EPA’s Proposed Greenhouse Gas Regulations: Implications for the Electric Power Sector
EPA’s Proposed Greenhouse Gas Regulations:
Implications for the Electric Power Sector
Richard J. Campbell
Specialist in Energy Policy
June 23, 2014
Congressional Research Service
7-5700
www.crs.gov
R43621
EPA’s Proposed Greenhouse Gas Regulations: Implications for the Electric Power Sector
Summary
The Environmental Protection Agency (EPA) has proposed regulations to reduce greenhouse gas
(GHG) emissions from existing power plants. EPA believes that its proposed Clean Power Plan
(CPP) will “protect public health, move the United States towards a cleaner environment, and
fight climate change while supplying Americans with reliable and affordable power.” Burning
fossil fuels to produce electricity results in the release of carbon dioxide, and represents the
largest source of GHG emissions in the United States. Under its proposed plan, EPA believes it
will be possible to lower the carbon intensity of power generation in the United States by
approximately 30% in 2030 from carbon dioxide emissions levels in 2005. To achieve this goal,
EPA is giving each state a numerical carbon reduction target, based on the state’s existing power
generation portfolio.
Under the Clean Air Act (CAA) section 111(d), the EPA must identify the best system of emission
reductions (BSER) that is adequately demonstrated and available to reduce pollution. The
regulations allow EPA to set goals, and give states the responsibility for creating compliance
plans which meet those goals. EPA set the state-specific goals based on (1) measures which
improve the efficiency of fossil-fueled power plants, (2) use of lower-emitting generation sources
such as natural gas or fuel-switching to natural gas, and use of nuclear power, (3) demand-side
efficiency, and (4) renewable electric generation. EPA has suggested these measures as four
BSER “building blocks” or options for states to consider when choosing how to meet their
specific GHG reduction goals. Under the proposed plan, however, states would have the
flexibility to choose the most cost-effective strategies to meet the targets.
EPA’s proposal for GHG reduction answers some questions from the electric power sector with
regard to the timeframe, timeline, and choices that would be made available for compliance. The
CPP proposal sets out a vision for a greater proportion of electricity coming from natural gas and
renewable electric generation, and less from coal-fired power plants. However, some issues still
remain unresolved with the potential implementation of the CPP.
Some observers say that EPA’s CPP essentially proposes an environmental dispatch regime for
power plant operation which could potentially result in increased electricity prices to consumers,
depending on the generation resource mix employed. But EPA believes adoption of greater energy
efficiency measures will actually reduce average retail electricity bills. Compliance may require
more natural gas consumption to firm up variable renewable electric generation. Increasing the
use of natural gas for power generation has resulted in some concerns, as deliverability and price
volatility issues have emerged as recently as this past winter. Power companies, gas suppliers, and
regulatory regimes are working on resolving these issues.
The electric utility industry values diversity in fuel choice options since reliance on one fuel or
technology can leave electricity producers vulnerable to price and supply volatility. Also, state-
specific compliance plans geared to individual state needs may complicate the coordination
necessary for reliability purposes. But EPA expects coal to remain a substantial part of the U.S.
energy mix through 2030, allowing goals of fuel diversity and generating resource mix to be
maintained.
Many fossil-fueled power plants do more than just generate electricity. Some of the power plants
scheduled for retirement provide ancillary services to the grid such as voltage support and
frequency regulation. Additional retirements of coal-fired capacity resulting from implementing
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EPA’s Proposed Greenhouse Gas Regulations: Implications for the Electric Power Sector
the proposal could impact reserve margins and even grid reliability during weather-related
outages or periods of temperature extremes. Incidents of more extreme weather appear to be
occurring, and will need to be planned for when considering the types of future generation which
may be needed to assure electric system reliability.
Implementing compliance plans will not come without real costs or hard choices for the states
and electric utilities that will have to work together. Potential implications for reliability and the
ultimate financial costs of the CPP are not known but will become clearer as state compliance
plans are filed, and implementation plans become known.
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EPA’s Proposed Greenhouse Gas Regulations: Implications for the Electric Power Sector
Contents
Introduction ...................................................................................................................................... 1
Background ...................................................................................................................................... 2
EPA’s Proposed Plan for Existing Coal Plants ................................................................................. 3
Discussion of EPA’s Proposal .......................................................................................................... 4
Existing State Clean Energy Programs ................................................................................ 5
Best System of Emissions Reduction .................................................................................. 6
Fuel Switching .................................................................................................................... 8
Nuclear Power ..................................................................................................................... 9
Demand-Side Energy Efficiency ......................................................................................... 9
New Source Review .......................................................................................................... 10
Issues Related to Compliance Strategies ....................................................................................... 11
Potential Impacts on Retail Electricity Prices ................................................................... 11
Implications for Fuel Diversity ......................................................................................... 12
Conversion of Coal to Natural Gas Firing ......................................................................... 14
Regulatory, Policy, and Reliability Concerns .................................................................... 14
Potential for Varying State Impacts ................................................................................... 16
Conclusion ..................................................................................................................................... 16
Figures
Figure 1. U.S. Electricity Generation by Fuel, 2012 ....................................................................... 2
Contacts
Author Contact Information........................................................................................................... 17
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EPA’s Proposed Greenhouse Gas Regulations: Implications for the Electric Power Sector
Introduction
The Environmental Protection Agency (EPA) has proposed regulations to reduce greenhouse gas1
(GHG) emissions from existing power plants (also referred to as electric generating units or
EGUs by EPA). EPA believes that its proposed Clean Power Plan (CPP)2 will “protect public
health, move the United States towards a cleaner environment, and fight climate change while
supplying Americans with reliable and affordable power.”3 Carbon emissions are linked by many
to anthropogenic climate change,4 and the EPA cites the Obama Administration’s intent to address
climate change5 concerns in its proposed Clean Power Plan to reduce carbon emissions.
Since carbon dioxide (CO2) from fossil fuel combustion is the primary GHG, and fossil fuels are
used for the majority of electric power generation, the focus of the proposed policies is on
reducing carbon emissions from power plants. Under its proposed plan, EPA believes it will be
possible to lower the CO2 emissions from power generation in the United States by approximately
30% by 2030 compared to levels in 2005. To achieve this goal, EPA is giving each state a
numerical carbon reduction target, based on the state’s existing power generation portfolio, and
EPA’s estimate of the state’s potential to reduce power demand.
EPA’s guidelines allow a 120-day comment period on the proposal, and require states to file a
compliance plan by June 2016. States that choose to join a regional carbon reduction plan would
have until June 2018 to submit the plan. The compliance mechanism would require states to
reduce the carbon emissions rate of power plants (i.e., overall tons of carbon dioxide emitted per
each MegaWatt-hour (MWh) of electricity produced). Whether working individually or
regionally, states would be allowed to choose an appropriate mix of generation using diverse fuels
(including renewable electricity6 and nuclear power), energy efficiency, and demand-side
management to meet the goals and their own needs.7
1 Greenhouse gases, according to EPA, are any gases that absorb infrared radiation in the atmosphere. There are six
greenhouse gases addressed by EPA regulatory actions: carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O),
and fluorinated gases—sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs). Carbon
dioxide is the most prevalent GHG produced by combustion of fossil fuels. See http://www.epa.gov/climatechange/
ghgemissions/gases.html.
2 See EPA’s proposed Clean Power Plan at http://www2.epa.gov/sites/production/files/2014-05/documents/
20140602proposal-cleanpowerplan.pdf. (CPP)
3 Environmental Protection Agency, “EPA Proposes First Guidelines to Cut Carbon Pollution from Existing Power
Plants/Clean Power Plan is flexible proposal to ensure a healthier environment, spur innovation and strengthen the
economy,” press release, June 2, 2014, http://www2.epa.gov/carbon-pollution-standards/clean-power-plan-proposed-
rule.
4 “Humans tap the huge pool of fossil carbon for energy, and affect the global carbon cycle by transferring fossil
carbon—which took millions of years to accumulate underground—into the atmosphere over a relatively short time
span. As a result, the atmosphere contains approximately 35% more CO2 today than prior to the beginning of the
industrial revolution. As the CO2 concentration grows it increases the degree to which the atmosphere traps incoming
radiation from the sun, which further warms the planet.” CRS Report RL34059, The Carbon Cycle: Implications for
Climate Change and Congress, by Peter Folger.
5 Executive Office of the President, The President’s Climate Action Plan, June 2013, http://www.whitehouse.gov/sites/
default/files/image/president27sclimateactionplan.pdf.
6 Renewable electricity includes power generation from wind, solar, geothermal, and biomass sources. However, while
hydropower is generally considered as renewable, some would argue that hydropower from large dams with
impoundments have potentially harmful environmental impacts both upstream and downstream from the dam.
7 EPA says that to date, 47 states have demand-side efficiency programs, 38 have renewable portfolio standards or
goals, and 10 states have market-based greenhouse gas emissions programs.
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This report presents an analysis of EPA’s proposed plan. Electric utilities and other stakeholders
will be analyzing the CPP to understand its provisions, and have until the close of the comment
period8 to provide input. It is possible that the CPP will be modified in response to relevant
comments received. The implications of implementing a final CPP are thus unlikely to be known
until after the states file their compliance plans which are due by June 2016.
The issues for Congress will be focused on the implications of the CPP on electric power system
reliability, the costs of electric power to customers, and the future structure of the electric utility
industry which could result from implementation of compliance plans.
Background
Burning fossil fuels to produce electricity results in the release of carbon dioxide, and represents
the largest source of GHG emissions in the United States. As shown in Figure 1, fossil fuel
combustion was responsible for approximately 68% of electric power generation as of 2012.Coal
was the fuel most used. Coal is also the fossil fuel which emits the most carbon dioxide per unit
of electric power produced, averaging 216 pounds of carbon dioxide per million British thermal
units (mmBTUs) of energy produced. By comparison, natural gas combustion releases about half
the carbon emissions at 117 pounds of carbon dioxide per mmBTU of energy produced.9
Figure 1. U.S. Electricity Generation by Fuel, 2012
Trillion kiloWatt-hours per Year
Oil, other
1%
Natural Gas
Coal
30%
38%
Renewables
12%
Nuclear
19%
Source: DOE, Annual Energy Outlook, 2014 Early Release, December 16, 2013, http://www.eia.gov/forecasts/
aeo/er/early_elecgen.cfm.
Notes: Renewable electricity includes hydropower, wind, solar, and biomass power generation. “Other”
includes other liquid fuels.
8 Comments on the proposed rule must be received on or before October 16, 2014.
9 Energy Information Administration, “How Much Carbon Dioxide Is Produced When Different Fuels Are Burned?,”
June 4, 2014, http://www.eia.gov/tools/faqs/faq.cfm?id=73&t=11.
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In a 2007 decision, the Supreme Court found in Massachusetts vs. EPA10 that GHG emissions
were air pollutants which could be regulated under the Clean Air Act (CAA).11 EPA then moved
in 2009 to declare that GHGs were a threat to public health in its “endangerment” finding, which
served as a basis for its subsequent actions.12 With regard to stationary sources of GHGs, EPA
proposed standards in September 2013 for the control of carbon dioxide emissions from new
electric power plants burning fossil fuels, under CAA section 111(b) regulations.
EPA has now released a proposal for reducing carbon dioxide emissions from existing power
plants which burn fossil fuels. Under CAA 111(d), the EPA must establish a procedure under
which states will submit plans establishing standards of performance for existing fossil fuel-fired
power plants. The standards of performance are to reflect the degree of emissions limitation
achievable through the application of the best system of emission reductions (BSER) that is
adequately demonstrated and available to reduce pollution. The regulation under CAA 111(d)
allows EPA to set goals, and gives states the responsibility for creating compliance plans which
meet EPA’s guidelines.
EPA’s Proposed Plan for Existing Coal Plants13
Under the provisions of EPA’s proposed Clean Power Plan, all existing fossil fuel-fired electric
power generation plants must comply with new state-specific targets to reduce carbon
emissions.14 The combined state targets are expected to result in reducing carbon emissions from
U.S. power generation approximately 30% by 2030 compared to carbon emissions levels in 2005.
EPA has designated four “building blocks” that it used to develop the state-specific GHG
reduction goals:
1. Improve the heat rate15 of fossil-fueled power plants. EPA suggests increasing
power plant efficiency by equipment upgrades and improvements. Using less
fossil fuel to create the same amount of electricity reduces carbon emissions. An
average heat rate improvement of 6% is targeted for coal-fired power plants.16
2. Increase use of low-emitting power sources. EPA suggests more frequent use of
power plants with lower carbon emissions resulting in less carbon pollution.
Dispatching (i.e., scheduling the operation) of higher efficiency natural gas
combined cycle units more often is suggested.
10 549 U.S. 497, 529 (2007).
11 42 U.S.C. 7401 et seq. (as amended).
12 U.S. Environmental Protection Agency, Endangerment and Cause or Contribute Findings for Greenhouse Gases
under Section 202(a) of the Clean Air Act, November 22, 2013, http://www.epa.gov/climatechange/endangerment/.
13 EPA, Clean Power Plan Proposed Rule, June 2, 2014, http://www2.epa.gov/carbon-pollution-standards/clean-power-
plan-proposed-rule.
14 U.S. Environmental Protection Agency, “Carbon Pollution Emission Guidelines for Existing Stationary Sources:
Electric Utility Generating Units,” 79 Federal Register 34829, June 18, 2014. (EMEGU)
15 Heat rate is the efficiency of conversion from fuel energy input to electrical energy output often expressed in terms of
BTU per kiloWatt-hour.
16 A discussion of potential improvements at coal-fired power plants is presented in CRS Report R43343, Increasing
the Efficiency of Existing Coal-Fired Power Plants, by Richard J. Campbell.
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3. Use of more zero -emitting power sources. EPA suggests expanding renewable
electricity generation (such as zero-carbon emission wind and solar facilities),
and nuclear power plants as a way to lower carbon emissions.
4. Using electricity more efficiently. EPA suggests energy efficiency as a way to
reduce power demand, with a targeted increase in demand-side energy efficiency
of 1.5% annually.
EPA recognizes that such options are already being used by some states to promote clean energy
and efficiency goals. EPA considers a BSER to include measures which improve the efficiency of
fossil-fueled power plants, use lower emitting generation sources such as natural gas or fuel-
switching to natural gas, and use nuclear power and renewable electric generation. Under the
proposed plan, EPA believes the states have the flexibility to choose the most cost-effective
strategies to meet the targets.
States must file a plan by 2016 to comply with EPA’s state-specific goals, unless they choose to
join a multi-state regional plan. Each state has been given a unique carbon emissions reduction
goal,17 which EPA maintains offers broad flexibility in which to plan and achieve reductions in
carbon emissions. Option 1 would involve a higher level of deployment of the four building
blocks over a longer timeframe (i.e., over 15 years to 2030). EPA also suggested an alternative
path on which it is asking for comment in Option 2, which would allow a lower level of
deployment of the four building blocks but over a shorter timeframe (i.e., over ten years to 2025).
EPA has set interim and final goals for the state-specific goals under both compliance scenarios.
They can meet the goals as individual states, or join together for regional solutions.
The state goals are given as an overall rate of carbon dioxide emissions intensity, that is, the
amount of carbon dioxide emissions in pounds (lbs.) from fossil-fueled power plants divided by
the amount of electricity generated in the state (from fossil-fired generation and low- or zero-
carbon emitting power sources) in MWh. EPA estimates that the state-specific carbon reduction
goals will result in the elimination of approximately 730 million metric tonnes18 of carbon by
2030, resulting in a reduction of approximately 30% of carbon levels compared to 2005.19
Discussion of EPA’s Proposal
Electric power generation in the United States differs regionally, and largely reflects local
resources, fuel costs, and availability of fuel supplies.20 EPA recognizes that it will take time to
implement compliance solutions to meet its proposed carbon pollution reduction plan. EPA has
attempted to provide flexibility for state compliance with its plan for reducing carbon emissions
from existing fossil-fueled power plants.
The EPA is also proposing to give states considerable flexibility with respect to the
timeframes for plan development and implementation, with up to two or three years
17 EMEGU, Table 8, Proposed State Goals.
18 One tonne (also known as a metric ton) is a unit of mass equaling 1,000 kilograms.
19 EPA, EPA Fact Sheet—Cutting Carbon Pollution from Power Plants, June 2, 2014, http://www2.epa.gov/sites/
production/files/2014-06/documents/20140602fs-important-numbers-clean-power-plan.pdf.
20 Edison Electric Institute, Different Regions of the Country Use Different Fuel Mixes to Generate Electricity, 2014,
http://www.eei.org/issuesandpolicy/generation/fueldiversity/Documents/map_fuel_diversity.pdf.
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permitted for final plans to be submitted after the proposed GHG emission guidelines are
finalized, and up to fifteen years for all emission reduction measures to be fully
implemented.21
While 2005 has been mentioned in broader U.S. policy terms for reductions in GHG emissions to
2030, it is not the year that EPA has used in its emissions reduction calculation. EPA chose 2012
as the year from which to establish a baseline for emissions reduction since that was the year for
which it has the most complete state emissions, net generation, and capacity data for all affected
EGUs.
For purposes of establishing state goals, historical (2012) electric generation data are used to
apply each building block and develop each state’s goal (expressed as an adjusted CO2
emission rate in lbs per MWh).22
Many regard this as beneficial for many states since U.S. GHG emissions overall have dropped
15% between 2005 and 2012.23
Existing State Clean Energy Programs
EPA also considers expanding state renewable electric programs and portfolio standards as tools
to reduce GHG emissions. However, for purposes of establishing a baseline, existing hydropower
is not included.
Hydropower generation is excluded from this existing 2012 generation for purposes of
quantifying BSER-related [renewable electricity] generation potential because building the
methodology from a baseline that includes large amounts of existing hydropower generation
could distort regional targets that are later applied to states lacking that existing hydropower
capacity. The exclusion of pre-existing hydropower generation from the baseline of this
target-setting framework does not prevent states from considering incremental hydropower
generation from existing facilities (or later-built facilities) as an option for compliance with
state goals.24
However, states will not receive credit for “early action” taken to reduce GHGs in the period prior
to the timeframe of the proposal. Therefore, GHG reductions resulting from state renewable
portfolio standards (and other similar measures) in the period from 2005 to 2012 will not count
towards GHG reductions in the 2020 to 2030 timeframe. But since they are programs already in
place, EPA considers these programs as helpful to meeting state-specific goals in the compliance
timeframe.
The EPA is also proposing that measures a state takes after the date of this proposal, or
programs already in place, which result in CO2 emissions reduction during the 2020-2030
period, would apply toward achievement of the state’s 2030 CO2 emissions goal. Thus, states
21 EMEGU, p. 34940.
22 EMEGU, p. 34863.
23 Matthew Philips, “EPA Did the Power Industry a Big Favor by Using 2005 Levels,” Bloomberg BusinessWeek, June
2, 2014, http://www.businessweek.com/articles/2014-06-02/epa-did-the-power-industry-a-big-favor-by-using-2005-
levels.
24 EMEGU, p. 34867.
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with currently existing programs and policies, and states that put in new programs and
policies early, will be better positioned to achieve the goals.25
While states must begin compliance with the proposed plan by 2020, full compliance is not
required until 2030. EPA points out that its four building blocks are suggested as a framework for
implementation; the states themselves will decide how to meet their goals. EPA also suggests that
regional compliance strategies would be acceptable under its proposal.
Each state will have the flexibility to design a program to meet its goal in a manner that
reflects its particular circumstances and energy and environmental policy objectives. Each
state can do so alone or can collaborate with other states on multi-state plans that may
provide additional opportunities for cost savings and flexibility.26
In establishing the state-specific goals for GHG reduction, EPA believes it has taken into
consideration the regional differences that exist in power generation types and resources. Each
state’s goal reflects the fact that a state’s CO2 emissions are a result of how efficiently its fossil-
fueled power plants operate, and how much they operate. Under the state-specific goals, the
highest allowed rate of GHG emissions is 1,783 lbs. of CO2 per MWh of electricity produced for
North Dakota, while the lowest emissions rate is 215 lbs. of CO2 per MWh in Washington state,27
with the apparent disparity in state goals reflecting the existing underlying generation mix in the
states.
Best System of Emissions Reduction
EPA has modeled the opportunities for heat rate improvement, dispatch of more gas and less coal,
increased renewable and nuclear generation, and end-use energy efficiency. The agency considers
these actions representing the “Best System of Emissions Reductions” which is adequately
demonstrated.28
Overall, the BSER proposed here is based on a range of measures that fall into four main
categories, or “building blocks,” which comprise improved operations at EGUs, dispatching
lower-emitting EGUs, and zero-emitting energy sources, and end-use energy efficiency. All
of these measures have been amply demonstrated via their current widespread use by utilities
and states.
The proposed guidelines are structured so that states would not be required to use each and
every one of the measures that the EPA determines constitute the BSER or to apply any one
of those measures to the same extent that the EPA determines is achievable at reasonable
cost. Instead, in developing its plan, each state will have the flexibility to select the measure
or combination of measures it prefers in order to achieve its CO2 emission reduction goal.29
25 EMEGU, p. 34839.
26 EMEGU, p. 34833.
27 EMEGU, Table 8.
28 EPA, Office of Air and Radiation, Goal Computation Technical Support Document, Technical Support Document for
the CAA Section 111(d) Emission Guidelines for Existing Power Plants, June 2014, http://www2.epa.gov/sites/
production/files/2014-05/documents/20140602tsd-goal-computation.pdf.
29 EMEGU, p. 34835.
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As part of the BSER determination, the EPA considered the impacts that implementation of
the emission reductions [based on the combination of the blocks] would have on the cost of
electricity and electricity system reliability.... Importantly, the proposed BSER, expressed as
a numeric goal for each state, provides states with the flexibility to determine how to achieve
the reductions (i.e., greater reductions from one building block and less from another) and to
adjust the timing in which reductions are achieved, in order to address key issues such as
cost to consumers, electricity system reliability and the remaining useful life of existing
generation assets.30
The EPA is proposing to evaluate and approve state plans based on four general criteria: 1)
enforceable measures that reduce EGU CO2 emissions; 2) projected achievement of emission
performance equivalent to the goals established by the EPA, on a timeline equivalent to that
in the emission guidelines; 3) quantifiable and verifiable emission reductions; and 4) a
process for biennial reporting on plan implementation, progress toward achieving CO2 goals,
and implementation of corrective actions, if necessary.31
In devising a compliance strategy, EPA proposes to allow each state to design a GHG reduction
program using strategies or technologies the state selects.
To meet its goal, each state will be able to design programs that use the measures it selects,
and these may include the combination of building blocks most relevant to its specific
circumstances and policy preferences. States may also identify technologies or strategies that
are not explicitly mentioned in any of the four building blocks and may use those
technologies or strategies as part of their overall plans (e.g., market-based trading programs
or construction of new natural combined cycle units or nuclear plants).32
EPA believes that shifting electric power production from coal-fired power plants to natural gas
combined-cycle generation (NGCC) represents a major opportunity to reduce GHG emissions
due to the greater overall efficiency of the newer NGCC generation fleet especially as compared
to older coal-fired power plants, and the current underutilization of NGCC generation capacity.
Our analysis indicated that the potential CO2 reductions available through re-dispatch from
steam EGUs to NGCC units are substantial. As of 2012, there was approximately 245 GW of
NGCC capacity in the United States, 196 GW of which was placed in service between 2000
and 2012. In 2012, the average utilization rate of U.S. NGCC capacity was 46 percent, well
below the utilization rates the units are capable of achieving. In 2012, approximately 10
percent of NGCC plants operated at annual utilization rates of 70 percent or higher, and 19
percent of NGCC units operated at utilization rates of at least 70 percent over the summer
season. Average reported availability generally exceeds 85 percent. We recognize that the
ability to increase NGCC utilization rates may also be affected by infrastructure and system
considerations, such as limits on the ability of the natural gas industry to produce and deliver
the increased quantities of natural gas, the ability of steam EGUs to reduce generation while
remaining ready to supply electricity when needed in peak demand hours, and the ability of
the electric transmission system to accommodate the changed geographic pattern of
generation.33
30 EMEGU, p. 34836.
31 EMEGU, p. 34838.
32 EMEGU, p. 34837.
33 EMEGU, p. 34857.
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The amount of re-dispatch from coal-fired EGUs to NGCC units that takes place as a result
of this competition is highly relevant to overall power sector GHG emissions, because a
typical NGCC unit produces less than half as much CO2 per MWh of electricity generated as
a typical coal-fired EGU.34
Under its proposal, EPA has suggested a range of equipment upgrades and improvement options
to increase heat rates (specifically at existing coal-fired power plants), which it believes
represents cost-effective opportunities to reduce GHG emissions.
Our assessment of heat rate improvements showed that these measures would achieve CO2
emission reductions at low costs, although compared to other measures, the available
reductions were relatively limited in quantity. Specifically, our analysis indicated that
average CO2 emission reductions of 1.3 to 6.7 percent could be achieved by coal-fired steam
EGUs through adoption of best practices, and that additional average reductions of up to four
percent could be achieved through equipment upgrades. Heat rate improvements pay for
themselves at least in part through reductions in fuel costs, generally making this a relatively
inexpensive approach for reducing CO2 emissions. We estimated that CO2 reductions of
between four and six percent from overall heat rate improvements could be achieved on
average across the nation’s fleet of coal-fired steam EGUs for net costs in a range of $6 to
$12 per metric ton.35
Although heat rate improvements have the potential to reduce CO2 emissions from all types
of affected EGUs, the EPA’s analysis indicates the potential is significantly greater for coal-
fired steam EGUs than for other EGUs, and for purposes of determining the best system of
emission reduction at this time EPA is conservatively proposing to base its estimate of CO2
emission reductions from heat rate improvements on coal-fired steam EGUs only.36
Fuel Switching
EPA sees the opportunity for coal to natural gas conversions at existing power plants (rather than
co-firing coal and natural gas together) as having a great potential to reduce GHGs. While
converting a coal-fired power plant to natural gas would be considered a higher cost option
compared to other heat rate improvements, EPA believes the incremental difference in the cost of
fuel would be the most significant cost component.
Natural gas co-firing or conversion at coal-fired steam EGUs offers greater potential CO2
emission reductions than heat rate improvements, but at a higher cost (although less than the
cost of applying CCS [Carbon Capture and Storage] technology). Because natural gas
contains less carbon than an energy-equivalent quantity of coal, converting a coal-fired steam
EGU to burn only natural gas would reduce the unit’s CO2 emissions by approximately 40
percent. The CO2 reductions are generally proportional to the amount of gas substituted for
coal, so if an EGU continued to burn mostly coal while co-firing natural gas as, for example,
10 percent of the EGU’s total heat input, the CO2 emission reductions would be
approximately four percent. The EPA determined that the most significant cost associated
with natural gas conversion or co-firing is likely to be the incremental cost of natural gas
relative to the cost of coal. 37
34 EMEGU, p. 34862.
35 EMEGU, p. 34856.
36 EMEGU, p. 34859.
37 EMEGU, p. 34857.
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Nuclear Power
Another higher cost option would be the construction of new nuclear power plants. However,
EPA views the completion of nuclear units currently under construction, and avoiding the
“premature” retirement of an estimated 6% of existing nuclear capacity, to be important to GHG
reduction goals in some states.38
Policies that encourage development of renewable energy capacity and discourage premature
retirement of nuclear capacity could be useful elements of CO2 reduction strategies and are
consistent with current industry behavior. Costs of CO2 reductions achievable through these
policies have been estimated in a range from $10 to $40 per metric ton.39
Nuclear generating capacity facilitates CO2 emission reductions at fossil fuel-fired EGUs by
providing carbon-free generation that can replace generation at those EGUs. Because of their
relatively low variable operating costs, nuclear EGUs that are available to operate typically
are dispatched before fossil fuel-fired EGUs. Increasing the amount of nuclear capacity
relative to the amount that would otherwise be available to operate is therefore a technically
viable approach to support reducing CO2 emissions from affected fossil fuel-fired EGUs.40
We have determined that, based on available information regarding the cost and performance
of the nuclear fleet, preserving the operation of at-risk nuclear capacity would likely be
capable of achieving CO2 reductions from affected EGUs at a reasonable cost.41
In addition to the nuclear generation taken into account in the state goals analysis, any
additional new nuclear generating units or uprating of existing nuclear units, relative to a
baseline of capacity as of the date of proposal of the emission guidelines, could be a
component of state plans.42
Demand-Side Energy Efficiency
The fourth building block of the BSER identified by EPA is “cost-effective” demand-side energy
efficiency programs.
The purposes of demand-side energy efficiency programs vary; goals include to reduce GHG
emissions by reducing fossil-fired generation, help states achieve energy savings goals, save
energy and money for consumers and improve electricity reliability. They are typically
funded through a small fee or surcharge on customer electricity bills, but can also be funded
by other sources, such as from CO2 [allowance auction program] proceeds. 43
California has been advancing energy efficiency through utility-run demand-side energy
efficiency programs for decades and considers energy efficiency “the bedrock upon which
climate policies are built.” It requires its investor-owned utilities to meet electricity load
38 “EIA in its most recent Annual Energy Outlook has projected an additional 5.7 GW of capacity reductions to the
nuclear fleet.... [EPA views] this 5.7 GW, which comprises an approximately six percent share of nuclear capacity, as a
reasonable proxy for the amount of nuclear capacity at risk of retirement.” EMEGU, p. 34871.
39 EMEGU, p. 34858.
40 EMEGU, p. 34870.
41 EMEGU, p. 34871.
42 EMEGU, p. 34923.
43 EMEGU, p. 34849.
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“through all available energy efficiency and demand reduction resources that are cost-
effective, reliable and feasible.”44
Demand-side energy efficiency programs produce electricity-dependent services with less
electricity, and thereby support reduced generation from existing fossil fuel-fired EGUs by
reducing the demand for that generation. Reduced generation results in lower CO2 emissions.
More than 40 states already have established some form of demand-side energy efficiency
polices, and individual states have avoided up to 13 percent of their electricity demand.45
New Source Review
The New Source Review46 (NSR) program was designed to prevent the degradation of air quality
from the construction of new facilities or modification of existing facilities which have
potentially harmful emissions. Efficiency improvements to power plants that reduce regulated
pollutants should not theoretically trigger NSR requirements, unless the improvements result in
an increase in emissions (e.g., because the modified plant operates for more hours). EPA has
proposed that states be given a primary role with regard to NSR determinations.
As part of its CAA section 111(d) plan, a state may impose requirements that require an
affected EGU to undertake a physical or operational change to improve the unit’s efficiency
that results in an increase in the unit’s dispatch and an increase in the unit’s annual
emissions. If the emissions increase associated with the unit’s changes exceeds the
thresholds in the NSR regulations discussed above for one or more regulated NSR pollutants,
including the netting analysis, the changes would trigger NSR.
While there may be instances in which an NSR permit would be required, we expect those
situations to be few. As previously discussed in this preamble, states have considerable
flexibility in selecting varied measures as they develop their plans to meet the goals of the
emissions guidelines. One of these flexibilities is the ability of the state to establish the
standards of performance in their CAA section 111(d) plans in such a way so that their
affected sources, in complying with those standards, in fact would not have emissions
increases that trigger NSR. To achieve this, the state would need to conduct an analysis
consistent with the NSR regulatory requirements that supports its determination that as long
as affected sources comply with the standards of performance in their CAA section 111(d)
plan, the source’s emissions would not increase in a way that trigger NSR requirements. 47
The EPA is aware of the potential for “rebound effects” from improvements in heat rates at
individual EGUs. In this context, a rebound effect would occur where, because of an
improvement in its heat rate, an EGU experiences a reduction in variable operating costs that
makes the EGU more competitive relative to other EGUs and consequently raises the EGU’s
generation output. The increase in the EGU’s CO2 emissions associated with the increase in
generation output would offset the reduction in the EGU’s CO2 emissions caused by the
decrease in its heat rate and rate of CO2 emissions per unit of generation output. The extent
of the offset would depend on the extent to which the EGU’s generation output increased (as
well as the CO2 emission rates of the EGUs whose generation was displaced). The EPA
44 EMEGU, p. 34850.
45 EMEGU, p. 34858.
46 NSR was established by Congress as part of the 1977 Clean Air Act Amendments (P.L. 95-95), and is codified in
sections 165-169 of the act. NSR requires pre-construction permits and the application of Best Available Control
Technology at new major sources of air pollution, and at major modifications of existing major sources.
47 EMEGU, p. 34928.
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considers the rebound effect to be a potential concern if heat rate improvements were the
only approaches being considered for the BSER, but believes that the effect can be addressed
by establishing the BSER as a combination of approaches that includes not only heat rate
improvements but also approaches that will encourage reductions in electricity demand or
increases in generation from lower- or zero-emitting EGUs.48
Issues Related to Compliance Strategies
The EPA’s proposal for GHG reduction answers questions from the electric power sector with
regard to the timeframe, timeline, and choices that would be made available for compliance. The
CPP proposal sets out a vision for a greater proportion of electricity coming from natural gas and
renewable electric generation, and less from coal-fired power plants, with state-specific goals for
carbon emissions reductions proposed for 2030. However, there are still some unresolved issues
remaining with potential implementation of the CPP.
Potential Impacts on Retail Electricity Prices
Under the Energy Policy Act of 2005 (P.L. 109-58), security constrained economic dispatch is
defined in section 1234 as follows:
... the operation of generation facilities to produce energy at the lowest cost to reliably serve
consumers, recognizing any operational limits of generation and transmission facilities.
EPA’s CPP recognizes that security constrained economic dispatch “assures reliable and
affordable electricity.”49 However, some observers say that EPA’s CPP essentially proposes an
environmental dispatch regime for power plant operation.50 Under environmental dispatch, the
goal is to use “cleaner” power generating units (i.e., which emit the least pollutants) by
scheduling these plants to operate first and as much as possible to serve load demands.
Power plants today are generally scheduled to operate (i.e., dispatched) under an economic
dispatch regime whereby power generation units are dispatched using generating units with the
lowest costs. Thus, under these economic dispatch regimes, the cost of power generation is
characterized by a power plant’s efficiency or heat rate, its variable costs of generation, its
variable costs of environmental compliance, and its start-up costs.51
The increased availability of natural gas has resulted in lower prices for wholesale electricity,
with a general expectation that wholesale prices will remain relatively low for the next few
years.52 EPA has conceded that this increased demand could push natural gas prices higher.53
48 EMEGU, p. 34859.
49 EMEGU, p. 34862.
50 “Scheduling of power plant operation or intertie access in the order of increasing damage to the environment, with
the least environmentally damaging first.” See http://www.bpa.gov/news/pubs/Pages/Definitions---E.aspx.
51 FERC Staff, Economic Dispatch: Concepts, Practices and Issues, Federal Energy Regulatory Commission,
November 13, 2005, http://www.ferc.gov/eventcalendar/Files/20051110172953-FERC%20Staff%20Presentation.pdf.
52 See EIA, Natural Gas Section, at http://www.eia.gov/forecasts/archive/aeo13/
source_natural_gas_all.cfm#netexporter.
53 “Under both approaches, the shifting in generation from higher-emitting steam EGUs to lower-emitting NGCC units
results in an increase in natural gas production and price. The two-block approach results in a production increase of
(continued...)
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There is a concern that shifting to an environmental dispatch regime could potentially result in
increased electricity prices to consumers, depending on the generation resource mix employed.
However, EPA expects only a “modest impact” on retail prices will result.
As described below in Section X, the results indicate that the proposed state goals (discussed
in Section VII) are readily achievable with no adverse impacts on electricity system
reliability, and that impacts on retail electricity prices are modest and fall within the range of
price variability seen historically in response to changes in factors such as weather and fuel
supply.54
Retail electricity prices are projected to increase 6 to 7 percent under Option 1 and increase
by roughly 4 percent under Option 2, both in 2020 and on an average basis across the
contiguous U.S. By 2030 under Option 1, electricity prices are projected to increase by about
3 percent.55
Moreover, EPA expects that energy efficiency measures may lead to an actual reduction in the
average retail bill for electricity of 9% by 2030.
Average monthly electricity bills are anticipated to increase by roughly 3 percent in 2020,
but decline by approximately 9 percent by 2030. This is a result of the increasing penetration
of demand-side programs that more than offset increased prices to end users by their
expected savings from reduced electricity use.56
Implications for Fuel Diversity
EPA’s CPP proposal ostensibly involves natural gas consumption under two of the four legs of the
BSER stool. EPA has suggested shifting the dispatch of power generators to lower-emitting
sources by increased scheduling of higher efficiency natural gas combined cycle units.
Scheduling these plants will result in higher natural gas consumption.57 EPA has also suggested
using more zero-emitting sources by deploying more renewable generation, which in many parts
of the United States will require more natural gas consumption to make variable renewable
electric generation more firm (i.e., provide power as renewable electric generation ebbs).
(...continued)
19-22 percent and a price increase of 10-11 percent. The four-block approach results in a production increase of 12-14
percent and a price increase of 9-12 percent.” EMEGU, p. 34933.
54 EMEGU, p. 34885.
55 EMEGU, p. 34935.
56 EMEGU, p. 34934.
57 “Given that significant underutilized NGCC exists in various U.S. regions, the possibility of further shifting from
coal base load plants to natural gas intermediate capacity exists. A recent study by the Massachusetts Institute of
Technology in 2011 noted that the existing U.S. NGCC generation fleet had an average capacity factor of
approximately 41%, while its design capacity allowed such plants to operate at 85%. The MIT study looked at a
scenario across selected regions of the United States which mimicked the ‘full dispatch’ of existing natural gas
combined cycle plants. The study concluded that under such a scenario (while noting that transmission constraints
exist), there is ‘sufficient surplus NGCC capacity to displace roughly one-third of U.S. coal generation, reducing CO2
emissions from the power sector by 20%.’” See CRS Report R42950, Prospects for Coal in Electric Power and
Industry, by Richard J. Campbell, Peter Folger, and Phillip Brown. (CoalProspects)
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As of 2012, electric power generation used 8.5 trillion cubic feet (TCF) of natural gas.58 EPA’s
CPP proposal essentially favors a switch to natural gas as the primary fuel used for power
generation, and estimates an increase of 1.2 TCF over 2012 consumption in 2020.59 However,
increasing the use of natural gas for power generation raises some concerns, as deliverability and
price volatility issues have emerged as recently as this past winter with the demand spikes
associated with the Polar Vortex cold weather events.60 Recovery of costs from the Polar Vortex
have proved to be an issue for some utilities,61 and the performance of demand response programs
in periods of extreme weather (e.g., in the winter especially) have come under question.62
FERC is working to improve coordination between the electricity and natural gas industries.63
Electricity generators get their natural gas from major pipelines or local distribution companies,
and these deliveries are usually scheduled during nomination cycles.64 More cost-effective,
natural gas storage facilities may be required for electric power production purposes, if greater
natural gas use for power generation is expected. However, the regulatory regime (i.e., Regional
Transmission Organization markets or traditional regulation) in place will likely have a bearing
on what choices are available to natural gas generators with regard to gas storage options or
contracting for firm capacity vs. the “just-in-time” manner of natural gas deliveries traditionally
available to power generators.
The electric utility industry values diversity in fuel choice options since reliance on one fuel or
technology can leave electricity producers vulnerable to price and supply volatility. EPA’s
proposal expects additional retirements of coal-fired power plants, with some new NGCC
capacity likely built to replace retiring coal capacity. Nuclear power plants are also aging, and
some plants expected to be in operation in the 2020 to 2030 timeframe could face premature
58 EIA Annual Energy Outlook 2014.
59 EMEGU, p. 34934.
60 FERC, 2014Winter 2013-2014 Operations and Market Performance in RTOs and ISOs, AD14-8-000, April 1, 2014,
http://www.ferc.gov/legal/staff-reports/2014/04-01-14.pdf.
61 Veronique Bugnion, The Polar Vortex Wreaks Havoc On Utility Bills, Energy Collective, January 31, 2014,
http://theenergycollective.com/vbugnion/334481/polar-vortex-wreaks-havoc-utility-bills.
62 “Not all events requiring commitment of demand resources will occur during the spring, summer, and early fall,
when the Limited and Extended Summer Demand products apply. As the Commission’s gas-electric coordination
investigation has shown, reliability problems can occur during the winter when gas-fired generators may have difficulty
with obtaining natural gas or transportation of natural gas. See Communication of Operational Information Between
Natural Gas Pipelines and Electric Transmission Operators, Order No. 787, FERC Stats. & Regs. ¶ 31,350 (cross-
referenced at 145 FERC ¶ 61,134, at P 8 (2013)) (“short term swings in demand by gas-fired electric generators
resulting from redispatch by electric transmission operators may be difficult to manage, particularly during times of
coincident peak loads on interstate natural gas pipelines and electric transmission systems, such as during unusual cold
weather events when end-use customers may rely on both natural gas and electricity”). See also PJM supplemental
answer at 7 (discussing PJM’s need for demand response during the polar vortex on January 7 and 8, 2014, and
indicating that all of its demand response was Limited Demand Response and therefore could not be required to run).”
See 146 FERC ¶ 61,052, footnote 48.
63 FERC, Natural Gas—Electric Coordination, June 2014, http://www.ferc.gov/industries/electric/indus-act/electric-
coord.asp.
64 “The natural gas industry generally follows the scheduling cycles adopted by the [North American Energy Standards
Board (NAESB)], which FERC regulations incorporate by reference. The NAESB standards set a nationwide natural
gas operating day (Gas Day), beginning at 9:00 a.m. CCT [Central Clock Time] and ending at 9:00 a.m. CCT the
following day. Current regulations provide for a minimum of four standard nomination cycles over that 24-hour period
with a ‘Timely Cycle’ and ‘Evening Cycle’ for nominations closing in the prior day and two ‘Intra-Day’ nominations
during the Gas Day.” See http://www.vnf.com/2311.
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retirement for a variety of reasons ranging from plant age to electricity market or other
conditions.
Unless electricity storage capacity is increased or other concepts develop, natural gas will likely
be used to smooth the variable output of some renewable electricity technologies. The developing
potential for a heavier reliance on natural gas for power generation is a concern for many in the
power sector. EPA, for its part, believes that its BSER proposal can help preserve fuel diversity
goals.
Large vertically integrated utilities generally have options within all four building blocks.
They tend to have large and, as a general matter, at least somewhat diverse generation fleets.
For their higher-emitting units, they have opportunities to use measures that reduce the units’
CO2 emission rates, such as heat rate improvements, co-firing, or fuel switching. While this
proposal preserves fuel diversity, with over 30 percent of projected 2030 generation coming
from coal and over 30 percent from natural gas, even companies that have traditionally
depended upon coal to supply the majority of their generation are diversifying their fleets,
increasing their opportunities for re-dispatch.65
Conversion of Coal to Natural Gas Firing
Switching a coal burning plant to natural gas can be a major undertaking as the boiler, fuel
handling, and fuel storage areas would have to be modified or replaced. A major engineering
study would have to be undertaken to determine the cost and extent of work to be performed for a
specific power plant unit. Coal power plants can have multiple units (i.e., with separate steam
boilers), some of varying ages and designs. A power plant location near a major natural gas
pipeline would make supplying natural gas to the facility easier, although a local natural gas
distribution company could also supply the fuel.
Adding a gas turbine to an existing steam turbine would be one option, but not without challenges
or significant modifications based on the age of the existing steam turbine and balance of plant.
Moderate increases in plant efficiency are possible from such a modification. A conversion to a
combined-cycle configuration could be a major modification, both in terms of work performed
and cost. But a considerable increase in power output and efficiency could result from such an
upgrade.66
Regulatory, Policy, and Reliability Concerns
State-specific compliance plans geared to individual state needs may complicate the coordination
necessary for reliability purposes. The individual state compliance plans required by EPA’s CPP
may have to be submitted to multiple jurisdictions (i.e., state public utility commissions, Regional
Transmission Organizations, the North American Electric Reliability Corporation, and FERC) at a
number of deliberative levels before a compliance plan can be finalized.67
65 EMEGU, p. 34886.
66 See Table 1, “Summary of Emission Reduction Scenarios,” Congressional Distribution Memorandum CD145,
Summary of Studies on Achieving Increased Coal Power Plant Efficiency and Lower Carbon Dioxide Emissions,
January 15, 2014, http://rsinquery.loc.gov/crsx/products-nd/14.5.doc.pdf.
67 See CoalProspects, “Electricity Reliability—State and Market Inputs.”
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Many fossil-fueled power plants do more than just generate electricity. Many power plants
provide ancillary services such as voltage support and frequency regulation to the grid. Additional
retirements of coal-fired capacity can impact reserve margins, potentially impacting reliability
when needed during weather-related outages or periods of temperature extremes.
Incidents of more extreme weather appear to be occurring, and will need to be planned for when
considering the types of future generation which may need to be built to assure electric system
reliability.68 EIA currently expects that a total of 60 GigaWatts of coal capacity will retire by
2020, with 90% of these retirements taking place by 2016 “coinciding with the first year of
enforcement for the Mercury and Air Toxics Standards.”69 Much of this capacity scheduled for
retirement was dispatched during the recent Polar Vortex, adding concern to how the grid will
meet power demands in future weather extremes.70
EPA’s CPP proposal relies on state-implemented renewable portfolio standards (RPSs) and energy
efficiency resource standards going forward. However, many state renewable portfolio standards
and goals are scheduled to expire in the 2015 to 2020 timeframe, with more by 2025.71 And many
state RPS policies with mandatory requirements have cost caps to ensure that the targets can be
met cost-effectively. Similarly, many state energy efficiency resource standards are expiring by
2020.72
The transmission system itself is aging and in need of modernization.73 The grid is stressed in
many regions because the system is being used in a manner for which it was not designed. More
transmission capacity will likely be needed to handle potentially more transmission transactions
under the EPA proposal. Much of the transmission system was built by individual electric utilities
to serve their own power plants. New power plants or increased use of existing NGCC capacity
may require upgraded transmission facilities, and potentially new natural gas infrastructure to
provide fuel. Increased dependence on renewable generation will likely require new transmission
lines, and many of today’s transmission projects awaiting regulatory approvals are intended to
serve renewable electricity projects.
FERC identified public policy requirements (such as state renewable portfolio standards) as
drivers which should be elevated to the level of reliability when it comes to approving new
transmission projects in its Order No. 1000, Transmission Planning and Cost Allocation.74 Actual
implementation of regional compliance plans will demonstrate whether the regime for
transmission planning and cost sharing will achieve FERC’s goals.
68 See CRS Report R42696, Weather-Related Power Outages and Electric System Resiliency, by Richard J. Campbell.
69 Energy Information Administration, “AEO2014 Projects More Coal-Fired Power Plant Retirements by 2016 Than
Have Been Scheduled,” February 14, 2014, http://www.eia.gov/todayinenergy/detail.cfm?id=15031.
70 Matthew L. Wald, “Coal to the Rescue, but Maybe Not Next Winter,” The New York Times, March 10, 2014,
http://www.nytimes.com/2014/03/11/business/energy-environment/coal-to-the-rescue-this-time.html?_r=0.
71 Database of State Incentives for Renewables and Efficiency, Renewable Portfolio Standard Policies, March 2013,
http://www.dsireusa.org/documents/summarymaps/RPS_map.pdf.
72 American Council for an Energy-Efficient Economy, State Energy Efficiency Resource Standards, April 2014,
http://www.aceee.org/files/pdf/policy-brief/eers-04-2014.pdf.
73 Dwayne Stradford, The Revitalization, Modernization of the Aging Transmission System, Electric Light & Power,
January 1, 2012, http://www.elp.com/articles/2012/01/the-revitalization-modernization-of-the-aging-transmission-
system.html.
74 See discussion of Order No. 1000 in CRS Report R41193, Electricity Transmission Cost Allocation, by Richard J.
Campbell and Adam Vann.
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The focus of the EPA’s CPP proposal will arguably fall on coal-fired power plants, with at least
two of the four building blocks centering on coal plant efficiency, dispatch, and emissions. The
age and condition of coal-fired power plants are key considerations in a decision to upgrade or
modify plants. Power plants in Regional Transmission Organization (RTO) regions operate in
competitive environments where a power plant’s operating and maintenance costs are not
guaranteed recovery. The additional costs of plant upgrades may not be cost-effective under RTO
electricity market regimes or prices. State implementation plans for EPA’s CPP may also result in
differing requirements within RTO regions for competitive generators. Capacity markets designed
to incentivize the construction of new generation in regions with competitive markets have had
mixed results. New power plants will most likely be built in regions of the country with
traditional regulation using tools like integrated resource planning, and rules allowing cost
recovery from ratepayers for approved investments.75
Potential for Varying State Impacts
EPA’s state-specific GHG emissions goals vary considerably in magnitude, leading to concerns
that some states may have much more to do than others and thus compliance with the CPP could
result in “winners and losers.” The approach to compliance taken by each state will certainly have
a unique cost and economic impact, and these could vary considerably between states. However,
EPA asserts the benefits of GHG reduction will far outweigh these costs. The agency says that the
state-specific goals reflect each state’s unique emissions profile and generation resource mix, and
maintains that the flexibility offered by its “building blocks” approach will allow states the
opportunity to choose a strategy capable of minimizing compliance costs and economic impacts.
Similarly, we recognize and appreciate that states operate with differing circumstances and
policy preferences. For example, states have differing access to specific fuel types, and the
variety of types of EGUs operating in different states is broad and significant. States are part
of assorted EGU dispatch systems and vary in the amounts of electricity that they import and
export. For these reasons, we also recognize and appreciate the value in allowing and
promoting multi-state reduction strategies.76
Conclusion
Moving forward, EPA GHG regulations can provide a basis for the evolution of the U.S. Electric
Power Sector. EPA recognizes that the grid and many of its fossil-fueled power plants are aging,
and provides input via the CPP as to how a future national system providing cleaner energy
choices could be powered. EPA believes the benefits of a cleaner environment from its plan are
without question. However, meeting the goals of EPA’s proposed plan will effectively require less
power generation from coal-fired power plants, or even outright retirements of coal-fired
generation. Considering the average age of the coal-fired power plant fleet, more retirements are
likely when the costs of efficiency improvements or upgrades are weighed in compliance plans.
EPA is not proposing the adoption of any new technologies, but suggests a framework for
transition. Implementing compliance plans will not come without real costs or making hard
75 Generally, an Integrated Resource Plan is a 10- to 20-year look forward at options for meeting future energy demand
which is revisited typically every three to five years to help ensure the continued validity of the planning process.
76 EMEGU, p. 34855.
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choices for the states and electric utilities who will have to work together to find an acceptable
compromise. The potential implications for reliability, and the ultimate financial costs of the CPP
will become clearer as state compliance plans are filed, and implementation plans become known.
Author Contact Information
Richard J. Campbell
Specialist in Energy Policy
rcampbell@crs.loc.gov, 7-7905
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