Combined Case and AEO2004 Reference Case

Because the combined case integrates the gas supply restrictions imposed in the other three cases, it is by far the most restrictive of the four examined. This is best illustrated by the reduction in projected natural gas consumption. In 2025, the combined case projects total gas consumption to be 26.9 tcf, compared to 31.4 tcf in the reference case, which is a 14-percent reduction (4.5 tcf). In 2025, domestic gas production is projected to be 3.8 tcf lower in the combined case than in the reference case, while net gas imports are 0.7 tcf lower in the combined case (Figure 16).

The largest reductions in end-use consumption occur in the electric generation and industrial sectors, with gas consumption reductions in 2025 of 36 percent (3.0 tcf) and 7 percent (0.7 tcf), respectively. Because this case restricts natural gas supply well beyond historical experience, it may not fully represent market conditions. So, the high sustained gas prices in this case might lead to more energy conservation and even the departure of gas-reliant manufacturing from the United States.

Although net LNG imports are constrained in the combined case, gas imports from Mexico and Canada are not constrained. Consequently, these pipeline imports are much higher in the combined case than the reference case projection. In 2025, gas exports from Canada are projected to be 3.5 tcf in the combined case, compared to the 2.6 tcf in the reference case (Figure 17). Mexico exports 0.9 tcf to the United States in 2025 in the combined case, compared to the 120 bcf of gas it imports from the United States in the reference case. In the combined case, Baja California, Mexico, supplies the western United States with 730 bcf of LNG via a pipeline in 2025, 360 bcf more than in the reference case. It is also possible that even more gas could be imported from LNG facilities in Canada and Mexico.

In considering the combined case, it should be noted that unconventional gas supplies are not restricted to a specific and constant level. The assumed changes to unconventional gas supply make these sources of gas more expensive to produce. In the combined case, unconventional gas production is above the 2002 level, because wellhead gas prices are projected to exceed the higher cost of developing unconventional supplies, sufficient to induce an incremental supply response. Incremental unconventional gas production peaks in 2019, when it is 0.7 tcf above the 2002 level, and then subsides through 2025, when it is 0.4 tcf above the 2002 level (Figure 18). Relative to the reference case, unconventional gas production in 2025 is 2.9 tcf lower in the combined case (9.2 tcf in the reference case and 6.3 tcf in the combined case).

Because Alaska gas and unconventional gas supplies are severely constrained in the combined case, only lower 48 conventional gas can be a large incremental source of domestic gas production. In 2025, lower 48 conventional gas production is projected to be 13.2 tcf in the combined case, compared to 12.1 tcf in the reference case. Production is only 1.1 tcf greater in 2025 because conventional resources have been significantly depleted by the end of the forecast, making incremental conventional gas supplies more expensive to develop and produce.

The severe supply constraints placed on the combined case result in projected prices being considerably higher than in the reference case. Figure 19 compares the wellhead gas prices for the combined and reference cases in 2002 dollars per mcf. In 2025, the wellhead prices in the combined case are 27 percent higher than in the reference case.

These gas prices are average annual prices, which masks both the winter/summer seasonal price variation and the gas price volatility caused by other short-term factors, such as weather severity. Because the combined case represents a significantly more constrained gas supply environment, the difference in winter peaking prices could be considerably greater than that implied by the difference between the average annual prices in the combined and reference cases.

The high wellhead gas prices projected for the combined case significantly reduce the construction and use of gas-fired electricity generation capacity. Projected gas-fired generation in 2025 is marginally greater than the 2002 gas-fired generation levels. In the combined case, gas is projected to generate 848 billion kilowatthours, which is only 162 billion kilowatthours higher than the 686 billion kilowatthours generated in 2002. In 2025, the gas share of the generation market is 15 percent, which is less than the 18 percent experienced in 2002 and the 23 percent projected in the reference case (Figure 20).

As in the other cases, when gas is used less in the electric generation sector, the difference is made up primarily through greater use of coal, renewable energy, and in this case oil. In 2025, coal-fired generation is 3,253 billion kilowatthours in the combined case, which is 224 billion kilowatthours more than that projected in the reference case, raising the coal share of the generation market to 57 percent. Similarly, renewable electricity generation is projected to be 68 billion kilowatthours higher in 2025 in the combined case and oil-fired generation is 121 billion kilowatthours greater. Oil generation increases more than renewable energy generation because dual-fired units that can burn both oil and natural gas switch to oil when gas prices get sufficiently high. Cumulatively from 2002 through 2025, wind generation accounts for 90 percent of the increase in total renewable generation. Biomass generation comprises most of the remainder.

The combined case exhibits a significant change in electricity prices, unlike the other three cases. In 2025, the combined case projects a busbar electricity price of 7.13 cents per kilowatthour, compared to the reference case price of 6.91 cents per kilowatthour, a 3-percent increase.