Coal Production
Total Coal Production Increases at a Slower Rate Than in the Past
In the AEO2009 reference case, increasing coal use for electricity generation
at both new and existing plants and the startup of several CTL plants lead
to modest growth in coal production, averaging 0.6 percent per year from
2007 to 2030—slightly less than the 0.9-percent average growth rate for
U.S. coal production from 1980 to 2007.
Western coal production, which has grown steadily since 1970, continues
to increase through 2030 (Figure 78), but at a much slower rate than in
the past. Most of the additional output originates from mines located in
Wyoming, Montana, and North Dakota. Roughly one-half of the West’s additional
coal production is used for fuel and feedstock at new CTL plants, and the
remainder is used for electricity generation at existing and new coal-fired
power plants.
Production of higher sulfur coal in the Interior region, which has trended
downward since the early 1990s, rebounds as existing coal-fired power plants
are retrofitted with flue gas desulfurization (FGD) equipment and new coal-fired
capacity is added in the Southeast. Much of the additional output from
the Interior region originates from mines tapping into the extensive reserves
of mid- and high-sulfur bituminous coal in Illinois, Indiana, and western
Kentucky. In Appalachia, total production declines slightly from current
levels as output shifts from the extensively mined, higher cost reserves
of Central Appalachia to lower cost supplies from the Interior region,
South America, and the northern part of the Appalachian basin.
Long-Term Production Outlook Varies Considerably Across Cases
U.S. coal production varies across the AEO2009 cases, in particular when
different policies are assumed with regard to GHG emissions. Different
assumptions about the costs of producing and transporting coal also lead
to substantial variations in the outlook for coal production.
The no GHG concern case illustrates the potential for a sizable increase
in coal production. In the absence of a risk premium for carbon-intensive
technologies, more new coal-fired power plants and CTL plants are built
than in the reference case. In 2030, coal production in the no GHG concern
case is 20 percent above the reference case projection (Figure 79). In
contrast, if policies to reduce or limit GHG emissions were enacted in
the future, they could result in significant reductions in coal use at
existing power plants and limit the amount of new coal-fired capacity built
in the future. The impact on coal use would depend on details of the policies,
such as the allocation of emissions allowances, the inclusion of a “safety
valve” or other mechanism to limit the price of allowances (and its level),
and the inclusion of provisions to encourage the use of particular fuels
or technologies.
In the high coal cost case, higher costs for coal mining and transportation
lead to some switching from coal to natural gas and nuclear in the electric
power sector, along with slightly slower growth in electricity demand.
In the low coal cost case, the trends are in the opposite direction. As
a result, coal production in 2030 is 17 percent lower in the high coal
cost case, and 11 percent higher in the low coal cost case, than in the
reference case.
Minemouth Coal Prices in the Western and Interior Regions Continue Rising
In the near term, rising prices for the mining equipment, parts and supplies,
and fuel used at coal mines lead to higher minemouth prices for coal in
all regions (Figure 80). In the Appalachian region, a resurgence in production
of high-value coal for export adds to the early price surge. In the longer
term, limited improvement in coal mining productivity and increased production
from the Interior and Western supply regions result in higher minemouth
prices in both regions, increasing on average by 1.2 percent per year from
2007 to 2030. After peaking in 2009, the average minemouth price for Appalachian
coal declines by 0.5 percent per year through 2030, as a result of falling
demand and a shift to lower cost production in the northern part of the
basin.
Reflecting regional trends, the U.S. average minemouth price of coal rises
significantly between 2007 and 2009, from $1.27 to $1.47 per million Btu.
After the initial run-up, however, prices level off and then fall slightly
through 2020, as mine capacity utilization declines and production shifts
away from the higher cost mines of Central Appalachia.
In the reference case, the assumed risk premium for carbon-intensive technologies
dampens investment in new coal-fired power plants; however, a growing need
for additional generating capacity of all types results in the construction
of 28 gigawatts of new coal-fired capacity after 2020. The combination
of new investment in mining capacity to meet demand growth and a continued
low rate of productivity improvement leads to an increase in the average
minemouth price of coal, from $1.39 per million Btu in 2020 to $1.46 in
2030.
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