Nuclear Energy 2014 - 2015:
Recognizing the Value
Nuclear Energy Institute Briefing
For the Financial Community
February 12, 2015
Good morning. I’m Marvin Fertel, president and CEO of the Nuclear Energy Institute. Thank
you for joining us this morning for our annual briefing.
Last year at this time, we had lost one nuclear plant – the Kewaunee plant in Wisconsin – to
adverse market conditions. We knew the Vermont Yankee plant would close at the end of 2014
for the same reasons. We also knew that other nuclear generating assets in Illinois and in other
competitive markets were at risk.
As we gather here in February 2015, Vermont Yankee did close down permanently last month.
Like Kewaunee, Vermont Yankee was a well-managed, solid performer that fell victim to a
market that did not compensate the facility for the attributes it provided. And we still have other
nuclear assets in Illinois and other competitive markets at risk.
It sounds like the same story, but it’s not. This year is different.
This year begins with something that we did not have at this time last year – recognition of the
value of these assets.
2014 was the year when many people – in the policy community, in the federal and state
governments, in the regional transmission organizations and elsewhere in the electric power
industry – reawakened to the value of America’s nuclear generating assets.
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The first step toward addressing a problem is gaining recognition that a problem exists, and I
believe we took that first step in 2014. Our challenge going forward is to turn intellectual
recognition of value into real, monetary recognition.
The electricity markets have changed significantly since they were restructured. Grid operators
today must balance a dynamic and complex set of circumstances:
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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.
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Here is what we plan to cover this morning. We’ll start by discussing the business and policy
environment, particularly as it relates to our merchant assets, then recap some of the major
events and activities from last year, and close with some thoughts about 2015 and beyond.
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When we spoke to you last year about the economic stress facing some of our nuclear plants
operating in competitive markets, we suggested several rather simple and basic propositions to
help frame the issues.
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First, we suggested to you that there was nothing wrong with any of the plants at risk.
Kewaunee, Vermont Yankee and others at risk were all solid performers – all of them highly
reliable plants with high capacity factors and relatively low generating costs. When Vermont
Yankee closed last month, it had just completed a 633-day continuous run.
Second, we suggested to you that it made no economic sense to allow these facilities to close
because replacement generating capacity, when needed, would likely produce more costly
electricity, fewer jobs that would pay less, and more pollution.
Third, we suggested that goods and services will only be produced in a competitive market when
they are priced and valued in the market. This is straightforward, practical economics. There are
no free goods.
We are accustomed to thinking of electricity as an undifferentiated bulk commodity. That is a
mistake. Every kilowatt-hour of electricity on the grid has a unique pedigree or set of attributes.
And all resources are not equal. Demand resources that can be called only on limited occasions
for short periods of time do not have the same reliability or resource value as a generating plant.
And all generating capacity is not the same. Each source of electricity has its own set of
attributes that provide varying degrees of value to the grid, and those attributes must be reflected
in the total compensation provided to each generator.
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Nuclear generating capacity has its own set of attributes, starting with production of large
quantities of electricity around the clock, safely and reliably. Nuclear power plants have fuel on
site and will run when needed. They also provide price stability, and portfolio value, and clean
air compliance value. All these attributes are valuable. Many are not paid for.
Sound market design must begin with a systematic inventory of the attributes of the various
forms of electric generating capacity that have value to the electricity grid. Unless and until
these attributes are recognized and priced, markets run the risk that they will disappear.
Fourth, and finally, we suggested 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 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 and affordable system for the long-term.
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Our industry devoted substantial resources to broadcasting these basic propositions widely across
the country in 2014. NEI and our companies used their own communications platforms and
programs, and we created a new campaign – called Nuclear Matters – to raise awareness of the
significant challenges facing our nation’s largest source of carbon-free electricity. Two wellregarded political figures chair this campaign – former Indiana Governor and United States
Senator Evan Bayh, a Democrat, and former New Hampshire Governor and Senator Judd Gregg,
a Republican.
Working with them, we have assembled an outstanding Leadership Council who have agreed to
serve as the voices for this campaign, including:
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Carol Browner, former EPA Administrator and special assistant to President Obama for
climate and energy policy
Spence Abraham, Energy Secretary under President Clinton
David Wright, former chairman of the South Carolina Public Service Commission and
former president of the National Association of Regulatory Utility Commissioners
Vicky Bailey, former commissioner on the Federal Energy Regulatory Commission
Bill Daley, former White House chief of staff and Secretary of Commerce
Former U.S. Senator Blanche Lincoln of Arkansas
Sean McGarvey, president of the Building and Construction Trades Union, and
Ed Hill, president of the International Brotherhood of Electrical Workers
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You may have seen the advertising associated with the Nuclear Matters campaign, because that
tends to be the most visible evidence of this initiative. But most of the work is being done at
events in the states where we have operating plants at risk, and seeks to educate state and local
government officials about the potential threat to reliable electricity supply at a reasonable price.
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Although we know the Nuclear Matters campaign and our other advocacy programs have had an
impact, two other events last year had as much – if not more – impact on the policy-making
process. One was the succession of five periods of extreme cold in January, February and March
that we refer to collectively as the Polar Vortex. The other was the proposal by the Obama
Administration’s Environmental Protection Agency to reduce carbon emissions from operating
coal-fired power plants under section 111(d) of the Clean Air Act.
Both focused attention squarely on the value of our nuclear power plants. One served as a
reminder that assured fuel on site – or, in our case, 12 to 24 months of fuel in the reactor core – is
a valuable attribute, and that the nuclear plants run when needed, whether or not the wind is
blowing, or the sun shining, whether or not fuel arrives just in time through a pipeline.
EPA’s proposed 111(d) rule shone a bright light on the fact that nuclear energy is our largest
carbon-free source of electricity, and that any credible program to reduce carbon emissions
would be seriously compromised if we lose operating plants.
As you know, the Polar Vortex uncovered some significant vulnerabilities in the electric supply
system. In PJM, during the extreme cold in early January 2014, a little over 40,000 megawatts –
22 percent of PJM’s installed capacity – was forced out of service because coal piles and coalhandling equipment froze, gas wells froze at the wellhead, fuel oil deliveries and barge traffic
were interrupted, or gas-fired plants simply could not get natural gas at any price. Almost
10,000 megawatts of gas-fired capacity in PJM could not run for lack of fuel. In MISO,
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approximately 33,000 megawatts of capacity was forced out of service and, again, roughly onequarter of that was gas-fired capacity that could not get gas.
Through it all, the nuclear units performed admirably – on average running at capacity factors in
the mid-90 percent range. We expect that from them, of course, and the point here is not that one
source of electricity is necessarily better than another. The point is that fuel and technology
diversity is the bedrock of a reliable, resilient system, and premature shutdown of nuclear units
compromises that portfolio value.
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Since last winter, we have seen significant movement on the part of the Federal Energy
Regulatory Commission and in a number of Regional Transmission Organizations to address
some of the underlying problems.
FERC had already opened – in September 2013 – a proceeding to examine capacity markets in
the eastern RTOs. FERC then convened a technical conference in April to explore the
vulnerabilities laid bare by the Polar Vortex, and to discuss lessons learned and whether reforms
were necessary to preclude any repetition.
All of us recognize that capacity market design is important, but we also recognize that most of
the revenue – 75 percent or more – is in the energy markets, and that continuing price
suppression in the energy markets would negate any improvements to the capacity markets. As
one expert told the FERC during the Commission’s technical conference on capacity markets:
“The number one priority for fixing capacity markets may well be fixing the energy markets.”
Prices in the energy markets are being suppressed in various ways – either because of out-ofmarket actions by the RTOs, which compromise price formation, or as a consequence of state
and federal mandates and out-of-market revenues. The FERC has already determined that outof-market subsidies can harm capacity markets, and has approved a Minimum Offer Price Rule
(MOPR) or similar mechanism in each of the eastern RTOs to minimize the effects of subsidies
in capacity markets.
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Subsidies can also compromise competitive market outcomes in the markets for energy.
Allowing market participants to reflect out-of-market revenues in their bids into the energy
markets distorts and suppresses competitive price signals. In addition, in the energy markets, the
RTOs frequently use out-of-market dispatch. As a result, the marginal resource’s offer is not
reflected in the energy market clearing price. Instead it is uplifted, so the price paid for all
resources in the energy market doesn’t appropriately reflect the scarcity value of that marginal
unit.
FERC also 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.
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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, which we should see
next week, will 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 units and other baseload capacity at risk, and it is obviously all to the
good for the operating nuclear plants, since fuel assurance is one of those attributes that, in our
view, deserves compensation.
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In April, at FERC’s conference on the Polar Vortex, a PJM executive suggested that the RTO
might be coming back to FERC with changes to reflect the value of fuel assurance.
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By December, PJM had requested FERC approval of a new “capacity performance” product to
drive greater reliability. In exchange for meeting higher performance standards, qualifying
generators (like nuclear power plants) would receive increased capacity payments. It appears
that generating units with relatively high forced outage rates – which, in PJM, includes
combustion turbines, coal fired power plants and gas-fired steam turbine generators – will incur
materially higher ongoing maintenance outlays, and incremental costs to reserve adequate gas
transmission capacity to ensure availability during cold weather, to meet PJM’s more stringent
reliability requirements. The nuclear generating assets, with an average forced outage rate over
the last 12 months of 1.9 percent, well below the PJM average of 5.7 percent, will not face these
costs and should be the major beneficiaries of the upward pressure on capacity prices.
The point here is not that the problem is solved, or that work underway has yet relieved the
economic stress facing some of the operating nuclear units. The point is that federal regulators,
state officials and the RTOs now clearly recognize that problems exist and are moving to
develop solutions. It is a significant evolution in thinking in a short period of time, and we look
forward to continuing progress because there is no time to lose. As you know, we have nuclear
plants operating at a loss as we speak.
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I said earlier that 2014 was all about recognizing the value of these assets, and the recent series
of reports to the Illinois state legislature from various state agencies provides dramatic proof of
that value.
According to analysis conducted by PJM for the Illinois Commerce Commission, 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, load payments would increase between $307 million and $437 million in the ComEd
zone, and between $752 million and $1.3 billion in PJM. That is one year’s impact. Remember
that these plants have several decades’ useful life left in them. PJM also confirmed in its
analysis that the system would be “unreliable” in 2019 under all retirement scenarios studied,
with “significant thermal and voltage violations” that would require “substantial time to correct.”
These impacts generally comport with our own analyses of nuclear power stations at risk. In
Illinois, losing all five reactors at risk would eliminate 2,500 direct jobs – those people working
at the plants. Total job losses – direct and indirect – in the first year would be 9,000. The direct
economic value lost in the first year would be $2.4 billion. Add to this another $1.2 billion in
indirect economic value in Illinois – that is, the value created in the counties and state from
having the plants there. And those losses ripple through time, year upon year.
We have also analyzed the economic impacts of losing other nuclear plants at risk.
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The Davis-Besse plant in Ohio generated nearly $500 million in direct economic value in 2014
and total economic value – direct and indirect – of $1.1 billion in Ohio. In addition, the facility
represents 700 jobs at the station, which creates an additional 4,600 jobs in other industries.
In upstate New York, Ginna produces approximately $230 million in direct economic value, and
total economic value to the state – direct and indirect – of $365 million. In addition, Ginna
provides 700 direct jobs and an additional 800 indirect jobs in the state.
This does not include taxes paid to county, state and federal governments. Exelon’s nuclear
operations in Illinois generate nearly $1.1 billion in federal taxes every year, and about $290
million in state taxes.
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Let me turn now to the Environmental Protection Agency’s proposed rule to reduce carbon
emissions from existing coal-fired plants, which focused attention on another valuable attribute
of nuclear energy.
EPA’s proposal is designed to reduce carbon emissions by 30 percent from 2005 levels by 2030,
and that goal simply 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. EPA’s proposal recognizes this fact, and attempts to provide states with an incentive
to preserve existing nuclear generating capacity.
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 31 states, carbon
emissions from the U.S. electric sector would be approximately 25 percent higher.
For perspective, the five reactors at risk in Illinois, by themselves, produced approximately 40
billion kilowatt-hours of carbon-free electricity in 2013 – four times total U.S. solar electricity
production, and roughly one-fourth as much electricity as America’s entire wind generation.
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:
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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.
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For each state with installed nuclear generating capacity, EPA included six percent of its nuclear
output in the equation used to calculate the state’s emission rate. The intent was undeniably
good – to create an incentive for states to preserve existing nuclear capacity – but, unfortunately,
it doesn’t work.
There is no logical basis to assume that six percent of the nuclear generation in every state with
nuclear generation is “at risk.” The nuclear plants at risk are not evenly distributed among all
states with nuclear capacity and, in those states with nuclear plants at risk, they typically
represent more than six percent of the carbon-free generation. 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 – in other words, a state could lose its nuclear generation, replace
only six percent of it with other zero-carbon resources, replace the rest with fossil-fueled
generation, still meet the intensity target, but total carbon emissions would increase.
In order to preserve existing nuclear capacity, NEI urged EPA to consider requiring states to
demonstrate in their state implementation plans how they intend to preserve their nuclear plants.
For regulated states, that would be a relatively straightforward showing. For states with
competitive markets, it could require the state to commit to policy changes or other mechanisms
to preserve their nuclear capacity. We also suggested that it might be appropriate to build a
compliance incentive into the final rule: If a state allowed a nuclear plant to close, those lost
carbon-free kilowatt-hours should count against that state’s compliance obligation.
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In addition, we believe that power uprates and license renewals should be considered new
capacity and count toward compliance, as an incentive to preserve and expand existing nuclear
generating capacity.
EPA also proposed to include output from the five nuclear plants under construction in the ratesetting formula, as though they were already operating at 90 percent capacity factors. This is not
acceptable. Adding potential output from these plants to the rate-setting formula reduces the
state’s intensity target significantly, thereby penalizing states that are taking action to
significantly reduce their carbon emissions. 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.
NEI does not believe output from the nuclear units under construction should be part of the ratesetting calculation, although they obviously should count toward compliance when operating.
Just to give you a sense of the market uplift we might see if EPA’s regulation were to be issued
as proposed, modeling by PJM showed EPA’s interim goals could be achieved in the PJM states
for a carbon fee as low as $15 or $20 per ton. The Electric Reliability Council of Texas found
that similar costs, between $20 and $25 per ton, would suffice to achieve ERCOT’s more
stringent final goal. According to comments on the 111(d) proposal filed by one of our
companies with EPA, compliance could be achieved with an average increase in consumer costs
of two to five percent for the 2020 to 2030 period. By way of comparison, average retail electric
rates rose 35 percent between 2003 and 2013 and an average of 3.2 percent between 2013 and
2014.
Understand, however, that this is an enormously complex and invasive proposal, which
generated a wide range of comment within the electric industry – from approval to vigorous
opposition. We have no way of predicting the outcome, but the President regards this as a legacy
issue so we are quite certain that EPA will publish the final rules governing existing facilities and
new facilities sometime this summer. After that: Almost certain litigation, probably all the way
to the Supreme Court.
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To wrap up our discussion of the business and policy environment, we believe we now have an
opportunity to address the problems and shortcomings we see in the markets.
Compared to last year at this time, when many policymakers were unaware of the challenges
facing our nuclear generating assets, the FERC, EPA, the RTOs and many states now recognize
the value of well-performing nuclear power plants and the consequences of allowing them to
shut down. When nuclear power plants close down prematurely, thousands of people lose their
jobs. Consumers lose reliable, relatively low-cost sources of electricity that would continue to
run at a stable price for decades. States and counties lose hundreds of millions of dollars in tax
revenue and other benefits. State and national initiatives to reduce carbon emissions are
seriously compromised.
We also see growing recognition that the solution to shortcomings in the capacity and energy
markets is to monetize the valuable attributes of the various sources of electricity, including
nuclear energy, and to address the issues that inhibit appropriate price formation in the energy
markets. The industry will continue to work with all stakeholders to ensure that the nuclear
plants receive appropriate compensation for the value they provide.
Whatever happens, remember that the companies forced to shut down these plants will relieve
stress on their earnings and negative pressure on their credit metrics. And the nuclear energy
industry in America will certainly survive – and, in fact, grow over the long-term. We shut down
10 reactors for various reasons in the 1990s, and our world did not end. In fact, nuclear energy
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continued to provide approximately 20 percent of America’s electricity, as the remaining plants
improved their performance to keep pace with growing electricity demand.
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Let me now recap some of the key events and activities from 2014.
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First, plant performance.
Nuclear generation in 2014 was 1.2 percent higher than 2013. According to our estimates, the
fleet operated at an all-time record capacity factor – 91.9 percent.
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We won’t have the 2014 cost data until midyear but, in 2013, U.S. nuclear plants operated at
about $41 per megawatt-hour on average, a nine percent decrease from $45 per megawatt-hour
in 2012. This was the first decrease we’ve seen since 2007. You can see in the bar chart on the
right that the first quartile operated below $28 per megawatt-hour.
That is total generating cost, which includes fuel, operating and maintenance costs, and capital.
Fuel costs in 2013 were up slightly, operating costs down slightly, and capital spending down
significantly. We invested $6.4 billion in the plants in 2013, a 25 percent decrease from the $8.6
billion in capex the year before.
When you combine the $2.2 billion reduction in capex between 2012 and 2013 and suspension of
the nuclear waste fee, which I’ll discuss later, we’ve taken about $3 billion out of the nuclear
industry’s cost structure in the last two years.
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We’ve told you for a couple of years now that capex runs in cycles. We put a large number of
nuclear power plants in service in a relatively short period of time, so we should expect to see
periodic surges in capex as plant equipment is replaced and upgraded. We’ve also told you that
we expect to see some moderation in capital spending going forward, and we believe we saw the
first signs of that in 2013.
Here’s a snapshot of the capex numbers, broken down into four major categories.
Almost one-half of total capex in 2013 went to spending on power uprates, steam generator and
vessel head replacements and other items necessary for operation beyond 40 years.
Routine replacement of equipment accounted for about one-quarter of the total and has been
relatively flat over the last several years.
Capex associated with compliance with the Nuclear Regulatory Commission’s regulations and
requirements was also about one-quarter of the total, and that has increased significantly in the
last 10 years.
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In fact, regulatory capex has roughly doubled since 2005.
This is a source of concern and we are working with the Nuclear Regulatory Commission on
several major initiatives designed to ensure maximum efficiency from capital and O&M
spending imposed by the regulatory process. We cannot afford to let spending to meet
regulatory requirements of low safety significance crowd out more important industry-driven
initiatives that would make measurable improvements to safety and reliability.
Addressing the cumulative impact of NRC regulatory actions, and self-imposed industry
requirements, is one of our highest priorities – made more urgent by the economic stress facing
some of our plants.
The industry will always invest what is necessary to ensure safety and reliability. But over the
years, the number of regulatory requirements has increased – including some 60 agency
rulemaking proposals now under consideration. The companies that operate nuclear plants must
devote resources to comply with these requirements, some of which do little to enhance safety.
As in any other business, managers at nuclear plants have finite resources and must make
decisions about what activities to perform. Regulatory activities are traditionally given top
priority. That means other work may be deferred – even if the work being deferred has greater
safety benefit. The industry believes that activities with the greatest safety benefit should be
scheduled first, regardless of who initiated them.
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The challenge is compounded by NRC cost-benefit analyses that significantly underestimate the
implementation cost of new requirements. Where a significant safety issue is involved, cost is
not a consideration. In most cases, however, the NRC is required by its regulations to determine
whether proposed changes will provide a safety benefit commensurate with cost. A valid
assessment requires an accurate cost estimate. A report last December by the Government
Accountability Office concluded that the NRC’s cost-benefit analysis procedures “do not support
the creation of reliable cost estimates.” The GAO report is consistent with the industry’s
experience. Data collected by the Nuclear Energy Institute show that the actual costs to
implement worker fatigue rules were two to five times the NRC’s estimate; for new fire
protection regulations, six times the NRC’s estimate; and for new security requirements, 19
times the NRC’s estimate.
We are developing tools to address these issues. Last summer, six nuclear plants pilot-tested a
new methodology that aggregates NRC-driven and plant-initiated activities, then ranks them
based on safety importance. All of the plants identified actions of low safety importance –
including regulatory actions – that had been scheduled ahead of actions with significantly higher
safety importance. With further refinements, the industry hopes to use this approach to ensure
that the most safety-important projects are completed first.
The industry is encouraging the NRC staff to apply this process internally to all types of
regulatory requirements, not just rulemaking. For example, in fiscal year 2013, the agency
issued fewer than 15 rules, but there were more than 50 generic communications, including
notices, advisories and other regulatory actions – all of which required resources to implement.
The U.S. nuclear industry has an enviable safety record. In the most recent 15 years of reporting
to Congress on operations at NRC-licensed facilities, the agency has identified only four
incidents deemed significant enough to mention as “abnormal occurrences.” This safety record
is not consistent with a doubling of regulatory capex over the last 10 years.
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As you know, we have five reactors under construction.
Unit 2 at the Tennessee Valley Authority’s Watts Bar station will be the first to reach
commercial operation.
Watts Bar 2, an 1100-megawatt reactor, will be TVA’s seventh nuclear plant. TVA halted
construction at Watts Bar 2 in 1985, with about $1.7 billion invested and the plant about 80
percent complete.
TVA estimates Watts Bar 2 will be completed between September 2015 and June 2016, with a
most likely completion date of December 2015, at an expected cost between $4 billion and $4.5
billion.
Last December, TVA completed cold hydrostatic testing, which verified that welds, joints, pipes
and other components in the reactor coolant system, steam-supply system and associated highpressure systems do not leak and will hold pressure. The final pressure test was successfully
conducted in mid-December.
The next major milestone at Watts Bar 2 will be hot functional testing, when the entire nuclear
system will be heated to operating temperature and pressure.
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By the way, TVA’s nuclear ambitions extend beyond Watts Bar 2. The company also plans to
apply to the NRC for an early site permit – the first step in the licensing process – to build a
small modular reactor at its Clinch River site in Tennessee.
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The new plant projects in Georgia and South Carolina achieved several major milestones over
the past year.
At Southern Nuclear Operating Company’s Vogtle Unit 3 and SCANA’s V.C. Summer Unit 2,
workers have installed the CA20 module. This is part of the auxiliary building that is located
outside and adjacent to the containment vessel. It will house various plant components,
including the used fuel storage area. The CA20 is considered a “super-module” because it is too
large to transport and requires assembly on site. With a total load weight of approximately two
million pounds, this module is one of the heaviest lifts on the construction site. It was lifted into
place using the 560-foot tall heavy lift derrick, one of the largest cranes in the world.
The CA05 module also has been installed at both of these reactors. It consists of reinforced steel
plates that will be filled with concrete to provide structural support for the containment building.
This module weighs 180,000 pounds and is housed in the containment building.
At Vogtle Unit 4 and Summer 3, workers installed the 920,000-pound cradle on which the
containment vessel bottom head will rest. They installed the 1.8 million-pound bottom head
about three months later.
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Several steps remain in the construction of the containment vessel for each reactor. After the
bottom head is in place, three massive rings will be placed on top of it, each fabricated with
multiple levels of steel plates. The lower ring is in place at both V.C. Summer Unit 2 and Vogtle
Unit 3. This component weighs 1.9 million pounds and measures more than 50 feet tall.
When all three rings are in place, the containment vessel will be capped with the top head. The
completed containment vessel will weigh about 4,000 tons and stand more than 200 feet high
with a 130-foot diameter.
At V.C. Summer, four low-profile forced-draft cooling towers are under construction. Two of
the towers are structurally complete, with work progressing on the other two. In addition,
workers topped off the cooling tower for Vogtle Unit 3.
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Let me also remind you that we continue to develop a pipeline of new projects – options that can
be exercised in the future when needed.
Last year, the NRC completed its safety review of GE-Hitachi’s advanced ESBWR design, and
certified that design as ready for market. It is the reactor of choice for Dominion and DTE
Energy. DTE recently completed the final hearing on its license for Fermi Unit 3, the last step
before NRC issues the combined construction/operating license.
We have 10 reactors – 12,500 megawatts – in active licensing now at the NRC. As you know,
obtaining a combined construction/operating license is a non-trivial $150 million to $200 million
commitment.
Three of these projects are maintaining their loan guarantee applications with the Department of
Energy – Dominion Resources’ North Anna 3 project (a single-unit ESBWR); Duke Energy’s
William S. Lee project (twin AP1000s), and Nuclear Innovation North America’s South Texas
Project 3 and 4 (twin ABWRs).
There is $10.6 billion remaining from the $18.5 billion in loan guarantee authority originally
authorized, after accounting for the $8.3 billion in guarantees to the Vogtle nuclear project in
Georgia. The $10.6 billion in remaining loan volume is clearly not sufficient to cover the needs
of all three projects, and we have urged DOE to seek additional loan guarantee authority to cover
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their needs, if and when the project sponsors choose to proceed. It is important that current
applicants retain line-of-sight on potential financing through the loan guarantee program.
You may recall that DOE and two of the co-owners of Vogtle 3 and 4 – Georgia Power and
Oglethorpe Power Corp. – closed last February on $6.5 billion in loan guarantees for that project,
and negotiations with the third owner, Municipal Electric Authority of Georgia, continue on its
$1.8-billion loan. This was a welcome step – expected to save Georgia Power’s customers $250
million over the term of the loan, for example.
The loan guarantee program deserves serious attention because it will become more important,
not less, in the future.
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With 69 nuclear reactors currently under construction around the world and 183 new nuclear
plant projects in the licensing and advanced planning stage, commercial opportunities for U.S.
vendors and suppliers are found increasingly in international markets. All the major forecasts
point to a major expansion in nuclear energy around the world over the next 20 years. The
International Energy Agency, the World Energy Council, and major oil companies like ExxonMobil and Royal Dutch Shell all forecast a doubling of nuclear generating capacity worldwide in
the next 15-20 years, and more than that in a carbon-constrained environment.
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Competition for this market is fierce, but U.S industry is well-positioned. American companies
have the most advanced and innovative technologies and designs – whether the advanced
passive-safety designs for large reactors or the small modular reactors now being developed,
which may be particularly appropriate for developing economies.
The commercial opportunity is large but strategic national objectives are also in play here. If the
United States participates successfully in the world market, we strengthen our ability to influence
nonproliferation policy and practices. If U.S. companies are not in the market, the U.S.
government does not have a seat at the table when policies are made.
If the United States increases its market share worldwide, we can also export our safety practices
and operational expertise, and thereby try to ensure higher levels of safety in nuclear power plant
operations around the world. The Nuclear Regulatory Commission – with 4,000 employees and
a one-billion-dollar-a-year budget – is well-regarded around the world for its technical expertise
and capability.
For several years, NEI has encouraged the U.S. government to pursue a comprehensive civil
nuclear trade policy that recognizes that nuclear energy is a strategic industry and an instrument
of U.S. foreign policy, and enables commercial nuclear suppliers to compete effectively in
international markets. Key attributes of this policy include coordination of U.S. government
trade policy by the White House; reform of U.S. export controls; enhanced export financing;
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facilitation of bilateral trade agreements, known as Section 123 agreements, with key trading
partners; and development of workable international nuclear liability regimes.
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We continue to implement safety improvements to address lessons learned from the accident at
Fukushima in 2011. The centerpiece of the U.S. industry’s response is a strategy called FLEX,
which will provide the greatest safety benefit in the shortest period of time. The FLEX approach
adds equipment – pumps, generators and the like – at diverse locations around the plant site. The
strategy is flexible, by design: It requires that the plant sites obtain, prepare and maintain
portable equipment that can connect to a variety of locations for injecting coolant and providing
a continuous supply of electricity.
FLEX will mitigate those extreme, unexpected scenarios that are beyond the plants’ design
parameters. The objective is to ensure capability to cope for an indefinite period through a
combination of installed plant systems and equipment, portable on-site equipment and off-site
resources.
Our FLEX strategy has become the benchmark worldwide for managing extreme challenges.
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In addition to having this equipment pre-staged at all 61 sites, last year we opened two centers
for additional critical equipment. The centers are located near Memphis and Phoenix and are
capable of delivering supplemental emergency equipment to any of America’s nuclear power
plants within 24 hours, enabling them to manage an extended loss of electrical power and/or
cooling water supply.
Each response center has five identical sets of equipment, which undergoes regular testing to
assure its functionality. All of the FLEX equipment – at the plant sites and at the national
centers – is similar and compatible. For example, all the equipment features standardized fittings
to allow use at any nuclear plant in the United States.
The $40 million startup cost for each facility and annual operating costs of about $4 million are
being shared by all the companies that operate reactors.
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Turning to used fuel ….
Until last year, the federal used fuel program had been in suspended animation after the Obama
Administration halted the NRC review of the Yucca Mountain license application and disbanded
the Department of Energy’s Office of Civilian Radioactive Waste Management. We joined the
National Association of Regulatory Utility Commissioners and others in separate lawsuits to
restart the NRC licensing process and stop collection of the nuclear waste fee. That fee, onetenth of a cent per kilowatt-hour, is the means by which the nuclear industry pays the federal
government to cover the cost for disposal of commercial used fuel. The fees are deposited into
the Nuclear Waste Fund, which is then supposed to be used for program expenses. The Nuclear
Waste Fund currently has 30-plus billion dollars in it and earns more than a billion dollars in
interest a year.
Last year, the Appeals Court instructed the Secretary of Energy to set the nuclear waste fee to
zero – given the absence of a DOE program and until such time as the DOE has implemented a
new program or fully resumed the Yucca Mountain project. In May of last year, the waste fee
went to zero, which saves the industry over $750 million per year. We do not expect the fee to
be reinstated anytime soon.
In 2013, the D.C. Circuit Court of Appeals also ordered the NRC to resume its review of the
Yucca Mountain license application. Just last month, the NRC issued the so-called Safety
Evaluation Report, which indicates, as expected, that Yucca Mountain can be used to dispose
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safely of used fuel. This is not the end of the licensing process. The adjudicatory phase to
address contentions must be completed when NRC and DOE receive additional funding from
Congress.
As we’ve told you many times, this program must be restructured. We need to complete
licensing of the Yucca Mountain facility and, if licensed, move forward with the project, as
required by the law and the court decision. We must create a new management entity to assume
DOE’s responsibilities, and to bring private-sector project management discipline to the project.
The new management entity must have access to future waste fee revenues and the $30-plus
billion currently in the nuclear waste fund. And we must site and operate an interim
consolidated storage facility in a willing host community and state until such time as the
permanent disposal site is available. An interim consolidated storage facility would allow the
federal government to begin meeting its contractual obligation to remove used fuel from our
sites, starting with fuel currently stored at shutdown reactors.
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We are also preparing to operate our plants beyond 60 years.
As you know, our plants are licensed initially to operate for 40 years. To date, 75 reactors have
received a first 20-year license renewal, 17 reactors have filed applications for renewal and are
under NRC review, and the remaining eight reactors have announced their intention to apply.
Thirteen reactors have passed the 40-year mark and are operating safely and reliably with
renewed licenses.
By 2029, several nuclear power reactors in the U.S. will have been generating electricity for 60
years and, by 2040, half of the nation’s nuclear fleet will have turned 60. Some of this capacity
will likely seek a second license renewal to operate past 60 years.
The regulatory process here is well-established. Active equipment and components that are
replaced regularly – like pumps, valves, instruments – are managed under the so-called
“maintenance rule.” These components are closely monitored to confirm that they can perform
their intended function when required, and are repaired or replaced at the end of their useful life.
The industry has collected vast quantities of reliability and performance data for these
components and uses this information – along with active performance monitoring – to predict
when replacement or repair of individual components is required.
The other category of equipment is passive, long-lived components. These include the
containment building, reactor vessel, tanks, concrete, piping and electrical cables and are not
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normally replaced. For plants operating beyond the original 40-year license, the effect of aging
on this equipment is subject to aging management programs to identify, monitor and manage the
effects of aging.
Demonstrating that the plants can operate safely and reliably during a second license renewal
term builds on the industry’s work in developing these aging management programs.
Understanding materials degradation, management of aging components, and the technical basis
for continued safety during an additional 20 years of operation is necessary to inform regulatory
requirements. This requires fundamental research into replacing, upgrading, and otherwise
maintaining underground pipes, electrical cables, concrete, metal and other long-lived materials
and components.
The industry – in cooperation with the Electric Power Research Institute (EPRI), the Department
of Energy (DOE), and the Nuclear Regulatory Commission (NRC) – is conducting extensive
research and development that will allow the industry to manage aging issues safely during a
second 20-year license renewal period.
We are in the process of identifying lead plants to demonstrate the process for second license
renewal.
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Although some of our nuclear plants will seek a second license renewal to operate past 60 years,
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.
Just over 30,000 megawatts reaches 60 years before 2035. Just to give you a sense of the scale
of the challenge: If today’s nuclear plants retire at 60 years of operation, given load growth
expected by the Energy Information Administration, 22 GW of new nuclear generating capacity
would be needed by 2030, and 55 GW by 2035, to maintain nuclear at 20 percent of U.S.
electricity supply.
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If the reactors operate to 80 years, 18 GW of new nuclear capacity would be needed by 2030,
and 23 GW by 2035, to maintain 20 percent.
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Let me close with a few thoughts about policy and politics and what the future holds.
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I want to close with some thoughts about electricity policy, and the increasingly urgent need for
a constructive national debate over an integrated energy and environmental policy.
Before I do that, a few thoughts about our political priorities this year in Congress and in the
states.
As you know, we have a new Congress, with Republican majorities in both chambers. We’ve
seen energy issues move up the Congressional agenda, but it remains to be seen if Congress and
the Administration can make progress on issues as complex as energy policy.
We know the House leadership will make used fuel a priority and, for the first time in several
years, some in the Senate leadership want the opportunity to consider used fuel legislation as
well. As I said earlier, restructuring the management and funding of the program is an
imperative.
We’ll continue to work with the appropriators to ensure sufficient funding for nuclear energy
research and development, including the money necessary to complete the design and licensing
work necessary to bring small modular reactors to market. We’ll continue to encourage
constructive oversight of the Nuclear Regulatory Commission, and the appointment of qualified
commissioners.
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The Export-Import Bank is operating under a short-term extension of its charter, which expires
in June. Ex-Im financing is extremely important to American nuclear suppliers operating
overseas. In fact, Ex-Im financing is usually a bid spec in nuclear tenders. Ex-Im Bank
reauthorization is proving to be a struggle, though we do believe there is strong support in both
houses of Congress if a vote is taken. It doesn’t seem to matter that the Ex-Im Bank has
generated $2.7 billion for taxpayers in the last six years, mostly through fees collected from
foreign customers. Nor does it matter that failure to reauthorize Ex-Im would amount to
unilateral trade disarmament, leaving the United States as the only major country without an
export credit agency.
We also have two major agreements for nuclear cooperation coming up for renewal this year –
one with China, one with South Korea. These agreements are necessary for commercial nuclear
exports from the United States. The agreements are negotiated by the State Department,
submitted to Congress, and enter into force automatically unless Congress passes – and the
President signs – a resolution of disapproval. These two agreements represent thousands of jobs
in America and billions of dollars in business for American suppliers, so we will be working
hard to make sure nothing interrupts that trade.
For the last several years, the states have been more effective in setting constructive energy
policy than the federal government. We are building four new reactors in Georgia and South
Carolina because both states provided a statutory framework and the regulatory support
necessary to finance these large infrastructure projects. This year, like you, we’ll be watching
Illinois particularly closely. The report commissioned by the Illinois legislature last year listed
several market-based approaches to provide appropriate value for the plants at risk. They
included a clean energy portfolio standard; potentially joining a regional cap-and-trade program
like the Regional Greenhouse Gas Initiative in the Northeast; and a carbon tax.
As I said earlier, the Nuclear Matters campaign will be focused this year on states where we have
nuclear plants under stress. Last year, we focused on raising awareness of the economic stress
facing some of the nuclear plants. This year, we will focus on solutions. In addition, we work
closely with state-based organizations – including the National Association of Regulatory Utility
Commissioners, the National Conference of State Legislatures, the National Governors’
Association, and others – and that work will obviously continue this year.
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Let me close with some thoughts on challenges facing our nation that cry out for attention.
We work in an industry with long latencies. Think about it: The world we’re living in today is a
product of decisions made 15 to 20 years ago – when the 1992 Energy Policy Act opened access
to the transmission system, when roughly one-half of the states decided to restructure the
electricity business, create competitive markets, and establish renewable portfolio standards.
The world we’ll inherit in the 2030s will be the product of decisions we make in the next several
years. And there are some serious policy issues that must be addressed.
For example, America’s electric generating technology options are narrowing dramatically.
Coal-fired generating capacity is declining. The U.S. has about 300,000 megawatts of coal-fired
capacity, and about 60,000 megawatts of that will shut down by 2020 because of tighter limits on
SO2, NOx, mercury and air toxics. EPA’s proposed regulation to reduce carbon emissions would
lead to an additional 40,000-45,000 megawatts of coal-fired retirements. And the pipeline of
coal-fired projects under development is all but empty.
Natural gas-fired generating capacity continues to grow dramatically. Since 1995, the United
States has built approximately 342,000 megawatts of gas-fired capacity, approximately 75
percent of all capacity additions, and the trend continues. While gas is clearly part of our
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nation’s strength in energy resources, overreliance on gas could expose consumers of natural gas
and electricity to price volatility and loss of reliability.
Renewables will play an increasingly large role but, as intermittent sources, they cannot displace
the need for baseload generating capacity, absent dramatic advances in energy storage.
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So the U.S. electricity sector is losing one of its major strengths – fuel and technology diversity.
A diverse portfolio of generating options is an essential characteristic of a robust and resilient
system. If current trends continue, that diversity is seriously at risk.
This diversity is taken for granted and, as a result, undervalued, as IHS Energy demonstrated in a
recent analysis commissioned by NEI, EEI and the U.S. Chamber of Commerce. IHS compared
a base case – reflecting the current generation mix in regional U.S. power systems during the
2010-2012 period – with a reduced diversity case involving a generating mix without meaningful
contributions from coal and nuclear power, with a smaller contribution from hydroelectric power
and an increased share of renewable power. The remaining three-quarters of generation in the
scenario would come from natural gas-fired plants. This is clearly the direction in which the
United States is heading.
IHS found that the cost of generating electricity in the reduced diversity case was more than $93
billion higher per year. Retail electricity prices were 25 percent higher. The typical household’s
annual disposable income was around $2,100 less in the reduced diversity scenario. The
negative economic impacts would be similar to an economic downturn, IHS said.
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We discussed the fact that the first of our nuclear plants begin to reach 60 years of operation in
the late 2020s.
But we also need to be mindful of what’s going on outside the nuclear sector. In 2030, of
today’s 300 GW of coal-fired capacity, only 23.5 GW will be less than 25 years old. Same story,
different numbers, for today’s gas-fired capacity.
So it seems to us that we’re looking at replacement of a significant amount of our generating
capacity – not just nuclear – between now and the 2030s.
Financing the sizeable nuclear construction program that we think will be necessary in the 2020s
remains a challenge, so developing workable financing approaches is as important going forward
as it was when the Energy Policy Act was enacted in 2005. Targeted revisions to the Atomic
Energy Act are necessary to produce a more stable, more efficient licensing process, and to
incorporate lessons learned during the licensing and construction of the new Vogtle and Summer
projects. The used fuel program must be set on a sustainable course. A workable regulatory
framework for second license renewal is a strategic imperative. So is commercial deployment of
small modular reactors.
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Although dates like 2030 and 2040 seem like a far-distant future – particularly when we are
preoccupied with the next election or the next quarter’s earnings – in the world of electric power
planning, 2030 is not that far away.
The runway to that future starts now, and we are doing everything we can to persuade the policy
community and the political system to engage on these issues and, as they do so, to fully
recognize nuclear energy’s unique value proposition.
With that, our thanks again for joining us this morning, and I’d be happy to answer any
questions.

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