6. Fossil Fuel Supply

The impact on fossil fuel supplies and prices from S.139 largely depends on the impact of S.139 on demand. Because of the broad nature of S.139 (all greenhouse gases), the method of allowance allocation (relying on historical 1990 and 2000 rather than current greenhouse gas emissions as a benchmark), the ability to trade allowances, the inclusion of specific regulations aimed at reducing petroleum consumption as a way to reduce import dependence, and the requirement that the Climate Change Credit Corporation use its funds to blunt the impact of the cost of the greenhouse gas emission reductions on selected groups (e.g., reducing the cost to consumers through the use of buy-downs, subsidies, negotiation of discounts, and consumer rebates, with a particular emphasis on low-income consumers), the impact on supply and price can vary extensively by consuming sector and fuel. As result, the impact on fossil fuel supply is not always intuitively obvious, although it is likely to be inversely correlated with the relative carbon content of the fuel. This chapter examines the projected impacts of S.139 on fossil fuel supplies and prices.

Natural Gas Industry

Natural gas is a clean, widely available fuel used in about 55 million homes for space heating¹⁵⁸ and in about 66 percent of the manufacturing plants¹⁵⁹ 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 south central part of the Nation. Gas is transported by pipelines from the production areas to consumers and becomes more expensive the farther the gas is shipped. Natural gas is typically cheaper than petroleum products and more expensive than coal on the basis of heating values.

Carbon Dioxide Emissions From Natural Gas Combustion

In 2001, combustion of natural gas by the end-use sectors and for the generation of electricity produced carbon dioxide emissions of 329 million metric tons carbon equivalent in the United States, about 21 percent of the U.S. total.¹⁶⁰ The industrial sector was responsible for the biggest share of those emissions, about 31 percent, followed by electricity generation, which contributed 28 percent of the carbon dioxide emissions from natural gas combustion. Natural gas consumption in the residential, commercial, and transportation sectors accounted for the remaining 41 percent of the carbon dioxide emissions from natural gas combustion.

Policies designed to reduce carbon dioxide emissions would generally boost natural gas consumption, principally because natural gas consumption would displace coal consumption in the electricity supply sector. Higher levels of gas production would require the development of more costly domestic gas resources, thereby pushing up wellhead gas prices. Higher prices for natural gas would eventually bring gas into competition with conservation (i.e., demand reduction) and alternative fuels, slowing the growth of gas consumption and prices.

In the reference and S.139 cases, cumulative carbon dioxide emissions from natural gas combustion from 2001 through 2025 are projected to be 10.4 and 10.5 billion metric tons carbon equivalent, respectively.

Although natural gas consumption from 2001 through 2025 is projected to be about 5 percent greater under S.139 than in the reference case on a cumulative basis, carbon dioxide emissions are only 1 percent greater because of the sequestration facilities projected to be built in conjunction with new natural-gasfired combined-cycle electricity generation plants.

Natural Gas Consumption

S.139 is expected to affect future natural gas supply and prices primarily by changing future projected natural gas consumption. Relative to the reference case, S.139 is projected to increase total natural gas consumption, on a cumulative basis from 2001 through 2025, by a total of 37.7 trillion cubic feet (Figure 6.1). In the reference case, total annual gas consumption is projected to be 34.7 trillion cubic feet in 2025, compared with 38.6 trillion cubic feet under S.139.

The increase in natural gas consumption under S.139 also increases the natural gas share of total U.S. energy consumption. In the reference case, natural gas is projected to be 26 percent of 2025 total U.S. energy consumption. In contrast, the natural gas share of total U.S. energy consumption under S.139 is expected to be 31 percent in 2025. Gas’ share increases because gas consumption is higher while total energy consumption is lower in the S.139 case (126.0 quadrillion Btu) than in the reference case (138.6 quadrillion Btu).

Most of the increase in natural gas consumption under S.139 over reference case levels occurs in the electricity generation sector. The large electric power sector increase in natural gas consumption results because S.139 is projected to substantially raise the cost of coal-fired electricity generation, which makes gas-fired plants the lowest cost option for generating electricity. Of the 37.7 trillion cubic foot increase in cumulative gas consumption from 2001 to 2025, 37.1 trillion cubic feet is projected to occur in the electric power sector (Figure 6.2).

Other sectors projected to post increases in natural gas consumption include the commercial sector, with an expected cumulative increase of 1.0 trillion cubic feet, and pipeline and lease fuel consumption,¹⁶¹ which accounts for another 1.5 trillion cubic feet of the cumulative increase. The increase in gas pipeline and lease fuel usage is a direct result of the increase in domestic gas production and transportation. Commercial gas consumption increases because the higher electricity cost projected in the S.139 case is expected to cause a significant increase in the volume of gas consumed in the production of electricity at commercial facilities. The growth of on-site commercial electricity generation is projected to outweigh the effect that higher gas prices have on reducing commercial gas consumption.

The residential and industrial sectors are projected to consume less natural gas under S.139 than in the reference case, on a cumulative basis from 2001 through 2025. The residential sector is projected to post a 1.8 trillion cubic foot cumulative reduction in gas use because of higher natural gas prices resulting from the overall increase in gas consumption and the lack of fuel switching options. Although gas prices to the residential sector increase, electricity prices increase by even more, thereby reducing the attractiveness of centrally generated electricity as a substitution option. On-site renewable energy continues to be more expensive that natural gas.

Cumulative industrial natural gas consumption declines by only 50 billion cubic feet in the S.139 case because of two countervailing effects. On one hand, the industrial sector is subjected to both higher gas prices and emissions allowance costs, which act to depress industrial natural gas consumption. On the other hand, high electricity prices encourage industrial entities to build more electric cogeneration facilities, which act to increase industrial natural gas consumption. Because these countervailing effects neutralize each other, industrial gas consumption remains relatively unchanged.

Total cumulative gas consumption in electricity generation from 2001 through 2025 is 20 percent greater in the S.139 case than in the reference case. A more detailed examination of gas consumption in electricity generation shows, however, that while S.139 total gas consumption is projected to increase significantly from 2001 through 2025, gas consumption in electric power generation is projected to decline in some regions (Figure 6.3). Specifically, the South Atlantic, Mountain, New England, and Pacific Census Divisions are projected to cumulatively reduce the volume of gas consumed in electric generation from 2001 through 2025 by 22, 16, 4, and 3 percent, respectively. These electricity gas consumption reductions occur primarily due to the higher price of gas under S.139 and the regional availability of lower cost substitutes, such as nuclear and renewable energy.

In those Census Divisions where natural gas consumption in electricity generation is projected to grow, the increases in natural gas consumption are generally quite large. The largest percentage increases in regional projections of gas-fired electricity occur in (1) the East North Central Census Division, with a 117 percent increase, (2) West North Central with a 39 percent increase, (3) East South Central with a 38 percent increase, (4) Middle Atlantic with a 31 percent increase, and (5) West South Central with an 11 percent increase. Generally, S.139 causes higher natural gas consumption levels (primarily in the electric power sector), which result in higher delivered gas prices. The higher prices tend to dampen natural gas consumption in the end-use sectors.

Natural Gas Supply

The cumulative 37.7 trillion cubic foot increase in natural gas consumption from 2001 through 2025 is matched by a commensurate increase in natural gas supplies. Of the increase in gas supplies, 13.2 trillion cubic feet, or 35 percent, is projected to come from an increase in domestic natural gas production, while the remaining 24.5 trillion cubic feet, or 65 percent, is projected to come from increased natural gas imports (Figure 6.4).

Of the 13.2 trillion cubic foot cumulative increase in domestic natural gas production from 2001 through 2025, 7.1 trillion cubic feet, or 54 percent, comes from onshore unconventional natural gas supply sources.¹⁶² Another 2.7 trillion cubic feet, or 20 percent of the cumulative increase in domestic gas production, is produced from onshore conventional gas supplies; and another 1.2 trillion cubic feet, or 9 percent, is projected to come from increased offshore natural gas production.

The remaining 2.2 trillion cubic foot increase in cumulative gas production from 2001 through 2025 is projected to come from Alaska. This cumulative increase in Alaskan natural gas production results from an earlier construction and operation date for the Alaskan gas pipeline. In the reference case, the Alaskan natural gas pipeline goes into operation in 2020, followed by a capacity expansion during 2025. In the S.139 case, the pipeline goes into operation 1 year earlier, in 2019, due to the higher future gas prices projected for the S.139 case. Similarly, the higher gas prices also cause the Alaskan pipeline expansion to go into operation 1 year earlier than the 2025 date projected in the reference case. In both the reference and S.139 cases, the MacKenzie Delta pipeline comes into operation in 2015, which makes currently stranded Canadian Arctic gas available to U.S. gas consumers.

Natural gas resources appear to be adequate to satisfy the production levels projected in both scenarios. In the reference case, between 2001 and 2025, domestic wells are projected to produce 564 trillion cubic feet out of an estimated technically recoverable resource base of 1,289 trillion cubic feet. In contrast, domestic wells are projected to produce a total of 577 trillion cubic feet under S.139. From 2001 through 2025, 44 percent of the technically recoverable gas resource base is produced in the reference case, compared with 45 percent in the S.139 case.

Of the 37.7 trillion cubic foot increase in cumulative 2001 to 2025 gas supplies, 24.5 trillion cubic feet is imported. Of the 24.5 trillion cubic feet, 78 percent or 19.1 trillion cubic feet is imported as liquefied natural gas (LNG), 16 percent or 3.9 trillion cubic feet is imported from Canada, and the remaining 6 percent or 1.6 trillion cubic feet is imported from Mexico.¹⁶³

The large cumulative increase in LNG imports under S.139 is expected to result from (1) the accelerated construction of new LNG terminals already projected to be built in the reference case, (2) the accelerated expansion of existing LNG terminals, and (3) the construction of additional new LNG terminals not projected to be built in the reference case. Generally, the higher gas prices associated with S.139 accelerate LNG construction schedules by about 2 years. In the reference case, total LNG deliveries are projected to be 6.6 billion cubic feet per day in 2025. In the S.139 case, total U.S. LNG deliveries are projected to be 91 percent higher, at 12.6 billion cubic feet per day in 2025. In the reference case, all new LNG terminals are projected to be built along the Gulf of Mexico and in the Bahamas.164 In the S.139 case, the bulk of LNG capacity is built in the Gulf and Bahamas, with some additional capacity being built in the South Atlantic Census Division.

Because natural gas imports account for 65 percent of total incremental supply, the relative proportions of each major gas source change significantly by the end of the forecast for S.139, relative to the reference case. As shown in Table 6.1, in 2025 the S.139 case projects gas imports to provide 28 percent of total U.S. gas supply, compared with 23 percent in the reference case. The increase in gas imports is largely attributable to an increase in the LNG import share of gas supply, which is projected to increase from 7.0 percent in the reference case to 12.0 percent in the S.139 case. The portion of supply expected to come from pipeline imports in 2025 increases slightly, from 16.0 percent in the reference case to 16.4 percent in the S.139 case.

Onshore conventional gas resources are projected to show the largest percentage point reduction in share of total gas supply, falling from 23.8 percent in the reference case to 21.6 percent in the S.139 case. In contrast, the other three domestic gas sources are projected to show less pronounced market share declines.

Natural Gas Prices

The primary effect of S.139 is to raise natural gas consumption, supply, and prices after 2010 (Figure 6.5). Gas prices are slightly lower prior to 2010 under S.139 than in the reference case. Consumers are expected to bank emissions credits by reducing their gas consumption prior to the effective date of the S.139 greenhouse gas emission limits. The reduction in pre-2010 gas consumption weakens gas prices during that period.

After 2010, S.139 is projected to result in higher natural gas prices than are projected in the reference case. The higher gas prices under S.139 result from higher projected gas consumption. Higher gas consumption levels under S.139 deplete domestic gas resources at a faster rate, resulting in the development of higher cost gas supplies.

In 2025 in the S.139 case, the average lower 48 wellhead natural gas price is 41 cents per thousand cubic feet higher (in 2001 dollars) than is projected in the reference case ($4.36 per thousand cubic feet versus $3.95 per thousand cubic feet). The price differential between these cases changes over time. Because the construction of an Alaskan natural gas pipeline and of new LNG terminals adds large “lumpy” increments of new gas supply capacity, gas prices weaken until this new capacity is fully absorbed by the growth in gas consumption. Because this new infrastructure is built at different times in the two cases, wellhead price softness is also projected to occur during different timeframes for the two cases. As a result, the gas price for the two cases has a tendency to weaken at different times, thereby causing the price spread between the two cases to change over time. The largest lower 48 wellhead price spread occurs in 2023 at 62 cents per thousand cubic feet.

Delivered natural gas prices equal the wellhead gas price plus transmission and distribution markups. The effective delivered cost of consuming gas, however, also includes the cost associated with purchasing emissions allowances for fuel consumption in the industrial (including petroleum refining), electric power, and transportation sectors. Figure 6.6 compares the 2025 effective delivered cost of gas, by cost component, for each end-use sector, for the reference and S.139 cases. In the industrial, electric power, and transportation sectors, the effective delivered cost of gas in 2025 is higher in the S.139 case (relative to the reference case) primarily due to the cost of emissions allowances, and secondarily due to the higher cost of gas supplies. In 2025, the greenhouse gas emissions cost for the industrial, electric power and vehicular transportation sectors is projected to average $3.25 per thousand cubic feet under S.139. Residential and commercial gas consumers do not bear a greenhouse gas emissions cost in the S.139 case, so the higher delivered gas prices for the residential and commercial sectors under S.139 directly result from the higher wellhead gas price associated with higher gas consumption levels.

Figure 6.7 shows the change in the effective delivered cost of gas to each of the end-use sectors over time due to S.139, and relative to the reference case. The effective delivered cost of gas to the industrial, electric power, and transportation sectors rises over most of the forecast period, because the cost of emissions allowances increases steadily through 2023 and then declines slightly until 2025. The change in the effective delivered cost of gas to the residential and commercial sectors primarily reflects the wellhead price differential between the reference and S.139 cases.

Natural Gas Pipelines

The construction of interstate pipeline capacity directly reflects changes in intraregional gas consumption and supply. The National Energy Modeling System does not constrain gas pipeline construction; that is, sufficient new capacity is built to accommodate the projected changes in regional consumption and supply.¹⁶⁵

As mentioned earlier, the MacKenzie Delta pipeline comes into operation in 2015 and the Alaskan North Slope pipeline is projected to go into operation in both scenarios, albeit at slightly different dates, that is 2020 in the reference case and 2019 in the S.139 case.

As noted earlier, the primary impact of S.139 is the projected increase in gas-fired electricity generation, which occurs primarily in the East North Central Census Division, with smaller regional increases occurring in the West and East South Central Census Divisions and the Middle Atlantic Census Division. Cumulative incremental gas supplies are expected to come from the following regions, in their order of relative importance: (1) LNG imports into the Gulf Coast, (2) Canadian imports, (3) Rocky Mountain gas production, (4) onshore Gulf of Mexico gas production, (5) lower 48 offshore gas production, and (6) Alaskan gas production. As a result of these changes in supply and consumption under S.139, additional new pipeline capacity is expected to be built along three major transportation corridors: (1) from Canada through the West North Central and into the East North Central and possibly further on into the Middle Atlantic; (2) from the Rocky Mountains through the West North Central and into the East North Central; and (3) from the coast of the Gulf of Mexico through the East South Central and into the East North Central, South Atlantic, and eventually the Middle Atlantic region.

Upstream Natural Gas Employment

The U.S. Department of Labor reports two data series regarding employment in the domestic petroleum exploration and production (E&P) industry: 1) eeu10131001(n), which pertains to oil and gas company employment, and 2) eeu10138001(n), which pertains to petroleum field service company workers. These employment data series do not differentiate between employees engaged in oil-related E&P activities and those working on gas-related E&P activities.¹⁶⁶ In order to develop separate estimates for each fuel, the projected petroleum employment levels were allocated to oil and to gas based on the projected relative proportions of future domestic oil and gas production, as measured on a Btu basis.

In 2001, the Department of Labor reported that 334,000 employees worked in oil and gas E&P activities. Because 12.3 quadrillion Btu of oil and 20.0 quadrillion Btu of gas were produced in 2001, gas E&P activities in 2001 are estimated to have employed 207,000 workers.

In the reference case, gas production grows throughout the forecast and so does gas E&P employment. Gas E&P employment is projected to grow to 273,000 people in 2025. Over the entire period spanning 2001 through 2025, the cumulative increase in gas E&P employment is 5.79 million person-years.

In comparison, the S.139 case projects higher gas employment levels due to higher gas production levels. From 2001 through 2025, the S.139 case projects a cumulative employment level of 5.93 million person-years and a 2025 employment level of 287,000 people. Compared with the reference case, the cumulative employment impact of the S.139 case from 2001 through 2025 is projected to be an additional 136,000 person-years. Natural gas E&P employment under S.139 does not increase to the same degree as the projected gas consumption levels, because natural gas imports are projected to account for 65 percent of the incremental gas supply projected under S.139 from 2001 through 2025.

Alternative Scenarios

The results from five alternate scenarios are discussed in this section: (1) the high technology reference case, (2) the S.139 high technology case, (3) the S.139 no new nuclear, no sequestration case, (4) the high gas price case, and (5) the high gas price S.139 case. The high technology reference case assumes high performance characteristics for the end-use demand and electricity generation sectors, similar to the assumptions made in EIA’s Annual Energy Outlook 2003 integrated high technology case.¹⁶⁷ The high technology reference case projects an energy future in the absence of S.139 enactment. The S.139 high technology case incorporates the same technology assumptions as the high technology reference case, but assumes the enactment of S.139. The S.139 no new nuclear, no sequestration case assumes S.139 enactment, and also assumes that neither of these two technologies would be commercially available through 2025. The high gas price case and high gas price S.139 case were developed to examine how S.139 might affect an energy future where gas prices are considerably higher than those projected in the reference case. These cases provide some insight as to the potential range of outcomes relative to natural gas supply, consumption, and prices that might result from passage of S.139. Generally, both high technology cases project lower future natural gas consumption. In contrast, the S.139 no new nuclear, no sequestration case projects higher future natural gas consumption than the S.139 case. The high gas price case and the high gas price S.139 case project both lower total gas consumption and less incremental gas consumption. Table 6.2 summarizes the projected results of five cases on natural gas consumption, supply, prices, greenhouse gas emissions, and employment relative to the reference case and the S.139 case.

A. High Technology Cases

The two high technology cases discussed in this analysis—the high technology reference case and the S.139 high technology case—assume that increased spending on research and development will result in earlier introduction, lower costs, and higher efficiencies for end-use technologies than in the reference case. The cost and efficiencies of the advanced fossil-fired and new renewable generating technologies are also assumed to improve relative to reference case values. The technological improvements assumed for these two cases reduce future energy requirements in general, and natural gas consumption in particular. For example, the high technology reference case projects significantly lower levels of future natural gas consumption than the reference case. On a cumulative basis from 2001 through 2025, the high technology reference case projects total gas consumption to be 672 trillion cubic feet, which is 5 percent less than the cumulative gas consumption projected for the reference case. The lower gas consumption level of the high technology reference case also reduces gas imports, domestic production and prices. In 2025, for example, the average lower 48 wellhead gas price is 44 cents per thousand cubic feet lower than projected in the reference case (i.e., $3.95 per thousand cubic feet in the reference case and $3.51 per thousand cubic feet in the high technology reference case).

In the remainder of this subsection, the impacts of S.139 will be appraised relative to the projections expected for the high technology reference case, comparing the S.139 high technology case projections with those of the high technology reference case. Relative to the high technology reference case, cumulative 2001-2025 gas consumption is projected to increase in the S.139 high technology case. Total cumulative gas consumption from 2001 through 2025 in the S.139 high technology case is projected to be 703 trillion cubic feet, which is 5 percent larger than the 672 trillion cubic feet projected for the high technology reference case. The 30.4 trillion cubic foot increase in cumulative natural gas consumption in the S.139 high technology case is largely attributable to the 29.7 trillion cubic foot cumulative increase in electric power gas consumption, relative to the high technology reference case.

The 2025 gas consumption level in the S.139 high technology case is higher than that projected in the high technology reference case, 35.6 trillion cubic feet versus 31.6 trillion cubic feet. Again, the higher 2025 gas consumption levels in the S.139 high technology case are largely attributable to higher electric power gas consumption. Under S.139, gas consumption in the electric power sector is 12.4 trillion cubic feet in 2025, compared with 8.6 trillion cubic feet in the high technology reference case.

In the S.139 high technology case, the higher gas consumption levels are matched by a commensurate increase in gas supply. Of the cumulative 30.4 trillion cubic foot increase in gas supplies from 2001 through 2025, 14.9 trillion cubic feet comes from gas imports, and the remaining 15.5 trillion cubic feet comes from domestic gas production. With respect to gas imports, 10.6 trillion cubic feet of the cumulative 2001-2025 increase in gas imports is projected to be imported as LNG.

With respect to domestic gas supplies, the 15.5 trillion cubic foot cumulative increase in domestic production in the S.139 high technology case is projected to be satisfied by a 7.1 trillion cubic foot cumulative increase in unconventional gas production, a 5.7 trillion cubic foot cumulative increase in Alaskan gas production due to the earlier construction and operation of a gas pipeline from Alaska to the lower 48 States, a 2.1 trillion cubic foot cumulative increase in conventional onshore gas production, and a 600 billion cubic foot cumulative increase in offshore gas production.

As before, the higher gas consumption levels in the S.139 high technology case are projected to result in higher gas prices relative to the high technology reference case. In 2025, the lower 48 average wellhead gas price is projected to be $4.09 per thousand cubic feet (in 2001 dollars), which is 58 cents per thousand cubic feet higher than the $3.51 per thousand cubic feet wellhead gas price projected in the high technology reference case.

Because cumulative incremental gas production is expected to increase in the S.139 high technology case relative to the high technology reference case, gas exploration and production industry employment levels are higher in the S.139 high technology case. Cumulative incremental 2001-2025 gas employment in the S.139 high technology case is projected to be higher by 116,000 worker-years than the high technology reference case, but 137,000 worker-years lower than the S.139 case.

B. No New Nuclear, No Sequestration Case

The no new nuclear, no sequestration case reduces the energy sector’s flexibility to comply with S.139 greenhouse gas emissions limits. The absence of new nuclear plants raises gas consumption. The absence of sequestration technology raises the cost of emission allowances. Not surprisingly, the no new nuclear, no sequestration case projects the highest level of gas consumption among the five cases discussed in this section. Because the no new nuclear, no sequestration case was developed to be consistent with the reference case, this discussion will compare the no new nuclear, no sequestration case to the reference case.

Cumulative 2001-2025 gas consumption in the no new nuclear, no sequestration case is projected to be 753 trillion cubic feet, which is 6 percent higher than in the reference case. As in the reference case, virtually all of this increase in cumulative gas consumption occurs in the electric power sector. Total cumulative 2001-2025 gas consumption is 45.1 trillion cubic feet greater in the no new nuclear, no sequestration case than in the reference case. Of this 45.1 trillion cubic foot increase in gas consumption, the electric power sector is projected to account for 43.7 trillion cubic feet of the incremental increase. The industrial and vehicular end-use sectors are expected to experience virtually no change in cumulative gas consumption, while the 1.6 trillion cubic foot increase in cumulative commercial gas consumption is more than offset by the 1.8 trillion cubic foot decline in cumulative residential consumption. Pipeline, plant and lease gas consumption is projected to increase by 1.6 trillion cubic feet on a cumulative basis, because of the higher level of domestic gas production.

The cumulative increase in gas consumption of 45.1 trillion cubic feet in the no new nuclear, no sequestration case is matched by a commensurate increase in natural gas supplies. As in the S.139 case, most of the increased gas consumption is supplied through gas imports. Net gas imports are projected to incrementally supply 30.3 trillion cubic feet from 2001 through 2025, for 67 percent of the total incremental gas supply. In the no new nuclear, no sequestration case, 23.9 trillion cubic feet of these incremental gas imports are projected to be delivered as LNG. Canada and Mexico are respectively projected to supply 3.3 and 3.1 trillion cubic feet of incremental gas supplies to the United States from 2001 through 2025.

U.S. domestic gas production is projected to cumulatively supply 14.8 trillion cubic feet of the incremental gas supply from 2001 through 2025. Onshore unconventional natural gas production is projected to account for 8.4 trillion cubic feet of the total, while onshore conventional gas contributes 3.6 trillion cubic feet and Alaska provides an incremental 2.2 trillion cubic feet. The offshore’s cumulative contribution to total gas supply increases by only 0.7 trillion cubic feet over the forecast period.

Natural gas E&P employment levels are projected to increase in the S.139 no new nuclear, no sequestration case, relative to both the reference and S.139 cases, due to higher gas production levels. In this case, 2025 gas E&P employment is projected to be 290,000, and cumulative 2001-2025 incremental employment is projected to be an additional 150,000 person-years, relative to the reference case.

In the no new nuclear, no sequestration case, the higher gas production rates deplete a higher proportion of the estimated gas resource base, thereby making the remaining gas resources more costly to produce. By 2025, in the no new nuclear, no sequestration case, the lower 48 wellhead gas price is projected to reach $4.70 per thousand cubic feet (in 2001 dollars), or 75 cents per thousand cubic feet greater than the 2025 wellhead gas price projected in the reference case.

The effective delivered cost of natural gas in the no new nuclear, no sequestration case is projected to be much higher than projected in the reference case, because both wellhead gas prices and greenhouse gas emission allowance costs are much higher. In 2025, the average lower 48 wellhead gas price is projected

to be $4.70 per thousand cubic feet (in 2001 dollars) in the no new nuclear, no sequestration case, which is 75 cents per thousand cubic feet higher than the $3.95 per thousand cubic foot prices projected in the reference case. In 2025, greenhouse gas emission allowance costs are projected to average $4.35 per thousand cubic feet for the electric power, industrial, and transportation sectors.

C. High Natural Gas Price Cases

The high gas price cases¹⁶⁸ were designed to analyze the effects associated with S.139 if natural gas prices were higher than projected in the reference case. The high gas price cases embody plausible assumptions regarding the causes for higher future gas prices. Those assumptions are:

• Both U.S. and Canadian gas resources are 25 percent less than the current resource base estimates assumed in the reference case.
• The petroleum industry’s future rate of technological progress is 25 percent lower than that observed historically (the reference case assumes the historical rate of technological progress).
• The Alaskan natural gas pipeline takes 10 years to plan, permit, and build rather than the 7 years expected in the reference case.
• New domestic LNG facilities cannot be constructed on the East and West coasts, but only in the Gulf of Mexico and in Florida,¹⁶⁹ whereas the reference case allows LNG facilities to be built in all three regions (i.e., East Coast, West Coast, and Gulf of Mexico).

With the exception of these four assumptions, the high gas price case uses all the other reference case assumptions. The high gas price S.139 case uses the same assumptions as the high gas price case, but also assumes the enactment of S.139.

These four gas supply assumptions create a more constrained gas supply picture, because there is less foreign gas potentially available to the market, which makes the country more dependent on domestic gas supplies, and because domestic gas is more expensive to produce. For example, the reference case projections are based on an estimated 1,289 trillion cubic feet of technically recoverable gas resources. By 2025, in the reference case, domestic gas wells are projected to produce 44 percent of the estimated technically recoverable resource base of 1,289 trillion cubic feet. In the high gas price cases, the technically recoverable gas resources base is assumed to be 967 trillion cubic feet. Between 2001 and 2025, the high gas price case is projected to cumulatively produce 514 trillion cubic feet, which is 53 percent of the assumed resource base. Gas prices are higher partly because there is a smaller domestic gas resource base, which experiences a greater degree of resource depletion than in the reference case projection. Moreover, the assumption that future technological progress in gas drilling and production will advance at a rate 25 percent below the historic trend also contributes to the higher gas prices projected for the two high gas price cases.

Figure 6.8 shows projected lower 48 average wellhead gas prices for both high gas price cases and for the reference case. Generally, the reference case projects lower prices because gas supplies are less constrained. Reference case wellhead gas prices are projected to rise gradually to $3.95 per thousand cubic feet (in 2001 dollars). In contrast, 2025 wellhead gas prices are projected to reach $5.55 per thousand cubic feet in the high gas price case and $5.70 per thousand cubic feet in the high gas price S.139 case. In both high gas price cases, the higher prices are projected to cause the Alaskan natural gas pipeline to begin planning and permitting around 2008, so that it becomes operational in 2018. In the reference case, however, the Alaskan gas pipeline comes into operation in 2020, with planning and permitting starting around 2014.

In the high gas price cases, the initiation of Alaskan gas pipeline operations in 2018 adds a large increment to domestic gas supply, thereby causing wellhead gas prices to weaken. Lower 48 wellhead prices are projected to remain more constant for the high gas price S.139 case than the high gas price case, because under S.139 any weakening in gas prices is immediately counterbalanced by an increase in gas consumption. In the high gas price case, the average lower 48 wellhead gas price rises by 38 percent after 2020, from $4.03 per thousand cubic feet (in 2001 dollars) in 2020 to $5.55 per thousand cubic feet in 2025. In the high gas price S.139 case, wellhead gas prices exceed $4 per thousand cubic feet in 2011 and continue to rise until peaking in 2024 at $5.83 per thousand cubic feet, then decline slightly to $5.70 per thousand cubic feet in 2025. In the high gas price S.139 case, the high gas prices just prior to 2025 cause both gas consumption to decline and domestic gas supplies to increase (as measured by gas reserve levels), thereby causing gas prices to decline slightly in 2025.

As shown in Figure 6.9, the high gas price cases differ from the other scenarios in one crucial respect, namely, that domestic gas consumption declines in both cases by the end of the forecast period. In the high gas price case, total U.S. natural gas consumption peaks in 2023 at 30.1 trillion cubic feet and declines to 29.3 trillion cubic feet in 2025. In the high gas price S.139 case, gas consumption peaks in 2020 at 31.2 trillion cubic feet and declines to 29.8 trillion cubic feet in 2025. The high gas price cases project a decline in consumption because high gas prices encourage consumers both to be more efficient in their use of natural gas and to substitute alternative energy sources wherever it is economically feasible.

Although total gas consumption declines toward the end of the forecast, the decline is not equally distributed among the end-use sectors. With the exception of a 20 billion cubic foot decline in residential gas consumption at the very end of the forecast, the sector primarily responsible for the overall decline in total gas consumption is electric power generation. In the high gas price case, electric power gas consumption peaks in 2022 at 7.6 trillion cubic feet and then declines to 6.7 trillion cubic feet in 2025. As shown in Figure 6.10, in the high gas price case, natural gas consumption in the electric power sector is reduced in the later years of the forecast by increased consumption of coal and petroleum fuels, which is a fuel substitution effect, caused by high gas prices.

Other than the decline in electric power gas consumption toward the end of each high gas price case projection, the gas consumption profile of the high gas price S.139 case relative to the high gas price case is similar to those projected for S.139 in the other alternate scenarios. Specifically, the enactment of S.139 under high gas prices increases total cumulative incremental gas consumption from 2001 through 2025 by only 11.4 trillion cubic feet, relative to the high gas price case.

Because the high gas prices in these cases make the use of natural gas less economically attractive, in the high gas price S.139 case, the electric power sector’s cumulative increase in gas consumption from 2001 through 2025 is only 14.2 trillion cubic feet more than in the high gas price case. In comparison, the cumulative increase in electric power gas consumption for the S.139 case relative to the reference case is projected to be 37.1 trillion cubic feet. Thus, the higher gas prices associated with these high gas price scenarios reduce the cumulative increase in electric power gas consumption by 62 percent relative to the reference case and S.139 case projections.

The impact of high gas prices on the electric power sector is also illustrated in the profile of electric generation capacity for the two high gas price cases. As can be seen in Figure 6.11, enactment of S.139 is projected to reduce 2025 coal-fired generation capacity by 218 gigawatts.¹⁷⁰ Because of high gas prices, total natural gas generation capacity is projected to increase by only 19 gigawatts between the two cases in 2025. In contrast, both nuclear and renewable energy are projected to show large incremental increases in capacity between the two cases, as an offset to the decline in coal-fired capacity. In 2025, in the high gas price S.139 case, nuclear power capacity is 66 gigawatts greater than projected in the high gas price case. Similarly, in 2025, renewable energy capacity is 171 gigawatts greater in the high gas price S.139 case than in the high gas price case.¹⁷¹ The net effect of high gas prices is to increase the economic attractiveness of nuclear, renewable energy, and coal sequestration technology relative to gas-fired capacity. If S.139 were enacted under these conditions, the electric power industry would be expected to build primarily new nuclear, renewable energy, and coal sequestration facilities to reduce the carbon emissions produced by coal-fired electricity generation.

In the high gas price cases, the other end-use sectors also react in a similar manner to enactment of S.139. Residential and industrial gas consumption levels are projected to decline on a cumulative basis from 2001 through 2025—by 2.2 and 1.7 trillion cubic feet, respectively—due to the higher gas prices. In the industrial sector, the reduction in natural gas consumption reflects the overall drop in industrial energy use.¹⁷² The commercial sector, in contrast, is projected to show a cumulative increase in commercial gas consumption, due to the sector’s ability to employ distributed electricity generation facilities as a means of avoiding the higher electricity prices projected as a result of S.139 enactment.

Because these high gas price cases are the result of a more constrained gas supply picture, relative to the alternate scenarios discussed earlier, they are significantly different with respect to the incremental sources of gas supply used to meet S.139 greenhouse gas emissions limits. Figure 6.12 shows the cumulative increase in gas supplies provided by the various supply sources from 2001 through 2025 for the high gas price S.139 case relative to the high gas price case. The limitations placed on Canadian and LNG imports significantly reduce their role in providing incremental gas supplies in the high gas price S.139 case.

In the prior scenarios, about two-thirds of cumulative 2001-2025 incremental gas supply came from natural gas imports and about one-third came from domestic production. In the high gas price gas cases, gas imports account for 46 percent of the cumulative 2001-2025 incremental gas supplies and domestic gas supplies account for the remaining 54 percent of cumulative 2001-2025 incremental gas supplies.

Because gas imports are limited both by smaller Canadian resources and the inability to build new LNG capacity on the East and West coasts, domestic supplies are required to make up the difference. Of the domestic gas supply sources, unconventional natural gas is projected to contribute 40 percent of the incremental gas supply projected for the high gas price S.139 case relative to the high gas price case.

Petroleum Industry

Nearly 40 percent of the Nation’s energy comes from petroleum, with two-thirds of that amount consumed in the transportation sector. The industrial sector accounts for 24 percent of the petroleum consumption, with the remaining 9 percent consumed by residential and commercial users and for power generation. Fifty-five percent of the Nation’s crude and petroleum products were imported at a cost of $89 billion in 2001, of which 61 percent was from Canada, Saudi Arabia, Venezuela, and Mexico. Domestic oil is produced mainly in Texas, Alaska, Louisiana, and California.

U.S. oil consumption is expected to increase by 9.23 million barrels per day between 2001 and 2025 in the reference case, despite a projected decline in domestic oil production. Most of the growth is expected in the transportation sector, where oil consumption is projected to increase by 7.98 million barrels per day from 2001 to 2025. About 61 percent of the increase comes from light-duty vehicle travel and 13 percent from increased air travel, with the remaining from the demand growth in the industrial, commercial, and residential sectors. Oil use in the industrial sector is projected to increase by about 35 percent between 2001 and 2025, mostly in refining and petrochemical feedstocks. As a result of these increases, petroleum’s share of the energy market is projected to increase slightly over time.

While petroleum production from conventional sources in the lower 48 States is expected to fall between 2001 and 2025, offshore and Alaskan production (excluding any future contribution from the Alaskan National Wildlife Refuge) are expected to increase, but not enough to prevent an overall decline. Net imports of crude oils and petroleum products are projected to rise to make up the difference between consumption and production. In the reference case, about 68 percent of the U.S. petroleum supply in 2025 is projected to come from imports, with two-thirds of total imports entering the country in the form of crude oil and the rest as finished or unfinished products.

Policies aimed at reducing greenhouse gas emissions would lead to lower consumption, production, imports, and refinery margins for the U.S. oil industry. However, end-use prices would be higher for consumers in sectors covered by S.139. Higher end-use prices—including the cost of greenhouse gas emission allowances—would reduce consumption in the greenhouse gas reduction cases, lessening the need for foreign imports. Refinery margins in those cases would be lower, because consumption of petroleum products and expansion of refinery capacity are projected to be lower than in the reference case. Petroleum’s share of the energy market is not expected to change significantly as a result of S.139, because there are limited alternatives to petroleum-based transportation fuels through the forecast period.

Petroleum Consumption

Petroleum consumption is expected to be lower in the greenhouse gas reduction cases than in the reference case (Figure 6.13). Consumption rises throughout the forecast in the reference case, from 19.69 million barrels per day in 2001 to 28.92 million barrels per day by 2025. In the greenhouse gas reduction cases, the allowance prices necessary to meet the greenhouse gas reduction in S.139 lead to lower levels of petroleum consumption in 2025—26.18 million barrels per day in the S.139 case. This trend follows closely the projected greenhouse gas allowance prices—the higher the allowance price, the greater the decline in consumption.

Consumption in the transportation sector is particularly affected by the greenhouse gas limits. Seventy-seven percent of the difference in petroleum consumption (2.74 million barrels per day) between the reference case and the S.139 case in 2025 is in the transportation sector. The rest of the difference comes mostly from the industrial sector. Eighty-five percent of the decline in the transportation sector in the S.139 case relative to the reference case comes from a decline in gasoline consumption (1.79 million barrels per day), with most of the rest of the decline from highway diesel (269,000 barrels per day). The reduction in motor fuels consumption is the direct result of reduced vehicle miles traveled and improved vehicle fuel efficiency caused by demand reactions to the greenhouse gas allowance price imposed on transportation fuels. The reduction in petroleum consumption accounts for about 42 percent of the reduction in total U.S. energy consumption by 2025 in the S.139 case.¹⁷³

Petroleum Supply

In the reference case, total lower 48 States crude oil production is projected to increase from 4.84 million barrels per day in 2001 to 5.29 million barrels per day in 2007, then to decline to 4.13 million barrels per day by 2025. The projected peak in 2007 is attributable primarily to offshore oil production (including the Gulf of Mexico and offshore California), which is more sensitive to changes in technology than onshore production. Roughly equal amounts of the lower 48 States onshore and offshore crude oil production are projected between 2007 and 2025, either on an annual or cumulative basis. Alaskan crude oil production in the reference case is expected to decline to 640,000 barrels per day in 2010. After 2010, the projected drop in oil production is expected to be offset by new oil production from the National Petroleum Reserve—Alaska (NPR-A), with the Alaskan crude oil production growing to a peak of 1.28 million barrels per day in 2021 through 2023, then to decline to 1.17 million barrels per day by 2025.

The greenhouse gas reduction cases have much less impact on U.S. domestic oil production than on imports. Domestic oil production in the greenhouse gas reduction cases are slightly lower than that projected in the reference case, resulting in negligible changes in oil production employment. The institution of greenhouse gas allowance prices depresses oil demand, but most of the decline in petroleum supply is from imports (Figure 6.14). The projections for net imports of crude oil and petroleum products are lower in the greenhouse gas reduction cases, with domestic sources providing a greater share of the Nation’s oil needs. As a share of total consumption, net oil imports reach 68 percent in 2025 in the reference case but only 65 percent in the S.139 case.

The Nation’s oil import dependence still grows in the S.139 case, although at a more modest pace relative to the reference case. In 2025, net petroleum imports (including both crude oil and petroleum products) in the S.139 case are projected to be 2.67 million barrels per day less than in the reference case. Natural gas plant liquids production grows by 100,000 barrels per day in 2025 in the S.139 case to compensate mostly for the reduction in petroleum production and imports to meet the demand, largely because of natural gas plant liquids’ lower carbon content per unit volume. Petroleum product imports account for 84 percent of the total reduction in oil imports in the S.139 case, with a 2.26 million barrel per day reduction in 2025. Mirroring the reduction in consumption, gasoline accounts for most of the reduction in petroleum product imports, with 1.79 million barrels per day in 2025, followed by 340,000 barrels per day for distillate (including diesel), 197,000 barrels per day for liquefied petroleum gas (LPG), and 50,000 barrels per day for jet fuel. Crude oil imports decline by 416,000 barrels per day in 2025 in the S.139 case because it is less expensive to produce petroleum products domestically than to import them. The greenhouse gas allowance prices in the greenhouse gas reduction cases yield larger shifts in product imports than in crude oil imports.

Finished petroleum products carry higher wholesale prices than crude oil. All greenhouse gas reduction cases result in substantial reductions in petroleum product imports, thus leading to substantial cost savings. In the reference case, the Nation is projected to spend $206 billion (2001 dollars) on petroleum imports in 2025 alone, an increase of $117 billon from 2001. In the S.139 case the spending on petroleum imports is projected to reach $159 billon by 2025, $47 billion lower than the reference case, mostly from importing less petroleum products. Most significantly, the cumulative savings in petroleum imports from 2010 to 2025 in the S.139 case relative to the reference case is $358 billion.

U.S. dependence on foreign oil is not significantly reduced prior to 2010 in the greenhouse gas reduction cases before the Phase 1 allotment for greenhouse gas emissions (benchmarked at the 2000 level) becomes effective. After 2010, due to the banking provisions of S.139, the effect of the Phase 2 allotment gradually phases in, because the overall tradable allowances are further limited starting in 2016. The impact of the Phase 2 allotment becomes more pronounced in the later forecast years because the limit is set without regard to economic growth.

Petroleum Product Prices

Under S.139, refiners and importers are required to purchase greenhouse emission allowances for petroleum products sold for transportation use. Refiners are also required to purchase allowances for fuel consumed in the refining of crude oil. For all other petroleum products, covered end-use consumers would need to purchase allowances. The effective price (including greenhouse gas allowance costs) of petroleum products consumed in the industrial, utility, and transportation sectors is higher in all greenhouse gas reduction cases because of the cost of the greenhouse gas allowances. The average effective price (including all greenhouse gas allowance costs) for all petroleum products in the S.139 case is $0.171 per gallon higher in 2010 when the Phase 1 allotment of the greenhouse gas emissions takes effect, and $0.261 per gallon higher in 2016 as a result of the Phase 2 allotment, and $0.390 per gallon higher in 2025 relative to the reference case (Figure 6.15).

Gasoline is the most affected petroleum product due to its large consumption base among all petroleum products. As a result, its price increases in the S.139 case parallel that of all petroleum products combined, rising $0.190 per gallon in 2010, $0.294 per gallon in 2016, and $0.402 per gallon in 2025 (Figure 6.16). The rise in the gasoline price in 2025 in the S.139 case is almost four times the Federal gasoline tax (discounted to the 2001 value). Diesel is more carbon-intensive than gasoline on a per-gallon basis and therefore is more sensitive to greenhouse gas emission caps. The increases in highway diesel prices range from $0.211per gallon in 2010 and $0.320 per gallon in 2016 to $0.516 per gallon by 2025.

Prices for the LPG, distillate, and residual fuels used in the residential and commercial sectors are marginally lower in the S.139 case, because these two sectors are not assumed to be covered under S.139 and overall petroleum consumption is lower relative to the reference case. These fuels could differ significantly in prices depending on the end use. For example, in the S.139 case in 2025, the price for distillate used in the residential sector is projected to be $1.19 per gallon (2001 dollars), while the effective price for distillate used in the industrial sector is projected to be $1.51 per gallon since the price of the greenhouse gas allowance is included.

Refineries

U.S. refineries as a whole are more complex than foreign refineries due largely to the stringent transportation fuel specifications and a larger market share for gasoline consumption. Because of the economy of scale in making large quantities of transportation fuels that meet the U.S. specifications, it is generally cheaper to supply petroleum products by processing the crude oils domestically rather than importing finished products from foreign sources. However, because of construction permitting restrictions and environmental regulations, it is difficult to expand domestic refinery capacity. As a result, much of the projected growth in petroleum product supply is met with imported product.

In the reference case, the crude oil processed in domestic refineries amounts to 16.8 million barrels per day in 2001, 19.1 million barrels per day in 2016, and 19.8 million barrels per day in 2025. By comparison, in the S.139 case U.S. domestic crude oil processing capacity is 19.0 million barrels per day in 2016 and 19.3 million barrels per day in 2025, slightly less than in the reference case. Thus, almost all reductions in the Nation’s petroleum consumption in the greenhouse gas reduction cases are attributable to reductions in petroleum product imports as the marginal source of petroleum product supply.

The average utilization rate projected for domestic refineries through the forecast horizon is slightly lower in the S.139 case than in the reference case, but the difference is within 0.5 percent. In the reference case the utilization rate (the ratio of actual crude oil throughput in a refinery to its capacity) is projected to be 93.1 percent in 2010 and to rise to 94.6 percent in 2025. In comparison, the utilization rates in the S.139 case are projected to be 92.8 percent in 2010 and 94.6 percent in 2025. Because most of the reduction in petroleum consumption is projected to result in reduced petroleum product imports, S.139 is not projected to cause refinery closures or underutilization due to the reduction in petroleum consumption.

Between 2004 and 2025, a cumulative $59 billion (2001 dollars) is projected to be invested by U.S. domestic refiners for expansions and updates in the reference case. During the same period, $53 billion is invested in the S.139 case, $6 billion lower. The reductions in investments are significant even though the projected domestic refinery capacities and utilizations are not very different compared to the reference case. This is because domestic production of gasoline and diesel is reduced in the S.139 case relative to the reference case. Because of the changes in the domestic refinery product slate, smaller investments for clean-fuel production are needed to meet Tier 2 low-sulfur gasoline and ultra-low-sulfur diesel (ULSD) standards.

Ethanol and Biodiesel

In the S.139 case ethanol and biodiesel are assumed to be exempt from the greenhouse gas allowances required for gasoline and diesel fuel. Growing additional corn to produce ethanol or growing additional soybeans to produce biodiesel absorbs an amount of carbon dioxide equal to the carbon dioxide emissions from the production and consumption of these fuels. However, the greenhouse gas allowance prices for gasoline and diesel fuel do not increase the overall prices of these fuels enough to significantly increase the penetration of ethanol or biodiesel. Table 6.3 shows that the price of ethanol per gasoline gallon equivalent is well above the price of gasoline in all cases. Energy costs are the sole reason for variation in ethanol production cost. Ethanol production requires natural gas and electricity. The prices of both sources of energy vary according to the greenhouse gas allowance price. The price of corn to ethanol producers, the largest single ethanol cost component, is projected to be $1.79 per gasoline gallon equivalent in 2025 in all cases since agriculture is exempt from coverage under S.139.¹⁷⁴ A gasoline gallon equivalent of ethanol is 1.5 gallons of ethanol, because a gallon of ethanol contains only 67 percent of the energy of a gallon of gasoline.

The price of virgin oil biodiesel at the plant gate in 2025 is projected to be $3.17 per diesel gallon equivalent in all cases. The price of non-virgin oil biodiesel at the plant gate in 2025 is projected to be $1.77 per diesel gallon equivalent in all cases.¹⁷⁵ A diesel gallon equivalent of biodiesel, whether from virgin oil or non-virgin oil, is 1.12 gallons of biodiesel, because a gallon of biodiesel contains only 89 percent of the energy of a gallon of diesel. The U.S. average price of ULSD at the refinery gate, including the cost of the greenhouse gas allowance, is projected to be $1.40 per gallon in 2025 in the S.139 case.

Production of biodiesel from soybean oil in all greenhouse gas reduction cases is exactly the same as in the base case, because the carbon savings are not large enough in any case to induce additional demand. The Department of Agriculture’s Commodity Credit Corporation provides funding for new and expanded soybean oil biodiesel production through 2007. After 2007, biodiesel production is expected to grow at the same rate as diesel production. Under these assumptions, 63 million gallons of biodiesel will be produced from soybean oil in 2025.

S.139 has competing effects on the demand for ethanol for gasoline blending. Demand for ethanol decreases because of decreased demand for gasoline, but demand for ethanol increases because it is exempt from the greenhouse gas allowance program. Because of the economics of ethanol production, ethanol production decreases once the greenhouse gas allowance program begins in 2010. By 2025, ethanol production is 475 million gallons per year below the reference case. Although ethanol is not competitive with gasoline as a source of energy, the greenhouse gas allowance exemption makes ethanol more attractive as a source of octane, as a sulfur dilutant, and as a toxics dilutant. As a result, even though the total amount of ethanol blended gasoline has been reduced, the remaining blends contain a slightly higher percentage of ethanol. This effect translates to an additional 24 million gallons of ethanol blended to gasoline in 2025 than would be expected without the greenhouse gas allowance exemption. Ethanol production is projected to reach 3.483 billion gallons per year in 2025 in the S.139 case. Only one new ethanol plant, with an annual capacity of about 40 million gallons will be needed to supplement the existing 2.894 billion gallons of operable capacity and the 547 million gallons of new and expanded capacity due by January 1, 2005.¹⁷⁶

Alternative Scenarios

Among all greenhouse gas reduction cases, the S.139 high technology case results in the most reduction in petroleum consumption. The Nation’s petroleum consumption is projected to reach 25.52 million barrels per day in 2025 in the S.139 high technology case, 1.95 million barrels per day less than in the high technology reference case (Table 6.4). The large reduction in petroleum consumption in the S.139 high technology case is attributed to two factors—more efficient energy use and greenhouse gas allowance costs. The efficiency improvements assumed in end-use, fossil electricity, and renewable technologies, as represented in the high technology reference case, result in a reduction in petroleum consumption of 1.45 million barrels per day in 2025 relative to the reference case. The greenhouse gas allowance cost leads to further reduction in petroleum consumption between the S.139 high technology case and the high technology reference case. The reduction in petroleum consumption in the high technology reference case helps to reduce petroleum imports as well, 1.25 million barrels per day less than the reference case in 2025. With the greenhouse gas allowance cost imposed, such as in the S.139 high technology case, the net petroleum imports in 2025 are projected to decrease by 1.86 million barrels per day relative to the high technology reference case.

The no new nuclear, no sequestration case also results in a reduction in petroleum consumption. The Nation’s petroleum consumption is projected to reach 25.97 million barrels per day in 2025 in the no new nuclear, no sequestration case, lower than the S.139 case total of 26.18 million barrels per day in 2025 and about 3 million barrels per day lower than the reference case total of 28.92 million barrels per day. In the no new nuclear, no sequestration case, the options for producing less greenhouse gas emissions are severely limited, thus leading to a further reduction in petroleum consumption. Net petroleum imports in the no new nuclear, no sequestration case are 200,000 barrels per day less than in the S.139 case. In the no new nuclear, no sequestration case, the average petroleum product price is projected to go even higher at $1.82 per gallon in 2025.

Coal Markets

Background

Coal provides the largest share, nearly 33 percent, of U.S. domestic energy production. In 2001, coal accounted for 51 percent of total U.S. electricity generation, including output at combined heat and power plants. In turn, coal consumed for electricity generation during 2001 represented 91 percent of total domestic coal consumption.¹⁷⁷ Steam coal is also consumed in the industrial sector to produce process heat, steam, and synthetic gas and to cogenerate electricity, and metallurgical coal is used to make coke for the iron and steel industry. In the reference case, coal production and domestic consumption (expressed in tons¹⁷⁸) are projected to increase at rates of 1.0 and 1.4 percent per year, respectively, primarily reflecting the continued growth of coal consumption for electricity generation.

The proposed limitations on greenhouse gas emissions will have a significant negative impact on the coal industry. In the greenhouse gas reduction cases analyzed here, the advantages of the low carbon content of natural gas and the zero net greenhouse gas emissions that are associated with nuclear and renewable fuels offset the relatively low fuel cost of coal for use in electricity generation. Thus, coal markets are projected to be severely affected, in terms of both overall sales and supply patterns, as the need to reduce greenhouse gas emissions results in significant shifts away from coal consumption to natural gas, nuclear, renewable energy, and efficiency improvements in the demand sectors.

Carbon Dioxide Emission Considerations

Coal, oil, and natural gas respond differently to restrictions on greenhouse gas emissions. Of the three, coal is most affected for reasons that relate to the nature of its markets and its chemical structure. Electricity generation markets, by far the largest market for coal, are becoming increasingly competitive and cost-conscious as various restructuring initiatives are acting to gradually transform the industry from a mostly regulated (cost-of-service pricing) market to a competitive market. Fossil fuels derive their energy content primarily from oxidation of their carbon and hydrogen contents. A constraint on the allowed amount of greenhouse gas emissions through the required use of allowances places a cost on greenhouse gas emissions from burning fossil fuels (i.e., a greenhouse gas allowance price) which falls most heavily on coal, primarily because coal derives a higher percentage of its energy content from the oxidation of carbon than either oil or natural gas. Carbon dioxide emissions per unit of energy obtained from coal are nearly 80 percent higher than those from natural gas and about 35 percent higher than from motor gasoline. The lower average conversion efficiency of coal-fired power plants relative to natural gas-fired plants results in yet a higher carbon emissions factor per unit of electricity generation. In 2001, average carbon dioxide emissions per unit of generation from coal-fired plants were 85 percent higher than from natural gas plants.

Coal is heterogeneous in terms of both its energy content and carbon content, although, compared with differences in energy content, variations in carbon dioxide emissions factors are relatively minor across coal supply regions and types of coal. For example, the carbon dioxide emissions factors represented in the National Energy Modeling System range from a low of 24.91 million metric tons carbon equivalent per quadrillion Btu for bituminous coal mined at surface mines in the Eastern Interior supply region (Illinois, Indiana, and western Kentucky) to a high of 26.79 million metric tons carbon equivalent per quadrillion Btu for North Dakota lignite. Thus, the largest carbon dioxide emissions factor represented for coal is only about 8 percent higher than the smallest emissions factor. In general, lower ranked lignite and subbituminous coals derive a higher proportion of their energy from carbon than does bituminous coal. As a consequence, restrictions on carbon dioxide emissions will increase the end-use price of coal sourced from the Northern Great Plains (Wyoming and Montana), North Dakota, and Texas by more than the price of coal sourced from bituminous coalfields such as those in Colorado and Utah, the Appalachian States, and the Eastern Interior region. Variations in hydrogen content in part explain the variations in carbon dioxide emissions factors across coal ranks, with subbituminous and lignite typically containing smaller quantities of hydrogen than bituminous coal.¹⁷⁹ On a pound-for-pound basis, the combustion of hydrogen generates about four times the amount of heat than the combustion of carbon.¹⁸⁰

Although carbon capture and sequestration technologies for coal-fired power plants are currently not economically attractive, these technologies may become a commercially viable option in the carbon reduction scenarios, with new plants projected to be built between 2015 and 2025. However, because these technologies are in the early stages of commercialization, there is considerable uncertainty about their future. An alternative case was developed in which sequestration was assumed to be unavailable. The primary sequestration technology represented in the National Energy Modeling System is an integrated gasification combined cycle coal plant supplied with additional equipment designed to capture 90 percent of the plant’s carbon dioxide emissions. The combined capital, operating, and maintenance costs for these plants also include the costs of sequestering the captured carbon dioxide emissions into a geological reservoir. (For a discussion of the estimated cost and performance characteristics of new generating technologies used by EIA for this study and their relative competitiveness based on projected levels of both fuel and greenhouse gas allowance costs, see the discussion on Electricity Supply in Chapter 5.)

Coal Consumption

In the reference case, domestic coal demand is projected to increase by 416 million tons, from 1,050 million tons in 2001 to 1,466 million tons in 2025 (Table 6.5), almost entirely because of projected growth in coal use for electricity generation. Total coal demand in other domestic end-use sectors is projected to remain relatively constant.

Coal consumption for electricity generation is projected to increase from 957 million tons in 2001 to 1,371 million tons in 2025 as the utilization of existing coal-fired generation capacity increases and, in later years, new capacity is added. The average utilization rate (excluding combined heat and power plants) is projected to increase from 69 percent in 2001 to 83 percent in 2025. Coal-fired generating capacity increases from 315 gigawatts in 2001 to 386 gigawatts in 2025, the net result of 81 gigawatts of projected new coal builds less 10 gigawatts of retirements. Despite increased utilization of coal plants and considerable additions of new capacity, coal’s share of total electricity generation is projected to decline slightly from 51 percent in 2001 to 48 percent by 2025, primarily due to a substantial increase in generation from new gas-fired plants. The share of total generation fueled by natural gas is projected to increase from 17 percent in 2001 to 28 percent by 2025.

In the S.139 case, requirements to reduce greenhouse gas emissions in all sectors of the economy (excluding the residential and commercial sectors), lead to a large shift in U.S. energy consumption away from coal to lower carbon-emitting fuels such as natural gas, renewable energy, and nuclear. The strong negative impact on U.S. coal consumption is primarily the result of three key factors: 1) high carbon dioxide emission factors for coal; 2) greater opportunities for fuel substitution in the electricity sector than in other sectors of the economy; and 3) relatively low emission abatement costs for greenhouse gases in the electricity sector, which leads to greater reductions of greenhouse gas emissions in this sector than in other sectors. In the S.139 case, carbon dioxide emissions in the electricity sector by 2025 are projected to be 76 percent less than the amount projected in the reference case. By comparison, total U.S. carbon dioxide emissions by 2025 are projected to be 34 percent less than in the reference case, and emissions in the industrial and transportation sectors in 2025 are 34 and 10 percent less, respectively, than in the reference case.

In the S.139 case, coal consumption for electricity generation is projected to increase from 957 million tons in 2001 to 966 million tons in 2010, but then declines precipitously to 227 million tons by 2025.

Electricity coal consumption in the S.139 case is 16 percent less than in the reference case in 2010 and 83 percent less in 2025.

Except for new integrated gasification combined cycle coal plants equipped with carbon capture and sequestration equipment, coal-fired capacity in the S.139 case gradually transitions from a position of primarily baseload capacity to one of intermediate capacity. Due to increasing greenhouse gas emission allowance costs in the S.139 case over the forecast horizon, natural gas, nuclear and renewable fuels plants gradually displace existing coal-fired capacity as lower cost sources of electricity generation. In addition to the cost of greenhouse gas allowances, operating and maintenance costs per unit of electricity generated will increase for coal plants run at low capacity utilization rates because of thermal fatigue and the inefficiencies of starting and stopping units that were designed for baseload operation. In the S.139 case, the average utilization rate of coal-fired generating capacity (excluding combined heat and power plants) is projected to decline from 69 percent in 2001 to 43 percent by 2025. Because the new integrated gasification combined cycle coal plants with carbon sequestration equipment are projected to be highly utilized in the S.139 case, the average capacity utilization factor for the remaining capacity not equipped with carbon sequestration technologies is projected to be considerably less than the average for all plants, declining to a low of 27 percent by 2025.

Coal-fired generating capacity is projected to decline from 315 gigawatts in 2001 to 147 gigawatts in 2025, the net result of 38 gigawatts of projected new integrated gasification combined cycle coal plants (with carbon capture and sequestration equipment) less 206 gigawatts of retirements. Coal’s share of total electricity generation is projected to decline from 51 percent in 2001 to 44 percent by 2010 and to 11 percent by 2025.

Due to gradually increasing greenhouse gas emission allowance costs over the forecast period, coal use in the industrial steam and coking sectors, taken together, is also projected to fall over the forecast period, from 89 million tons in 2001 to 73 million tons by 2025. Relative to the reference case, coal consumption in the industrial steam coal sector is 18 percent less in the S.139 case by 2025, and consumption in the coking coal sector is 21 percent lower.

Coal Production

In the reference case, U.S. coal production rises from 1,138 million tons in 2001 to 1,456 million tons in 2025 (Figure 6.17), an increase of 318 million tons. In the S.139 case, U.S. coal production is projected to remain fairly constant through 2010, but then declines precipitously to 315 million tons by 2025. The last time that the U.S. coal industry recorded a smaller amount of annual production was in 1902 when production was 302 million tons.¹⁸¹ Relative to the reference case, coal production in the S.139 case is 13 percent lower by 2010 and 78 percent lower by 2025.

Reductions in coal consumption are expected to occur in all regions and consuming sectors, but they will be of different magnitudes and affect different coal types. As a result, regional production patterns in the carbon reduction cases will shift differentially across regions relative to the reference case, rather than on a basis that is strictly proportional to national levels of coal consumption.

In the electricity sector, the sharp reductions in overall coal consumption after 2010 in the S.139 case will make it easier to achieve the sulfur dioxide (SO2) emissions target of 9 million tons as specified in the Clean Air Act Amendments of 1990, with the result that prices for the SO2 allowances will be driven to zero by approximately 2015. This eliminates the added benefit of using low-sulfur coals from the Central Appalachian and Western regions that exists throughout the entire reference case.

Coal of bituminous rank, however, will gain a slight price advantage over lower-ranked subbituminous and lignite coals in the S.139 case, because of its lower carbon dioxide emissions factor. This advantage becomes more pronounced after 2015, as the additional reduction in greenhouse gas emissions targets from 2000 levels to 1990 levels in 2016 leads to substantially higher prices for greenhouse gas emissions. Projected additions of new integrated gasification combined cycle plants with carbon sequestration technologies, particularly after 2020, effectively negate the carbon disadvantage of lower ranked coals at these facilities. In the S.139 case, the new integrated gasification combined cycle plants are projected to produce 10 percent of total coal-fired generation by 2020 and 50 percent by 2025.

Relative to the electricity sector, the slower decline in coal consumption in the industrial and coking coal sectors in the S.139 case will translate into relatively less severe production cuts in regions that currently supply these markets than the reductions in those regions that depend more heavily on electricity generators. The potential for western subbituminous coal to expand into most industrial applications is limited by its lower heat content and other physical characteristics, such as moisture content and handling problems.

There will be some upward pressure on coal transportation rates, as a result of the higher effective prices for diesel fuel (fuel cost plus greenhouse gas allowance costs) used for rail, barge, and truck transportation. Conversely, lower quantities of coal shipments could place downward pressure on transportation rates.

In the reference case, the share of total U.S. coal production originating from mines west of the Mississippi River increases from 53 percent in 2001 to 62 percent in 2025, primarily as a result of its lower cost and the growing requirements for low-sulfur coal under the Clean Air Act Amendments of 1990. In contrast, the western share decreases to 42 percent by 2025 in the S.139 case. Of the 467million-ton reduction in western coal production projected to occur over the forecast period in the S.139 case, 71 percent is borne by subbituminous surface mines in the Powder River Basin. The low-sulfur coal from these mines is used almost exclusively for electricity generation and must be transported over relatively long distances to reach many of the markets that are projected to expand in the reference case.

Coal Prices

Because coal is heterogeneous in terms of heat content, sulfur level, and other physical properties, trends in national average prices are affected substantially by the relative shares of the various coal types produced and sold and by the units in which prices are reported. For example, coal from the Powder River Basin is generally the lowest-priced coal per ton on a minemouth basis; however, because Powder River Basin coal has roughly two-thirds the heat content of bituminous coal, its cost advantage is somewhat less on a Btu basis and may be nonexistent when delivered to distant markets.

In general, to the extent that market share shifts away from Powder River Basin coal, which has a low minemouth price, to higher-priced bituminous coal, the national average minemouth price will increase. This compositional effect offsets the reduction in minemouth prices at the regional level that is likely to occur because of intraregional competition and the lower production quantities that occur when carbon restrictions take effect. The regional productivity improvements projected in the reference case are assumed to occur at the same rates in all the carbon reduction cases given the same rate of technological progress. However, if the level of investment in new capital equipment is severely constrained, there could be adverse impacts on productivity.

Similar to coal transportation, higher fuel prices in the greenhouse gas reduction cases also will act to increase coal mining costs, which, in turn, will affect minemouth coal prices. U.S. coal producers consume considerable amounts of diesel fuel and electricity, with underground mines relying heavily on electricity and surface mines consuming substantial quantities of both diesel fuel and electricity. In the S.139 case, diesel fuel prices (inclusive of the greenhouse gas allowance cost) are projected to rise to $10.89 per million Btu by 2025, and the price of electricity in the industrial sector is projected to rise to $20.86 per million Btu. These price projections for diesel fuel and electricity in 2025 are 51 percent and 55 percent higher than in the reference case, respectively.

In the reference case, the average minemouth price of coal (in constant 2001 dollars) is projected to decline from $17.59 per short ton in 2001 to $14.39 per short ton in 2025 (Figure 6.18). In the S.139 case, the minemouth price of coal is projected to decline to $13.67 per ton, 5 percent less than in the reference case. On a supply region basis, projected declines in minemouth coal prices in the S.139 case typically exceed the decline in the national level price. For example, under the carbon restrictions specified in the S.139 case, the average minemouth price of coal projected for Central Appalachia (southern West Virginia, eastern Kentucky, and Virginia) in 2025 is 22 percent lower than in the reference case, and the average price of coal produced at mines in the Powder River Basin (Wyoming and Montana) in 2025 is 53 percent lower than in the reference case.

Delivered prices for coal reflect the sum of the minemouth price and transportation cost. The effective delivered price of coal also includes the greenhouse gas allowance cost associated with meeting a greenhouse gas reduction target, because the consumer of the coal must hold sufficient allowances to cover the carbon emissions that result from its combustion. In the S.139 case, the allowance cost exceeds the delivered price, adding $2.02 per million Btu to the effective delivered price of coal to electricity generators in 2010 and $5.62 per million Btu in 2025.

In the reference case, the national average delivered price of coal to electricity generators declines from $25.04 per short ton in 2001 to $22.27 per short ton in 2025. In the S.139 case, the effective delivered price of coal, including the greenhouse gas allowance cost, rises to $65.08 per short ton in 2010 and to $136.11 per short ton in 2025 (Figure 6.19). Excluding the greenhouse gas allowance cost, the delivered price of coal to the electricity sector in the S.139 case is projected to decline to $18.81 per short ton by 2025, 16 percent less than in the reference case.

Coal Industry Employment and Productivity

Between 1978 and 2001, the number of miners employed in the U.S. coal industry fell by 4.9 percent per year, declining from 246,000 to 77,000. The decrease primarily reflected strong growth in labor productivity, which increased at an annual rate of 6.0 percent over the same period. An additional factor contributing to the employment decline was the increased output from large surface mines in the Powder River Basin, which require much less labor per ton of output than mines located in the Interior and Appalachian regions.

In the reference case, productivity improvements are assumed to continue but to decline in magnitude over the forecast period. Different rates of improvement are assumed by region and by mine type, surface and underground. On a national basis, labor productivity in the reference case increases on average at a rate of 1.6 percent a year over the entire forecast, declining from an estimated annual rate of 2.5 percent between 2001 and 2010 to 1.1 percent between 2010 and 2025.

The expectation that the rate of productivity improvements will slow over the forecast horizon, combined with projections of continuing increases in coal production, leads to a relatively stable outlook for U.S. coal mine employment. In the reference case, employment is projected to decline by 1.3 per year between 2001 and 2010 but is expected to stabilize during the later years of the forecast as increases in production outpace expected improvements in productivity. In absolute terms, coal mine employment is projected to decline from 77,000 in 2001 to 68,000 in 2010. After 2010, coal-mining employment declines slightly for several years thereafter but rebounds to 68,000 by 2025 (Figure 6.20).

In the S.139 case, lower levels of coal production in all supply regions relative to the reference case result in lower coal industry employment in all regions. In this carbon reduction scenario, coal mine employment is projected to decline by 5.3 percent a year, from 77,000 in 2001 to 21,000 by 2025.

Alternative Scenarios

Alternative scenarios to the S.139 case were run to assess what impacts on U.S. energy markets would result from using assumptions that differ from those in the S.139 case. Some of the other assumptions that were explored in these alternative cases, and whose impacts on U.S. coal markets are discussed below, include: (1) a case where it is assumed that no advanced fossil-fired generating capacity with sequestration technologies or advanced nuclear will be built; (2) a case that allows up to 50 percent of the greenhouse gas targets to be met by using international offsets, which is more than the S.139 limit of 15 percent in the 2010-2015 period and 10 percent for 2016 and beyond; (3) two cases that include optimistic technology assumptions for the residential, commercial, industrial, and transportation sectors combined with optimistic technology assumptions for new fossil, nuclear, and renewable generating capacity (one with and without the provisions of S.139); and (4) two cases that include less optimistic assumptions about natural gas supply and infrastructure, resulting in projections of higher natural gas prices.

In the alternative scenario assuming no new advanced nuclear and no new advanced fossil-fired generating capacity with carbon sequestration technologies, the outlook for U.S. coal production and consumption is considerably lower than in the S.139 case. In the no new nuclear, no sequestration case, U.S. coal consumption is projected to decline to 352 million tons by 2020 and to 160 million tons by 2025, 25 percent and 48 percent less for those years, respectively, than in the S.139 case. The no new nuclear, no sequestration case leads to the construction of both additional advanced gas-fired generating capacity without sequestration technologies and renewable energy facilities (primarily dedicated biomass plants).

In the alternative scenario that allows covered entities to meet up to 50 percent of their targets with international offsets, U.S. coal production and consumption are projected to be considerably higher than the levels projected in the S.139 case. In the offset 50 case, U.S. coal consumption is projected to decline to 667 million tons by 2020 and to 519 million tons by 2025, 42 percent and 70 percent higher for those years, respectively, than in the S.139 case. Lower greenhouse gas emission allowance prices are the key factor underlying the improved outlook for coal. In 2020, the greenhouse gas allowance price is projected to be $144 per metric ton carbon equivalent, 19 percent less than in the S.139 case; and by 2025 the price is projected to rise to $174 per metric ton carbon equivalent, or 21 percent less than in the S.139 case. Coal-fired generating capacity is projected to decline to 206 gigawatts by 2025, the net result of 5 gigawatts of projected new coal builds less 114 gigawatts of retirements. Because of thermal fatigue and the inefficiencies of starting and stopping units that were designed for baseload operation, an additional improvement in the offset 50 case is the higher average capacity utilization factors projected for coal-fired plants not equipped with carbon sequestration technologies. In the offset 50 case, the capacity factor for this group of coal-fired power plants is projected to decline from 69 percent in 2001 to 52 percent by 2025. In the S.139 case, the average capacity factor for this group of coal plants is projected to decline to 27 percent by 2025.

With the exception of the S.139 high gas price case, the projected decline in coal consumption in the S.139 high technology case is less than in any of the other greenhouse gas reduction scenarios whose assumptions reflect the provisions set forth in S.139. The higher levels of coal consumption in the S.139 high technology case are primarily due to projections of lower greenhouse gas allowance costs than in the other greenhouse gas cases, reducing the effective delivered price of coal inclusive of greenhouse gas costs to end-use consumers in the industrial sector and to electric power producers. The lower greenhouse gas allowance costs in the S.139 high technology case result mostly because of reduced consumption of energy in the end-use sectors. Coal consumption in the S.139 high technology case is projected to decline to 595 million tons in 2020 and to 375 million tons by 2025, 54 percent and 72 percent less, respectively, than projected for those years in the high technology reference case.

Among the greenhouse gas reduction cases whose basic assumptions reflect the provisions set forth in S.139, the S.139 high gas price case results in the lowest overall reduction in coal consumption. The smaller projected decline in coal use in this case is primarily due to improved competitiveness of new coal-fired generating capacity relative to new gas-fired capacity that results because of higher natural gas prices. In the S.139 high gas price case, coal-fired generating capacity is projected to decline from 315 gigawatts in 2001 to 231 gigawatts by 2025, the net result of 81 gigawatts of projected new coal builds (advanced coal-fired capacity equipped with carbon sequestration technologies) less 165 gigawatts of retirements. The projected greenhouse gas allowance prices are similar to other carbon reduction scenarios, rising to $188 per metric ton carbon equivalent by 2020 and to $214 per metric ton carbon equivalent by 2020. Coal consumption in the S.139 high gas price case is projected to decline to 639 million tons in 2025 and to 547 million tons by 2025, 57 percent and 66 percent less, respectively, than projected for those years in the high gas price reference case. In the high gas price reference case, 145 gigawatts of new coal-fired generating capacity is projected to be built. This compares with 81 gigawatts of new coal builds projected in both the reference and S.139 high gas price cases. (For a discussion of the estimated cost and performance characteristics of new generating technologies used by EIA for this study and their relative competitiveness based on projected levels of both fuel and greenhouse gas allowance costs, see the discussion on Electricity Supply in Chapter 5.)

Coal Forecast Comparisons

As indicated by the various greenhouse gas reduction scenarios discussed in this report, there is considerable uncertainty regarding the projected levels of coal consumption. This uncertainty relates to factors such as assumptions about the ways in which greenhouse gas emission allowances are distributed to covered entities, the extent to which covered entities will be allowed to rely on emission allowance offset credits, expectations about technological improvements in the U.S. energy industry, and, perhaps most importantly, the environmental hurdles and the estimated costs associated with the development of fossil-fired generating capacity equipped with carbon capture and sequestration technologies.

By 2020, coal use in the various reduction scenarios evaluated in EIA’s analyses is projected to range from a low of 7.7 quadrillion Btu in the no new nuclear, no sequestration case to a high of 14.4 quadrillion Btu in the offset 50 case, reflecting declines of 65 percent and 35 percent, respectively, from 2001. By 2025, the projected levels of coal consumption are projected to range from a low of 3.7 quadrillion Btu in the no new nuclear, no sequestration case to a high of 11.9 quadrillion Btu in the S.139 high gas price case, reflecting declines of 83 percent and 46 percent, respectively, from 2001.

As an additional point of reference, the Massachusetts Institute of Technology (MIT) Joint Program on the Science and Policy of Global Change recently completed an analysis of S.139 that indicates that the impact on U.S. coal markets will be considerably less severe than projected by EIA. In the MIT analysis, featuring caps on greenhouse gas emissions, banking of emission allowances, but no emission allowance offset credits, U.S. coal consumption is projected to decline to only 19.9 quadrillion Btu by 2020, or 10 percent less than in 2001.¹⁸² In an alternative scenario featuring caps on carbon dioxide emissions alone, banking of emission allowances and access to offset credits (up to 15 percent of covered emissions through 2015 and 10 percent thereafter), MIT projects that U.S. coal consumption will decline to only 20.9 quadrillion Btu by 2020, or 5 percent less than in 2001.¹⁸³

As an added perspective, it is useful to compare the differences in 2020 between the EIA and MIT reference case coal forecasts and their respective greenhouse gas and carbon dioxide reduction scenarios. In EIA’s S.139 case, U.S. coal consumption is projected to decline to 10.2 quadrillion Btu by 2020, 63 percent less than the EIA reference case forecast of 27.9 quadrillion Btu, by 2020. In MIT’s carbon dioxide emissions reduction case featuring access to offset credits, coal consumption is projected to decline to 20.9 quadrillion Btu by 2020, or 35 percent less than their reference case forecast of 32.2 quadrillion Btu.

Unlike the scenarios featured in EIA’s analyses that use a set of marginal abatement cost curves to assign prices to offset credits, the MIT analysis assumes that offset credits will be available at zero cost. The greenhouse gas allowance prices projected in the MIT analyses are comparable to those projected by EIA, but slightly lower. In the MIT scenarios discussed above, allowance price is projected to rise to $158 per metric ton carbon equivalent (2001 dollars) by 2020 in the greenhouse gas cap case with zero offsets, and to $134 per metric ton carbon equivalent by 2020 in the carbon dioxide cap case with access to offsets. This compares with a projected greenhouse gas allowance price of $178 per metric ton carbon equivalent by 2020 in EIA’s S.139 case.

Because the EIA analyses of S.139 show much larger increases in natural gas consumption than do the MIT analyses, one possible explanation for the large variation between the EIA and MIT coal forecasts is differences in cost assumptions for new fossil-fuel-fired generating capacity with carbon sequestration technologies (for a discussion of EIA’s cost assumptions, see the Chapter 5 discussion of Electricity Supply). EIA’s analyses indicate that new natural-gas-fired generating capacity with carbon capture and sequestration technologies will typically be a more economical choice than coal-fired capacity equipped with similar technologies, while MIT’s analyses appear to indicate the opposite. In the MIT study, natural gas use is projected to increase by 9 percent between 2000 and 2020 in a greenhouse gas cap case that assumes no offset credits, and to increase by 14 percent over the same period in the carbon dioxide cap case that allows for the percentage of offsets as specified in S.139. In EIA’s S.139 case, natural gas consumption is projected to increase by a much more substantial amount, 52 percent, between 2000 and 2020.

Another potential reason for MIT’s more robust outlook for U.S. coal consumption is their much smaller projected increase in consumption of petroleum products than is projected in EIA’s greenhouse gas reduction scenarios. In MIT’s analyses, the relatively small projected increases in petroleum consumption over the forecast horizon would effectively free up greenhouse gas allowances for the electricity sector, making it less difficult for this sector to comply with the caps specified in S.139. In the MIT greenhouse gas cap case with no offsets, petroleum consumption is projected to increase by 5 percent between 2000 and 2020, and in their carbon dioxide cap case with access to offset credits petroleum consumption increases by 8 percent over the same time period. In EIA’s S.139 case, consumption of petroleum products is projected to increase by 26 percent between 2000 and 2020.

6. Fossil Fuel Supply - Tables

Notes