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Nuclear Power

Nuclear Power: 12 percent of America�s Generating Capacity, 20 percent of the Electricity

Charts on plant ownership, costs, license extensions, and future trends.

Opinions vary regarding the future of nuclear power, but it is a fact that existing U.S. plants are performing well. Nuclear power plants now operate at a 90 percent capacity factor, compared to 56 percent in 1980. Additionally and in contrast to oil and gas, nuclear fuel costs are low and relatively stable. Fuel costs now average less than one half cent per kilowatthour. This is well below the costs of major competing fossil fuels. Production costs for nuclear power, operation and maintenance plus fuel costs, are also low, averaging 1.8 cents per kilowatt-hour. This cost roughly matches coal and is significantly below the costs of operating a natural gas plant.

Despite all of this relatively attractive news regarding nuclear power, there has been no new order for a nuclear power plant since the 1970s. The last nuclear plant to be completed went on line in 1996. A few, perhaps four, construction licenses are still valid or are being renewed for half-completed reactors, but there are no active plans to finish these reactors.

What follows is an attempt to describe the sources of nuclear power�s apparent strength. This will also include a brief overview of the varied problems that nuclear power industry faces if it seeks to expand its market share further.

The Track Record of Nuclear Power

Nuclear power is a relatively new industry even though nuclear generation capacity has been almost constant since 1990. While prototype and early plant designs have been around since the 1950s, the first large scale and truly commercial units only began operating in the late 1960s in the United States. The following table includes only light water reactors that have been licensed for commercial operation since 1968. The oldest reactors still operating in the United States were licensed in 1969.

U.S. Light Water Reactors Operating License Year
License Year
Reactors Licensed
Share of Reactors
Closed Reactors
Operable Reactors
Share of Operable

Half of the commercial nuclear reactors operating in the United States are less than 24 years old. Because the newer units tend to be larger than the older units, this represents slightly more than half of the generating capacity of the operating units. The column of �closed� reactors illustrates that about 92 percent of all commercial reactors built in the United States since 1968 are still operable. The list also indicates that only the oldest reactors have had a problem with premature closures. Only one reactor (Three Mile Island 2) completed since 1976 has permanently closed. No U.S. reactor has closed since 1998.

Although nuclear generating capacity has remained roughly constant from 1990, the amount of electricity produced has increased 33 percent during the same period because capacity utilization has increased from 66 percent in 1990 (56 percent in 1980) to over 90 percent in 2002. The increase in nuclear power generation due to capacity factor increases is roughly equivalent to building a number of new power plants operating at former capacity levels.

Capacity Factors at U.S. Nuclear Power Plants, 1980-2002
Capacity Factor

During the 1980s electric utilities knew that for nuclear power to be commercially viable, operating and maintenance costs had to be reduced. One way to do this was to improve plant utilization. A series of institutional changes have facilitated the process since then. During the 1980s the Institute of Nuclear Plant Operators (INPO) was set up to share technical information. New fuel designs permitted higher burnups. Such improvements permitted the expansion of periods between refueling outages to be increased from 12 months to 18 months and sometimes to two years. Refueling outages have also been cut from as much as three months in 1990 to about a month today. Methods of undertaking other maintenance and capital replacement during these outages or even during operations have also been improved. Time requirements for planned and unplanned maintenance have been shortened. More recently techniques such as risk informed maintenance have also been expanded to the government regulatory environment, improving the contribution of regulators to safe and continued plant operation. Finally, the introduction of competition to the wholesale electricity market has honed the motivations of plant operators toward safe and reliable plant operation.

It would be difficult to separate one of these trends out as more important than another, though the reduced outage time is a major component. Because refueling and maintenance outages must still continue at reactors, we are clearly approaching a technical limit for average plant capacity factors. We are probably not there yet but it will not be more than a few percentage points higher. Improved nuclear power performance in the future must come from other sources.

In addition to increased availability, lower costs have influenced the use of nuclear power. Not all electricity is same. There are many means by which and locations where one can produce electricity. There are also cycles in demand that vary by day, week, and season. The incentive is to produce electricity for each part of the cycle at the lowest possible cost. When it comes to average and marginal operating costs nuclear power usually has the advantage.


Source: EIA, Electric Power Annual 2000

A number of notes should be made on this chart. The first of these is that the data gather all steam-based fossil fuel energy together. Fuel costs are lower for steam-based power for coal than for oil or gas. Thus, coal-based power has only a slightly higher U.S. average production cost than does nuclear. The costs are so close that, while nuclear costs average lower than coal, there is a good deal of overlap when regions of the country or individual reactors are considered.

Nuclear power does, however, have an advantage in day-to-day operations in its low marginal costs. Day-to-day marginal costs are primarily fuel costs. A disproportionate part of nuclear power operating costs come from operations and maintenance costs that do not vary much with output. Because nuclear power�s marginal costs are lower than coal�s marginal costs, nuclear power plants tend to use their full output capacity before coal plants. This gives nuclear power an advantage in base load operations and results in a higher capacity factor.

U.S. Capacity and Market Share by Fuel 2000
Capacity Factor (percent)
Generation Share (percent)
Generation (billion kWh)
Oil & Gas


This table is a bit misleading though it does indicate the impact of availability, demand, and cost. In this case it is the oil and gas numbers that are not consistent with what one anticipates. The term �oil and gas� includes a good deal of peaking and cycling capacity. Thus while modern gas turbine-based combined cycle plants might see relatively high capacity factors, many oil and gas plants operate only rarely during the year. The peaking and cycling character of a large portion of oil and gas capacity makes capacity factor data look worse than it really is, though coal and nuclear plants will generally have higher capacity factors than oil and gas plants. Hydroelectric power capacity factors were low because of the drought during 2000. Also, cheap hydropower can be stored in the form of water. This allows it to be sold when prices are higher, during peak demand periods, when such cycles are permitted. Numbers for nuclear presently are around 90-91 percent capacity factor and 20-21 percent generation share.

One recent trend in the U.S. nuclear power industry that might influence future performance has been an increased concentration of operations into fewer and fewer hands. This had taken place almost exclusively through the acquisition of existing commercial reactors by firms that already manage commercial reactors.

Operators of U.S. Reactors
Capacity (MWe)
Share of Capacity
2nd Five Firms
Others (3+ Reactors)
Others (<3 Reactors)

If this were ownership rather than management the percentages would be smaller for many firms. This is because many reactors have joint ownership arrangements that differ from management arrangements. Of the top five managers, only Entergy and Exelon have been buying management rights at U.S. nuclear plants. Exelon has not done so lately and has talked about either buying or selling AmerGen claims and responsibilities. The second tier firms, plus those managing three plus units have also bought management rights. In some ways recent acquisitions have thus been a leveling process among managing firms. The data in the table do not include the Stars group which shares some responsibilities among the managers of many of the smaller managerial groupings.

Another recent trend that will result in increased nuclear capacity to help sustain the nuclear share of electricity generated is referred to as capacity uprates. Uprating capacity has been an ongoing process since the inception of the nuclear power industry. Uprates have also occurred in other power sub-sectors such as coal and hydroelectric. Nuclear uprates have however garnered a substantial portion of the media attention, if only because the regulatory environment makes nuclear uprates public knowledge.

Present technologies permit uprates of existing nuclear reactors of around 5-20 percent. In some cases these uprates have already occurred. EIA�s projections place the near term potential around 4 GWe, based primarily on utility and regulatory announcements. Others such as the Nuclear Energy Institute go as high as 10 GWe. One restriction on higher numbers will be balance of plant considerations and occasionally the economics of the increase. When uprates are viable they provide low cost increases in plant capacity with little change in operations and maintenance costs. These low operations and maintenance costs can mean that some uprates might make economic sense even when they are more expensive than adding less expensive capacity using other fuels. The industry now investigating yet further means to raise plant capacity. These might result in additional uprates beyond present anticipations.

Source: Nuclear Regultory Commission Energy Information Administratioin Press Reports

License renewal has also been an issue in the nuclear power industry that is related to future nuclear power generation. Operating licenses expire after 40 years but may be extended with the approval of the Nuclear Regulatory Commission. License renewals add 20 years. The NRC has indicated that �substantially all� existing reactors intend to renew their licenses. The renewal process has been less burdensome than was once anticipated and is at best only an indicator of the future of particular plants. Because the license renewal process takes time to complete, reactors built during 1968-74 have to announce and implement proposed renewal applications within the next few years.

The following table is based on NRC�s published list indicating which reactor managers have announced their intention to renew operating licenses.

U.S. Nuclear Power Plant Renewal Status
License Year
Number of Reactors
On NRC List
Not On NRC
List Closed

The 1968-74 group has been less forward with their plans than the later 1975-1978 group. In contrast the newest reactors have no reason to hurry their announcements. Just two firms manage most of the ten oldest excluded reactors. These firms thus might be withholding announcements for policy reasons rather than because of uncertain plans. The basic point is that there might still be issues related to eventual license renewal though the only reactors of immediate concern are the very oldest units. The NRC list is complicated by the inclusion of five potential applications described as �not publicly announced.� Some plants in this group might include more than one reactor and sometimes more than one plant. Thus a minimum of five and probably more reactors should be added to the table. It is though where they belong and whether the apparent problem is statistical or real.

New Nuclear Construction

Nuclear power�s future share in electricity generation will decline if there are no new orders. The nuclear power industry presently has no commitments to build new reactors. The TVA has announced that by 2007 it hopes to bring Browns Ferry-1 back into operation. That reactor has been closed since 1985. The TVA also has three partially completed reactors for which construction licenses are either active or for which extended licenses are being sought. Three firms also plan to apply for early site permits, though such permits are not commitments to build. Nonetheless the business environment has not encouraged power plant construction of any type by any firm during 2002-03. Nuclear plants are no exception.

There are several reasons why there are no firm plans to build new nuclear power reactors. First among these in the short term is that many if not most regions of the Nation presently have surplus baseload generating capacity. There are exceptions to this conclusion. California imports much of its base load electricity needs but also effectively discourages new production from the typical base load power sources, coal and nuclear. This short term base load surplus must be worked off before any new nuclear construction can be seriously considered.

A longer-term reason why no nuclear power has been built is that the capital costs of building a new nuclear power plant have historically been high. There are also considerable financial costs and risks related to the long construction periods in the industry. The last completed nuclear reactor, Watts Bar-1, took 24 years to complete. There has been a history of regulatory uncertainty. The extreme case is the Shoreham plant on Long Island that was essentially completed before it was decided that it would not be allowed to operate. Policy issues such as spent fuel disposal methods, liability insurance questions, and overall safety concerns on the part of the public have also adversely affected nuclear construction.

The nuclear power industry and its promoters are addressing each of these issues. Prospective builders now promise lower costs. Regulatory processes are now better specified and, when possible, implemented early and consistently in the decision process. Financial risk, construction periods, waste disposal, and safety are now being handled in more direct and organized manners. Difficulties with public acceptance remain but are hard to gauge.

N.B. U enrich and fuel fabrication Europe annual updated with links to more details in individual countries. Reprocessing spend fuel in France 2008; in UK 2008 Pu in Japan & world, sept2010 Thomas Cockran-us-situation-25May2010

The Energy Information Administration in its Annual Energy Outlook 2003 projects in its reference case that no nuclear units will become operable between 2001 and 2025. This projection is a reference scenario that functions as a mid-term forecast under current laws and regulations. The EIA also examined a scenario where the costs of nuclear construction were lowered to a level that some vendors say they will achieve after first of a kind engineering and financing difficulties are worked out. The Annual Energy Outlook�s conclusion under this �advanced nuclear cost case� is that additional nuclear power capacity would come on line if cost targets are reached.

Are the changes in the nuclear power industry enough to make a difference in its future? There are still no new orders. Thus in the short term recent achievements are not enough. Getting new orders is the challenge that the nuclear industry must still meet if it wishes to expand. Most of the risks in building nuclear power plants must be faced early in the plant�s life cycle. A fossil fuel plant faces its greatest risks, uncertain demand and fuel prices, after the plant begins operation. This will discourage nuclear power investment when other anticipated costs are comparable. Nuclear power�s task remains controlling its risks better than competing fuels control their risks.


  John Moens
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