Here’s what’s driving the renaissance.
Richard J. Myers is executive director, Policy Development, at the Nuclear Energy Institute. Contact him at email@example.com.
Nine companies, consortia, or joint ventures are planning approximately 12 new nuclear power plants in the United States. How do the business challenges they face differ from the challenges faced by companies using other fuel sources?
History will record that the rebirth of nuclear power in the United States did not begin in 2005, but 13 years earlier, in 1992. Back then, a few companies were struggling to complete the last three or four of the 103 nuclear plants that now supply one-fifth of U.S. electricity. The common wisdom held that no electric utility would ever build another nuclear reactor in the United States. And Congress passed the 1992 Energy Policy Act, which overhauled a cumbersome and unworkable approach to designing, building, and licensing nuclear plants, replacing it with the more efficient, predictable process being used today by companies planning new nuclear plant construction.
The 1992 Energy Policy Act also set in motion negative trends and events that led to today’s energy market conditions. For all its virtues, the 1992 energy legislation unleashed a lengthy period of turmoil in the electricity business, one that continues to this day. It eliminated forever the presumption that electricity generation was a natural monopoly, and mandated open access to the transmission system for all power producers. It institutionalized competition, and prompted restructuring of the electricity business at the state level, starting in the mid-1990s. It forced companies to seek out the business model best suited to their core competencies: Fully integrated? Wires and pipes only? Generation only? Spin off the generating assets to create additional shareholder value? Stick with the regulated business (a bit dull perhaps but steady and predictable)? Or venture into the unregulated enterprises like generation and trading (more attractive price/earnings multiples but highly volatile)?
A Decade of Underinvestment
This continuing business uncertainty made for heady and exciting times, but it had a crippling effect on capital investment in the electricity sector. Transmission transactions increased 400 to 500 percent in the last half of the 1990s, but transmission investment in 1999 was less than one-half of the level 20 years earlier. Investment in coal-fired and nuclear power plants—the capital-intensive baseload technologies that form the backbone of U.S. electricity supply—all but collapsed. Between 1992 and the end of 2004, a meager 9,500 MW of new coal-fired capacity and 4,300 MW of new nuclear capacity started commercial operation, and construction had started on all of it long before the ’92 Energy Policy Act.
Instead, the U.S. power sector built massive amounts of gas-fired generation—more than 275,000 MW between 1992 and the end of 2004. When the gas-fired build cycle started in the 1990s, the market needed gas-fired capacity. The United States ended the 1980s heavy on baseload coal and nuclear plants, and needed mid-merit and peaking capacity to rebalance the system. Gas-fired capacity serves that part of the dispatch order well.
As the decade wore on, however, construction of gas-fired generating capacity accelerated, from an average of about 6,000 MW annually through much of the 1990s to approximately 40,000 MW in 2001, peaking at roughly 53,000 MW/year in 2002 and 2003. By then, it was clear that gas-fired capacity was being built to serve baseload demand, and it was being built in place of coal-fired and nuclear plants because gas-fired capacity represented the lowest investment risk at a time of punishing business uncertainty.
Only a relative few warned that growth in demand for natural gas was unsustainable; that consumers of natural gas, and of electricity from natural gas, would face punishing price volatility, and that demand growth and supply constraints eventually would combine to price much of this new gas-fired generating capacity out of the market. Today, we are paying the price for more than a decade of underinvestment in critical electric power infrastructure.
Driven largely by higher oil and natural gas prices, fuel costs for the electric sector increased by 35 percent last year—from $68 billion in 2004 to $92 billion in 2005. Recall that spot natural-gas prices were in the $6 to $7 per million BTU range through the summer of 2005, even before two major hurricanes wrecked the gas production and processing infrastructure along the Gulf Coast and sent spot prices soaring north of $10 per million BTU.
Add to this continued upward pressure on the cost of coal-fired generation. Spot prices for SO2 allowances soared above $1,500 per ton late in 2005. Those prices are clearly not sustainable. But most analysts forecast long-term equilibrium prices in the range of $800 to $1,000 per ton—significantly higher than the $200-per-ton prices that prevailed until late 2003—as the markets internalize the tighter limits on emissions mandated by the Clean Air Interstate Rule.
Evidence that the surplus generating capacity around the nation is disappearing also surfaced. For the first time in a decade, U.S. reserve margins dropped in 2005, according to recent analysis by Cambridge Energy Research Associates (CERA). Summer electricity demand increased by the equivalent of 30,000 MW to 35,000 MW, and a surge in retirements virtually offset new generating capacity coming on line.
All this adds up to a bleak outlook. If there is a silver lining, it is this: Today’s electricity markets reinforce the strategic value of generating capacity that can provide large volumes of baseload electricity, without emissions, at stable, predictable prices. More than anything else, the renewed interest in, and commitment to, nuclear power reflects the fundamentals in the energy markets.
Managing the Risks
Nine companies, consortia, or joint ventures are planning approximately 12 new nuclear power plants in the United States (see Table 1). This first wave will enter service in 2015 or so.
This did not happen overnight. In 2000, the Nuclear Energy Institute assembled the companies already heavily invested in nuclear power and launched a program to create business conditions under which companies could build new nuclear plants when they needed new baseload capacity. The initiative had two major elements: To demonstrate that the new licensing process created by the ’92 Energy Policy Act would work as intended, and to identify the tools and techniques necessary to ensure availability of financing.
Licensing New Nuclear Plants. The new licensing process moves all regulatory and licensing approvals to the fore, prior to any significant capital expenditures. Plant designs are approved (or certified) in advance. Sites are approved before major capital investment begins. And companies receive a single license to build and operate the plant. That license includes measurable, quantitative criteria that, if met, will allow the plant to load fuel and start up when construction is complete. The threshold for intervention after the construction and operating license is issued is high, and is intended to preclude frivolous intervention, unwarranted delays, and other costly mischief.
This is a significant change from the licensing process under which all of today’s nuclear plants were licensed. That two-step process required a license to build the plant and another to operate it. In many instances, only 10 percent of the design was complete at the construction permit stage. This “design-construct-inspect as you go” approach often resulted in significant rework, design changes and on-site modifications.
Once the plant was built, it had to receive a license to operate. So a billion-dollar facility remained idle while the second phase of the licensing proceeding proceeded. In some cases, what should have cost $500 million and taken four years to build cost several billion dollars and took 10-plus years to complete.
In summary, the conditions that led to large cost increases for some operating nuclear power plants no longer exist (see Table 2). Past experience was useful in identifying the weaknesses in the regulatory process and fixing those weaknesses. Past experience does not, however, provide useful guidance as to the cost of nuclear power plants that will be built in the future, or the length of time it will take to build them.
Financing New Nuclear Plants. The next generation of U.S. nuclear plants (see Table 3) are modeled on today’s plants but incorporate features designed to make them safer and less costly to operate. Because of “first-of-a-kind” design and engineering costs—approximately $500 million per reactor design—the first new nuclear plants will cost more than later, follow-on plants. Recognizing this, the Energy Policy Act of 2005 provides investment stimulus in the form of production tax credits and federal loan guarantees to offset the higher cost, thus ensuring that the first new nuclear plants will be competitive and economically viable. Once the first few new nuclear plants are built, and the “first-of-a-kind” design and engineering costs have been recovered, follow-on plants will be built without federal government financial support (see Table 4).
Under the loan guarantee authority, the federal government will guarantee debt financing for up to 80 percent of total project cost. This will allow companies to structure projects with a more highly leveraged capital structure than is typical of conventional regulated utility financing, obtain debt at preferential rates, and reduce total project cost by several hundred million dollars.
The legislation also includes a production tax credit of $18/MWh for up to 6,000 MW of new nuclear capacity. The production tax credit places emission-free nuclear energy on an equal footing with other sources of emission-free electricity (including wind power and closed-loop biomass), which have received a production tax credit since 1992.
The 2005 energy legislation also provides an innovative form of investment protection for the first six reactors. This risk insurance is similar to the sovereign risk insurance available through institutions like the Overseas Private Investment Corp. to American companies doing business elsewhere. The federal government will cover debt service and other costs for the first few plants if commercial operation is delayed for reasons beyond the company’s control, such as a failure by the NRC to meet schedules and litigation. The industry believes the NRC’s new licensing process will work as intended, but no one can be completely certain until it has been tested. The regulatory process is the one risk that industry cannot hedge. The delay insurance will allow boards of directors to authorize multi-billion-dollar investments in new nuclear plants, confident that they are protected against unforeseen delays.
The financial stimulus provided by the 2005 Energy Policy Act affords the nuclear industry substantial flexibility in structuring and financing new nuclear projects and in managing the risks associated with financing. The industry expects to see a spectrum of financing arrangements: Regulated projects, merchant projects, varying degrees of leverage, projects built by single companies, projects built by consortia in order to share risk, projects that are non-recourse to the project developers’ balance sheets, and projects that are full recourse.
In those states that are still operating under cost-of-service regulation, companies likely will build new nuclear plants as rate-base projects, using a conservative 50/50 capital structure. This regulatory arrangement provides substantial protection: Investors know they have reasonable assurance that all costs prudently incurred can be recovered through rates. Unregulated generating companies will build new nuclear power plants as merchant projects, with the financing supported by long-term power purchase agreements and loan guarantees.
Companies now are preparing applications for combined construction/operating licenses (COLs). The first of these will be submitted to the Nuclear Regulatory Commission (NRC) in 2007, and should receive NRC approval in 2010 or so. Assuming a 48-month construction period, which has been achieved routinely overseas, the first new nuclear plants will be operating in 2014-2015, close on the heels of the next wave of new coal-fired capacity that is now starting construction or well along in the development process. By 2025, an educated guess shows approximately 30,000 MW of new nuclear capacity operating, with at least that much under construction.
Fuel and Technology Diversity
During the 1990s, the conventional wisdom held that the risks associated with nuclear power plants—operations, used fuel management, licensing, and construction of new plants—were uniquely overwhelming and insurmountable. It is now clear that the common wisdom should be greeted with considerable skepticism, and that the nuclear industry’s business challenges are quite manageable.
In the mid-1990s, the common wisdom (including the Annual Energy Outlook produced by the DOE’s Energy Information Administration) forecast that one-half of U.S. nuclear generating capacity would shut down prematurely because of competitive pressures. Who would have guessed that five years later, the industry would be thriving, profitable, and consistently recording average capacity factors in the 90-percent range, with the top quartile of plants operating above 97 percent? In the mid-1990s, who would have guessed that, by 2005, three-quarters of the U.S. nuclear fleet would have obtained 20-year license extensions, or planned to do so? In the mid- to late-1990s, who would have guessed that the president and the Congress would approve Yucca Mountain in Nevada as a suitable site for a used fuel storage and disposal facility? Or that states and local communities would compete among themselves, offering companies incentives to build new nuclear capacity?
Many factors have combined to bring nuclear power to the beginning of this new construction cycle: unsustainable pressure on natural gas supply and intense price volatility; increasing environmental pressures on coal-fired generating capacity, including the prospect of controls on greenhouse gas emissions; and, perhaps more than anything, the recognition among industry executives and policy-makers of the need for fuel and technology diversity, coupled with the recognition that all fuels and technologies have unique business challenges. The business challenges facing nuclear energy are not necessarily larger or more formidable than those facing coal or natural gas or any other source of power. They’re just different.
A prudent company, indeed a prudent nation, will balance those challenges by diversifying its portfolio.