1990+9% high technology cases, respectively. Neither of the carbon sequestration technologies penetrates the market in the 1990+9% high technology case, because the projected carbon price is relatively low, and other high-technology options are more attractive.

Nuclear Power

One carbon-free technology around which there is considerable uncertainty is new nuclear power plants. Currently nuclear power accounts for 20 percent of the power produced in the United States; however, no new nuclear power plants have been ordered since 1978, and the last one to come on line was Watts Bar 1 in 1996. In recent years, the overall performance of existing plants has improved dramatically (although several older units Figure 90. Projections of Average Heat Rates for Natural-Gas-Fired Power Plants In High and Low Technology Cases, 1996-2020 Btu per Kilowatthour

were retired before their 40-year operating licenses expired). In addition, manufacturers are now working on designs for a new generation of nuclear power plants, which are expected to be safer and less costly. As with any new technology the first few newly designed units are likely to be quite expensive, but costs should fall as manufacturers and regulators gain experience with them.

A special sensitivity case was used in this analysis to examine the possible impacts of new nuclear power plants on the carbon reduction cases. Because new nuclear plants are not economical in the 1990+9% case, this sensitivity was analyzed against the 1990-3% case. The 1990-3% nuclear sensitivity case assumes a carbon emissions target 3 percent below 1990 levels and new nuclear plant costs about 8 percent lower than the costs typically associated with the early units of new technologies, with rapidly declining costs as the new technology penetrates the market.

In the 1990-3% nuclear sensitivity case, about 40 gigawatts of new nuclear capacity is built, mostly in the later part of the projection period (Figure 92). With higher carbon prices and lower initial construction costs, the new plants are becoming competitive with other generating technologies. Nuclear electricity generation in the 1990-3% nuclear sensitivity case is only 9 billion kilowatthours higher than in the 1990-3% case in 2010 but is 248 billion kilowatthours higher in 2020.

As discussed above, increases in nuclear capacity and generation will result in greater amounts of spent nuclear fuel discharged from nuclear generating units. The waste must ultimately be moved to a permanent storage facility. The 1990-3% nuclear sensitivity case results in a 15-percent increase in projected cumulative Figure 92. Projections of Nuclear Generating Capacity in the 1990-3% Nuclear Sensitivity Case, 2000-2020

2020 Source: Office of Integrated Analysis and Forecasting. National Energy Modeling System runs KYBASE.D080398A FO03BLW.D0803988, and NUKE03LC.D081298A

spent fuel discharges by 2020, relative to the reference

case.

The future of nuclear power in the United States is uncertain. Indeed, it may depend on the extent to which limits are set on carbon emissions in response to the Kyoto Protocol. The reference and carbon reduction cases in this analysis assume no new nuclear construction, for several reasons. One is concern about the future of nuclear waste disposal. The Nuclear Waste Policy Act of 1982 directed the U.S. Department of Energy (DOE) to begin accepting spent fuel for permanent disposal in 1998. As yet, however, no permanent waste storage site is available, and most of the waste is still being stored on-site by the utilities that operate nuclear power plants. The current schedule projects 2010 as the earliest that the proposed site at Yucca Mountain could begin accepting waste. Given the history of schedule slippage in the waste repository project, new investors may not commit to new nuclear power construction until they are certain that DOE will be prepared to handle the waste. In addition, public concerns about the safety of both plant operations and waste disposal will need to be addressed. The public's association of nuclear power with its weapons origin, along with highly publicized accidents at Three Mile Island and Chernobyl, have heightened safety concerns. Public opposition can cause delays in project approval, adding risk to investments in nuclear power.

Another uncertainty is the cost of new nuclear construction. If another nuclear reactor is built in the United States, it will be one of several new designs that have been approved by the U.S. Nuclear Regulatory Commission (NRC). Two evolutionary designs have received final approval from the NRC, and one "passively safe" design is still being reviewed. The nuclear industry hopes that creating relatively few, standardized designs

will bring down construction costs and reduce the time needed to build future plants. However, past experience suggests that there will be considerable uncertainty until the first new units have actually been completed. No nuclear plant operating in the United States today was built at its initial estimated cost or schedule. Instead, all faced both cost overruns and delays in completion.

There is also uncertainty about the useful lifetimes of currently operating nuclear reactors. In recent years, a number of nuclear plants have been permanently shut down well before their license expiration dates, mainly because of the availability of more economical generation. Operating a nuclear unit for a full 40 years (the license life) will generally require additional capital expenditures over the last 10 to 15 years of the plant's life. Whether or not it is economical to incur such costs will depend on factors specific to each plant, such as location, other types of generation available, and fuel prices.

If limitations are placed on carbon emissions in the future, the relative costs of electricity generation could shift in favor of nuclear power. This analysis assumes that license renewal for nuclear plants will be considered, if economical, in all cases with restrictions on carbon emissions. Operators of nuclear power plants that are economical will renew the plant licenses. incurring the costs assumed to be necessary to prepare the plant for an additional 20 years of operation. In 1998, two utilities-Baltimore Gas & Electric and Duke Power-filled applications to renew the operating licenses of existing plants, the Calvert Cliffs units in Maryland and the Oconee plant in South Carolina. The approval process is likely to be lengthy for the first few plants, but as the NRC develops a standard review process, more utilities may consider license renewal a viable option.

The impacts on fossil fuel suppliers of policies to limit carbon emissions will depend on how much carbon is in each type of fuel: the more carbon in the fuel, the more severe the impact. If the Kyoto Protocol carbon emissions reduction targets were imposed, the U.S. coal and oil industries would see lower consumption and production than in the reference case, which does not incorporate the Protocol, whereas the natural gas industry would expand. Natural gas wins out over coal and oil in the carbon reduction cases used for this analysis, because its carbon content per British thermal unit (Btu) is only 55 percent of that for coal and 70 percent of that for oil. As a result of higher natural gas consumption and lower oil and coal consumption, carbon emissions from natural gas are projected to be higher in the carbon reduction cases, while emissions from oil and coal are lower.

Natural Gas Industry

Natural gas is a clean, economical, widely-available fuel used in more than 58 million homes and more than 60 percent of the manufacturing plants in the United States. Almost one-quarter of the energy consumed in the United States comes from natural gas. Most of the natural gas consumed in the United States is produced domestically from wells in the central part of the Nation. Gas is transported from the Central United States by pipelines throughout the country and becomes more expensive the farther it must be shipped. Yet natural gas is generally cheaper than oil products, though more expensive than coal on the basis of heating values.

In 1996 the combustion of natural gas produced 318 million metric tons of carbon emissions in the United States, about one-fifth of the U.S. total. The industrial sector was responsible for the biggest share of those emissions, about 45 percent, followed by residential, commercial, and electricity generation in order of magnitude. Twelve years from now, if no carbon reduction measures are put in place, emissions from natural gas combustion are expected to be about 100 million metric tons higher than they were in 1996. Even though the projected emissions are higher in 2010, the natural gas share of total emissions increases only slightly from 1996.

Natural gas consumption, production, imports, and prices are all expected to rise in the reference case.

Natural gas consumption increases more rapidly than consumption of any other major fuel in the reference case from 1996 to 2010. Natural gas use increases in all sectors, but consumption by electricity generators more than doubles to take advantage of the high efficiencies of combined-cycle units and the low capital costs of combustion turbines. By 2010 the generating capability of combined-cycle plants increases more than sixfold, and the generating capability of combustion turbines more than doubles. More than four-fifths of the new consumption is supplied by increased domestic production. The remainder comes from increased imports, primarily from Canada.

Two-thirds of the production increase between 1996 and 2010 is expected to come from onshore resources in the lower 48 States; the rest is expected to come from Alaska and lower 48 offshore resources. More production comes from onshore lower 48 resources, because roughly 75 percent of current proved reserves are located onshore, and continued technology improvements make development of the vast onshore unconventional resources more economical. Wellhead prices rise moderately in the reference case through 2010, reflecting increased consumption and its impact on resources, as each type of production progresses from larger, more profitable fields to smaller, less economical ones.

Policies designed to reduce carbon emissions would boost natural gas consumption, production, imports, and prices, principally because natural gas consumption would displace coal consumption in the electricity supply sector. In response, gas production and imports would increase, pushing up prices. In the 3-percentbelow-1990 (1990-3%) case, for example, the natural gas share of the U.S. energy market is projected to increase from 24 percent in 1996 to 35 percent in 2010, compared with an increase of only 2 percentage points in the reference case. Following the imposition of a carbon price, higher prices for natural gas eventually would bring gas into competition with conservation (i.e., demand reduction) and renewable fuels, slowing the growth of gas consumption and prices.

Natural Gas Consumption

Natural gas plays a key role in the transition to lower carbon emissions, because it allows fuel users to consume the same number of Btu, while emitting less carbon. Thus, one strategy for fuel users seeking to

quickly reduce coal use is to increase gas use. Natural gas consumption is expected to rise more rapidly in all the carbon reduction cases than in the reference case, driven by rising consumption in the electricity supply sector (Figure 93). Although electricity generators would produce less electricity in the carbon reduction cases than in the reference case, they would consume more natural gas, because relatively high-carbon coal would be replaced with relatively low-carbon natural gas. In the 9-percent-above-1990 (1990+9%) case, where the projected carbon price is relatively low, natural gas steadily replaces coal; but in the 1990-3% case, with a higher carbon price, renewable sources of generation begin to compete successfully with natural gas after 2010.

Note: Other uses are for residential, commercial Industrial, and transportation consumption.

Source: Office of Integrated Analysis and Forecasting, National Energy Mod ing System runs KYBASE.0080308A FD24ABY 00803988, FD0BABV D0803988, and FD03BLW.D0803088

The projections for natural gas use in the residential, commercial, industrial, and transportation sectors are almost always lower in the carbon reduction cases than in the reference case, because those sectors have significantly less opportunity to switch from highercarbon fuels to lower-carbon natural gas. In the residential and commercial sectors there is very little coal use, and most oil consumption occurs in areas where natural gas pipelines are limited. In the industrial sector, under the best circumstances, gas consumption can only hold its own in the carbon reduction cases, as some boilers switch from coal to gas. In the transportation sector gas has difficulty competing because of the limited range of compressed natural gas vehicles. As a result, consumption of natural gas in these sectors is reduced from the reference case levels because of higher natural gas prices, which lead to conservation and the penetration of more efficient technologies.

The pattern of total gas consumption differs in the carbon reduction cases, depending on the carbon price (Figure 93). Higher carbon prices, as in the 1990-3% case, lead to a quick surge in natural gas consumption when the carbon price takes effect in 2005 and gas gains an advantage over coal for electricity generation. Later in the forecast the increase in gas consumption in the 19903% case is moderated, as renewables on the supply side and energy efficiency gains on the demand side begin to cut into the natural gas market. Moderate carbon prices in the 1990+9% case result in a steadier rise in natural gas consumption, ultimately to higher levels in 2020 than those expected in the 1990-3% case, because natural gas prices are not high enough to induce significant levels of conservation or competition from renewables. Low carbon prices in the 24-percent-above-1990 (1990+24%) case lead to an even slower, 1.8 percent annual rise in consumption, from 1996 to 2020.

From 1950 to the late 1980s, electricity generators were third among the major users of natural gas, after industrial and residential users. In the late 1980s, they began to slip into fourth position, after commercial users, where they are today. When oil and coal prices were declining in the late 1980s, gas prices were fairly constant. As a result, oil and coal took a larger share of the growing electricity generation market while gas use remained flat. Gas consumption continued to grow in the commercial sector, however, eventually surpassing electricity sector consumption.

In the future, supply to electric generators is expected to become more important to the gas industry. In the reference, 1990+24%, and 14-percent-above-1990 (1990+14%) cases, electricity generators become the second largest consumers of natural gas, behind the industrial sector. by 2010. In the higher priced carbon reduction cases. they become the largest consumers of natural gas by 2010. Consumption of natural gas for electricity generation is projected to reach 12.2 trillion cubic feet in 2010 in the 1990-3% case, more than 5 trillion cubic feet higher than in the reference case and more than four times the 1996 level (Figure 93). Electricity generators can be expected to take a greater interest in natural gas pipeline capacity expansion by investing in some projects or by making long-term contracts. Pressure to merge gas and electricity companies could mount as the advantage of arbitraging the two markets becomes apparent. Electricity generators might also increase their direct ownership of natural gas resources or make long-term contracts with producers in efforts to reduce price volatility. Natural Gas Production

In most of the carbon reduction cases examined here, natural gas production, in response to higher consumption and prices, is higher than it is in the reference case