More than half of the electricity in

the United States is generated by coalfired powerplants. U.S. coal producers

sell almost 90 percent of their product

for electricity generation, and so, the

future of the U.S. coal industry will be

determined by the future of coal-fired

electricity-generation plants.

The U.S. Geological Survey

(USGS) is completing a National Coal

Resource Assessment (NCRA) of five

major coal-producing regions of the

United States (fig. 1): (1) the Appalachian Basin, (2) the Illinois Basin, (3) the

Gulf Coast, (4) the Colorado Plateau,

and (5) the Northern Rocky Mountains

and Great Plains. The Powder River and

Williston Basins are the principal producing areas of the Northern Rocky

Mountains and Great Plains region.

Two principal forces that will control

the size of the coal market for electric power

generation are electricity-market deregulation and airborne emissions regulation.

Forces Shaping Future U.S. Coal Production and Use

U.S. Department of the Interior

U.S. Geological Survey

USGS Fact Sheet FS–158–00

Revised March 2001

EXPLANATION

0 

25 

50 

75 

100 

% PRODUCED COAL

0 0.6 1.2 1.8 2.4 3.0 3.6 4.2 4.8 

SULFUR, lbs/MMBtu

CENTRAL APPALACHIAN BASIN

0 

25 

50 

75 

100 

% PRODUCED COAL

0 0.6 1.2 1.8 2.4 3.0 3.6 4.2 4.8 

SULFUR, lbs/MMBtu

ILLINOIS BASIN

0 

25 

50 

75 

100 

% PRODUCED COAL

0 0.6 1.2 1.8 2.4 3.0 3.6 4.2 4.8 SULFUR, lbs/MMBtu

NORTHERN APPALACHIAN BASIN

0 

25 

50 

75 

100 

% PRODUCED COAL

0 0.6 1.2 1.8 2.4 3.0 3.6 4.2 4.8 

SULFUR, lbs/MMBtu

POWDER RIVER BASIN

0 

25 

50 

75 

100 

% PRODUCED COAL

0 0.6 1.2 1.8 2.4 3.0 3.6 4.2 4.8 

SULFUR, lbs/MMBtu

COLORADO PLATEAU

0 

25 

50 

75 

100 

% PRODUCED COAL

0 0.6 1.2 1.8 2.4 3.0 3.6 4.2 4.8 

SULFUR, lbs/MMBtu

GULF COAST 

Assessed areas

Unassessed areas

Williston 

Basin

Powder River

Basin

1

5

4

3

2

Major region

(see caption)

1

Figure 1. Coal fields of the conterminous United States. The U.S.

Geological Survey is completing a National Coal Resource Assessment; colors on the map show assessed areas within five major

coal-producing regions: (1) the Appalachian Basin, (2) the Illinois

Basin, (3) the Gulf Coast, (4) the Colorado Plateau, and (5) the

Northern Rocky Mountains and Great Plains (includes the Powder

River and Williston Basins). Graphs show sulfur contents of coal

delivered to powerplants in 1998 from mines in a specific area.

Vertical line in each graph is the 2000 Phase II SO2 compliance

standard of the 1990 Clean Air Act Amendments. Data on sulfur

contents are from the Federal Energy Regulatory Commission

(available at http://www.ferc.fed.us/electric/f423/F423annual.htm).

lbs/MMBtu = pounds per million British thermal units of calorific

value. 
Under market deregulation, electric

powerplants will no longer have captive

markets but will have to compete to sell

their electricity. They will have to

search for the lowest cost fuel supplies.

The quest to reduce fuel costs has

reduced the number of operating coal

mines by half since 1990, as smaller,

inefficient mines have closed and larger

mines have adopted new technologies to

increase productivity. At the coal

industry level, much of the productive

capacity is now concentrated in a handful of major producers. Coal-fired

plants also will compete with new, highly efficient, central gas-fired powerplants and “distributed or localized”

generation systems including micro-gasturbines and photovoltaic systems that

generate electricity.

The other principal force that will

shape the coal market is the need to

comply with the 1990 Clean Air Act

Amendments (CAAA90). The amendments set new Federal regulations on

sulfur dioxide (SO2) emissions from

powerplants. Figure 2 shows declining

sulfur contents of coals used by U.S.

powerplants from 1973 to 1999.

Phase II of the CAAA90, implemented in January 2000, capped powerplant SO2 emissions nationally at 8.95

million short tons per year. This cap

would currently limit a plant’s emissions

to 1.2 pounds of SO2 per million British

thermal units (lbs SO2/MMBtu) (or 0.6

lb sulfur/MMBtu in the coal). Each

powerplant is initially allotted SO2

emissions allowances at a rate of 1.2 lbs

SO2/MMBtu based on its fuel use during the 1985 through 1987 base period.

Plants constructed after 1996 are not

allotted emissions allowances. To keep

emissions within the Phase II allotments, an operating coal-fired powerplant that does not currently meet the

standard could retrofit with a flue-gasdesulfurization (FGD) system, switch to

low-sulfur coal or another fuel, purchase

additional emissions allowances, or

close down. If a powerplant’s emissions

are below its initial allotment, it may

sell or trade excess allowances. As of

January 2000, there were 11.8 million

short tons of SO2 allowances available

for sale to noncompliant plants; the

allowances were accrued during Phase I

of the CAAA90.

As of late 1999, responses to industry surveys showed that noncompliant

plants anticipated the following changes

to achieve compliance:

• plants representing 55 percent of

productive capacity would switch to

low-sulfur coal

• plants representing 35 percent

would purchase SO2 allowances

and continue to use higher sulfur

coal

• plants representing 10 percent (listed as undecided) would switch to

another fuel, shut down boilers, or

install FGD systems

The announced intentions to switch

to low-sulfur coal could translate into an

additional demand for 190 million short

tons per year of low-sulfur subbituminous coal or 135 million short tons per

year of low-sulfur bituminous coal production. Additional low-sulfur coal

demand will increase as the number of

stockpiled allowances available for sale

to noncompliant plants shrinks.

The graphs in figure 1 show sulfur

contents of produced coal transported

from mines in a specific area to powerplants in 1998. The vertical line in each

graph is the 2000 Phase II SO2 emissions compliance standard. Only small

amounts of the coal shipped to powerplants from the northern Appalachian

Basin and the Illinois Basin met those

emission limits. About 35 percent of the

coal shipped from the central Appalachian Basin coal region, 75 percent of the

coal shipped from the Colorado Plateau

region, and 90 percent of the coal

shipped from the Powder River Basin

complied with the emissions standard.

With coal blending, all of the coal in the

Powder River Basin and the Colorado

Plateau and 60 percent of the coal

shipped from the central Appalachian

Basin met compliance limits. Gulf Coast

and Williston Basin lignite coals are

used at local plants that already have

FGD systems. The USGS NCRA estimates that large volumes of low-sulfur

coal are in the Powder River Basin and

emerging producing regions of the Colorado Plateau.

Provisions of the CAAA90 relating

to fine particulates and hazardous airborne pollutants (HAP’s) are still

planned, and so the full effect of that act

has yet to be felt. So far, the forces of

deregulation and uncertainty in future

emissions rules have shaped power

industry responses to the CAAA90 regulations. Projections for the long-term role

of coal may be uncertain, but for at least

the next decade, it will continue to be the

primary indigenous energy source used

by the U.S. economy. Knowledge of the

quantity and location of potential coal

supplies is needed, and a detailed understanding of the quality of the coal will be

necessary to meet future energy needs.

0.6 

0.9 

1.2 

1.5 

1.8 

2.1 

2.4 

SULFUR (WEIGHT%)

1973 1978 1983 1988 1993 1998 

YEAR

Figure 2. Sulfur content of coals used at

U.S. powerplants, 1973 to 1999. Data from

the Federal Energy Regulatory Commission

(available at http://www.ferc.fed.us/electric/

f423/F423annual.htm).

Emil Attanasi

U.S. Geological Survey

956 National Center

Reston, VA 20192

Telephone: (703) 648–6129

E-mail: attanasi@usgs.gov

Brenda Pierce

U.S. Geological Survey

956 National Center

Reston, VA 20192

Telephone: (703) 648–6421

E-mail: bpierce@usgs.gov

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