MARVIN S. FERTEL
President and Chief Executive Officer
1201 F Street, NW, Suite 1100
Washington, DC 20004
P: 202.739.8125
msf@nei.org
nei.org
February 23, 2015
The Honorable Cheryl A. LaFleur
Chairman
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
RE:
FERC Examination of the Environmental Protection Agency’s Clean Power Plan
(Docket Number AD-15-4-000)
Dear Chairman LaFleur:
As the Federal Energy Regulatory Commission (FERC) conducts its technical conferences on the
Environmental Protection Agency’s (EPA) Clean Power Plan, the Nuclear Energy Institute1
appreciates the opportunity to provide its views on the importance of nuclear energy in reducing
the U.S. electric sector’s carbon footprint, and the critical role of FERC in achieving that goal.
Simply put, FERC will play as important a role as EPA in achieving the objectives of the Clean
Power Plan – reducing carbon emissions from the electric sector by 30 percent from 2005 levels
by 2030.
That goal will be much more difficult to the extent that additional nuclear power plants are
closed prematurely due to economic stress caused, in part, by flawed market design.
Through its oversight of market design and market policies and practices in the nation’s
organized markets, and with appropriate changes to capacity markets and energy markets, FERC
could help avert additional shutdowns, beyond those that have already occurred. In so doing,
FERC would also prevent potential degradation in reliability of electricity service.
1
NEI is responsible for establishing unified nuclear industry policy on matters affecting the nuclear energy
industry, including regulatory, financial, technical and legislative issues. NEI members include all companies
licensed to operate commercial nuclear power plants in the United States, nuclear plant designers, major
architect/engineering firms, fuel cycle facilities, materials licensees, and other organizations and individuals
involved in the nuclear energy industry.
The Honorable Cheryl A. LaFleur
February 23, 2015
Page 2
I.
Market Design, Policies and Practices Are Partly to Blame
for Nuclear Power Plant Shutdowns
In 2013 and 2014, the United States shut down two nuclear power plants, both in competitive
markets. The Kewaunee plant in Wisconsin closed in May 2013, the Vermont Yankee plant
closed in December 2014. As 2015 begins, nuclear generating assets in Illinois and in other
competitive markets are at risk. There were several reasons for the shutdowns that have occurred
– including low natural gas prices, and low growth (or no growth) in electricity demand for
several years as the U.S. economy emerges from recession. But these plants’ economic situation
was also stressed by out-of-market revenues made possible by federal and/or state mandates, by
price suppression that occurs in the energy markets, and by capacity markets that do not fully
value the attributes the nuclear plants provide.
The shutdowns that have occurred are regrettable because Kewaunee, Vermont Yankee and
others at risk were, and are, solid performers – all of them highly reliable plants with high
capacity factors and relatively low generating costs. In 2014, for example, America’s nuclear
power plants operated at a record average capacity factor of 91.9 percent. Total generating cost
(fuel, operations and maintenance and capital) averaged $40.83 per megawatt-hour (MWh) in
2013 (the last year for which data is available). Average total generating cost for the top quartile
of plants was $27.67/MWh; and for multi-unit sites (like two power stations in Illinois),
$34.50/MWh.
In our view, it makes no economic sense to shut down facilities like these because replacement
generating capacity, when needed, would likely produce more costly electricity, fewer jobs that
would pay less, and more pollution.
As you know from comments filed in other dockets before the commission, companies operating
nuclear power plants and other generating assets in the competitive markets have a number of
concerns about operation of the energy and capacity markets.
Specifically, we do not believe that wholesale markets always provide accurate price signals to
promote efficient operations, nor do they have in place mechanisms to ensure long-term resource
adequacy and reliability. For various reasons, locational marginal prices (LMPs) do not reflect
the full cost of actual operation of the generation and transmission system. Out-of-market
revenues – either as a result of federal and state mandates and incentives or as a result of RTO
actions – interfere with price formation and the price signals necessary for efficient dispatch.
Finally, wholesale markets do not always compensate generators for the attributes they provide,
including such valuable features as assured fuel supply and reliability.
The Honorable Cheryl A. LaFleur
February 23, 2015
Page 3
The nuclear energy industry applauds the actions taken by FERC to date to address these issues,
including:

In September 2013, the commission opened a proceeding to examine capacity markets in
the eastern RTOs.

In April 2014, FERC convened a technical conference to explore the vulnerabilities laid
bare by the Polar Vortex, and to discuss lessons learned and whether reforms were
necessary to preclude any repetition.

Between October and December 2014, FERC conducted a series of three workshops to
explore possible improvements to market design and operational practices in order to
ensure appropriate price formation in energy and ancillary services markets. FERC is
looking broadly at how the RTOs manage the technical, operational and market issues
that give rise to uplift payments, the levels of transparency associated with uplift, price
caps, scarcity and shortage pricing, and other issues that affect prices. In mid-January,
FERC provided participants in those workshops an opportunity to file follow-on
comments, and posed a list of substantive questions that demand consideration.

Finally, last November, FERC, recognizing the importance of fuel assurance to
reliability, ordered the RTOs to report within 90 days on the status of their efforts to
address market and system performance associated with fuel assurance issues. The
reports, filed last week, are intended to describe the nature of fuel assurance concerns
specific to each region, and the strategy the RTO has implemented, or plans to
implement, to address fuel assurance concerns. In its order, FERC noted that many of the
comments during its technical conferences on capacity markets and the Polar Vortex
questioned whether the existing markets value fuel assurance. As currently designed, the
eastern capacity market auctions establish capacity prices based on economic bids of
sellers, but do not directly take into account generator type, fuel supply arrangements, or
operational characteristics.
These initiatives at FERC are a remarkably swift response to the market conditions that are
placing certain nuclear generating units and other baseload capacity at risk, and the commission
deserves great credit for having moved aggressively to address market design, and market
policies and practices.
Obviously, the issues are not resolved, and the work to date has not yet relieved the economic
stress facing some of America’s operating nuclear units. But it appears that FERC recognizes
The Honorable Cheryl A. LaFleur
February 23, 2015
Page 4
that problems exist and is moving to develop solutions. This is a significant evolution in
thinking in a short period of time, and NEI looks forward to continuing progress and concrete
remedies. There is no time to lose: Certain nuclear power plants are operating at a loss as we
speak.
II.
Preservation of the Existing Nuclear Fleet is Essential to any Credible Program
to Reduce Carbon Emissions and to Preserve Electric Reliability
EPA’s proposal is designed to reduce carbon emissions by 30 percent from 2005 levels by 2030,
and that goal cannot be achieved without preserving the nuclear power plants that provide
approximately 20 percent of America’s electricity, and 63 percent of America’s carbon-free
electricity.
Nuclear energy provides three times more carbon-free electricity than hydropower and nearly
five times more than wind energy. Without nuclear power plants operating in 30 states, carbon
emissions from the U.S. electric sector would be approximately 25 percent higher.
For perspective, it is instructive to compare the contribution to carbon abatement from various
carbon-free sources. For example:

In June 2013, Southern California Edison Co. formally announced the permanent
shutdown of its two-unit San Onofre nuclear generating station in southern California. In
2011 (the last full year of operation for the two reactors), the station produced 18.1
billion kilowatt-hours (kWh) of carbon-free electricity. In 2013, all of California’s
carbon-free renewable generating capacity produced 16.98 billion kWh. San Onofre’s
shutdown thus more than offsets the state’s entire carbon-free renewable generation.

Exelon Corp. has made it clear that five of its nuclear reactors in Illinois are at risk of
premature shutdown. Those five reactors produced approximately 40 billion kilowatthours of carbon-free electricity in 2013 – four times total U.S. solar electricity production
(approximately 9 billion kilowatt-hours), and roughly one-fourth as much electricity as
America’s entire wind generation (approximately 170 billion kilowatt-hours).
This is not to say that nuclear energy is necessarily better than other carbon-free sources of
electricity, but simply to note that any reasoned discussion of carbon abatement strategies must
start with the facts.
The Honorable Cheryl A. LaFleur
February 23, 2015
Page 5
EPA’s proposed Clean Power Plan recognizes the critical importance of nuclear energy, and
attempts to provide states with an incentive to preserve existing nuclear generating capacity.
EPA also recognized that maintaining the existing nuclear fleet is a cost-effective carbon
abatement strategy. In its proposed rule, EPA estimated that the cost of keeping “at risk” nuclear
plants operating is $12 to $17 per metric ton of CO2 abated – lower than EPA’s estimate that:



Adding renewable capacity costs $10-$40 per metric ton of CO2 abated;
Increasing natural gas combined cycle power plant utilization rates to 70 percent costs
$30 per metric ton of CO2 abated; and
Implementing demand-side management programs costs $16-$24 per metric of CO2
abated.
It is not the purpose of this letter to restate NEI’s position on the proposed 111(d) rule. In
Attachment I, we have included the Executive Summary of NEI’s formal comments to EPA on
its proposed Clean Power Plan, which raise a number of concerns with the treatment of nuclear
energy in the proposed rule, and enumerate the reasons why the proposed rule does not achieve
EPA’s intent.
Our purpose here is simply to document the importance of nuclear energy to achieving the goals
of the Clean Power Plan, and to note that any program to reduce carbon emissions would be
seriously compromised if additional nuclear generating units shut down. To the extent market
design, policies and practices under FERC’s jurisdiction may contribute to those shutdowns, then
FERC is indirectly responsible for the success or failure of EPA’s initiative to reduce carbon
emissions from the electric sector.
In addition, nuclear power plant shutdowns may also compromise reliability of electric service
and lead to higher wholesale electricity prices. In 2013, the Illinois legislature asked four state
government agencies to analyze the impacts of closing down the five nuclear reactors named at
risk by Exelon Corp. – Clinton (in MISO), and Quad Cities 1 and 2 and Byron 1 and 2 (in PJM).
According to analysis conducted by PJM for the Illinois Commerce Commission (ICC), if
Byron, Quad Cities and Clinton retired prematurely, locational marginal prices would likely
increase between $2.70 and $3.80 per megawatt-hour in the ComEd zone, and between $0.90
and $1.50 per megawatt-hour in PJM, depending on the different scenarios and sensitivities
analyzed. In addition, annual load payments would increase between $307 million and $437
million in the ComEd zone, and between $752 million and $1.3 billion in PJM. PJM also
confirmed in its analysis that the system would be “unreliable” in 2019 under all retirement
The Honorable Cheryl A. LaFleur
February 23, 2015
Page 6
scenarios studied, with “significant thermal and voltage violations” that would require
“substantial time to correct.”
An analysis prepared by MISO at the request of the ICC found that the annual impact on electric
rates from the premature closure of Quad Cities, Clinton, and Byron would range from $810
million (base case) to $1.2 billion (high gas case).
Finally, it is worth noting that the Clean Power Plan establishes a 2030 target (30 percent
reduction in carbon emissions from 2005 levels). EPA appears to intend that carbon reductions
achieved under this rule be permanent and maintained beyond 2030.
The nation’s nuclear generating capacity is licensed for an original 40-year license term, with an
option (under the Atomic Energy Act) for license renewal for additional 20-year periods.
Approximately three-quarters of the reactors operating today have received Nuclear Regulatory
Commission (NRC) approval to operate to 60 years.
Starting in approximately 2030, however, existing nuclear power plants reach the end of 60 years
of operation. Although the industry and the NRC are now developing the framework for an
additional 20-year license renewal (past 60 years), it is not certain that all of today’s nuclear
power plants will take advantage of this option. Some of this capacity will likely seek a second
license renewal to operate past 60 years, but some will not. Additional capital investment will
almost certainly be required to operate past 60 years and, in some cases, market conditions or
other factors may not justify that capital investment.
Operation of the nation’s nuclear power plants beyond 60 years cannot be taken for granted, and
failure to address the imperfections that exist in the competitive markets will impact business
decision-making in the short-term (leading to more premature shutdowns of productive nuclear
energy assets) and in the long-term (because the probability of operating beyond 60 years will
decline).
III.
Conclusion: Time to Act
The first step toward addressing a problem is gaining recognition that a problem exists. NEI
commends the commission for having taken that first step in 2014. The challenge going forward
is to turn intellectual recognition of value into appropriate monetary recognition.
The electricity markets have changed significantly since they were restructured. Grid operators
today must balance a dynamic and complex set of circumstances:
The Honorable Cheryl A. LaFleur
February 23, 2015
Page 7






low gas prices, which result in reduced energy market revenues;
slow (or, in some regions, zero) growth in electricity demand;
state policies that mandate production from certain sources of electricity;
growing reliance on renewable and intermittent resources, which creates operational
challenges;
growing reliance on out-of market revenues; and
greater reliance on demand resources, which represent a challenge to the definition of the
capacity product.
This combination of factors has led to sustained economic stress on some existing generating
capacity, particularly baseload capacity. At a time when the surplus of generating capacity in the
eastern United States is decreasing, as existing capacity retires, effective and efficient market
design and operating practices in the capacity and energy markets are more critical than ever.
NEI believes that sustainable market design demands consideration of all the factors that
constitute a robust and resilient market. Among other things, those factors include short-term
price, long-term price stability, the value of fuel and technology diversity, environmental factors
like the Clean Power Plan and others. Short-run cost is an important and necessary metric, but
solving this complex equation for that one variable only – lowest possible short-run electricity
price – will not produce a reliable, resilient, environmental sustainable and cost-effective system
for the long-term.
Our thanks in advance for considering these comments.
Sincerely,
Marvin S. Fertel
Attachment
c:
The Honorable Philip D. Moeller, Commissioner
The Honorable Tony Clark, Commissioner
The Honorable Norman Bay, Commissioner
The Honorable Colette D. Honorable, Commissioner
Jeff Dennis, Director, Division of Policy Development
Attachment I
Executive Summary of the Nuclear Energy Institute’s comments
to the Environmental Protection Agency on EPA’s proposed rule
to reduce carbon emissions from existing power plants
under Section 111(d) of the Clean Air Act
NUCLEAR ENERGY INSTITUTE COMMENTS
ON THE ENVIRONMENTAL PROTECTION AGENCY’S PROPOSED RULE
TO REDUCE CARBON EMISSIONS FROM EXISTING POWER PLANTS
UNDER SECTION 111(d) OF THE CLEAN AIR ACT
DOCKET NO. EPA-HQ-OAR-2013-0602
EXECUTIVE SUMMARY
In the Federal Register on June 18, 2014, the Environmental Protection Agency (EPA) proposed
new regulations designed to reduce carbon emissions from existing power plants. The proposal
is designed to reduce carbon emissions by 30 percent from 2005 levels by 2030.
This goal cannot be achieved without preserving the 100 nuclear power reactors that provide
approximately 20 percent of America’s electricity, and almost two-thirds of America’s carbonfree electricity. EPA’s proposal recognizes this fact, and attempts to provide states with an
incentive to preserve existing nuclear generating capacity.
EPA also recognizes that maintaining the existing nuclear fleet is a cost-effective carbon
abatement strategy. In its proposed rule, EPA estimates that the cost of keeping “at risk” nuclear
plants operating is $12-$17 per metric ton of CO2 abated. This is lower than EPA’s estimate
that:



Adding renewable capacity costs $10-$40 per metric ton of CO2 abated;
Increasing natural gas combined cycle power plant utilization rates to 70 percent
costs $30 per metric ton of CO2 abated; and
Implementing demand-side management programs costs $16-$24 per metric of CO2
abated.
The U.S. nuclear energy industry commends EPA for recognizing the importance of nuclear
energy to any credible program to reduce carbon emissions, but EPA’s treatment of nuclear
energy in the proposed rule is fundamentally flawed. Despite the agency’s intent, the proposed
rule will not preserve nuclear power plants at risk of premature shutdown, and creates a
significant penalty for those states that have taken steps to maintain a diversified portfolio of
generating assets and reduce carbon emissions by building new nuclear power plants.
The nuclear generation component in the proposed rule is based on:
1. A percentage of existing nuclear capacity (six percent), which EPA considers at risk of
premature shutdown. Adding six percent of 2012 nuclear megawatt-hours to the
denominator when calculating a state’s intensity target will, in EPA’s view, provide states
an incentive to avoid premature nuclear shutdowns.
1
2. Nuclear plants under construction (in Georgia, South Carolina and Tennessee) are treated
as though they are already operating at 90 percent capacity factors. Output from those
plants is added to the denominator when calculating the intensity target, thereby driving
down those states’ emission rates.
For both existing nuclear generating capacity and nuclear capacity under construction, this
approach is not grounded in fact, seems purely arbitrary, and is unacceptable.
The Proposed Rule Provides No Incentive
To Preserve Existing Nuclear Generating Capacity
There is no logical or factual basis to assume that six percent of the nuclear generation in every
state with nuclear generation is “at risk.” Although there are nuclear plants at risk, they are
generally located in states with competitive markets, not evenly distributed among all states with
nuclear capacity. EPA’s approach is thus arbitrary and indefensible analytically. In some states
(depending on the make-up of the state’s generation portfolio), the six percent “at risk” factor
may have perverse and unintended consequences – i.e., a state could lose its nuclear generation,
replace only six percent of it with other zero-carbon resources, still meet the intensity target, but
total carbon emissions would increase. As a result, the six percent nuclear factor does not
achieve the intended result: It provides no incentive for states to preserve nuclear capacity at
risk.
The Proposed Rule Penalizes States with Plants Under Construction
For nuclear plants under construction, there is no logical basis to include output from these plants
in the rate-setting formula. First, these plants are not complete and not operating: Their
generating experience and their capacity to avoid emissions have yet to be established. Second,
adding potential output from these plants to the denominator in the rate-setting formula reduces
the state’s intensity target significantly, thereby penalizing states that have supported new
nuclear plant construction. For example, South Carolina’s state target is 22 percent more
stringent than it otherwise would be because of EPA’s treatment of Summer 2 and 3. Georgia’s
and Tennessee’s targets are 14 percent more stringent on this basis. This is a substantial and
unjustified penalty levied on just three states for no legitimate purpose related to the permissible
goals of the Clean Air Act.1
1
See, e.g., Motor Vehicle Mfrs.’ Ass’n v. State Farm Mut. Auto. Ins. Co., 436 U.S. 29, 2 (1983) (agency rules must
be “based on consideration of the relevant factors and within the scope of the authority delegated to the agency by
the statute”); see also Chevron U.S.A, Inc. v. NRDC, 467 U.S. 837, 845 863 (1984) (considering whether the EPA’s
action was “the policy concerns that motivated the enactment,” and noting that an agency’s rules must be based on
“a reasonable accommodation of conflicting policies that were committed to the agency’s care by the statute”
(citations and quotation marks omitted)).
2
Although the states would be able to receive credit for these new nuclear plants – by counting the
output from them in their compliance calculations – that credit is effectively nullified by
including that output in the rate-setting formula. NEI does not believe output from the nuclear
units under construction should be part of the rate-setting calculation.
NEI also strongly opposes any efforts to, in EPA’s words, “include in the state goals an
estimated amount of additional nuclear capacity whose construction is sufficiently likely to merit
evaluation for potential inclusion in the goal-setting computation.”2 There is only one justifiable
approach to new nuclear generating capacity that might be “under construction” either currently
or at some time in the future: Remove it entirely from the target-setting calculation but credit the
output to compliance.
The Appropriate Treatment for Nuclear Generating Capacity in the Rule
NEI believes that EPA must revise its proposal in order to provide proper credit for nuclear
power as a carbon-free source of electricity, and to ensure that states have a sufficient incentive
to preserve the existing nuclear fleet and to build the new nuclear energy capacity that will be
required to achieve meaningful reductions in CO2 emissions. NEI does not agree with the
proposed treatment of nuclear energy (including six percent of current nuclear generation and all
nuclear generation under construction in the rate-setting formula).
NEI also believes that two basic principles must govern the structure of any carbon reduction
program:


Avoided emissions have the same compliance value as emission reductions, and
All zero-emission sources (nuclear, renewables, hydro, energy efficiency) displace
emissions from affected units and should receive appropriate credit.
Aspects of EPA’s proposed rule under Section 111(d) fail to meet these fundamental criteria.
Renewable energy, nuclear energy and hydro receive vastly different treatment under the
proposed rule, but nuclear energy does not receive appropriate credit. Existing renewables are
included in the rate-setting formula; existing nuclear energy is not (save for six percent of
existing nuclear generation considered at risk); existing hydro is ignored. EPA’s proposal does
not explain why different generation sources are treated differently under the rule, and does not
provide appropriate credit for existing nuclear power plants.
NEI Recommendations: EPA’s 111(d) Rule Should Send States an Unequivocal Signal to
Preserve Existing Nuclear Capacity, Provide Credit for “New” Nuclear Generation

2
If EPA continues with its proposed interpretation of Best System of Emission Reduction
(BSER), the agency should remove the six percent “at risk” nuclear capacity from the
79 Fed. Reg. at 34,871.
3
goal calculation. Various stakeholders will doubtless offer alternative approaches to the
treatment of existing nuclear generation in their comments. One approach that EPA
could consider, however, is for a state to demonstrate in its plan reasonable assurance that
it will preserve its existing carbon-free generating capacity, particularly nuclear
generating capacity. For operating nuclear generating units in regulated states, such
assurance already exists because integrated utilities have a reasonable opportunity to
recover costs, plus a reasonable return. In competitive states with nuclear generating
units potentially at risk, this assurance could involve a commitment to policy changes
through legislation or regulation, or other market-based mechanisms, or a combination
that would create incentives for continued operation of these zero-emitting generators.

In the event of premature economic shutdown of a nuclear unit (most likely to occur in a
competitive market if the unit is not recovering its costs), the lost nuclear kilowatt-hours
should be subtracted from the denominator of the state’s compliance calculation. This
would provide states an unequivocal signal that existing nuclear generating capacity has
irreplaceable carbon-abatement value and must be preserved. This compliance penalty
would not apply in any situation or in any state where a nuclear unit shuts down for
reasons beyond a state’s control. This compliance penalty would only be applied for the
period between premature shutdown and the end of the unit’s remaining useful life.3

In addition, NEI recommends that EPA consider ways to provide at least some limited
compliance value for existing nuclear generating capacity, as an additional incentive to
the states to preserve that capacity. For example, in all its calculations, EPA assumes a
uniform 90-percent capacity factor for all nuclear power plants, existing and new. It is
certainly true that the U.S. nuclear fleet, on average, has consistently achieved capacity
factors in the 90-percent range for the last 15 years, but the average lifetime capacity
factor of the 100 nuclear plants now operating is 81.6 percent through 2013. Given this:
1. States could be allowed to count megawatt-hours produced by any nuclear plant
above an 81.6-percent capacity factor to be counted toward compliance; or
2. Alternatively, the same model could be applied on a state-by-state basis: All
nuclear megawatt-hours above the lifetime capacity factor of a state’s nuclear
generating units could be counted toward compliance; or
3. A single-year baseline may not be appropriate for nuclear power plants, which
typically shut down only every 18-24 months for refueling and maintenance
outages. If the baseline year happens to be a refueling outage year, it may
understate a nuclear generating unit’s long-term performance. For this reason, the
3
The intent is to provide an incentive for states in competitive markets to maintain their nuclear generating
capacity, without imposing restrictions in non-market jurisdictions. This concept requires further development
before being included in final guidelines. Critical details, such as the definition of “premature economic shutdown”
and “reasons beyond the state’s control,” must be addressed.
4
industry typically uses three-year rolling averages when evaluating nuclear plant
performance. Given this, another option might be to allow a state to count toward
compliance any nuclear megawatt-hours produced above the industry’s three-year
rolling average.
In sum, creating ways for states to capture limited compliance value for existing nuclear
generating units would directly serve and support EPA’s principal objective – ensuring
continued operation of the nation’s largest source of carbon-free generating capacity.

Remove nuclear generating capacity under construction from the rate-setting formula,
and allow states to include “new” nuclear generating capacity, when it is operating, in
their compliance calculations, thereby providing an incentive to expand carbon-free
nuclear generating capacity. “New” nuclear capacity should include:
1. New nuclear power plants (those currently under construction or others that might
be built between now and 2030 and beyond);
2. Power uprates at existing nuclear plants (which increase the plant’s capacity)
initiated at the beginning of the 2012 baseline year or thereafter;
3. Nuclear plants relicensed to operate beyond 60 years (second license renewal),
and any nuclear plants that had not received license extensions to operate beyond
their original 40-year license term as of the beginning of the 2012 baseline year.
Nuclear Plant Operation Beyond 60 Years Cannot be Treated as a Foregone Conclusion
The proposed rule establishes a 2030 target (30 percent reduction in carbon emissions from 2005
levels). EPA appears to intend that carbon reductions achieved under this rule be permanent and
maintained beyond 2030.4
The nation’s nuclear generating capacity is licensed for an original 40-year license term, with an
option (under the Atomic Energy Act) for license renewal for additional 20-year periods.
Approximately three-quarters of the reactors operating today have received Nuclear Regulatory
Commission (NRC) approval to operate to 60 years. Starting in approximately 2030, existing
nuclear power plants reach the end of 60 years of operation. Although the industry and the NRC
are now developing the framework for an additional 20-year license renewal (past 60 years), it is
not certain that all of today’s nuclear power plants will take advantage of this option. Some of
this capacity will likely seek a second license renewal to operate past 60 years, but some will not.
(In fact, some of today’s capacity may not reach 60 years.) Additional capital investment will
4
See 79 Fed. Reg. at 34,852 (noting that the rule would require each state to “achieve its final CO2 emission
performance level by 2030, and maintain it thereafter”); id. at 34,892 (“The proposed goals reflect the EPA’s
quantification of each state’s average emission rate from affected EGUs that could be achieved by 2030 and
sustained thereafter ….”).
5
almost certainly be required to operate past 60 years and, in some cases, market conditions or
other factors may not justify that capital investment.
This situation places a high premium on (1) preserving existing nuclear generating capacity by
ensuring workable regulatory requirements for second license renewal (i.e., past 60 years), and
(2) building new nuclear generating capacity to maintain, at a minimum, nuclear energy’s current
20-percent share of U.S. electricity supply.
An Integrated Energy and Environmental Policy is Essential
The electric power industry and the federal and state governments must work cooperatively to
put in place the policy instruments and financing support necessary to modernize the nation’s
electricity infrastructure, increase the use of zero-carbon or low-carbon resources, replace the
nuclear reactors that do not reach 60 years or retire at the end of 60 years of operation, and
expand the size of the U.S. nuclear fleet beyond today’s 100 gigawatts (GW) of capacity.
Absent such cooperation, nuclear energy’s share of U.S. electricity supply will likely decline,
and U.S. energy and environmental goals will be seriously compromised. A continuing, growing
contribution from nuclear energy is essential to produce baseload electricity at stable prices and
to sustain reductions in emissions of carbon and other criteria pollutants.
These challenges require an integrated, internally consistent energy and environmental policy,
involving both federal and state governments. The federal government could provide the
leadership necessary to develop such an integrated policy, but energy policy and environmental
policy remain balkanized, scattered among several Executive Branch agencies, each pursuing
separate – and not necessarily consistent – objectives. EPA’s proposed rule to reduce carbon
emissions from existing power plants continues that pattern. If it is appropriate to reduce the
electric power sector’s carbon footprint, that objective should be part of a larger set of energy
and environmental policy initiatives that provide the policy conditions necessary to achieve those
carbon reductions.
6