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WNA Speech on US Electricity Market Conditions, Richard Myers, Sept. 12, 2013

Nuclear Energy in the United States:
After the Storms, A Bright Future


Remarks by Richard Myers
Vice President, Policy Development
Nuclear Energy Institute
World Nuclear Association Annual Symposium
September 12, 2013


Let me start by expressing my sincere thanks to the World Nuclear Association for the opportunity to speak this morning. I must tell you that the working relationship between WNA and NEI is stronger than it has ever been. Senior management of our two organizations hold monthly conference calls to review the status of major issues, and to discuss challenges and opportunities. This is a welcome change and, given the stress under which our industry is operating in many parts of the world, it’s important that we cooperate closely. As someone once said, we must all hang together or we shall certainly hang separately.

We are particularly interested in speaking to this assembly—which represents such a broad cross-section of the leadership of the world’s nuclear energy industry—because of recent events in the United States.

What recent events, you might ask?

I’m not referring to the fact that America’s nuclear power plants continue to perform extremely well—with an average capacity factor of just over 90 percent for the first half of the year—or that we invested $8.5 billion in our plants last year to sustain those high levels of safety and reliability.

I’m not referring to the fact that we’re seeing signs of political interest and willingness to address used fuel issues, or the fact that legislation to restructure the American program has been introduced in the U.S. Senate.

I’m not even referring to the recent decision by a federal court ordering the U.S. Nuclear Regulatory Commission to resume its consideration of the license application for the Yucca Mountain disposal facility.

And I didn’t cross the Atlantic to discuss the American industry’s response to the lessons learned from the Fukushima accident, or the fact that we are well along with our FLEX initiative—adding more portable, backup safety equipment at each plant so that we can respond to extreme natural events, regardless of the cause. And I didn’t come here to discuss the two regional response centers we’re developing—one in Memphis and one in Phoenix—that will serve as dispatch points for additional equipment and resources, if needed.

And I’m not here to discuss our 30-billion-dollar-plus construction program: four new reactors under construction in Georgia and South Carolina—due on line in 2017 and 2018—and Watts Bar Unit 2, which will be completed in 2015.

And I don’t want to talk about the 14 reactors still pursuing combined construction/operating licenses at the NRC. No one expects construction on any of them to start anytime soon, and some may never be built but, post-2020, some surely will.

And I didn’t come all this way to discuss how our government is working with us to improve our nuclear export capability, so that American-based companies are better positioned to compete, or the progress we’re making in persuading our government that nuclear energy is a strategic technology—just like defense sales—and should be used as an instrument of America’s foreign policy.

No … I didn’t come to London to talk about those things.

I’m here today to discuss the shutdown of four reactors this year in the United States and the recent announcement that a fifth will shut down at the end of next year. We want to be sure that you understand the context in which these events are occurring.

The U.S. electric sector is experiencing a period of wrenching disruption and sustained stress—the product of virtually no growth in electricity demand for the last several years (thanks to the anemic performance of America’s economy), low natural gas prices and “soft” power markets. Demand for electricity in the United States has not yet returned to the level seen in 2007, before the financial crisis.

In 2012, U.S. natural gas prices slipped briefly below $2 per million Btu (MMBtu) and, since gas-fired generation sets the price in many power markets, electric power prices dropped substantially as well. Wholesale spot prices across most regional power markets last year were at 10-year lows.

The combination of no growth in electricity demand, excess generating capacity, low natural gas prices and low power prices challenges the economic viability of many power plants, including certain nuclear power plants.

To some extent, the amount of nuclear generating capacity that might shut down in the next several years depends on whether the federal and state governments and regional entities recognize—and address—the serious stresses building below the surface of the U.S. electricity industry. And the extent to which governments address these issues depends directly on the industry’s success in focusing attention on them.

All fuels, all technologies carry some level of risk. A diverse portfolio—coal, nuclear, natural gas, renewables, efficiency—is the core strength of the U.S. electric power supply system, or indeed any electricity system. This fuel and technology diversity serves as a hedge against price volatility or supply disruptions in any part of the portfolio. As with a financial portfolio, risks are lower and returns higher with a diversified mix of assets.

In the U.S. electric power sector, this fuel and technology diversity is at risk. Since 1995, approximately 75 percent of all capacity built in America was gas-fired—almost 350,000 megawatts. Coal and nuclear, the two sources of electricity that can produce electricity around-the-clock at stable prices with virtually no price volatility, represented a scant six percent of the total.  And it appears that this “dash to gas” will continue: At least 50,000 MW of gas-fired capacity—and, by one estimate, as much as 100,000 megawatts—is expected to be added this decade.

The United States has about one million megawatts of generating capacity. Roughly 400,000 megawatts of that is coal and nuclear. They supply roughly 60 percent of U.S. electricity. These are the two sources of electricity that provide the greatest price stability but, looking forward, less than 10,000 megawatts of new coal-fired and nuclear capacity is expected by 2020.

There’s something wrong with this picture.

In addition, a large amount of U.S. fossil-fueled generating capacity is expected to shut down in the next five to seven years, partly due to low gas prices, but mostly due to increasing environmental requirements. Consensus estimates suggest that 100-110 gigawatts (GW) of generating capacity—approximately 10 percent of installed capacity—will be retired this decade.

There are several reasons to be cautious about over-dependence on natural gas.

First, volatility. Last year’s low natural gas prices (in the range of $2-3 per million Btu) were not sustainable. Natural gas prices are already increasing. So far this year, the average price of natural gas delivered to electric generators is 44-percent higher than the first six months of 2012. For the first six months of 2013, spot gas prices at major trading hubs were up significantly from the same period last year—by 50-percent-or-so in most of the nation, to over 100-percent higher in the northeast.

Second, gas demand is increasing in other sectors besides electricity. By 2020, new demand from the electric power sector, the industrial sector and for liquefied natural gas (LNG) exports represents a 20-30 percent increase from today’s consumption. Can the U.S. natural gas resource base support this production level? Of course. The resource base is huge. The question is whether the necessary infrastructure—pipelines, gathering systems, gas processing facilities and so forth—will be built precisely at the right time and in the right places to match growing demand. The answer is probably not.

Several major markets in the United States have had nasty warnings about what can happen when states or regions find themselves over-dependent on natural gas. New England in early 2013 was the most recent example. New England depends on natural gas for over 50 percent of its electricity supply (almost double its dependence in 2000), and found itself skating on thin ice several times in January and February 2013, with reliability of electric service at risk and spot prices for natural gas and electric power spiking dramatically.

Gas prices in the region soared above $30 per MMBtu in January and February. Electricity prices reached $250 to $260 per megawatt-hour. This is a market that typically clears in the mid-$40-per-megawatt-hour range. The total value of New England’s wholesale energy markets in January and February 2013 was estimated to be about $2 billion. By comparison, the value of the region’s electricity market totaled about $5 billion in all of 2012.

An after-the fact assessment by the organization that operates the grid in New England is littered with stark descriptions of what happened: “Persistent reliability concerns … the region needs to develop immediate solutions to avert serious threats to system reliability next winter … a condition that is unsustainable.”

New England is not the only vulnerable part of the country. In 2000, Florida relied on natural gas for about 18 percent of its electricity supply. Today it is 70 percent and likely to increase further with the Crystal River reactor shut down. In New York, gas-fired generation increased from 29 percent of electricity supply in 2000 to 44 percent in 2012.

As you know, a number of states in America restructured their electricity markets in the late 1990s, and the business of producing electricity has turned into two distinctly different enterprises.

In those states still subject to traditional regulation, companies and regulatory agencies evaluate resource options and project economics over a 40-year time horizon, as is appropriate when you’re building 40-year assets, and they assign value to real (but qualitative) factors like fuel and technology diversity, price stability and environmental attributes.

Restructured merchant states have not yet developed mechanisms to value these “public goods” and internalize them in their decision-making.

Regulated states have been able to create the conditions under which companies can undertake long-term, capital-intensive projects and preserve fuel and technology diversity. In the south and southeast, state legislatures and regulatory commissions provide the assurance of cost recovery necessary for capital-intensive projects. This is why the Vogtle and Summer nuclear projects are under construction in Georgia and South Carolina.

By contrast, fifteen years of experience with deregulated markets suggests that these markets are not producing price signals sufficient to stimulate investment in new generating capacity, or to support continued operation of existing capacity. This is clear from assessments of these markets by the independent companies commissioned to monitor market performance.

It is also clear that a short-term surplus of electric generating capacity is temporarily masking the inevitable consequences of inadequate price signals and short-run decision-making.

So far this year, four nuclear reactors have shut down permanently, and a fifth is scheduled for shutdown at the end of next year. Three are unique situations, unlikely to be repeated.

The common thread at Crystal River 3 and San Onofre 2 and 3 was steam generator replacement. Since the Surry nuclear power plant in Virginia replaced its steam generators in the early 1980s, approximately 110 nuclear reactors around the world have replaced their steam generators, in what has become a routine practice. Of all the reactors that have replaced their steam generators, three have ended badly. That does not represent a trend.

Crystal River 3 is a case study in how uncertainty over repair cost can force shutdown; San Onofre, a case study in how open-ended regulatory uncertainty can produce the same result.

Of the five, Kewaunee and Vermont Yankee are the only ones that were the victims of economic pressure. And they are the greatest concern, particularly because both plants were—and are—solid performers. Kewaunee had an average capacity factor of 94.3 percent for 2010-2012; Vermont Yankee was 90 percent. There was—and is—nothing wrong with these plants.

There’s something seriously wrong with the markets in which they are operating, which do not value baseload capacity that can be dispatched when needed, which do not provide value for fuel and technology diversity, and which do not recognize the clean air compliance value of a nuclear power plant.

Still, these two shutdowns raise legitimate questions: Is it the start of a trend? Will other nuclear power plants follow?

It is certainly true that a handful of older, smaller nuclear power plants—like older, smaller coal-fired plants—are vulnerable to weak market conditions, particularly in unregulated merchant markets. Older, smaller plants that face major capital investment requirements are the most vulnerable.

How many additional nuclear plants shut down, if any, will depend on a number of factors, all difficult to forecast with any confidence, including energy and capacity prices in the market in which the plant operates, natural gas prices, regional growth in electricity demand, economic growth in the region, political sentiment about the plant, and—perhaps most important—whether and when policymakers and political leaders address the defects in market structure, design and performance discussed above.

It’s important to maintain a realistic perspective on nuclear power plant shutdowns, no matter how many there are, remembering that this year is not the first time the U.S. nuclear industry has shut down power plants. In the mid- to late-1990s, the American industry closed 10 reactors, typically due to a combination of several factors—economic uncertainty in the face of restructuring and deregulation, regulatory distress. Some forecasters took the shutdowns as a sign that the U.S. nuclear industry’s best days were behind it.

In its annual forecast for 1997, the Department of Energy predicted: “The 1997 Annual Energy Outlook reference case assumes that … 50 units will retire between 1995 and 2015 … . [The Outlook] assumes that individual reactor performance improves for the first 20 or 25 years of operation, after which it declines as units age. As a result, the national average capacity factor stays near the current level of 77 percent.”

This forecast, and others like it, was not only wrong; it was spectacularly wrong. Fifty reactors did not shut down, and industry performance did not stall at 77 percent, but leveled off at approximately 90 percent, with the top quartile of plants typically running at 95-percent average capacity factors.

Although the short-term picture is challenging, the long-term prospects for nuclear energy in America remain strong, and the value proposition for nuclear energy is as robust as ever.

That value proposition starts with production of large quantities of electricity around the clock, safely and reliably, when needed. But the value proposition does not end there.

Nuclear power plants also provide clean air compliance value. In a cap-and-trade system, nuclear energy reduces the compliance burden that would otherwise fall on emitting generating capacity.

Nuclear power plants provide voltage support to the grid, helping to maintain grid stability.

Nuclear power plants provide forward price stability and are not subject to the price volatility associated with gas-fired generating capacity, in particular.

Nuclear power plants contribute to the fuel and technology diversity that is one of the bedrock characteristics of a reliable and resilient electric sector.

Finally, nuclear power plants provide large numbers of high-paying jobs (larger numbers and higher-paying than other sources of electricity) and anchor the local tax base.

These are the unrecognized values of nuclear energy. They are not monetized by markets. They do not show up in net present value calculations. But they exist nonetheless.

And it’s our job to ensure that everyone recognizes that.