IMPACTS OF THE ACID

RAIN PROGRAM ON COAL

INDUSTRY EMPLOYMENT

United States 

Environmental Protection 

Agency

Clean Air Markets Division

Office of Atmospheric Programs

(6204N)

EPA 430-R-01-002

March 2001
EPA would like to acknowledge ICF Consulting for project management and analysis of the data and the issues

central to this report. 
Table of Contents

I. Executive Summary i

II. Purpose and Background 1

III. Projections of Changes in Labor Demand 7

A. Overview of Methodology 7

B. Changes in Coal Demand as Projected by the IPM96 Analysis 7

C. Translation of Coal Demand into Labor Demand 8

IV. Demand Changes in Context 11

A. Historical Employment Levels and Trends 11

B. National Title IV Employment Impacts in Context 12

C. Employment Changes in the Regions Most Affected by Title IV 13

D. Programs to Assist Unemployed Coal Miners 15

V. Limitations of the Analysis 17

VI. References 19

APPENDIX A: Description of the 1996 Integrated Planning Model A-1

A.1 Analytical Overview A-1

A.1.1 Macro Energy And Economic Assumptions A-3

A.1.2 Electric Energy Cost And Performance Assumptions A-3

A.1.3 Pollution Control Performance And Cost Assumptions A-5

A.2 References A-6

APPENDIX B: Coal Use Projections With and Without Title IV B-1

APPENDIX C: Differences Between 1990/1992 and 1996 Analyses C-1

C.1 Analyses Considered C-1

C.2 Industry Changes Since The 1992 RIA C-2

C.3 Comparisons Of Coal Demand Projections C-6

C.4 Changes In Employment Impact Projections C-9

C.5 References C-12

APPENDIX D: Results of Modeling and Analysis for 2000 D-1

APPENDIX E: List of Acronyms and Definitions E-1

APPENDIX F: Peer Review Process F-1

This report addresses the impacts of the Acid

Rain Program (created under Title IV of the Clean

Air Act Amendments of 1990) on coal mining

employment. It revisits the results of a study that

was originally conducted in 1990, which compared the economic impacts of the acid rain provisions of several legislative scenarios being considered at the time. The earlier study projected

that Title IV could have a substantial effect on

coal mining employment. It predicted a gross loss

of 13,000-16,000 coal miner job slots1 by the year

2001 as a result of Title IV. 

The current study revisits the original 1990 analysis and the differences in the results are quite substantial. The 2000 report projects that by the year

2010, Title IV of the Clean Air Act could result in

a gross loss of approximately 7,700 job slots, or

about half the loss projected by the 1990 study.

The net loss would be only 4,100 coal miner job

slots because 3,600 new job slots would be created. The extent to which Title IV affects coal mining employment, specifically job slots, is the

focus of this paper. 

These changes should be considered within the

context of historical trends in coal mining

employment. Employment for coal miners over

the last 50 years peaked in 1978 at approximately

250,000 workers and has steadily declined in subI. Executive Summary

0

50

100

150

200

250

1970 1975 1980 1985 1990 1994 2000 2005 2010

Year

Thousands of Workers

With Title IV

No Title IV

Title IV 

Enacted

Title IV 

Im plem ented

(1995)

Exhibit 1: Job Slot Changes in the Mining Sector: Coal Mining Employment Changes With and

Without The Acid Rain Program 

i

Source: U.S. Department of Energy, Energy Information Administration (EIA) (2000). Energy Policy Act Transportation Rate Study:

Final Report on Coal Transportation. 

1 The measure of coal mining employment used in this report is “job slots,” the sum of which is equal to the number of coal mining

jobs or to the number of working coal miners in any one year. For details, see page 1.
sequent years. Even without Title IV, jobs for coal

miners decreased as productivity improvements

and other economic factors eroded the need for

large numbers of miners. In 1990, the number of

coal workers fell to 130,000. By 2010, approximately 50,000 coal miner jobs are projected to

remain. Ninety-five percent of the decline (over

75,000 jobs) is expected to be due to productivity

gains, and only five percent of the loss in jobs

(4,100) is expected to be attributable to Title IV.

These percentages are more dramatic compared

to the peak of coal mining employment in 1978,

where 98 percent of the projected job loss

between 1978 and 2010 is related to productivity

gains and only two percent of the net decrease in

coal miner job slots is due to Title IV. 

This analysis is complicated by changes in the

demand for labor in the coal industry, resulting

from factors unrelated to Title IV. Worker productivity improvements and the increasing share of

production from strip mining due to increased

substitutability of coal types have allowed the

demand for coal to be satisfied with fewer workers. These differences in productivity are a result

of the differences in mine types and the differences in the kinds of technologies used in each

mine type. Regional shifts of coal production

result in decreased labor requirements, or miner

job slots.

Concerns over the effects of Title IV on coal

employment stem from limits the Acid Rain

Program places on the emissions of sulfur dioxide

(SO2), especially those emissions from the electric power industry. The Acid Rain Program limits the number of tons of SO2 that are emitted to

about half the number of tons plants would emit

without Title IV’s limits. To comply with the

emissions limits mandated by Title IV, some utilities changed the type of coal that was used while

others installed control technologies. The switch

by utilities to lower-sulfur coals can reduce the

demand for high-sulfur coal and the workers who

mine it. The employment consequences of Title

IV compliance decisions are derived largely from

the fact that different regions of the country tend

to have different levels of sulfur in their coals.

Coal found west of the Mississippi, for example,

is generally lower in sulfur than coal found in the

Midwest or the Appalachians. Within the

Appalachians, sulfur content varies; northern

Appalachian coal tends to have a higher sulfur

content than central or southern Appalachian

coal. Likewise, the sulfur content of Midwestern

coal also tends to vary somewhat but it is primarily high in sulfur. As plant operators switch

among coals based on sulfur content (in addition

to other characteristics such as heat and moisture

content) in response to Title IV, they can increase

or decrease the demand for the coal mined in different regions of the country. In turn, demand for

miners in different regions can increase or

decrease. These changes are further complicated

by the fact that the labor required to produce a ton

of coal differs across the regions. Thus, shifts to

lower sulfur coal can, in some cases, reduce the

net demand for miners, rather than simply shifting

the locus of coal mined. 

The results of this 2000 report show that the Acid

Rain Program has had a limited impact on coal

employment and that the program’s future

impacts on coal mining employment will be considerably lower than originally predicted. 

ii
This report reviews the impacts of the U.S.

Environmental Protection Agency's (EPA) Acid

Rain Program, established under Title IV of the

1990 Clean Air Act Amendments, on coal mining

employment.1 The estimated impacts are derived

from modeling runs conducted in 1996 to estimate the costs of air regulations. By comparing

coal demand by region for two model runs, only

one of which took into account the SO2 reductions

required by Title IV, it was possible to calculate

the broad regional shifts in coal production that

could be attributed to Title IV. Productivity estimates for the eastern and western portions of the

country were then used to translate these changes

in coal demand into changes in coal industry

employment. 

The breakdown of coal supply into regions is not

sufficiently detailed to capture all of the intraregional and intrastate shifts that may be caused by

Title IV. Nonetheless, EPA considers the broad

conclusions of the analysis to be sound. The

report includes Title IV's impact on the number of

miners' jobs and how those jobs shift between the

eastern and western U.S. coal production regions. 

Future employment impacts are expressed in

terms of incremental changes in "job slots,"

which are defined as the number of workers needed to produce the industry's projected output of

coal at projected productivity levels.2 The analysis focuses on the extent to which Title IV results

in fewer coal mining job slots, rather than on Title

IV's impact on miners' employment. As mining

productivity increases and demand for coal is

steady, there will be fewer job slots but not necessarily miner lay-offs if these changes can be

met through retirement or voluntary job changes.

Because the demand for coal miners has been

changing significantly as a result of factors unrelated to Title IV, one important component of this

report is to document the extent to which coal

miner job slots would be expected to decline in

the absence of the Acid Rain Program--i.e., in the

"baseline" scenario. Comparing incremental

effects of EPA's program to this baseline reduction in job slots shows the incremental effects of

Title IV.

"Jobs slots" is used in this report as a measure of

employment and employment impacts, because it

is identified with numbers of workers. Because

productivity per hour varies from region to

region, and labor hours per worker per year vary

as well, concentrating on job slots can mask some

of the effects of a change in demand. For instance,

total labor hours by miners could rise, while job

slots decline, if there were an increase in demand

for western coal and a decrease in demand for

eastern coal. The changes in job slots presented in

this report could have been divided into changes

caused by drops in coal demand, shifts to regions

with higher hourly productivity, and shifts to

regions with higher hours per work year; howevII. Purpose and Background

1. This paper uses the EIA definition of coal employment, that “includes all employees engaged in production, preparation, processing, development, maintenance, repairs, shop or yard work at mining operation. It excludes office workers but includes mining

operations management and all technical and engineering personnel." (EIA, 1995)

2. In any given year, the number of mining jobs, and the number of working coal miners, are expected to equal the number of "job

slots." This term is used to avoid the impression that a miner loses his or her job whenever there is a reduction in the demand for

mine labor, given that no miners need to lose their jobs if the rate of attrition matches the rate of reduction in demand. Other

measures of employment demand use the total number of employees or the number of shifts completed by employees. However,

as the length of shifts and number of hours worked per miner change over time, using these factors prevents consistent comparisons over time. Thus, the calculations in this report are based on a 2,060 hour work year in the East and a 2,536 hour work year

in the West (For more detail, see Chapter III.C). Although the number of hours per slot could always change, it would be hard to

predict what effects this might have on job slots. For example, if miners increase the number of hours worked per year by 5 percent but there is 4 percent less shifting of coal, the number of jobs in the East would still decline.

1
er, an analysis at this level of detail would be

cumbersome and unlikely to add significantly to

the outcomes presented in this report. Because the

annual output per worker in the East and West differ by about a factor of four, while labor hours per

year differ by only about 20 percent, it is clear

that the annual productivity differences between

East and West are due primarily to the differences

in output per miner per hour. Furthermore,

because the regional shifts in coal use are so much

greater than the changes in total coal production,

it is apparent that most of the changes in job slots

are due to the interregional shifts. 

Concerns over the effects of Title IV on coal

employment stem from the limits the Acid Rain

Program places on emissions of sulfur dioxide

(SO2) from utilities, which used almost 90 percent

of the coal produced in 1996 (EIA, 1998). These

limits reduce the demand for high-sulfur coal and

the workers who mine it. Media reports have cited

job losses in the thousands due to restrictions

imposed by the Clean Air Act. The New York

Times, for example, reported that coal mine

employment in Illinois, Indiana, Ohio,

Pennsylvania, western Kentucky, and northern

West Virginia plunged more than 50 percent

between 1990 and 1996. While the change in

employment is attributed largely to automation,

the Clean Air Act in general and the Acid Rain

Program in particular are also blamed by the

media, political groups, and mining interests for

the loss of miners' jobs in the high-sulfur areas of

the East (New York Times, 1996). 

West Virginia and other states producing highsulfur coal have been identified as suffering

severe employment losses as a result of environmental policies, which include air regulations;

however, policies that affect land use, waste disposal, and mining methods can also be important.

Loss of mining employment has effects not only

on the miners, but on other employees in the

region, as these miners' demand for retail, entertainment, and related services declines with the

loss of income. As recently as 1999, the

Associated Press reported that "limits on sulfur

pollution were imposed during the 1990s by the

Clean Air Act, [subsequently] decimating the

high-sulfur coalfields of northern West Virginia,

western Pennsylvania, Ohio, Indiana and Illinois"

(AP, 1999). 

This report examines the validity of such employment loss claims. The Acid Rain Program was

developed pursuant to a mandate contained in

Title IV of the Clean Air Act as amended in 1990.

Title IV sets two broad goals for EPA to reduce

acid precipitation. First, SO2 emissions are to be

reduced by 10 million tons per year below the

level in 1980. Second, NOx emissions are to be

cut (in combination with regulations from other

Titles of the Clean Air Act, including Title II,

which affects mobile sources) by 2 million tons

per year below the 1980 level. Almost all of Title

IV's SO2 and NOx reductions are to be made from

coal-fired power plants operated by utilities. 

Efforts to meet the NOx reduction goals are not

expected to have any significant impacts on coal

use or miners' employment. Most plants, through

modifications to the power plant burners, can

meet the moderate reductions in power plant NOx

emissions required by the Title IV NOx program.

Furthermore, the type of coal burned does not sufficiently affect either NOx emissions rates in the

absence of combustion controls or their control

efficiency. Thus, the NOx program does not discourage the use of any particular type of coal, and

would have minimal effects on the total use of

coal.

Title IV's SO2 program, on the other hand, could

potentially cause a significant increase in the

costs for utilities that burn high sulfur coals. The

program operates by distributing authorizations to

emit SO2, called allowances, to the owners of fossil fuel fired power plants that were in operation

by 1995. To be permitted to emit SO2, plant owners must hold allowances; for each ton emitted

from a plant, the owner must surrender one

allowance. Thus, the Act controls the number of

tons that are emitted by limiting the number of

allowances that are distributed. By distributing

fewer allowances than the number of tons that

plants would emit without Title IV's limits, the

Act causes SO2 emissions to go down. This

reduction in SO2 emissions, in turn, reduces the

2
associated sulfates that occurs when SO2 is transformed in the atmosphere and returns to earth as

acid rain and dry acidic deposition. Sulfates are a

form of fine particulate matter that adversely

affects human health, visibility, the ecology of

lakes and streams and the aesthetics and durability of bronze or marble structures and statues. 

Though the Act controls the total number of

allowances, it does not control which plants will

emit SO2. Instead, EPA lets the allowances that

are distributed circulate freely among power

plants through the market. Allowances may be

sold by plants that are able to reduce emissions

enough to be left with surplus allowances, and

may be bought by plants that need more

allowances than their allocation to cover their

emissions. Utilities may also bank allowances for

future use or sale. The flexibility introduced by

the allowance market has important implications

for coal use, in that it opens up many more compliance options for utilities. Rather than selecting

only among control options that meet a particular

emissions limit for each stack, plants can choose

to switch to a lower sulfur coal, buy allowances,

or use banked allowances. Utilities may also

choose to install a scrubber that might be expensive to install and operate, but might allow a plant

to over-control emissions.3 If a plant's allowances

exceed its emissions, the excess allowances may

be sold or banked. The system also establishes a

nationwide marginal price for SO2 reductions,

equal to the market price for allowances. The

emissions reduction goal is derived from a statutory cap of 8.95 million tons of SO2 emissions

from utilities.

Title IV's SO2 program is being implemented in

two phases. In Phase I, which took effect in 1995,

263 of the largest boilers in the eastern United

States with high emission rates received enough

allowances for them to emit about 2.5 lbs. of SO2

per mmBtu. In Phase II, which started in 2000,

the rest of the fossil-fueled utility units serving

generators larger than 25 MW have been brought

into the system, and all units have been provided

with allowances sufficient to emit at levels up to

1.2 lbs. of SO2 per mmBtu (or less, if their existing permits required a lower limit). Thus, beginning in 2000, there is both an expansion in the

number of utilities affected by the limit and a

tightening of the aggregate SO2 emission limit.

Knowing that their plants would have fewer SO2

allowances in 2000, many operators covered by

Phase I over-controlled emissions and banked the

excess allowances for use during the early years

of Phase II. Because utilities have been over-controlling and banking excess allowances, the full

impact of Title IV's SO2 program on coal employment is not expected to be seen until about a

decade into Phase II (by the year 2010). For this

reason, this report concentrates on projections for

the year 2010. 

The combination of the SO2 emission limits under

Title IV and the flexibility of control strategies

provided by the allowance system interact with

the regional distribution of coal types to affect

coal employment. Because of the allowance system, utilities are not obligated to change the type

of coal they use or the way they use it—they can

continue to use coal that is high in sulfur if they

purchase enough allowances or choose to scrub.

On the other hand, the allowance market provides

a clear signal that the use of high sulfur coal has

an additional cost. Therefore, power plant operators are given a market incentive to switch to a

lower sulfur fuel or to install scrubbers in the

stacks to reduce SO2 emissions. If the choice is

made to scrub, the plant might continue to use or

even switch to a higher sulfur fuel, depending

upon relative fuel prices, because the scrubber

reduces SO2 emissions from high sulfur coal. In

Phase I of the program, 16 plants employing 27

boilers chose to scrub. Because sulfur removal

rates were 90-95%, these few units accounted for

3 This report is based on modeling that does not account for the SO2 reduction potential provided by coal washing. In a study of

SO2 controls for China, coal washing was assumed to reduce SO2 emissions from coal-fired generation by a third. In that it

excludes a potentially cost-effective control measure, this report may overestimate the impacts of Title IV on coal industry employment (Liu and Spofford, 1994).

3
about half of the SO2 reductions in Phase I

(Ellerman et al., 2000). 

The employment consequences of these compliance decisions are derived largely from the fact

that different regions of the country tend to have

different levels of sulfur in their coals.4 Coal production regions as defined in this report are

shown in Exhibits 1 and 2.5 Coal found west of

the Mississippi, for example, is generally lower in

sulfur than coal found in the Midwest or the

Appalachians. Within the Appalachians, sulfur

content varies; northern Appalachian coal tends

to be higher in sulfur than central or southern

Appalachian coal. As plant operators switch

among coals based on the coal's sulfur levels in

response to Title IV, they can increase or decrease

the demand for the coal output in different regions

of the country. In turn, demand for miners in different regions can increase or decrease. These

changes are complicated by the fact that different

regions need more or fewer miners to produce a

ton of coal. Coal miners' productivity is generally

higher in some of the most important low-sulfur

mining regions in the West than in most of the

eastern high-sulfur mines because the coal in the

West lies in thick layers close to the surface.

Thus, shifts to lower sulfur coal can reduce the

net demand for miners, rather than simply shifting

the locus of coal mined. 

Exhibit 1. Map of Coal-Producing Regions in the United States.

4 Because the heat content per ton of coal can vary, it is more precise to state that different regions tend to have different ratios of

sulfur per mmBtu of heat content.

5 The regions in Exhibit 1 show the breakdown used in IPM, which closely track the regions used by EIA.

4

Source: Energy Information Administration, http://www.eia.doe.gov/cneaf/coal/coal_trans/fig3.html
Exhibit 2. Coal-Producing States By Region

Region

Eastern Region States in Eastern SubRegion

Coal Mined in 1992

(1,000 short tons and

percent of total)

Sulfur Content

Maryland 3,341 (0%) Primarily High Sulfur

Ohio 30,403 (3%) Primarily High Sulfur

Pennsylvania 68,981 (7%) Primarily High Sulfur

Northern

Appalachia

Northern West Virginia 50,022 (5%) Primarily High Sulfur

Alabama 25,796 (3%) Primarily Low Sulfur

Eastern Kentucky 119,382 (12%) Primarily Low Sulfur

Tennessee 3,476 (0%) Primarily Low Sulfur

Virginia 43,024 (4%) Primarily Low Sulfur

Central and

Southern

Appalachia

Southern West Virginia 112,142 (11%) Primarily Low Sulfur

Illinois 59,857 (6%) Primarily High Sulfur

Indiana 30,466 (3%) Primarily High Sulfur

Midwest

Western Kentucky 42,686 (4%) Primarily High Sulfur

Western Region Coal Mined in 1992 Sulfur Content

Alaska 1,534 (0%) Primarily Low Sulfur

Arizona 12,512 (1%) Primarily Low Sulfur

Arkansas 58 (0%) High and Low Sulfur

Colorado 19,226 (2%) Primarily Low Sulfur

Iowa 289 (0%) Primarily High Sulfur

Kansas 363 (0%) Primarily High Sulfur

Louisiana 3,240 (0%) High and Low Sulfur

Missouri 2,886 (0%) Primarily High Sulfur

Montana 38,889 (4%) Primarily Low Sulfur

New Mexico 24,549 (2%) Primarily Low Sulfur

North Dakota 31,744 (3%) Primarily Low Sulfur

Oklahoma 1,741 (0%) Primarily High Sulfur

Texas 55,071 (6%) High and Low Sulfur

Utah 21,339 (2%) Primarily Low Sulfur

Washington 5,251 (1%) Primarily Low Sulfur

Wyoming 190,172 (19%) Primarily Low Sulfur

Source: Energy Information Administration, Coal Industry Annual, 1996. Table 1: Coal Production by State, 1987, 1992-1996, p.4. 

5
Organization of the Report

Section III of this report outlines projected

changes in coal use by utilities from a 1996 analysis and translates those demand changes into the

expected number of job slot changes in 2010.6

Section IV presents a discussion of those job slot

changes relative to national coal employment

trends, and Section V outlines limitations of the

analysis. Appendix A provides a description of

the 1996 Integrated Planning Model, which was

used for the analysis; Appendix B shows the

model projections of coal production under the

baseline and Title IV for 2000, 2005, and 2010;

Appendix C contains a comparison of results

between the 1996 analysis and the analysis created for the 1990 Clean Air Act Amendments;

Appendix D contains a comparison of results of

modeling and analysis for 2000 based on the 1996

analysis and the 1992 analysis; Appendix E presents definitions of the acronyms and abbreviations used in the report; and Appendix F summarizes the peer review process that was undertaken

for this report. 

6 IPM is a model that allows the calculation of coal and other energy input use, operating costs, emissions, and least-cost

responses to emission limits for electric generating units in the United States. Appendix A contains a detailed description of the

1996 version of the Integrated Planning Model.

6
A. Overview of Methodology

The projections of changes in labor demand as a

result of Title IV are calculated using estimates of

changes in coal use by utilities and regional mine

labor productivity projections. The change in coal

use by utilities is a model-derived output that is

generated using a series of assumptions about the

utility sector. The 1996 analysis (IPM96) was

produced as part of a series of model runs conducted by ICF in support of EPA's Clean Air

Power Initiative (CAPI) and the prospective

analysis of the effects of the Clean Air Act (CAA)

under Section 812 using a utility model called the

Integrated Planning Model (IPM).1 This study

complements an earlier work for EPA using the

same model. By comparing two of these model

runs, one with Title IV's SO2 program and one

without the SO2 program, changes in utilities' fuel

choices were projected. Productivity of miners in

2010 is estimated using EIA data and IPM-projected productivity growth rates. These inputs can

be translated into regional changes in the demand

for miners. This section describes those calculations for the 1996 IPM analysis. 

Over the past ten years, labor productivity growth

in the mining sector has greatly exceeded the historic productivity growth rate in manufacturing.

An analysis of the technology and management

practices used in existing mines indicates that

considerable opportunities still exist to improve

productivity (ICF, 1996).

EPA's productivity growth assumptions for 2010

are based on an analysis of historic productivity

by state, in union and non-union areas, and in surface and deep mines. Historic rates of improvement are projected to continue, but decline over

time toward a more typical U.S. manufacturing

labor productivity growth rate (2.5- 3.0 percent

per year). This rate of improvement is applied to

both existing and new mines (ICF, 1996).

The majority of this paper focuses on projections

of coal use and employment in 2010 from the

1996 IPM analysis. Appendix C compares the

1992 analysis completed for EPA's Regulatory

Impact Analysis (RIA) of the Acid Rain

Implementation Regulations with the 1996 IPM

analysis.

B. Changes in Coal Demand as Projected

by the IPM96 Analysis

Changes in baseline coal use in favor of low-sulfur western coal can be expected to have an

impact on coal use and coal mining employment.

The regional changes in coal demand predicted by

IPM for the year 2010 as a result of Title IV range

from a loss of 58 million tons (or about 32 percent) in northern Appalachia to a gain of 63 million tons (or almost 11 percent) in the West from

a baseline that excludes Title IV. Nationwide,

consumption is expected to drop by 2 million tons

in 2010 (which is about a fifth of one percent) as

a result of Title IV's SO2 requirements.2 Exhibit 3

presents the baseline of utility coal use and the

projected impact of Title IV on utility coal use in

the year 2010. The analysis of coal use and

III. Projections of Changes in Labor

Demand

1 Both analyses are available on the internet. EPA's Clean Air Power Initiative, Oct. 1996. Obtained from

http://www.epa.gov/capi/capifs3.html, September 1998. 

2 Because tons of coal from different mines vary in their heat content, the percentage change in the use of energy from coal is not

the same as the percentage change in tonnage used. Much of the coal produced in the West is subbituminous, which has a lower

heat content than the bituminous coal mined in the East. Thus, a shift of coal production from the East to the West would be likely

to reduce the use of coal measured on the basis of total energy content even if total tonnage did not change.

7
changes in job slot demands is conducted by

region; refer to Exhibit 2 for a breakdown of the

states in the eastern and western regions. Though

the shift to western coal in response to Title IV is

associated with a reduction in demand for coal

produced in the East, it could have a mitigating

effect on shifts in coal production within the East.

Because of its low sulfur content, each ton of

western coal that is used in place of an equivalent

amount of high-sulfur eastern coal (from northern

Appalachia or the Midwest) could eliminate the

need to shift several tons of production from highsulfur to medium-sulfur eastern coal. This issue,

and interaction between transportation cost

changes and baseline demand patterns, is discussed more fully in Appendix C. 

C. Translation of Coal Demand

into Labor Demand

As noted above, the difference in productivity between the eastern and

western coal producing regions is primarily attributable to the difference in

how the coal is mined. Given estimates of future coal production,

regional miner productivity rates are

necessary to develop projections of

mine labor demand in future years. In

1994, the year in which the base case

assumptions for the 1996 IPM analysis were developed, eastern coal miners produced an average of 3.28 tons

of coal per hour while western miners

produced 13.23 tons per hour (EIA,

2000c). Western miners also averaged more hours

of work per year -- 2,536,3 versus an average of

2,060 per year for eastern miners (EIA, 1995).4

These two factors imply that each million tons of

coal mined per year in the East required 148 miners:

1,000,000 tons /(3.28 tons/hr * 2,060 hr/yr)

or 148 miners,

while each million tons mined in the West

required only 30 miners: 

1,000,000 tons /(13.23 tons/hr * 2,536 hr/yr)

or 30 miners.5

Coal Supply Region Baseline

Utility Coal

Use

Utility

Coal Use

with Title

IV

Title IV

Impact

East (Total of Eastern

Sub-Regions)

483 418 - 65

 Northern Appalachia 180 122 - 58

 Central & Southern

Appalachia 196 228 + 32

 Midwest 107 68 - 39

West 575 638 + 63

Total US 1,058 1,056 - 2

Exhibit 3. Baseline Utility Coal Use Projections in the Year

2010 (millions of tons)

3 Hours-per-job estimates are from the Coal Industry Annual 1994, Energy Information Administration, October 1995, Table 1

(Production by region), Table 39 (Average number of miners by region), and Table 38 (Productivity). Production (tons) is first divided by the number of miners to obtain tons/worker. This result is then multiplied by hours/ton to obtain hours/worker.

4 This means that any given shift in coal production from eastern to western mines will tend to decrease the number of job slots

because of higher productivity per unit of labor in the West and because the number of hours worked by a miner in the West is

higher than the number of hours worked by a miner in the East.

5 Because of differences in heat contents among coals, a shift of a million tons from one region to another would not necessarily

leave the total energy content of the coal constant. Shifting a given amount of coal, measured in terms of its heat content, from

East to West might require an increase in the West that exceeded the reduction in the East, slightly changing the job shift estimates. In the modeling of the effects of Title IV, these differences in heat contents were accounted for. 

Source: 1996 IPM runs. Totals do not sum due to rounding. 

8
Thus, shifting output from

eastern to western coalfields

will have employment impacts,

even given constant production

volumes. For example, a shift

of 30 million tons of output

from eastern to western coalfields would require 148 * 30

or 4,400 fewer miners in the

East, and only 30 * 30 or 900

more miners in the West, for a

net reduction of 3,500 job

slots.6

Exhibit 4 shows the productivity rates that were used in the

1996 IPM analysis. 

The productivity increases for coal mining

nationwide are incorporated into the IPM analysis

using the base year 1994 and the values listed in

Exhibit 4, above. Such changes in productivity

would occur even in the absence of the Acid Rain

Program. At these rates of productivity increase,

output per hour in the East would reach 3.28 *

1.045(2000 - 1994) , or 4.27 tons per worker per

hour in the year 2000 and 6.14 in 2010, while

western output would reach 13.23 * 1.045(2000 -

1994), or 17.23 tons per hour in 2000 and 24.77

in 2010. This level of productivity represents an

87 percent increase over the productivity level in

1994 in both regions. Assuming no change in the

number of hours of work per year in each region

from the 1994 base case assumptions, these

hourly productivity projections lead to estimates

of 79 miners per million tons per year in the East,

and 16 miners per million tons per year in the

West. Using these values, the regional coal output

changes shown in the third column of Exhibit 3

can be translated into the labor requirement

changes shown in Exhibit 5. 

Employment impacts of Title IV are reported in

terms of net and gross changes. The net loss

(4,100 miner job slots) is the nationwide change

in jobs -- balancing losses in some regions with

gains in others. Gross losses (7,700 miner job

slots) are the total job slot losses in regions that

show decreases in the need for coal miners.8 As

discussed above, these projections can be seen as

indicating a fairly small decrease in net employment (of approximately 4,100 miner job slots in

2010, which is approximately eight percent of the

baseline level of 54,000). At the same time, the

figures suggest more substantial gross change in

job slots in individual regions: a total of 7,700

fewer miners (18 percent of the baseline level of

43,400 miners in these regions) would be needed

in northern Appalachia and the Midwest in the

year 2010; 3,500 more miners (34 percent of the

baseline level of 10,400 miners in these regions)

Productivity Measure East West

1994 Base Productivity 3.28 13.23

Productivity Growth Rate: 1994-1999 4.5 % 4.5 %

2000 Productivity (calculated) 4.27 17.23

Productivity Growth Rate: 2000-2004 4.0 % 4.0 %

Productivity Growth Rate: 2005-2010 3.5 % 3.5 %

2010 Productivity (calculated) 6.14 24.77

Exhibit 4. Productivity Measures used in the Analysis7 (tons per

worker per hour and percentage growth per year)

6 Thus, one job slot is the equivalent of one miner-year of work, or 2,536 hours in the West and 2,060 hours of labor in the East.

7 Actual growth rates could be sensitive to the demand shifts discussed in this report, especially if Title IV's effects on demand led

to more closures or cutbacks at the less efficient mines in each region. Differential cutbacks could increase the effects of coal

demand shifts (by increasing the number of job slots affected by each million ton shift), though this change might be offset in the

long run as higher eastern productivity led to greater competitiveness.

8 It should be noted that gross job loss within the mining industry does not fully capture all of the possible employment effects

within mining regions. As a result of multiplier effects on regional economies, additional job losses outside of the industry are also

possible.

Sources: U.S. Department of Energy, Energy Information Administration, Coal Industry

Annual 1994 and ICF analysis.

9
would be needed in central and southern

Appalachia and the West. 

Another aspect of these measures of gross job

changes that should be kept in mind is that

intraregional shifts in coal demand (i.e., within

northern Appalachia) may be even more important than the interregional shifts discussed above

(i.e., between the East and West).9 Though the

northern Appalachian region is described as producing medium-to-high sulfur coal, for example,

coals with a wide range of sulfur levels can be

found in that region. Shifting from high-sulfur

mines to low-sulfur mines within northern

Appalachia would cut average sulfur levels, and

result in gross miner labor demand reductions in

the higher sulfur mines of the region, without registering as a net change in the region's output or

miner labor demand. To some extent, these shifts

in intraregional coal shipments mean that the

measure of gross job slot changes presented in

this analysis understate the changes (both positive

and negative) in job slots that will result from

Title IV. On the other hand, job slot shifts that

occur within smaller geographical regions are not

likely to be as disruptive as those that involve

shifts in labor demand from the East to the West,

because many of the same miners might be able to

fill the job slots even after they have shifted. 

9 Coal switching within regions in Phase I of Title IV (1995-2000) was four times as important as coal switching between regions.

(Ellerman et al., 1997).

10
The preceding sections have shown that Title IV

of the Clean Air Act will reduce the overall

demand for miners in the coal industry and will

also induce regional shifts in demand for miners,

though neither of these changes is as great as had

been projected when the CAAA were enacted in

1990. They also touched on concerns over effects

of declining coal industry employment on local

economies, and the linkage between these

impacts and Title IV. 

Before concluding that Title IV is or will be a

major factor in these employment changes, however, it is important to place the projected effects

of Title IV in context. This section presents data

on the sharp decline in coal employment in the

past, along with projections of future changes in

employment expected even in the absence of Title

IV. This baseline trend is then compared to the

projected effects of Title IV itself, both for the

nation as a whole and for regions that will be

more heavily affected by Title IV due to the sulfur content of their coal resources. This comparison makes clear that it is the underlying trend

toward higher miner productivity, not the effects

of Title IV, that drives the long-term change in

mining employment.

A. Historical Employment Levels and

Trends

The level of demand for coal miners can be analyzed by looking separately at the total amount of

coal produced and miner productivity. Higher

coal production leads to increased miner demand,

while higher miner productivity (output per miner

per hour) reduces the mine labor required for a

given quantity of coal. 

From 1972 to 1990, annual coal production grew

at an average rate of between three and four percent, almost doubling in that period to just over a

billion tons in 1990. Since 1990, coal production

has changed little. Thus, in the absence of significant changes in miner productivity, demand for

coal miners would be near its peak.1 Exhibit 6

shows annual coal production between 1972 and

1995. 

Miners' productivity, however, did change dramatically over this period. After rising rapidly

and steadily from 1949 through the late 1960s,

miner productivity plunged by about a third

through the 1970s. This drop in productivity

resulted from a combination of labor unrest,

aggressive implementation of mine safety regulations, and rapid entry of less experienced firms

and miners in response to the oil shocks of the

1970s (Darmstadter, 1997). 

Productivity (in terms of the hourly average tons

of coal mined per miner) began climbing again at

IV. Demand Changes in Context

Year Annual Production

(millions of short tons)

1972 602.5

1975 654.6

1980 829.7

1985 883.6

1990 1,029.1

1995 1,033.0

Exhibit 6. Historical Trends in Annual Coal

Production

1 It should be noted that improvements in productivity have contributed to the increased use of coal over time. In the absence of

these changes in miner productivity, current levels of coal usage would be lower.

Source: Annual Energy Review.

http://www.eia.doe.gov/emeu/aer/coal.html (EIA, 2000b).

11
the end of the 1970s and grew very rapidly

through at least 1994: in contrast to the two-percent-per-year drop in miner productivity from

1970 to 1980, miner productivity rose by more

than six percent annually from 1980 through

1994. Part of this rapid gain resulted from

improvements and growing mechanization in

both surface mining (prevalent in the West) and

underground mining (common among mines in

the eastern U.S.). Labor productivity at surface

mines benefited from increases in the size of the

excavating equipment (i.e., larger equipment can

haul more coal per hour than smaller, more laborintensive equipment). At the same time, underground mining shifted towards highly mechanized "longwall" techniques in which mining

machines ate into a coal seam along a wall a thousand feet long or more, while the unsupported

roof of the mine was allowed to collapse behind

the equipment as it moved. Miners' productivity

at both underground and surface mines also benefited from the increasing use of sophisticated

computer control systems (Darmstadter, 1997). 

Another factor leading to higher average productivity among miners was the closure of some of

the smallest and least efficient mines. These

mines had been opened in response to the oil

shocks and a resulting spike in the price of coal in

the mid 1970s (EIA 1998, p. 113). When coal

prices declined, these mines were no longer profitable. 

Aggregate miner productivity was also boosted

by the rapid increase in the West's share of coal

production starting in the early 1970s. Because

miner productivity in the West is several times

that of the rest of the U.S., the nation's average

miner productivity increases as production shifts

to the West. Western coal is transported to eastern

utilities by rail. Aiding the penetration of western

coal into eastern markets, including the increased

use in the utility industry, has been a drop in rail

rates of more than a third between 1979 and 1993

(Darmstadter, 1997). Moreover, ambient air quality standards for SO2 favored low-sulfur coal

(even before the promulgation of regulations

under Title IV2). 

Through the 1970s, the combination of increasing

coal production and declining output per miner

led to rapid increases in employment.

Employment reached a peak in 1978 at about

250,000 workers. From that point, rapid increases

in productivity outstripped the rate of growth in

coal demand, and employment began to drop. By

1994, just before Title IV's SO2 program went

into effect, the number of coal workers had fallen

below 100,000, a loss of about 150,000 miner

jobs in less than 20 years. 

B. National Title IV Employment Impacts

in Context

By projecting coal demand and miner productivity into the future, it is possible to project future

changes in demand for coal miners. Under

assumptions that leave out the effects of Title IV,

modest increases are projected in coal demand by

utilities for both eastern and western coal through

at least 2010. These estimates are presented in

Appendix B, which also shows projections for

total coal demand under simplifying assumptions

that the ratio between utility demand and total

demand is constant.3 Over the same period, annual increases are projected in miner productivity of

4.5 percent until 2000, falling to 4.0 percent per

year for the next five years, and then to 3.5 percent in 2005 and thereafter (EPA, 1996).

Combining region-specific estimates of coal production for 2000, 2005, and 2010 with estimates

of labor requirements per million tons of produc2 The influence of air quality standards in existence before the Title IV regulations were promulgated may have been weakened by

the nature of the SO2 emissions rate targets, a large portion of which (perhaps over 90 percent), were non-binding. State

Implementation Plans generally are not the binding mechanisms that drive reduction in SO2 emissions and are only one way to

meet local air quality standards (Burtraw, 2000).

3 The numbers supporting these graphics are presented in Appendix B.

12
tion (calculated using projected increases in mining productivity from a 1994 baseline) yields projections of mining employment in the absence of

Title IV. These projections are shown in Exhibit

7a. Exhibit 7b provides the data points shown in

Exhibit 7a.

Exhibit 7a also shows projected coal mining

employment if the effects of Title IV are taken

into account. This projection, shown as the lightcolored bar, was calculated based on the coal output projections shown in Appendix B under the

heading "Projections Including Effects of Title

IV," and identical productivity estimates. Exhibit

7a shows clearly that,

although mining employment has fallen dramatically since its peak in the

late 1970s, and is expected to continue falling,

most of this drop has

occurred and would continue to occur independently of Title IV. This

same point is made in a

different way in Exhibit

8. Exhibit 8 compares the

cumulative loss in miners' job slots through

2010 from the 1978 peak

and from 1990 (the year

the CAAA was enacted)

to the miners' job slot

losses attributable to Title IV. As shown, the losses attributable to Title IV are small compared to

the drop in miner job slots that was already underway and continues to occur due to increases in

coal miner productivity. 

C. Employment Changes in the Regions

Most Affected by Title IV

The preceding section concentrated on the effects

of Title IV on total nationwide coal employment,

netting out the reductions in miners' job slots in

some regions with the gains in others. It is also

useful to focus specifically on the regions that are

projected to lose miner job slots as a result of Title

IV, keeping in mind that there will be offsetting

0

50

100

150

200

250

1970 1975 1980 1985 1990 1994 2000 2005 2010

Year

Thousands of Workers

With Title IV

No Title IV

Title IV

Enacted

Title IV

Implemented

(1995)

Exhibits 7a and b. Job Slot Changes in the Mining Sector: National

Coal Mining Employment With and Without Title IV

Thousands of miners

Year With Title

IV

Without

Title IV

1970 150 150

1975 175 175

1980 230 230

1985 169 169

1990 131 131

1994 984 98

2000 67 69

2005 60 63

2010 50 54

Sources: 1) Data from the U.S. Department of Energy,

Energy Information Administration, Coal Industry Annual

1994; 2) ICF analysis.

Sources: 1) Data from the U.S. Department of Energy,

Energy Information Administration, Coal Industry Annual

1994; 2) ICF analysis.

13

7a.

4 There may have been some effect on employment in 1994, even before Title IV took effect, as a result of utilities anticipating the

regulations. This possible effect was not modeled in EPA's analyses.

7b.
gains in job slots for miners in other

regions.

In addition to projected output by

region and for the entire U.S., Exhibit

3 also shows total output and output

changes in northern Appalachia and

the Midwest. Coal employment in

these two regions is expected to

decline under Title IV because of the

higher sulfur levels in their coal

resources. To put these changes in the

context of historical employment

changes in these areas, Exhibit 9a

shows total employment in these

regions with and without Title IV.

Exhibit 9b provides the data points

shown in Exhibit 9a. Though the

effects of Title IV are more evident in

Exhibit 9a than in Exhibit 7a, which

shows national mining job losses, it is

again true that most of the lost job slots came

before Title IV, and that mining employment is

expected to continue to decline in these regions

even if Title IV did not exist. Exhibit 10 displays

the cumulative loss in miners' job slots through

2010 from the 1978 peak and from 1990 (the year

the CAAA was enacted) to the miners' job slot

losses attributable to Title IV. By the year 2010,

the loss in job slots attributable to Title IV will

represent only about ten percent of the reduction

from the peak in 1978. 

0

20

40

60

80

100

120

140

160

180

200

1985 1990 1994 2000 2005 2010

Year

Thousands

Total Reductions in Job Slots, Relative to 1978

Total Reductions in Job Slots, Relative to 1990

Total Difference in Job Slots, Relative to Baseline Without Title IV

Exhibit 8. National Coal Mining Employment Losses

With and Without Title IV

Sources: ICF analysis of and data from the U.S. Department of Energy,

Energy Information Administration, Coal Industry Annual 1994.

0

20

40

60

80

100

120

1970 1975 1980 1985 1990 1994 2000 2005 2010

Year

Thousands of Workers

With Title IV

No Title IV

Title IV 

Enacted

Title IV 

Implemened

(1995)

Exhibit 9a. Coal Miners’ Job Slots With and Without Title IV in Northern Appalachia and the

Midwest

14
D. Programs to Assist Unemployed Coal

Miners

Mine and other coal industry workers facing job

losses attributable to the requirements of the

Clean Air Act are eligible for grants from the

Federal government for job training, educational,

and relocation assistance. Operating between

1992 and 1993, the Clean Air Employment and

Training Act (CAETA) was designed as a special

appropriations through the U.S. Department of

Labor to assist such workers. The program was

discontinued after 1993, but the Department of

Labor maintained the authority to provide grants

through a discretionary fund in Part B of Title III

of the Job Training Partnership Act, as amended

by the 1990 CAAA in Title XI "Clean Air

Employment Transition Assistance," (29 U.S.C.

1501).5

As of 1998, over $82 million was granted by the

Federal government between 1992 and 1996 to

coal mining companies, states, and the United

Mine Workers Union for provision of job counseling, vocational and occupational training,

needs related payments, and related services.

Workers in eastern and midwestern States

received the majority

of grants and funding,

with Illinois (12

grants, $32.5 million)

and West Virginia

(seven grants, $23.5

million), receiving the

largest share of the

assistance. The average grant served

approximately 182

workers and provided

nearly $2.4 million in

dislocated worker

services. Exhibit 11

shows, by State, the

number and value of

CAETA and Title III

grants directed to dislocated coal miners

between 1992 and

1996. 

Thousands of miners Year With Title IV Without Title IV

1970 70 70

1975 90 90

1980 105 105

1985 71 71

1990 52.3 52.3

1994 35.8 35.8

2000 28.6 34

2005 23.5 31

2010 18.1 26

0

10

20

30

40

50

60

70

80

90

100

1985 1990 1994 2000 2005 2010

Year

Thousands

Total Reductions in

Job Slots, Relative

to 1978

Total Reductions in

Job Slots, Relative

to 1990

Total Difference in

Job Slots, Relative

to Baseline

Without Title IV

Exhibit 9b. Coal Miners’ Job Slots With

and Without Title IV in Northern

Appalachia and the Midwest

Exhibit 10. Coal Miners’ Job Slot Losses With and Without Title IV in

Northern Appalachia and the Midwest

Sources: ICF analysis of and data from the U.S. Department of Energy, Energy Information

Administration, Coal Industry Annual 1994.

5 During 1992 and 1993, almost $25 million was allocated through CAETA. An additional $58 million was awarded through the discretionary Title III program. Nearly $31 million was granted through Title III in 1995.

Sources: ICF analysis of and data from the U.S. Department of

Energy, Energy Information Administration, Coal Industry

Annual 1994.

15
Location of Grantee(s) Number of Grants

Awarded

Number of Workers

Served

Total Amount of Grants

(Undiscounted)

Illinois 12 2,119 $ 32,508,695

West Virginia 7 1,258 $ 23,482,784

Indiana 1 682 $ 6,573,467

United Mine Workers Union 1 625 $ 2,000,000

Pennsylvania 1 543 $ 1,400,000

Ohio 8 495 $ 8,103,152

Kentucky 1 225 $ 5,249,890

Missouri 1 192 $ 1,000,000

Idaho 1 164 $ 485,027

Kansas 1 33 $ 900,000

Texas 1 30 $ 842,189

Total 35 6,366 $ 82,545,204

Exhibit 11. CAETA and Title III Grants: Distribution by State 1992-1996 Program Years

Source: Brian Deaton, US Department of Labor, February 27, 1998. Table titled "Projects Funded to Assist Dislocated Workers

from Clean Air Amendments Impacts." 

16
The analyses conducted for this report incorporated a fine-grained representation of the behavior of

a large number of industrial entities; it covers

both a long period of time and a wide geographical area. As with any similar attempt to project

the future in detail, it is subject to limitations and

uncertainties. Thus, several factors could lead to

cost and emission impacts above or below the

reported impacts. Those factors are shown in

Exhibit 12.1

V. Limitations of the Analysis

Limitation Potential Influence

on the Findings

This study is based on the results of two energy/economic models, IPM and CEUM, both of which

necessarily make various simplifying assumptions. For example, these models assume that utilities

act so as to minimize the total cost of producing a given quantity of electricity, setting aside other

motives such as a desire to preserve local mining jobs. The models also assume risk neutrality and

perfect foresight. This may affect job loss because, for example, utility planners might expect

higher allowance prices than are actually seen, and over-invest in scrubbers, which use higher sulfur

coal that would further limit job loss. Even with entirely correct information on the current

population of generating units, however, the difficulty of predicting changes in that population (as

well as in other factors) in the future would add uncertainty to the projections.

Decreased job loss

Pollution Control Costs and Performance - EPA used estimates of SO2 scrubber costs and

performance that reflect the current state of the art. However, technological progress stimulated by

competition could lead to improvements in the performance and cost of pollution control technology

in the future. These improvements could in turn lead to greater reliance on scrubbers relative to coal

switching, and therefore to smaller changes in coal mining employment. For this reason, the

Agency’s estimates of future job impacts could be overstated.

Decreased job loss

The analyses used for this report relied on a database that consists of information on virtually every

utility generator in the U.S. The Agency has assembled the best information on each boiler and

generator that is publicly available. Inevitably, when working with information on such a large

number of facilities, some units might not be represented correctly. Improvements to the database

could lead to changes in estimated impacts.

Mixed effects on job

loss

Though most of the attention given to the job impacts of Title IV relates to coal miners, Title IV

positively affects employment in railroads and pollution control equipment manufacturing,

installation, and operation. These secondary employment effects have not been examined in this

analysis. It is important to note instances in which environmental programs will generate new jobs

to offset jobs that are lost. The crux of the controversy over Title IV, however, appears to be

centered on the gross number of mining jobs lost in high-sulfur coal mining regions, rather than on a

measure of net jobs created. As no number of jobs created in the transportation or pollution control

industries would have an effect on the gross reductions in labor demand due to coal miner job

losses, no estimate of jobs created was produced for this report.

Decreased net job

loss

Because coal-mining regions were the geographical unit of analysis, this report did not pick up

potential shifts between states in these regions, or within individual states. This limitation probably

has little effect on estimates of the net changes in labor demand, but might have resulted in

underestimates of gross labor demand shifts.

Increased gross job

loss

To ensure consistency with related analyses, the most recent model runs used for this report were

conducted in 1996, and therefore did not use the most up-to-date projections of the growth in labor

productivity, other regulatory initiatives, or fuel prices.

Mixed effects on job

loss

Exhibit 12. Limitations of the Analysis

1 In addition to those limitations discussed, it should also be noted that this analysis does not take into consideration non-utility

use of coal, nor does it consider whether any difficulties might arise for displaced workers in finding new employment opportunities. 

17
18
VI. References

Associated Press (1999). West Virginia Coal Industry Under Pressure. January 1999.

Burtraw, Dallas (2000). Phone conversation with E. Holler, ICF Consulting. October 6, 2000.

Deaton, Brian (1998). US Department of Labor. Table titled "Projects Funded to Assist Dislocated Workers from Clean

Air Amendments Impacts," February 27, 1998.

Darmstadter, Joel (1997). Productivity Change in U.S. Coal Mining. Resources for the Future. July 1997.

Ellerman, A. Denny, Schmalensee, Richard, Joskow, Paul L., Montero, Juan Pablo, and Bailey, Elizabeth M. (1997).

Emissions Trading Under the U.S. Acid Rain Program: Evaluation of Compliance Costs and Allowance Market

Performance. MIT Center for Energy and Environmental Policy Research, Cambridge, MA, October 1997. 

Ellerman, A. Denny, Schmalensee, Richard, Joskow, Paul L., Montero, Juan Pablo, and Bailey, Elizabeth M. Markets

for Clean Air: The U.S. Acid Rain Program. New York: Cambridge University Press, 2000.

ICF Consulting (1996). Coal Supply Assumptions in the Clean Air Power Initiative. Attachment F-5-5.

Liu, Feng, and Spofford, Walter O. (1994). Air Pollution Control in China: Current Status, Policy Issues, and

Prospects. Mimeographed. Washington, D.C.: Quality of the Environment Division, Resources for the Future. August

1994.

The New York Times (1996). East's Coal Towns Wither In the Name of Cleaner Air. February 16, 1996, page A1.

U.S. Department of Energy, Energy Information Administration (EIA) (2000a), Coal Glossary.

http://www.eia.doe.gov/cneaf/coal/page/gloss.html#s 

U.S. Department of Energy, Energy Information Administration (EIA) (2000b), Annual Energy Review.

http://www.eia.doe.gov/emeu/aer/coal.html

U.S. Department of Energy, Energy Information Administration (EIA) (2000c). http://www.eia.doe.gov/cneaf/coal/cia/

p6p01.txt 

U.S. Department of Energy, Energy Information Administration (EIA) (1995). Coal Industry Annual 1994. October

1995. Table 1 (Production by region), and Table 38 (Productivity), Table 39 (Average number of miners by region) and

note to Table 39.

U.S. Department of Energy, Energy Information Administration (EIA) (1996). Coal Industry Annual, 1996. Table 1:

Coal Production by State, 1987, 1992-1996, p.4.

U.S. Department of Energy, Energy Information Administration (EIA) (1998). Impacts of the Kyoto Protocol on U.S.

Energy Markets and Economic Activity. October 1998. Table B16, p. 202. This analysis did not assume compliance

with the Kyoto Protocol.

U.S. Environmental Protection Agency, Office of Atmospheric and Indoor Air Programs, Acid Rain Division, (1992).

Regulatory Impact Analysis of the Acid Rain Implementation Regulations.

U.S. Environmental Protection Agency, Office of Air and Radiation (1996). Analyzing Electric Power Generation

Under the CAAA. July 1996, page A2-A-2.

U.S. Environmental Protection Agency, Acid Rain web site - http://www.epa.gov/airmarkets

19

This appendix discusses the use of the Integrated

Planning Model (IPM) for the analysis, including

assumptions about the baseline and about technologies for power generation and emission control. 

A.1. Analytical Overview

The actions of electricity generators under a set of

regulations were projected using IPM, which is a

detailed computer model of the electric power

industry. IPM is designed to find the most efficient (that is, the least-cost) way to satisfy the

demand for electricity under a series of limitations or constraints. The constraints under which

IPM "produces" electricity can include a limit on

tons of SO2 emissions, and it is by setting this

constraint that the effects of Title IV can be modeled. Running IPM without a limit on tons of SO2

emissions produces a picture of the baseline situation in which the Title IV is not in effect. A rerun

of the IPM after adding a constraint that limits

SO2 emissions to a specified number of tons

shows what the industry would do to comply with

Title IV while keeping its costs as low as possible.

More detail on how IPM operates is provided

below and in Analyzing Electric Power

Generation Under the CAAA, Office of Air and

Radiation, U.S. Environmental Protection

Agency, July 1996 (www.epa.gov/capi/IPM/

update.htm). 

IPM is an optimization model that uses a linear

programming formulation to select investment

options and to dispatch generating and load management resources to meet overall electricity

demand and energy requirements. The model

selects the investment options based on the cost

and performance characteristics of the available

options, forecasts of customer demands for electricity, and reliability criteria. System dispatch,

which involves the determination of proper and

most efficient use of the existing and new

resources available to utilities and their customers, is determined using the resource mix, unit

operating characteristics, and fuel and other costs.

Unit and system operating constraints provide the

system-specific reality to the model's simulations.

The model has the capability of using forecasts of

conditions, requirements, and option characteristics to make present decisions and is thus termed

as dynamic. The model tries to represent the perspective of utility managers, regulatory personnel, and the investing public in reviewing important financial options for the utility industry and

electricity consumers. The model's objective is to

minimize the discounted sum of capital and operating costs over the full planning horizon. 

IPM has been used for over ten years by electric

utilities, trade associations, and government agencies both in the U.S. and abroad to address a wide

range of electric power market issues. The applications have included capacity planning, environmental policy and compliance planning, wholesale price forecasting, and asset valuation. EPA

has used IPM extensively for environmental policy and regulatory analysis. In particular, EPA has

used IPM to analyze NOx emission policy and

regulations as part of the Clean Air Power

Initiative (CAPI) in 1996 and as a tool to analyze

alternative trading and banking programs during

the OTAG process in 1996 and 1997. 

IPM has undergone extensive review and validation over this ten-year period. In April 1996, EPA

requested participants in the CAPI process to

comment on the Agency's new approach to forecasting electric power generation and selected air

emissions. EPA received many helpful comments

and made a series of changes in its methodology

and assumptions based on CAPI participants' recAppendix A: Description of the 1996

Integrated Planning Model

A-1
ommendations. Recently, IPM and EPA's modeling assumptions were reviewed as part of the

OTAG process. Again, changes were made to the

methodology and assumptions to accommodate

participants' recommendations.

The version of IPM used by EPA represents the

U.S. electric power market in 21 regions, as

depicted in Exhibit A-1. These regions correspond in most cases to the regions and subregions used by the North American Electric

Reliability Council (NERC). IPM models the

electric demand, generation, transmission, and

distribution within each region as well as the

transmission grid that connects the regions. 

The model includes existing utility power plants

as well as independent power producers and

cogeneration facilities that sell firm capacity into

the wholesale market. Data on the existing boiler

and generator population, which consists of close

to 8,000 records, are maintained in EPA's

National Electric Energy Data System (NEEDS).

In order to make the modeling more time and cost

efficient, the individual boiler and generator data

are aggregated into "model" plants. EPA's application of the model has focused heavily on understanding the future operations of coal-fired units,

which will have the greatest air emissions among

the fossil-fired units. The operation of other types

of non-fossil fuel-fired generation capacity,

including nuclear and renewables, are also simulated but at a higher degree of aggregation. 

Working with these existing model plants and

representations of alternative new power plant

options, IPM determines the least-cost means for

supplying electric demand while limiting air

emissions to remain below specified policy limits.

Multiple air emissions policies can be modeled

simultaneously. For example, IPM is used in this

study to simulate compliance with existing

CAAA Title IV SO2 emission requirements.

While determining the least-cost solution, IPM

also determines the optimal compliance strategy

for each model plant. 

A wide range of compliance options are evaluated, including the following:

! Fuel Switching - For example, switching

Exhibit A-1. Integrated Planning Model Regions in the Configuration Used by EPA

Source: ICF Consulting.

A-2
from high sulfur coal to low sulfur coal.

! Repowering - For example, repowering an

existing coal plant to a gas combined-cycle

plant.

! Pollution Control Retrofit - For example,

installing selective catalytic reduction (SCR),

selective non-catalytic reduction (SNCR), or

gas reburn (to reduce NOx emissions), or

flue gas desulfurization (to control SO2 emissions).

! Economic Retirement - For example, retiring

an oil or gas steam plant.

! Dispatch Adjustments - For example, running

high NOx cyclone units less often, and low

NOx combined-cycle plants more often.

IPM provides estimates of air emission changes,

incremental electric power system costs, changes

in fuel use, and other impacts for each air pollution policy analyzed.

The model is not limited in scope to facilities

owned by electric utilities, but also includes independent power producers (IPP) that provide electricity to the power grid on a firm-contract basis,

as well as IPP facilities larger than 25 MW that

provide power on a non-firm basis. 

IPM simultaneously models over an extended

time period, and reports results for selected years.

These analyses provide results for 2000, 2005,

and 2010.

In applying IPM to analyze EPA emission policy,

EPA has developed a set of data and assumptions

that reflect the best available information on the

electric market and operating factors. The relevant data and assumptions can be grouped into the

following categories:

!"Macro Energy and Economic Assumptions -

These assumptions are related primarily to

electricity demand projections, fuel prices,

power plant availability, capacity factors,

lifetimes, and heat rates. Heat rate data on

individual coal plants are used in constructing the model plants. Also included in this

category are discount rate and year dollar

assumptions. 

! Electric Technology Cost and Performance -

These assumptions are related to electric technology cost and performance for existing and

new plants, as well as for existing plant refurbishment and repowering.

! Pollution Control Performance and Costs -

These assumptions primarily cover the performance and unit costs of pollution control

technologies for NOx and SO2.

Each of these sets of data and assumptions are

briefly discussed below. More detail can be found

in EPA's report entitled "Analyzing Electric

Power Generation under the CAAA."

A.1.1 Macro Energy and Economic

Assumptions

EPA made assumptions about major macro energy and economic factors, as shown in Exhibit A2. See Appendix No. 2 of EPA's report

"Analyzing Electric Power Generation under the

CAAA" for details on most of the macro energy

and economic factors. 

A.1.2. Electric Energy Cost and Performance

Assumptions

In order to simulate the electric power market

under base case conditions, assumptions were

made on the cost and performance of new power

plants as well as for repowering existing power

plants. These characterizations of new power

plant costs and performances were used in IPM to

determine the least cost means for meeting projected future electricity requirements subject to

the base case emission restrictions and the SO2

emission limits specified for the analysis. 

A-3
Factor Assumption Source/Comments

Discount Rate 6 percent ICF estimate

Electricity Demand Growth Rate

(% per Year)

1993-2000 = 1.8%

2001-2010 = 1.7%

After 2010 = 1.3%

NERC and DRI estimates

Power Plant Lifetimes Fossil Steam = 65 years if ≥ 50 MW

 = 45 years if < 50 MW

Nuclear = 40 year license length

ICF estimate

U.S. Nuclear Capacity (GW) 1993 = 99 GW

2000 = 97 GW

2005 = 94 GW

2010 = 90 GW

2020 = 48 GW

ICF estimate based on

current utility plan and

assumed plant shutdowns;

No new nuclear construction

assumed

Nuclear Capacity Factors (%) 2000 = 75%

2005 = 74%

2010 = 73%

2020 = 74%

EIA estimate

U.S. Imported Crude Oil Prices

(1995 $/BBL)

2000 = $20

2005 = $22

2010 = $24

2020 = $28

1996 EIA estimate, post

2010 extrapolation

Wellhead Natural Gas Price

(1995$ per MMBtu) 2000 = $1.80

2005 = $1.92

2010 = $1.92

Model forecast of future gas

prices in the Base Case

Fossil Steam Plant Availability (%) 1994 = 80%

2000 = 82%

2005/10/20 = 85%

ICF estimate based on

historic trends

Coal Mining Productivity Increases

(% per year) 1995-1999 = 4.5%

2000-2004 = 4.0%

2005-2009 = 3.5%

2010-2014 = 3.0%

2015-2025 = 2.5%

ICF estimate based on long

run trends

Coal Transportation Rates

(% change/year 2001-2010) Current rail, truck, and barge costs,

declining 2% per year

ICF estimate using unit cost

information and FERC form

423 delivery data and long

run trends

Exhibit A-2. Key Baseline Assumptions for Electricity Generation

Sources: As noted in the right-hand column.

A-4
Power plant cost and performance assumptions

were developed for the following new conventional and unconventional power plant types:

New Conventional Power Plants

! Conventional Pulverized Coal

! Advanced Coal (Integrated Gasification

Combined Cycle - IGCC)

! Combined Cycle

! Combustion Turbine

New Renewable/Nontraditional Options

! Biomass IGCC

! Solar Photovoltaics

! Solar Thermal

! Geothermal

! Wind

In order to capture changes in technology over

time, cost and performance projections were

developed for 2000, 2005, and 2010. In general,

the year 2000 estimates reflect current technology, the 2010 estimates reflect advancements in

costs and performance, and the 2005 estimates

represent midpoints between these values. The

approach was adopted from work that the Energy

Information Administration (EIA) did in support

of the 1995 and 1996 Annual Energy Outlooks

(AEO95 and AEO96). EIA had its approach peerreviewed during its development.

In addition to the AEO, key data sources used to

develop the cost and performance assumptions

are as follows:

EPRI, TAG Technical Assessment Guide,

Electricity Supply - 1993, EPRI TR-102276-

V1R7, June 1993; 

SERI, The Potential of Renewable Energy: An

Interlaboratory White Paper, SERI/TP-260-3674,

March 1990; and

TVA, Integrated Resource Plan Environmental

Impact Statement, Volume Two, 

Technical Documents, July 1995. 

In addition to these assumptions on new power

plants, EPA also developed assumptions on the

cost and performance of repowering existing

power plants. The following three types of repowering options were considered:

! Repowering Coal Steam to Integrated

Gasification Combined-Cycle

! Repowering Coal Steam to Gas CombinedCycle

! Repowering Oil/Gas Steam to Gas

Combined-Cycle

The key sources of data for this section are the

repowering studies conducted by Bechtel

Corporation and the TVA Integrated Resource

Plan EIS. 

For more details on the assumptions made about

the cost and performance of new power plants and

repowering of existing power plants, see

Appendix No. 3 of EPA's report, "Analyzing

Electric Power Generation under the CAAA."

A.1.3. Pollution Control Performance and

Cost Assumptions

Exhibit A-3 contains the scrubber cost assumptions used in the model. These assumptions were

developed from a review of Phase I experience in

the 1989 base case and 1992 SO2 RIA, updated

for 1995 dollars and to reflect a 95 percent SO2

removal rate (consistent with actual planned performance for announced Phase I scrubbers).

Actual costs will need to be adjusted upwards to

Exhibit A-3. Scrubber Cost Assumptions

(1995$, excludes retrofit factor) (Based on estimates for medium sulfur coal (2%S))

Capital ($/kW) 172

Fixed O&M ($/kW/yr) 6.2

Variable O&M (mills/kWh) 1.0

Capacity Penalty (%) 2.1%

Energy Penalty (%) 2.1%

% Removal 95%

Source: U.S. Environmental Protection Agency (July 1996),

Office of Air and Radiation, Analyzing Electric Power

Generation Under the CAAA.

A-5
A.2 References 

Bechtel Power Corporation (February 1996), Cost Estimates for NOx Control Technologies Final Report.

Bechtel Power Corporation (June 1996), Draft technical study on the use of gas reburn to control NOx at coal-fired

electric generating units. 

Electric Power Research Institute (June 1993), TAG Technical Assessment Guide, Electricity Supply - 1993, EPRI TR102276-V1R7.

SERI (March 1990), The Potential of Renewable Energy: An Interlaboratory White Paper, SERI/TP-260-3674.

Tennessee Valley Authority (July 1995), Integrated Resource Plan Environmental Impact Statement, Volume Two,

Technical Documents.

U.S. Environmental Protection Agency (July 1996), Office of Air and Radiation, Analyzing Electric Power Generation

Under the CAAA. For more about the Clean Air Act Amendments, visit the Clean Air Power Initiative (CAPI) main

page at http://www.epa.gov/capi/capi.html.

account for the difficulty of the retrofit. This

report assumes a retrofit factor of 1.1 for large

power plants. For plants with installations below

500 MW, these factors should be scaled by

(500/x)0.6, where x is the MW size of the power

plant. 

For more details on the assumptions made about

pollution control cost and performance see

Appendix No. 5 of EPA's report, Analyzing

Electric Power Generation under the CAAA.

A-6
This appendix presents the projections of coal

production by region made in the course of modeling the effects of Title IV. Under assumptions

that do not include Title IV, only modest increases were projected in coal demand by utilities for

both eastern and western coal through at least

2010. These estimates are presented in Exhibit B1, which also shows projections for total coal

demand under simplifying assumptions that the

ratio between utility demand and total demand is

constant. Exhibit B-2 shows the change in

demand for coal from 1994 to 2000, 2005, and

2010. These demand estimates, along with projections of miner productivity, were used to project future changes in demand for coal miners.

Appendix B: Coal Use Projections With and

Without Title IV

Baseline Demand Projections Projections Including Effects

of Title IV

Demand by

Utilities

Estimated Total

Demand

Demand by

Utilities

Estimated Total

Demand

Year 2000 2000 2000 2000

Region

Northern Appalachia 170 194 139 159

Central & Southern Appalachia 164 187 188 214

Midwest 94 108 76 86

West 525 598 549 625

Total 953 1,086 952 1,084

Northern Appalachia + Midwest 265 301 215 245

Year 2005 2005 2005 2005

Region

Northern Appalachia 183 208 133 152

Central & Southern Appalachia 180 205 212 242

Midwest 96 109 70 80

West 569 648 612 696

Total 1,028 1,171 1028 1,170

Northern Appalachia + Midwest 279 318 204 232

Year 2010 2010 2010 2010

Region

Northern Appalachia 180 205 122 138

Central & Southern Appalachia 196 223 228 260

Midwest 107 122 68 78

West 574 654 637 725

Total 1,058 1,205 1055 1,202

Northern Appalachia + Midwest 287 327 190 216

Source: IPM 1996 runs.

Exhibit B-1. Coal Use by Utilities and Total Production With and Without Title IV (millions of tons per

year)

B-1
Exhibit B-2. Coal Use Changes Due to Title IV

Change

(in millions of tons)

Percent Change

Demand by

Utilities

Estimated Total

Demand

Demand by

Utilities

Change in Utility

Demand Due to

Title IV

Year 2000 2000 2000 2000

Region

Northern Appalachia -31 -35 -18.2% -18.0%

Central & Southern Appalachia 24 27 14.6% 14.4%

Midwest -18 -22 -19.1% -20.4%

West 24 27 4.6% 4.5%

Total -1 -2 -0.1% -0.2%

Northern Appalachia + Midwest -50 -56 -18.9% -18.6%

Year 2005 2005 2005 2005

Region

Northern Appalachia -50 -56 -27.3% -26.9%

Central & Southern Appalachia 32 37 17.8% 18.0%

Midwest -26 -29 -27.1% -26.6%

West 43 48 7.6% 7.4%

Total 0 -1 0.0% -0.1%

Northern Appalachia + Midwest -75 -86 -26.9% -27.0%

Year 2010 2010 2010 2010

Region

Northern Appalachia -58 -67 -32.2% -32.7%

Central & Southern Appalachia 32 37 16.3% 16.6%

Midwest -39 -44 -36.4% -36.1%

West 63 71 11.0% 10.9%

Total -3 -3 -0.3% -0.2%

Northern Appalachia + Midwest -97 -111 -33.8% -33.9%

Source: IPM 1996 runs 

B-2
Several analyses have been conducted over the

years bearing on the magnitude of the Title IVinduced shifts in coal and labor demand. Changes

in the models and assumptions used to conduct

these analyses have raised the issue of whether

the earlier conclusions about labor market

impacts have changed as well. This appendix discusses the changes in assumptions, and compares

the projected coal and labor demand impacts of

Title IV in the context of these changes. The

assessment is complicated by several circumstances: many different analyses of the impacts of

Title IV have been conducted; there are multiple

factors affecting job impacts; projection timeframes differ from study to study; there are gaps

in the data that are required to make consistent

comparisons; and there are different ways to

interpret the same results. Still, it is possible to

infer that the more recent analyses take changes in

the industry into account, and are thereby correct

in predicting lower overall labor demand impacts. 

This appendix is divided into four sections, covering the following: the analyses that are compared; industry changes since the 1992 analysis;

differences in impacts on coal demand; and differences in impacts on labor demand.

C.1. Analyses Considered

This document examines comparisons of the

impact in the year 2010 (and, to a lesser extent,

2000) of Title IV from two studies: ICF's analysis

for the EPA's Regulatory Impact Analysis (RIA)

of the Acid Rain Implementation Regulations;

and ICF's Integrated Planning Model (IPM) runs

for the Clean Air Power Initiative (CAPI) and

Section 812 Prospective analyses (which are the

focus of the body of this report). The analysis for

the RIA was conducted in 1991 using the Coal

and Electric Utilities Model (CEUM), with baseline assumptions prepared in 1989. Outputs of the

model that are available include coal output by

region with and without the SO2 program, under

two baseline scenarios: a low emissions growth

case, and a high emissions growth case. As discussed in the body of this report, the

CAPI/Section 812 analyses were conducted in

1996 using an improved and updated utility

model called IPM. Available outputs include utility coal use by region, with and without the Title

IV SO2 program; the runs use a single set of baseline assumptions dating from 1996.1

Three related studies were examined, but the

detailed comparisons made between the 1992 and

1996 studies were not also done for these studies.

These related studies include the following: ICF's

1990 analysis of proposed acid rain programs,

using CEUM and 1989 base case assumptions

(which was a precursor to the 1992 ICF analysis

used for the RIA); ICF's 1995 analysis of the Title

IV SO2 program using CEUM and 1993 base case

assumptions; and a recent study conducted at MIT

of the actual effects of Phase I of the SO2 program

against a backdrop of changes prior to the program's effective date. The 1990 analysis is important in that it explicitly calculated and presented

coal industry employment changes associated

with changes in coal supply. The regulatory

regimes that it analyzed—competing Senate and

House acid rain proposals—were similar to the

final proposals analyzed in 1991 and presented in

the 1992 Regulatory Impact Analysis. The 1995

Appendix C: Differences Between

1990/1992 and 1996 Analyses

1 Though the 1998 version of IPM was run for the SIP call analysis (see http://www.epa.gov/ttn/rto/sip), those results were not

used in this report because a no-Title IV case was not run using 1998 data. A comparison of the job slot impacts of Title IV

requires a comparison of the model results with and without Title IV.

C-1
ICF analysis differed in that it used a single set of

base case assumptions, which were closer to the

"low" 1989 base case, and recognized the possibility of using subbituminous western coal from

the Powder River Basin in eastern boilers

designed to use bituminous coal. The MIT analysis employed a questionnaire, interviews with

power plant operators, data on allowance prices,

and actual use of coal and scrubbers in complying

with Phase I of the Title IV SO2 program. The

review of actual data in the MIT analysis was

used to estimate the actual cost of the program

and help explain the utilities' responses to the program. These three analyses are referred to in the

text for illustrative purposes. 

C.2. Industry Changes Since the 1992 RIA 

Of the numerous changes in the coal and electric

utility industries that have occurred since the

1992 analysis was conducted, three are of particular importance to the question of employment

impacts.2 These three changes—coal mining productivity projections, the suitability of subbituminous coal for eastern boilers, and shipping cost

reductions—are discussed in turn in the following

sections. 

Coal mining productivity. The trend toward

improved coal-mine productivity appeared much

stronger by 1996 than had been assumed in the

analyses of the late 1980s and early 1990s.

Exhibit C-1 compares the productivity growth

rates that were used in the 1992 and 1996 analyses. 

Labor productivity growth in the mining sector

has greatly exceeded the historic productivity

growth rate in manufacturing over the last ten

years. An analysis of the technology and management practices used in existing mines indicates

that considerable opportunities still exist to

improve productivity.

EPA's future productivity growth assumptions are

based on an analysis of historic productivity by

state, in union and non-union areas, and in surface

and deep mines. The historic rates of improvement are then projected to continue, but to decline

toward a more typical U.S. manufacturing labor

productivity growth rate (2.5 - 3.0 percent per

year) over time. This rate of improvement is

applied to both existing and new mines.

A review of 1985-94 average labor productivity

growth in each region indicates that growth has

been about 5.6 percent per year (SAB, 1997).

Furthermore, this rate seems to be similar in all

parts of the country, regardless of union membership or mine type. Rates vary from one year to the

next, but, overall, no significant differences can

be identified by mine type or union affiliation in

the last ten years. Although the 1993 coal strike

has affected the trend, the rate of improvement

has been declining over time.

Exhibit C-1 shows that the hourly output that

would have been predicted in the 1992 analysis

for the year 2010 was considerably lower than in

the 1996 analysis. The more recent projections,

used in the 1996 analysis, set the rate of productivity growth for the years 1996 through 2000 at

4.5 percent per year, dropping to 4.0 percent and

then 3.5 percent over the next ten years. This rate

translates into substantially higher projected productivity for the year 2010. This gain in projected

labor productivity might appear to favor western

coal producers, whose projected output per worker has risen more than the output per worker at

eastern mines (i.e., an increase from 2.0 percent in

the 1992 analysis, to between 3.5 and 4.5 percent,

instead of the smaller increase from 3.0 percent to

between 3.5 and 4.5 percent for the East).

Because labor is a much larger component of the

cost of eastern coal than western coal, however,

the unexpectedly large improvements in eastern

productivity are actually more significant economically than the even larger percentage gains in

western productivity. Thus, labor productivity

2 An additional change resulting from restructuring since 1998 is that plants have changed from being EIA classified as traditional

utilities to non-utilities. Because this analysis uses data from 1996, this issue does not affect the outcomes.

C-2
improvements might have tended to shift utilities

toward the use of eastern coal to some degree. 

Substitutability of Coal. A second important

change in assumptions is the recognition that subbituminous coal from the Powder River Basin in

the West can be used in eastern boilers that were

designed for bituminous coal. The ability to substitute Powder River Basin coal is important for

two reasons: it is less expensive to mine than the

eastern coal it can replace, and it is generally

much lower in sulfur than eastern coal. Thus, it is

potentially a very attractive fuel source both for

economic reasons and for compliance with regulations requiring lower SO2 emissions. In early

analyses of the effects of Title IV, coal from the

western Powder River Basin had been assumed to

play a minor role in utilities' compliance strategies because of questions about the costs of transporting it to the East, and about its suitability for

boilers designed for higher-heating-value/lower

ash bituminous coal. The 1990 and 1992 analyses

assumed that eastern bituminous boilers would

not switch to western subbituminous coal, though

the text mentioned that this kind of switch was

potentially important. By 1993, the possibility of

this type of coal switching was well established,

though it was assumed

that it would involve a

significant capital cost

(ICF, 1993). Coal purchasing patterns show

the growth in the number of power plants that

are switching to subbituminous coal, which

primarily comes from

western regions. For

example, during a peak

electricity usage month

in 1999, approximately

136 of 244 coal burning

power plants east of the

Mississippi River, or 58

percent of the plants,

purchased subbituminous coal. This compares with 110 of 263

plants, or 42 percent of

plants, during the same month in 1993 (EIA, 1993

and 1999). The effects of this change in assumptions can be seen in the 1995 analyses of the

effects of Title IV, which showed a significantly

larger shift toward western coal at the expense of

lower-sulfur central and southern Appalachian

coal (ICF, 1995). 

Assumptions about Transportation Costs. A

third change over the past six years has been a

very significant drop in the per-mile costs of shipping coal by rail. This decrease is attributed to

several factors. Railroads were able to reduce

costs in part because deregulation of the industry

in 1980 allowed the industry to restructure itself

by abandoning unprofitable lines and merging

with other companies. Costs were further reduced

through work force and equipment downsizing.

Some of these cost savings were eventually

passed on to customers. Utilities were also able to

secure lower rates by increasing use of leased or

utility-owned rail-cars, rather than railroadowned cars. 

While the cost to ship coal between the various

supply-and-demand-regions fell overall, the differences were not always uniform. For example,

1992 Analysis 1996 Analysis

Productivity Measure East West East West

1989 Productivity (calculated) 2.50 10.07 NA NA

1994 Base Productivity 3.28 13.23 3.28 13.23

2000 Productivity (calculated) 3.46 12.52 4.27 17.23

2010 Productivity (calculated) 4.65 15.27 6.14 24.77

Growth Rate to back calculate

1994 Rate to 1989 Rate for 1992

Analysis

5.6 % 5.6 % NA NA

Growth Rate: 1994-1999 3 % 2 % 4.5 % 4.5 %

Growth Rate: 2000-2004 3 % 2 % 4.0 % 4.0 %

Growth Rate: 2005-2010 3 % 2 % 3.5 % 3.5 %

Exhibit C-1. Comparison of Productivity Measures used in the 1992

and 1996 Analyses (tons per worker per hour and percentage growth per year)

Source: ICF analysis.

C-3
between 1988 and 1993, the cost to ship a ton of

coal from western supply regions to the east

North Central region declined by 40 percent on

average. At the same time, the rail costs to ship a

ton of coal from eastern supply regions to the east

North Central region declined only by about 25 to

30 percent. Because of this difference in the rates

of cost decline, and the great distance from the

western coal fields to the East, the cost to ship a

ton of low-sulfur western coals to eastern markets

has decreased relatively more than the cost to ship

eastern coals to the eastern markets (EIA, 1995).

This relative change in transportation costs has

apparently outweighed, by a considerable degree,

the advantages of increased labor productivity in

the East, leaving a substantial net incentive to use

western coals.

The effects of this increased cost-effectiveness

are illustrated in Exhibit C-2. The diagram is a

schematic picture of the interplay of mining and

transportation costs in determining the relative

sales of western and eastern coals. Costs are

shown vertically, while space is shown horizontally. Western coal costs considerably less to

mine, so point A (showing the cost of the western

coal with no transportation cost) is lower than

point B. Not all customers would necessary find

western coal less expensive, however, because

shipping it eastward is costly: each additional

mile that it must be shipped toward the East raises its delivered cost, as shown by the line sloping

upward to the right. (The slope of the line is related to the cost of shipping in cents per ton-mile.)

Eastern coal must also be shipped if it is to compete for the business of coal users between the

West East Cost of Western Coal at Minemouth Cost of Eastern

Coal at Minemouth

Delivered Price of Western Coal,

High Rail Rates

Delivered Price of Eastern Coal,

High Rail Rates

Geographical Range Over Which Western Coal’s

Delivered Price is Lower than Eastern Coal’s

Geographical Range Over Which

Eastern Coal’s Delivered Price is

Lower than Western Coal’s

A

B

C

Exhibit C-2. Schematic Explanation of Effects of Rail Transportation Rates on Coal Competition

C-4

Source: ICF analysis.
eastern and western coal-fields: the delivered cost

of eastern coal is represented by the line sloping

upward to the left.

At a certain point, the delivered costs of the two

coals are equal (shown as point C). There, the

delivered cost of the western coal at that point

will be mostly transportation cost, while the

delivered cost of the eastern coal will be more

heavily based on mining cost. For all points east

of this dividing line, eastern coal will have an

economic advantage; for all points to the west,

western coal will be less expensive.

A decline in the per-mile cost of transportation

can be shown on the diagram as a flattening of the

delivered-cost lines, as shown in Exhibit C-3: at a

lower cost per ton-mile, each incremental distance adds less to the delivered cost than at the

higher cost. As a result, the delivered-cost lines

cross at a point further to the right (i.e., further to

the East), and the dividing line between the area

served by western and eastern coal regions moves

as well. These diagrams illustrate the concept

that, as the transportation costs hampering the

spread of inexpensive western coal come down,

the area of the country in which it is economically competitive expands.

The net increase in the attractiveness of using

western coal, described above, would exist even

in the absence of Title IV. In other words, coal

users in the Midwest and East would find western

coal relatively more cost-effective even if its

lower sulfur content were of no importance.

Therefore, part of the reduction in SO2 emissions

West East Cost of Western Coal at Minemouth Cost of asternCoal

at Minemouth

Geographical Range Over Which Western Coal’s

Delivered Price is Lower, at High Rail Rates

Wider Geographical Range Over Which Western

Coal’s Delivered Price is Lower, at Low Rail Rates

Reduction in Rail Rates

Means Delivered Costs Rise

Less with Distance

Reduction in Rail Rates

Means Delivered Costs Rise

Less with Distance

A

B

C

C’

Source: ICF analysis

Exhibit C-3. Schematic Explanation of Effects of Rail Transportation Rates on Coal Competition

C-5
required by Title IV would already be accomplished in the baseline.3 Because Title IV's limits

are specified in terms of a nationwide cap on

emissions, the shift toward low-sulfur western

coal in the baseline means that less incremental

SO2 reduction will be needed to meet the Title IV

requirements. The MIT study of Phase I compliance strategies suggests that the shift to western

coal for economic reasons cut baseline SO2 emissions by 425,000 tons annually—a reduction that

accounted for more than ten percent of the total

emissions reductions under Phase I (Ellerman et

al., 1997).

C.3. Comparisons of Coal Demand Projections 

The baseline shift in coal use discussed above

appears to have been captured by ICF's IPM

model. This tentative conclusion is based on the

fact that the baseline results from 1996 show a

relative increase in the use of western coal and a

drop in eastern coal use, compared to the 1992

results. Because of differences between IPM and

the earlier CEUM, though, this conclusion is not

certain. This section presents and discusses these

results and the reason for the uncertainty in the

conclusion. 

Exhibit C-4 compares two different coal projections in the absence of Title IV: the 1992 RIA's

projection of total coal production, and the 1996

analyses' projection of coal use by utilities.

4

Because these two projections differ (by the

amount of coal exported or used by industry), it is

not possible to show conclusively how projections of utility coal use differ between the 1992

and 1996 analyses. The sizes and directions of the

differences between the two projections for eastern coals versus western coals, however, strongly

suggest that the more recent analysis projects

more western coal use by utilities. 

As seen in Exhibit C-4, ICF's more recent analysis projects utility use of eastern coal in both 2000

and 2010 to be considerably below earlier projections of eastern coal production. These differences do not necessarily mean that projected utility use of eastern coal fell between 1992 and

1996, because the differences shown in the table

could be explained by the quantity of coal taken

by industry and exporters. The 1996 projection of

utility use of western coal, however, is now higher than the 1992 projection of western coal production for the year 2000. Because utility use of

western coal is only one component of total production, it must be true that the year 2000 projection of utility use of western coal was higher in

1996 than in 1992. A similar pattern is seen for

the year 2010: the difference between 1992 and

1996 projections for western coal is much smaller than for eastern coal. The differences between

the 1992 and 1996 projections for both 2000 and

2010 are easily explained by a shift from eastern

to western coal by utilities. Nevertheless, it is true

that these patterns could also have resulted from

other shifts (e.g., changes in total utility demand

and/or changes in exports or industrial use). 

Exhibit C-5 compares Title IV's projected impacts

on coal use for the year 2010 for the 1992 and

1996 analyses. The 1996 analysis predicts greater

shifts between eastern and western coal than the

1992 analysis, and a much smaller shift from

high-sulfur Midwestern coal to low-sulfur central

C-6

3 It may well be that some of the changes in technology that induced the shift in favor of using more western coal were actually

induced by the existence of Title IV and the development of the Acid Rain Program. For example, the prospect of a need for substantial cuts in utility SO2 emissions could have given utilities an added incentive to develop ways to use low-cost, low-sulfur subbituminous coal in boilers originally designed for bituminous coal. To the extent that this is the case, the baseline discussed here

would not be a true non-Title IV baseline, and the effects of Title IV presented in this report would be understated compared to

their true values. No attempt was made to determine the extent to which the changes favoring the use of subbituminous coal were

endogenous in this way, though if the attempt had been made, the results of the analysis might fall somewhere between those

shown for the 1992 analysis and 1996 analysis.

4 Projections for the year 2000 are included in the table because their implications for baseline coal use are less ambiguous than

are the projections for 2010.
and southern Appalachian coal was projected in

1996 than in 1992. 

A greater projected shift toward the West in the

1996 analysis might seem counterintuitive, given

the expectation that more recent projections

should take into account the greater baseline penetration of western coal due to lower rail rates and

expanded opportunities for using subbituminous

coal in the East. By reducing baseline sulfur emissions, this shift should reduce the need for further

coal switching, and might have been expected to

reduce net job slot losses. 

From another perspective, however, the changes

that led to a baseline increase in the use of western coal would also make it a more attractive

option for the additional reductions in SO2 emissions that will be needed in Phase II. Because the

baseline shifts toward the use of low-sulfur western coal for economic reasons did not meet the

goals of Title IV's Phase II program by themselves, there will still be a need for incremental

sulfur reductions. The impacts of these incremental reductions will depend on the choices made by

power plant operators from among their compliance options. If western coal is less expensive to

Exhibit C-5. Comparison of Projected Effects of Title IV on Coal Use in the Year 2010 (millions of

tons per year)

Coal Producing Region 1992 RIA

Analysis, High

Base Case

1996 Analysis Difference (1996

Analysis minus

1992 RIA)

East - 35 - 65 -30

 Northern Appalachia - 41 - 58 -17

 Central & Southern Appalachia 135 32 -103

 Midwest - 129 - 39 90

West 38 63 25

Total 3 - 2 -5

Source: 1992 SO2 RIA, Appendix 4b, 1996 IPM runs. Totals do not add due to rounding.

C-7

Source: ICF analysis. Totals do not add due to rounding.

2000 2010

Coal Supply Region 1992 RIA

(total

production;

high base

case)

1996

Analysis

(use by

utilities)

Difference

(1996

analysis

minus 1992

RIA)

1992 RIA

(total

production;

high base

case)

1996

Analysis

(use by

utilities)

Difference

(1996 analysis

minus 1992

RIA)

East 648 428 - 220 955 483 -472

 Northern Appalachia 197 170 - 27 290 180 -110

 Central & Southern

Appalachia 302 164 - 138 359 196 -163

 Midwest 149 94 - 55 306 107 -199

West 491 524 33 675 575 -100

Total 1,138 952 - 186 1,630 1,058 -572

Exhibit C-4. Baseline Coal Industry Output and Use Projections in the Years 2000 and 2010 (millions

of tons per year)
ship than before and still has a substantial cost

advantage, it might still be the best compliance

choice for a large segment of the industry.5 Thus,

it would not be surprising to see greater shifts in

job slots from eastern to western coal producing

regions in a model in which western coal is more

accessible. The only question would be whether

the baseline shift to the West was large enough to

preempt the need for further shifts in response to

regulations.

This question can be addressed using the analytical framework presented in Exhibits C-2 and C-3.

Exhibit C-6 shows the combined effects of (1) the

need to purchase allowances on the cost of using

high sulfur coal, and (2) the reduction in transportation costs in the baseline. The need to purchase additional allowances for every additional

ton of high-sulfur coal is illustrated by the upward

shift in the costs for the eastern coal. Minemouth

cost B shifts upward to B" to show the true cost of

using a ton of high-sulfur coal under Title IV. The

delivered cost curves sloping upward to the left

shift as well; the resulting curves are shown as

dotted lines. If there had been no change in transportation costs, the breakeven point between

western and eastern coal would be at D" (based on

intersection point C"). Point D" is further to the

East than the original breakeven point D, indicating that Title IV would cause western coal's market share to gain relative to eastern coal. 

As discussed above, however, a change in transportation costs would cause part of the market

share change to take place in the baseline. In

Exhibit C-6, this baseline shift is shown as the

distance from D to D'. It might seem, then, that

instead of Title IV causing an incremental market

share change from D to D", it would cause only

the small shift from D' to D".

Exhibit C-6. Combined Effects of Transportation Rates and Allowance Price on Coal Competition

West East

A

Effect of Allowance Price on Cost

of Using High-sulfur Coal

B

D D’

B”

D’”

C”

D”

C”’

Source: ICF analysis.

C-8

5 In this simplified analysis, no distinction is made between the eastern and western coals in terms of heat content per ton. If the

heat content per ton of lower sulfur western coal is lower than that of the coal it is replacing, this difference would have to be

reflected by expressing the costs of purchasing and transporting the coals in terms of equivalent amounts of energy: point A would

be somewhat higher, and the slopes of lines A-C'' and A-C''' would be somewhat steeper. The main point of the graph would not

be affected. 
The effects of the transportation cost change,

though, interact with the effects of allowance

prices to cause an additional increase in the market share of western coal. With lower transportation costs, the effect of a given allowance price,

and hence a given upward shift in the cost of

using eastern high-sulfur coal (shown by the shift

from B to B") would be to move the breakeven

point from D' to D"'(based on intersection point

C"'). This eastward shift in the zone in which

western coal is competitive is potentially large

enough to outweigh the baseline effect noted in

the paragraph above. In other words, even though

the transportation cost reduction led to a baseline

shift in western coal's market share that reduced

the incremental effects of Title IV, the net effect

of Title IV on western coal use could still be

greater with lower transportation costs. In the diagram, lower transportation costs would increase

Title IV's net effect so long as the distance from

D' to D"' exceeds the distance from D to D'.

The net effect of lower transportation costs on

Title IV's impact on western coals depends on a

number of factors. One crucial factor, not shown

in Exhibit C-6, is the extent to which the baseline

shift in western coal use causes allowance prices

to be lower (than if the baseline shift had not

occurred). As noted above, Exhibit C-6 was constructed as though allowance prices, and thus the

shift from B to B", would be the same whether

transportation costs were high or low. In fact, the

baseline shift to greater use of western low-sulfur

coal could reduce the price of allowances by

reducing the need for incremental SO2 reductions.

Though it would be cumbersome to illustrate,

lowering B" would shift D"' to the left, showing a

smaller net effect of Title IV on western coal use.

In the extreme, if the baseline increase in western

coal due to transportation cost reductions (D to

D') were large enough to accomplish all of Title

IV's goals, the allowance price would drop to zero

(because there would be no need for, and thus no

value in, further SO2 reductions). In that case, the

effects of Title IV on western coal use would

clearly be smaller as a result of the transportation

cost change.

In actuality, emissions consequences of the baseline shift in coal use was apparently only a fraction of the required emission reduction in Phase I

of Title IV and manifestly did not drive the

allowance price to zero (Ellerman et al., 1997). It

is, therefore, difficult to tell a priori whether

transportation cost reductions increased or

decreased the effects of Title IV on western coal

use. It does not seem unreasonable that the

CEUM and IPM modeling results suggest that the

effects on western coal use increased.

Another consequence of the increasing attractiveness of western coal, both in the baseline and as a

compliance strategy, is that it would definitely

reduce the need for coal shifting within the East.

In the earlier analysis, much of the needed reduction in sulfur had to come from shifts from highsulfur eastern coal to lower-sulfur eastern coal. In

part, these changes could come within a given

region or state. To a substantial degree, however,

they also came from interregional shifts within

the East: particularly, from high sulfur coal in the

Midwest region to medium or low sulfur coal in

the central and southern Appalachian region. To

the extent that the 1996 analysis projected greater

shifts to western coal, it also projects a smaller

need for shifts within the East. Furthermore,

because the differences in sulfur levels between

eastern coals is often not as great as between eastern and western coal, more total tons of coal must

be shifted in order to cut SO2 emissions by a

given amount. Thus, because both the baseline

and post-Title IV shifts toward western coal are

very good substitutes for shifts between eastern

coal regions, it is reasonable to expect that there

are fewer tons of coal demand moving among the

eastern regions in the 1996 analysis. 

C.4. Changes in Employment Impact

Projections

The different productivity and baseline assumptions used in the 1992 RIA and 1996 analysis

result in somewhat different employment change

projections. The 1992 RIA did not quantify the

employment impacts of Title IV. It did, however,

provide a qualitative assessment, stating that there

C-9
would be both a small net decline in nationwide

employment and significant shifts from one

region to another. Corresponding to the coal mining changes shown in Exhibit C-5, the RIA projected decreased employment in northern

Appalachia and the Midwest.6

Similarly, employment gains were projected for

central and southern Appalachia and the West.

These employment gains, however, were not

expected to completely offset the employment

losses in northern Appalachia and the Midwest. 

The effects of projected coal switching shown in

Exhibit C-5 on coal mining employment can be

calculated using projected labor productivity.

Understanding the impacts on employment, however, is complicated by the fact that projections of

mining productivity have changed since the late

1980s and early 1990s. As discussed above,

whereas the base cases prepared in 1989 (and

used in the 1992 analyses) projected coal miner

productivity increases of only two to three percent

per year, the 1996 analysis recognizes that actual

productivity has been rising twice as fast. Thus,

the employment implications of changes in coal

use projections from 1992 to 1996 depend on

which productivity assumptions are used.7

To focus on the effects of differences in coal use

projections, we first show the projected effects on

employment holding the productivity assumptions constant from the 1992 to the 1996 analysis.

Exhibit C-7 shows the incremental impacts of

Title IV on coal labor requirements for the 1992

and 1996 analysis, using the labor productivity

assumptions from the 1992 analysis (shown in the

first two columns of Exhibit C-1). The projected

job slot changes in Exhibit C-7 are based on the

productivity factors of 4.65 tons per miner-hour

in the East and 15.27 tons per miner-hour in the

West. The differences in employment impact estimates between the 1992 and 1996 analyses result

solely from differences in their projections of coal

use. 

Exhibit C-7. Labor Demand Comparisons for 2010 Using Constant Productivity Growth

Assumptions (from the 1989 Base Cases) (numbers of job slots)

Coal Supply Region 1992 RIA

( high base case)

1996 Analysis Difference

(1996 analysis

minus 1992 RIA)

East - 3,700 - 6,800 - 3,100

 Northern Appalachia - 4,300 - 6,100 - 1,800

 Central & Southern Appalachia + 14,100 + 3,300 - 10,800

 Midwest - 13,500 - 4,100 + 9,400

West +1,000 + 1,600 600

Net* Change - 2,700 - 5,200 - 2,600

Gross** Change (in regions with

reduced demand)

- 17,800 - 10,100 + 7,600

* Net is nationwide job slot change, netting the gains and losses in regions listed above.

** Gross is the total regional losses for those regions that have losses.

Source: ICF analysis. Totals do not add due to rounding.

C-10

6 Because it takes fewer workers to mine a given quantity of coal in the West than in the East, shifting coal production from the

East to the West will add fewer workers in the West than it will subtract in the East.

7 As a concrete example, a drop in coal demand of 10 million tons will have twice the effect on labor demand if it took 200 workers

to produce each million tons than if it only took 100 workers.
Applying the lower labor productivity growth

rates used in the 1992 analysis to the coal demand

impacts projected by both the 1992 and 1996

analyses, the 1992 analysis projected a 2,700 jobslot-loss in 2010, compared to the 1996 analysis's

5,200 job slots. However, from a difference perspective, the gross reductions in labor demand in

the regions most affected by Title IV are considerably smaller (10,100 job slots vs. 17,800)

according to the more recent analysis. This result

occurs because the 1996 analysis projected less

coal switching within the East than did the 1992

analysis. 

Exhibit C-8 shows effects of combining the more

recent coal demand estimates with newer labor

productivity projections. The net effects of Title

IV are projected to be greater by only about 2,700

job slots. Gross employment impacts of Title IV

are now projected to be substantially smaller than

previously projected. The 1992 RIA analysis projected (implicitly) that almost 18,000 job slots

would be eliminated by 2010; now, projections

using the 1996 analysis are that less than half that

number—7,700—will be lost. This change in

gross job slot losses results from a dramatic drop

in projected job slot losses in the Midwest (from

over 13,500 down to about 3,000). As discussed

above, the increased shift to western coal was in

place of shifts to eastern low-sulfur coal. 

* Net is nationwide job slot change, netting the gains and losses in regions listed above.

** Gross is the total regional losses for those regions that have losses.

Source: ICF analysis. Totals do not add due to rounding.

Coal Supply Region

1992 RIA

(high base case)

1996 Analysis Difference

(1996 analysis minus

1992 RIA)

East -3,700 -5,100 -1,500

 Northern Appalachia -4,300 -4,600 -300

 Central & Southern Appalachia +14,100 +2,500 -11,600

 Midwest -13,500 -3,100 +10,400

West +1,000 +1,000 0

Net* Change -2,700 -4,100 -1,500

Gross** Change

(in regions with reduced

demand)

-17,800 -7,700 +10,100

Exhibit C-8. Labor Demand Comparisons for 2010 Using Productivity Growth Assumptions from

the 1989 Base Cases for the 1992 Analysis, and Productivity Growth Assumptions from the 1996

Base Case for the 1996 Analysis (numbers of job slots)

C-11
C.5. References

Ellerman, A. Denny, Schmalensee, Richard, Joskow, Paul L., Montero, Juan Pablo, and Bailey, Elizabeth M. (1997).

Emissions Trading Under the U.S. Acid Rain Program: Evaluation of Compliance Costs and Allowance Market

Performance. MIT Center for Energy and Environmental Policy Research, Cambridge, MA, October, 1997.

ICF Consulting (1993). Memo from ICF Resources to Ann Watkins at EPA on base case revisions. August 20, 1993.

ICF Consulting (1995). ICF briefing. September 1995.

Science Advisory Board (SAB) (1996). Minutes Of The Advisory Council Of Clean Air Compliance Analysis.

Attachment F-5-5 "Coal Supply Assumptions in the Clean Air Power Initiative," July 31, 1996. Referenced at

http://www.epa.gov/science1/minut4.htm

U.S. Department of Energy, Energy Information Administration (EIA) (1995). Energy Policy Act Transportation Rate

Study: Interim Report on Coal Transportation. October 1995, p. 21.

U.S. Department of Energy, Energy Information Administration (EIA) (1999 and 1993). Annual Energy Review

"Monthly Cost and Quality of Fuels for Electric Plants". Data from July 1999 and July 1993.

http://www.eia.doe.gov/cneaf/electricity/page/ferc423.html

C-12
As noted in the body of this

report, the analysis focuses on

2010 because the full effects of

Title IV are not expected to be

seen until about that year. For purposes of comparison to analyses

that discuss Title IV's impacts in

2000, and to show how projections of coal and labor demands

change over time, it may be useful

to see projections for 2000 based

on both the 1990/1992 analysis

and the 1996 analysis. This

appendix consists of four tables:

Exhibits D-1 and D-3 show coal

use and employment projections

based on the 1996 IPM runs, and

Exhibits D-2 and D-4 show similar projections based on the earlier 1990/1992 analysis.

Tables D-1 and D-2 show generally comparable

coal shifts from the East to the West, with very little net change in total tons of coal either produced

or used by utilities. The more recent analysis,

however, shows a much smaller shift within the

East. In 1996, utilities were projected to increase

their year 2000 use of central and southern

Appalachian coal by 24 million

tons, and to decrease their use of

Midwest coal by 18 million tons.

In 1990/1992, the equivalent figures were an increase of 62 million

tons for central and southern

Appalachian coal, and a drop of 64

million tons in the Midwest. 

These different projections of

interregional coal shifts are

reflected in the employment projections: Exhibit D-3 shows a

much smaller shift of job slots

between the Midwest and central

and southern Appalachia than

does Exhibit D-4. Largely as a

result of this difference, Exhibit

Appendix D: Results of Modeling and

Analysis for 2000

Exhibit D-2. Projections of Coal Industry Output in the Year

2000. (Using 1990/1992 model runs) (millions of tons)

Coal Supply Region

Coal

Production

in Baseline

Coal

Production

with Title

IV

Title IV

Impact

East 648 615 -33

 Northern Appalachia 197 166 -31

 Central & Southern

Appalachia

302 364 62

 Midwest 149 85 -64

West 491 521 30

Total 1,138 1,134 -4

Source: 1992 SO2 RIA, Appendix 4b (high base case). Totals do not sum due to

rounding. 

Coal Supply Region Utility Coal

Use in

Baseline

Utility

Coal Use

with Title

IV

Title IV

Impact

East 428 403 -25

 Northern Appalachia 170 139 -31

 Central & Southern

Appalachia

164 188 24

 Midwest 94 76 -18

West 524 549 25

Total 952 952 0

Source: 1996 IPM runs. Totals do not sum due to rounding.

Exhibit D-1. Projections of Coal Use by Utilities in the Year

2000. (using 1996 IPM runs) (millions of tons)

D-1
Exhibit D-3. Projected Effects of Title IV on

Coal Industry Employment in the Year 2000

(Using 1996 IPM runs)

Coal Producing Region Change in Job

Slots

East - 2,800

 Northern Appalachia - 3,500

 Central & Southern

Appalachia 2,700

 Midwest - 2,000

West 600

Net* Job Slot Change - 2,300

Gross** Job Slot Change - 5,600

* Net is nationwide job slot change, netting the gains and

losses in regions listed above.

** Gross is the total regional losses for those regions that

have losses.

Source: ICF analysis, using 1996 IPM runs. Totals do not

sum due to rounding.

Exhibit D-4. Projected Effects of Title IV on

Coal Industry Employment in the Year 2000.

(Using 1990/1992 model runs)

Coal Producing Region Change in Job

Slots

East - 4,000

 Northern Appalachia - 3,700

 Central & Southern

Appalachia 7,400

 Midwest - 7,700

West 700

Net* Job Slot Change - 3,200

Gross** Job Slot Change - 11,400

* Net is nationwide job slot change, netting the gains and

losses in regions listed above.

** Gross is the total regional losses for those regions that

have losses.

Source: 1992 SO2 RIA, Appendix 4b (high base case).

Totals do not sum due to rounding.

D-2

D-3 shows a smaller gross and net reduction in

job slots.1 These patterns are similar to those seen

in the analyses for the year 2010, with smaller

shifts within the East leading to smaller gross job

losses. 

1 Here and elsewhere in this report, "gross job slot changes" are the sums of job slot reductions across all of the regions with losses, whereas "net job slot changes" are the sums of job slot reductions across all regions, net of job slot increases.
1992 RIA: the Regulatory Impact Analysis developed for Title IV provisions in 1992

1996 Analysis: an analysis created in 1996 to estimate the coal production and employment impacts of

the Title IV provisions of the Clean Air Act

The Act: The Clean Air Act (CAA)

CAA: Clean Air Act 

CAPI: Clean Air Policy Initiative (http://www.epa.gov/capi/capi.html)

CEUM: The Coal Electric Utility Model, used to generate the coal projections for the 1992 RIA

EIA: Energy Information Administration

IPM96: 1996 version of the Integrated Planning Model

Job Slot: one job slot is the equivalent of one miner-year of work (2,536 hours in the West and 2,060

hours of labor in the East)

Low sulfur coal: The Energy Information Administration (EIA) "classifies coal, in terms of pounds of

sulfur per million Btu as low (less than or equal to 0.60 pounds of sulfur), medium (between 0.61 and

1.67 pounds of sulfur), and high (greater than or equal to 1.68 pounds of sulfur). When coal is sampled,

sulfur content is measured as a percent by weight of coal on an 'as received' or 'dry' (moisture-free)

basis." (EIA, 2000a) 

RIA: Regulatory Impact Analysis

Appendix E: List of Acronyms and

Definitions

E-1

EPA's draft report, "Impacts of Title IV of the Clean Air Act Amendments of 1990 on Coal Industry

Employment," was subjected to external peer review during the spring, 2000. EPA uses peer review to

uncover any technical problems or unresolved issues in a work product through the use of independent

experts.1 The peer review process is used to enhance the technical work product by providing a documented critical review by qualified individuals who are independent of those who performed the technical

work. Because the draft report analyzes the potential impact of a major environmental program on an

employment sector that has undergone significant reduction over time, the Agency wanted to be certain

that the report's methodology, assumptions and conclusions received in-depth assessment. 

EPA began the peer review process by inviting four eminent resource economists (Dallas Burtraw, A.

Denny Ellerman, Richard Gordon, and Michael Rieber) to conduct the review. EPA asked for an overall

evaluation of the report based on whether criteria such as the validity of the methodology, the appropriateness of the assumptions, and the soundness of the conclusions were satisfied. EPA also asked for more

detailed responses to a series of questions, such as the consistency of the paper's conclusions with the

reviewers' understanding of coal industry employment. Finally, the reviewers were invited to submit specific comments on the format and content of the paper, which the reviewers provided through line-by-line

citations from the text. 

To assure the integrity of the handling of reviewer comments, each reviewer was assigned a randomly

selected number for use in submitting reviews. In addition to the questions described above, EPA asked

the reviewers whether the report should be issued as a public document. Three reviewers responded that

the report should be released with minor changes. One reviewer believed that the report should be released

only after major revisions. EPA incorporated many of the comments and suggestions submitted by the

reviewers into the report. Comments that would have required effort beyond the scope of the report or that

would have required major structural revisions or new analyses were not accepted. EPA prepared a document that recorded all comments submitted by the peer reviewers and the Agency's responses. This document and all other materials prepared during the course of the peer review will be maintained. 

Biographies of the Peer Reviewers:

Dr. Dallas Burtraw is a Senior Fellow at Resources for the Future and a lecturer at Johns Hopkins SAIS

University. He specializes in environmental policy issues such as the effects of SO2 trading, emissions

reductions, and social costs. His research interests also include restructuring of the electric utility market,

social costs of pollution, and the impacts of environmental regulation.

Dr. A. Denny Ellerman is an internationally recognized authority on coal economics and emissions trading. He is currently serving as the Executive Director of the Center for Energy and Environmental Policy

Research at Massachusetts Institute of Technology. He lectures at the Sloan School of Management and

has written numerous articles related to CO2 trading and other market based compliance measures.

Appendix F: Peer Review Process

F-1

1 U.S. Environmental Protection Agency, Science Policy Council, Peer Review Handbook, EPA 100-B-98-00
Dr. Richard Gordon is a leading authority on the economics of the coal industry. He served as the

Director of the Center for Energy and Mineral Policy Research at the Pennsylvania State University,

Department of Mineral Economics. A small selection of works from his list of publications includes: U.S.

Coal and the Electric Power Industry; Coal in the U.S. Energy Market: History and Prospects; "North

American Free Trade: Another Challenge to Coal;" and "Energy, Exhaustion, Environmentalism, and

Etatism."

Dr. Michael Rieber is an authority in mineral economics, and currently serves as a professor at the

University of Arizona and as a visiting professor at the Western Australian School of Mines/Curtin

University of Technology in Perth, Australia. He specializes in topics such as the markets for copper and

mercury, and the economics of coal slurry pipelines. Dr. Rieber has also provided expert testimony before

government agencies and consults for local governments, mining companies, and other organizations.

F-2