64840 (October 23, 2015).
    Numerous states and private parties petitioned for review of the
CPP before the D.C. Circuit. On February 9, 2016, the U.S. Supreme
Court stayed the rule pending review, West Virginia v. EPA, 577 U.S.
1126 (2016), and the D.C. Circuit held the litigation in abeyance, and
ultimately dismissed it, as the EPA reassessed its position. American
Lung Ass'n, 985 F.3d at 937.
4. The CPP Repeal and ACE Rule
    In 2019, the EPA repealed the CPP and replaced it with the ACE
Rule. In contrast to its interpretation of CAA section 111 in the CPP,
in the ACE Rule the EPA determined that the statutory ``text and
reasonable inferences from it'' make ``clear'' that a ``system'' of
emission reduction under CAA section 111(a)(1) ``is limited to measures
that can be applied to and at the level of the individual source,'' (84
FR 32529; July 8, 2019); that is, the system must be limited to control
measures that could be applied at and to each source to reduce
emissions at each source. See 84 FR 32523-24 (July 8, 2019).
Specifically, the ACE Rule argued that the requirements in CAA sections
111(d)(1), (a)(3), and (a)(6), that each State establish a standard of
performance ``for'' ``any existing source,'' defined, in general, as
any ``building . . . [or] facility,'' and the requirement in CAA
section 111(a)(1) that the degree of emission limitation must be
``achievable'' through the ``application'' of the BSER, by their terms,
impose this limitation. The EPA concluded that generation shifting is
not such a control measure. See 84 FR 32546 (July 8, 2019). Based on
its view that the CPP was a ``major rule,'' the EPA further determined
that, absent ``a clear statement from Congress,'' the term ```system of
emission reduction''' should not be read to encompass ``generation-
shifting measures.'' See 84 FR 32529 (July 8, 2019). The EPA
acknowledged, however, that ``[m]arket-based forces ha[d] already led
to significant generation shifting in the power sector,'' (84 FR 32532;
July 8, 2019), and that there was ``likely to be no difference between
a world where the CPP is implemented and one where it is not.'' See 84
FR 32561 (July 8, 2019); the Regulatory Impact Analysis for the Repeal
of the Clean Power Plan, and the Emission Guidelines for Greenhouse Gas
Emissions from Existing Electric Utility Generating Units, 2-1 to 2-
5.\172\
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    \172\ https://www.epa.gov/sites/default/files/2019-06/documents/utilities_ria_final_cpp_repeal_and_ace_2019-06.pdf.
---------------------------------------------------------------------------

    In addition, the EPA promulgated in the ACE Rule a new set of
emission guidelines for existing coal-fired steam-generating EGUs. See
84 FR 32532 (July 8, 2019). In light of ``the legal interpretation
adopted in the repeal of the CPP,'' (84 FR 32532; July 8, 2019)--which
``limit[ed] `standards of performance' to systems that can be applied
at and to a stationary source,'' (84 FR 32534; July 8, 2019)--the EPA
found the BSER to be heat rate improvements alone. See 84 FR 32535
(July 8, 2019). The EPA listed various technologies that could improve
heat rate (84 FR 32536; July 8, 2019), and identified the ``degree of
emission limitation achievable'' by ``providing ranges of expected
[emission] reductions associated with each of the technologies.'' See
84 FR 32537-38 (July 8, 2019).
    The EPA also stated that, under the ACE Rule, compliance measures
that the State plans could authorize the sources to implement ``should
correspond with the approach used to set the standard in the first
place,'' (84 FR 32556; July 8, 2019), and therefore must ``apply at and
to an individual source and reduce emissions from that source.'' See 84
FR 32555-56 (July 8, 2019). The EPA concluded that various measures
besides generation shifting--including averaging (i.e., allowing
multiple sources to average their emissions to meet an emission-
reduction goal), and trading (i.e., allowing sources to exchange
emission credits or allowances)--did not meet that requirement. The EPA
therefore barred states from using such measures in their plans. See 84
FR 32556 (July 8, 2019).

5. D.C. Circuit Decision in American Lung Association v. EPA Concerning
the CPP Repeal and ACE Rule
    Numerous states and private parties petitioned for review of the
CPP Repeal and ACE Rule. In 2021, the D.C. Circuit vacated the ACE
Rule, including the CPP Repeal. American Lung Ass'n v. EPA, 985 F.3d
914 (D.C. Cir. 2021). The court held, among other things, that CAA
section 111(d) does not limit the EPA, in determining the BSER, to
measures applied at and to an individual source. The court noted that
``the sole ground on which the EPA defends its abandonment of the [CPP]
in favor of the ACE Rule is that the text of [CAA section 111] is clear
and unambiguous in constraining the EPA to use only improvements at and
to existing sources in its [BSER].'' 985 F.3d at 944. The court found
``nothing in the text, structure, history, or purpose of [CAA section
111] that compels the reading the EPA adopted.'' 985 F.3d at 957. The
court explained that contrary to the ACE Rule, the above-noted
requirements in CAA section 111 that each State must establish a
standard of performance ``for'' any existing ``building . . . [or]
facility,'' mean that the State must establish standards applicable to
each regulated stationary source; and the requirements that the degree
of emission limitation must be achievable through the ``application''
of the BSER could be read to mean that the sources must be able to
apply the system to reduce emissions across the source category. None
of these requirements, the court further explained, can be read to
mandate that the BSER is limited to some measure that each source can
apply to its own facility to reduce its own emissions in a specified
amount. 985 F.3d at 944-51. The court likewise rejected the view that
the CPP's use of generation-shifting implicated a ``major question''
requiring unambiguous authorization by Congress. 985 F.3d at 958-68.
    Having rejected the CPP Repeal Rule's view, also reflected in the
ACE Rule, that CAA section 111 unambiguously requires that the BSER be
``one that can be applied to and at the individual source,'' the court
also ``reject[ed] the ACE Rule's exclusion from [CAA section 111(d)] of
compliance measures'' that do not meet that requirement. 985 F.3d at
957. Thus, the court held that CAA section 111 does not preclude states
from allowing trading or averaging. The court explained that the ACE
Rule's premise for its view that compliance measures are limited to
measures applied at and to an individual source is that BSER measures
are so limited, but the court further stated that this premise was
invalid. The court added that in any event, CAA section 111(d) says
nothing about the type of compliance measures states may adopt,
regardless of what the EPA identifies as the BSER. Id. at 957-58.
    The D.C. Circuit concluded that, because the EPA had relied on an
``erroneous legal premise,'' both the CPP Repeal Rule and the ACE Rule
should be vacated. 985 F.3d at 995. The court did not decide, however,
``whether the approach of the ACE Rule is a permissible reading of the
statute as a matter of agency discretion,'' 985 F.3d at 944, and
instead ``remanded to the EPA so that the Agency may `consider the
question afresh,' '' 985 F.3d at 995 (citations omitted). The court
also rejected the arguments that the EPA cannot regulate CO2
emissions from coal-fired power plants under CAA section 111(d) at all
because it had already regulated mercury emissions from coal-fired
power plants under CAA section 112. 985 F.3d at 988. In addition, the
court held that that the 2015 NSPS included a valid determination that
greenhouse gases from the EGU source category contributed significantly
to dangerous air pollution, which provided a sufficient basis for a CAA
section 111(d) rule regulating greenhouse gases from existing fossil
fuel-fired EGUs. Id. at 977.
    Because the D.C. Circuit vacated the ACE Rule on the grounds noted
above, it did not address the numerous other challenges to the ACE
Rule, including the arguments by Petitioners that the heat rate
improvement BSER was inadequate because of the limited amount of
reductions it achieved and because the ACE Rule failed to include an
appropriately specific degree of emission limitation.
    Upon a motion from the EPA, the D.C. Circuit agreed to stay its
mandate with respect to vacatur of the CPP Repeal, American Lung Assn
v. EPA, No. 19-1140, Order (February 22, 2021), so that the CPP
remained repealed. In its motion, the EPA explained that the CPP should
remain repealed because the deadline for states to submit their plans
under the CPP had long since passed. In addition, and most importantly,
because of ongoing changes in electricity generation--in particular,
retirements of coal-fired electricity generation--the emissions
reductions that the CPP was projected to achieve had already been
achieved by 2021. American Lung Assn v. EPA, No. 19-1140, Respondents'
Motion for a Partial Stay of Issuance of the Mandate (February 12,
2021). Therefore, following the D.C. Circuit's decision, no EPA rule
under CAA section 111 to reduce GHGs from existing fossil fuel-fired
EGUs remained in place.
6. U.S. Supreme Court Decision in West Virginia v. EPA Concerning the
CPP
    In 2022, the U.S. Supreme Court reversed the D.C. Circuit's vacatur
of the ACE Rule's embedded repeal of the CPP. West Virginia v. EPA, 142
S. Ct. 2587 (2022). The Supreme Court made clear that CAA section 111
authorizes the EPA to determine the BSER and the degree of emission
limitation that State plans must achieve. Id. at 2601-02. However, the
Supreme Court invalidated the CPP's generation-shifting BSER under the
major questions doctrine. The Court characterized the generation-
shifting BSER as ``restructuring the Nation's overall mix of
electricity generation,'' and stated that the EPA's claim that CAA
section 111 authorized it to promulgate generation shifting as the BSER
was ``not only unprecedented; it also effected a fundamental revision
of the statute, changing it from one sort of scheme of regulation into
an entirely different kind.'' Id. at 2612 (internal quotation marks,
brackets, and citation omitted). The Court explained that the EPA, in
prior rules under CAA section 111, had set emissions limits based on
``measures that would reduce pollution by causing the regulated source
to operate more cleanly.'' Id. at 2610. The Court noted with approval
those ``more traditional air pollution control measures,'' and gave as
examples ``fuel-switching'' and ``add-on controls,'' which, the Court
observed, the EPA had considered in the CPP. Id. at 2611 (internal
quotations marks and citation omitted). In contrast, the Court
continued, generation-shifting was ``unprecedented'' because ``[r]ather
than focus on improving the performance of individual sources, it would
improve the overall power system by lowering the carbon intensity of
power generation. And it would do that by forcing a shift throughout
the power grid from one type of energy source to another.'' Id. at
2611-12 (internal quotation marks, emphasis, and citation omitted). The
Court also emphasized that the adoption of generation shifting was
based on a ``very different kind of policy judgment [than prior CAA
section 111 rules]: that it would be `best' if coal made up a much
smaller share of national electricity generation.'' Id. at 2612. The
Court recognized that a rule based on traditional measures ``may end up
causing an incidental loss of coal's market share,'' but emphasized
that the

CPP was ``obvious[ly] differen[t]'' because, with its generation-
shifting BSER, it ``simply announc[ed] what the market share of coal,
natural gas, wind, and solar must be, and then require[ed] plants to
reduce operations or subsidize their competitors to get there.'' Id. at
2613 n. 4. Beyond highlighting the novelty of generation shifting, the
Court also emphasized ``the magnitude and consequence'' of the CPP. Id.
at 2616. It noted ``the magnitude of this unprecedented power over
American industry,'' id. at 2612 (internal quotation marks and citation
omitted), and added that the EPA's adoption of generation shifting
``represent[ed] a transformative expansion in its regulatory
authority.'' Id. at 2610 (internal quotation marks and citation
omitted). The Court also viewed the CPP as promulgating ``a program
that . . . Congress had considered and rejected multiple times.'' Id.
at 2614 (internal quotation marks and citation omitted). The Court
explained that ``[a]t bottom, the [CPP] essentially adopted a cap-and-
trade scheme, or set of state cap-and-trade schemes, for carbon,'' and
that Congress ``has consistently rejected proposals to amend the Clean
Air Act to create such a program.'' Id.
    For these and related reasons, the Court viewed the CPP as raising
a major question, and therefore, under the major questions doctrine,
required ``clear congressional authorization'' as a basis. Id.
(internal quotation marks and citation omitted). The EPA had defended
generation shifting as qualifying as a ``system of emission reduction''
under CAA section 111(a)(1), but the Court found that the term
``system'' is ``a vague statutory grant [that] is not close to the sort
of clear authorization required'' under the doctrine, id., and, on that
basis, invalidated the CPP.
    The Court declined to address the D.C. Circuit's conclusion that
the text of CAA section 111 did not limit the type of ``system'' the
EPA could consider as the BSER to measures applied at and to an
individual source. See id. at 2615 (``We have no occasion to decide
whether the statutory phrase `system of emission reduction' refers
exclusively to measures that improve the pollution performance of
individual sources, such that all other actions are ineligible to
qualify as the BSER.'' (emphasis in original)). Nor did the Court
address the scope of the States' compliance flexibilities.

C. Detailed Discussion of CAA Section 111 Requirements

    This section discusses in more detail the key requirements of CAA
section 111 for both new and existing sources that are relevant for
these rulemakings.
Approach to the Source Category and Subcategorizing
    CAA section 111 requires the EPA first to list stationary source
categories that cause or contribute to air pollution which may
reasonably be anticipated to endanger public health or welfare and then
to regulate new sources within each such source category. CAA section
111(b)(2) grants the EPA discretion whether to ``distinguish among
classes, types, and sizes within categories of new sources for the
purpose of establishing [new source] standards,'' which we refer to as
``subcategorizing.'' The D.C. Circuit has stated that whether and how
to subcategorize is a decision for which the EPA is entitled to a
``high degree of deference'' because it entails ``scientific
judgement.'' Lignite Energy Council v. EPA, 198 F3d 930, 933 (D.C. Cir.
1999); see Sierra Cub, v. Costle, 657 F.2d 298, 318-19 (D.C. Cir.
1981).
    Although CAA section 111(d)(1) does not by its terms address
subcategorization, the EPA interprets it to authorize the Agency to
exercise discretion as to whether and, if so, how to subcategorize, for
the following reasons. CAA section 111(d)(1) provides a broad grant of
authority to the EPA, directing it to ``prescribe regulations which
shall establish a procedure . . . under which each State shall submit
to the Administrator a plan [with standards of performance for existing
sources.]'' The EPA promulgates emission guidelines under this
provision directing the States to regulate existing sources. The
Supreme Court has recognized the breadth of authority that CAA section
111(d) grants the EPA:

    Although the States set the actual rules governing existing
power plants, EPA itself still retains the primary regulatory role
in Section 111(d). The Agency, not the States, decides the amount of
pollution reduction that must ultimately be achieved. It does so by
again determining, as when setting the new source rules, ``the best
system of emission reduction . . . that has been adequately
demonstrated for [existing covered] facilities.''

West Virginia, 142 S. Ct. at 2601-02 (citations omitted). That this
broad authority under CAA section 111(d) includes subcategorization
follows from the fact that these provisions authorize the EPA to
determine the BSER. Subcategorizing is a mechanism for determining
different controls to be the BSER for different sets of sources. This
is clear from CAA section 111(b)(2) itself, which authorizes the EPA to
subcategorize new sources ``for the purpose of establishing . . .
standards.'' In addition, the EPA's implementing regulations under CAA
section 111(d), promulgated in 1975, 40 FR 53340 (November 17, 1975),
provide that the Administrator will specify different emission
guidelines or compliance times or both ``for different sizes, types,
and classes of designated facilities when costs of control, physical
limitations, geographical location, or [based on] similar factors.''
\173\ In promulgating this provision, the EPA made clear the purpose of