Limited Electricity Generation Supply and Limited Natural Gas Supply Cases |
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Development of U.S. energy resources and the permitting and construction of large energy facilities have become increasingly difficult over the past 20 years, and they could become even more difficult in the future. Growing public concern about global warming and CO2 emissions also casts doubt on future consumption of fossil fuels—particularly coal, which releases the largest amount of CO2 per unit of energy produced. Even without regulations to limit greenhouse gas emissions in the United States, the investment community may already be limiting the future use of some energy options. In addition, there is considerable uncertainty about the future availability of, and access to, both domestic and foreign natural gas resources. To examine the effects of uncertainty about future supplies of electricity and natural gas, three alternative cases were developed for AEO2008. The limited electricity generation supply case assumes that higher construction and operating costs together with other factors, such as lack of public acceptance, will limit the use of energy sources other than natural gas for power generation—including coal without CCS technology, nuclear power, and renewable fuels. The limited natural gas supply case assumes that no Arctic natural gas pipeline will be in operation before 2030, the availability of LNG to U.S. regasification terminals will be limited, the U.S. oil and natural gas resource base will be less than in the reference case, access to the resource base will be more limited than assumed in the reference case, and that improvements in oil and natural gas exploration and development technologies will be slower than in the reference case. Finally, a combined limited case includes all the assumptions from the first two cases. Assumptions Limited Electricity Generation Supply Case In the AEO2008 reference case, based on existing laws and regulations, the use of natural gas for electricity generation continues to increase in the near term, then declines as generators increasingly turn to coal, renewables, and new nuclear power capacity in the longer term. New coal-fired capacity without CCS could be limited, however, by policy changes aimed at limiting CO2 emissions. Several States already are beginning to implement emission reduction programs, and the U.S. Congress is discussing potential Federal programs. In California and Washington State, recent legislation has set emission standards for electric power plants that would preclude new coal-fired plants without CCS from providing power to those States (see “Legislation and Regulations”). There are also several proposals at the Federal level that would impose caps on CO2 emissions. The limited electricity generation supply case, in addition to assuming that new coal-fired power plants without CCS cannot be built, also assumes that construction costs for new plants with CCS will be 25 percent higher than in the reference case. Currently, new nuclear capacity is being proposed in response to incentives provided in EPACT2005, rising fossil fuel prices, and concerns about CO2 emissions; however, there continue to be concerns about nuclear waste disposal, public acceptance, and the ability to build new plants on time and within budget. It is likely that some new nuclear plants will be built, given current interest levels and financial incentives, but if early builds encounter delays in construction or licensing or significant cost overruns (as occurred with the first generation of nuclear plants), the longterm potential for nuclear electricity in the United States could be reduced. The limited electricity generation supply case assumes the same amount of new nuclear capacity as in the reference case by 2030; however, in circumstances where the reference case assumes that current capacity factors, averaging over 90 percent nationally, will be maintained throughout each plant’s 60-year lifetime, the limited electricity generation supply case assumes that the national average capacity factor for nuclear power plants will fall to 70 percent in 2030. To date, no nuclear power plant has operated for 40 years, and industry experience in maintaining older nuclear plants is limited. Thus, it is possible that replacement of major components on older plants could cause significant outages, or that gradual breakdowns could lead to lower capacity factors. Adding large amounts of economical renewable capacity may also face challenges. The reference case projects a large increase in renewable capacity (mostly wind and biomass), mainly to meet the requirements of State RPS programs. There is also some public resistance to the siting of new wind and biomass plants, however, and their costs may increase after the “best” sites have been used. The limited electricity generation supply case assumes the same amounts of new wind and biomass capacity as in the reference case, but the availability of new biomass energy crops is delayed until 2020, compared with 2010 in the reference case. Biomass gasification technology is a new, unproven design that could run into delays and cost overruns, and in addition it could take many years to develop the infrastructure to grow, cultivate, harvest, and transport new energy crops. The costs for all other new renewable capacity (geothermal, landfill gas, solar thermal, and solar PV) are assumed to be 25 percent higher than in the reference case. Again, these technologies are new, and there is considerable uncertainty about initial cost estimates. Limited Natural Gas Supply Case The limited natural gas supply case represents an environment in which numerous natural gas supply options are unavailable, less available, or more costly to develop than in the reference case. Among the most significant uncertainties for future natural gas supply are the development of natural gas pipelines in the Arctic region of North America, the future availability of LNG imports, the size of the domestic natural gas resource base, and the rate of technological improvement in the industry. Currently, two large natural gas pipelines are under consideration for development in the Arctic region: a Mackenzie Delta pipeline in Canada and an Alaska pipeline [59], both of which are large, expensive construction projects. It is expected that 6 years will be required to permit, license, design, construct, and open the Mackenzie pipeline and 9 years will be required to do the same for the Alaska pipeline. A number of factors could delay completion of the projects beyond 2030, however, including: higherthan- expected construction costs that would make the pipelines unprofitable throughout the projection period; higher-than-expected State and Provincial taxes and royalties on natural gas production; environmental concerns requiring expensive remediation; delays in regulatory approval and permitting; and difficulties in addressing the concerns of native peoples whose lands are crossed by the pipelines. Accordingly, the limited natural gas supply case assumes that neither pipeline will be opened before 2030. The future availability of LNG imports depends critically on the development of new LNG supply sources throughout the world, which in turn will require the construction of large, expensive liquefaction facilities and LNG tankers. Typically their financing is supported by multi-decade contract commitments from large natural gas consumers, such as natural gas and electric utilities; however, those large consumers face considerable uncertainty of their own, including whether new nuclear generating capacity will reduce long-term requirements for natural gas supply, whether alternative supplies will be available from other sources at lower prices, and whether suitable pricing mechanisms will be available to ensure that LNG suppliers earn a reasonable rate of return while the consumers pay prices that are reasonable in comparison with the prices of other sources of natural gas supply. It is possible that potential LNG suppliers could face considerable difficulty in obtaining customer commitments sufficient to support the financing required for development of LNG supplies that are able to satisfy world demand for natural gas. Further, if LNG supplies are scarce relative to world demand, overseas natural gas prices could exceed U.S. domestic prices, drawing LNG supplies away from the U.S. market. Alternatively, new sources of LNG supply could be fully committed to overseas customers under long-term contracts, making spot purchases of LNG either unavailable or prohibitively expensive. Availability of supplies could also be limited by policies adopted by the countries that produce LNG. For example, LNG producers could operate in concert to limit LNG supplies in order to increase prices or to make more natural gas available to their own consumers. They might also adopt production taxes, excise taxes, and tariffs that would make LNG economically unattractive in the United States. The LNG assumptions used in the limited natural gas supply case are identical to those used in the low LNG case (discussed later in “Issues in Focus”), with U.S. gross imports of LNG held constant at 1.0 trillion cubic feet per year from 2009 through 2030 [60]. The LNG restrictions apply to the United States only; LNG imports to Canada and Mexico remain sensitive to prices, and new LNG import capacity is assumed to be constructed in those countries according to predetermined price triggers. The actual size of the domestic oil and natural gas resource base is another source of uncertainty. The USGS and Minerals Management Service (MMS) calculate the U.S. undiscovered oil and natural gas resource base on a probabilistic basis, reporting a mean estimate, a 95-percent probability estimate, and a 5-percent probability estimate of technically recoverable oil and natural gas resources in each major U.S. petroleum basin. As an example, for the U.S. lower 48 onshore basins, the USGS mean probability estimate of undiscovered natural gas resources is 483 trillion cubic feet, the 95-percent probability estimate is 291 trillion cubic feet, and the 5-percent probability estimate is 735 trillion cubic feet [61], illustrating the wide range of uncertainty with regard to the size of the U.S. oil and natural gas resource base. The AEO2008 reference case assumes that the technically recoverable U.S. oil and natural gas resource base is equal to the USGS and MMS mean estimates. Given the uncertainty inherent in those estimates, however, the actual resource base could be considerably smaller. Further, the ability to develop the resource base could be limited by other factors, including the possibility that future laws and regulations could place more Federal and State land off limits to oil and natural gas production. The limited natural gas supply case assumes that the U.S. unproven oil and natural gas resource base and Canada’s undiscovered natural gas resource base are 15 percent smaller than the estimates used in the reference case. Another factor that could reduce available natural gas supplies is a slowdown in the rate of technological progress. Technological progress generally reduces the cost of finding, developing, and producing natural gas resources. In addition to their direct impacts on costs, technology improvements can increase finding and success rates, which have an impact on the average costs of production. A slower rate of progress results in higher capital and operating costs for oil and natural gas exploration and development than would otherwise be the case. The limited natural gas supply case assumes a technological progress rate that is one-half the rate in the reference case. Results Electricity Generation In 2006, coal-fired power plants supplied 49 percent of U.S. electricity generation. In the AEO2008 reference case, coal’s market share is maintained through 2020 and grows to 54 percent in 2030, primarily as a result of projected increases in natural gas prices. In the limited electricity generation supply case, natural gas supplies are unchanged from those in the reference case, while generation from other fuels is constrained. As a result, the coal share of total generation drops to 42 percent in 2030, and the natural gas share increases from 20 percent in 2006 to 27 percent in 2030, as compared with 14 percent in 2030 in the reference case (Figure 15). By assumption, nuclear, wind, and biomass remain at or below reference case levels from 2006 through 2030, while generation from other renewables and from oil increases slightly. Although delivered natural gas prices to the electric power sector in 2030 are 16 percent higher in the limited electricity generation supply case than in the reference case because of higher demand, the price increase is not enough to shift generation from natural gas to the competing technologies. In the limited natural gas supply case, no constraints are assumed for any electricity generation technology relative to the reference case, but natural gas supplies are limited. As a result, in 2030, delivered natural gas prices to the electric power sector are 39 percent higher than in the reference case, and natural-gasfired generation is 42 percent less than in the reference case. With no technology restrictions, natural gas is displaced by increases in the use of coal, nuclear, and some renewables (geothermal, biomass, and wind) for electricity generation. In the combined limited case, all the fuel choices for electricity generation are more expensive than in the reference case. Natural-gas-fired generation in 2030 is higher than in the reference case, but with higher natural gas prices (84 percent higher than those in the reference case) the difference is smaller than in the limited electricity generation supply case. Coalfired plants with CCS are built, increasing the demand for coal, and investment in new renewable technologies increases, including geothermal and offshore wind. Oil-fired generation also increases substantially, because it is less expensive to use distillate than natural gas even in some newer combined-cycle plants. Total electricity generation is 6 percent lower in the combined limited case than in the reference case, as higher costs for fuel and for plant construction result in higher prices and lower demand for electricity. The technology mix for new capacity additions differs dramatically among the three limited cases (Figure 16). In the limited electricity generation supply case, the only new coal-fired builds are those currently under construction, and almost all the additional coal-fired plants projected to be built in the reference case are replaced by new natural-gas-fired capacity (an additional 60 gigawatts). Nuclear generating capacity is the same as in the reference case, and renewable capacity additions are 8 gigawatts higher. In the limited natural gas supply case, higher natural gas prices reduce natural-gas-fired capacity additions, while additions of coal-fired, renewable, and nuclear capacity increase relative to the reference case. Because more older generating units are retired in the limited natural gas supply case (primarily, those using natural gas) more new capacity is added than in the reference case. In the combined limited case, 17 gigawatts of new coal-fired capacity with CCS is built. Natural-gasfired capacity also increases relative to the reference case, but by a smaller amount than is projected in the limited electricity generation supply case. More new capacity using renewable technologies that are not constrained by assumption, including geothermal, landfill gas, and offshore wind, is built in the combined case than in the reference case, even though their construction costs are assumed to be higher than in the reference case. Natural Gas Consumption Natural gas consumption for electric power generation in 2030 varies widely across the cases, from 43 percent below the reference case level in the limited natural gas supply case to 78 percent above the reference case level in the limited electricity generation supply case (Figure 17). The largest difference from the reference case is in the limited electricity generation supply case, because constraints on competing fuels, such as the CCS requirement for new coal-fired plants, make natural gas the fuel of choice for new capacity. In the limited electricity generation supply case, natural gas consumption for electricity generation is 3.9 trillion cubic feet above the reference case level in 2030, while total U.S. natural gas consumption in 2030 is only 3.6 trillion cubic feet higher than in the reference case. Higher natural gas prices in the limited electricity generation supply case reduce residential, commercial, and industrial natural gas consumption in 2030 by a total of 0.4 trillion cubic feet from the reference case projection. In the limited natural gas supply case, where only natural gas supply is constrained, higher natural gas prices cause natural gas to lose market share in all the end-use consumption sectors. In 2030, total natural gas consumption is 3.8 trillion cubic feet less in the limited natural gas supply case than in the reference case. In the electric power sector, which is particularly fuel flexible and price sensitive, natural gas consumption in 2030 is 2.2 trillion feet lower than in the reference case. In the combined limited case, total natural gas consumption in 2030 is 3 percent lower than projected in the reference case, although natural gas use for electricity generation is 21 percent (1.1 trillion cubic feet) higher than in the reference case. In comparison, natural gas consumption in the electric power sector in 2030 is 3.9 trillion cubic feet higher in the limited electricity generation supply case and 2.2 trillion cubic feet lower in the limited natural gas supply case than in the reference case. The constraints on other sources of electricity generation in the limited electricity generation supply case thus have a much more pronounced effect on natural gas consumption in the electric power sector than do the natural gas supply constraints in the limited natural gas supply case. In all three cases, higher natural gas prices reduce natural gas consumption in the residential, commercial, and industrial sectors relative to the reference case. In the combined limited case, natural gas consumption in the end-use sectors in 2030 is 14 percent lower than in the reference case. In the short term there is little potential in those sectors for fuel switching, which generally occurs only over the long term as older equipment is retired. In the residential and commercial sectors, most of the reduction in natural gas consumption in the three cases results from conservation and more efficient appliances. In the industrial sector, where there is some fuel-switching capability, part of the decrease is attributable to fuel substitution. In addition, although not quantified here, higher prices could drive some industrial users to either shut down operations or move them outside the United States to locations where fuel and other operating costs are lower. In the end-use sectors, the largest reduction in natural gas consumption occurs in the combined limited case, because the highest natural gas prices are also projected in the combined case. In 2030, natural gas consumption is 19 percent lower in the industrial sector, 8 percent lower in the residential sector, and 10 percent lower in the commercial sector than projected in the reference case. Natural Gas Supply As consumption patterns shift across the cases, the mix of natural gas supply sources changes considerably (Figure 18). These changes are dictated largely by the natural gas supply conditions assumed in the limited natural gas supply case and in the combined limited case, which assumes that no Alaska natural gas pipeline is built and that gross LNG imports do not increase after 2009. Consequently, in these two cases, lower 48 sources provide most of the incremental natural gas supply. In the limited electricity generation supply case, all natural gas sources contribute to incremental supply in 2030. The largest increase is 1.1 trillion cubic feet from unconventional natural gas production, which consists of tight gas, shale gas, and coalbed methane. Unconventional natural gas makes up the bulk of the undiscovered resource base and shows significant growth in the reference case projections. Conventional natural gas production (onshore and offshore) in 2030 is 0.6 trillion cubic feet above the reference case level. Alaskan production and LNG imports, which are not constrained in this case, both respond to higher prices, increasing by 0.4 and 1.0 trillion cubic feet, respectively. Offshore production is slightly higher, by 0.2 trillion cubic feet, and pipeline imports are higher by 0.4 trillion cubic feet. In the limited natural gas supply case, where total natural gas consumption in 2030 is 3.8 trillion cubic feet less than in the reference case, the lack of an Alaska pipeline and the constraint on U.S. LNG imports account for 2.9 trillion cubic feet of the reduction in natural gas supply. Unconventional natural gas production is also reduced by 1.8 trillion cubic feet, whereas domestic production from other sources, particularly onshore conventional resources, is increased by 0.4 trillion cubic feet and pipeline imports are increased by 0.6 trillion cubic feet. The decrease in unconventional natural gas production in the limited natural gas supply case relative to the reference case is a direct result of the changes in supply assumptions. Because the undiscovered unconventional resource base is considerably larger than the conventional resource base, the assumption of a 15-percent smaller resource base has the greatest volumetric impact on unconventional natural gas resources. Technology advances already have made most conventional supplies economically recoverable, and thus a reduced rate of technological progress has a larger impact on the cost of developing unconventional and offshore resources. Deepwater offshore resources are further constrained by infrastructure limitations and long lead times for the construction of new production platforms and pipelines. Thus, conventional production increases, unconventional production decreases, and there is only a small increase in offshore production in the limited natural gas supply case relative to the reference case. Although the natural gas technology and resource assumptions in the limited natural gas supply case apply to Canada as well as to the United States, LNG imports into Canada and Mexico are not constrained [62] and are responsive to higher prices. As a result, both countries are projected to increase their LNG imports and make more natural gas available to the U.S. market by pipeline. In the combined limited case, net natural gas pipeline imports in 2030 are almost 6 times the reference case level. Although U.S. pipeline imports of natural gas might be expected to increase in the limited electricity generation supply case, the assumed opening of an Alaska natural gas pipeline reduces Canadian exports to the United States. Before 2025, the largest source of incremental U.S. natural gas supply in the combined limited case is conventional lower 48 natural gas production. In 2030, however, higher natural gas prices cause net pipeline imports to become the largest source of incremental supply. Net pipeline imports in 2030 are 1.6 trillion cubic feet higher and account for slightly more than one-half of the total increase in natural gas supply in the combined limited case relative to the reference case. LNG imports into Canada and Baja California, Mexico, are 1.1 trillion cubic feet higher in the combined limited case than in the reference case in 2030, accounting for more than 50 percent of the increase in net pipeline imports. Other domestic production accounts for the remainder of the difference in incremental supply between the two cases in 2030, with onshore conventional production 1.3 trillion cubic feet higher and offshore production 0.2 trillion cubic feet higher in the combined limited case than in the reference case. The increases in domestic conventional natural gas production and pipeline imports offset declines in unconventional production and Alaska production. They also offset a decline in LNG imports that are eliminated from the combined limited case by assumption but are available in the reference case. Natural Gas Prices In each of the three limited cases, natural gas prices are higher than projected in the reference case (Figure 19). The assumptions for the limited natural gas supply case have a more significant impact on price than those for the limited electricity generation supply case, with natural gas wellhead prices 45 percent and 14 percent higher in 2030 than in the reference case, respectively. The largest difference from the reference case is in the combined limited case, with prices 89 percent higher than in the reference case in 2030. End-use prices for natural gas increase in response to the higher wellhead prices and moderate consumption, while price increases both result from and contribute to changes in the mix of supply sources. The reason for the large price variations across the cases is the need to turn to more expensive sources of supply to satisfy the demand for natural gas as consumption increases and available sources of supply diminish. With the exception of Alaska and unconventional natural gas, the domestic conventional natural gas resource base is largely depleted, and only limited production increases are possible in response to consumption increases. Most of the large conventional fields have already been discovered, leaving only the smaller and deeper fields that are more costly to develop. In the limited electricity generation supply case, which assumes the same resource base and rate of technological progress as in the reference case, unconventional natural gas production increases in response to higher prices. The assumptions for the limited natural gas supply case limit technological progress and reduce the size of the resource base, causing a much greater price increase than in the limited electricity generation supply case. Increased demand for natural gas in the limited electricity generation supply case raises the natural gas wellhead price in 2030 to $7.57 per thousand cubic feet, compared with $6.63 per thousand cubic feet in the reference case. In the limited natural gas supply case, the wellhead price in 2030 is $9.61 per thousand cubic feet, and in the combined limited case it is $12.55 per thousand cubic feet. Electricity Prices In the AEO2008 reference case, real electricity prices are projected to remain relatively flat, with the 2030 price slightly below the current price. In the three limited cases, all with higher natural gas prices, electricity prices in 2030 are 4 percent to 36 percent higher than 2006 prices (Figure 20). Electricity prices in 2030 in the limited electricity generation supply case are higher than those in the limited natural gas supply case, even though natural gas prices are lower, because there are more options to change the generation mix in the limited natural gas supply case. In the limited electricity generation supply case, with capacity additions largely restricted to natural gas technologies, electricity prices are more sensitive to changes in natural gas prices and are 13 percent higher in 2030 than projected in the reference case. In comparison, electricity prices in 2030 in the limited natural gas supply case are 5 percent higher than in the reference case. In the combined limited case, electricity prices in 2030 are 37 percent higher than in the reference case.
59. The reference case assumes that pipelines from Canada and Alaska will be connected to natural gas markets in the lower 48 States. If no Arctic pipelines were built, however, there would be no pipeline to move natural gas from Alaska’s North Slope to southern Alaska, where it would otherwise be converted to LNG and shipped to foreign and domestic customers. As an alternative, natural gas from the North Slope could be converted to petroleum liquids and transported through the existing Alyeska oil pipelines (also known as the TransAlaska Pipeline System). 60. Net LNG imports are slightly lower than gross LNG imports before 2011, because LNG exports to Japan from Alaska are expected to continue through 2011, at about 65 billion cubic feet per year. 61. U.S. Geological Survey, “USGS National Assessment of Oil and Gas Resources Update (December, 2006),” web site http://certmapper.cr.usgs.gov/data/noga00/natl/tabular/total.xls. The estimates cited in this discussion are rough approximations. The actual probability spread of the estimates is considerably larger. 62. If LNG imports into Canada and Mexico were constrained to the same degree as assumed for the lower 48 States, natural gas prices would be even higher, causing both a larger decrease in domestic natural gas consumption and a larger increase in lower 48 production.
Contact: Phyllis Martin/Joseph Benneche |
