– 1 –

Good morning. I’m Marvin Fertel, president and CEO of the Nuclear Energy Institute.

Thank you for joining us this morning for this annual update on the nuclear power industry.

Once again in 2015, U.S. nuclear plant performance was outstanding – a tribute to the

dedicated men and women who operate and maintain the 99 nuclear reactors that produce

approximately 20 percent of the nation’s electricity, and two-thirds of our carbon-free

electricity.

And in the next three years or so, we will commission five new reactors, representing about

6,000 megawatts of new capacity.

Unfortunately, in the last three years or so, companies have shut down – or announced their

intent to shut down – eight nuclear reactors, about 6,300 megawatts of generating capacity.

So our presentation this morning is focused on the efforts underway to ensure that we do not

lose any more valuable assets, and that we continue to build new reactors when Watts Bar 2,

Vogtle 3 and 4 and Summer 2 and 3 are completed.

Our message here – to state and federal government agencies and regional organizations – is

direct and simple: We have no time to waste. If we do not demonstrate a greater sense of

urgency about addressing the problems in the electricity markets, we will lose more good-

performing, non-emitting nuclear plants.

– 2 –

Here is what we plan to cover this morning. We’ll start with industry performance, recap

some of the major events and issues from last year, summarize for you the work underway to

offset the economic pressure on some nuclear plants, and close with some thoughts about

2016 and beyond.

There is nothing we can do about low natural gas prices or low growth in electricity demand,

so the industry is committing substantial resources to things we can control – correcting

weaknesses in competitive electricity markets; valuing the attributes of nuclear plants that are

not recognized, or not fully recognized, by the markets; and a major new industry initiative to

drive greater efficiency at our plants and reduce costs.

Our goal is obviously to minimize the number of nuclear plants shut down because the

markets do not recognize their value.

Why are we doing this?

We’re not doing it because we’re concerned that a few more plant shutdowns in the short-

term have implications for the industry’s future long-term.

Like most industries, the nuclear energy industry experiences periods of economic stress.

Ten U.S. nuclear reactors shut down during the 1990s, and the industry emerged from that

down cycle more productive and more profitable. The long-term fundamentals suggest the

same will happen again.

– 3 –

So we’re doing everything we can to preserve our operating nuclear energy assets because

it’s the right thing to do.

– 4 –

It’s the right thing to do for the highly skilled people who operate and maintain these plants,

and all those whose livelihood depends on the plant.

It’s the right thing to do for the towns and counties and states in which these plants operate.

– 5 –

And it’s the right thing to do for consumers of electricity.

The green bars on this slide show the average cost of electricity from our nuclear plants – the

fleet average, and the average for multi-unit plants and single-unit plants. The most costly

nuclear plants – the smaller single-unit stations – produced electricity, on average, for

approximately $44 a megawatt-hour in 2014.

It might be possible to find cheaper electricity off the grid for a short time – for as long as

there’s spare gas-fired combined cycle capacity, and spot gas available below $2 per million

Btu, which is clearly not sustainable.

But sooner or later, that nuclear capacity must be replaced and, when it is replaced with new

gas-fired combined cycle capacity, consumers will pay more on a levelized cost basis.

The blue bars on the slide show various estimates of the levelized cost of electricity from a

new gas-fired combined cycle plant – from the Energy Information Administration, from an

integrated resource plan filed recently by a regulated utility, and from Lazard. All are well

above the cost of electricity from even the single-unit nuclear sites.

No-one has yet given us a satisfactory answer to the question of why it makes sense to shut

down a carbon-free $44-per-megawatt-hour nuclear plant that provides 600-or-so direct jobs,

– 6 –

and replace it with a $60-70 per-megawatt-hour gas-fired plant that provides maybe 30 jobs

and has roughly one-half the carbon emissions of a coal-fired power plant.

– 7 –

So let’s look at industry performance in 2015.

– 8 –

In terms of reliability and productivity, 2015 was another solid year.

We estimate average capacity factor was just shy of 92 percent – record.

We estimate nuclear generation for the year was 798 billion kilowatt-hours – a bit higher

than 2014, even though we had one less plant.

– 9 –

We won’t have the 2015 cost data until midyear but, in 2014, U.S. nuclear plants operated at

about $36 per megawatt-hour on average, the second year of declining cost since the peak of

about $40 per megawatt-hour in 2012.

The first quartile continued to operate below $30 per megawatt-hour, the second quartile at

about $34 per megawatt-hour.

That is total generating cost, which includes fuel, operating and maintenance costs, and

capital.

We invested $6.5 billion in the plants in 2014, about the same as 2013, and a 26 percent

decrease from the $8.7 billion in capex in 2012.

– 10 –

As you know, capex runs in cycles. We put a large number of nuclear plants in service in a

relatively short period of time, so we should expect to see periodic surges in capex as major

components and equipment are replaced and upgraded.

For several years, we’ve been expecting to see some moderation in capital spending, and we

believe we saw the first signs of that in 2013 and 2014.

For example, capital investment in power uprates peaked at $2.5 billion in 2012 but declined

to $315 million in 2014.

– 11 –

Capex for compliance with the Nuclear Regulatory Commission’s requirements was about

one-third of total capex in 2014.

Capital spending to meet regulatory requirements was around $1 billion a year in 2007 and

2008, before reaching a peak of almost $2 billion in 2014. This increase began with

significant investments in security post-9/11, followed by expenditures for Fukushima

response, which totaled $1 billion in 2014.

As we complete the Fukushima-related safety enhancements – and we expect to be

substantially complete with Fukushima response by the end of the year – we expect

regulatory capex to moderate substantially, and revert toward the 2007-2008 levels.

– 12 –

Operating costs have also increased over the last 12 years – from about $19 per megawatt-

hour in 2002 to about $21 per megawatt-hour in 2014. Operating costs have actually

declined a little over the last four years.

– 13 –

Moving on from plant performance, I’d like to highlight several key issues and activities

from last year.

– 14 –

The Tennessee Valley Authority completed construction of the second reactor at its Watts

Bar station, and received its operating license last October. The plant has loaded fuel and is

conducting the testing necessary before full-power operation, which is expected about

midyear.

– 15 –

The four reactors at Summer and Vogtle are expected to come online in 2019 and 2020.

Last year was notable for the major changes announced last October that will improve project

management and cost and schedule certainty.

The project sponsors and their suppliers restructured their EPC (engineering-procurement-

construction) contracts to resolve their disputes. The agreements also ended litigation over

disputed costs.

– 16 –

An opportunity is to figure out how to continue new plant construction after the Vogtle and

Summer projects are complete, to take advantage of the lessons learned.

Six other combined license applications, representing 10 new reactors – 12,500 megawatts of

generating capacity – are under active review at the NRC, including several that reference the

reactor design being built at Vogtle and Summer.

In our view, when Vogtle and Summer are completed and operating is precisely the time for

projects that reference the AP1000 design to move toward construction, assuming a need for

the power or a need to replace existing carbon-emitting generating capacity.

The detailed design and engineering on the AP1000 will have been completed. In addition,

the lessons learned from these two projects can be applied immediately to new projects,

before those lessons are forgotten.

It appears that the time-to-market for the Vogtle and Summer projects will be 10-12 years.

Since the next AP1000 projects will have already received and banked their COLs for a

design that is already certified, it should be possible to reduce time-to-market to the time

required for construction – closer to four to five years.

– 17 –

We’re also seeing continuing progress on the small modular reactors. The lead developer –

NuScale Power – plans to file its application for design certification with the NRC before the

end of the year. NuScale is aiming for first commercial deployment in the early 2020s, and

has a large public power entity in the West lined up as its first customer.

Coming along behind them, with commercial deployment expected in the 2030s, is a new

generation of even more advanced reactors. One organization recently found nearly 50

companies backed by $1.5 billion in venture capital. Names like Transatomic, X-energy,

TerraPower and others.

These advanced reactors were the centerpiece of a first-ever White House Summit on

Nuclear Energy last November. They’re also receiving growing financial support from the

Department of Energy. Just a few weeks ago, DOE selected two companies – X-energy and

Southern Company Services – to develop advanced nuclear reactor designs. Both projects

consist of industry-led teams, including other companies, research institutions, universities

and national laboratories. DOE’s initial investment will be $6 million for each project, with

matching funds from both companies, and DOE could provide up to $80 million for both

projects over several years.

– 18 –

The industry has significantly improved safety at U.S. nuclear power plants through prudent

post-Fukushima investments. Essentially all U.S. reactors have implemented the NRC’s

post-Fukushima safety requirements ahead of the NRC’s schedule.

The industry has managed its response to Fukushima while avoiding costly new requirements

that would have provided little benefit. For example. the NRC decided against a requirement

to install external reactor containment vent filters, an avoided cost of at least $1.6 billion for

no added safety benefit.

Remember that the root cause of the Fukushima accident was lack of electric power and lack

of water to cool the reactor core and the used fuel pools.

So the centerpiece of the U.S. industry’s response to Fukushima is our strategy called FLEX.

The FLEX approach adds portable equipment – pumps, generators and the like – at diverse

locations around the plant site. The strategy requires that the plant sites obtain, prepare and

maintain portable equipment that can connect to a variety of locations. This ensures that we

can always maintain the flow of cooling water and provide a continuous supply of electricity.

In addition to having this equipment pre-staged at all 61 sites, we operate 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 plants

– 19 –

within 24 hours. This is yet another layer of equipment that will enable them to manage an

extended loss of electrical power and/or cooling water supply.

– 20 –

The global market for commercial nuclear technology is a tremendous opportunity for U.S.

suppliers. There are 66 reactors under construction around the world today, and another 158

reactors on order or planned. The Department of Commerce estimates that the global market

– including fuel and services – could be as large as $750 billion over the next 10 years.

The international nuclear energy business is fiercely competitive, and U.S. suppliers

generally compete against state-owned enterprises, 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.

– 21 –

Last year saw a major referendum in Congress on America’s position in the world nuclear

energy market, with a positive outcome on all major issues.

After a bruising political struggle in Congress, which pitted the American business

community against politicians at both ends of the political spectrum, the Export-Import Bank

was reauthorized for four years. Ex-Im Bank is critical for U.S. nuclear suppliers to compete

in the international market.

Two major nuclear cooperation agreements – with China and South Korea – were renewed

during the fourth quarter. And the Department of Energy finalized its nuclear export rules,

modernizing a cumbersome process that put American companies at a competitive

disadvantage next to other supplier nations.

– 22 –

As you know, our plants are licensed initially to operate for 40 years.

To date, 81 reactors have received a first 20-year license renewal, 11 reactors have filed

applications for renewal and are under NRC review, and the remaining six reactors have

announced their intention to apply.

– 23 –

We are also preparing to operate our plants beyond 60 years.

By 2030, 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. And the NRC affirmed last year that the

existing process needs no revision.

The industry, DOE and the NRC are conducting extensive research and development on

managing aging issues safely during a second 20-year license renewal period. The research

has shown there are no generic technical issues that would prevent a nuclear plant from

operating safely beyond 60 years.

Last November, Dominion Virginia Power became the first company to announce its intent

to file a second license renewal application, for its two-unit Surry nuclear power plant. Surry

is a pressurized water reactor. In the near future, we expect a boiling water reactor licensee

to announce its intent to begin the NRC process for second license renewal.

Deciding whether or not to pursue second license renewal will be a business decision: Does

the capital investment required make sense given business conditions at the time?

– 24 –

Let’s turn to the initiatives underway to create additional margin for all our plants.

This has two main components – increasing revenue and reducing cost through greater

efficiency.

The industry started several years ago to work on increasing value – by correcting

weaknesses in competitive electricity markets, and seeking to monetize the attributes of

nuclear power plants that are not recognized, or not fully recognized, by the competitive

markets.

These efforts are beginning to bear fruit.

– 25 –

Nuclear plants in competitive markets face the cumulative impact of several negative forces,

including:

Sustained low natural gas prices, which are suppressing prices in wholesale power

markets.

Relatively low growth – and in some markets, no growth – in electricity demand.

Federal and state mandates for renewable generation, which suppress prices, particularly

during off-peak hours. Some parts of Illinois see negative prices for as much as 10-11

percent of the off-peak hours.

Transmission constraints, which require power plants to pay a congestion charge to move

their power onto the grid. Some nuclear plants at particularly congested points on the

grid see congestion charges of $5-10 per megawatt-hour.

Market designs that do not compensate the baseload nuclear plants for the value they

provide to the grid, and market policies and practices that tend to suppress prices.

Given the large number of factors causing the stress, it’s no surprise that there’s no single,

simple solution.

– 26 –

In a number of cases – Illinois, Ohio, New York – we see the states taking steps to implement

policy changes that would preserve existing nuclear plants.

States also have tools available under the Clean Power Plan to preserve their nuclear energy

assets, although Tuesday’s Supreme Court decision to stay the rule obviously throws the

future of the Clean Power Plan into doubt.

– 27 –

The industry is pursuing reforms in both capacity markets and energy markets, and there has

been significant movement on the part of the Federal Energy Regulatory Commission

(FERC) and a number of Regional Transmission Organizations to address some of the

underlying problems.

– 28 –

Last year, for example, FERC approved a proposal from PJM to reform its capacity market to

provide additional compensation to generating resources – like nuclear power plants –

capable of sustained, predictable operation. These so-called Capacity Performance resources

are expected to be available and capable of providing energy and reserves when needed, and

will face substantial penalties if they are not.

PJM held its first capacity auction – for the 2018-2019 delivery year – in August 2015 and

two transitional auctions in September. In all three auctions, the Capacity Performance

resources cleared at significantly higher prices than previous auctions that did not include a

Capacity Performance product.

MISO recently indicated that the MISO zone in southern Illinois – home to the Clinton

nuclear plant – “may not be providing a price signal sufficiently in advance that will result in

efficient investment in new resources or to sustain investment in existing resources.”

There’s clear evidence that these market reforms work. They provided a short-term reprieve

to certain plants last year. But by themselves, they are not enough. Unfortunately, we’ve

already seen the gains from Capacity Performance eroded by the continuing deterioration in

the energy markets.

We’ve had disappointments, to be sure. New England ISO proposed last year to include

nuclear units in its Winter Reliability Program, recognizing correctly that the nuclear plants

– 29 –

provide similar reliability to dual-fueled power plants. Unfortunately, FERC denied the

proposal last September, and Entergy cited that denial as one of several factors that prompted

its decision to shut down the Pilgrim nuclear plant.

– 30 –

In the energy markets where baseload plants generate most of their revenue, accurate price

formation is absolutely essential.

Price formation issues are complicated, but the goal is relatively simple: Ensure that all costs

necessary to operate the system are reflected in locational marginal prices (or LMPs).

Transparent, accurate price formation breaks down when grid operators take actions that

deviate from least-cost dispatch.

In such cases, system operators manually dispatch a resource that is needed to resolve a

constraint, or address a reliability concern, but those costs do not show up in the clearing

price. The RTOs provide make-whole payments, or “uplift” payments, to those resources.

This uplift tends to suppress price signals and inhibit accurate price formation.

It’s almost impossible to generalize because uplift is highly specific to a host of

circumstances, but the price suppression, in aggregate, can be substantial, as the example on

this slide shows.

– 31 –

NEI has been working with the Edison Electric Institute and the Electric Power Supply

Association (which represents the competitive generating companies) on this issue for some

time.

On this slide, you can see the remedies we’ve proposed.

The goal: To encourage FERC to take action to address a number of operating practices

common to the RTOs that tend to distort price signals or suppress prices in the energy markets.

– 32 –

FERC has developed an exhaustive record on price formation issues, starting with a series of

technical conferences in late 2014.

Last September, FERC took a first step, with a Notice of Proposed Rulemaking (NOPR) that

would revise its regulations governing how the Regional Transmission Organizations set

prices in the energy markets.

The agency followed the NOPR with an order directing the RTOs to report back on how they

manage various price formation issues, including uplift. And last month, FERC proposed

another change to its regulations in this area. The most recent proposal would change the

policy on offer caps, and would allow the RTOs to use the higher of $1,000 per megawatt-

hour or a cost-based offer.

FERC’s first step – the NOPR last September addressing settlement intervals and shortage

pricing – proposed two changes.

The first would require that each RTO settle energy transactions in its real-time markets at

the same time interval it dispatches energy. Any misalignment between dispatch and

settlement intervals may distort the price signal.

The second change would require that RTOs trigger shortage pricing for any dispatch

interval during which a shortage occurs. There’s an obvious problem if there’s a delay

– 33 –

between the time when a system experiences a shortage and the time when prices reflect the

shortage condition.

Although welcome, the two changes FERC proposed last September could be described as

“low-hanging fruit.” These are issues that influence the real-time market, but revenue to the

baseload nuclear units is determined in the day-ahead market. So closing the gap between

day-ahead and real-time markets is also essential.

– 34 –

As we’ve said many times, some nuclear plants are struggling because the electricity markets

do not recognize the attributes of nuclear power plants and the distinct value they bring to the

electric supply system, including their carbon-abatement value.

Nuclear energy is by far America’s largest source of carbon-free electricity, and that attribute

should increase in value as the United States and the rest of the world grapple with the

challenge of climate change. Regardless of what happens with the Clean Power Plan, it is

clear that nuclear energy is indispensable to any credible program to reduce carbon

emissions.

– 35 –

States have a number of options to recognize the carbon-free value of their nuclear plants,

and thereby ensure that this generating capacity remains in operation.

Several states – Illinois, New York, North Carolina – are considering various clean energy

standards.

It’s obviously impossible to speculate about the outcome of the litigation over the legality of

the Clean Power Plan, but the plan as proposed did provide states options that would preserve

their existing nuclear facilities.

The Clean Power Plan gives states two compliance options – a rate-based approach (in which

individual sources or the state as a whole must meet an emission rate measured in pounds per

megawatt-hour), or a mass-based approach (in which the state must simply meet a cap,

measured in tons of CO2).

EPA clearly prefers the mass-based compliance option, and the regulation is structured to

move the states in that direction. Both EPA and the states are familiar with mass-based

programs because they’re used for other pollutants. They’re also familiar with mass-based

trading programs, in which emitting sources must hold an allowance for every ton of the

pollutant released.

– 36 –

Under the Clean Power Plan, there are mechanisms available in a mass-based system that

would recognize nuclear plants’ compliance value and preserve existing nuclear capacity, if

the states choose to use them.

A state can, for example, include both existing sources of CO2 emissions and new sources

under its cap. In a mass-based compliance regime that includes new and existing sources,

closing a nuclear power plant would have consequences. That plant’s generation must be

replaced in such a way that the state’s electric generating units do not exceed the cap.

– 37 –

In parallel with our efforts to generate additional revenue and increase asset value, we have

also launched an industrywide program to drive greater efficiency across the industry.

We call this initiative “Delivering the Nuclear Promise – Advancing Safety, Reliability and

Economic Performance.”

– 38 –

We are analyzing our operations to determine where we can improve efficiency. This multi-

year program is identifying opportunities for efficiency measures, cost reductions and

technology solutions that could be implemented industrywide to advance safety and improve

operations.

We will always maintain our commitment to safety and reliability. In fact, I’m confident that

safety will continue to improve, because our staff will be focused on high-priority work and

not distracted by less significant issues.

The program was developed by chief nuclear officers from across the industry. It will also

leverage the expertise of industry organizations, like NEI, the Institute of Nuclear Power

Operations and the Electric Power Research Institute.

Teams of industry experts have identified initial areas where cost efficiencies or process

improvements may be gained. The pace and scope of implementation at each nuclear power

plant site will be determined by the company that owns and operates it.

The goal is to achieve significant and sustainable cost savings by 2018 and beyond.

– 39 –

We established these goals to be deliberately aggressive and aspirational – to signal that we

are not looking for minor incremental improvements to the status quo, but more

revolutionary, game-changing innovations and improvements.

But as you can see from the walkdown through the numbers above, we believe the goal is

realistic.

– 40 –

For example, the $3-per-megawatt-hour estimated reduction in capex through 2020 would

bring the fleet average down to approximately the level we saw in 2004, before we embarked

on replacement of steam generators and reactor vessel heads, and power uprates, across the

industry.

The $2-per-megawatt-hour reduction in fuel cost would bring us back to pre-2008 levels,

when uranium and enrichment costs were higher than today. Given the lead time between

when fuel is purchased and when it is placed in the reactor, the higher fuel costs in 2014 are

the result of fuel purchased several years ago.

– 41 –

Step one in the plan was to analyze the cost data, to understand what is driving operating

costs, so that we could identify opportunities to improve.

We could see clearly where the major cost increases have occurred, and that gave us

signposts as we charted a path toward greater efficiency.

For example, we could see that four activities – work management planning and execution,

corrective action, and training – were major cost drivers, and accounted for 50 percent of the

industry’s operating budget.

Based on analysis of the cost drivers, we created teams – each led by a CNO – to develop

specific improvement opportunities.

That was last October. By year’s end, the teams had produced over 180 ideas that were

successively reviewed and refined until approximately 50 ideas were identified for pursuit in

2016.

The teams are developing specific Improvement Opportunities. These will be distributed via

new NEI Efficiency Bulletins, and will be endorsed by INPO to assure adherence to our

highest safety and reliability standards.

– 42 –

We’re excited about what we can achieve as an industry, but we’re also encouraged by what

we see at the Nuclear Regulatory Commission.

In parallel with our efforts to improve efficiency, we are seeing progress on an initiative

designed to address the cumulative impact of NRC regulatory actions.

This agency has grown over the years – from approximately 3,000 employees in 2004 to

approximately 4,000 in 2014, a 25-percent increase. Likewise, the NRC budget: from $626

million to $1 billion, a 60-percent increase, over the same 10-year time period.

The industry will always spend what is necessary to ensure safety and reliability. But over

the years, the number of regulatory requirements continues to increase – including some 47

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.

NEI has recommended changes in the NRC’s process of evaluating proposed regulatory

actions of all types, including termination of rulemakings that would impose significant cost

with little or no safety or security benefit.

Under the leadership of NRC Chairman Stephen Burns, the NRC is implementing an

initiative called Project Aim, designed to provide recommendations for improving

– 43 –

performance; to develop realistic projections of the workload for the agency five years out,

and to make recommendations for agency budget and workforce to guide “right-sizing” of

the agency.

And we’re seeing the first fruits of this effort. In 2015, the commission directed the staff to

set priorities for regulatory actions. The NRC terminated a number of activities last year,

generally because the costs and resources required were not commensurate with the benefits.

– 44 –

In closing, a few thoughts about the future.

– 45 –

For the last several years, during these briefings for the financial community and in other

forums throughout the year, we have suggested several basic principles that should govern

our thinking about electricity markets, and guide our efforts to structure these markets for a

sustainable future.

We are convinced that there was nothing wrong with any of the nuclear plants that have shut

down for market-related reasons, or any of those at risk. Kewaunee, Vermont Yankee and

others were all solid performers – highly reliable plants with high capacity factors and

relatively low generating costs. Even the Pilgrim nuclear plant, which faces some regulatory

issues, posted an 89.2-percent average capacity factor over the 2012 to 2014 period. The

nuclear plants at risk in western PJM are producing in the low-$30-per-megawatt-hour range.

For those plants, there’s clearly something wrong with the markets in which they’re

operating. They’re not structured to recognize the value of the resources in place. They’re

not operated so that all costs are reflected in prices. They’re distorted by out-of-market

revenues and mandates.

As we consider solutions to this set of problems, this leads us back to simple economic

principles.

Goods and services will only be produced in a competitive market when they are priced and

valued in the market. There are no free goods.

– 46 –

We cannot continue to think of electricity as an undifferentiated bulk commodity. Every

kilowatt-hour of electricity on the grid has a unique set of attributes, depending on how it is

produced.

So, for example, electricity generated from wind is carbon-free (a valuable attribute) but it is

not dispatchable and it tends to be correlated inversely with demand (the wind generally

blows at night when the electricity is needed the least).

Electricity from coal-fired power plants is dispatchable (a valuable attribute), and it has

reserves of fuel on site (another valuable attribute), but it’s not carbon-free.

On-site fuel supply, and the ability to run when needed, is a valuable attribute. It deserves

compensation. The New England ISO and PJM recognize this. Other ISOs have not yet

evolved to that point.

– 47 –

So every kilowatt-hour of electricity on the grid has a distinct pedigree. If we don’t identify

the attributes, and incorporate them into our decision-making, and value them in our market

design and market policies, then companies will stop providing those attributes – and that, of

course, is what’s happening.

Here are the attributes of nuclear energy. You can see that nuclear electricity is a premium

product. As you go through this list of attributes, you can also see that a number of them –

price stability, grid support, clean air compliance value, portfolio value and so forth – need to

be recognized and valued whether the plant is in a regulated state or in an organized market.

As I said at the beginning, if we do not recognize and value these attributes – in both the

competitive markets and the regulated markets – we will continue to lose the valuable

baseload generating capacity that drives our four-trillion-kilowatt-hour-a-year economy 24-

by-7.

– 48 –

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, nor will it assure we meet our

environmental goals.

We’re seeing early signs that state and federal policy-makers are beginning to recognize

these simple facts.

And we’re seeing early signs that they’re beginning to recognize that nuclear energy’s value

proposition, shown on this slide in summary form, is too large to lose.

But, as I said at the start, we are not doing enough, fast enough to establish the policies

necessary to preserve existing nuclear assets.

Instead, we’re driving companies to make decisions that our nation will regret for the next 20

or 30 years, or longer, on the basis of short-term, unsustainable price signals.

With that, let me close and open the floor to questions.