Order Code RL31819
Report for Congress
Received through the CRS Web
U.S. Coal:
A Primer on the Major Issues
March 25, 2003
Marc Humphries, Coordinator
Analyst in Energy Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress

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U.S. Coal: A Primer on the Major Issues
Summary
The U.S. coal industry has gone through a number of gradual shifts in recent
decades. The industry has become more concentrated, and mine productivity has
improved. More low-sulfur coal and less high sulfur coal is today being produced.
Less coal is exported, in part because of a strong U.S. dollar. Improved production
methods, such as greater utilization of and improvements in longwall mining
technology, have lowered the cost of underground mining, although surface mining
continues to hold a substantial cost advantage.
The United States is well endowed with coal. The total demonstrated resource
base is estimated by the Energy Information Administration (EIA) at 508 billion short
tons, of which about 274 billion short tons are classified as recoverable reserves. U.S.
recoverable reserves are estimated at 25% of total world reserves. Production of U.S.
coal reached an all-time high in 2001 at 1,121 million short tons.
Coal supplies 22% of the nation’s energy demand but 52% of its electricity
needs. EIA forecasts coal to fall to 47% of the U.S. electricity market by 2025
because of increased competition from natural gas. About 1,063 million short tons
of coal were consumed in the United States in 2001, 90% of which was used in the
electric power sector. Currently, railroads move about 65% of all coal, barges
transport about 15%, and trucks about 11%.
State agencies play a large role in regulating the coal industry, often exercising
authority delegated by federal agencies pursuant to federal environmental and safety
laws. The Surface Mining Control and Reclamation Act (SMCRA) established the
bulk of the guidelines for coal mining and created the Office of Surface Mining in the
Department of the Interior. Other federal agencies regulate mining safety, air and
water emissions, and other aspects of coal production and use.
Air emissions and mountaintop mining are the most important environmental
issues currently affecting the coal industry. Coal-fired electric generating facilities
are a major source of air emissions, including sulfur dioxide (SO 2), nitrogen oxides
(NOX), particulate matter (PM), mercury, and carbon dioxide (CO2). Regulations
under the Clean Air Act (CAA) limit SO2, NOX, and PM emissions, with further
requirements on the horizon. CO2, a greenhouse gas associated with potential climate
change, however, is not controlled under the CAA. The practice of mountaintop
mining – removing the top of a mountain to reveal underlying coal seams – has
received considerable attention recently. When mountaintop material is deposited in
adjacent valleys, streams flowing through the valleys are buried.
The outlook for U.S. coal is mixed. While forecasts predict steady growth in
coal supply and demand, the increased production is expected to come from fewer,
larger mines and fewer producers. Continued competition from natural gas is likely
to put pressure on coal prices for the foreseeable future.
This report will not be updated.

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Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Energy Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Cycle of Coal Utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Coal Supply and Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Resources and Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
U.S. Coal Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Coal Production Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Coal Production on Federal Lands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Coal Consumption Patterns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Coal Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Coal Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Coal Trade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Tax Incentives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Structure of the Coal Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Financial Health of the Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Federal Agencies and Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Office of Surface Mining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Mine Safety and Health Administration . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Environmental Protection Agency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Other Federal Agencies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Environment, Health, and Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Regulation of Air Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
National Ambient Air Quality Standards – New Source Performance
Standards – Lowest Achievable Emissions Rate . . . . . . . . . . . . . 18
Multi-Pollutant Legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
New Source Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Global Climate Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Mountaintop Removal Mining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Regulatory Setting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Criticism and Legal Challenges to Mountaintop Mining . . . . . . . . . . . 27
Administrative Actions and Congressional Activity . . . . . . . . . . . . . . 28
Other Environmental Concerns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Subsidence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Acid Mine Drainage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
The Abandoned Mine Land (AML) Fund . . . . . . . . . . . . . . . . . . . . . . 29
Health and Safety Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Accident Prevention . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Health Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Black Lung Benefits Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Coal Research and Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Outlook and Recap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

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List of Figures
Figure 1. Turning Coal into Electricity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Figure 2. U.S. Coal Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Figure 3. U.S. Coal Production by Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Figure 4. U.S. Electric Power Sector Energy
Consumption, 2001 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
List of Tables
Table 1. U.S. Coal Reserves by Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Table 2. World Coal Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Table 3. U.S. Coal Demonstrated Resource Base, Top 5 States . . . . . . . . . . . . . . 7
Table 4. U.S. Coal Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Table 5. Major U.S. Coal Producers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Table 6. Mine Productivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Table 7. 1999 Emissions From U.S. Fossil-fuel-fired Electric Generating Plants
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Table 8. Recap of Major Coal-related Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

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U.S. Coal: A Primer on the Major Issues
Introduction
In recent decades, the U.S. coal industry has been changing significantly. Coal
production has shifted from high-sulfur to low-sulfur. The number of coal mining
firms has decreased, while the size of the average mine and labor productivity have
increased. Driven by strong demand from electric power plants – coal’s primary
customer – coal production has risen steadily. However, natural gas has been the
recent fuel of choice for new power plants, eroding coal’s market share.
The United States is well endowed with coal. The Energy Information
Administration (EIA) estimates there are about 274 billion tons of recoverable
domestic coal reserves. The total demonstrated resource base (DRB)1 is estimated at
508 billion tons.2
However, a number of constraints affecting the mining and use of coal –
including air and water pollution controls and health and safety requirements – may
limit just how much of this resource potential is ultimately realized.
Regulation of air emissions is one of the most controversial and longstanding
coal issues. Coal-fired plants emit a variety of pollutants, including sulfur dioxide,
nitrogen oxides, mercury, and particulate matter. Coal combustion is also a major
source of carbon dioxide, which may play a role in global climate change.
Water pollution issues are also a subject of debate, particularly the practice of
mountaintop mining – removing the top of a mountain to reveal underlying coal
seams. A federal district court in West Virginia ruled in May 2002 that depositing
mountaintop material in adjacent stream valleys violated the Clean Water Act.
However, in January 2003, the 4th Circuit Court of Appeals in Richmond, Virginia,
overturned district court decision.3 No appeal has been filed.
The amount of research and development (R&D) for new coal technology is
important to the industry, especially efforts to develop cleaner combustion systems
1 The demonstrated resource base is the sum of coal in both the measured (proven) and
indicated resource categories. The DRB represents that part of the identified coal resource
from which reserves are calculated.
2 U.S. Department of Energy (DOE), Energy Information Administration (EIA), Coal
Industry Annual, 2001
3 Kentuckians for the Commonwealth v. Corps of Engineers, S.D.W.Va., No. 2:01:0770,
5/08/02; Kentuckians for the Commonwealth v. Rivenburgh, No. 02-1736; and Pocahontas
Development Corp. et al v. Rivenburgh, No. 02-1737, CA4, 1/29/03.

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CRS-2
and other technologies for reducing coal’s environmental impact. Alongside federal
R&D programs are tax incentives contained in Title 29 of the Internal Revenue Code
to encourage synthetic fuel development and clean coal technology. Mine safety,
health, and environmental questions are being addressed through the Black Lung
Fund and the abandoned mine reclamation fund.
This report is intended to be a primer on the role of coal in the U.S. energy
picture and on the issues noted above, particularly mountaintop mining and clean air
compliance. Some of these issues are discussed in greater detail in separate CRS
reports.
Energy Trends
Out of the four major U.S. fuel sources – oil, natural gas, coal, and uranium –
coal has the largest domestic reserve base and the largest share of U.S. energy
production in Btus. A far smaller percentage of U.S. coal demand is met by imports
than for the other major fuels. EIA projects that coal imports will continue to be
negligible through 2025, while other major fuels will see a growing reliance on
foreign sources, and that coal will continue to be the largest source of domestic
energy production.4
Production of coal in the United States reached an all-time high of 1,128 million
short tons in 2001, although it dropped slightly in 2002. Coal production accounted
for 33% of total U.S. energy production in terms of Btu value in 2001. In EIA’s 2025
forecast, coal accounts for about the same share – 32.6%. Annual coal consumption
is forecast to gradually rise, increasing by 400 million short tons between 2001 and
2025. In 2025, over 90% of coal will likely be used in the electric power sector, as
it is today. Domestic mines will continue to meet the overwhelming majority of U.S.
coal demand, with imports remaining below 2%, according to the EIA projections.
U.S. coal exports are currently about twice the level of imports but are projected by
EIA to steadily lose world market share.
U.S. natural gas production is projected to increase by 1.3% annually through
2020 – from 19.5 trillion cubic feet (tcf) to 25.1 tcf, according to EIA. With annual
consumption estimated to reach 33 tcf, natural gas imports of about 8 tcf will be
needed to fill the gap – about 25% of consumption. The gap is expected to be met
primarily with imports from Canada. Net imports of natural gas currently are about
3.7 tcf, or 16%, of demand. EIA projects that natural gas will rise from 27% of U.S.
energy production in 2001 to 30% in 2025.
U.S. oil production is expected to increase slightly, from 8.9 million barrels per
day (mbd) to 9.4 mbd in 2025. Net oil imports are expected to grow from 55% of
demand in 2001 to 68% by 2025. Total U.S. petroleum demand is expected to grow
at 1.7% annually through 2025, reaching 29.2 mbd. The transportation sector will
continue to account for 74% of petroleum end use – which is expected to be 21.6
mbd.
4 U.S. DOE, EIA, Annual Energy Outlook, 2003, January 2003.

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CRS-3
Energy production from nuclear power is projected to be flat, while energy from
renewable sources, including hydropower, is expected to increase by about 2.2%
annually. Renewables are forecast by EIA to grow from 5.5% of U.S. energy
consumption in 2001 to 6.3% in 2025.
Cycle of Coal Utilization
Two-thirds of U.S. coal comes from surface mines, while the remaining one-
third comes from deep underground mines.5 For underground mining, the most
efficient technique is the longwall method, which employs a large machine with a
rotating drum that moves back and forth across a wide coal seam. Once coal is
removed by a longwall miner or other method, it is then moved out of the mine with
conveyor belts or shuttle cars.
Surface mining, also called “open-pit” or strip mining, entails blasting rock
above the coal with explosives. This overburden rock is then removed with huge
electric shovels and draglines to reveal the coal seam. The coal seam in a surface
mine is worked in long cuts by uncovering and removing coal then backfilling and
reclaiming land in sequence. In other words, while coal extraction is taking place, as
required by federal law, the reclamation work occurs in an adjacent area previously
mined.
After being mined, some coal6 goes through a cleaning prep facility, where it is
cleaned and separated by grades. Cleaning upgrades the quality of the coal by
removing some of the impurities such as rock, clay, and other ash-producing
material. In general, 30 tons of refuse are removed for every 100 tons of raw
bituminous coal that is cleaned. This refuse is generally pumped into an
impoundment area often built near old underground mines in steeply sloping valleys.
Once cleaned and separated, if necessary, the coal is stockpiled and shipped to
the customer by rail, barge, truck or conveyor. It usually takes more than one mode
of transport for coal to reach its final destination.
Utilities burn pulverized coal to produce high-pressure steam that powers an
electric generator. The pulverized coal, burned at about 1,400 degrees centigrade
(depending on the boiler design), has a higher rate of combustion than non-pulverized
coal. This high heat converts water in tubes lining the boiler into steam. The high
pressure steam passes through a turbine, causing the turbine shaft to rotate at high
speed and turn an electric generator. The electricity is transformed into high voltages
for long distance transmission, then near the point of consumption converted back
to a lower, safer voltage (see figure 1). About 500 out of the 3,000 power plants in
the United States burn coal.
5 Another type of mining, called “steep slope” mining, has largely been superseded by
“mountaintop removal mining” discussed in a later chapter.
6 About half of bituminous coal is cleaned, while subbituminous coal generally is not (see
definitions in the next section).

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CRS-4
Figure 1. Turning Coal into Electricity
Source: Facts About Coal and Minerals, National Mining Association (NMA), May 2002
As coal is burned, emissions are produced that contain sulfur dioxide, nitrogen
oxides, carbon dioxide, particulate matter, ash, and mercury. A discussion on coal
combustion emissions is found in the Environment, Health and Safety section of this
report.
Coal Supply and Demand7
Resources and Reserves
Coal – a dense carbonaceous fossil fuel – is formed from decayed organic matter
that has been subjected to various temperatures and pressures without the presence
of oxygen. This burnable carbonaceous rock also contains various amounts of
mineral matter. Coal seams are formed along with other sedimentary rocks, primarily
sandstone and shale.
There are four basic types of coal throughout the United States:
1.
Lignite: a brownish-black coal with relatively high moisture and ash
content and relatively low heating value. Lignite is mined in Texas, North
Dakota, Louisiana, and Montana.
2.
Subbituminous: This is a dull black coal with higher heating value than
lignite and used for generating electricity and space heat. Resources are
found in Montana, Wyoming Colorado, New Mexico, Washington, and
Alaska.
7 Prepared by Marc Humphries, CRS Resources, Science, and Industry Division.

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CRS-5
3.
Bituminous (soft coal): This type of coal has a higher heating value than
subbituminous and lignite and is the type typically used for electric power
generation in the United States. It is found primarily in Appalachia and the
Midwest
4.
Anthracite (hard coal): Anthracite has the highest energy content of all
coals but occurs in a limited geographic areas, mainly in Appalachia and
Pennsylvania.
Coal quality is measured by its Btu (energy) value, sulfur levels, and ash
content. The content of sulfur is significant because of the sulfur dioxide (SO2)
emissions that occur during coal combustion. There are controls on the amount of
SO2 allowed from coal-fired power plants.
U.S. Coal Reserves. The U.S. demonstrated reserve base for coal is
estimated at 508 billion short tons, but as much as 45% is considered to be
unrecoverable. Thus, accessible reserves are estimated at about 274 billion short
tons. EIA statistics show that more than half of U.S. coal reserves are located in the
West (see Table 1).
Table 1. U.S. Coal Reserves by Region
Coal-Producing Region
Million Short Tons
% of Total
Surface
Appalachia
16,518.1
13.4
Interior
27,261.2
22.1
West
79,145.5
64.3
U.S. Total
122,924.9
100.0
Underground
Appalachia
39,630.9
26.2
Interior
37,491.6
24.8
West
73,865.5
48.9
U.S. Total
150,988.0
100.0
Total
Appalachia
56,149.1
20.4
Interior
64,752.8
23.6
West
153,011.0
55.8
Total U.S.
273,912.9
100.0
Source: Energy Information Administration., U.S. Coal Reserves, A Review and Update, 1995Tables
may not add due to rounding.

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CRS-6
The breakout of the demonstrated reserve base (DRB) by sulfur content (low,
medium, high)8 is fairly even. Low-sulfur coal is estimated by EIA at 170.8 billion
short tons (b st); medium 141.1 b st; and high at 183.7 b st. The location of the
various coals is not evenly divided, however. Eighty-four percent of the low-sulfur
coal is in the West, 15% in Appalachia, and only 1% in the Interior region.
Conversely, the Interior states contain 69% of all the high-sulfur bituminous coal,
Appalachia 25%, and the West only 7%. Figure 2 shows the major U.S. coal-
producing regions.
The United States ranks number one in the world in recoverable coal reserves.
Russia has an estimated reserve base of 173 billion short tons, while China has 150
billion short tons. Taken together, the top three countries hold 55% of the world’s
recoverable coal reserves. U.S. recoverable coal reserves represent about 25% of total
world reserves. Russia holds 16%, and China 14%. When India and Australia are
added, the top five countries account for 71% of world coal reserves (see Table 2).
Figure 2. U.S. Coal Deposits
Source: National Mining Association
On a statewide basis, Montana and Illinois rank one and two for demonstrated
reserve base of coal (see Table 3), but when looking at accessibility and recovery
factors, a different picture emerges. In Illinois, whose entire demonstrated resource
base (see footnote 1) is bituminous, 82% is underground; the state’s accessibility
factor9 for underground coal is 67%, and its recovery factor is 50%. This would
8 A low sulfur level is 0.60 lbs. or less sulfur per million Btus; medium sulfur level is 0.61-
1.67 lbs per million Btus; a high sulfur level is 1.68 lbs or more sulfur per million Btus.
9 The accessibility factor is the amount of the demonstrated coal reserve base (surface and
(continued...)

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CRS-7
indicate relatively low estimated recoverable reserves from the DRB. Overall, the
Interior region, with its high-sulfur, primarily underground coal, drops from a DRB
of 145 billion short tons to 65 billion recoverable short tons – or from 29% to 23%
of the total reserve base. The entire Interior region is a mature producing region that
appears to have reached its production peak.10
Table 2. World Coal Reserves
(million short tons)
Country
Reserves
% of Total
United States
274
25.0
Russia
173
16.0
China
150
14.0
Australia
99
9.0
India
83
7.0
Other
310
29.0
Total World Reserves
1,089
100.0
Source: Department of Energy, Energy Information Administration, International Energy Outlook,
2002.
Table 3. U.S. Coal Demonstrated Resource Base, Top 5 States
(in million short tons)
State
Underground
Surface
Total
Montana
71.0
48.7
119.7
Illinois
88.5
16.6
105.1
Wyoming
42.5
25.3
67.8
West Virginia
31.0
4.4
35.4
Kentucky
18.6
13.5
32.1
All Others
90.2
57.4
147.6
Total DRB
341.8
165.9
507.7
Source: Energy Information Administration., Coal Reserve Data.
9 (...continued)
underground) that is considered accessible for future development. This term is discussed
in the EIA document U.S. Coal Reserves: A Review and Update, p. 37.
10 Milici, Robert C., U.S. Geological Survey, Production Trends of Major U.S. Coal-
Producing Regions, Pittsburgh Coal Conference 1996.

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CRS-8
In the West, the accessibility rate is much higher: 90% for western Montana and
98% for Wyoming. However, the recovery rate is a major limiting factor in Montana
coal production, given that 60% of its DRB is underground. Even though its
accessibility is high at 90%, Montana has a recovery factor of 56%.11 Coal reserves
in the Powder River Basin (PRB) in Wyoming are enormous.
Coal Production Trends
U.S. coal production of 1,127.7 million short tons in 2001 set a new record,
although it fell slightly in 2002. Production has fluctuated over the past 10 years
(1992-2001) between about 1 billion short tons annually to 1.1 billion short tons (see
Table 4). Overall, this indicates relatively flat production since 1992.
However, important changes are taking place in the share of Eastern coal versus
Western, low-sulfur coal. The production trend of eastern Appalachian coal is
slightly downward from recent high levels in 1997-98 (see figure 3). In 1997,
Western production surpassed coal production from Appalachia. Production from
the Interior states also showed an overall decline during the past several years.
Table 4. U.S. Coal Production
(million short tons)
Year
Total Coal Production
1992
997.5
1993
945.4
1994
1,033.5
1995
1,033.0
1996
1,063.9
1997
1,089.9
1998
1,117.5
1999
1,100.4
2000
1,073.6
2001
1,127.7
2002
1,099.9
Source: Monthly Energy Review, DOE/EIA, January 2003, and
Mining Engineering, May 2002.
11 EIA, U.S. Coal Reserves, 1995.

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CRS-9
Most of the Western producers operate surface mines, in contrast to the larger
number of underground mines in the Interior and Eastern regions. Surface mining
operations accounted for 65% of total mine output in 2001, compared with about
61% of output in 1996. Declining production in Interior states is evident, while
production in Western states, Wyoming in particular, has increased at 4.8% annually
over the past decade. Appalachian production, while up in 2001, has been declining
at an average rate of 1.4% annually for the last 10 years.
The leading coal-producing states are Wyoming (365.6 million short tons,
hereafter m st) and West Virginia (160.4 m st). In 2001, they accounted for 47% of
total U.S. production. Kentucky, the third-largest producer, contributed 132.1 m st.
Coal production in the United States is projected to continue to rise, reaching
1,440 million short tons by 2025, up from the current production level of 1,121
million short tons. While some increases in low-sulfur coal production occur in
Appalachia, most of the low-sulfur coal production is expected to occur in the West.
Spurred partly by the Clean Air Act, production of low-sulfur coal – particularly
Western coal, the lowest in sulfur – is projected to rise from about 600 million short
tons in 2001 to about 900 million short tons in 2025. In contrast, production of
Eastern coal is projected to remain nearly flat through 2025, according to EIA. The
annual growth rate for Western coal is expected to be 1.7% through 2025.
Figure 3. U.S. Coal Production by Region
Source: EIA, Coal Industry Annual, 2000, January 2002.

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CRS-10
Coal Production on Federal Lands
U.S. government-owned lands hold about 60% of U.S. recoverable coal
reserves. The federal coal leasing program is administered by the Bureau of Land
Management (BLM) under the authority of the Mineral Leasing Act of 1920, as
amended, and the Mineral Leasing Act for Acquired Lands of 1947. BLM is
responsible for coal leasing on roughly 570 million acres of federal lands as well as
on private lands where mineral rights are owned by the federal government.
Regulatory guidance for BLM’s leasing program is contained in Title 43 of the
Code of Federal Regulations (CFR), part 3400. BLM conducts competitive coal
lease sales either through a regional leasing process or a leasing-by-application
process. Once “fair market value” is established, sealed bids are accepted prior to the
sale date. Eligible bids must meet or exceed the fair market value of the coal tract
as determined by BLM, and include necessary fees, e.g., upfront rental payments and
a portion of the bid amount. Permits and licenses to mine must still be acquired from
BLM, the Office of Surface Mining (OSM), and state and local governments.
Coal leases on federal lands awarded after the Coal Leasing Act of 1976 pay
royalty rates of 8% of the value of production from underground mines and 12.5%
of the value of production from surface mines. Annual rental fees are $3 per acre.
Before a lease is issued the lessee must post a financial guarantee or bond sufficient
to cover the costs of reclamation and other provisions of the lease agreement.
Coal production on federal lands was 393.5 million short tons in 2001, or 35%
of all U.S. production. A record 411.8 million short tons of coal was produced on
federal lands in 2000. This is up from 253 million short tons in 1991. Royalty
payments have fluctuated widely over the last 10 years and reached $337.7 million
in 2001, up from $276.7 million in 1991.
Coal Consumption Patterns
Coal supplies 22% of U.S. energy demand but 56% of the energy used by the
electric power sector (utility and non-utility consumption). Total U.S. coal
consumption was 1,063 million short tons in 2001, with 91% of coal used in the
electric power sector. The other end-use sectors, accounting for the remaining 9% of
coal consumption, include other industrial (5%), coke plants (2.5%), and
residential/commercial (1.5%).
Coal consumption has maintained a greater than 50% share of the electric power
sector for many years (see figure 4). Although total coal consumption for electricity
generation is predicted to rise, coal’s share of electric power generation will fall
below 50% by 2025, according to EIA. Demand for coking coal for steelmaking is
expected to decline from about 25 m st to 17 m st, because increased steel production
is coming from minimills that do not use coke. EIA forecasts coal consumption to
rise from 1,063 m st in 2001 to 1,444 m st in 2025. Over the same period, EIA
predicts a drop – from 22% to 20% – in coal’s overall share of U.S. energy demand.

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CRS-11
Figure 4. U.S. Electric Power Sector Energy
Consumption, 2001
(%)
Source: National Mining Association, Facts About Coal and Minerals, 2002.
Coal Prices
Coal price statistics generally refer either to prices at the mine or to delivered
prices to consumers (typically electric utilities). Up to half of the price of coal
delivered to customers can consist of transportation costs.
Transportation costs also have a strong effect on the price charged at the mine
– the greater the distance from major markets, the less valuable a coal deposit
becomes. Along with transportation, other major factors affecting coal prices are:
! production costs, determined by the nature of a coal deposit and the
extraction method employed (i.e., surface versus underground
mining);
! energy content of the coal (Btus per ton – the greater the Btu content,
the more valuable the coal);
! sulfur content – the lower the sulfur content, the more valuable the
coal;
! land fees, for purchase or lease, including fees for mining on federal
lands;
! state and other taxes; and
! profit.

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CRS-12
Western coal tends to be lowest in sulfur, but it also has relatively low Btu
content and is farthest from most major electricity markets. However, the production
costs at large Western surface mines are relatively low, which allows Western coal
to compete very effectively even with higher-Btu Eastern coal that doesn’t have to
be transported as far. The lowest-quality Western coal, which is generally not
economic to transport significant distances, is often consumed at electric power
plants at mine locations. Mine prices12 for coal produced from surface mining
operations averaged $12.46 per short ton in 2000. Underground mine prices were
nearly double at $24.73 per short ton.
Average coal prices at the mine have generally declined from $21.49 per short
ton in 1991 to $16.78 per short ton in 2000.13 Price differentials between Western
and Eastern coal are substantial. Mine prices in the West average $8.73 per short ton,
while coal prices in Appalachia are near $26 per short ton. Interior prices fall
between the two at $18.37 per short ton. Price data, when further broken out by state,
show Wyoming prices falling from $8.09 per short ton in 1991 to $5.50 per short ton
in 2000. EIA projects that average mine prices will fall 0.87% annually through
2025.
Because of transportation costs, customers farthest from major mining areas
tend to pay the most for delivered coal. On average, electric utility customers paid
$24.28 per short ton for delivered coal in 2000. But customers in New England paid
the highest average price, at $40.16 per short ton, followed by South Atlantic
customers, paying $34.81 per short ton. The average price of delivered coal to
electric utilities is forecast by EIA to fall by 0.5% annually to $22.17 per short ton
by 2025.
Coal Transportation
Railroads are the primary shipment mode for about 65% of all U.S. coal. About
15% is moved primarily by barge on inland waterways. Truck deliveries account for
about 11% of all coal moved in the United States, and 8% is moved by conveyor belt
or other systems.14
Transportation costs on average account for 41% of delivered coal prices, but
EIA projects coal transportation costs to fall by 1.2% each year through 2025. Coal
transport can account for as much as 60% of the delivered price of coal out of the
Powder River Basin (PRB), although costs have been dropping. Transport costs are
lower because of larger unit trains with high-capacity coal cars (100 tons or more),
and improved rates and cycle times from Western coalfields. Between 1988 and
1997, the average rate per ton decreased by 35% for Powder River Basin coal while
12 Mine prices cited in this report are “freight on board” (FOB); that is, the coal has been
loaded into a rail car or other conveyance for shipment.
13 All prices are discussed in Platts RDI Consulting, Coal Supply and Demand
Fundamentals, Carnegie Mellon University, November 25, 2002, nominal dollars.
14 EIA, Coal Industry Annual 2000.

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CRS-13
shipments jumped by 74%.15 As production of Western coal increases, adequate rail
capacity to Eastern markets, although improving, may become a growing concern.
Coal Trade
U.S. coal exports (both steam and coking coal) declined by 50% between 1997
and 2001 to 48.7 million short tons. This decline is likely to continue because higher-
cost U.S. coal is generally becoming less competitive in foreign markets. EIA
expects U.S. coal exports to drop from 7% of world coal trade in 2001 to 3% in 2015,
despite increasing world demand, particularly in Asian markets. Major world
exporters of steam coal are Australia, Indonesia, South Africa, and China.16
U.S. coal imports set a record in 2001, rising 58% from the previous year.
However, the 19.8 million short tons imported in 2001 were less than half of U.S.
exports and only about 2% of total U.S. demand. The sharp rise in imports resulted
from tight supplies in the United States overall and a higher demand for low-sulfur
coal. Imported coal at $34 per short ton is competitive with prices paid by consumers
in the New England and South Atlantic regions. Electric utilities accounted for over
50% of imported coal. Colombia provided the United States with 57% of its coal
imports in 2001, and Canada ranked second at 17%.17
Tax Incentives18
Coal is subject to one federal excise tax (the black lung excise tax) and one fee
(Abandoned Mine Land Reclamation Fee), but it also qualifies for certain tax
benefits: percentage depletion allowance (rather than cost depletion) and expensing
(rather than capitalization) of mine development and exploration costs. The demand
for coal has also been stimulated by favorable rulings from the Internal Revenue
Service that allow coal that is ground, soaked, and cured to be defined as a
“synthetic” fuel, thus qualifying for a tax credit under §29 of the IRS code. The credit
for such synthetic fuel, which is primarily used as a boiler fuel, is approximately $26
per ton of coal, and is available through 2007 for facilities placed in service by June
30, 1998. The §29 credit was also available for coalbed methane through the end of
2002.
Also important to coal producers are proposals to subsidize the use of clean coal
technologies. Both the House- and Senate-passed versions of comprehensive energy
legislation in the 107th Congress (H.R. 4) would have provided an investment tax
credit for capital equipment using clean coal technologies and a production tax credit
15 DOE/EIA, Energy Policy Act Transportation Rate Study: Final Report on Coal
Transportation, October 2000.
16 Ewart, Ellen, “U.S. Coal Exports Don’t Swing Much Anymore,” Coal Age, January
2003.
17 Freme, Fred, “Coal Overview,” Mining Engineering, May 2002.
18 Prepared by Salvatore Lazzari, Specialist in Energy Policy, CRS Resources, Science, and
Industry Division.

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CRS-14
for the electricity generated from facilities that use clean coal technologies. Although
H.R. 4 was not enacted, similar proposals are possible in the 108th Congress.
Structure of the Coal Industry19
The U.S. coal industry is becoming more concentrated. Coal production from
the top five producers jumped from 26% of total U.S. production in 1991 to 51% in
2001 (see Table 5). The top two producers in 2001, Peabody Energy and Arch Coal,
were responsible for 27.9% of all U.S. production.
The 10 largest-producing mines – nine of which are in Wyoming – accounted
for 28% of U.S. production in 2000. The top 10 mines and all but two of the 20
largest mines are surface mines. The three leading producers in Wyoming are
Peabody Energy (99.2 m st), Kennecott Energy (77.4 m st), and Arch Coal (60.6 m
st). In the second-leading coal producing state of West Virginia, the top three
producers are Consol Energy (17.9 m st), Arch Coal (16.7m st), and Peabody Energy
(9 m st). The top 10 producing mines in West Virginia accounted for 45% of the
state’s production and 5% of U.S. production in 2000.
Table 5. Major U.S. Coal Producers
(million short tons)
Year 2001
Year 1991
Producers
Tonnage
% of Total
Producers
Tonnage
% of Total
Peabody
194.4
17.3
Peabody
91.7
9.2
Arch Coal
118.4
10.6
Consol Coal
55.2
5.5
Kennecott
Energy 117.5
10.5
AMAX
Coal
44.8
4.5
Consol Energy
73.7
6.6
ARCO Coal
32.6
3.3
RAG
American Coal
65.5
5.9
Exxon Coal
31.5
3.2
Source: Coal Industry Annual, 1993 for 1991 data. NMA Facts About Coal and Minerals, 2002 for
2001 data.
This trend toward consolidation is likely to continue, because the smaller
operations with higher-cost coal in the East are becoming less competitive. Low-cost
coal plus lower transportation costs is expected to allow more Western coal to
penetrate eastern markets.
The concentration of production in the industry is not expected to have any
upward price effects, as price forecasts by EIA generally decline over the next 25
years. For example, in 2001 dollars, mine prices are projected to fall an average of
0.8% annually through 2025 (another $3.23 per ton). In nominal, unadjusted dollars,
19 Prepared by Marc Humphries, Analyst in Energy Policy, CRS Resources, Science, and
Industry Division.

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CRS-15
the average price of coal at the mine is forecast to climb from $18.83 in 1995 to $26
in 2025. Western coal prices are projected to remain less than half of Eastern coal
prices.
While coal production is climbing, the number of mines is declining and will
likely continue to decline in the future. The number of mines producing more than
10,000 short tons per year dropped from 4,092 in 1987 to 1,453 in 2000. The mines
that remain are producing more on average and using less labor to do it. The number
of coal miners fell from 83,462 in1996 to 70,000 in 2000, and tons per worker-hour
rose by 21% (see Table 6). The decline was about 2% per year from 1970-2000. The
reduction in mining employment is not expected to be as dramatic over the next 20
years, but the decline is expected to continue by an average of 0.5% each year.20
Labor costs relative to the value of coal production have dropped from 23% of
mine production value in 1990 to 16% in 2001. EIA expects labor costs as a share of
mine value to fall to 13% by 2025.
Table 6. Mine Productivity
Year
Number of Mines
Number of Workers
Tons/Average Man Hour
Producing More Than
10,000 short tons/year
1992
2,746
110,196
4.36
1993
2,475
101,322
4.70
1994
2,354
97,500
4.98
1995
2,225
95,700
5.20
1996
1,903
83,462
5.69
1997
1,828
81,516
6.04
1998
1,726
85,418
6.20
1999
1,591
78,723
6.61
2000
1,453
71,522
6.91
Source: 1997, 2002 Keystone Coal Industry Manual, EIA Coal Industry Annual, 2000
Financial Health of the Industry
The financial status of the coal industry is difficult to determine because
financial data is not readily available from many companies. However, EIA provides
return on investment (ROI) data from its Financial Reporting Service (FRS). ROI
figures on the coal industry indicate a general picture of mostly positive financial
20 AEO, 2003, p. 87.

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CRS-16
results. The industry averaged about a 7% ROI over the years 1992-2001, including
a 26.4% return in 1998 but only a 1.7% return in 2000.21
Behind the average results, a much more mixed financial picture unfolds. For
example, three major coal producers are under Chapter 11 bankruptcy protection,
several companies have discontinued operations, and others are in financial
difficulty. These financially troubled companies are primarily in Appalachia and the
Interior regions. Because of widespread financial weakness in the industry, there is
relatively little capital investment for infrastructure or new mines, according to
industry analysts.22
Federal Agencies and Coal23
In conjunction with the states, federal agencies play a major role in regulating
coal mining in the United States, as well as implementing environmental laws that
affect coal. Below is a list of federal agencies that regulate the U.S. coal industry and
programs that are relevant to the industry.
Office of Surface Mining
The Office of Surface Mining in the Department of the Interior (DOI)
administers the Surface Mining Control and Reclamation Act of 1977 (SMCRA, 30
U.S.C. 1201 et seq.). The Office of Surface Mining oversees state programs that
meet federal requirements, or it is the primary regulator in states without approved
programs. The Act requires state or federal permits for surface mines and for the
surface operations of underground mines, as well as a process for determining areas
not suitable for coal mining. A reclamation plan is required for each mine, including
a detailed timeline for reclaiming the land. Surface miners must also meet all
applicable environmental regulations and performance standards. Performance bonds
and financial guarantees must be sufficient to cover the costs of reclamation.
Mine Safety and Health Administration
The Mine Health and Safety Administration (MSHA) of the Department of
Labor (DOL) is the primary regulator under the Federal Mine Safety and Health Act
of 1977 (the Mine Act, 30 U.S.C. 801 et seq.). The Mine Act amended the 1969 Coal
Act and consolidated all federal health and safety regulations of the mining industry
into a single statutory system. The Mine Act transferred responsibilities from DOI
to DOL and established MSHA. The Act also established an independent Federal
Mine Safety and Health Review Commission to review MSHA’s enforcement
actions. The 1977 Mine Safety and Health Act included provisions of the 1969 Coal
Act that prescribed mandatory health and safety standards and provided Black Lung
benefits.
21 EIA, Performance Profiles of Major Energy Producers, Appendix B, January 2003.
22 Ewart, op. cit.
23 Prepared by Marc Humphries, Analyst in Energy Policy, CRS Resources, Science, and
Industry Division.

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CRS-17
Environmental Protection Agency
The Environmental Protection Agency (EPA) administers the Clean Air Act, the
Clean Water Act, the Resource Conservation and Recovery Act, and other major
environmental laws that affect coal production and use. Under the Clean Air Act,
EPA sets and enforces performance standards for large new or modified stationary
sources, such as power plants, to ensure air quality standards. Provisions of the
Clean Water Act require that each state develop and implement a comprehensive
water quality management plan, subject to approval of EPA.
Other Federal Agencies
The Army Corps of Engineers issue permits for disposal of solid wastes, dredge,
or fill material in navigable waters. The U.S. Geological Survey conducts coal
resource assessments throughout the United States. The Bureau of Land
Management administers the federal coal leasing program. The Minerals
Management Service collects and distributes revenues from royalty, rent, and bonus
bids from the leasing and production of coal on federal lands. The federal
government continues to promote clean coal strategies through R&D funding at the
Department of Energy.
Environment, Health, and Safety
Regulation of Air Emissions24
Beginning with the Clean Air Act of 1970, and with substantive additional
measures enacted in amendments of 1977 and 1990, electric utilities have been
subjected to a multilayered patchwork of air pollution emission requirements. Coal-
fired electric generating facilities are major emitters of several gases (see Table 7),
with clean air controls currently directed at three pollutants: sulfur dioxide (SO ),
2
nitrogen oxides (NOx), and particulate matter (PM).
Table 7. 1999 Emissions From U.S. Fossil-fuel-fired Electric
Generating Plants
(thousands of short tons)
Coal
Petroleum
Natural Gas
SO
11,295
670
2
2
NOx
6,547
123
376
CO
1,900,304
91,753
198,655
2
Source: Energy Information Administration, Electric Power Annual 1999 Volume II, p. 42.
24 Prepared by Larry Parker, Specialist in Environmental Policy, CRS Resources, Science,
and Industry Division.

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CRS-18
Sulfur oxides have health effects and are a major contributor to acid rain and
visibility impairment. Nitrogen oxides have direct health effects, contribute to acid
rain and visibility impairment, and are a precursor to ozone, a primary constituent of
smog. Particulates have health effects, with the smallest particles now thought to be
serious causative agents; current regulations focus on particles 10 microns in size or
smaller (PM ) and proposed regulations would control particles less than 2.5
10
microns in diameter (PM ).25 Emissions of SO and of NOx contribute to the
2.5
2
formation of these very fine particles. In 1999, according to EPA, electric utilities
accounted for approximately 67% of U.S. emissions of SO , 25% of NOx, and 11%
2
of PM . Most of those emissions were from coal-fired facilities.
10
In addition, fossil fuel fired electric generating facilities produce two other gases
of environmental and health concern: mercury (Hg) and carbon dioxide (CO ). While
2
some sources of mercury are currently regulated, emissions from electric utilities are
not. However the Clean Air Act Amendments of 1990 designated Hg as a hazardous
air pollutant subject to a regulatory regime spelled out in §112. A 1997 EPA study
required by the act concluded mercury is a hazard to public health and found that
electric utility steam generating units account for about one-third of the nation’s
mercury emissions.26 On December 14, 2000, EPA announced its intention to
regulate utility Hg emissions in 2004, with an effective date of 2007 or 2008.27
Carbon dioxide is a major greenhouse gas, and fossil fuel fired electric
generating facilities account for about 36% of U.S. emissions. While CO emissions
2
are not currently regulated, the United States is a signatory of the United Nation
Framework Convention on Climate Change, which involves a voluntary commitment
to hold greenhouse gas emissions to 1990 levels. At present, U.S. emissions of CO2
are running some 10% over that goal.28 The United States signed the Kyoto Protocol,
under which the U.S. would be legally committed to reduce emissions in the 2008-
2012 period by 7% from a baseline that includes 1990 CO levels; however, that
2
Protocol has not been submitted to the Senate for advice and consent and is not in
force. But it remains possible that, beyond the existing voluntary goal, utilities could
be subjected to emissions limits on CO at some time in the future.29
2
National Ambient Air Quality Standards – New Source Performance
Standards – Lowest Achievable Emissions Rate. As enacted in 1970, the
CAA established a two-pronged approach to protect and enhance the quality of the
25 68 Federal Register 1660.
26 U.S. Environmental Protection Agency, Mercury Study Report, EPA-452/R-97-003,
December 1997.
27 EPA, “Regulatory Finding on the Emissions of Hazardous Air Pollutants From Electric
Utility Steam Generating Units,” Federal Register, Vol. 65, no. 245 (December 20, 2000),
79825-79831.
28 John E. Blodgett and Larry Parker, Global Climate Changes: Reducing Greenhouse
Gases–How Much from What Baseline? CRS Report 98-235 ENR. Updated Jan. 29, 2001.
29 For a review of U.S. global climate change policy, see: Larry Parker and John Blodgett,
Global Climate Change Policy: Cost, Competitiveness, and Comprehensiveness, CRS
Report RL30024.

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CRS-19
nation’s air. First, the Act established National Ambient Air Quality Standards
(NAAQS), which set limits on the level of specified air pollutants in ambient air.
Second, the Act required national emission limits to be set for major new polluting
facilities; these are called New Source Performance Standards (NSPS).
NAAQS have been established for six pollutants, including SO , NOx, and PM.
2
Under the law, EPA sets primary NAAQS30 to protect the public health with an
“adequate margin of safety.”31 EPA periodically reviews NAAQS to take into
account the most recent health data. NAAQS are federally enforceable with specific
deadlines for compliance, but states are primarily responsible for actually
implementing the standards, through development and enforcement of State
Implementation Plans (SIPs). In general, these plans focus on reducing emissions
from existing facilities to the extent necessary to ensure that ambient levels of
pollution do not exceed the NAAQS. For example, EPA’s recently promulgated
NOx SIP Call requires 20 states and the District of Columbia to revise their SIPs to
achieve substantial NOx reductions from their existing facilities to help ozone non-
attainment areas in the Northeast comply with the ozone NAAQS.32
For areas not in attainment with one or more of these NAAQS, the 1970 CAA
mandates states to require new sources to install Lowest Achievable Emissions Rate
(LAER) technology. Along with offset rules, LAER ensures that overall emissions
do not increase as a result of a new plant’s operation. LAER is based on the most
stringent emission rate of any state implementation plan or achieved in practice
without regard to cost or energy use.33 Existing sources in a non-attainment area are
required to install Reasonably Available Control Technology (RACT), a state
determination based on federal guidelines.
The 1970 CAA also established New Source Performance Standards (NSPS),
which are emission limitations imposed on designated categories of major new (or
modified existing) stationary sources of air pollution. For fossil fuel fired electric
generating facilities, EPA has set NSPS for SO , NOx, and PM , and is required by
2
10
the Act to review the standards every eight years. A new source is subject to NSPS
regardless of its location or ambient air conditions.
In summary, under this overall regulatory regimen, existing sources in non-
attainment areas are subject to controls determined by the state as necessary to meet
NAAQS; existing sources are essentially free from controls in attainment areas. And
30 “Secondary” NAAQS, also nationwide standards, protect “welfare” values, such as
visibility and agricultural productivity. There is no specific deadline for achieving
secondary NAAQS.
31 For a further discussion of NAAQS standard-setting, see: John Blodgett, Larry Parker,
and James McCarthy, Air Quality Standards: The Decisionmaking Process, CRS Report 97-
722 ENR.
32 63 Federal Register 57356.
33 LAER may not be less stringent than NSPS.

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CRS-20
major new sources, including fossil fuel fired electric generating facilities, are subject
to NSPS as the minimum requirement anywhere.34
The requirement under the CAA to control SO2, NOx and PM has increased the
cost of coal-fired electric generation and affected the distribution of coal production
around the country.35 For example, the distinction between new and existing
powerplants has resulted in existing facilities switching to lower sulfur coal over the
past 30 years to control SO2 in compliance with SIPs and the acid rain program under
title IV. In contrast, the 1979 NSPS for SO2 has put low- and high-sulfur coal on a
more equal footing for new powerplant construction. Increased controls for NOx
required by the 1998 NSPS for new sources and the NOx SIP for existing sources in
the eastern United States will increase costs but have no influence on coal production
distribution as SO2 control did. Increased costs for existing coal-fired facilities are
not anticipated to be sufficient to cause facilities to use natural-gas-fired facilities
instead. However, for new facilities, the increased cost from the NOx NSPS widens
the current cost advantage that new natural gas facilities have over new coal-fired
facilities.
Multi-Pollutant Legislation. As noted above, coal-fired electric generating
facilities are major sources of air pollutants and greenhouse gases. A patchwork of
regulations to limit PM, SO2, and NOx emissions exists, with further requirements
on the horizon. The piecemeal nature of the regulations and the uncertainty of future
requirements impose not only direct costs on utilities, but also make planning
difficult in an environment already characterized by industry restructuring, volatile
energy prices, and technological changes.
To bring some consistency and stability to the regulations affecting utility
emissions, legislative initiatives have proposed a “multi-pollutant” strategy. Key
elements of the strategy include:
! aligning pollution control processes and procedures for SO , and
2
NOx so that both regulators and utility managers could anticipate
requirements and integrate their decisions about how to control
emissions;
! adopting efficient economic mechanisms – most notably “cap and
trade” strategies – for the control of the pollutants;
! stabilizing requirements over time; and
34 The federal focus on new facilities arose from several factors. First, it is generally less
expensive to design into new construction necessary control features than to retrofit those
features on existing facilities not designed to incorporate them. Second, uniform standards
for new construction ensures that individual states will not be tempted to slacken
environmental control requirements to compete for new industry.
35 See Larry Parker and John Blodgett, Electricity Restructuring: The Implications for Air
Quality, CRS Report 98-615, pp. 20-22.

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CRS-21
! incorporating potential future control requirements for other emitted
gases (e.g., Hg, CO – a “four pollutant” strategy) into this more
2
stable scheme.
This approach to controlling power plant emissions would have several
tradeoffs. Overall, it would exchange regulatory and economic uncertainty for short-
to mid-term certainty. For the environment, the current controversy that accompanies
the setting of standards and the implementing of regulatory reduction requirements
would be exchanged for a specific reduction target that would not change for 10-15
years. From an economic standpoint, implementing emission caps through emission
trading would reduce costs, and the straightforward enforcement mechanism would
also provide industry with certainty with respect to its responsibilities and potential
penalties, and provide a consistent regulatory regime for industry planning. Finally,
the program might open the door for simplifying or replacing elements of the current
piecemeal requirements. On the other hand, cap and trade systems could conflict with
health standards to protect local areas, as they would allow relatively high pollution
in specific locations as long as the total emissions caps were not exceeded.
The overall impact on coal from a multi-pollutant strategy would depend on
whether CO2 were included, and how. The more modest the CO2 reduction, the
longer the compliance deadline, and the more flexible the compliance strategy, the
less the impact. If a stringent program were enacted, such as would be needed for
compliance with the Kyoto Protocol, the impact would be substantial. If CO2 is not
included, multi-pollutant legislation is not projected to greatly influence the overall
production of coal for electric generation. However, a multi-pollutant bill could
create an advantage for bituminous coal over subbituminous coal, depending on the
specifics of the proposal, particularly with respect to Hg control. Generally,
bituminous coal has a higher ionic mercury content than subbituminous, which has
a greater elemental mercury content. Technology that would be used to control SO2
(“scrubbers”) and NOx (selective catalyst reduction) has the co-benefit of reducing
ionic mercury, but much less effect on elemental mercury. Thus, using bituminous
coal may save operators the expense of additional, dedicated Hg control. However,
there are uncertainties, and insufficient work has been done to determine how much
advantage may be involved here.
New Source Review. The Clean Air Act requires a preconstruction review
of, and a permit for, almost any major modification of an air polluting source or any
major new source. Assuming that a state has an EPA-approved State Implementation
Plan (SIP), which spells out the state’s strategy for complying with NAAQS,
regulatory approval to construct the new source or modify the existing source must
come from the appropriate state agency. To receive this “Permit to Construct,” the
applicant must show that the proposed source or modification will not result in, or
exacerbate, violation of a NAAQS, either locally or downwind. In addition,
applicants must show that their proposal will not result in local or downwind
exceedences of increments of increased air pollution allowed under Prevention of

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CRS-22
Significant Deterioration (PSD) regulations in areas complying with NAAQS. It is
this preconstruction review process that is called New Source Review (NSR).36
The NSR process is triggered for any new source that potentially could emit 100
tons annually (or less in some areas) of any criteria air pollutant, and by any
modification that will cause a significant increase in annual emissions (regulatorily
defined as 40 tons for SO and NOx37). The specific NSR requirements for affected
2
sources depend on whether the sources involved are subject to the PSD or the non-
attainment provisions.38 If covered by PSD, the source is required to install Best
Available Control Technology (BACT), which is determined on a case-by-case basis,
and which cannot be less stringent than the federally determined New Source
Performance Standard (NSPS) for that pollutant. If covered by non-attainment
provisions, the source is required to install Lowest Achievable Emission Rate
(LAER) and obtain applicable offsets for that particular area.39 Like BACT, LAER
must not be less stringent than the federal NSPS.
There is no firm data that NSR has obstructed the construction and operation of
new power plants. The controversy over NSR with respect to power generation
focuses on existing facilities and under what conditions they meet the modification
trigger that would require them to undergo NSR. As defined under the 1970 Clean
Air Act, a modification is “any physical change in, or change in the method of
operation of, a stationary source which increases the amount of any air pollutant
emitted by such source or which results in the emission of any air pollutant not
previously emitted.”40
Enforcing these thresholds has been more difficult than their apparent clarity
would suggest. EPA’s thresholds for the NSPS program generally represent no
practical constraint on life extension efforts by utilities. Most life extension efforts
improve the availability and reliability of generating units, not their capacity to
generate. Thus, their maximum hourly emission rate would not change. Likewise,
most life extension efforts cost far less than 50% of a plant’s asset value, an NSPS
threshold under EPA regulations.41
NSR review has a far more sensitive trigger – a tonnage increase in pollutant
output. Because life extension does improve availability and reliability, it is likely
36 Some restrict the term “NSR” to the review process in a non-attainment area only; the
review process in an attainment area being called “PSD pre-construction review.” This
report uses the term to indicate both. In addition, new and modified sources must meet New
Source Performance Standards (NSPS).
37 40 CFR 52.24(f)(10) for nonattainment; 40 CFR 52.21(b)9230(i) for PSD.
38 It should be noted that a source can be affected by the PSD requirements for one
pollutant, and by the non-attainment requirements for another pollutant.
39 For details on these provisions and their requirements, see Clean Air Act, Part C –
Prevention of Significant Deterioration of Air Quality, sections 160-169; and, Part D – Plan
Requirements for Nonattainment Areas, sections 171-178.
40 Section 111(a)(4).
41 40 C.F.R. 60.15.

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CRS-23
to increase emissions over levels emitted before the life extension activities were
undertaken. But how does one measure the change? What are the baselines42?
Fundamental to the debate on NSR enforcement with respect to existing
facilities is the notion of “routine maintenance.” In promulgating implementing
regulations, EPA exempted certain activities from the definition of physical or
operational change. Among those activities exempted was: “maintenance, repair, and
replacement which the Administrator determines to be routine for a source
category....”43 Responding to this situation, utilities began to spread out their life
extension efforts in an attempt to make them fit into their routine maintenance
schedules.44 Much of the debate, therefore, focuses on whether “routine
maintenance” has become a major NSR loophole for power plant owners.45
A change in NSR is unlikely to have a significant impact on overall coal
production, particularly with respect to construction of new generation.46 With
respect to existing facilities, if more stringent SO controls were to result from
2
rigorous enforcement of NSR, an advantage for low-sulfur coal could be reduced if
those more stringent controls involved technology (such as scrubbers) rather than
switching to lower-sulfur coal.
Global Climate Change. Except for requiring utility monitoring of
emissions, CO is not controlled under the CAA, and controversy exists as to whether
2
CO should be considered a pollutant at all. The slim chance that the regulatory
2
regime adopted at Kyoto would be ratified by the Senate contributed to the Clinton
42 Defining the baseline has been a key issue. Every powerplant has what is called
“nameplate” capacity, which indicates its theoretical size; but the actual output is defined
by its “operating capacity,” which is determined by the engineering and operational details
of the individual plant. Moreover, from an engineering perspective, the operating capacity
declines over time as a result of boiler deterioration, pipe clogging, and other predictable
changes due to use. The issue is, then, what level of capacity restored by renovations
triggers NSR?
43 40 CFR 60.14(e)(1)
44 As observed by Robert Smock, Editor, “Power Plant Life Extension Trend Takes New
Directions,” Power Engineering (February 1989): “There are signs that many utilities
will not use the term “life extension” to describe their spending on old power plants,
even though extended life is one of the major goals of the spending program. The
reason for the aversion to the term lies in the 1970 Clean Air Act. That federal law
requires all power plants constructed after August, 1971 to restrict emissions of air
pollutants such as sulfur dioxide. Plants built prior to 1971 are exempt, which
includes most of the early candidates for life extensions. The problem is that the law
also says that grandfathered plants can lose their exemption if they are “modified”
or “reconstructed” in a major way and emission of proscribed pollutants are
increased.”(p.21)
45 See Larry Parker and John Blodgett, Clean Air: New Source Review Policies and
Proposals, CRS Report RL31757.
46 See Larry Parker, Clean Air: New Source Review Policies and Proposals, CRS Report
RL31757.

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CRS-24
Administration’s refusal to even submit the treaty to that body. At the same time, the
country is obligated under the 1992 United Nations Framework Convention on
Climate Change (FCCC) to pursue strategies with the goal of maintaining CO2
emissions at their 1990 levels.47 Current CO emissions are about 10% above their
2
1990 levels. The Bush Administration has abandoned both the Kyoto Protocol
process and the FCCC goal of maintaining CO emissions at their 1990 levels.
2
Instead, it has proposed a voluntary program to reduce the ratio of greenhouse gas
emissions to Gross Domestic Product (GDP) over the next 10 years. However,
absolute emission levels would continue to increase over this time period.
In the face of scientific uncertainty, the focus of U.S. debate on a climate
change policy can be categorized by the three-Cs: (1) cost (the impact on the
economy); (2) competitiveness (impact of U.S. global competitiveness); and (3)
comprehensiveness (desire for a level playing field for all countries). A CRS survey
of 17 cost estimates for the Kyoto Protocol resulted in a range of between $23 and
$348 a metric ton of CO removed.48 Such an order of magnitude difference in cost
2
estimates makes consensus difficult. This situation is particularly true for the coal
industry, which would feel a substantial burden under any reduction scheme.
Several factors can both lower the cost and reduce the range of cost estimates
presented above. One major factor in producing the $23 - $348 range was
assumptions made about the viability of emissions trading under Kyoto. CO2
reduction cost estimates for global emissions trading scenarios are in the range of
$23-$50 a ton. However, serious questions have been raised as to whether the
trading mechanisms embodied in the Kyoto Protocol could produce the cost savings
suggested by some studies.49 Some of the these objections might be swept away
under a properly designed four-pollutant strategy, because such a strategy would not
necessarily be designed to meet the Kyoto targets. Several of the four-pollutant
strategies proposed in the 107th Congress chose the FCCC 1990 stabilization target
for their CO cap, not the Kyoto reduction requirement.
2
Setting a CO reduction target under a four pollutant strategy would be a very
2
contentious issue. CO emissions from electric generation have risen about 23% from
2
1990 to 2000. Add to this an additional 19% for increased emissions anticipated
between 2000 and 2010, and a reduction requirement back to the FCCC target would
be a substantial undertaking. However, the cost would be less than if the additional
7% required by Kyoto were added to the reduction requirement.
Several of the building blocks for a CO cap and trade program are in place.
2
There is an established baseline (1990), and a credible inventory for powerplant
emissions. Continuous CO emissions monitoring is required for power plants under
2
the 1990 CAAA. There is some experience with international emission credits
47 See John Blodgett and Larry Parker, Global Climate Change: Reducing Greenhouse
Gases – How Much from What Baseline? CRS Report 98-235 ENR.
48 Larry Parker, Global Climate Change: Lowering Cost Estimates through Emissions
Trading – Some Dynamics and Pitfalls, CRS Report RL30285.
49 ibid.

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CRS-25
thanks to the Joint Implementation program pioneered by the United States in the
mid-1990s. The issues of baselines for international projects and domestic allocations
would be contentious; however, the advantage of CO not having been controlled is
2
that policymakers can begin with a relatively clean sheet.50
As noted under “multi-pollutant” legislation, CO2 control could have a
substantial effect on coal production, depending on its specifics. The more modest
the CO2 reduction, the longer the compliance deadline, and the more flexible the
compliance strategy, the less the impact. As noted, a stringent program such as
compliance with the Kyoto Protocol would have a substantial effect.
(For more information about legislative proposals on air emissions, see Larry
Parker, Air Quality: Multi-Pollutant Legislation in the 108th Congress, CRS Report
RL31779.)
Mountaintop Removal Mining51
The environmental, economic, and societal impacts of the surface mining
practice termed “mountaintop removal mining” have attracted considerable attention.
This type of surface mining occurs in Appalachian states ranging from Ohio to
Virginia, especially in West Virginia.52
As its name suggests, mountaintop removal mining involves removing the top
of a mountain with explosives and earth-moving machinery to uncover the coal
seams contained in the mountain. Mountaintop removal creates an immense quantity
of excess overburden, or spoil, which is typically placed in valley fills on the sides
of the former mountains. One consequence is that streams flowing through the
valleys are buried.
While mountaintop removal mining has been practiced in some form since the
1960s, it became a prevalent coal mining technique in parts of central Appalachia
during the 1990s for several reasons. First, as the demand for electricity increased,
so has the demand for the relatively clean-burning, low-sulfur coal found in certain
parts of Appalachia, particularly eastern Kentucky and southern West Virginia.
Second, coal supplies near the surface have been significantly depleted. Third is the
development of large draglines that are capable of moving over 100 cubic yards of
earth in a single scoop.
Until recent years, excess spoil from coal mining was generally placed in the
extreme headwaters of streams, affecting primarily ephemeral streams that flow
50 For a discussion of alternative market mechanisms for CO control, see: Larry Parker,
2
Global Climate Change: Market-Based Strategies to Reduce Greenhouse Gases, CRS Issue
Brief IB97057, updated regularly.
51 Prepared by Claudia Copeland, Specialist in Resources and Environmental Policy,
Resources, Science, and Industry Division.
52 For more information on this issue, see Claudia Copeland, Mountaintop Mining:
Background on Current Controversies, CRS Report RS21421, February 11, 2003.

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CRS-26
intermittently only in direct response to precipitation in the immediate watershed.
Because smaller upstream sites are exhausted and because of the increase in
mountaintop mining activity, today the volume of a single stream fill can be as much
as 250 million cubic yards, with stream burials up to two miles long.53
Regulatory Setting. Regulation of valley fills from mountaintop removal
mining occurs primarily under two federal statutory programs, the Surface Mining
Control and Reclamation Act (SMCRA) and the Clean Water Act (CWA), and
involves several federal and state agencies.
SMCRA addresses the necessary approvals for surface mining operations, as
well as inspection and enforcement of mine sites until reclamation responsibilities
are completed and all performance bonds are released.
The CWA prohibits the discharge of any pollutant from any point source into
the waters of the United States, except in compliance with a permit issued under one
of the two permit programs established by the statute. The two permit programs are
the National Pollutant Discharge Elimination System (NPDES) program,
administered by the Environmental Protection Agency (EPA) under CWA Section
402, and the dredge and fill permit program administered by the U.S. Army Corps
of Engineers (Corps) under CWA Section 404.54
The NPDES program focuses primarily, but not exclusively, on discharges such
as wastewater from industrial operations and sewage treatment plants. The standard
for issuing a 402 permit – which sets limitations on the quantities, rates, and
concentrations of water pollutants – is compliance with pollutant limitation and
control provisions in the Act.
The Section 404 permit program applies to the discharge of dredged or fill
material. Environmental guidelines for such discharges are promulgated by EPA in
conjunction with the Corps. The standard for issuance of a 404 permit is
consideration of the full public interest by balancing the favorable impacts against
the detrimental impacts of a proposed activity.
Section 404 permits consist of two basic types: individual permits for a
particular site, and nationwide (general) permits for categories of discharges that have
no more than minimal adverse impacts on the waters of the United States. Disposal
of excess overburden associated with mountaintop removal mining has generally
been permitted by the Corps under Nationwide Permit 21, which authorizes
discharges from surface coal mining activities that result in no more than minimal
impact (site-specifically and cumulatively) on the aquatic environment.
53 “Brief for the Federal Appellants on Appeal from the U.S. District Court for the Southern
District of West Virginia, in the U.S. Court of Appeals for the Fourth Circuit.” Bragg v.
Robertson, No. 99-2683. p. 6.
54 The CWA authorizes delegation of both of these permit programs to qualified states. The
NPDES program has been delegated to 44 states, including each of the Appalachian states
where mountaintop mining occurs. The Section 404 program has been delegated to two
states, neither in central Appalachia (Michigan and New Jersey).

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CRS-27
The U.S. Fish and Wildlife Service (FWS), which implements and enforces the
Endangered Species Act, also has responsibilities relevant to mountaintop removal
mining. Coordination with FWS is required for both SMCRA and CWA permits.
Criticism and Legal Challenges to Mountaintop Mining. Critics of
mountaintop mining say that, as a result of valley fills, streams and the aquatic and
wildlife habitat that they support are destroyed by tons of rocks and dirt. In addition,
critics assert that mountaintop removal cracks the walls and foundations of nearby
homes; causes dust, noise and vibration from blasting; collapses drinking water
wells; destroys nearby streams for fishing, hiking, swimming or aesthetic pleasure;
and has forced the relocation of whole communities.55 Environmental groups argue
that the federal agencies’ practice of authorizing valley fills under Section 404
permits is unlawful because mining overburden is waste material that pollutes and
destroys waterways, and impacts are more than minimal, which is the standard for
coverage by a nationwide permit.
The mining industry and its supporters argue that mountaintop mining is
essential to the conduct of surface coal mining in the Appalachian region. Waste
disposal in valley fills is a necessary part of that activity because of the steep
topography of the region, and they assert that mountaintop mining would not be
economic or feasible if producers were restricted from using valleys for the disposal
of overburden. Requiring Section 402 permits, rather than 404 permits, would
effectively prohibit a broad range of mining activities that have been allowed by
longstanding practice, they say.
Critics have recently been using litigation to challenge the practice of
mountaintop removal mining. In 1998, a West Virginia environmental group filed
a lawsuit in federal court against the West Virginia Department of Environmental
Protection and the Corps, alleging multiple violations of the CWA and SMCRA.
The lawsuit asserted in part that the Corps had been granting permits that allow
disposal of waste in U.S. waters, contrary to the CWA, and permits under the
nationwide permit program that have greater than “minimal” adverse effects.
In an October 1999 ruling, the federal district court held that disposal of mining
spoil in valley streams violated federal and state mining rules and the CWA (Bragg
v. Robertson, 72 F.Supp.2d 642 (S.D.W.Va. 1999)). Under the ruling, mining spoil
was reclassified from its current description as “dredge and fill material” to “waste
material” that is subject to CWA Section 402 permit requirements, thus raising the
regulatory hurdles for disposal.
Upon appeal, the district court ruling was overturned on the basis of jurisdiction
and state sovereignty issues (Bragg v. Robertson, 248 F.3d 275 (CA4 2001)). In
January 2002, the Supreme Court declined to hear a challenge to the 4th Circuit
decision.
55 Rosenberg, Daniel L. “Mountaintop Mining and Proposed Rule Change Will Waste Clean
Water Act.” National Wetlands Newsletter, vol. 22, no. 4, July-August 2000. p. 12.

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CRS-28
A second lawsuit was brought in August 2001 challenging issuance of a permit
under the Corps’ Nationwide permit program for a mountaintop mining operation in
Kentucky. The same federal district court judge who heard the Bragg case similarly
ruled in this case that the disposal of waste from mountaintop mining into U.S.
waters is not allowed under Section 404, and he permanently enjoined the Corps
from issuing Section 404 permits for the disposal of mountaintop mining overburden
where the purpose is solely to dispose of waste (Kentuckians for the Commonwealth
v. Corps of Engineers, S.D.W.Va., No. 2:01:0770, 5/08/02). Upon appeal, the 4th
U.S. Circuit Court of Appeals ruled that the district court’s action was too broad, and
the court lifted the injunction prohibiting the Corps from issuing Section 404 permits
for disposal of mountaintop mining waste (Kentuckians for the Commonwealth v.
Rivenburgh, No. 02-1736, and Pocahontas Development Corp. et al v. Rivenburgh,
No. 02-1737, CA4, 1/29/03). No appeal has been filed at this writing.
Administrative Actions and Congressional Activity. Additional
controversies over these issues arose because of a proposal by EPA and the Corps in
April 2000 to revise regulations that implement CWA Section 404 by redefining the
terms “fill material” and “discharge of fill material.” One effect of the agencies’
proposal was to establish regulatory definitions more consistent with the Clinton
Administration’s position in the then-ongoing Bragg litigation, namely its view that
regulating mountaintop removal mining under CWA Section 404 is not inconsistent
with that Act. This proposed rule was not finalized before the Clinton
Administration left office in January 2001 but was finalized by the Bush
Administration, substantially as proposed, in May 2002.56 Environmental groups
continue to contend that the disposal practice is unlawful under the Clean Water Act
and that the revised rules allow for inadequate regulation of disposal activities,
including coal mining waste.
Some congressional interest in these issues has been evident. Industry groups
and others had sought a legislative remedy for the U.S. district court’s ruling in the
Bragg case. Late in 1999, during debate on omnibus FY2000 appropriations
legislation, Senator Byrd proposed legislative language that would have provided a
two-year environmental waiver to allow mountaintop coal mining in West Virginia
to continue. The provision passed as an amendment to a short-term continuing
resolution (H.J.Res. 82), but it was not included in the final bill, the Consolidated
Appropriations Act for FY2000 (P.L. 106-113).
Other Environmental Concerns
Subsidence. Mine subsidence occurs when the support of an underground
mine roof shifts or collapses, causing the ground surface above to sink. It may take
many years for the underground pillars in a conventional coal mine to give way to
erosion or other factors. Greater use of longwall mining, in which no pillars are left
underground, has increased public concern about subsidence.
56 Department of the Army, Corps of Engineers, and Environmental Protection Agency.
“Final Revisions to the Clean Water Act Regulatory Definitions of ‘Fill Material’ and
‘Discharge of Fill Material.’” 67 Federal Register, No. 90, May 9, 2002. pp. 31129-31143.

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CRS-29
The altered ground slopes caused by subsidence can damage roads and
buildings, and may interfere with natural drainage into rivers and aquifers.
Subsidence is regulated under SMCRA, which requires underground mining to be
conducted in a way that prevents subsidence from causing damage to the surface.
Backfilling or leaving some coal in place can help prevent subsidence. Underground
mining cannot take place in areas below impoundments, below aquifers used for
water supplies, and near or below public buildings, unless it has been determined that
subsidence will not cause damage to those sites.57
Acid Mine Drainage. Acid mine drainage occurs when water flowing from
a mine becomes highly acidic because of exposure to iron sulfide, which is common
in coal mines. Air and water in a mine react with the iron sulfide to produce sulfuric
acid and iron hydroxide. EPA has cited acid mine drainage primarily from
abandoned coal mines as the number-one water quality problem in Appalachia.58
About 10% originates from surface mines and the balance from abandoned
underground mines.
Two major methods are used to treat acid mine drainage. An “active” treatment
uses hydrated lime or crushed limestone to neutralize the acidic water. A biological
or “passive” treatment system uses anoxic (without oxygen) drains, limestone rock
channels, alkaline recharges of the groundwater, and a diversion of the drainage
through wetlands. The passive systems are inexpensive but unproven over the long
run. OSM’s Appalachian Clean Streams Initiative, which began in 1994, is designed
to clean up acid mine drainage using public and private-sector support.
The Abandoned Mine Land (AML) Fund.59 The AML Fund was
established to address the reclamation of coal mines that were in operation prior to
the enactment of SMCRA, and whose owners are no longer in business or cannot be
held liable for reclamation because there were no standards then in place. The AML
fund and program is administered by the Office of Surface Mining (OSM). The fund
is financed by fees collected on coal production. The collections are split into federal
and state shares and distributed to states with approved reclamation programs.
Annual distributions are set by congressional appropriation.
Because receipts to the fund have exceeded appropriations, the fund has an
unobligated balance currently exceeding $1.6 billion. Some of the interest generated
by those balances is paid to the United Mine Worker Combined Benefit Fund. Still,
many states would like to see the pace of distributions accelerated, or would like to
see the formula for grant distribution changed. Coal production has moved
westward, and these states are now paying more into the AML fund while the greater
percentage of abandoned coal mine sites remains in the East and Appalachia. The
57 U.S. Congress, Office of Technology Assessment, The Direct Use of Coal, Prospects and
Problems, of Production and Combustion, 1978.
58 Office of Surface Mining, Department of the Interior Circular, “A Plan To Clean Up
Streams Polluted By Acid Drainage.” This circular can be found at
www.osmre.gov/acsiplan.
59 Prepared by Robert Bamberger, Specialist in Energy Policy, CRS Resources, Science, and
Industry Division.

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CRS-30
AML fund’s authorization expires at the end of FY2004; reauthorization is likely to
be controversial.
Health and Safety Issues60
Safety. Safety in the coal industry has undergone a steady trend of
improvement since 1925. Whereas in that year there were 2,518 fatalities in
accidents, the number has fallen almost continually since, reaching an all-time low
of 27 in 2002. Some of this trend is explained by a decrease in coal industry
employment (from 749,000 in 1925 to about 115,000 currently, according to MSHA
statistics61), some of it by a shift from underground to surface mining, but most of it
by safety improvement. Thus, the overall annual fatality rate decreased over the
period from 3.36 per thousand workers to 0.23 per thousand. Nevertheless, coal
mining remains one of the most dangerous industries in which to work, its fatality
rate still at least five times the average for all private industry, and exceeding that of
many industries generally thought to be dangerous, such as construction and
trucking.62
The Mine Safety and Health Administration (MSHA) is charged with
overseeing the safety of coal and other mining industries. MSHA’s budget of $253
million (FY2002) is somewhat less than the $443 million of its sister agency, the
Occupational Safety and Health Administration (OSHA), but OSHA is responsible
for protecting a far larger number of workers. MSHA oversees a mining industry
(including surface operations and all other minerals besides coal) of about 200,000
workers, while OSHA is responsible for most of the rest of the economy. Thus,
MSHA is able – and indeed, mandated – to perform site inspections much more
frequently than does OSHA.
Accident Prevention. Although mine accidents have declined greatly in
frequency and severity over the years, all parties involved agree that there is still
room for improvement. The United Mine Workers union has been particularly vocal
in criticism of MSHA. It contends that there is an insufficient number of inspectors
and that penalties, both as proposed and as negotiated, are not strong enough. In
general, the union would make enforcement of standards the highest priority.63 The
mining industry generally supports MSHA’s existing regulatory approach, although
it has urged that inspections be focused on mines with indications of problems rather
than be distributed among all mines as currently required.
MSHA, in its latest five-year plan, chooses a strategy of “expanding existing
outreach efforts in the mining community, and shifting the emphasis of regulatory
60 Prepared by Edward Rappaport, Analyst in Industry Economics, CRS Domestic Social
Policy Division.
61 MSHA industry employment numbers differ from EIA figures because of the number of
mines included and other factors.
62 Bureau of Labor Statistics, National Census of Fatal Occupational Injuries, 2001.
63 UMWA Calls on MSHA to End Coal Mine Fatalities. United Mine Workers Journal,
March 2002. p. 18.

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CRS-31
programs from after-the-fact enforcement to education and training and accident
prevention.” Through these initiatives – as well as continued enforcement – the
agency aims to substantially reduce fatal and non-fatal injury rates by as much as half
by 2005. It will also continue working on long-term health hazards by reducing the
prevalence of excessive exposures to dust and noise.64
Some recent, widely publicized accidents have highlighted specific areas that
may merit further attention. The accidental flooding of the Quecreek Mine in
Pennsylvania in July 2002 raised questions about the accuracy of underground mine
maps and their availability to operators of nearby mines. The Quecreek accident
might have been avoided if the mine operator had had access to the final map of a
nearby abandoned mine that had since filled with water. The Pennsylvania State
government is acting to redress the deficiencies that led to the accident. In response
to the Jim Walter No. 5 mine accident in Alabama in September 2001 (which took
13 lives), MSHA is making a number of changes, including additional training for
inspectors, increased management oversight, and a new standard on mine emergency
response. Most of the victims in this case were responding to a relatively small
explosion when a larger one occurred. The mine workers union alleges that MSHA
had not followed up properly on numerous previous violations.65
Health Protection. Accidental injuries can be quantified much more reliably
than the extent of occupationally caused disease. At this point, though, it seems safe
to say that coal mining has caused disability more by way of long-latency disease
than by traumatic injury. Prime among these diseases is black lung (coal workers’
pneumoconiosis (CWP)), which still claims about 1,400 fatalities per year (down by
about half since 1982). Improved dust control requirements led to a decrease in the
prevalence of the disease from the 1970s into the 1980s, but rates have basically
leveled out since then.66
MSHA is expressly required by its authorizing statute to enforce a dust control
standard (currently set at 2 milligrams/cubic meter as an 8-hour average “for each
miner in the active workings of each mine”). There has been continual controversy
about how concentrations are to be measured and how MSHA is to monitor the
operators’ plans and performance. In July 2000 MSHA proposed new regulations
under which its inspectors would verify plans and performance by directly collecting
single full-shift samples, rather than the previous practice of multiple samples
retrieved by the operators. On March 6, 2003, a revised verification regulation was
proposed, and the rulemaking reopened on the companion proposal regarding
measurement methods.67
64 Strategic plan available at [www.msha.gov/MSHAINFO/STRAPLAN/STRAPLAN.pdf].
65 See union complaint at [www.umwa.org/brookwood/brookwood.shtml].
66 For example, among miners with 10 to 14 years of work, the number with positive x-rays
declined from 8.8% in the mid-1970s to 1.7% in the mid-1980s, but rose to 2.2% in the mid-
1990s. U.S. Department of Health and Human Services. Work-Related Lung Disease
Surveillance Report. Cincinnati: NIOSH, 1999 (DHHS report no. 2000-105). Table 2-11.
67 68 Federal Register 10783.

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Meanwhile, MSHA has been working on or has recently issued regulations
dealing with a number of other respiratory hazards that affect coal miners, including
diesel particulates, asbestos, and silica.
Black Lung Benefits Program. The Black Lung Benefits fund is paying
some $400 million per year in income and medical benefits to more than 60,000
primary beneficiaries. The basic support payment is $535 per month as of 2003,
augmentable if there are dependents. Miners are eligible if they are disabled due to
CWP or other chronic dust disease arising out of coal mine employment. In
December 2000 the Department of Labor issued the first extensive revision of its
black lung regulations since 1983. The revisions were generally regarded as making
benefits easier to obtain in some cases. Controversy about eligibility has occurred
in legislative, regulatory, and judicial forums since the inception of the program.
In the 107th Congress, the Bush Administration proposed a refinancing of the
black lung trust fund, which owed more than $7 billion to the Treasury as of FY2002.
Although program revenues (from a tax on coal production) have exceeded the cost
of benefits in recent years, the debt to the Treasury has been growing because of
accumulating interest charges. The Administration proposal would eventually retire
the debt, primarily through intragovernmental transfers with arguably no budgetary
impact, but also by requiring an extension of the coal tax that finances the fund
beyond its currently scheduled expiration of 2014.
Coal Research and Development68
Technology areas for coal research and development include improved power
generation, cleanup of emissions, and production of coal-derived fuels.
As noted previously, most U.S. coal is used to generate electricity. In the
traditional approach to electricity generation, coal is burned to heat water, and the
resulting steam drives a turbine-generator. Advanced techniques can result in lower
fuel consumption and reduced emissions of pollutants and carbon dioxide. The most
prominent approach is integrated gasification combined cycle (IGCC), in which coal
is gasified to fuel a combustion turbine, whose exhaust is then used to heat water to
drive a steam turbine.
Because of the large base of existing power plants, techniques for improving the
performance and emissions of existing power plants are also a major area of research.
A growing research emphasis is the capture and sequestration of carbon dioxide
emissions, such as through injection into underground coal seams or depleted oil
reservoirs. Research on the use of coal to produce liquid and gaseous transportation
fuels is now focused mostly on production of hydrogen.
68 Prepared by Daniel Morgan, Analyst in Science and Technology Policy, CRS Resources,
Science, and Industry Division.

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Coal research is conducted at DOE in the Fossil Energy R&D program. Most
prominent is the Clean Coal Power Initiative (for which $130 million is requested for
FY2004). This is a cooperative program, with industry cost-sharing, that seeks to
enhance the reliability, efficiency, and environmental performance of coal-fired
power generators.69 Other activities include Central Systems (FY2004 requested
budget: $86 million), Sequestration R&D ($62 million), Fuels ($5 million), and
Advanced Research ($37.5 million).
The Clean Coal Power Initiative succeeds and continues the Clean Coal
Technology program. The Clean Coal Technology program is made up of 38
demonstration projects, the last of which were selected in 1993. (Most have now
completed their demonstration phase, although many of the completed
demonstrations remain in commercial operation.) All federal funds for Clean Coal
Technology were provided by Congress between FY1986 and FY1997 in the form
of advance appropriations totaling $1.8 billion. The private sector has provided an
additional $3.5 billion, with each project receiving at least half its support from
private funds.
The DOE Vision 21 initiative seeks to integrate research and development in
several areas, including coal as well as other fuels, with the ultimate goal being a
high-efficiency, low-emissions power plant that combines generation of electricity
with other products such as industrial heat, chemicals, or hydrogen.70 The Vision 21
Technology Roadmap71 provides an overview of the concept and the technologies
involved and, for each technology area, identifies the current status and the
initiative’s approach to meeting its objectives over the next five, 10, and 15 years.
Outlook and Recap
The outlook for U.S. coal is mixed. While supply and demand forecasts indicate
coal will still have a dominant but smaller position in the electricity market, mine
closures and employment losses are expected to continue. There appears to be a
trend toward increased production from fewer mines, larger mines, and fewer
producers.
The continued strong market position of the relatively few major buyers, utilities
in particular, will likely be one factor putting downward pressure on coal prices.
Production costs for many coal operators are falling and will likely continue to fall
as they employ new production technology. But future technology development may
be constrained by low or nonexistent profit margins.
69 The web page of the Clean Coal Power Initiative is
<http://www.fe.doe.gov/coal_power/cct/ccpi/>.
70 The webpage of the Vision 21 initiative is
<http://www.netl.doe.gov/coalpower/vision21/>.
71 The Vision 21 roadmap is available online at
<http://www.netl.doe.gov/coalpower/vision21/roadmap.html>.

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CRS-34
As electricity demand increases, new coal-fired plants may become more
economic than natural gas plants at gas prices near $4 per million Btu.72 And EIA
forecasts that natural gas prices will rise high enough after 2010 to keep coal
competitive. However, EIA also predicts that coal’s share of electricity production
will drop from its current 52% to 47% in 2025. Some energy analysts argue that the
future price of natural gas may be overstated and that the future market share of
natural gas in the electricity market has been underestimated.73
The federal government, with its regulatory role and as the largest holder of coal
reserves, will be a significant player in the future of U.S. coal. Major issues –
discussed in the body of this report – range from environmental regulations to
federally funded research on coal technology. These are summarized in Table 8.
Table 8. Recap of Major Coal-related Issues
Issue
Comment
Legislative Activities/
Further Information
Abandoned Mine Lands
Many states would like
The AML fund is up for
to see changes in the
reauthorization at the
distribution of the AML
end of 2004.
fund. Coal production
has moved westward, so
Western states are
paying more into the
fund while most of the
abandoned mine sites
remain in the East.
Clean Air Act: Impact
This is a major initiative
Bills introduced in the
on coal markets of
of the Bush
108th Congress. See
replacing or
Administration,
CRS Report 31779 for
supplementing CAA
involving emission caps
comparison of
command and control
on NOx, SO2, and Hg.
proposals. See CRS
mechanisms for electric
Contentious issues
Report RL 30878 for in-
generating facilities with
include stringency of
depth background on the
a market-oriented multi-
caps, compliance
issue.
pollutant approach to air
deadlines, regulatory
pollution control
relief from other
provisions of CAA, and
inclusion of CO2
emissions.
72 Ewart, op. cit.
73 Economics of the Minerals Industry, 4th Edition, The Economics of Coal and Nuclear
Energy, Richard Newcomb and Michael Rieber, AIME, 1985.

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CRS-35
Global Climate Change
Mandatory controls on
Bills have been
carbon dioxide – a major
introduced in the 108th
coal emission – have
Congress. See IB97057
been rejected by the
for background on
Bush Administration as
controlling greenhouse
too costly and
gases, including
disruptive. However,
legislation. See CRS
both independent and
Report 31779 for a
multi-pollutant bills
review of legislation in
including CO2 have been
the context of multi-
introduced, with one
pollutant proposals and
reported by the Senate
the Administration’s
Environment and Public
voluntary initiative.
Works Committee in the
107th Congress.
Mine Safety
MSHA wants to expand
None
outreach efforts in
mining communities
from after-the-fact
enforcement to
education, training and
accident prevention.
The goal is to reduce the
injury rate in half by
2005.
Mountaintop Mining
Mountaintop mining
A January 2003 decision
involves removing the
in the U.S. Circuit Court
top of a mountain to
of Appeals overturned
recover the coal seams
an earlier U.S. District
within. Excess
Court decision that ruled
overburden is placed in
valley fills violated the
valley fills on the sides
Clean Water Act.
of the former mountain.
Legislation has been
One consequence is that
introduced in the 108th
streams flowing through
Congress to overturn
the valleys are buried.
recent regulations on
valley fill permits. For
details, see Mountaintop
Mining: Background on
Current Controversies,
CRS Report RS21421.

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CRS-36
New Source Review:
This is a major
Regulations have been
Impact on coal markets
regulatory and
promulgated and
of modifying or
legislative initiative of
proposed. Legislation
eliminating current NSR
the Bush
has been introduced in
provisions with respect
Administration. Some
the 108th Congress. See
to electric generating
regulatory changes have
CRS Report 31757 for
facilities
been promulgated while
an in-depth discussion
others have been
of the issue.
proposed. The
Administration’s
proposed multi-pollutant
legislation contains
broad relief from NSR.
Research and
The Clean Coal Power
$150 million was
Development
Initiative is most
appropriated in FY2003
prominent of the coal
and $130 million is
R&D programs. This
sought in FY2004.
initiative succeeds and
continues the Clean
Coal Technology
Program.
Taxes
Coal is subject to special
Legislation extending
taxes for black lung
synthetic fuel tax credits
benefits and abandoned
for coalbed methane has
mine land reclamation
been introduced in the
but also can qualify for
108th Congress.
synthetic fuel credits.

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