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Annual Energy Outlook 2004 with Projections to 2025 Forecast Comparisons Index (click to jump links) The AEO2004 forecast period extends through 2025. One other organization—Global Insight, Incorporated (GII)—produces a comprehensive energy projection with a similar time horizon. Several others provide forecasts that address one or more aspects of energy markets over different time horizons. Recent projections from GII and others are compared here with the AEO2004 projections.
From 2002 to 2025, the projected growth in gross domestic product (GDP), based on 1996 chain-weighted dollars, is 3.0 percent per year. This projected growth is slightly lower than the 3.1-percent average annual growth projected in AEO2003 (Table 27). The AEO2004 forecast was based on the August 2003 long-range forecast of GII, modified to reflect EIA’s view on world oil prices. Through 2008, the AEO2004 forecast of 3.3-percent average annual growth in GDP is similar to other forecasts: the GII forecast is 3.3 percent, the same as the November 2003 forecast by Oxford Economic Forecasting (OEF), and both the July 2003 forecast by the Office of Management and Budget (OMB) and the August 2003 forecast by the Congressional Budget Office (CBO) show 3.2-percent average annual growth through 2008. From 2002 through 2013, the AEO2004, GII, and OEF forecasts show 3.2-percent growth per year, while the CBO forecast is 3.0 percent per year. From 2002 to 2025, the GII forecast shows 3.0-percent average annual growth in GDP. The range of average annual economic growth rates around the AEO2004 reference case is from 2.4 percent in the low economic growth case to 3.5 percent in the high economic growth case. Comparisons with other oil price forecasts—including GII, the International Energy Agency (IEA), Petroleum Economics, Ltd. (PEL), Petroleum Industry Research Associates, Inc. (PIRA), Natural Resources Canada (NRCan), Deutsche Bank A.G. (DB), Energy and Environmental Analysis, Inc. (EEA), National Petroleum Council (NPC), Strategic Energy & Economic Research, Inc. (SEER), and Centre for Global Energy Studies (CGES)—are shown in Table 28 (GII, Spring-Summer 2003; IEA, September 2002; PEL, April 2003; PIRA, October 2003; NRCan, 1997, reaffirmed in September 2002; DB, September 2003; EEA, October 2003; NPC, October 2003; SEER, November 2003; CGES, January 2003). The world oil price measure varies by forecast. In some it is the spot price for West Texas Intermediate (WTI), Brent, or a basket of crude oils. AEO2004 uses the composite U.S. refiners’ acquisition cost of crude oil, including transportation and fees. There is no simple way to put the forecasts for oil prices (Table 28) on a common basis. With the exception of PEL and CGES, which fall below the AEO2004 low world oil price case in 2020, the range between the AEO2004 low and high world oil price cases spans the range of published forecasts. The AEO2004 forecast of end-use sector energy consumption shows higher growth for petroleum and natural gas than occurred between 1980 and 2002, and growth in projected electricity consumption is only slightly less (1.8 percent compared to 1.9 percent) (Table 29). Much of the projected growth in petroleum consumption is driven by increased demand in the industrial sector for petrochemical and manufacturing applications as economic activity expands, and in the transportation sector as improvements in efficiency are unable to offset increases in miles traveled. Natural gas consumption is expected to increase in the residential, commercial, and industrial sectors as environmental and economic pressures benefit natural gas at the expense of petroleum and coal consumption. Coal consumption in those end-use sectors is expected to decline slightly as a result of increased fuel switching and growing concern about emissions. Electricity is expected to remain the fastest growing source of delivered energy (although not outpacing historical growth rates), because many traditional uses of electricity (such as for air conditioning) approach saturation while average equipment efficiencies rise. The AEO2004 projections are generally consistent with the outlook from GII; however, GII forecasts slower growth in natural gas consumption and electricity losses as well as slightly faster growth in petroleum consumption, resulting from differences in relative prices and projected growth in each sector. The AEO2004 electricity forecast assumes that wholesale markets in most U.S. regions will be restructured, resulting in average wholesale electricity prices that approach long-run marginal costs. The same cannot be said for retail markets at the State level: as of 2003, only 17 States and the District of Columbia had competitive retail markets in operation. Further, a number of States have delayed opening competitive retail markets, Arkansas has repealed retail restructuring, and California has suspended restructuring. The AEO2004 forecast assumes that no additional retail markets will be restructured, but that the partial restructuring (particularly in wholesale markets) will lead to increased competition in the electric power industry, lower operating and maintenance costs, lower general and administrative costs, early retirement of inefficient generating units, and other cost reductions. Comparison across the AEO2004, GII, and EEA forecasts shows slight variation in projected electricity sales (Table 30). The forecasts for total electricity sales in 2025 range from 4,861 billion kilowatthours in the AEO2004 low economic growth case to 5,527 billion kilowatthours in the AEO2004 high economic growth case. The AEO2004 reference case projection of 5,207 billion kilowatthours is framed by the GII forecast (5,072) and the Energy Ventures Analysis (EVA) forecast (5,341), with the SEER forecast at 5,319 billion kilowatthours. Demand growth rates range from 1.7 percent in the GII forecast to 1.8 percent in the AEO2004 reference case and 2.1 percent in the AEO2004 high economic growth case. All price forecasts reflect competition in wholesale markets and slow growth in electricity demand relative to GDP growth, exerting downward pressure on real electricity prices through 2025. Rising natural gas prices balance some of the downward pressure and tend to push electricity prices up in the later years of the forecasts. AEO2004 projects a slight decline in real electricity prices over the full period of the forecast, although average prices increase slightly during the last several years as capacity margins tighten and natural gas prices climb. In contrast, GII projects a decline over the second half of the forecast as lower natural gas prices to generators ($4.03 per quadrillion Btu in GII compared with $4.92 per quadrillion Btu in AEO2004 in 2025) contribute to a decline in average electricity prices from 7.1 cents per kilowatthour in 2010 and 2015 to 6.9 cents per kilowatthour in 2025 in the GII forecast. EVA, providing the only other price forecast, projects steady electricity prices over the forecast period. Both AEO2004 and GII incorporate large amounts of planned capacity in the short term, with AEO2004 projecting about 53 gigawatts through 2004 and GII projecting about 75 gigawatts, virtually all of which is expected to be gas-fired. These two forecasts project a glut of capacity with falling prices in the near term, along with steady capacity margins that begin to erode only in the later years. All five forecasts project that demand will grow fastest in the commercial sector and that more cycling and baseload capability will be built than peaking units. All the forecasts except EVA show significant net additions to coal-fired capacity: 101 gigawatts by 2025 in AEO2004, 57 gigawatts in the EEA forecast by 2020, and 130 gigawatts in the GII forecast by 2025. GII projects 2.5 gigawatts of nuclear retirements, more than AEO2004, which projects no retirements and 3.9 gigawatts of expansion through uprating of existing capacity. The EVA forecast of fuel-mix proportions differs substantially from AEO2004 and the other forecasts. Whereas all the other forecasts project that coal will provide about one-half and natural gas about one-quarter of electricity generation throughout the period, EVA projects much greater reliance on natural gas by 2025. The EVA forecast assumes that legislation similar to Clear Skies—including further restrictions on sulfur dioxide (SO2), nitrogen oxides (NOx), and mercury emissions—will be in effect by 2010. The EVA forecast also includes a $5 per ton tax on carbon dioxide emissions beginning in 2013. This combination (further environmental restrictions and a tax on carbon dioxide) allows for only marginal growth in coal-fired generation, with natural gas making up the shortfall (natural-gas- and coal-fired generation are nearly equal by 2025). Natural gas prices, and consequently electricity prices, are held in check by large gains in the efficiency of natural gas combined-cycle capacity. The differences among published forecasts of natural gas prices, production, consumption, and imports (Table 31) indicate the uncertainty of future market trends. Because the forecasts depend heavily on the underlying assumptions that shape them, the assumptions made in each forecast should be considered when different projections are compared. The AEO2004 reference case is within the range of projections for total natural gas consumption in the other forecasts throughout the forecast period. The lowest projected totals for natural gas consumption are from the NPC Balanced Future scenario, and the highest are from the EVA forecast. For residential and commercial natural gas consumption, DB projects the largest growth. The lowest consumption levels for these sectors are generally projected by GII or PIRA. The AEO2004 reference case projections fall in the middle of the range for residential consumption and toward the low end for commercial consumption. Natural gas consumption in the industrial and electric power sectors is more difficult to compare, given potential definitional differences. The EVA forecast shows the fastest growth in natural gas consumption in combined totals for the industrial and electric power sectors, whereas the NPC Reactive Path and Balanced Future scenarios and the DB forecast show much slower growth than the other forecasts. Domestic natural gas consumption is met by domestic production and net imports. All forecasts show domestic production providing a decreasing share of total natural gas supply, with AEO2004 and both NPC cases showing a smaller shift in that direction and significantly lower net imports. The two NPC cases generally project the lowest levels of pipeline and liquefied natural gas (LNG) imports, with the highest levels projected by EVA for both sources. Only EVA and GII project pipeline imports higher in 2025 than they are today; the NPC Balanced Future scenario projects pipeline imports in 2025 at less than one-third of current volumes. PIRA and EVA, as well as GII and DB in 2025, show net imports as providing a notably higher share of total supply than in the other forecasts. Wellhead natural gas price projections in the AEO2004 reference case are higher than in the other available forecasts (not all forecasts provide wellhead price projections), with the exception of EEA. Of the three forecasts that project end-use prices (AEO2004, GII, and EEA), AEO2004 shows the highest end-use-to-wellhead margins for the electric power sector and the lowest end-use-to-wellhead margins for the industrial sector. For the residential and commercial sectors, the projected margins in AEO2004 fall in the middle range of the available forecasts. Margins are notably lower for the residential and commercial sectors in the EEA forecast and for the electric power sector in the GII forecast (some of the differences may reflect definitional variations). The GII, DB, and PIRA forecasts of world oil prices and domestic petroleum production, consumption, and imports can be compared with the AEO2004 reference, low world oil price, and high world oil price cases (Table 32). The AEO2004 reference case projects a world oil price of $25.07 per barrel (2002 dollars) in 2015, compared with projections from GII at $24.08 per barrel, DB at $18.41 per barrel, and PIRA at $26.70 per barrel. PIRA’s higher projection, however, does not compare directly with the other forecasts, because its pricing point (West Texas Intermediate at Cushing, Oklahoma) differs from those in the other forecasts (refiners’ acquisition cost of imported crude oil) and tends to be higher. The AEO2004 reference case and GII price projections for 2020 and 2025 are also in a similar range, with the DB projections being significantly lower. The PIRA oil price forecast extends only to 2015. The AEO2004 reference case and GII projections for 2025 are almost identical, but DB’s projection is nearly $4.00 per barrel lower. The DB price forecast is more in line with the AEO2004 low price case forecast of $16.98 per barrel throughout the forecast period. DB’s oil price projections follow from the lower expected product demand than in the AEO2004 reference case, especially for gasoline. GII’s oil price projections follow from lower crude oil costs. The AEO2004 reference case and GII project domestic crude oil and natural gas liquids (NGL) production of about 7.8 million barrels per day in 2015. All other forecasts, except the AEO2004 high world oil price case, are more pessimistic about U.S. production in 2015. DB and PIRA are below even the AEO2004 low world oil price case, by 10,000 barrels per day and 560,000 barrels per day, respectively. GII is more optimistic about domestic crude oil and NGL production in 2025 than are DB and AEO2004. GII’s projection is 280,000 barrels per day above the AEO2004 high world oil price case. DB is at the opposite end of the spectrum, projecting production at 1.24 million barrels per day below the AEO2004 low world oil price case and 2.40 million barrels per day below the AEO2004 high world oil price case. All the forecasts project that imports will meet more than one-half of expected petroleum product demand in 2015. Both the AEO2004 reference case and PIRA project net imports of crude oil and petroleum products at 15.52 million barrels per day in 2015. GII’s projection is 370,000 barrels per day higher than those two forecasts, and DB’s projection is 410,000 barrels per day lower. When imports are considered as a percentage of demand, a slightly different pattern emerges. Although DB’s projected quantity of imports is below the AEO2004 reference case, its import share of product supplied is slightly higher (0.2 percent), because DB projects lower overall product demand in 2015. The AEO2004 high world oil price and low world oil price cases project the lowest and highest import shares, respectively. The forecasts project that imports will be needed to meet approximately two-thirds or more of product demand in 2025. GII projects 260,000 barrels per day more and DB projects 1.64 million barrels per day more than the AEO2004 reference case projection. In 2025, GII projects a higher volume of both imports and product demand than the AEO2004 reference case, with a lower share of imports needed to meet product demand. The AEO2004 high world oil price case projects the lowest share of imports in 2025, at 64.6 percent, and DB projects the highest share at 75.9 percent (1.3 percent above the AEO2004 low world oil price case). GII expects slower expansion of domestic refinery capacity than do the other forecasts and, therefore, projects larger quantities of petroleum product imports and correspondingly lower crude oil imports. GII projects petroleum product imports 2.15 million barrels per day above the AEO2004 low world oil price case projection of 3.03 million barrels per day in 2015, and 3.00 million barrels per day above the AEO2004 low world oil price case of 5.07 million barrels per day in 2025. GII projects higher levels of total petroleum demand in 2015, 2020, and 2025 than the AEO2004 reference case and a different product slate, with higher levels of jet fuel demand and lower levels of demand for gasoline, distillate, and residual fuel. GII expects more growth in air travel than do the other forecasts. While the DB forecast generally projects lower levels of petroleum demand in total and by product than do the AEO2004 and GII forecasts, it includes higher levels of demand for residual fuel oil in 2015, 2020, and 2025. The AEO2004 low world oil price case projects the highest amounts of gasoline, distillate, and residual fuel demand in 2015, 2020, and 2025. PIRA projects the lowest level of gasoline demand in 2015, 550,000 barrels per day below the AEO2004 high world oil price case. The AEO2004 high world oil price case projects the lowest level of gasoline demand in 2025. The unknown factors affecting the future of the coal industry, including the continued uncertainty of pending environmental regulations, are evident when the AEO2004 forecast is compared against those of EVA and Hill & Associates, Inc. The AEO2004 reference case does not anticipate when and how new environmental requirements may take effect, whereas the other forecasts may represent such assumptions. For instance, although AEO2004 does represent the provisions of the State implementation plan (SIP) call for 19 States where NOx caps have been finalized, it does not include revised limits on emissions of particulates, because no specific plan is yet in place. Hill & Associates assumes a 21-State SIP call in effect by 2005 and also assumes further reductions of allowable SO2 levels—4.35 million tons by 2010—in accordance with expectations of future restrictions on particulate emissions. EVA assumes that legislation similar to Clear Skies (including further restrictions on SO2, NOx, and mercury) will be in effect by 2010. EVA’s forecast also includes a $5 per ton fee on carbon dioxide emissions beginning in 2013. Neither Hill & Associates nor AEO2004 represents mercury or carbon dioxide reductions in its reference case. Given the more restrictive assumptions of the EVA forecast, it is not surprising that AEO2004 projects higher coal consumption levels than EVA in 2015, 2020, and 2025. AEO2004 also projects higher coal consumption levels than Hill & Associates, which may be explained partly by Hill & Associate’s assumption of additional restrictions on SO2 emissions. AEO2004 and EVA show an increase in coal production and consumption from 2002 to 2025, whereas the Hill & Associates forecast remains fairly flat through 2020 (and does not extend to 2025). The AEO2004 reference case projects a decline in real coal prices from 2002 to 2015 and 2020, followed by a small increase from 2020 to 2025 (Table 33). Hill & Associates projects average minemouth prices— excluding coking coal and exports—that are roughly the same as projected in the AEO2004 reference case in 2015 and 3 cents per million Btu lower in 2020. The slightly higher minemouth prices projected in AEO2004, relative to Hill & Associates, may be due in part to the higher production levels projected in AEO2004. The EVA forecast of national average minemouth prices, lower than the 2002 minemouth price, varies little between 2015 and 2020 and increases by less than 1 percent (based on short tons) from 2020 to 2025. As western production makes further inroads into markets traditionally served by eastern coal, the average heat content of the coals produced and consumed will drop as well, reflecting the lower thermal content per ton of western coals. The AEO2004 and EVA forecasts indicate similar average heat contents (calculated by dividing dollars per ton by dollars per million Btu). The average heat content of coal production in the EVA forecast is roughly 20.6, 20.4, and 20.3 million Btu per ton in 2015, 2020, and 2025, respectively, compared the AEO2004 reference case projections of 20.3, 20.3, and 20.2 million Btu per ton. Those similarities suggest comparable shares of western production in the two forecasts. In contrast, the average heat content associated with coal production in the Hill & Associates projections for 2015 and 2020 is about 22 million Btu per ton, indicating a relatively larger share of eastern production. Gross exports of coal represent a small and declining part of domestic coal production. In AEO2004, their share of total production is expected to fall from 4 percent in 2002 to roughly 2 percent in 2020 and 1 percent in 2025. Currently, coal is the only domestic energy resource for which exports still exceed imports. All the forecasts project that this will change, and that the United States eventually will import more coal than it exports. Hill & Associates projects the fastest rate of increase in net coal imports, with 20.4 million tons more coal imported than exported in 2015. Both EVA and AEO2004 project similar levels of net imports in 2025, at 17.8 and 22.7 million tons, respectively. Strong price competition from other exporters and the loss of markets as Europe moves away from coal for environmental reasons are among the causes for the long-term decline in export projections. The coal forecasts reviewed reflect the uncertainties facing the U.S. coal industry as it simultaneously adapts to the financial pressures arising from increasing environmental restrictions on coal use (both here and in Europe), restructuring of the U.S. electricity generation industry, and increasing competition from the relatively unexploited coalfields of international competitors.
Released: January 2004 |
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