The Direct Use of Coal

April 1979

NTIS order #PB-295797
Library of Congress Catalog Card Number 79-600071

For sale by the Superintendent of Documents, U.S. Government Printing Office

Washington, D.C. 20402 Stock No. 052-003 -00664-2

ii
Foreword

Coal production in the United States will more than double by the year

2000, to as much as 2 bilIion tons per year. The investments in facilities, manpower, and technologies for the mining, transportation, and use of such vast

quantities of coal will be immense.

This report assesses the benefits and risks of such a massive shift to coal

and away from other fuels. It deals with the social, economic, physical, and

biological impacts of such a shift. It examines the complete coal system,

from extraction to combustion, including the key steps and institutions that

policy can influence. The environmental impacts and possible effects on the

public health are documented. Occupational and community impacts are examined. Technologies under development that might reduce costs, increase

convenience of use, or mitigate negative impacts are reviewed.

This assessment was requested by the House Committee on Science and

Technology. It is another in a series of assessments that are being provided to

Congress to assist in the development of national energy policy.

The Project Director for this assessment was Mr. Alan T. Crane, who was

supported by the Energy Group staff and Dr. Richard E. Rowberg, Group

Manager. We are grateful for the assistance provided in this assessment by

the Coal Advisory Panel, chaired by Mr. Harry Perry, and the overal l

guidance provided by OTA’s Energy Advisory Committee, chaired by Professor Milton Katz .

Daniel De Simone

Acting Director

..

///
Acknowledgements

This report was prepared by the Energy Group staff of the Office of Technology

Assessment. The staff wishes to acknowledge the assistance of the following contractors

and consultants in the collection and analysis of data.

Teknekron

Institute for Energy Analysis

Arthur Squires

University of Oklahoma

Georgia Institute of Technology

Environmental Law Institute

A. V. Slack

Kendrick & Company

Brophy Associates, Inc.

The Academy for Contemporary Problems

Environmental Policy Institute

Maeva Marcus

Martha Spence

Nancy Schuh

Citizens for a Better Environment

Lee Balliet

Tetra Tech

William T Reid

J. Philip Bromberg

James L. Weeks

Reginald Brown

Harvard University

University of Denver

Donald Lief

Joseph Mohbat

Lawrence Miike

The fo

The Environ

Iowing Government agencies also provided assistance:

mental Protection Agency

The Department of Energy

The Department of Labor

The Department of Health, Education, and Welfare

The Congressional Research Service

i v
Direct Use of Coal Project Staff

Lionel S. Johns, Assistant Director

Energy, Materials, and Global Security Division

Richard E. Rowberg, Energy Group Manager

Alan T. Crane, Project Director

Marvin Ott, Policy

Steven Plotkin, Environment and Public Health

A. Jenifer Robison, Regulatory Issues

Curtis Seltzer, Mining Implications and Community Impacts

Joanne Seder, Research Associate

Lisa Jacobson Lillian Quigg Rosaleen Sutton

Supplements to Staff

Robert J i meson

Barbara G. Levi

W, Gene Tucker

L. Wiliiam Richardson

Contributors

Lynda L. Brothers

J. Bradford Hollomon

OTA Publishing Staff

John C, Holmes, Publishing Officer

Kathie S. Boss Joanne Heming

v
OTA Energy Advisory Committee

Milton Katz, Chairman

Director, International Legal Studies, Harvard Law School

Thomas C. Ayers

President and Chairman of the Board

Commonwealth Edison Company

Kenneth E, Boulding

Professor of Economics

Institute of Behavioral Science

University of Colorado

Eugene G Fubini

Fubini Consultants, Ltd.

Levi (J.M.) Leathers

Executive Vice President

Dow Chemical USA

Wassily Leontief

Department of Economics

New York University

Direct Use of Coal Advisory

Harry Perry, Chairman

Resources for the Future, Inc.

Mike Clark

l-fighlander Research Center

David Comey*

Citizens for a Better Environment

A W. Deurbrouck

Department of Eneergy

Michael E Enzi

Mayor, City of Gillette

Don Gasper

Consolidation Coal Company

W. L. Johns

E. 1. du Pent de Nemours & Co.

Lorin Kerr

United Mine Workers of America

George Land

A MAX Coal Corporation

Ed Light

West Virginia Citizens Action Croup

George E. Mueller

President and Chairman of the Board

System Development Corporation

Gerard Piel

Publisher

Scientific American

John F. Redmond, Retired

Shell Oil Company

John C. Sawhill

President

New York University

Chauncey Starr

Electric Power Research Institute

Panel

Robert Lundberg

Commonwealth Edison

Paul Martinka

American Electric Power (Retired)

David Mastbaum

Environmental Defense Fund

Ken Mills

Tug Valley Recovery Center

Michael Rieber

University of Arizona

Steve Shapiro

United Mine Workers of America, LU 6025

Ronald Surdam

University of Wyoming

Joana Underwood

INFOR M

Ralph Perhac

Electric Power Research Institute

Joseph Yancik

National Coal Association

The Advisory Panel provided advice and constructive criticism throughout this project. The panel

does not, however, necessarily approve, disapprove, or endorse this report. OTA assumes full responsibility

for the report and the accuracy of its contents.

*Died January 1979. The OTA Coal Project staff expresses their sincere appreciation for the assistance and support

that David Comey had contributed throughout this assessment.

v i
Summary

Coal can be America’s most productive domestic energy source well into the 21st

century. No other fuel, however, evokes such memories of environmental damage

and social disruption. Although new programs, practices, and legislation have addressed many of these problems, their adequacy and effectiveness are uncertain, and

new concerns are emerging. Thus, coal’s future is a mixture of promise and risk.

This report analyzes the role that coal combustion may play in the Nation’s

energy future, the factors that will shape that role, and the impacts that may result.

SUPPLY AND DEMAND

A tripling of coal production and use by

2000 appears to be possible without either

substantial regulatory relaxation or major

technological innovations. Such rapid growth

may be in the national interest even though

total energy demand will probably grow more

slowly than it has in the past. However, several

factors might inhibit this rapid rate of development Primary among these is the likelihood

that demand for coal will not rise this quickly.

Coal is not normally the fuel of choice unless it

offers a large cost advantage. Many users will

prefer oil and natural gas as long as they are

available, despite their higher prices, because

of their greater convenience and lower capital

investment requirements. Recent regulations

have increased the cost of mining and burning

coal, thus reducing its attractiveness. The 1978

National Energy Act discourages large new facilities from burning gas or oil, but additional

legislation or other incentives may be required

if coal’s share of the energy system is to be further increased. If demand does triple, several

potential supply constraints could still interfere with achieving a tripling of coal supply.

Mine-to-market transportation systems will

need upgrading and expansion. Federal coal

leasing may have to resume. Conflicts between

mine labor and management could escalate to

the point where national production is compromised. Some communities, particularly in

the East, may need assistance to accommodate the required development. Public concerns about the siting of mines, powerplants,

and other facilities may delay expansion.

In addition, questions have been raised

about the reliability of available control

technologies and their ability to meet environmental regulations. Significant problems

with these technologies could constrain future

coal use. The technological viability of fluegas desulfurization (FGD) to meet proposed air

pollution emission standards is a focus of this

controversy. A growing body of evidence, however, indicates that this technology wiII be adequate though expensive. Safe disposal of FGD

sludge also appears to be feasible technologically, but expensive. Finally, requirements of

the Surface Mine Control and Reclamation Act

will raise the cost of coal but should not pose

technical barriers to meeting demand.

ENVIRONMENT AND PUBLIC HEALTH

This report does not identify any significant of conscious economic tradeoffs, tack of effiviolations of existing environmental standards cient control devices or insufficient enforcethat inevitably would result from a substantial ment of existing standards. For example, some

rise in coal use. However, some adverse envi- underground mines wiII cause acid mine drainronmental impacts are likely to occur with in- age or subsidence problems long after their

creased coal mining and combustion because abandonment; permanent controls for these

v i i
problems are not available for all mining situations. Some emissions may prove to be inadequately regulated because of scientific uncertainty concerning the cause and significance

of their effects. Emissions of sulfur dioxide,

nitrogen dioxide, carbon dioxide (COZ

) and fine

particulate will all increase significantly by

the end of the century under a high coal

scenario and present or pending regulations.

Increases in coal-related air pollution may

cause or aggravate three potential environmental problems whose magnitude and importance cannot yet be evaluated adequately. Additional evidence of these problems could

force a reappraisal of our environmental control strategy or even our commitment to increased coal development.

First, fossil fuel combustion (along with the

clearing of forest land) appears to be causing

an atmospheric COZ buildup that may lead to

significant changes in global climate. C02 is

not likely to become a serious problem before

the next century, but if it does, a dramatic

worldwide reduction in both fossil fuel combustion and deforestation may be the only way

to halt or reduce climate change. Coal is the

fossil fuel of greatest concern because of its

large reserves and high carbon content; presumably, the faster coal use increases the

sooner a critical point will be reached and the

more difficult it will be to switch to nonfossil

fuels.

Second, there is a possibility that present

ambient air standards are inadequate to protect the public health from problems resulting

from long-term exposure to low levels of

pollutants. Some controversial analyses suggest that current exposure levels may be responsible for tens of thousands of premature

deaths annually. Increases in emissions of coal

combustion-related pollutants could aggravate existing problems.

Third, acid rain, which has been linked to ex

-

tensive damage to aquatic ecosystems and

may also cause terrestrial damage, may increase as a result of increased emissions of

sulfur and nitrogen oxides from coal combustion.

If additional evidence confirms current concerns, further reduction in air emissions may

be desirable to reduce the health and environmental risks associated with increasing U.S.

coal use. Existing coal-burning facilities would

be primary targets for emission regulations,

since many of these will not be stringently controlled under State air quality enforcement

plans. The technical and economic problems

of retrofitting capital-intensive control systems

on existing plants can be severe. Thus, emission reductions may be most efficiently realized by supplying these facilities with cleaned

coal. The various techniques for coal cleaning

(physical desulfurization, solvent refined coal,

and synthetic fluids) may become the primary

component of a national strategy for achieving

the dual objective of increased use of coal and

an improved environment.

OCCUPATIONAL SAFETY AND HEALTH

Considerable improvement has been recorded in reducing mine fatalities since the

enactment of the 1969 Federal Coal Mine

Health and Safety Act, but there has been no

reduction in the rate of disabling injuries, and

the total number of injuries has been increasing. In 1977, 139 coal workers were killed and

about 15,000 suffered a disabling injury — each

of which cost an average of almost two months

lost time. A tripling of production, under the

assumptions of this report, wilI result in approximately 370 fatalities and 42,000 disabling

injuries per year.

The prevalence of coal workers’ pneumoconiosis should be lower in 2000 than it was in

197o as a result of the Federal respirable dust

standard, but thousands of workers wilI nevertheless be disabled by various respiratory

diseases (collectively called black lung

disease). Furthermore, important questions

I/ill
have been raised concerning the effectiveness

of enforcement of the existing dust standard

and the adequacy of the research on which it is

based.

COMMUNITY IMPACTS

Coal development brings both beneficial

and adverse social and economic consequences. Communities with diversified economies are better equipped to deal with rapid

development and are more likely to benefit.

Where existing services are already under

severe stress, coal development is likely to

bring additional social and economic problems. Public services and facilities will not be

able to expand sufficiently to cope with increased demand. Tax revenues will not increase fast enough to finance needed improvements.

Some communities in Appalachia will be

particularly vulnerable to these adverse impacts, Stagnant coal demand and excess production capacity during the 1920-70 period led

to depressed economic conditions in the mining industry and communities. Inadequate

services and facilities are a legacy of these

conditions. Increased coal production without

substantial new revenues and technical aid

from the Federal or State governments is likely

to exacerbate current inadequacies in housing,

transportation, health care, and other public

and private services,

Some western communities may suffer serious social and economic dislocations if mining

ISSUES AND

Legislative activity bearing on coal will fall

into three categories: further amelioration of

negative impacts; promotion of coal to reduce

the use of other fuels; and oversight to ensure

that existing legislation is being appropriately

implemented, This section Iists the major steps

discussed in this report that Congress may consider, The options are not recommendations.

Some, in fact, may be contradictory. The options are intended only to show how this

expands too rapidly. States with underground

reserves are especially vulnerable. Development of these reserves wilI require many new

workers and will bring substantial population

growth to sparsely populated areas. Mining of

Indian coal may create significant social problems on reservations. However, with some exceptions, the tax revenues that couId be generated by coal development can provide significant opportunities for economic benefit. To

minimize economic dislocations, provision

wilI have to be made to overcome the initial

shortfalIs of funds that follow the onset of development. Also, mismatches between areas

absorbing the impacts and those reaping the

economic benefits must be resolved.

Finally, the diversified economies of many

Midwestern coal counties will allow them to

benefit from coal development. These counties combine the population and adequate

service base needed to absorb development

without severe stress.

The following section describes some of the

related policy issues that Congress may consider, A detailed summary of the entire report

is found in the

OPTIONS

overview of chapter 1 .

analysis can be used to reach a given end, the

desirability of which depends in part on the

perspective of the policy maker. Cross references to the relevant sections of the main

report are included.

Control of Coal-Related Air Pollution

Coal combustion is accompanied by a risk

of health damage (possible increased incii x
dence of illness and premature death) and

ecological disturbances (e. g., by acid rainfall)

from air polIution.

Although existing pollution sources are

rapidly being controlled by State implementation plan (S1P) regulations and new sources wilI

be subject to new source performance standards and other regulations, ambient concentrations of fine particulate and nitrates could

rise rapidly (and those of sulfates more slowly)

during the next few decades if coal development continues at the expected rate. The

reasons for these increases include: failure of

particulate control requirements to distinguish

among different particle sizes, allowing the

use of controls that are less effective in controlling the smaller (and more dangerous) particles; unavailability of efficient NOx controls;

and basing of S I P emission control requirements on local impacts only, thus allowing certain sources to escape tight controls because

their pollution is widely dispersed.

The tradeoff between emission requirements

and costs of control is severely complicated by

the scientific controversy surrounding the effects associated with these pollutants. Scientists still do not agree on the existence or importance of some of the effects or their precise

cause.

Text discussions:

Air Pollution Controls Ch.III

Long range transport of

pollution . . . . . . . . Ch. V

Expected future emission levels . . . Ch. V

Health effects . . . . . Ch. V

Acid rain ecosystem

effects . . Ch. V

Options . . . . . Ch. VIII

Options

● Increase Federal research emphasis on the

impacts and mechanisms of long-range

pollutant transport. Increase Federal effort on development of more effective,

less expensive controls for NOX

, S0x, and

fine particulate, Emphasize clean fuels

and low cost technological controls

suitable for retrofit.

x

If the public health and ecological risks are

seen as sufficiently dangerous that further

limitations should be applied before the risks

are better defined by further research, the

following actions should be considered:

●

●

●

●

Establish emission and ambient standards

for fine particulate.

Revise the Clean Air Act to allow direct

Federal control of existing sources of pollution. Actions could range from requiring

recently built facilities to comply with

NSPS requirements, to selective emission

reductions on large facilities when their

State Implementation Plan requirements

are lenient or when they are located in

areas that are the source of problems

associated with long range transport of

polIutants.

Revise the Clean Air Act to allow regional

and/or Federal control of siting of major

facilities when they might contribute to

pre-existing long range transport problems.

Give maximum priority to development of

N OX controls.

The Role of Cost Benefit Analysis in

Environmental Decisionmaking

The need to weigh costs against benefits has

recently become a critical topic of debate in

regulatory decision making. An array of environmental decisions affectin g coal development will be affected by the outcome of this

debate. For example, the Environmental Protection Agency has recently proposed new

source performance standards (NSPS) for sulfur dioxide emissions from coal-fired utility

boilers. The additional cost of installing and

operating the equipment (flue gas desulfurization) to meet these standards is of great concern to utilities. Alternative strategies have

been proposed that could grant utilities

somewhat relaxed standards that could be met

at lower cost. No one, however, has produced

a convincin g analysis of the relative value of

the different strategies in ameliorating adverse

impacts — public health risks, crop, ecological

and material damage, etc. — to compare with

the costs.
The NSPS debate shares a common problem

with other environmental issues: the costs of

controls are more easily computed than their

environmental benefits. Thus, a fair balancing

of costs and benefits in setting environmental

standards is always difficult and frequently impossible.

Text discussions:

Flue gas desulfurization

argument. Ch.IV

Environmental Impacts. Ch.V

Options Ch.VIII

Option A:

Maintain the status quo. The present regulatory emphasis is on the use of “Best Available (polIution) Control Technology, ” although

the agencies have used legislative language requiring consideration of the cost of achieving

the standards as a restraint on how expensive

the required controls can be. (The degree of

their “restraint" is of course a subject of some

disagreement).

Option B:

Require regulatory agencies to develop and

publish "impact statements” that state their

estimates of the costs and benefits of proposed standards and regulations.

Option C:

Establish a mechanism to decide whether a

forthcoming standard must be set by an explicit balancing of costs and benefits. The

basis for this decision would be the state of the

art of impact assessment for the pollutant in

question.

Occupational Health

Despite a strict. standard for respirable coal

mine dust mandated by Congress in 1969,

miners continue to be exposed to harmful

dusts and fumes. The current standard should

greatly lower the number of miners disabled by

coal workers’ pneumoconiosis if it is complied

with regularly, Exposure to nonrespirable dust

(associated with other respiratory diseases)

and other toxic substances is neither measured

nor regulated. Hearing loss is another major

occupational hazard. The present dust and

noise sampling programs are of questionable

reliabiIity. Some mines may not be in compliance even when their sample data say they

are. Even with current standards and diligent

compliance, it is likely that thousands of

miners wilI show evidence of work-related lung

disease in the future.

Text discussion . . ChVI

Options

●

●

●

●

●

Reassess the inherent safeness of the current respirable dust standard.

Consider alternatives to current dust

sampling, including continuous in-mine

monitoring, and possibly more effective

ways of carrying out sampling, such as

miner- or MS HA-control of the program.

Encourage the establishment of health

standards for other harmful substances —

nonrespirable dust, trace elements, fumes,

etc. — that are now unreguIated.

Consider lowering the Federal noise standard for mining.

Promote occupational health training for

miners.

Occupational Safety

Coal mining involves higher probabilities of

occupational death and disabling injury than

almost any other trade. Although coal’s fatality rate has improved considerably with the implementation of the 1969 Federal Coal Mine

Health and Safety Act, the frequency and

number of disabling injuries — about 15,000 in

1977– has not improved. Both fatalities and

injuries wiII rise in proportion to increases in

production unless accident frequency rates are

lowered.

Text discussion: Safety . . . . . . . Ch. VI

Options

● Consider the feasibility of requiring or encouraging conversion to the “safest

available mining equipment” (adjusted to

individual mine characteristics), consistx i
●

●

●

●

●

ent with the intent of the 1969 and 1977

Federal mine safety laws.

Establish Federal safety standards for

mine equipment.

Require 90-day apprentice training before

a miner is allowed to operate an unfamiliar piece of mobile mine equipment.

Clarify the right of individual miners to

withdraw from conditions of imminent

danger under Federal law.

Establish Federal limits on fatality and injury frequency for different kinds of

mines. Substantial penalties could be

levied against mine operators exceeding

these limits.

Establish performance standards for the

Mine Safety and Health Administration.

Community Impacts

In communities where coal mining has dominated local Iife, rapid coal growth tends to

produce a broad range of socio-economic

problems. The chronic underdevelopment of

community services and facilities associated

with earlier coal development has left a

substantial legacy of needs. Where mining has

been a negligible factor in local affairs as in

the West, rapid growth can easily overwhelm

existing institutions. The level of current need

and ability to manage growth depends on sitespecific conditions, coal company policies and

the local tax system, among other factors.

Expanding mining communities suffer from a

lack of housing, planning capability, experience with Federal programs, and money to

develop services and facilities concurrently

with mine development. Such needs can be expected to be met at the state and local level

after mining growth stabilizes if the local

economy is healthy. Chronically underdeveloped and temporarily overwhelmed communities, however, would benefit from Federal

assistance if appropriate funding channels can

be devised.

Text discussion: Eastern . . . . . Ch. VI

Western . . . . . Ch. VI

Options

● Enact a national severance tax on coal (or

on other fuels to avoid an economic disin-

●

●

●

●

●

●

●

centive to use coal) to help finance

needed improvement in impacted communities.

Provide loans or subsidies for programs to

provide better public services in these

places, possibly through a public, nonprofit coalfield development bank.

Develop programs that would encourage

economic diversification in coal-dominated regions.

Require operators to submit a “community impact statement” to local and Federal

officials before mining begins.

Promote access to land in communities

where it is presently unavailable for housing.

Improve flood control measures in Appalachian coalfields as a way of encouraging investment in coal and noncoal

development and housing.

Maintain roads by enforcing coal truck

weight limits and institute a highway coal

haulage tax to fund road reconstruction.

Institute a rural health care system for

coalfields.

Labor-Management Relations

The history of coal’s labor-management relations is a chronicle of turmoiI caused by uncertain markets, hostile attitudes, and inequities.

Although lost time from strike activity increased in the 1970s over the 1950s and 1960s,

no enduring coal shortage has been experienced, even during the 3’/2 month UMWA

strike in 1977-78. Strikes disrupt normal production patterns, but experienced coal purchasers take adequate precautions by accumulating large stockpiles. As more and more coal

is Iikely to be mined in non-UMWA operations,

strikes may decline in national importance.

Nevertheless, the potential for intermittent

disruption will exist as coal assumes a more

central role in the Nation’s energy system.

Government intervention has generally been

resisted by both unions and operators, and it

has not been effective. Harsh measures aimed

at either party may do substantial long-term

damage to labor-management relations even

when they work in the short term.

x i i
Text discussion:

Industry Profile . . . . . . . Ch. IV

Labor Profile Ch. IV

Collective Bargaining Ch. IV

Workplace and Community Implications . Ch. VI

Options . . . . Ch, VI II

Options

●

●

●

Create contingency plans for emergency

coal shortages.

Promote programs to improve social conditions in the coalfields, thereby removing

sources of confIict.

Plan for government seizure of the mines

in the event of a crippling strike.

#

Increasing the Use of Coal

This report assumes coal use will grow

substantialIy. Such growth is consistent with

present expectations of energy needs, supply

of alternative fuels and potential constraints

on coal supply. National policy could seek to

further increase coal’s share of the total energy

supply, perhaps to reduce dependency on

foreign oil or nuclear power. Measures to

stimulate demand would then be considered.

The mining industry is expected to be able to

meet any plausible demand for at least the

next decade, but thereafter, constraints on production could become serious, especially if demand rises very rapidly,

Options

●

●

●

Increase demand for coal by strengthening penalties and incentives in the National Energy Act. Industrial users will be

the most Iikely target for such initiatives

(chapter I I).

Improve technology to make coal combustion more attractive. Clean coal and

synthetic fuels are essentially the only

ways of using coal in small furnaces and

boilers while meeting clean air standards.

Fluidized bed combustion may be an

asset to industrial use of coal (1 I I-G and

IV-L)

Facilitate supply by ensuring an early

resumption of Federal leasing (IV-A), and

improving the transportation systems

(IV-J).

● Reduce the costs and constraints of mining and combustion by easing regulatory

standards. Although this study has not

found any fundamental incomparability

between increased coal use and existing

environmental regulations, reclamation

and emission controls are expensive. A

less drastic step would be to institute

more flexible regulations designed to be

less stringent where the potential

damage is less.

Oversight

Legislation has addressed many major

for

impacts created in the past by coal production

and use. Some issues and programs may require particularly intensive oversight to assure

that congressional intent is being carried out.

The list below identifies the most important

such programs discussed in this report.

●

●

•

●

●

●

●

Development of long-range air-pollution

transport models and emplacement of

ambient air-quality monitoring to determine the effect of siting and energy policy

decisions. Epidemiological and ecological

studies to determine the impacts of air

quality changes (V. B.).

Enforcement of control of surface mine

runoff during operation and reclamation,

especialIy for small mines. Development

of ways to control acid mine drainage and

subsidence from abandoned underground

mines (V.C. and D.).

Enforcement of adequate dust control in

mines through sampling or continuous

monitoring (V1.A. ).

Resumption of leasing of Federal coal

with appropriate safeguards (IV.A. and

VI 1. A.2.).

Development of Federal strategies to

assist the upgrading of the coal transportation system (IV. j .).

Enforcement of current mine safety and

health standards through inspections and

penalties.

Conversion of oil and gas burning

facilities to coal under the National

Energy Act (1 I and VI 1. A.8. ).

. . .

X111
Contents

Page

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii

Chapter

1.

I 1.

Ill .

I v .

v .

V I .

VII .

VII 1.

lntroduction and Overview . . . . . . . . . . . . . . . . . . . . . . 3

Energy and the Role of Coal . . . . . . . . . . . . . . . . . . . . . 33

Coal Technology and Techniques . . . . . . . . . . . . . . . . . 53

Factors Affecting Coal Production and Use. . . . . . .109

Environmental Impacts. . . . . . . . . . . . . . . . . . . . .183

Workplace and Community Implications . . . . 25 9

Present Federal Coal Policy. . . . . . . . . . . .337

Policy Options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .373

Glossary: Acronyms and Definitions . . . . . . . . . . . . . . . . . . . . .407

x v
Chapter 1

INTRODUCTION AND OVERVIEW

●
Chapter 1.-INTRODUCTION AND OVERVIEW

Induction ● ****tid e***   ** **   ** *. **** *e e******* *

Overview v***   ** *e **.9   ** . **** **** *m** .*** *e*e 9

Energy and the Role of Coal. . . . . . . . . . . . . . . . . . . . . . . . . . . .

Environmental Impacts and Controls. . . . . . . . . . . . . . . . . . . . .

lmpacts on Air Quality. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

lmpacts on Land and Water . . . . . . . . . . . . . . . . . . . . . . . . . .

Workplace and Community impacts . . . . . . . . . . . . . . . . . . . . .

Coal Worker HeaIth and Safety . . . . . . . . . . . . . . . . . . . . . . .

Community Impacts.. . . ., . . . . ........ . . . . . . . . . . . . . . .

Social impacts of Transportation. . . . . . . . . . . . . . . . . . . . . .

lmpacts on Coal-Using Communities . . . . . . . . . . . . . . . . . . .

Factors Affecting Coal Production and Use. . . . . . . . . . . . . . . .

Coal Availability and Leasing. . . . . . . . . . . . . . . . . . . . . . . . .

Industry Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Labor Profile. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Labor-Management Relations and Collective Bargaining. . . .

Productivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

FederaI Coal Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Implementation. . . . . . . . . . . . . . . . . .% . . . . . . . . . . . . . . . . .

Future Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..:......

Environmental Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Community and Social Impacts . . . . . . . . . . . . . . . . . . . . . . .

Labor/Management Relations . . . . . . . . . . . . . . . . . . . . . . . .

Workplace Health and Safety . . . . . . . . . . . . . . . . . . . . . . . .

Leasing of Federal Coal Reserves . . . . . . . . . . . . . . . . . . . . . .

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Chapter I

INTRODUCTION AND OVERVIEW

INTRODUCTION

The increased use of coal has become the focus of a national debate over the need for

energy and the desire to maintain a healthy physical and social environment,

U.S. reserves of coal are vast, and the technologies of coal production and combustion

are welI developed Thus coaI offers a major aIternative to U.S. dependence on foreign supplies of oil However, coal development has a history of exploitation and turmoil in the coalfields of Appalachia, of cities laden with soot and noxious fumes, and of destruction of land

and water resources Although an extensive regulatory system and other pressures have

ameliorated many of coal’s historic problems, it stiII retains potential for damage Many

believe that rapid development of U S. coal resources cannot be accomplished without unacceptable damage both to the natural environment and to the communities where coal mining

and combustion occur

Federal policymakers face difficult choices

in dealing with coal’s adverse impacts. On the

one hand, strict controls almost always result

in higher costs of mining and using coal. These

costs may inhibit demand for coal and slow its

pace of development Also, efforts to control

one adverse impact sometimes cause another.

For example, the scrubbers used to reduce

sulfur oxide (SOx pollution produce large

quantities of sludge that represent a land use

and potential water pollution problem. Finally,

gaps in our knowledge of the importance and

causes of certain environmental effects create

doubt as to whether all required control measures are necessary or effective. Failure to adequately control an environmental or health impact, however, may result in adverse consequences that outweigh the costs of control,

These consequences may not be fully measurable in dollars and may take years to occur. In

addition, the public opposition to new coal

mines and powerplants aroused by a failure to

control environmental and health impacts may

be a more significant deterrent to development than are high prices. On the whole, Federal policy has tried both to encourage increased production and use of coal and to

lower its environmental, occupational, and

social costs, The attempt to write legislation

and regulations that balance these two goals

has been marked by controversy, with extensive Iitigation between environmental and coal

development interests as one result.

This report presents the results of a broad

study of the mining and direct combustion of

coal. There are three major themes, The first is

to determine coal’s potential contribution to

future U.S. energy needs. Next is an assessment

of the environmental and social impacts that

may result from rapid coal development. Finally, there is a guide for policy initiatives that

Congress may consider in addressing a variety

of coal-related issues. I n addition, the report

provides information on impacts and on new

technologies that should be useful for legislative oversight of Federal energy and environmental R&D programs. It identifies those impacts that have escaped the regulatory system

and those that have been only partialIy controlled. In many cases, it also describes the

means available to eliminate or mitigate these

impacts.

Assessment of adverse environmental impacts is particularly controversial because information is lacking in critical areas. Many important issues will not be resolved conclusively

for many years. Nevertheless, decisions on economic, environmental, and social policy to be

made over the next few years will be based on

this incomplete information. Hence, some of

this report’s conclusions are tentative, based

on an evaluation of the existing evidence. For

those areas where the evidence is particularly

controversial, alternative arguments are discussed.
4 ● The Direct Use of Coal

quences of coal use with either the use of

other fuels or with energy conservation. No

alternative to coal development is free of ●

adverse consequences; these must be taken

into account before coal “place” in the

overall U.S. energy picture can be determined.

Second, the report does not provide a complete and definitive accounting of the costs ●

and benefits associated with coal mining and

combustion, Not all costs and benefits are

known or knowable, Often, they cannot be

measured in the same terms. Therefore, the

report attempts to identify the uncertainties

●

surrounding the impacts described. The existence of high levels of uncertainty, as well as

the strong role that personal values play in

gauging the importance of impacts, clearly has

profound implications for policymaking. ●

The report is organized as follows: ●

● Chapter I I surveys U.S. energy patterns

and alternative forecasts of national energy demand and coal supply.

● Chapter I I I describes the coal resource

base and mining and combustion technologies. It also describes technologies available to control air pollution from coal

combustion,

Chapter IV analyzes the factors that will

affect coal production and use, including

leasing, industry structure, labor relations,

regulatory restrictions, physical and economic constraints, and public attitudes.

Chapter V describes the environmental

and public health effects associated with

mining and combustion under the current

reguIatory system.

Chapter VI describes the occupational

health and safety aspects of mining and

the socioeconomic effects on communities that can be expected from increased

coal use.

Chapter VII reviews current legislation

regulating coal production and use,

Chapter VII I analyzes policy dilemmas

that accompany coal development and

outlines Federal policy options in the

areas of environment and health, community impacts, labor-management relations,

occupational health and safety, and coal

leasing,

OVERVIEW

This overview focuses on the elements of the

report most useful to policymakers. It discusses the reasons for expecting coal use to

grow rapidly and the manner in which that

growth may occur. It then describes the expected environmental and social impacts.

These impacts have been addressed by a number of Federal policy initiatives. Because such

Federal actions will influence future coal development, they are discussed in the context of

all other factors that wilI affect coal production and use. Finally, policy options are outlined that might be considered either to encourage coal use or to curb remaining adverse

impacts.

Energy and the Role of Coal

The importance of coal must be gauged in

the context of the energy system of which it is

a part. Both the demand for energy in general

and the supply of other fuels wilI affect the use

of coal. Energy demand depends on the efficiency of use and the level of demand for

goods and services that consume energy.

Rising population and real gross national product will increase demand, while increases in efficiency of use in response to higher prices and

Government policies will reduce it. Most estimates of energy demand in 2000 falI between

100 and 150 quadrillion Btu (Quads), compared with 73.1 Quads used in 1975, The upper

end of this range is becoming increasingly

unlikely because of a leveling off of population, rapidly increasing efficiency of use, and

indications that many of the goods and services that consume energy are reaching saturation levels.

Coal’s share of future energy demand will

depend on its availability, cost, and attractive-

.
Ch. I—Introduction and Overview ● 5

ness as compared to alternative fuels, Total

U.S. petroleum and natural gas production

cannot expand much and may well decline by

2000 unless ways are found to tap presently

uneconomical resources such as geopressurized gas Thus oiI and gas are Iikely to continue

to be discouraged as fuels for powerplants,

leaving coal and nuclear energy as the only

two commercial options for electric utilities.

Nuclear power will expand rapidly as reactors

on order are completed, but further growth

faces uncertainties in public acceptance,

costs, scheduIes, and (possibly) uranium supplies. Specific site characteristics such as proximity to coal and environmental factors will affect future selections As coal and nuclear are

generally competitive, policy decisions affecting one may well influence the other.

Oil, gas, and electricity will be coal’s major

competitors in the industrial and residential/

commercial sectors. Solar energy and other

new fuels have great potential, but economics

and the logistics of expansion may delay extensive use until the next century. Coal use by industry will be increased by legal restrictions on

future oil and gas use. Requiring smaller users

to shift to coal will incur problems of high

costs and less effective polIution control. New

technologies such as fluidized-bed combustion

(FBC), thoroughly cleaned coal, and synthetic

fuels may be necessary if small facilities are to

increase greatly their use of coal The residentiallcommercial sector wilI be especially deterred by the inconvenience of delivery, storage,

and ash disposal. Without rapid growth in central heating plants, the residential sector will

only SIightly increase coal consumption as

long as other fuels are available

Achieving a 150-Quad energy supply by 2000

wouId calI for a very successfuI oiI and gas discovery rate, substantiaI imports, an upsurge i n

orders for nuclear powerplants, and an all-out

expansion of coal Problems with any of these

wouId preclude such a rapid expansion of supply.

Most energy scenarios assume a rapid expansion of coal. By 2000, production could be

two to three times the present level. The regional distribution of production (in millions

ot tons) for this range is estimated as follows:

Year

1977 1985 2000

Surface mines

Appalachia 185 130-155 130-175

Midwest 91 75-95 95-135

West 141 415-495 700-1,005

Total 417 620-745 925-1,315

Underground mines

Appalachia 205 225-260 380-505

Midwest 54 60-80 120-180

West 13 50-60 80-110

Total 272 355-400 580-795

Total

Appalachia 390 355-415 510-680

Midwest 145 135-175 215-3-15

West 154 460-510 780-1,115

Grand total 689 955-1,145 1,505-2,110

The sharpest increases in coal consumption

wiII be i n the West-Central and Mountain regions. All regions east of the Mississippi (except New England) will sustain a more gradual

growth in their already comparatively high

consumption. By 2000, consumption will be

much more evenly distributed than now with

all regions except New England and the Pacific

States burning large quantities,

The actual level and distribution of production and combustion will depend largely on

the costs of production, transportation, and

combustion. Surface mining is generally

cheaper than underground mining. Large

mechanized mines exploiting thick seams enjoy substantial cost advantages over smaller

mines working thin seams. For example, new,

western surface mines might produce coal at

$5/ton while an Appalachian underground

mine could have production costs of $30. The

increasing share of Western coal will keep

average coal costs down, but transportation

costs can be significant if the shipping distance

is more than a few hundred miles. Thus, Western coal is not necessarily competitive with

Eastern coal for a particular site. Combustion

costs depend on coal characteristics and the

technology to accommodate them. For example, boilers burning high-sulfur or high-ash

coals require more expensive control equipment. Coal characteristics vary widely even

within a seam, but can be characterized

roughly by region, In general, Eastern coal has

a high heat content but often has a high concentration of sulfur. Midwestern coal is slight-
6 ● The Direct Use of Coa/

Iy lower in heat value and higher in sulfur,

while Western coal is lowest in heat value and

sulfur. These factors are weighed by potential

users. Policy initiatives affecting these costs

(e. g., limits on sulfur emissions) influence decisions of whether to use coal and where to purchase it.

Environmental Impacts and Controls

if coal does indeed stage the comeback that

has been forecast, it will return to prominence

in a manner vastly different from the way it

dominated national energy use in the past. The

availability of pollution controls, better combustion techniques, and new mining methods,

coupled with enforcement of a wide range of

environmentaI protect ion requirements,

should prevent a repetition of much of the environmental degradation — soot-laden cities,

scarred landscapes, ruined and discolored

streams — that accompanied coal development

in the past. However, despite the laws and new

equipment and techniques, large-scale coal development may still be accompanied by substantial environmental impacts. Some of these

impacts could result from inadequacies in the

enforcement of the laws or in the environmental controls. Other impacts may result

from the failure to regulate a damaging pollutant or to specify an adequate level of protection from a regulated pollutant. These kinds of

failures usually result from inadequate knowledge: the inability to recognize a subtle but important impact, to connect a known impact to

its correct source, or to determine properly the

quantitative relationship between impact and

source.

This very real deficiency in our knowledge

of environmental processes makes it difficult

to determine whether current plans for coal

development could cause unacceptable environmental impacts. Some of the more spectacular impacts that have been attributed to

coal development — for example, the warming

of the Earth’s atmosphere by increasing levels

of carbon dioxide (COZ

) (a possible long-term

effect), or the thousands of premature deaths

attributed to the particulate sulfate products

of sulfur dioxide (SOZ

) emissions (an effect said

to be occurring now)— represent risks rather

than certainties. Scientists disagree sharply on

the extent of the risks, greatly increasing the

difficulty of developing environmental

policies. Part of this disagreement involves

sharply differing opinions about the quality of

data and the validity of analytical methodology. Part also involves more basic philosophical differences about the nature of “proof.’:

Because many environmental relationships are

drawn from circumstantial and statistical

evidence, considerable judgment must be used

in determining when a “postulated” relationship turns into a “probable” one, and finally,

into a “proven” one. The long fight to conclusively prove a relationship between smoking and cancer is a classic example; many environmental cause-and-effect relationships

follow the same Iines.

Finally, one additional problem with predicting environmental impacts is that their

magnitude depends on the effectiveness of

pollution control systems, and this can change.

The regulatory systems often will respond to

newly perceived environmental threats by requiring more stringent controls. Because it

cannot be predicted how weiI the future environment wilI be monitored, the extent to which

ongoing research will discover new evidence

linking particular pollutants to specific impacts, or how policy makers will respond to

such evidence, the discussion below focuses

on the effects of coal development under the

current regulatory system and attempts to

place the postulated, probable, and proven environmental impacts into perspective. However, virtually all of the most severe of the impacts described below are capable of being

mitigated or eliminated by controls that are

available today or are under active development.

Impacts on Air Quality

Although the mining and transportation of

coal can cause local air pollution problems

from fugitive dust (from mining operations,

storage piles, and coal hauling) and noxious

fumes (from smoldering mine fires), the major,

national air quality impacts from large-scale

coal development will come from the combus-
Ch. I—Introduction and Overview 7

tion portion of the fuel cycle— from coal-fired

powerplants, industrial boilers and furnaces,

and commercial space-heating plants. The air

pollutants released in large quantities by combustion units include the oxides of sulfur,

nitrogen, and carbon, as well as particles of

ash that become entrained in the hot flue

gases. Smaller quantities of trace inorganic

elements, radionuclides, and hydrocarbons are

also emitted; these are often adsorbed on the

surface of the ash particles.

Of the major pollutants, SOX and nitrogen

oxides (NOx - in the form of S02 and nitrogen

dioxide (NO,)– and particulate matter are controlled directly by Federal law. The present

strategy for regulating these pollutants under

the Clean Air Act combines a series of “local”

control levels— incorporated in State implementation plan (S1P) requirements to meet National Ambient Air Quality Standards (NAAQS)

and Prevention of Significant Deterioration

(PSD) requirements–with New Source Performance Standards (NSPS) that set nationwide emissions limits on large new polIution

sources. In general, the regulations are

directed at the chemical form of the pollutants

as they are emitted from their source, and are

focused on maintaining air quality requirements within a local air quality control region.

Unfortunately, the pollutants are neither

chemically nor physically static within the atmosphere. Most are subject to complex chains

of chemical transformations, with the importance of each reaction depending on the

presence of catalysts, intensity of sunlight,

degree of humidity, and other factors. Physical

processes are also at work, mixing the pollutants and at times carrying them far from their

source until they are removed from the atmosphere by settling, by colliding with terrestrial

surfaces, or by being “washed out” by rainfal1.

Examples of long-range transport include instances of “hazy blobs” of urban pollutants

crossing the boundaries of several States and

persisting for periods of a week or more, and

elevated levels of sulfate particulate in Pennsylvania that originate with SOZ emission s

from a cluster of coal-fired powerplants in the

Ohio River Basin that are alined with the prevaiIing wirids.

Two key problems are created by this longrange transport and transformation:

1. Areas can experience episodes of poor air

quality caused by pollution sources that

are outside their jurisdictional boundaries

and thus essentially beyond their control

under the current reguIatory system.

2. The pollutants that may be present in the

air and that may be doing the most damage are not necessarily the same as the

pollutants being regulated. Controls on

the “primary” emitted pollutants may not

be effective on the “secondary,” transformed pollutants.

A major reason why Federal regulatory strategy does not explicitly take these factors into

account is that the analytical ability to trace

pollutants from source to “receptor,” through

both chemical transformation and long-distance physical transport, is inadequate. Moreover, the identification and measurement of

the physical impacts of these secondary pollutants are often disputed. To identify specific

problems, each of the major pollutants, its

transformation products, and its impacts is

examined in turn.

Sulfur oxides have received more attention

than any other emission from coal combustion, primarily because of the large quantity of

emissions, the diversity and controversy surrounding its impacts (human health effects,

acid rain, crop damage, etc.), and the great expense involved in S0x controls. Coal combustion is now, and is likely to continue to be, the

major source of SOX emissions in the United

States. Although existing coal combustion

sources will be coming into compliance with

local regulations in the next few years and new

sources will be subject to strict NSPS, the expected expansion in coal combustion should

prevent total S0x emissions from continuing to

decline significantly in the next decade and

should cause them to rise (although slowly)

thereafter.

The SO, that emerges from the stack of a

coal-fired boiler is either removed (primarily
by impaction in an area close to its source)

from the atmosphere or transformed into sulfuric acid or to some other form of sulfate ion.

These sulfates tend to be transported over a

wide area and are removed predominantly by

rainfall. Transport of sulfates over distances of

hundreds of miles is not uncommon.

The major effect of the locally deposited

S 02 is to damage crops and forests during

meteorological conditions that cause the

“plume” (column of exhaust gases from the

stack) to touch the ground. Lower plant species

may suffer severe losses downwind of coalburning facilities, while a wide variety of crops

are damaged when other pollutants react with

SO,. However, these effects should not increase greatly in severity on a-nationwide basis

because of the relative stability of S02 emissions for the next few decades and because

new powerplants will operate with S02 scrubbers.

The major effects of the sulfate transformation products are continuation and possible

aggravation of the effects of acid rain (discussed below) and the possibility of major

human health effects. Both of these are excel lent examples of research inadequacies;

scientists as yet cannot credibly describe the

relationship between emissions and the ambient concentrations that may occur far from

the pollution source, and do not agree on the

magnitude of the impacts. Improvement and

verification of some existing long-range air

pollution models may soon allow acceptable

predictions of ambient concentrations caused

by distant sources. This would still leave

unresolved the prediction of the environmental and health impacts from these concentrations.

The estimation of human health effects

from sulfates or from any air pollutant is extraordinarily difficult. Short-term tests on

cultures and tests on animals can employ high

levels of pollutants and thus can measure easily identifiable acute effects; however, the

relevance of these effects to human beings is

uncertain. Clinical studies utilize human subjects but only at low levels of concentration;

the impacts that are measured are not easily

translatable into estimates of more dangerous

effects at high concentration levels or at low

levels over long periods of time. Human epidemiological studies have tended to suffer from

problems with heterogeneous populations,

poorly measured pollution exposures, and

muItiple polIutants.

A series of epidemiologic analyses of the

relationship between mortality rates and air

pollution in several American cities has linked

current levels of sulfate (and particulate) concentrations to tens of thousands of premature

deaths yearly in this country. These analyses

suffer from the generai problems associated

above with most epidemiological studies as

well as inadequate data on those population

characteristics that might affect the death

rate, and they have been rejected on these

grounds by many health scientists. However,

the arguments advanced by these scientists are

inconclusive and have not invalidated the

analyses. It remains a possibility that existing

levels of air pollution are causing significant

numbers of deaths. (Sulfate should be considered as a pollution indicator rather than as

necessarily the prime cause, although presumably the causative polIutants are produced

in association with the sulfate precursor, SO Z

.)

If the relationship between current levels of air

pollution and large numbers of premature

deaths were proven, or if it were perceived as

proven by a politically significant portion of

the population, future coal development

could be substantially affected by demands

for restrictions on development, deliberate

shifts to alternative energy sources, or increases in pollution control requirements and

cost.

Although coal combustion is now secondary

to automobiles as a source of Nitrogen oxides,

the present inabiIity of coal-fired boilers to reduce their uncontrolled emissions by more

than about half will yield a substantial increase— perhaps 20 percent by 1990— in total

U.S. NO, emissions (unless more efficient controls are developed and used) despite further

cleanup of automobiIe exhausts.

The threshold for almost all observed effects

on ecosystems is well above the NOZ levels in

most U.S. cities, and the forecast increase in

emissions should not cause significant new
Ch. 1—Introduction and Overview ● 9

damage from NO,. However, NO, is a precursor of photochemical oxidants such as ozone

and peroxyacyl nitrates (PAN). Oxidants are

the most damaging air pollutants affecting

agriculture and forestry in the United States.

Elevated ozone concentrations caused by

long-range transport from urban areas have

become a regional problem throughout the

United States, causing widespread damage to

crops on both coasts. However, the relationship between N02 emissions and oxidant formation is not well understood; thus, although

increased N02 emissions may be expected to

cause some increased oxidant formation and

subsequent ecosystem damages, the severity

of this outcome is highly uncertain.

The transformation of SO, and NO, into

acid suIfate and nitrate and the long-range

transport of these acid products can damage

the environment by producing acid rain. The

transformation products of SOZ and NOZ m a y

be the major contributors to the current acidity of rainfall over most of the Eastern United

States. The resulting increases in the acidity of

lakes have seriously degraded some aquatic

ecosystems, Although acid rain has been

shown to affect individual components of the

terrestrial ecosystem, it has not been proven to

affect that ecosystem to the same extent that

it clearly affects aquatic systems. However,

postulated associations of acid rain with some

ominous trends (such as declining forest

growth) and potential impacts (such as leaching of toxic metals and damage to nitrogen-fixing bacteria from increasing soil acidity) suggest an urgent need for more research on acid

rain effects. The problem is especialIy important in the Northeastern United States. The

Southwest, which will absorb substantial

amounts of acid sulfate and nitrate, will not be

as troubled because its soil and water are predominantly alkaline.

Because of the widespread use of electrostatic precipitators (ESPS) that remove large

particles with high efficiency but are less efficient in controlIing smalIer particles, any ecosystem impact of particulate emissions from

coal-fired powerplants will be caused almost

exclusively by fine particulate and the associated trace elements and hydrocarbons that are

adsorbed on their surfaces. Although total particulate emissions will be substantially reduced in the future as a result of strict controls

on new plants and progress in obtaining conformance with State regulations for existing

plants, emissions of fine particulate may increase unless controls are installed that are

equally effective for al I particle size ranges.

The physical characteristics of fine particulate make them candidates for potential

ecosystem and health damages, but virtually

no data exist to verify such effects. Speculation about ecosystem damages is based on the

potential for alteration of normal soil processes associated with nutrient recycling and

with soil micro-organisms, as well as a small

amount of evidence of trace hydrocarbon

damage to aquatic systems. Similarly, there is

a speculative potential for a human health impact based on the ability of fine particulate to

penetrate the lung’s defenses, and the coating

of toxic materials on the particles. The same

types of controversial epidemiological studies

that have implicated sulfate as being associated with premature deaths have also implicated particulate.

in recognition of the possible health implications of increasing fine-particulate emissions, the 1977 Clean Air Act amendments require the Environmental Protection Agency

(EPA) to study the health effects of fine particulates, associated trace elements, and

polycyclic organic matter (POM) and to establish regulatory controls for these pollutants if

necessary.

Both the fine particulate directly emitted

from coal combustion facilities and the particulate sulfate that are the transformation products of SOZ emissions are effective in scattering Iight and thus causing a degradation of visibility. The Southwest in particular would appear to be vulnerable to this damage, because

regional shifts in power generation will add

considerably to its pollution burden, and its

vistas are an important resource. Although

Federal PSD restrictions are designed in part to

protect western visibility, the state of the art in

predicting the visibility impacts of new coal-
10. The Direct Use of Coal

fired powerplants–or of any light-scattering

particles — is not well advanced. Although visibility impacts may occur hundreds of miles

from a large source, EPA has specified 50 km

as the maximum distance over which current

air quality models are credible for evaluating

the effects of new pollution sources—and

most modelers would consider this an optimistic assessment of the state of the art. Thus, the

restrictions on visibility reductions will be difficult to enforce, until acceptable long-range

transport and visibility models are available.

Most of the impacts discussed above would

originate from large coal-fired powerplants or

industrial boilers. Few predictions of energy

growth expect major increases in coal combustion by small residential and commercial

boilers or furnaces. Small boilers or furnaces,

if poorly maintained, can experience incomplete combustion and generate elevated levels

of hydrocarbon emissions. A major worry in

such a situation would be increased generation

of POM, some species of which are carcinogenic. Because these emissions would tend to

come from low stacks, possibly in densely

populated areas, special attention must be

paid to these units if larger than expected

growth of direct coal use occurs in the residential and commercial sectors.

Despite the serious uncertainties involved in

identifying air pollution impacts and their

causes, all but one of the major pollutants

from coal combustion have sufficiently recognized impacts and means of control to have

warranted Federal regulation of their emissions. The exception is Carbon dioxide, which

at current and expected ambient levels displays no direct or immediate adverse impacts

on human health or on the biota but may conceivably represent the greatest long-term

danger from an increase in the use of coal or

other fossil fuels. Fossil fuel combustion over

the past century appears to be a major cause

of increasing concentrations of COZ in the

Earth’s atmosphere (deforestation may be

another major cause); C02 levels have increased 5 percent since 1958 alone. Some predictions show CO, concentrations as doubling

by the middle of the next century. This could

present a substantial risk of significant climatic change, because COZ in the Earth’s atmosphere has a “greenhouse effect, ” allowing

incoming sunlight to warm the Earth’s surface

but trapping outgoing heat radiation. Effects

of such a climate change, if it occurred, could

include massive shifts in the productivity of

farmlands as well as partial melting of the

polar icecaps and flooding of coastal cities.

Current gaps in our understanding of how climate is regulated and how COZ is cycled between its sources and reservoirs leave this issue

surrounded by considerable uncertainty.

Although the problem is widely perceived by

the scientific community as potentially serious, some scientists believe that any effect

would be overwhelmed by the natural climatic

cycle that may be moving the Earth to a cooler

future climate. A further critical aspect of the

problem is the apparent lack of a practical

CO, emission control technology for fossil

combustion. Should control of CO2 be judged

necessary, the available options are to reduce

worldwide fossil fuel combustion (by energy

conservation and switching to alternative

energy sources) and to stop ecosystem changes

(especially deforestation) that might be aggravating the problem.

As discussed above, each of the pollutants

generated by coal combustion will have

proven or postulated environmental and/or

health impacts, even with the level of pollution control currently required by Federal,

State, and local regulations. Our inability to

assess accurately the level of impacts and their

economic and social values leads to extreme

difficulty in selecting appropriate levels ‘of

control. These inadequacies partially explain

the Federal strategy of choosing the “best

available control technology” instead of using

an approach that would select control levels

more oriented to weighing costs and benefits.

Whichever approach is chosen, the selection

of controls clearly requires an understanding

of the control options and the associated costs

and difficulties.

Feasible control options are available for

three of the four major pollutants generated

by coal combustion– particulate, SO2, and

NO,. The fourth, CO2 can theoretically be

scrubbed out of the flue gases, but the quanti-
Ch. l—introduction and Overview ● 11

ty of absorbent required and volume of waste

products generated appear to be too large for

serious consideration.

Control of SOX emissions from large coal

combustion sources can be accomplished by a

variety of measures, including selection of

low-sulfur coals, coal cleaning, flue-gas desulfurization (FGD), and several new combustion

technologies. E PA’s proposed NSPS for coalfired electric utilities would guarantee that virtually all new powerplants would use FGD

(scrubbers) to reduce S0, emissions. However,

stringent control of new plants and achievement of full compliance with SIP requirements

for existing plants will not substantially reduce

the 30 million or so tons of S0x emitted annualIy in the United States, because the S I P requirements are often not very severe. Powerpiants, which have tall stacks, can in many circumstances emit very large amounts of pollutants without seriously affecting local air quality. In some instances, plants are burning relatively high-sulfur coal without controls even

though they are in full compliance with their

SIPs. Thus, there is considerable room for further reduction of SOX emissions if such a

reduction were dictated by national policy.

The scrubbers required on all new powerplants are expensive to build and operate. The

scrubber system on a 500-MW powerplant

might cost $50 milIion to $75 million out of a

total plant cost of $400 million, and add 0.4 to

0.8 cents to each kilowatthour of electricity

the plant produces. Furthermore, Iime/limestone scrubbers, the systems that currently

dominate the utility market, are throwaway

processes and therefore generate wastes that

are themselves considered a significant environmental problem. This problem is discussed in more detail in the next section.

Scrubber installations in this country have

been beset by many significant operating problems, including extensive scaling of surfaces,

failure of stack linings, corrosion and erosion

of critical components, and plugging of orifices. The utility industry generally considers

scrubbers to be an unreliable technology and

an inefficient means of achieving control of

S0x. There is available evidence, however, that

U.S. utility operators can comply with proposed NSPS requirements for SO, removal efficiency and reliability. For instance, Japanese

scrubber experience with medium-sulfur coal

(the energy equivalent of 3 percent sulfur U.S.

coal) and operating conditions similar to those

in U.S. plants has been extremely successful,

achieving reliabilities and control efficiencies

in excess of 90 percent.

Alternative means of controlling S0x are

available or under development for use on new

and existing coal-fired powerplants. Some of

the alternatives offer reduction in NOX and/or

particulate in addition to S0x control.

Further control of existing powerplants can

be accomplished by using low-sulfur coal or

coal that has been physically or chemically

cleaned. Options that may become suitable

for new plants include solvent-refined coal

(SRC-1, the solid form, which is the only one

considered in this report), combined-cycle

powerplants using liquid and gaseous fuels

from coal, and fluidized-bed combustion

(FBC). SRC-I and FBC may also become useful

in promoting environmentally sound coal use

in smaller industrial and commercial units. Advanced electrical generation systems are

undergoing R&D but do not appear to have the

potential to make a serious impact on energy

use for at least the next several decades.

The extent of application of these alternatives depends on their costs. Except for lowsulfur coals, state-of-the-art FGD systems, and

mechanical cleaning systems now in use, the

costs of the alternatives are specuIative.

Control of NOx is currently accomplished by

design modification and adjustment of operating conditions rather than using “add-on”

controls. Effective techniques for minimizing

N OX emissions are staged combustion, which

reduces excess air in the boiler, and burner

designs which delay mixing of fuel and air.

Combinations of these and other strategies

have succeeded in lowering NOx emissions

from large utility boiIers by 40 to 50 percent.

Although gas-cleaning systems for NOx control are not currently used in this country, a

number of processes are under development.

The Japanese are the most advanced in this
12 . The Direct Use of Coal

field. These processes included injection of

ammonia or various solids into the combustion

chamber, and scrubbing of the flue gases using

absorbents such as magnesium oxide. Capital

costs of these systems are said to be of the

same order of magnitude as FGD.

EPA is developing a IO W- N OX burner for

coal-fired boilers that it hopes will be inexpensive and effective. (EPA hopes for an 85-percent emission reduction relative to an uncontrolled boiler. ) If successful, the burner could,

by the late 1980’s, cut back sharply on predicted rises in NOx emissions.

High efficiency control of particulate has

been a long-term practice in the electric utility

industry, the dominant user of coal. Although

mechanical or cyclone collectors were extensively used in the past, ESPs are the collection

technology on most coal-fired utility boilers

today. ESPs collect particulate by charging

the individual particles and collecting them on

plates to which a powerful opposite charge has

been applied. They often can attain collection

efficiencies of over 99 percent.

Requirements for control of SOX emissions

from coal combustion and resulting increased

use of low-sulfur coal have created problems

for ESPs. The ash particles from low-sulfur coal

are usualIy of high resistivity and are not easily

charged and collected by the ESP. Degradation of performance from a shift to low-sulfur

coal can be extremely severe, with particulate

emissions increasing tenfold or more. Designers of new powerplants have attempted to

solve this problem by increasing the size of the

ESPS or installing them at a hotter (lower resistivity) part of the exhaust cycle, or by using

controls that depend on the mechanical rather

than electrical properties of the particles.

These “mechanical” controls include wet

scrubbers and baghouses (fabric filters).

Although these options may be available to

some existing plants, many plants have space

limitations or want to avoid large capital expenditures because of their limited remaining

operating life. Flue gas conditioning, which involves the injection of a chemical into the flue

gas to coat the particles and reduce their resistivity, may be an attractive option for such

plants (although questions have been raised

about increased gaseous emissions caused by

these systems).

The proposed Federal requirements for particulate control are said to be too stringent to

be universally met by ESPS. Compliance with

the proposed requirements (a particulate NSPS

of 0.03 lbs/million Btu of heat input) for utility

boilers burning low-sulfur coal may require the

use of baghouses. However, baghouses are a

relatively untried technology for large coalfired boilers. A few systems have been installed or ordered for such plants. The experience of these plants will be influential in determining the future direction of particulate control in the utility industry.

The choice of technology is particularly important in terms of controlling fine particulate and trace elements. ESPS are not efficient collectors of “respirable size” particles,

and a continuation of current particulate-control technology could lead to substantial (and

potentially dangerous) increases in fine-particulate emissions over the next several decades.

Baghouses, on the other hand, can be designed

to collect fine particles at greater than 99-percent efficiency.

Impacts on Land and Water

In contrast to the impacts of air pollution,

most impacts of water pollution, solid waste

disposal, and land disturbance are more concentrated geographically. They are controlled

less by technological devices than by adjustments in operating procedures, and the degree

of control obtained is often extremely dependent on local conditions. Thus, appropriate enforcement and careful monitoring are especially important to the success of controlling

these impacts.

In the past, coal development in general,

and mining in particular, were often devastating to both land and water ecosystems. The

major damage from mining was caused by the

acid drainage from both underground and surface mines, the lack of adequate restoration of

surface-mined Iand, and the subsidence of

lands overlying underground mines. Ecological

damage also resulted from the heating of surface waters by powerplant cooling systems.
Ch. I—Introduction and Overview . 13

All of these impacts are now addressed by

Federal legislation. As a result, some problems— in particular, acid mine drainage from

large active mines, and powerplant thermal

pollution — have been virtually eliminated as

significant problems for future development.

All of the others have been reduced, although

substantive problems of enforcement and/or

availability of effective controls remain. Also,

some new problems may resuIt from the regional shift of coal production to areas where

little experience can guide new operations,

and from the generation of waste products

from air pollution control measures.

Mining.–Approximately 60 percent of national coal production comes from surface

mines, and the proportion will not rise much.

The use of new mining methods that integrate

reclamation into the mining process and enforcement of the Surface Mine Control and

Reclamation Act (SMCRA) should reduce the

importance of reclamation as a critical national issue. However, concern remains that

the combination of development pressures

and inadequate knowledge may lead to

damage in particularly vulnerable areas—

alluvial valley floors in the West, prime

farmland in the Midwest, and hardwood

forests, steep slope areas, and flood-prone

basins in Appalachia. Although most of these

areas are afforded special protection under

SMCRA, the extent of any damage will depend

on the adequacy of enforcement of the new

strip-mining legislation. Assuming strong enforcement of SMCRA, no major problems with

acid mine drainage from active surface and

underground mines shouId result from increased coal development. However, inactive

mines may stiII present some technical control

problems. Although a very small percentage of

inactive surface mines may suffer from acid

seepage, problems with underground mines

should be the primary problem. Despite a long

history of Federal and State efforts aimed at

controlIing acid drainage from inactive underground mines, some mining situations do not

al low adequate permanent control once active

mining and water treatment cease. A significant percentage of the mines that are active at

present or that will be opened in this century

will present acid drainage problems on

closure, This problem may taper off as

shallower reserves are exhausted and new

mines begin to exploit coal seams that are

deeper than the water table. Many of these

mines wilI be flooded, allowing the seams to

be shut off from the oxidation that creates the

acid drainage.

Another impact of underground mining that

will not be fulIy controlled is subsidence of the

land above the mine workings. Unfortunately,

there are no credible estimates of potential

subsidence damage from future underground

mining. Subsidence, Iike acid drainage, is a

long-term problem. However, SMCRA does not

hold the developers responsible for sufficient

time periods to ensure elimination of the problem, nor does it specifically hold the developer

responsible to the surface owner for subsidence damage. The major “control” for subsidence is to leave a large part of the coal resources — up to 50 percent or more — in place

to act as a roof support, There is obviously a

conflict between subsidence prevention and

removal of the maximum amount of coal.

Moreover, the supports can erode and the roof

CO I lapse over a long period of time. The resulting intermittent subsidence can destroy the

value of the land for development. A second

“control” technique — IongwalI mining — actually promotes subsidence, but in a swifter and

more uniform fashion. Longwall mining is

widely practiced in Europe but is in Iimited use

in the United States. It is not suitable for all

situations,

Although all types of mining have the potential to severely impact ground water quantity

and quality by physical disruption of aquifers

and by leaching or seepage into them, this

problem is imperfectly understood. The shift

of production to the West, where ground water

is a particularly critical resource, wilI focus increased attention on this impact. As with other

sensitive areas, SMCRA affords special protection to ground water resources, but the adequacy of this protection depends on the state

of knowledge about the problem and on the

level of enforcement,

Impacts of Combustion and Waste Disposal.

The major impact of coal-fired combustion

sources on the land and water stems from the
14 . The Direct Use of Coa/

secondary effects of environmental controls —

the effects of cooling tower blowdown and

water consumption, and those of the waste

products collected by air pollution controls.

Most powerplants built in the future will use

closed-cycle cooling, so that thermal damage

from once-through cooling systems will not be

an impact of future coal development. However, the concentrated salts, or “blowdown,”

from these closed-cycle systems are discharged into the Nation’s waterways. The dissolved solids discharged by coal-fired electric

utilities, of which blowdown is the predominant source, are nearly 20 percent of the total

national dissolved solids discharge. Although

effluent limitations have been established

under the Clean Water Act, increases in utility

coal burning will play an important role in the

expected substantial growth in the discharge

of dissolved solids in the South Atlantic, Midwest, North-Central, and Central regions.

An additional impact of closed-cycle cooling systems results from their water consumption, which is approximately double that attributed to once-through cooling. Although the

magnitude of consumption for a particular faciIity varies with location, a 3,000-MW powerplant can be expected to consume between

20,000 and 30,000 acre-feet per year (mostly

for cooling). If a number of these plants are

built in the arid portions of the West, their

water requirements could exacerbate existing

water problems in several river basins — for example, in the Upper Colorado and Yellowstone. Reduced flows can interfere with the

rivers’ assimilative capacity and in some extreme cases damage or destroy ecosystems

from sheer lack of water. This problem is as

much institutional as physical, because much

of the water consumption in the West results

from existing water allocation and pricing procedures that undervalue the water; the absence of a comprehensive Federal water policy

hinders the resolution of these problems. Furthermore, technological means (dry or wet-dry

cooling systems) are available to sharply

reduce powerplant water consumption,

although the systems are expensive and lower

plant efficiency.

The impacts caused by the disposal of powerplant waste heat into the environment are

relatively independent of the fuel source, although impacts from the current generation of

nuclear powerplants will be somewhat higher

per kilowatt than those of similarly sized fossilfired plants because of the nuclear plants’

lower efficiency. Thus, the effects of blowdown and water consumption should be attributed to electricity demand rather than specifically to coal use.

Both the particulate control devices and S02

scrubbers on coal combustion faciIities produce massive quantities of wastes (projected

to be approximately 80 million tons of ash and

slag and 20 million tons of sludge by 1985, or

fully half of the Nation’s total noncombustible

solid waste and industrial sludge), which can

cause land use problems and environmental

damage unless properly managed.

A 1,000-MW powerplant may require a disposal area of 500 acres or larger for a 30-year

period, even assuming that the sludge is dried

and the wastes are 20 feet thick. However, the

land use problem posed by this requirement is

eased by the Iikelihood that most new powerplants will be built outside of densely populated areas, where more land is available.

The major environmental problem associated with waste disposal is the contamination

of surface and ground waters by leaching of

trace elements from the ash and sludge.

Although the ash contains by far the greater

amount of trace elements, the fluid that is

trapped in the sludge also presents a significant leaching problem for years after disposal.

The actual environmental damage caused

by disposal of these wastes will depend on the

form of the regulations and the firmness of enforcement of the Resource Conservation and

Recovery Act (RCRA). Methods exist for reducing or controlIing the potentialIy severe impact

on ground water, but they are expensive and

are likely to be applied only sporadically

unless they are required by law; some may be

difficult to monitor and enforce. These methods range from lining of disposal ponds and
Ch. I—Introduction and Overview ● 15

landfills, chemical stabilization of the scrubber sludge, and alteration of the chemistry of

the scrubber (to create a more manageable

waste), to utilizing regenerable scrubber systems and virtually eliminating the sludge portion of the problem altogether. Designation of

ash and sludge as hazardous materials under

RCRA would force use of these controls, but,

according to the Department of Energy (DOE)

estimates, could almost double disposal costs

over present practices. (Industry thinks these

estimates are too low. ) A side effect could be

to eliminate some present uses of ash, such as

its use in roadbeds. Twenty percent of the ash

produced by the utility industry is constructively used rather than being disposed. Even

without a “hazardous” designation, however,

a rigorously enforced RCRA will force substantial changes in present disposal practices to

protect ground water.

Workplace and Community Impacts

Coal Worker Health and Safety

Coal mining has always been a hazardous

occupation. The 1969 Federal Coal Mine

Health and Safety Act addressed some workrelated health and safety hazards, explosions

and dust control in particular. But coal workers are likely to continue to suffer from occupational disease, injury, and death at a rate

well above other occupations, and the total

magnitude of these impacts will grow along

with the growth in coal production.

The mine-worker health issue that has received most Congressional attention is black

lung disease, the nonclinical name for a variety of respiratory illnesses of which coal

workers’ pneumoconiosis (CWP) is the most

prominent. More than 420,000 Federal compensation awards were made between 1970

and the end of 1977, costing the Government

more than $5.5 billion. The industry will pay a

greater share of the compensation costs in the

future as a result of the 1977 black lung legislation. Ten percent or more of workin g coa l

miners today show X-ray evidence of CWP, and

perhaps twice that number show other black

lung illnesses— including bronchitis, emphysema, and other impairments— some of which

are caused, or worsened, by cigarette smoking.

The prevalence of respiratory disease is probably less today than it was 10 years ago because about 50,000 older — and often disabled — miners have retired and about 150,000

new workers have been hired.

To prevent CWP from disabling miners in

the future, Congress mandated a 2-mg/m3

standard for respirable dust (the small particles

that cause pneumoconiosis). This standard was

based on British research done in the 1960’s

and is lower than any other country ’s. However, critics now question the inherent safeness

of this standard and the soundness of the British methodology. The safeness of the standard,

which was based on mathematical probabilities, must stilI be confirmed by long-term

epidemiological evidence. The Federal dustsampling program, which is intended to measure compliance with the standard, is not a reliable indicator of daily dust exposure. Many

opportunities for intentional and inadvertent

sampling errors exist. Sampling is so infrequent

and the timelag in reporting the results back to

the mine so great that sampling has Iimited relevance to actual dust control. A monitoring

program based on continuous sampling and

immediate correction may prove to be a more

useful approach. Because black lung compensation is costly and because several hundred

thousand more miners will be employed in the

next 25 years, it may prove useful to reassess

the safeness of the dust standard and to evaluate alternative dust-sampling procedures.

If respirable dust is controlled effectively,

CWP will be reduced and a major source of

black lung disease will have been addressed.

However, other sources and potential sources

of miners’ respiratory disability may require attention. Other coal mine dust constituents—

the large dust particles (that affect the upper

respiratory tract) and trace elements — deserve

additional research. Toxic fumes from mine

equipment fires and diesel emissions are hazards that may deserve regulation. Cigarette

smoking increases breathing difficulties in diseased miners and probably shouId be discouraged in this work force. Under the most optimistic assumptions, it is estimated that 11,000

to 18,000 working miners will show X-ray evi-
dence of CWP in 2000 and at least an equal

number will exhibit other respiratory impairment. Even more retired miners will have CWP,

and many will be disabled by it. If dust control

is not effective or adequate, disease prevalence will be higher and more cases of CWP

and black lung wilI be found.

Mine safety — as distinct from mine health —

has shown a mixed record of improvement

since the 1969 Act was passed. The frequency

of mining fatalities has decreased for both surface and underground mines, but no consistent

improvement has been seen in the frequency

of disabling injuries. Coal worker fatalities

numbered 139 in 1977, and disabling injuries

approached 15,000. Each disabling injury resulted in an average of 2 months or more of

lost time. The number of disabling injuries has

been increasing as more workers are drawn to

mining and accident frequency remains constant.

On the whole, surface mining is several

times safer than underground mining. But

some underground mines show safety records

equal to or better than some surface mines.

Generally, western surface mines are safer

than eastern surface mines. As western surface-mine production assumes increasing

prominence, accident frequency industrywide

is Iikely to decline when expressed as accidents per ton of output. But this statistical

trend may conceal no improvement or even a

worsening of safety in deep mines.

Post-1 969 mine safety performance is related to several factors. High-fatality mine disasters have been reduced substantially. Operator compliance with Federal safety standards

and frequency of inspection appear to be correlated with improved safety. Big, new mines

that have been opened since 1970 tend to be

safer than older, smaller mines. Greatly improved coal profitability in 1974 and 1975

coincided with the industry’s two best years in

reducing injuries. The emphasis on safe work

by the United Mine Workers of America

(UMWA) and Federal agencies were other important factors.

Labor-saving technology or different work

processes may or may not improve safety and

may conflict with improved health goals. The

introduction of continuous miners in the

1950’s raised productivity and lowered fatalities and injuries because the work force was

reduced by 70 percent. But the new machines

produced higher dust levels, which caused

higher rates of black lung. Longwall mining

systems appear to be more productive than

other units and safer in terms of fatalities, but

not in injuries. About half of the longwaIls

surveyed recently did not meet the respirable

dust standard. Speeding up the pace of work to

increase output is likely to increase accident

frequency. Improved workplace relations and

less absenteeism are likely to increase both

productivity and safety.

Mine-safety analysis is made difficult by

weaknesses in the recorded Federal data. Reporting practices are not uniform throughout

the industry. Some companies have adopted

light-duty policies (with respect to injured

workers) that allow them to report fewer disabling injuries. Some companies probably do

not report all injuries and illnesses. The Mine

Safety and Health Administration (MSHA) has

tightened its reporting requirements recently,

and better reporting should result.

As more coal is mined and more miners are

hired, the number of coal worker fatalities and

injuries is Iikely to increase even if accident

frequency improves somewhat. Depending on

future coal production levels, between 157 and

187 coal workers are likely to be killed and between 17,400 and 20,800 injured in 1985. That

represents a 13- to 35-percent increase in fatalities over 1977 and a 17- to 39-percent increase

in injuries. I n 2000, between 259 and 371 coal

worker fatalities are forecast and between

29,200 and 41,800 injuries. These estimates

represent an 86- to 167-percent increase in

fatalities over 1977 and a 95- to 180-percent increase in injuries. These calculations assume

no underreporting and undercounting. The 25-

year total (1976-2000) of mine fatalities may exceed 5,000 and injuries may exceed 500,000.

Reducing these numbers calls for action in

several areas that may conflict with increased

productivity. Federal policy should address

three main issues:
Ch. I—Introduction and Overview . 17

1. reducing the number and frequency of

disabling injuries,

2. assessing the safety costs of increased

production and productivity strategies,

and

3. reevaluating the effectiveness of existing

Federal enforcement programs.

Equipment can be designed with improved

safety as a factor. Broader Federal equipment

standards could help. Western and Midwestern

surface mining could be encouraged by Federal policy, but this emphasis would probably

have severe employment and price impacts in

the East. Predictable growth in coal demand

and steady profitability might be encouraged

to further enable companies to devote time

and money to safety and . health. Federal

inspections —the factor apparently most directly correlated with good safety— could be

increased. More severe sanctions against

chronic high-accident operations might be

considered. More effective safety and job

training, coupled with increased participation

of coal miners in safety and health efforts, may

also prove fruitfuI.

Community Impacts

Coal mining brings many diverse benefits

and costs to coalfield communities. The

private sector— mine operators, coal workers,

and local business— benefits from steady coal

output through profits, wages, and spendable

income, respectively. Private production costs

are paid by the mine operator. But when costs

are externalized, mine workers and local

private interests often pay them. These costs

can be measured in dollars, human health, and

environmental quality. Coal production also

entails public costs and benefits. Local communities will benefit from population growth

(at a manageable pace), more tax revenues, increased employment, and better services from

wisely planned coal development. On the

other hand, if growth is too rapid, communities

may be unable to expand services fast enough.

Even without much coal growth, the public

costs of past mining in Appalachia are substantial and deserve redress. Chronic community

underdevelopment exists throughout this

region and may impede rapid coal growth in

several dozen counties.

Coal development will occur in three different kinds of communities. Many Appalachian communities are hampered by the legacy

of historical underdevelopment. Coal-based

growth will continue the pattern of a “onecrop” economy with all of the costs and

benefits of that mode of economic development. In other Appalachian communities and

in the Midwest, coal will be mined in communities with diversified economies. The

social costs of coal development are likely to

be the least substantial there. In the West, coal

development will create boomtown growth in

some counties and towns. The extent of coal’s

social costs (both public and private) depends

on the rapidity of development, the adequacy

of existing public services, the ability of local

communities to manage growth, the level of

local public participation in coal development, the kinds of mines that are planned, and

the attitudes of mine operators and the local

citizens toward development.

East.–The Appalachian coalfields have produced more than 90 percent of all coal ever

mined in the United States. Because they never

experienced a sustained period of growth and

profitability, operators were forced to cut

costs simply to stay in business. Local jurisdictions were usually unable to raise sufficient tax

revenue to provide adequate public services

because taxes on coal might have handicapped the ability of local operations to compete. Roads, schools, water and sewage facilities, recreation, health care, and local public

administration suffered from this unwillingness or inability to tax adequately coal production and undeveloped coal reserves. The

cyclical nature of coal demand also made rational, public financial planning difficult. The

lack of diversified economies made spendable

income and public revenue in coal towns

almost totally dependent on the whims of demand for local coal. For most of the 1920-70

period, overall coal demand stagnated, which

meant that State and local tax revenues did

not increase greatly even during the short-1ived

booms. The company-town system, which was
18 The Direct Use of Coa/

the main form of community socialization

throughout most of the Appalachian coalfields, intensified community dependence on

local coal sales. Many of today’s coal towns

began as company towns. They have yet to

compensate for the public deprivations characteristic of their earlier underdevelopment.

On the other hand, whatever public infrastructure exists today in these communities stems

from coal development. Had coal mining not

begun 80 or 90 years ago, these counties might

have even fewer public services than they do

today. They would have small populations and

little industry. But they would also have few of

the social costs of coal development.

No significant net increase in Eastern coal

production is anticipated before 1985, although substantial production gains should occur thereafter. This interval can be used to

plan how coal development can be managed

best. Yet severe community overloads are already apparent in much of Appalachian coalfields, where the combination of existing inadequacies and thousands of new miners has

overwhelmed the ability of communities to

provide services.

Appalachia will experience two contrasting

patterns in the early 1980’s. Some communities

where metallurgical or high-sulfur coal is

mined are likely to continue to stagnate because of weak demand. Production will not increase, although the coal-related population

may grow. Historical patterns of underdevelopment will continue. Two to three dozen

counties may fit this pattern. For more than a

year, 10,000 to 15,000 Appalachian miners

have been working irregularly because of slack

demand. Little has been done to encourage

coal demand from these hard-hit areas or to

plan the economic diversification of their

economies (an even sounder long-term approach).

The opposite case will find boom-like conditions imposed on underdeveloped communities. Production and population will increase

rapidly. Spendable income and demand in consumer goods will rise. Demand for housing and

public services will increase sharply and may

not be met. Local tax resources may not provide needed public services. Production and

productivity may be slowed because of these

shortcomings. I n communities where underdevelopment is least, boom conditions are likely

to be most readily accommodated. Several

growth-related problems are worth identifying.

Housing is crucial to expanding coal production. Both the supply and adequacy of coalfield housing are deficient. Most coalfield land

is owned by coal producers or land-owning

companies, which generally refuse to sell land

suitable for housing. It is often uneconomic for

them to sell the surface rights to coal-bearing

land, and future liability for subsidence is also

a constraint. Consequently, coal field housing

supply is deficient and many areas have experienced severe congestion and inflated land and

housing prices. Private builders and mortgage

money are in short supply. The quick-fix “solution” to the lack of land and housing has been

the mobile home. This is widely seen as less desirable than single-family construction. The

lack of housing has made for long commutes

between home and workplace, which may contribute to absenteeism. To increase housing

SUpply, land and mortgage money will have to .

be made available. In many places, a housingconstruction industry must be assembled

almost from scratch. Increased flood-control

measures are necessary to permit building on

valIey fIoors.

Roads in the Appalachian coalfields are generally in poor condition. Most were badly constructed initially. The shortage of tax revenues

and heavy coal-truck traffic have left them in a

constant state of disrepair. Illegal overloading

of coal trucks is widespread and contributes

heavily to roadway destruction. To upgrade

the 6,880 miles of coal-haul roads judged inadequate to meet the current volume of coal

traffic would cost an estimated $4. I to $4.9 bilI ion, with another $600 million to $700 million

to replace inadequate bridges. Small fractions

of these sums are now spent on maintenance,

and even less on reconstruction and rehabilitation. Strict enforcement of maximum load

standards is necessary to take full advantage

of dollars used for road repair. Alternatives to

coal-truck haulage such as overland trams,

conveyor belts, and slurry pipelines would

limit future road damage and inconvenience.

Increased appropriations for road repair

(whether raised by general taxes or user taxes)
Ch. I—Introduction and Overview ● 19

are likely to be a less cost-effective— but a

necessary — option.

Other kinds of services and facilities are

often inadequate. Many towns have limited

water and sewage treatment systems — if they

have any at all. This constrains the development of private housing. Health care services

fall short of national standards. Recent refinancing of the UMWA medical plan appears to

have weakened coalfield health delivery systems. Public administration is competent in

some places, but planning, familiarity with

assistance programs and sol id local development strategies are often lacking. Opportunities for recreation and education are often

limited.

While some Appalachian coal communities

will be able to handle rapid coal growth with

little difficulty, many will not. It is difficult to

quantify the implications for Eastern coal production of community underdevelopment.

Common sense, as well as several recent

studies, suggests that the ability of the East to

produce more coal rests in part on controlling

the future social costs of increased production

and dealing with present inadequacies. To internalize fully the social and environmental

costs of coal mining, coal will have to be

priced to reflect its true costs of production.

Federal policy makers face difficult questions with respect to Appalachian coal development. The first is who should pay to rectify

coal’s accumulated social deficit. The general

public? Current coal consumers? Coal operators out of their profits? State and local

governments through coal taxes and generaI

revenues? Second is the question of how to

establish new patterns of economic development that will bring local social costs and

benefits into balance. Policy makers may wish

to examine alternative ways of accomplishing

this end, such as economic diversification

plans financed by revenues from coal development, public regulation of coal development,

and better planning. No Federal policy now addresses these complex issues, although the Appalachian Regional Commission and the President’s Commission on Coal are examining

them. If serious breakdowns develop at the

local level in the next few years, Congress may

wish to consider this matter systematicalIy.

Midwest.–Coal counties in the Midwest are

Iikely to be in a better position to benefit from

increased coal development than either Appalachia or the West. These counties generally

have diversified economies, which have made

them less vulnerable to coal’s booms and

busts. Because much of their tonnage will

come from surface mines, the rate of population growth is not likely to be excessive.

Because local tax revenues here were higher

than in Appalachian counties, community

services are generally better. As a rule of

thumb, it has been found that where coal mining has been the single, dominant economic

activity, communities are least prepared to

manage rapid coal development. Counties

where mining has been less prominent and

economics more diversified appear to be more

able to benefit from rapid development. Most

of the Midwest fits into this category.

West.–Significant Western coal production

is a recent phenomenon. Today, about 9,000

miners produce more than 20 percent of national production. Future growth will be rapid.

Between 34,000 and 42,000 miners will be

working in the West by 1985. Six States —Colorado, Montana, New Mexico, North Dakota,

Texas, and Utah–are each expected to add 55

million to 61 million tons more annual capacity by 1987, according to optimistic forecasts.

Wyoming may be able to produce more than

270 million additional tons by that year, although 147 million tons is a more plausible

estimate. Depending on how much actual production occurs, from 6 to 11 western counties

will experience population growth rates exceeding 5 percent annually. Four of these

counties are in Utah, where underground mining (with its comparatively high labor requirements) will take place. Mercer County, N.

Dak., and Campbell County, Wyo., are also

vulnerable. If coal production matches optimistic Industry predictions, two Colorado

counties and three Montana counties will also

show 5-percent growth rates. Towns in other

counties wilI also experience boom conditions.

Western towns have had varied degrees of

success coping with rapid coal growth. Some,
20 ● The Direct Use of Coa/

like Rock Springs, Wyo., reflect a range of

social problems and genera I community breakdown. Others, like Gillette, Wyo., have muddled through the initial boom problems and

are in the process of managing growth with

some success. Western towns often find themselves short of housing, water and sewage

treatment systems, health care facilities, and

front-end revenues. With some exceptions,

local tax revenues appear to be able to provide

needed services in the long run, although revenue shortages may be felt during the first 5

years or more of rapid growth.

Indian coal development presents special

issues. Although considerable tonnage may be

mined from Indian reservations, relatively few

new miners — perhaps several thousand — are

likely to be employed there. Most are expected

to be Indians already living on the reservations. Western tribes are now insisting on

Indian-preference in mine employment in their

reservations along with higher tonnage royalties. Boomtowns are not expected to occur

on the reservations, although several reservation towns may show high population growth.

Boomtown conditions are not likely to constrain Western coal production goals. But Federal policymakers must face questions concerning equity of sacrifice, responsibility for

controlling the social costs of private energy

development, and responding to local demands for assistance. As in much of Appalachia, many western towns will need to deal with

one-crop economies, rapid population growth,

and revenue shortages.

Social Impacts of Transportation

Coal transportation can be barely noticeable, or it can create a major disturbance — depending on means used and the route chosen.

About two-thirds of all coal is shipped by railroad. More fatalities result from coal transport

than from mining. New routes may have to be

selected to avoid populated areas. Grade

crossings will have to be improved to prevent

accident and disruption. Trucks are used for

short hauls, especially in Appalachia. They

contribute greatly to road deterioration, dust,

and highway safety problems. Barges and

slurry pipelines are probably the least disruptive modes but can be used only under special

conditions. An alternative to coal haulage is

electric transmission. Its major liabilities are

the health and safety concerns of high-voltage

electric fields (as yet unquantified) and the

visual impact of towers and rights-of-way. The

health issue is particularly controversial and

requires considerable research.

Impacts on Coal-Using Communities

Coal mining can easily dominate local communities, but combustion facilities tend to be

a much smaller— and more stable— part of

community economic activity. When a coalfired powerplant is built, several impacts

occur— increased wage income and employment, side by side with more air pollution and

disruption from transport. As the literature on

the social impacts of powerplant operation is

limited, this study surveyed public attitudes of

residents near three large powerplants. In all

cases, the respondents living within 3 miles of

the pIants found them objectionable. This attitude diminished rapidly with distance. The

most widely perceived disadvantage was air

pollution. The major perceived advantages

were employment and the availability of

energy. In general, slightly more than half the

respondents found the plants to be reasonably

acceptable neighbors.

Factors Affecting Coal

Production and Use

All of coal’s major supply factors — reserves,

labor, capital, and industrial infrastructure—

must be available to support greatly increased

production. From time to time, each may become a short-term bottleneck, as in the case of

a national strike. But none, either singly or

together, is expected to hamper the mining of

as much coal as can be sold over the next 25

years. However, attainment of the highest coal

scenarios could be precluded by any of several

factors. Many potential constraints will be

alleviated in the normal course of events.

Others may require special attention. These

factors are discussed below.
Ch. /—/ntroducfion and Overview c 21

Coal Availability and Leasing

Unlike other domestic fossil fuels, coal is

still plentiful. In the East, most coal reserves

are owned by producers or landowning corporations. About 65 percent of all coal reserves in the West, however, is owned by the

Federal Government and can be mined by private companies only under Federal lease. The

rest is owned by States, Indian tribes, or corporations. About 17 billion tons, or 5 percent

federally owned coal resources have been

competitively leased. This is far more than will

be mined over the next decade in the West, but

the characteristics of the tracts leased and the

needs of the mining industry are such that further leasing may be required soon to meet production projections for 2000,

A leasing moratorium is now in effect while

procedures are being devised to remedy past

abuses. The Carter administration plans to end

the moratorium in the early 1980’s. In the interim, only leases necessary to maintain an existing mining operation or to meet existing contracts are issued. The new leasing program will

emphasize public participation and environmental acceptability in the context of multiple-use land management. In addition, leases

may be reorganized to reflect logical mining

units, and they may be required to meet

criteria of diligent development and continued

operation. The terms of all existing leases will

not be modified under the revised leasing program. This exclusion has drawn criticism from

environmentalists, Indians, and others. With

the resumption of leasing, coal operators will

be able to plan with a degree of certainty that

has been lacking in the recent past. Until

Federal leasing policy is finalized, it is not

possible to determine the extent to which the

overall policy will encourage or constrain the

development of coal reserves on public lands.

Industry Structure

The structure of the bituminous coal industry is complicated and dynamic. Although

there are more than 6,000 operating mines, it

has been estimated that there are only about

600 independent producers or producer

groups. The 15 top coal operators mined about

40 percent of all domestic production in 1977,

and between 40 to 45 percent of alI utility consumption. Five of the top 15 producers are captives, owned by steel companies or utilities.

The others are owned by horizontally integrated energy companies or conglomerates.

Only two are independent coal companies. In

the last 10 years, three trends have emerged

and are Iikely to continue: 1 ) increasing concentration among companies selling in regional and specialized markets; 2) increasing

utility-owned production (known as vertical integration); and 3) growing ownership of coal

production by horizontally integrated energy

companies.

Competition, price, and coal supply are matters directly affected by industry structure. industry advocates and critics disagree over

whether or to what extent these factors have

been affected by the changes in coal ownership. Although a number of recent studies have

examined the competitive structure of the coal

industry, none has focused the quantitative

analysis properly or developed the case study

information that would justify definitive conclusions. As coal production from utilityowned mines and energy-company mines is

likely to increase faster than coal production

nationally, the competitive implications of

such ownership patterns deserves close analysis and monitoring.

Labor Profile

Today’s 237,000 coal workers are a diverse

group. More than 140,000 work in underground

mines, whiIe 65,000 work as surface miners.

Others work on new mine construction projects, and in preparation plants, mine-related

shops, or mine offices. About 2,000 are

women. More than 10,000 are Black, Hispanic,

or Indian. More than 90 percent Iive East of the

Mississippi River, and most of those work in

the Appalachian fields. Although about half of

all coal production in 1985 and 2000 will come

from west of the Mississippi, more than 80 percent of the labor force will work east of it.

Most of this group will work in underground

mines and in Appalachia. The work force is

young: the median age for underground miners

is about 33; for surface miners, about 37. As

the current work force ages, job experience
should increase. This should improve safety

and productivity.

Between 65 and 70 percent of all coal workers are members of UMWA. They account for

about 50 percent of total national production.

The average annual income for most underground miners exceeds $1 7,000; for surface

miners, more than $20,000. (Some miners who

log a great deal of overtime can earn $35,000

annually, but they are exceptions. ) Because of

mining’s high wage rates and certain social factors, the turnover rate industrywide is probably

below average. However, where employment

is not steady or where community conditions

are perceived to be harsh, individual mines

have experienced high turnover.

It is estimated that very little– if any– increase in net mine employment wiII occur between now and 1985. Although several thousand miners will retire in these years, a sufficient supply of younger workers appears to be

available. By 2000, however, mine employment is estimated to increase by 45 percent to

110 percent over 1977 levels. Most of these additional workers will be needed in the East and

should be available from indigenous coalfield

populations. Labor supply does not seem to be

a problem in the boom areas of the West because of high wage rates.

Labor-Management Relations and

Collective Bargaining

Labor-management relations in the coal industry have never been very good for very

long. This stormy relationship has been shaped

by the structure of the industry, the level of

coal demand, the level of competition among

coal producers, the nature of the underground

workplace, the social experience of the coal

camp, and the history of the effort to unionize

the work force.

One measure of the stability–if not the

quality–of day-to day relations in the workplace is the level of wildcat strike activity.

Miners engage in unauthorized work stoppages more than any other group of industrial

workers; underground coal miners strike more

than any other group. Over the last 40 years,

coal miners have participated in wildcat

strikes more frequently when coal demand was

firm and employment security was high.

Wildcat strikes occurred with unprecedented frequency between 1973 and 1978

when coal prices more than doubled and demand was growing. These strikes usually begin

at a single mine. Sometimes they spread quickly to many others when a disputed condition

exists across the coal fields. Most wildcats are

limited to one mine and arise over a disputed

work condition, interpretation of the contract,

or the miners’ perception of harassment. Several were precipitated by widespread disgruntle

ment over broader issues — compulsory shiftrotation, pendin g black lung legislation, controversial school textbooks, gasoline rationing, the right to strike, the use of Federal injunctions against wildcat strikers, and cutbacks in medical benefits. Since the last contract strike, wildcat strikes have been much

less frequent. Poor market conditions, improvement in the grievance procedure, and

depleted savings are the probable reasons for

the improvement. UMWA and mine management appear to be improving their ability to

resolve disputes, which should lead to less

strike activity in the future. Many miners are as

opposed to the recent level of wildcat strike

activity as are their employers because of the

loss of income these shutdowns entail. But

these strikes have always been a part of coal

mining and may never be eliminated. There appears to be little that Federal policy can – and

possibly should —do to stabilize this area of

private enterprise. Harsh legal penalties

against strikers do not seem to deter wildcat

strikes in this industry.

Collective bargaining in the coal industry

has usually been characterized by acrimony,

strikes, cataclysmic rhetoric, and reluctant

Federal involvement. The most recent contract

impasse came in the winter of 1977-78, when

for 109 days, UMWA miners struck their employers, their Government and, it can be said,

their own negotiators.

The 1977-78 strike lasted almost 4 months

because the Bituminous Coal Operator’s Association (BCOA) insisted on a set of dramatic

changes in the old contract. These changes—
Ch. /—/ntroduction and Overview 23

involving health and pension benefits, the

future of the UMWA Funds, whether management would have the right to fire and discharge strikers and absentee workers—were

objectionable to rank-and-fiIe miners although

they were accepted by UMWA negotiators.

BCOA members felt they were necessary to

achieve what they called “labor stability. ” The

contract that was finally ratified incorporated

many of the changes BCOA demanded. The

ramifications of this contract —the attempted

recall of UMWA President Arnold Miller, grassroot discontent, and health care changes — are

still working themselves out. It is likely that

UMWA members will demand major revisions

in the current agreement in 1981.

The executive branch has had little success

in mediating contract negotiations in this industry, Both the union and the operators balk

at Federal intervention, and miners have little

respect for Taft-Hartley injunctions. Short of

nationalization of the industry or draconian

labor controls, there is probably little that Congress can do to improve the negotiating/contract ratification process. It is essentially a

private relationship in the private sector. Rising coal demand and continued prosperity for

mine operators should improve the climate of

negotiations. As more and more production

comes from non-UMWA mines, the national

impact of UMWA contract strikes should decline. This was clearly evident last year when,

after the 3 ‘/z-month strike, no power shortages

were recorded and onIy 25,000 workers were

laid off.

The dynamics of collective bargaining and

labor-management relations are very much in

flux. One factor behind the development of

western mines is the more tranquil labor situation in the West. Members of BCOA, which has

negotiated industrywide contracts with

UMWA since 1950, may jointly or separately

decide to begin negotiating regionally or on a

company-by-company basis. Observers disagree about whether denationalization of collective bargaining will reduce net lost time

from contract strikes. High-income western

miners may become more inclined to unionize

in the future as working conditions and job security supplant wages as their main job concerns. Western miners have had a tradition of

militant unionism, and it may be premature to

conclude that western mines will necessarily

be nonunion operations. UMWA contract

strikes are Iikely to continue to affect most

metallurgical and export production, and

roughly half of Eastern steam coal output.

Productivity

Although productivity has declined since

1969, the evidence suggests that it has not affected the ability of the industry to produce as

much coal as can be sold. Much of the explanation for the rise in productivity in the

1950’s and 1960’s has to do with mechanization (which cut the work force by 70 percent by

1969), the absence of workplace health and

safety regulation, the lack of surface mining

controls, the high level of job experience

among miners, and the ability of the industry

to externalize a variety of production costs.

The hidden costs of rising productivity in

these decades were unemployment, community stagnation, black lung disease, unreclaimed

surface mines, and other environmental problems. Several factors have combined to reduce

productivity since 1970. A principal one is that

44,500 UMWA miners– about half of the 1969

UMWA working membership, which represented 74 percent of all miners — retired in the

1970’s. These retireees had key production

jobs, for the most part, and their productivity

was high. Overall, about 60 percent of today’s

coal workers have been hired in the 1970’s.

State surface mining regulations cut productivity, as did Federal environmental controls.

The 1974 UMWA contract added an estimated

5,000 additional workers to the work force for

training and safety reasons. The 1969 Act

slowed down certain mining cycles to control

methane, dust, explosions, and ground conditions. High prices in the mid-1970’s encouraged

more than 1,000 small, low-productivity mines

to open. In addition, railcar shortages, absenteeism, and poor labor-management relations contributed to low productivity.

The decline in productivity seems to have

bottomed out. As more and more production is

mined by western surface mines, larger mines,

and newer mines (both surface and under-
24 . The Direct Use of Coal

ground), workers’ productivity should increase

gradually. Improved labor-management relations and more appealing community conditions should reduce absenteeism, thus raising

productivity. An increasingly experienced

work force should boost efficiency. Stable

prices should discourage inefficient producers

and prune inefficient mines. If the industry can

lower its injury experience, a contributing

source of poor productivity would be addressed. No technological developments appear to be on the horizon that will quickly and

dramatically raise productivity, although

several innovations, such as continuous faceto-portal haulage and continuous roof support

systems, should help. The most promising area

for productivity improvement is better job

training and restructuring work relations.

Other Factors

Potential constraints on coal production include supplies of water, capital, and equipment, and transportation facilities. Although

the United States appears to have an adequate

national water supply to meet projected

energy requirements in the near-term to midterm future, severe local and regional shortages as well as institutional constraints on

water availability could become problems.

Although these problems could be alleviated

through water conservation practices in a

variety of sectors (e. g., energy, municipal, and

agricultural uses), present water pricing and

water rights allocation systems do not encourage these practices.

The availability of capital and equipment

for coal development are market factors that

should not become constraints if the industry

remains economically sound. However, the

availability of transportation facilities could

impose local constraints on coal supply unless

track conditions are improved and the supply

of railroad cars is increased. Similar local

transportation constraints are posed by inadequate coal

Federal

more coal

haul roads and waterway systems.

Federal Coal Policy

coal policy emphasizes two goals:

should be mined and burned, but

more attention should be paid to controlling

the environmental, health, and safety costs of

doing so. Congress has enacted legislation to

meet both objectives. Sometimes the objective

of one legislative measure conflicts with the

objective of another. Compromises and tradeoffs are often made, either as part of the regulatory process or in litigation.

Much of the discussion about Federal coal

policy quickly narrows to a discussion of

regulatory restrictions on supply and demand.

Lost in this process is the considerable effort

given to helping industry produce coal and

burn it. Federal research money for coal

amounted to about $73 million for the Bureau

of Mines and about $669 million for the DOE

fossil fuel program in FY 1979. Loan money has

been made available to “small” underground

operators. Federal tax policy on depreciation

and depletion encourages investment and

reduces tax burdens. Millions of Federal tax

dollars are spent annually on highway construction, inland waterways, and railroads that

benefit mine-to-market transportation. The National Energy Act of 1978 promotes coal as a

primary energy source. The Act significantly

strengthens Federal authority to order combustion facilities to convert to coal by prohibiting

the use of oil or natural gas in new facilities as

well as the use of gas in existing facilities after

1990. However, the impact of the prohibitions

may be difficult to ascertain because most

utilities are not planning new oil or gas units.

Where the prohibitions could have a major

impact —on smalIer industries — the amount of

coal involved is not as great and exemptions

are more easiIy obtained.

Significant Federal regulation of coal production and combustion is relatively recent,

beginning in 1969 with the Federal Coal Mine

Health and Safety Act. Although mine safety

legislation had been enacted as early as 1910,

it appears to have had little impact on fatalities and injuries. The 1969 legislation improved some mine conditions significantly, resulting in fewer high-fatality disasters and

lower dust levels. It did not, however, specifically address injury-prevention and little improvement has been recorded since 1970 in

this area. The 1977 amendments required train-
Ch. /—/ntroduction and Overview 25

ing programs and tightened other aspects of

the 1969 Act. To control respirable dust,

methane, poor roof conditions, explosive conditions, and other hazards, the 1969 Act required mine operators to take extra safety

measures and hire more safety-related personnel, which contributed to declining productivity. However, this is a very complex issue and it

has not been demonstrated that the 1969 Act is

the principal cause of the decline, although it

has been a factor.

The Surface Mine Control and Reclamation

Act of 1977 is designed to change coal mining

practices that generate severe social and environmental costs and to prohibit mining in

areas that cannot be reclaimed. The Act sets

performance standards intended to prevent

adverse environmental impacts, such as

ground and surface water contamination and

degradation of agricultural land quality.

Operators must demonstrate, as a prerequisite

to obtaining a mining permit, that the land can

be restored to a postmining land use equal to

or better than the premining use. I n addition,

significant constraints are placed on coal mining in the prime farmlands of the Midwest and

in the alluvial valleys of the arid and semiarid

regions of the West. Enforcement of these

standards wilI play a critical role in determining the effect of the Act on coal production.

Much controversy exists over whether and

to what degree the 1977 Act will impede coal

production. Certainly, it will increase the costs

of surface-mined coal. It may also hit small

operators harder than larger companies. Productivity may be affected as more worker time

and equipment are devoted to preventing environmental damage. It will be several years,

however, before an accurate assessment of the

impact of this Act can be made.

The major concerns in managing the environmental impacts of coal combustion are its

effects on air, water, and land quality. General

environmental management is regulated under

the National Environmental Policy Act of 1969

(N EPA), which requires that all Federal agencies include a detailed environmental impact

statement (E I S) in every recommendation or report on legislative proposals and other major

Federal actions significantly affecting the

quality of the human environment. Most major

Federal coal-related programs (such as leasing)

and federalIy permitted activities (such as construction of a powerplant) are subject to the

E IS requirement. Although the E I S process has

increased institutional awareness of the need

to minimize adverse environmental impacts, it

has been criticized for its alleged attention to

procedure over substance-and for the time it

adds to the beginning of a project. In 1978 the

Council on Environmental Quality promulgated new E I S regulations that are designed to

reduce paperwork and delays, improve EIS

quality, and better integrate the E IS into agency decision making. These new procedures

should remove most of the objections to NE PA

and result in better decisions and greater environmental protection.

Federal policy toward air quality is implemented under the Clean Air Act Amendments

of 1977, which will speed achievement of ambient standards and allow greater growth in the

future since each new facility will limit its

emissions as strictly as possible. However, the

amendments do not reflect a consistent unified approach to some of the fundamental

problems, and the overall effect of the Act is

difficult to assess. Exemptions for smaller

sources and the Amendments’ failure to deal

with pollutant transformation and transport

may undermine the air quality protection intended to accommodate new large coal-fired

sources. Coal-fired facilities may also require

greater expenditures for pollution control

equipment or be subject to stricter siting and

other preconstruction review procedures; thus

they may be at a competitive disadvantage

relative to cleaner fuels. In addition to these

increased costs, coal combustion may be prohibited near areas where air quality-related

values are important, such as national parks

and wiIderness areas.

Similarly, water quality impacts of coal mining and combustion are regulated under the

Clean Water Act, which requires coal mine and

combustion facility operators to meet effluent

limitations designed to achieve Federal water

quality goals. The techniques for meeting

these limitations are available, but may re-
26 . The Direct Use of Coal

quire mine operators to institute waste water

treatment and may increase the costs of both

mining and combustion.

The Resource Conservation and Recovery

Act regulates the disposal of solid wastes from

coal-related activities, including ash and

scrubber sludge and mine wastes. If these

wastes are listed as hazardous, RCRA will impose strict disposal and recordkeeping requirements that will significantly increase coal

combustion costs. However, the environmental and health benefits from preventing the

open dumping of these wastes are also substantial.

Implementation

Numerous departments and agencies are responsible for implementing Federal policies

that affect the production and use of coal.

Those with substantial roles include EPA,

which regulates the byproducts of coal use

through administration of the Clean Air and

Water Acts and RCRA; the Department of Labor, which is responsible for miners’ health and

safety; the Department of the Interior, which

administers SMCRA; DOE, which has the authority to order coal conversions and, in

cooperation with Interior, administers the

Federal coal leasing program; and the Council

on Environmental Quality, which has primary

oversight responsibility for NE PA. I n addition,

numerous interagency consultation and coordination requirements involve a variety of

other departments and agencies in policy implementation.

Some critics of Federal coal policy argue

that energy development is overregulated.

Others contend that more regulation is

needed, either because of the way agencies

have interpreted their mandates or because

conflicts or gaps among those mandates preclude the existence of either a coherent national coal policy or a coherent environmental

protection policy. The major factors affecting

implementation of such policies, in addition to

those mentioned above, include the lack of

comprehensive Federal programs for leasing,

land use, and water resource management; the

absence of workable mechanisms for resolving

interstate or interregional pollution problems;

and the focus on immediate problems to the

detriment of long-range planning. These could

hamper increased coal use in the short-term

and midterm future.

In general, Federal policies that affect coalrelated activities are not expected to constrain

increased coal use in the long term. The requirements of the Clean Air Act impose the

most significant constraints in the short term,

both by limiting the number of available sites

for combustion facilities and by substantially

increasing the costs of combustion. However,

the air quality benefits that will result should

facilitate coal combustion in the long term.

The cumulative effect of all other existing

regulations may delay the construction of new

facilities or the opening of new mines and will

make both mining and combustion more expensive.

Future

Each of the national

mand scenarios in this

Policy

energy supply and dereport involves a substantial increase in coal use over the next two

decades. There is no doubt that the resource is

physically present and accessible to sustain a

high level of use over that period. It is also

clear from an engineering standpoint that coal

can be extracted, processed, and burned at a

cost that will make it very competitive with

other fuels. What is not clear is how the external costs, institutional and social constraints,

and other nonmarket factors associated with

coal use will affect the validity of the economic and technological analysis. At one extreme,

increased coal use might pose such serious external costs to the environment and public

health that strict limits on its use would be required. At a minimum, the process of reducing

external costs — by increasing, for example,

pollution controls and coping with internal

constraints (such as labor-management conflicts)—will moderately increase the economic

costs of coal utilization. Given the central

place of coal in future U.S. energy planning

and projections, the stakes involved in formulating a national coal policy are substantial.
Ch. /—/ntroduction and Overview ● 27

The task of policy analysis in this area is to

identify the potential problems and constraints

and to examine the range of governmental policies that offer some promise of amelioration.

There are three basic types of criteria for

choosing among these Government policies: 1 )

national objectives concerning the timetable

for and level of coal production and use, 2)

political and normative values, and 3) pragmatic calculations concerning the absolute

and relative efficacy of policies in stimulating

production and use and/or minimizing adverse

impacts.

National objectives concerning the magnitude and timing of coal use set the context

within which coal policy is formulated. The

mining industry should be able to double or

triple its production by 2000 if current conditions continue. Existing and pending environmental, health and safety, leasing, and other

legislative and regulatory requirements may be

costly but otherwise appear to be compatible

with greatly increased coal production.

Nevertheless, there are actions that will provide an additional margin of safety against the

possibility that these supply projections are

overly optimistic or that it becomes necessary

to raise coal’s fraction of U.S. total energy supply above the levels posited in this report.

Many of these measures have merit independent of their potential effect on coal supply.

The list includes efforts to: 1) mitigate the

adverse community impacts that might constrain coal development, 2) address the causes

of labor-management disputes, 3) anticipate

and avert potential coal transportation bottlenecks by upgrading existing modes (e. g., railroads) and facilitating the creation of new ones

(e. g., slurry pipelines), 4) expedite the formation of a leasing policy and the designation of

eligible tracts, 5) streamline the permitting

process for new mines, and (6) develop procedures for anticipating and accommodating

potential objections to new coal facilities in

order to avoid extensive litigation and delay.

Demand is more likely to be a constraint on

coal development over the next two decades

than is supply. While demand will probably be

adequate to sustain all but very high energy

scenarios, this is far from certain. Several

broad policy options are available to strengthen the future market for coal. These include: 1 )

tax pressures and incentives to induce utility

and industrial conversion to coal, 2) RD&D

support for technologies (e. g., FBC and SRC)

that can help make coal an acceptable fuel for

small users, 3) RD&D support for improved,

less expensive emission control technologies,

4) RD&D support for coal gasification and liquefaction technologies, and 5) higher prices for

natural gas and fuel oiI through deregulation

or surcharges. It is most likely, however, that

no significant policy initiatives will be required

to reach plausible supply and demand projections. In sum, the targets discussed in this

report regarding coal production and use for

the remainder of the century do not emerge as

a critical basis for sorting among legislative

and regulatory options; both rapid growth and

the current controls can be accommodated.

The choice between conflicting courses of

action will often require subjective judgments

concerning what is desirable. With regard to

coal policy, the most important value conflict

involves the relative priorities to be assigned to

increasing production and to reducing adverse

impacts. The existing Iegislation and regulations define a rough but discernible balance

between these two value sets. Future policy

may maintain that balance or shift it in favor

of either production or impact amelioration.

This choice lies at the heart of national coal

policy. Specific dimensions of the choice include tradeoffs between: coal extraction and

environmental quality, coal combustion and

environmental quality and public health, coal

extraction and the well-being of coal field communities, and coal extraction and workplace

health and safety. A second value conflict

arises over whether increased Government

regulation is the appropriate way to achieve

national energy policy goals, or whether the

emphasis should be on broad guidelines (performance standards), negotiation, and mediation. Finally, if regulation is determined to be

necessary, value conflicts will result from the

allocation of decision making authority among
the various levels of government: Federal,

State, local, and tribal. Value judgments and

priorities, then, play an important role in shaping coal policy choices.

Judging policy options also involves an

assessment of the utility of different policies in

solving the specific production, utilization,

and impact problems associated with coal.

Five major areas of policy concern have been

identified, each with a potential for significant

influence on efforts to expand the production

and use of coal. They are: 1 ) environmental impacts, 2) community and social impacts, 3)

labor-management relations, 4) workplace

health and safety, and 5) leasing of Federal

coal reserves.

Environmental Impacts

Environmental considerations

tant potential constraint upon a

are an imporsubstantial in-,

crease in coal production and combustion. The

era of unregulated environmental impacts is

clearly past for coal, as for other fuels. An

elaborate, though still incomplete framework

of legislation, regulation, and implementing institutions is in place. It constitutes a national

policy system for managing the environmental

impacts of increased coal use. The relevant

control technologies are at various stages in

their evolution from conception to maturity,

but most have at least reached the point where

a first-generation technology can actually be

applied. Control technologies for combustion

emissions are particularly important, and although existing technologies are far from optimal, the outlook is promising. In short, after

the investment of substantial economic, technological, and human resources over recent

years, the ingredients of a viable environmental policy for coal now exist.

Under these circumstances the paramount

task of policy analysis is to identify ways that

the existing policy system might be upgraded

with regard to:

● gaps in present knowledge about the

nature and magnitude of the risks to the

environment associated with coal utilization,

●

●

●

●

the performance and future prospects of

specific control technologies and the

means of stimulating improvements,

omissions, inconsistencies, or disutilities

in existing environmental laws and regulations,

implementation of laws and regulations,

and

promising new policy innovations or instruments.

Community and Social Impacts

A comprehensive national energy program

also may include policies designed to alleviate

the adverse community impacts associated

with coal development. These policies, if they

are to be effective, must take into account two

basic characteristics of the present situation.

First, there is considerable uncertainty over the

nature of future coal development impacts

and the balance of benefits and costs that will

accompany them. Second, value disagreements over what impacts are beneficial and

what are adverse occur even where the nature

of these effects is understood. Whether economic growth itself is to be viewed as a

positive or negative phenomenon in particular

localities is itself the subject of dispute. Nevertheless, a number of potential adverse community impacts can be identified including

overloaded public services, hyperinfIation,

and various symptoms of social stress and instability. A number of general and specific

policy measures designed to cope with these

problems can be identified, ranging from,

Federal grants to coalfield communities for

public works construction to studies of ways to

limit the corrosive impact of energy development on Indian tribal culture. Given the uncertainties and value disagreements regarding

community impacts, there is a need for policies that seek to deal with the concerns of interested parties in a context where compromise is encouraged. This will occur if all parties affected by increased coal use participate

in decisions about the location, timing, and

scale of coal developments that directly affect

them and if Federal policies are designed to

distribute the risks, costs, and benefits of in-
Ch. I—Introduction and Overview ● 29

creased use equitably among al I affected parties.

Labor/Management Relations

Although recent instability in labor-management relations in the coal industry has been

significant mainly at the local and subregional

level, future instability could have significant

implications for the nationaI economy. Consequently, Federal policy makers may try to actively influence the situation. If so, their task is

twofold: deciding how to ameliorate the

causes of destructive labor-management conflict and lay the groundwork for a more constructive long-term relationship, and planning

ways to cope with future strikes, should they

occur.

Under present legislation the Federal Government can do Iittle to alter directly the terms

of labor-management relations. The principal

causes of wildcat and contract strikes are the

conditions of work and terms of employment.

They are essentially privately determined matters. However, some policies can alter the context in which the unions and operators interact. These include measures designed to ensure steady growth in the demand for coal in

major sectors of the economy. The recently

passed National Energy Act contains a number

of these provisions. A healthy market should

ease the historic economic insecurity—of both

operators and miners—that has been such a

large factor in the industry’s labor problems.

Other promising actions are equally indirect

and relate to the basic social, economic, and

environmental ills that contribute to the

miners’ discontent. They include such diverse

measures as improving dust monitoring and

control within underground mines to restoring

Appalachian trout streams.

In the event of another major coal strike the

Federal Government would have an interest in

promoting a settlement that is prompt and

noninflationary, and one that establishes the

basis for long-term labor-management stability. In pursuit of these objectives, five major

strategies will be available: 1 ) reliance on collective bargaining with Iimited Government intervention, 2 collective bargaining with strong

Government involvement, 3) use of Taft-Hartley with limited efforts at enforcement, 4) TaftHartley with vigorous enforcement, and 5)

Government seizure of the mines. Each of

these options has opportunities and liabilities

that vary with the particular circumstances of

a strike; however, as noted previously, past

Federal intervention in coal field labor-management disputes has been counter-product ive.

Workplace Health and Safety

Mining, particularly underground, is a hazardous occupation as measured by the record

of work-related accidents and diseases. Any

substantial increase in coal production inevitably will mean thousands of diseased and

injured miners. The question facing policymakers is what modifications in or additions to

existing standards and enforcement might

minimize that number? Efforts to answer this

question will focus on improved dust control,

research related to the appropriate dust standards, and research on the effects of new pollutants and the synergistic impacts of multiple

pollutants in terms of mine health. The major

need in mine safety is to develop an accidentreduction strategy to Iimit the rising number of

disabling injuries, which now amount to about

15,000 a year and result in 2 months or more

lost time each, Improved safety and job training, education in different work practices,

changes in management and worker attitudes,

and new Federal safety standards for mine

equipment are some approaches to this problem.

Leasing of Federal Coal Reserves

Western coal comprises roughly half of the

Nation’s coal reserves and the Federal Government owns 65 percent and indirectly controls

another 20 percent of that resource. Consequently, Federal policy concerning the leasing

of those reserves can have a substantial influence on the future of coal use. The most

basic policy question concerns whether additional leasing of Federal coal lands will be required to meet projected increases in demand,

and, if so, when and how much. The answer remains unclear; the 1977 amendments to the
30 ● The Direct Use of Coal

Clean Air Act may have reduced the attractiveness of Western coal for utilities, and legal

uncertainties surround the status of pending

lease applications. In any case, recent litigation means that no new leasing will be possible

until the early 1980’s at best. Assuming that it

wilI become necessary at some point to resume leasing, the Federal Government will

have to decide to what extent private industry

should be allowed to determine which lands

will be made available. One option would permit operators to nominate those Federal lands

they desire to mine and the Government to approve or disapprove the proposed lease. Under

a second option the Government would identify areas eligible for leasing and industry

would nominate specific tracts. Still another

option would leave to the Government selection of both the areas and specific tracts for

leasing. The comparative attractiveness of

these options will depend on whether the principal selection criteria are reducing planning

and administrative costs, minimizing environmental damage, increasing tonnage mined,

forestalling litigation, or controlling adverse

socioeconomic impacts. Whichever approach

ultimately is selected, a number of specific

issues will have to be clarified. They include

definition of logical mining units, status of

preference-right lease applications, requirements of diligent development and continued

operation, estimated recoverable reserves, advance royalty payments, and the exchange of

environmentalIy sensitive leased lands for

other unleased Federal land. Some important

institutional issues center on the division of

leasing responsibility between the Departments of the Interior and Energy. The Department of the Interior has the overall responsibility for the leasing program, but DOE controls

economic leasing terms and conditions.
Chapter II

ENERGY AND THE ROLE OF COAL
Chapter II-ENERGY AND THE ROLE OF COAL

Electric Power Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Decentralized Electric Power Generation: An Alternative

Approach?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

industrial Use of Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Residential and Commercial Use of Coal . . . . . . . . . . . . . . . . .

Distribution of Coal Combustion and Production.. . . . . . . . . .

1.

2.

3.

4.

5.

6.

1.

2.

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TABLE S

Energy Demand Scenarios, Year 2000, and Their Determinants

Energy Supply and Demand Scenarios . . . .

Coal Combustion Projections . . . . . . . . . . .

Powerplant and lndustry Coal Combustion.

Coal Production Projections . . . . . . . . . . . .

Coal Mine Employment Forecasts . . . . . . . .

FIGURES

Combustion of Coal and Lignite by End-Use

Coal Combustion Distribution . . . . . . . . . .

. . . . . .

. . . . . <

. . . . . ,

. . . . . .

..,,. 0

Sector

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. . . . . . . . .

. . . . . . . . .

. . . . . . . . .

. . . . . . . . .

. . . . . . . . .

. . . . . . . . .

●

●

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✎

✎

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Page

33

34

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38

39

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39

39

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41

4 4

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47

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48
Chapter II

ENERGY AND THE ROLE OF COAL

Coal is expected to rapidly become more

abundance relative to domestic reserves of oil

important in the Nation’s energy system. Its

and gas should preclude the steep price increases that may be in store for oil and gas as their production becomes more expensive, and

most observers conclude that our present heavy dependence on foreign oil is a grave political and economic Iiability.

Many of the functions served by the energy of oil and gas could also be served by coal,

as they were in the past. Others, however, such as residential heating and transportation,

seem less appropriate for coal to serve unless the coal is first converted to a more convenient

form. It is necessary to examine energy demand in general, and the various sectors of energy

consumption in particular, to determine the degree to which coal can rejoin the energy system and how. This chapter describes the factors that determine energy and coal demand

Three energy scenarios are presented to demonstrate a range of possible coal growth requirements. These scenarios reflect the range of most current predictions, though recent projections have tended to be toward the lower end of this range. Thus the high development scenario serves to indicate the probable upper limit on the amount of coal that will be needed. If

the actual level is lower than the low development scenario, both the challenge of meeting

demand and the resulting impacts will be reduced. The coal production and combustion elements of the scenarios are described in detail to set the stage for the following chapters.

KEY FACTORS AFFECTING ENERGY DEMAND

Three primary factors are ultimately responsible for determining future energy use: population, economic activity as indicated by the

gross national product (GNP), and efficiency of

energy use. Each factor is a complicated function of subfactors, which are often interrelated. Appendix I in volume II amplifies this

abbreviated analysis.

People are the final

and services that use

population, the more

Changes in population

by fertility, death, and

consumers of the goods

energy. The higher the

energy will be needed.

growth are determined

immigration rates. Estimates of the former range from 1.7 to 2.1 births

per woman over her lifetime (1.8 in 1975), but

the effects on energy consumption will not be

great before 2000. The death rate is not expected to change significantly by 2000. Hence

immigration is the least certain factor. Population is expected to be between 246 million and

260 mill ion by 2000, an increase of 13 to 20 percent from the present 217 million. Of more immediate concern are the demographic shifts

within the total population. The labor force

will grow considerably faster than the population as a whole. The shift in the median age

that this implies suggests not only that GNP

will increase as described below, but that

households and drivers, both major energyconsuming groups, will increase faster than

population. Changes in tastes, lifestyles, and

habits, perhaps engendered by rising prices,

can also affect energy demand, but such shifts

cannot be confidently predicted.

GNP is a measure of overalI economic activity, most of which consumes energy. A close relationship has been observed in the past between GNP and energy consumption. The recent charges in this relationship are discussed

in the next paragraph. GNP obviously depends

in part on the population size and the labor

force in particular. The number of persons in

the labor force age group (16 to 65) can be predicted quite accurately to the year 2000. The

number of persons actually working depends

on the labor participation rate and the unem33

44- 102 0 - 74 - 4
34 ● The Direct Use of Coal

ployment rate. The former is expected to continue its upward trend, reflecting the increased

participation of women. Unemployment is expected to drop below 5 percent for most of the

rest of the century. The positive effect of a

large population and a higher rate of participation in the labor force is partially offset by

the expected continuation of the long-term decIine in work hours; average hours worked per

week dropped from 40.0 in 1948 to 37.1 in

1973. The final element in estimating future

GNP is labor productivity, the measure of output per worker, per hour worked. The replacement of manpower with capital, materials,

knowledge, and energy has been the historic

means of increasing productivity. It now appears that industry is finding a more attractive

return on its capital when it restructures this

equation to reduce the use of energy. This is

one of several factors that have Ied to a longterm decline in the rate of growth of labor productivity. If this rate continues to decline, a

very low-growth economy with lower energy

needs than this report assumes wilI emerge. Recent concern has led to tax law changes, indicating that a national commitment exists to reverse the decline, which is the assumption of

this analysis. All these factors combine to yield

estimates of G N P in 2000 of $3,300 biIIion to

$3,600 billion (constant dollars) compared to

$1,516 billion in 1975. This increase of 120 to

140 percent will about double real, per capita

income.

Energy efficiency relates the performance of

a given task or process to the quantity of

energy required. Efficiency (or the conservation measures implemented to enhance it) is

not to be confused with constraint, which implies less consumption of the goods or services

involved. Energy efficiency rises largely in

response to economic pressures — fuel prices in

particular— but also to tax benefits and other

policies. History provides little help in estimating the response to energy price increases,

as the cost of fuel was stable or slowly declining in real terms throughout the century. Until

1973 there was little incentive to design for

energy efficiency and almost none to change

an existing practice. The situation is quite different now, and decisions based on cost estimates will result in rising energy efficiency.

There will be exceptions. As resources become

scarcer, more energy wiII be required to produce them, and as energy conversions such as

electricity and synthetic fuels assume a larger

role, efficiency will be adversely affected.

Nevertheless, recent economic and energy

data imply that energy and GNP have been

largely decoupled and a substantially different

ratio will be established. Measuring this

change is much more difficult than measuring

the previous factors. Conservation will be a

function of fuel prices, which will depend in

part on factors such as domestic oil and gas

reserves, foreign and domestic policy decisions, and technology developments. Thus the

uncertainty in projecting future energy efficiencies largely accounts for the wide range in

the scenarios to follow.

DEMAND SCENARIOS

Forecasting energy demand is a highly uncertain art. As described in the previous section, there are too many important variables

that can only be speculatively quantified. Depending on assumptions, modelers can produce scenarios for 2000 predicting anywhere

from 60 to 190 Quadsl (73.1 Quads in 1975).

Both extremes are highly improbable. Most

forecasts fall between 100 and 150 Quads.

‘A Quad IS short for quadrllion Btu

Rather than selecting existing scenarios or creating more, the following analysis simply

assumes energy consumption levels in 2000 of

100, 125, and 150 Quads and then determines

the circumstances that would be consistent

with arriving at each level and the patterns in

which these aggregate levels would be distributed.

The objective of these energy demand scenarios is to determine the impact of a given
Ch. //—Energy and the Role of Coa/ . 35

level of aggregate energy demand on coal consumption. Aggregate demand is the sum of

residential/commercial, industrial, and transportation demand, Most energy used in residences and commercial establishments is for

heating and cooling. Oil and gas are the primary fuels for direct heating and electricity for

cooling. The use of electricity for heating is increasing rapidly. The transportation sector is a

major consumer of liquid fossil fuels. Industry

and electric utilities, which use large quantities of energy to produce steam, are the prime

candidates for the substitution of coal for oil

and gas.

The 100-Quad demand scenario is a slowgrowth scenario. An assumed fertility rate of

1.7 births per woman marks the leveling off of

a long-term decline in U.S. fertility, and with

moderate immigration results in a projected

population of 246 million in the year 2000. This

modest increase in population is accompanied

by an equally modest average rate of GNP

growth: 3.8 percent between 1975-85, and 2.8

percent between 1985-2000.

A key assumption in the 100-Quad scenario

is a major increase in the price of oil and gas

relative to coal because of a disappointing discovery rate. The price of oil is expected to increase to $25/bbl in 1975 dollars by the year

2000, while natural gas increases to $4.30/1 ,000

ft’ at the wellhead. These dramatic price increases reflect increased scarcity and deregulation of oil and gas. Long-term contracts and a

competitive industry wilI prevent coal prices

from rising as rapidly: from $1 7.50/ton in 1975

to $28.88/ton in 2000. Accordingly, oil prices

increase by a factor of 2.4, gas prices by a factor of 10, and coal prices by a factor of 1.65.

The price of energy to the consumer will not increase as much because other determinants of

retail energy prices (refining costs, distribution

costs, etc. ) will not rise at the same rate as fuel

costs. As a result, electric power increases

from 2.7 cents/kWh to only 4.5 cents/kWh in

2000. The basis for these increases is discussed

in the Supp/y Alternatives section of this

chapter and in appendix I of volume II.

These increases in absolute energy prices

lead to major efforts to implement energy-saving technology, resulting in increased energy

efficiency. I n industry a 30-percent increase in

energy efficiency is assumed. Industrial use of

petrochemical feedstocks is also forecast to

grow at a much slower rate as a result of high

prices. In the transportation sector auto efficiency increases from 14 miles per gallon

(mpg) in 1975 to 27 mpg in 2000, small trucks

and vans increase in efficiency from 11 to 18

mpg: heavy trucks, planes, and ships experience a 20-percent increase in efficiency. I n the

residential/commercial sector it is assumed

that 2 percent of old homes (pre-1975) and

commercial structures are retrofitted with insulation each year, and 10 percent are fitted

with heat pumps by 2000, AlI new homes and

commercial structures are insulated, and 25

percent of these are equipped with heat

pumps.

The breakdown of sectoral energy demand

resuIting from these assumptions is shown in

table 1. The increase in household/commercial

energy demand greatly exceeds popuIation

growth because of demographic shifts and a

substantial increase in per capita use; however, it is much less than the assumed increase

in the number of households and in commercial footage, implying increased efficiency.

The significant increase in industrial energy

use is partially explained by the corresponding

growth in GNP, 120 percent between 1975 and

2000. Energy consumption grows slower than

GNP for two reasons: first, the achievement of

increased energy efficiency already cited; and

second, a substantial shift in the composition

of industrial production away from petrochemical products. Transportation energy demand rises slightly faster than population, reflecting the increased gas mileage of automobiles and offsetting increases in mileage driven

per capita, air travel, etc.

The 125-Quad scenario implies a more Iiberal supply system but a less successful conservation effort. Thus energy prices are the same

as in the 100-Quad scenario. The key demographic and economic assumptions in the 125-

Quad scenario are essentially the same as in

the 100-Quad case, but the Nation has not

been as successful in implementing energy-efficient technology, nor has there been a sub-
36 ● The Direct Use of Coa/

Table 1 .—Energy Demand Scenarios, Year 2000, and Their Determinants

Demand scenarios/primary

assumptions

1975 -

- 

–

73.1 Quads

2000

Scenario A

100 Ouada

Ferttllty rate 17

Hours worked 198 x 10*

Labor productwlty growth

1970-80 1 8% annual

1980.85 2 2% annual

1985.2000.2 60/. annual

GNP growth per year

1975.85: 3 8%

1985.2W3: 2 80/0

2000

Scenario B

125 Queda

Fertlllty rate 1.9

f-fours worked 2(XI x 10”

Labor produclwlty growth:

(Same as Scenario A)

GNP growth per year’

(Same as Scenario A)

2000

Scenario C

150 Quada

Fertll!ty Rate 19

Immlgratlon + 750,000

f-fours worked. 203 x 1OD

Labor productlwfy growth

1975-80 2 O“A annual

1960-85 2 40/. annual

1985-2000 2 80/. annual

GNP growth per year’

1975-85 40/0

1985-2000 3%

Resldentlal/commercial ‘-

Wads 06 change Slatlstlcs —

257 #of homes’ 72x 10*

Commercial ft ftz 252 x 1OS

335 30 ”/0

~

444 72%

542 11 1“0

#of homes 102 x 10’ ( + 420/. )

Old (pre. ’75) 434 x 10$

New 586 X 10’

Commercial ft It’ 946 x 10$(+ 2750/. )

Old 152 x 10’

New 294 X 10’

Retrofit rate

Old 20/. !nsulatedlyear

1OO/. heat pumps

New all Insulated

250/. heat pumps

#of homes same as Scenario A

Commercial ft same as Scenario A

Retrofit rate

Old 10/. insulated/year

New 10°/0 heat pumps

-.

Industry

Statistics

High energy consumption

In petrochemicals

Shift composition away from

petrochemicals

30 ”/0 Increase in efficiency

525 101 % Shift composition away from

petrochemicals

20% increase in efficiency

1 —

64.3 147 ”/0

Transportation

Quads ‘ % change Statistics

18.8 Autos 104 X 104

MPG 14

 MPG (trucks) 11

222

281

18.1 % Autos. 120 X 10” (15”/0)

MPG 27

MPG (trucks) 18

20°/0 increase m efficiency

49.5% Autos. 152 X l@ (46%)

MPG 27

MPG (trucks) 18

10% increase In efficiency

I

315 67 5% Autos: 170 X 10' (630/’)

No change in efficiency factors increased consumption of energy IS the result of lowered energy prices

occasioned by increased avallablllty of Ilquld fuels and natural gas

stantial shift in industrial production away

from petrochemicals. ’ The difference in energy consumption in the two cases is primarily

attributable to the differences assumed in

energy efficiency. I n industry the increase in

energy efficiency is 20 percent instead of 30

percent. In transportation, the efficiency increase for heavy trucks, planes, and ships is 10

percent instead of 20 percent. In the residential/commercial sector the retrofit rate of insulation into old homes is 1 percent instead of

2 percent, and only 10 percent of new homes

and commercial structures have heat pumps.

The only other significant departure from the

100-Quad scenario is the number of automobiles–l 52 million instead of 120 million.

The 150-Quad scenario may be characterized as a high-growth, cheap-oil case. It assumes no improvements in energy efficiency.

Energy fuel prices are much lower than in the

other two cases. Oil is only $12.48/bbl, natural

gas is only $2.25/1 ,000 ft3

, and the price of coal

and electricity is unchanged from 1975 levels

of $1 7.50/ton and 2.7 cents/kWh respectively.

Oil and gas are priced much more favorably in

relation to coal and electricity than in the lowand medium-demand scenarios. The automobile population in this high-growth scenario is

170 million, much greater than in the previous

scenarios.

Implications

The greatest growth in these scenarios is in

the use of electricity by the industrial and

residential/commercial sectors. All these incorporate lower growth in electricity than the

historical average, but this growth rate has

been declining since about 1966 to the present

3.4 percent that is envisioned for the 100-Quad

scenario. The direct use of energy by industry

has grown slowly over the last three decades.

Industrial consumption totaled 18.8 Quads in

1977, only 47 percent higher than in 1947 and

actually lower than in 1968.3 A resumption of

2

The population assumptions are slightly higher for

this scenario — an estimated 254 milIion based on a fertility rate of 1 9; however, no affect is assumed on GNP,

which is the same as i n the 100-Quad case.

●

3Annual Report to Congress, 1977, Department of Energy, Energy Information Administration.
Ch. II-Energy and the Role of Coal ● 3 7

rapid growth by industry is unlikely. Opportunities for the substitution of coal for oil and

gas are limited and is discussed later in this

chapter under the section, Projections of Coal

Production and Use.

In the commercial sector, total demand has

increased in al I three scenarios, but the 100-

Quad scenario actually lowers direct use of

energy. EIectric power and synthetic fuels are

clearly substitutable for oil and gas in this sector. The extent to which direct combustion of

coal is substitutable hinges upon a number of

factors, which are examined subsequently. The

transportation sector, for the most part, depends on liquid fuels, hence the direct combustion of coal and electric power is limited as

a substitute. Demand growth in this sector

means demand growth for oil, natural or synthetic. The greater number of automobiles in

the higher scenarios implies a continuing development of outlying suburbs, less mass transit, and increased driving for recreation.

A word should be said about how these demand scenarios compare with other studies.

The Department of Energy (DOE) conducted

its Market Oriented Program Planning Study

(MOPPS) in 1977. Total primary energy demand estimated by MOPPS in the year 2000 is

117.25 Quads, which is bracketed by the 100-

and 150-Quad scenarios. The breakdown of the

MOPPS estimate by sector is 36 Quads for the

household/commercial sector, 20.8 Quads for

transportation, 56.9 Quads for industry, and

3.5 Quads for metallurgical coal exports.

Comparing MOPPS to the 100-Quad scenario, the most significant difference is in the industrial sector, where the MOPPS estimate exceeds the 100-Quad scenario by 12.5 Quads.

The MOPPS scenario projects increased use of

gas and oil as petrochemical feedstocks, and

the overall increase in energy efficiency is

presumably lower than that assumed for the

100-Quad case. The MOPPS industrial energy

demand more closely approximates the 52.5

Quads estimated in the 125-Quad scenario,

where overalI industrial energy efficiency increases are one-third less than in the 100-Quad

case, and where petrochemical feedstocks

continue at pre-1975 rates of use. The significant source of difference between the 125-

Quad scenario and MOPPS is in the household/

commercial sector, 44.4 Quads compared to

36 Quads in MOPPS. This relatively large difference is accounted for by greater implementation of energy-saving technology in the

MOPPS scenario.

The Energy Information Administration of

DOE, in its Annual Report to Congress for

1977, projects a domestic consumption of

about 100 to 110 Quads in 1990, with a sectoral

distribution similar to this report’s 100-Quad

scenario. The EIectric Power Research Institute

(EPRI), in their report “Supply 77” of May 1978

uses a reference case for 2000 of 159 Quads

and compares it to scenarios of 146 and 196

Quads. EPRI clearly expects a more favorable

fuel supply situation, less public and governmental intervention, and lower price elasticities than this report considers probable. At the

other extreme, the Committee on Nuclear and

Alternative Energy Systems considered levels

of energy consumption as low as 58 Quads and

up to 180 Quads in 2010.4

In creating the three scenarios, various assumptions have been stipulated regarding key

factors and relationships. Little has been said

about the implications of a given scenario for

lifestyles. The way people live and their attitudes have a great deal to do with their willingness to accept constraints on their behavior

that might be implied by energy resource constraints and high prices. Whether consumers

would resist conservation policies is a matter

of specuIation.

Americans have traditionally duly complied

with requirements associated with emergency

situations, but indefinite compliance is a different matter. Most people are economically

rational, however, and if it is apparent that

price increases are not contrived and are being

applied fairly, they will adjust their patterns of

consumption appropriately.

The historical growth rate in per capita energy consumption since 1950 has been 1.4 percent annualIy. The scenarios discussed here resuIt from 0.9-, 1 .7-, and 2.3-percent increases.

4U.S. Energy Demand Some Low Energy Futures, ”

5cience, Apr. 14,1978
38 . The Direct Use of Coal

Thus even 125 Quads implies an acceleration

of per capita energy consumption growth.

Given expectations regarding increased energy

efficiency and higher fuel prices, there is no

reason to assume that rational Americans cannot adjust to a reduced rate of increase in

energy use. There is no basis for concluding

that the lower per capita growth in energy use

wiII result in deprivation. Hence low energygrowth scenarios cannot automatically be reHistorical

demand wi

jected as contrary to the demands of the

American people. On the other hand, if 150

Quads are available at sufficiently low prices,

ways wilI be found to use them, and it is incumbent on low energy-growth advocates to

suggest how consumers will be spending their

doubled real income, if not for energy-consuming goods and services, or whether in fact economic growth should be dropped as a national

goal.

SUPPLY ALTERNATIVES

y, energy supply has risen to meet

thout major increases in prices,

largely because of the Nation’s vast resources

and the increasing efficiency of production.

The situation is quite different now. Few if any

analysts expect the Nation’s production rates

of oil and gas to double at any price. Total exhaustion is not a near-term concern, but resource depletion is sufficiently advanced that

major new discoveries are noticeably harder to

make, and new production is significantly

more expensive. As oiI and gas currently supply 75 percent of national energy demand, an

indefinite continuation of past trends is not an

option for the future. These expectations are

reflected in the price assumptions for the 100-

and 125-Quad scenarios. The 150-Quad scenario incorporates much lower prices for natural

gas and oil on the assumption of major new

discoveries.

The energy sources considered here are oil,

gas, coal, nuclear, solar, and geothermal.

Hydropower is not expected to increase significantly because of the lack of economic sites

not subject to significant environmental degradation. Each energy source presents a different

set of characteristics that are valued differently by the various users. The most important

characteristics are price (including transportation), convenience, facility cost, cleanliness,

and reliability of supply.

100-Quad Scenario

The essence of the 100-Quad scenario is the

sharply higher price of oil and gas caused by

resource constraints. The same high price

structure could result from a high fuel tax

policy, but such a policy is improbable unless

impending resource constraints are widely perceived to be real. The higher prices keep U.S.

oil and gas production close to current levels

through enhanced recovery and exploitation

of less attractive sites, such as Alaskan, offshore, and marginal fields. Oil imports are expected to drop in response to policies aimed at

that end. Coal production is expected to more

than double and actually become the most important fuel. Nuclear power increases rapidly

but more modestly than most recent projections. Solar energy increases at a very rapid

rate, but the time frame is too short to do

much more than lay a significant base for the

21st century. New technologies, such as the

production of liquid fuels from shale and biomass, are not expected to make major contributions by 2000.

The economic advantages of coal and nuclear power become overwhelming for electric

utilities. Industry’s energy growth is derived entirely from coal and electricity. Transportation’s relatively small growth comes mostly

from oil. The residential/commercial sector

grows mostly with electricity. The actual

breakdown is shown in table 2 for all scenarios.

125-Quad Scenario

The same general price structure is assumed

to prevail as in the previous scenario, but the

less elastic demand leads to higher consumption. It is assumed that national policies result
Ch. //—Energy and the Ro/e of Coa/ . 39

Table 2.— Energy Supply and Demand Scenarios

Type Coal Oil

Electric” Direct Total Electric Direct Total Electrlc

20.2 52.7 15.3 8.8 6.5 32.6 3.2

1 187 0

120 136 3

8 0 157 15

2 2 2 2

18 18

7 7

42.5 57.5 31.1 20.2 10,9 30.1 1.7

0 4 218 0

21 1 125 5

210 159 31

2 7 2 7

4 3 4 3

3 3

53.8 71.2 37.8 26,4 11.4 40.4 2.2

0 4 277 0

294 150 5

240 209 3 4

2 8 2 8

4 4 4 4

4 4

67.8 62.2 41.3 28.9 12.4 48.4 4.0

0 6 309 0

350 192 0 5

322 242 4 0

3 0 3 0

4 5 4 5

7 4

i

Gas

*

Solar and other

Total

3.2

7,1

Total Dlrect Total Electric Electrlc Direct

3.2

1

1975 (actual)””. . . . . .

Transportation

Resldenttal/commercial

Industrial

Metallurgical

Exports

Stock changes

73.1

188

257

238

2 2

29.4

180

5 8

5 6

19.9 16.7 1.8

0 6

7 6

8 5

16.2 14.5

0 6

7 2

8 4

17.6 18.6

0 7

8 0

8 9

3.2

5.1

5.1

5.1

0.0

2.0

0

10

10

18

7

100.0

222

336

100 Quads .

Transportation

Resldentlal/commercial

Industrial

Metallurgical

Exports

Stock changes

28,4

212

3 8

3 4

17.2 1.0

369

2 7

4 3

3

125 Quads .‘. . . . . . . . . 125,0

Transportation 281

Resldentlal/commerc [al 444

lndustrial 449

Metallurgical 2 8

Exports 4 4

Stock changes 4

38.2

270

19,1 1.5

3.0

9.1

7.1

4.0

0

2 0

2 0

4 6

6 6

150 Quads .

Transportation

Resldent!al/commercial

Industrial

Metallurgical

Exports

Stock changes

150.0

315

542

564

3 0

4 5

4

44.4

300

6 4

8 0

26.4 2.0

0

10

10

. All values in columns labeled electricr are for the heat produced at the powerplant. The values for hydroelectric power under solar and others represent the heat that would have heen required at a typical thermal generating stattion to produce the same electrical power

“ Derived from Bureau of Mines Department of the Interior press release of Mar. 14, 1977.

in a significant increase in the availability of Interpretation

imported oil, and a vigorous expansion in electric power generation. These steps are required

by the assumed increase in the consumption of

petroleum in the transportation sector and by

a greater demand for electric power. I n providing for the increased electric power, coal- and

nuclear-generated power are assumed to share

equally in the expansion, and geothermal energy is starting to become significant. Both the

industrial and residential/commercial sectors

are turning to the direct use of solar energy.

An infinite variety of scenarios can be drawn

to meet any given demand scenario. The actual mix wit I depend upon relative prices, fuel

availability, and the other characteristics Iisted

above. Federal policy will have a considerable

influence on the relative level of each fuel as

welI as on the level of demand. Much has been

said here of the importance of the availability

of oil and gas, but little about their actual

availability. A detailed analysis of the subject

is beyond the scope of this study, but the values here are consistent with other recent

studies. The higher estimates could be r-net

only with a substantial fraction of imported

oil. If for political reasons it is necessary to

strictly limit imports, other fuels could probably not be expanded much beyond the levels

of the 150-Quad scenario to meet the deficit.

Nuclear energy has in the past been projected

for much higher levels than the highest in table

2 (500 plants of 1,000 MWe). Only about

200,000 MWe have been ordered so far, and

many of these projects are inactive. I n order to

exceed 500,000 MWe by 2000, all these plants

wiII have to be completed and more than 30 orUnder this scenario, coal does not surpass

oil as the leading fuel, largely because of increased imports.

150-Quad Scenario

In addition to the increased availability of

oiI and gas, nuclear power grows at a more optimistic rate. The economic advantages of

these fuels limit the growth of coal to little

more than that of the 125-Quad case, and actually makes solar energy less attractive than for

slower growth scenarios.
40 ● The Direct Use of Coa/

dered each year throughout the 1980’s. This is over regulatory delays, expensive redesigns

about the maximum rate of orders ever and and retrofits, public opposition, and perhaps

might be accommodated by the industry, but eventually, fuel shortages unless unproven

utilities are showing no signs of resuming uranium reserves are discovered or the breeder

ordering at such a level. A utility ordering a reactor is commercialized. Hence the levels

reactor now faces considerable uncertainty assumed here are unlikely to be exceeded.

PROJECTIONS OF COAL PRODUCTION AND USE

The scenarios of the previous section all

show coal to be the fuel of greatest total

growth, This growth can occur in a variety of

ways and places. The primary distinction in use

is between electricity generation and direct

heat applications. At present, about 70 percent

of the coal mined in the United States is

burned for electricity, and the bulk of coal’s

growth will be in that sector. Direct use by industry is the only other large-scale use considered here. The historical distribution by

end-use sector is shown in figure 1. The virtual

disappearance of the transportation and retail

(essentially the same as residential/commercial) markets is apparent, as is the growing

dominance of the utility sector. Also included

in figure 1 are the projections to meet the

scenarios of the previous sections. Table 3

summarizes the coal consumption of the three

scenarios.

Coal-based synthetic fuels are another frequently mentioned possibility. Projections of

several million barrels per day equivalent by

2000 have been made, but these are becoming

increasingly improbable. In order to build up

the industry to meet these levels, a major commitment would have to be made— soon. Coal

is an economically rational source of energy

when electricity is desired, but for Iiquid or

gaseous fuels, as long as natural sources are

available at one-third to one-half the cost of

synthetics, there is little incentive for any individual user to turn to the latter. A future

OTA report will address the fundamental questions raised by the previous sentence: the logic

of electricity vs. synthetics when natural fuels

are Iimited, what these Iimits are, and the rate

at which a synthetic fuels industry can be developed when needed. To the extent that any

coal-based synthetic fuel production does occur, this analysis assumes it would come at the

expense of electric generation or oil imports.

The former is unlikely to occasion any significant change in the impacts discussed in this

report. The latter possibility is accounted for

by a slight increase in the coal production

levels of the previous section.

As discussed in the previous section, coal as

a fuel presents a set of characteristics that

potential users will compare to alternative

fuels; The balance, and hence the eventual

level of coal consumption may be shifted by

changes in several factors in addition to

growth in demand for electricity and industrial

processes that can use coal or coal-derived

electricity. These factors, which include technological improvements and regulatory restrictions, are discussed in detail in chapter IV. This

section analyzes the demand of the users consistent with the scenarios, and the patterns of

supply needed to meet the demand.

Electric Power Generation

Uti l

of the

native

ties currently produce about 44 percent

r electricity with coal. The major alterfor the rest of this century is nuclear

power. Most new utility demand for coal will

be from new powerplants, as conversion of existing plants to coal will be quite difficult and

expensive.

The status of coal-fired electric power

capacity in megawatts as of September 1978 is

as follows:

Planned or under

Existing construction

220,583 152,521

Total

373,104
Ch. I/—Energy and the Ro/e of Coa/ 41

1,700

1,600

1,500

1,400

Figure 1.—Combustion of Coal and Lignite by End” Use Sector

Resident ial/commercial

General industry

and other

Electric power utilities

1,300

Actual ~

1,200

1,100

600

500

400

300

200

100

Utilities

I I I I I

1947 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000

SOURCES Annual Report to Congress, Energy Information Adminlstration, Department of Energy, vol. Ill, 1977, and the Off Ice of Technology Assessment
42 . The Direct Use of Coa/

Scenario

1975 . . . . . . . .

1985

A.. .

B .

c

2000

A

B

c

Total

productio n

655

955

1050

1145

1505

1845

2110

—

Utilltle s

403

675

725

775

965

1275

1410

Table 3.—Coal Consumption Projections

(millions of tons)

Total

Resldentlal/ domestic Potential

Industr y commercia l

6 2 12

90 15

120 15

150 15

150 25

160 25

200 25

Because of lengthening construction schedules, it is unlikely that any plants not included

in these figures would be operating by 1985;

the above total of 373,104 MW is thus an upper

limit for 1985 capacity estimates.

If recent history is a guide, some of the units

planned but not yet under construction will be

dropped, and some construction schedules will

slip. Some older units will also be retired,

though probably only a few thousand megawatts worth over the next decade. Other old

units will be downgraded from baseload to intermittent operation. This procedure was more

pronounced in the past because new plant efficiencies were rising, making the newer plants

cheaper to operate, but this trend has leveled

off since the early 1960’s. I n fact, plants with

scrubbers are less efficient and more expensive

to operate. Utilities may favor the use of older

plants when they do not need all their capacity, a factor that will tend to make attainment

of clean air standards more difficult than expected.

The National Electric Reliability Council is

predicting 309,476 MWe capacity (of units

greater than 25 MWe) by 1985, consuming 824

million tons of coal. The above concerns indicate this is an optimistic schedule. If all

plants with prevention of significant deterioration permits are completed on schedule, and if

3,000 MWe are retired, there will be 301,000

MWe, but a more conservative estimate might

be 295,000 MWe. This would correspond to

coal consumption of perhaps 775 million tons.

This is obviously still a huge jump over the

1977 utility use of 475 million tons (estimated).

combustion synfuels

477 0

780 0

860 0

940 0

1140 65

1460 70

1635 145

Nonenerg y

83

95

95

100

100

105

110

Exports

67

70

80

90

185

190

200

Addltlons

to stocks

32

10

15

15

15

20

20

If major deferrals result from a continuation of

the very low growth of the past few years, utility demand may be as much as 100 million tons

lower.

Beyond 1985, projections are highly uncertain. A growth rate of 5 percent from 295,000

MWe in 1985 for the remainder of the century

would result in about 450,000 MWe of coalfired powerplants by 2000. A growth rate

nearer historical levels would lead to 600,000

MWe. These would lead to coal demands of

1,400 million and 2,000 million tons annually.

(Increases in coal are not proportional to increases in capacity, because the shift to lower

heat value Western coal requires more tons for

the same electrical output. ) Utility forecasts

are changing rapidly, mostly towards lower

estimates. Historical growth patterns appear to

be unlikely to continue, as pointed out in the

previous sections. The year 2000 coal-fired

electric generation of tables 2 and 3 is

equivalent to about 330,000 to 450,000 MWe.

The exact level will depend primarily on the

level of demand for electricity and the competitiveness of nuclear power; it is therefore

quite sensitive to policy decisions affecting nuclear power and the economics of coal.

Decentralized Electric Power

Generation: An Alternative Approach?

The projections have implicitly assumed

that the utility industry would continue the

trend toward larger (600 to 1,200 MWe) generating plants. Existing generating plants in 44

States average less than 100 MWe each, but

only three States have any planned faciIities at
Ch. I/—Energy and the Role of Coal ● 43

that low level, and planned additions in 20

States average greater than 500 MWe. Every

State that has planned capacity additions (only

Vermont and the District of Columbia have

none) will significantly increase the average

capacity per plant This trend for generating

units may be leveling off, but stations, which

can include several units, are clearly still getting larger as sites become scarcer Economics

of power plant construction and operation

have been the primary cause of the growth in

size. The physical size of the plant, and the

materials and labor to construct it, increase

less than proportionally with its size. Operating costs (excluding fuel) are only slightly

higher for a 500 MWe plant than for a 50 MWe

plant.

Considerable interest has recently been expressed in some quarters in small, dispersed

plants. (“Small” is relative: a 50 MWe plant

would serve an average community of 20,000

people. ) This interest has been prompted partly by the downtime maintenance experience

with large coal-fired powerplants and partly by

the environmental and social impacts of large

plants and the resulting issues of public acceptability. Appendix I I of volume I I discusses

the issue in detail, Smaller plants can in theory

be placed closer to the communities they serve

because their siting criteria are so much more

modest. This dispersal would substantially reduce the need for long-distance, high-voltage

transmission, though the distribution system

would remain the same. Such a siting policy

also raises the possibility of using the waste

heat from the plants (about 60 percent of the

total heat of combustion) for district heating

or industrial processes. The latter in particular,

usualIy called cogeneration, has been espoused as a major element in energy conservation policy. There are no technical barriers to

either district heating or industrial cogeneration. Both have been in operation for many

years. The major impediments are economics

and a variety of institutional problems.

In order to assure continuity of supply, a

spinning reserve (virtually instantly available)

equivalent to the biggest single unit online

must be maintained. The smaller all the units

are, the easier it is to assure the same degree of

reliability. It should be noted, however, that

most utiIities are part of large grids. The entire

grid shares the spinning reserve, so the excess

capacity for each utility is not large.

The present high interest rates throw the

economies of scale into question, Interest on

capital costs is one of the larger items in the

final bill for a large plant that may take 6 or

more years to construct. Small plants may take

one-third to one-half the time to construct,

thus providing a much faster return on their

share of the capital. This time factor is also a

great advantage to utilities as they plan in this

era of uncertainty in load forecasting. Another

economic advantage is that the smaller size

makes possible the factory fabrication and

shipment of components that now must be

field fabricated, Factory labor is often cheaper

and more productive than construction labor,

Community impacts during construction will

clearly be less severe for smaller plants. Remote siting of large plants needing more than

1,000 construction workers can provoke serious strains in the nearby smalI communities

that must support them temporarily. Construction of small plants near bigger cities would be

relatively inconspicuous to the community inf restructure.

One of the major arguments advanced in

favor of decentralized power systems is enhancement of local control, particularly if the

plants are owned by a local government or a

cooperative. This argument is very difficult to

analyze. Until recently, few consumers were

concerned with the other end of their powerIine as long as the power was there when they

flipped the switch, and their bills weren’t too

high. Obviously many persons feel the latter

criterion is not now being met, but it is questionable whether decentralization or local

control would provide much relief. The advantages would be more subjective: a sense of involvement and control over factors affecting

one’s Iife. It is as easy to name examples showing indifference to involvement (e. g., the difficulty of getting neighborhood committees to

do much) as it is to list advantages. Further exploration of this issue is beyond the scope of

this report.
There would probably not be a great deal of

difference in total environmental impacts between a centralized and decentralized system

of the same capacity. Total emissions could be

about the same, and though they would be

more dispersed for the small-scale system they

would probably also directly affect more people. Lower stack heights could lead to a different mix of local and long-range transport pollutants, as discussed in chapter V. Insofar as any

system includes district heating or cogeneration, thermal pollution and the combustion of

other fuels would be substantially reduced.

Small plants and dispersed siting have their

disadvantages, of course. Construction clearly

requires more materials and possibly more

labor for the same output, Environmental control measures are often easier and cheaper to

implement in large plants. Flue-gas desulfurization, for example, may prove prohibitively

expensive for small units. Hence even if decentralization proves advantageous otherwise,

full realization may have to await commercialization of developments such as fluidized-bed

combustion or highly cleaned coal, which are

discussed in the next chapter. It is also likely

that public heath impacts of dispersed facilities would be greater even for the same efficiency of control, simply because such plants

would be in more densely populated regions.

Fuel delivery and waste removal can be major drawbacks to dispersed units. Unit trains

have cut transportation costs for big plants to

about half that of conventional trains, but

these and slurry lines would not be practical

for small plants. Insofar as the plants are

located in more densely populated areas,

transport would be more obtrusive, especially

if trucks are used.

Some of the problems and expenses facing a

utility trying to get a plant constructed and

online are not markedly different for a small

plant. Hence the total effort for several small

plants will be greater than for one large plant.

Operating costs have already been mentioned.

Licensing would be another. Opposition to particular sites may not be much less intense, and

if a close-in site is selected, opposition could

be much more intense than for a remote site.

This factor is further discussed in chapter IV.

This largely qualitative discussion is ambiguous. The economic and environmental tradeoffs are uncertain, and the social impacts depend on values and expectations. Thus neither

approach appears to have an overwhelming

advantage — a striking observation, as the

trend has been so strong to centralization. The

economies of scale discussed above are not

the whole cause of the trend. Regulatory constraints are another factor as suggested by the

controversial Avech-Johnson5 effect:

Utilities subject to a constraint on their rate of

return have incentives to expand the size of

their rate base to unjustifiable levels.

Thus while large central stations are clearly in

the utilities’ best interest they are not necessarily in society ’s. Reversal of the trend may require drastic changes in utility operations and

ownership, and in regulatory practices. Nevertheless, the subject seems worthy of more detailed analysis. Particular attention should be

directed to the States with utility systems most

resembling the decentralized concept. Michigan, Nebraska, Wisconsin, and lowa, for example, have many small generating utilities and

facilities and access to coal.

Industrial Use of Coal

The outlook for coal use by industry is quite

different from that for utilities. Industry

burned 60 million tons in 1976, representing

only about 10 percent of all energy purchased

by industry. Both figures have been dropping

steadily for 30 years, and there appears to be

no major effort on industry’s part to reverse

the trend. These factors have left industry as

the sector of greatest opportunity for policy

actions for conversion from oil and gas to coal.

A recent report by the Congressional Budget

Office’ extensively analyzed the use of fuel by

manufacturers and the prospects for increasing their use of coal. This report found that

coal use could be raised by about 90 million

‘H. Avech and L. Johnson, “Behavior of the Firm Under

Regulatory Constraint,” American Economic Review, 211

(December 1962), pp. 1059-69.

“’Replacing Oil and Natural Gas With Coal: Prospects

in the Manufacturing Industries, ” Congress of the United

States, Congressional Budget Office, August 1978,
Ch. 11—Energy and the Role of Coal ● 45

tons above present levels by 1985 under various tax policies.

Industry uses most of its energy for process

steam, electric power generation, and direct

heat applications. Most of these functions

could in principle be provided by coal, but

conversion of existing oil- and gas-fired facilities to coal wilI be quite difficult. There is Iittle experience with large coal-fired furnaces

for direct heat rather than steam generation,

so most applications will be for steam-raising

boilers. Boilers or furnaces not designed to

burn coal must be essentially replaced to accommodate coal, and entirely new storage and

handling equipment must be added. Coal requires twice the storage volume for the same

heat content as oil, and the handling equipment is larger and more expensive. Ash removal equipment and disposal must also be included. PolIution control equipment is generally necessary, even when not required for oil

or gas. If industry is to be held to emission Iimitations similar to those being promulgated for

utilities, only the very largest facilities will be

able to consider coal. New technologies such

as fluidized-bed combustion or synthetic fuels

would be necessary to meet both coal use and

environmental goals. Strong financial incentives above the fuel cost savings must be considered if it is desired to force these conversions. New facilities are more favorable targets. Energy consumption by industry, however, is expected to grow much more slowly

than consumption by utilities. Hence industry

cannot adopt coal as a major fuel without

wide-seaIe replacement of existing units.

Guiding industry toward coal will be difficult but not impossible. Small powerplants and

process steam generators are used throughout

industry. Coal boilers are now available to

cover a wide range of needs. These units can

be installed much faster than utility powerplants. Some of the small units (up to about 1

ton of coal burned per hour or equivalent to

about 2 MWe) can be manufactured and delivered as a package. Thus if the economics and

the less tangible factors, such as reliability of

supply, prove favorable, industrial coal use

could rise rapidly. Industrial process heaters

must be designed with a specific purpose in

mind. The cement industry uses several million

tons of coal annually for direct heat and could

expand this relative to other fuels. The glass

and metals industries may also find coal use

advantageous. 7

The 1962 Census of Manufactures by the Bureau of Census8 reported that

the chemical, paper, and food industries were

also major users of coal, with most industrial

use in the East North Central, Middle Atlantc,

and South Atlantic regions.

Coal use by industry will almost certainly

reverse its long-term decline because of the

fuel cost advantage and policy initiatives.

Hence a low estimate for 1985 for industrial

use of steam coal is 90 million tons. On the

higher side, perhaps 150 million tons might be

feasible. By 2000, industrial coal will have

risen even without further policies to encourage it. A minimum figure for energy use might

be 150 million tons. An upper limit is almost

arbitrary as the outcome is sensitive to so

many factors, but for the purposes of this report 200 million tons is used. Oil and gas will

be the preferred alternatives as long as they

are available at competitive prices. Solar

energy couId prove uniquely advantageous for

industry if the costs (including reliable backup)

prove competitive, as it could be used to avoid

both fuel and emission restrictions.

Residential and Commercial

Use of Coal

Coal has nearly disappeared as a fuel for

homes and commercial facilities over the last

three decades. In 1948 coal provided 50 percent of the energy used in this sector, but this

has declined to less than 2 percent. ’ The reasons are obvious: for the smalI user in particular, coal required dirty and noisy truck deliveries, messy storage in the house, and daily

‘Frank H. Boon, “Industrial Consumers May Loom

Very Large In Coal’s Future, ” Coa/ Age, February 1976

8Richard L Gordon, reprinted in Coal In the U.S. Energy

Market, Lexington Books, 1978

‘E N Cart, Jr , M, M Farmer, C E Johnlg, M Lleberman, and F M, Spooner, “Evaluation of the Feasiblllty

for Widespread Introduction of Coal Into the Residential

and Commercial Sector, ” Government Research Laboratories of EXXON Research and Engineering Company for

the Council on Envlronmental Quallty, April 1977
46 ● The Direct Use of Coa/

stoking and ash removal, and it left the air

laden with smoke and fumes. Most Americans

turned to oil and gas, and the coal retail market (essentially the same as residential and

commercial use) nearly followed the transportation market into oblivion as shown in figure

1. Recently, however, concerns over the price

and availability of oil and gas have sparked a

flurry of inquiries, though not yet substantial

orders, to manufacturers of coal-fired equipment. Although a return to coal might at first

appear unlikely, the scenario warrants examination because of the large energy consumption of the residential and commercial sectors

(21 percent of the U.S. energy budget). Appendix I I I analyzes this potential in greater detail.

The retail market now is about 12 million

tons per year, including anthracite. Most of

this is consumed in the Appalachian coal-producing States, plus New York, Illinois, and

Michigan. There is no national or even regional

market structure for coal or furnaces. Dealers

purchase coal from the mines (usually small

ones) and have it delivered by train or truck. As

the purchases are usually made on a one-time

basis (spot market) in small quantities, and delivery is made without the economies of scale

utiIities enjoy, the retaiI price of coal is startlingly high, perhaps $80 to $100 per ton. These

prices are probably enough in themselves to

preclude a resurgence of coal use, but they

could drop if the retail market develops into a

more stable operation, Many mines sell coal

by the pickup truck load at about $30 per ton,

and retail markets in the mining areas carry it

at $40 to $45 per ton, but this will benefit only

those living near coalfields.

Although improvements in equipment, such

as automatic stokers, and improvements in

combustion technology could increase residential use of coal, the scenarios used here do

not anticipate much growth. Coal-fired district

heating plants (such as the U.S. Capitol Power

Plant) may be the only way that coal could experience a resurgence in the residential market, as such large plants make stringent environmental controls practical and relieve the

end-use consumer of the inconvenience. Large

commercial customers may, however, find it

economical to use coal in either conventional

boilers or fIuidized-bed combustion units.

Given the marginal economic advantages,

the choice of coal as a heating fuel for the

residential/commercial sector is not likely to

be based on economic or financial calculation

alone. Convenience and reliability of supply

wiII probably be of major concern. The projected scenarios envision residential/commercial use of coal to double from 12 million tons

in 1975 to 25 million in the year 2000, a growth

that is virtually immaterial to the national energy picture, but perhaps environmentalIy significant in some regions.

Distribution of Coal Combustion

and Production

The national levels of consumption shown in

table 3 will not be uniform across the country. ,

Most coal will be burned within a few hundred

miles of the coal fields, as it is now. The regional distribution of use is shown in figure 2 and

listed in table 4. Production by State is shown

in table 5. Even more than for the national

levels, these projections are not estimates but

indications. The actual distribution wilI depend on relative changes in regional cost of

production and transportation, success in controlling emissions of high-sulfur coal, customers’ perceptions of the reliability of delivered

supply, and other unpredictable factors. Policy

decisions affecting these factors can produce

inter regional shifts of several hundred million

tons annually by 2000. For instance, the trend

towards Western coal is expected here to moderate after 1985 because of the full scrubbing

regardless of sulfur content required by the

Clean Air Act Amendments of 1977 (discussed

in chapter IV, pages 167-1 75).

The manpower required to produce this coal

(assuming no change in mine productivity) is

shown in table 6.

Conclusions

The coal projections discussed here appear

to be achievable under the present Iegal/reguIatory and economic climate. If actual use
Ch. I/—Energy and the Role of Coal ● 47

Figure 2.—Coal Combustion Distribution

1976 1985 2000

High LOW High L O W

,.

t 1

1976 1985 2000

High Low High Low

1976 1985 2000 1976 1985 2000

~;. $

s EAS T

SOUT H r SWTH /4TLANTl C

CENTRAL t \

I

1976 1985 2c00

High Low High Low
48 . The Direct Use of Coal

Table 4.—Powerplant and Industry Coal Combustion

(million/tons)

6 1985

Low

industry

o

15

16

10

6

3

6

6

28

90

High

utility

High

industry

Low High

Utllity

High

Region” industrv

New Englan d

Middle Atlantlc .

Utility

0.8

45

83.3

84.7

12.7

4

39

52

145

4465

Industry

o

10.85

10.85

6.33

1.61

.4

3

3

utility

3

64

124

101

112

11

~

185

775

2 :

25

15

15

5

10

12

45

150

2

58

106

88

98

10

66

66

South Atlanti c

East South Centra l

West South Centra l

Pacific .,

Mountain ~

West North Central.

East North Centra l

14

16

24.4 57

80.64

161 —234 159 35

Total 965 150 . 675 1410 200

Mountain. New Mexico, Arizona, Utah, Colorado, Nevada, Idaho, Montana. Wyoming

Middle Atlantic New York, Pennsylvania, New Jersey Pactflc- California, Oregon, Washington

South Atlantlc Maryland. Delaware. West Virginia, Virginia, North Carolina, South Carolina, Georgia, Florida West North Central. North Dakota, South Dakota, Minnesota, lowa, Nebraska, Kansas, Missouri

‘New England Maine, New Hampshire, Vermont, Massachusetts, Connecticut, Rhode Island

East South Central -Kentucky, Tennessee, Mississippi Alabama

West South Central Arkansas, Louisiana, Oklahoma, Texas

East North Central- Wisconsin, Illinois, Indiana, Michigan, Ohio

Table 5.—Coal Production Projections

(million of tons per year)

Tota l

- “

.—— —— —

Surtace Uncle

!

~

High

15

1

49

3

40

20

:

35

175

10

55

32

35

3

135

11

64

200

120

135

140

10

15

310

OQ5

315

10

—

40

2

30

15

3

5

25

130

5

39

21

28

2

14

—

34

2

12

4 6

38 45

70 80

7

: :

355

3

62

25

41

4

3:

74 43 110

205 I 132 680

10

165

57

77

6

315

11

94

210

125

7

24

27

28

5 5

95

13

30

65

50

47

54

10

6

220

495

745

91 95

6

45

130

: ;

85

6

9

260

700

925

54

—

4

—

—

—

—

9

—

—

13

120

—

25

5

:

—

39

1

5

135

11

39

55

175 215

13 8

45 70

60 135

11

6

29

11

12

17

.

5

45

141

55

38

37

43

10

5

198

415

620

.

3$ 43 77

80 110 154

250 689 —

417 ‘-

272

a

I ---- i — 1978 Keystone Coal Industry Manual p 666 (estimated)

bibid. pp. 674-685 data adjusted to eliminate present production capacity

does not rise to these levels, it is more likely to

be from lack of demand rather than restricted

supply, but several factors could induce the

latter situation, as discussed in chapter IV. Demand for coal could remain below these levels

either because energy demand has been successfuIly curtailed or other fuels prove unexpectedly bountiful. Neither situation calls for

remedial action, though attention could still

be directed to reducing the negative impacts

of coal (see chapters V and Vi).

If it is deemed necessary to achieve projections higher than these because of disappointing oil and gas discoveries or inadequate

growth by nuclear and other energy sources,

attention may have to be directed to loosening

environmental and other restrictions or accelerating development of technologies that better accommodate them. Coal’s growth rate

may also need acceleration beyond that dictated by the immediate market conditions,

possibly because of an unexpected sharp drop
Ch. //—Energy and the Role of Coal ● 49

in oil or gas availability. Then greater efforts of following chapter. Detailed analyses of the imcoercion or incentives would be required, placations, such as emission quantification,

possibly coupled with a streamlining of

process of getting mines into production.

These scenarios are used as guidelines in

the have not been made, as the results would not

vary greatly from published analyses.

the

Table 6.—Coal Mine Employment Forecasts

— . .

State —..—. — . .

Appalachia

Alabama

Georgia

Kentucky

Maryland

Ohio

Pennsylvania

Tennessee

Virglnla

West Vlrglnla

Total ApplachiaMidwest

Missouri

Illinois

Indiana

Kentucky (west)

Oklahoma

Total Midwest -

west

Arizona

Colorado

Montana

New Mexico

North Dakota

Texas

Utah

Washington

Wyoming

Total West

Surface

Low

3,290

—

6,725

575

3,210

6,070

940

1,480

4,410

26,680

590

3,980

3,510

2,960

845

11870

660

1,920

1,800

3,090

1775

2,340

1,670

7641

1210

15,200

High

4,080

240

7,470

770

4,010

6,6&3

1,180

1,910

5,630

31,970

790

5,170

4,490

3,380

1,410

15,240

780

2,740

2,130

4,070

2,250

2,940

1,670

910

1,350

18,840

— —

2000

Low

2,720

—

7,470

380

4,810

3,040

710

1 060

6,120

26,310

990

6,720

2,950

3,950

560

15,170

480

4,110

4,260

6,100

3,840

4,630

1,330

1,360

1,660

27710

High

.

4,080

—

9160

575

6,420

4,050

940

t 700

8,570

35.495 “

1.970

9,470

4,490

4,930

850

21,710

660

5.850

6,550

9,760

6480

7,630

1,670

2270

1,910

42,780

———- — Under — - — — 1

iow9,430

—

20,010

475

9,990

22,090

1,380

11,090

42,480

116,945

—

12,440

—

6,280

1,010

19,730

—

7,840

—

910

—

9,520

—

420

18,690

5

High

11,320

—

23,210

950

11,100

25,960

1,840

12,670

47,990

--135,040

—

16,910

—

7,850

2,020

26,780

—

8,720

—

490

1,360

—

10,830

—

1,260

22,660

ground

2000

Low I

16,970

—

34,010

950

17,7611

44,180

1,640

13,200

88,950 —

197,8&”

--- 1

23,920

2,820

10,360

2,020

39,12 0 t —10,900

2,270

970

1,360

—

12,800

860

2,110

31,270

,

High

25,150

46010

1,420

27,750

55,230

2,300

21,110

103,160

282,130

—

35,090

7,080

13,180

3,030

58,360

—

13,070

4,540

2,430

1,820

—

16080

1,720

4,210

43870

Total

1985

Low

12,700

—

26,740

1,050

13,200

28,160

2,320

12,575

46,890

143,63 0

590

18,400

3,510

9.240

1,855

31595

660

9,760

1,800

3,090

2,685

2,340

11,190

760

1,625

33,900

High

15,400

240

30,680

1,720

15110

32.640

3,020

14,580

53,620

167,01 0

-

790

22,080

4,490

11,230

3,430

42020

780

11,460

2,130

4560

3,610

2,940

12,500

910

2610

41500

I

2000

Low

19,690

—

41480

1,330

22,570

47,220

2,550

14,260

75,070

224,170

990

30,640

5,770

14,310

2,580

54,290

480

15,010

6,530

7,070

5,200

4,630

14,130

2.220

3710

58,980

High

29.230

—

55,170

1,995

34,170

59,280

3,240

22,810

111,730

317,62 5

1,970

44,560

11,550

18,110

3,880

80,070

660

18,920

11,090

12,190

8,300

7,630

17,750

3,990

6,120

86,650 -
Chapter II

COA TECHNO

TECHNIQUES 

OGY AND
Chapter lll.–COAL TECHNOLOGY AND TECHNIQUES

Page

Patterns of Use ● * * * * * * * . * . * . . ****.*.,. 53

Eastern Deep Mined Coal Burned at an

East Coast Plant . . . . . . . . . . . . . . . . . 54

Eastern Strip-Mined Coal Burned at a

Mine-Mouth Plant. . . . . . . . . . . . . . . . 55

Western Strip-Mined Coal Burned at a

Midwestern Plant .

Coal Resources . . . . . . .

Types of Coal . . . . . .

Coal Formations . . . .

Coal Distribution . . .

Eastern Regions. . .

Western Regions. .

Mining and Preparation .

Surface Mining . . . . .

Underground Mining.

Coal Preparation. . . .

Capital Costs. . . . . . .

. . . . . . . . . . . . . . . 55

. * * * * . ******.** 55

. . . . . . . . . . . . . . . 57

. . . . . . . . . . . . . . . 58

. . . . . . . . . . . . . . . 58

. . . . . . . . . . . . . . . 60

. . . . . . . . . . . . . . . 64

● * * * * * ******.** 64

. . . . . . . . . . . . . . . 64

. . . . . . . . . . . . . . . 69

. . . . . . . . . . . . . . . 73

. . . . . . . . . . . . . . . 77

Transportation and Transmission . . . . . . . . . 77

Railroads . . . . . . . . . . . . . . . . . . . . . . . . . 78

Waterways . . . . . . . . . . . . . . . . . . . . . . . 78

Highways . . . . . . . . . . . . . . . . . . . . . . . . 81

Slurry Pipelines . . . . . . . . . . . . . . . . . . . . 81

Electric Transmission . . . . . . . . . . . . . . . 83

Transportation Patterns and Cost. . . . . . 84

Combustion Technology and Methodology . 87

Utility Boiler Furnaces . . . . . . . . . . . . . . 88

Pulverized Coal-Fired Boiler Furnace . 88

Characteristics of Pulverized Coal

Furnaces ., . . . . . . . . . . . . . . . . . . . 89

Supercritical Boilers . . . . . . . . . . . . . . 89

Slagging and Fouling. . . . . . . . . . . . . . 90

Cyclone Furnaces . . . . . . . . . . . . . . . . 91

Industrial Boiler Furnaces. . . . . . . . . . . . 91

Pulverized Coal-Fired Industrial

Boiler Furnaces . . . . . . .

Spreader Stokers. . . . . . . .

Traveling-Grate Stokers . .

Underfeed Stokers . . . . . .

Vibrating-Grate Stokers . .

Air Pollution Control Technology

Particulate Control , . . . . . . .

Cyclone Collectors . . . . . .

Electrostatic Precipitators

Wet Scrubbers. . . . . . . . . .

Fabric Filter Baghouses. . .

Sulfur Oxide Control. . . . . . .

. . . . . . . . . 92

. . . . . . . . . 92

. . . . . . . . . 92

. . . . . . . . . 92

. . . . . . . . . 93

. . . . . . . . . 93

. . . . . . . . . 93

. . . . . . . . . 93

. . . . . . . . . 94

. . . . . . . . . 95

. . . . . . . . . 95

. . . . . . . . . 95

Flue-Gas Desulfurization -Utilities . . 95

Input Requirements . . . . . . . . . . . . . . 96

cost. . . . . . . . . . . . . . . . . . . . . . . . . . . 97

Alternative FGD Processes . . . . . . . . . 98

Page

Flue-Gas DesulfurizationI-Industrial. 98

Nitrogen Oxide Control. . . . ‘ . . . . . ., . . 98

Future Technologies. . ..................100

Coal Preparation. . .................100

Mechanical Coal Cleaning . ........100

Advanced Cleaning Processes. .. ....100

Solvent-~Refined Coal . ..............101

Low-Btu Gas and Combind Cycles .. ..101

Fluidized-Bed Combustion . ..........102

Magnetohydrodynamics. . ...........104

Fuel Cells . . . . . . . . . . . . . . . . . . . . .. ..104

7<

8.

9

10.

11.

12.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

TABLES

Page

Examples of Coal/Lignite Deliveries at

U. S. Powerplants During 1977. . . . . . . . 55

Coal Ranks and Typical Characteristics 57

Geometric Mean of 36 Trace-Elements

in 601 Coal Samples From Four Major

Coal-Producing Regions . . . . . . . . . . . . 60

Recoverable Reserves as of January 1,

1976 . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Mechanically Cleaned Bituminous Coal

and Lignite . . . . . . . . . . . . . . . . . . . . . . 76

Origin and Destination of Coal

Deliveries to Electric Utilities in 1976. . 85

FIGURES

Page

Coal System Components. . . . . . . . . . . 54

U. S. Coal Resources and Reserves. . . . . 56

Regional Recoverable Reserves That

Burn With Emissions Equal or Less Than

Indicated. . . . . . . . . . . . . . . . . . . . . . . . 59

Coalfields of the Conterminous

United States . . . . . . . . . . . . . . . . . . . . 61

incline No. l, Herrin Bed Illinois . . . . 62

Strip Mining Method. . . . . . . . . . . . . . . 66

Typical Contour Stripping Plus

Auger Method . . . . . . . . . . . . . . . . . . . . 69

Underground Mining. . . . . . . . . . . . . . . 72

Longwail Mining System . . . . . . . . . . . . 75

Coal Distribution by Transportation

Mode and End Use, January-September

1977 . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

Lime-Limestone Scrubbing System . . . . 97
Chapter Ill

COAL TECHNOLOGY AND TECHNIQUES

This chapter describes the various conditions and technologies that exist in the coal system from resources in the ground through use and disposal of wastes. The section below provides an overview and summary. Subsequent sections expand on the various elements of the

system.

PATTERNS OF USE

Coal is burned to produce heat, which in

turn is used to generate steam for process heat

or the production of electricity. Alternatively

the heat may be used directly in industrial

process systems or space heating. Coal also

can be used to effect chemical reactions as in

the reduction of iron ore or the production of

lime, or indirectly as a source for synthetic

gaseous or liquid fuels, but such uses are not

considered in this report.

Although the direct use of coal in the utility,

industrial, commercial, and residential sectors

is commercially feasible using current technology, other factors may limit its use. The total

energy system — from resources in the ground,

through extraction, transportation, and end

use— must be examined to identify constraints

on and impacts of its use. Figure 3 illustrates

the variety of conditions and technological options that must be considered in the direct use

of coal.

Coal is an abundant, widely distributed resource in the United States. It is variable in

composition, moisture, sulfur, ash, and trace

element content. Because of geological and

geographic differences, mining and transportation methods vary. In Appalachia, most coal is

mined underground with a variety of mechanized equipment. Most Midwestern and Western coal is surface-mined, using giganti c

shovels or draglines to remove the overburden

and expose the seam. Railroads are the dominant transportation means. I n the East and

Midwest, barges are important supplements.

Alternatively, the coal may be converted to

electricity at the minesite and the energy transported to market by wire.

The major factors influencing the design of

combustion facilities are the size of the unit,

the type of coal to be burned, and the environmental standards it must meet. Thus it is difficult and sometimes impossible to switch to a

different coal. Also the technology of the utility sector is often inappropriate for the industrial or commercial installation.

Because of the many interrelated factors involving coal, geographic conditions, and technologies, control equipment and methods

often must be “fine-tuned” to individual circumstances. Reclamation techniques must be

adjusted to topography, climate, and future

desired land use and social values. Control of

sulfur oxide (SOx emissions from the burning

of coal can be achieved by removing sulfur

before, during, or after combustion. The most

effective and economical design for a particular case depends on such matters as the mode

of operation of the combustion unit, the sulfur

concentration in the coal, the availability of

quality absorbents, etc. Similarly, the efficiency of particulate control technology can be affected by changes in the sulfur content of the

coal or the physical and chemical composition

of the ash.

New technologies for extracting, transporting, “cleaning, ” upgrading, and burning coal

are continuously emerging, as are environmental controls for every phase.

To illustrate the combinations that exist in

the overall coal-energy system, three hypothetical examples are depicted for the utility sector as end-user. Each user is an electric powerplant of 800 MW operating 70 percent of the

time.

53
54 ● The Direct Use of Coa/

Figure 3.—Coal System Components

t

Surface

Area

Contour

Auger

“This system undergoing research and development in the U.S.

● “Can be considered an alternate to coal transportation in getting the energy to the final point of use.

SOURCE: Office of Technology Assessment

Eastern Deep-Mined Coal Burned at Next, the coal is loaded onto railroad hopan East Coast Plant

The plant requires about 1,85 million tons of

coal per year with a heat content of 13,500

Btu/lb. Any one of the five largest West Virginia underground mines could currently be the

single source. Such a supply requires mining at

the rate of about 275 acres per year if the seam

is 8 feet thick. After the coal is brought to the

surface it is crushed, screened, washed, and

dried at a preparation plant near the minesite.

About 700 persons are employed for extraction

and preparation. The price of the coal leaving

the preparation plant is $30/ton.

per cars in a unit train. The train consists of 100

cars and makes three 250-miIe round trips each

week between the preparation site and the

powerplant. Transportation adds about $5 to

$8 per ton to the price. At the powerplant, a 60-

to 90-day supply is normally stored to assure a

continuous feed to the boilers during any

short-term supply interruption. Three-fourths

of a pound of coal is burned to produce a kilowatthour of electricity. Ten percent of the coal

is ash. I n the combustion step about 20 to 40

percent of the ash settles and is removed from

the bottom of the furnace. The lighter residual

ash is entrained in the flue gases and carried
Ch, Ill—Coal Technology and Techniques ● 55

out as “fly ash, ” more than 99 percent of

which is coIIected in particulate control equipment. In some plants, a portion of the ash is

used for cement and the remainder disposed as

sol id waste, The plant is 20 miles from the

main electric load center. A transmission line

of 66,000 volts is used to deliver the power to

the distribution network, where the voltage is

appropriately reduced for ultimate use in the

industrial, commercial, and residential sectors.

Eastern Strip-Mined Coal Burned at a

Mine-Mouth Plant

This coal has a lower heat content (11,300

Btu/lb) than that in the previous example, so

2.2 million tons are needed annually. It is produced at a mine by simultaneously exploiting

three superimposed seams. The top seam is 9

feet thick and lies under 100 feet of overburden. The second and third seams are 4 and 6

feet thick and lie below intervenin g layers of

10 feet of shale. Eighty-five acres of coal are

removed yearly. A total of 250 miners are employed in two operating shifts. The coal is

crushed, screened, and transported 15 miles by

truck to the powerplant, Although the powerplant is similar to that in the previous example,

it is larger to accommodate the greater volume

of coal with high moisture and ash content.

The ash is returned to the mine. The higher

capital cost of the powerplant is offset by the

lower operating cost of the fuel – $20/ton.

Western Strip-Mined Coal Burned at a

Midwestern Plant

This coal has only 8,500 Btu/lb, so 3 million

tons/yr are required. A 30-foot seam is exploited by 90 miners working in two shifts. The

overburden is 125 feet. Mining and reclamation proceed at the rate of 50 acres/yr. The extracted coal is crushed and screened at the

mine and delivered to the powerplant daily by

a 100-car unit train. As the 1 ,000-miIe trip requires 50 hours each way, excluding loading

and unloading time, six trains are continuously

in service and spare equipment is provided for

maintenance periods.

These examples, although hypothetical, are

similar to actual cases. Table 7 lists quantitative values in some actual cases. The diversity

of suppliers, customers, types of coal, means

of delivery, and contracts revealed in the table

illustrates the variabiIity in a coal-based energy system.

Table 7.— Examples of Coal/Lignite Deliveries at U.S. Powerplants During 1977

Wt Wt Wt Coal Con- Con- Deliv.

Cap Btu/b sulf. ash moist tram

Plant and unit no State MW

veyor Barge tract price c

Stri p

a Dee pa l b % % % miles feet males yrs $ ton Origin, State, and mines

Walsh, # 1 Tex. 528 1.75 -- 8,250 030 50 320 1,451 — 25

Monticello, #l-2. Tex.

1669

1,150 292 -- 6300 070 143 350 11 –

Chesterfield, #5-6

25 4 30dd

Va. 1,000 1 25 22 12500 1 20 100 120 450 — 25 3700

av

Kincaid, #l- 2 Ill. 1,212 — 2.80 10500

WiII County, #l-4 Ill,

370 90 16,8 – 1 130 — 34 1950

1,093 250 – 9,600 0.46 45 232 1,246 –

Powerton, #5-6 . Ill.

175 20 2370

1 700 1 70 1 70 10,550 368 11 8 137 410 – — 4 1300

Chalk Point, #l- 2 Md. 660 41 13 12,995 1 71 122 6 3

Bruce Mansfield, #1

3 3 0 —

Pa.

25 2800

825 – 292 11,500 310 150 100 – 80 25 2300

Wyoming, Amax, Gillette

Texas, Winfield

E Kentucky, St Paul

Illinois Peabody #10

Mont & Wyo Decker & Big Horn

Illinois Monterey (Deep) Captain

(Strip)

Centr. W Penn some Md

Ohio, Quarto, Wheeling

a 

In millions of tons

b AS received by utility

c Estimated average price duuring 1977

d The $430 per ton quoted does not include transportation over the utility's 11-mile self-operated rail system.

COAL RESOURCES

Coal deposits already identified in the more than 500 years. It is estimated that other

United States contain enough energy to supply deposits, as yet unidentified, are equivalent in

the Nation’s entire present energy demand for magnitude. By comparison, the known re-
56 ● The Direct Use of Coa/

serves of domestic crude oil would last less

than 20 years at the same rate of depletion.

The amount of coal that can be extracted is

less than the quantity residing underground.

Some deposits are too small or inaccessible to

warrant the financial investment required to

bring a mine into operation. others underlie

surfaces that cannot be disturbed. Finally, all

the coal in any particular deposit cannot be extracted by even the best mining technology

and equipment because of safety or economic

considerations.

These concepts are illustrated in figure 4

and defined as follows:

●

●

●

Coal Resources are the total coal deposits

regardless of whether they can be mined

or recovered. Some but not all of the resources are known. There is no assurance

that the unknown quantities actually exist, This estimate is based on the geological similarity of potential fields to known

coal-bearing areas.

Coal Reserves are deposits assumed to be

commercially minable by virtue of their

seam thickness and accessibility. The

magnitude of reserves can be estimated

with considerably more confidence than

that of resources.

Recoverable Reserves are the estimated

tonnage of coal that can be produced

with existing mining technology. Reserves

that cannot be mined for legal, political,

social, or other reasons are not included.

The recoverable reserves represent less than

50 years of the Nation’s present total energy

consumption, and this figure is subject to

downward revision if more stringent regulations are enacted. Upward revision will result if

the estimated resources can be identified, or if

new techniques increase the recoverable fraction. Coal may never be required to supply energy at such a high consumption rate (75

Quads of energy imply about 3.75 billion tons/

yr), although it did supply almost 80 percent of

a much smaller demand in 1910. It can, however, substitute for a large share of the decline

in the production rate of oil and gas. Unlike oil

and gas, coal can be a major source of energy

through the 21st century.

The estimates of recoverable reserves in

figure 4 are for deposits no deeper than 1,000

feet and at least 28 inches thick if they are to

be mined underground, or with depth-to-seam

thickness ratios of 10 or less for surface mines.

These limits are set for reasons of mining economics. Large quantities of coal exist in otherwise minable deposits that do not meet these

qualifications, but little incentive now exists to

mine them because others are less expensive to

mine. Until the energy expended for recovery

exceeds the recoverable energy, no intrinsic

reason exists why these less attractive deposits

cannot eventually be exploited after more favorable seams are exhausted. Average depths

of coal mines in Europe exceed 1,000 feet. One

Figure 4.- U.S. Coal Resources and Reserves

Billion

tons

4,000

3,000

2,000

SOURCE ‘Paul Averitt Coal Resources of the United States Jan 1, 1974

Geological Survey Bulletin 1412

“ “ Based on 57 percent recoverability in underground mines and 80 percent in

surface mines
Ch. Ill—Coal Technology and Techniques . 57

mine in the U.S.S.R. is reported to operate

deeper than 2,500 feet. Even in the United

States, one Colorado coal mine is at a 3,000-

foot depth and an Alabama coal mine at 1,900

feet. Several Appalachian seams of less than

28 inches are mined underground. Exploitation

of these reserves presently uncounted as recoverable could substantially extend the useful lifetime of coal.

Types of Coal

Coal is divided into five classes: anthracite,

bituminous, subbituminous, lignite, and peat.

Peat is the earliest stage in the formation of

coal. Heat and pressure force the moisture and

hydrocarbon from the peat until progressively

higher ranks of coal are formed. Thus, anthracite contains the lowest percentage of moisture and the highest percentage of carbon. The

chemical and physical properties of the other

types lie between anthracite and peat. The

composition, heat content, and locale of typical ranks of coal are shown in table 8. Highvolatile bituminous coals have agglomerating

characteristics (tendency to fuse when heated),

as do higher ranks of coal generally. The

lowest rank coals, subbituminous and lignite,

are nonagglomerating. In general, moisture

and volatile content decreases and fixed carbon increases with increased rank.

Boilers and furnaces can be designed to

burn almost any coal, but may not be readily

adaptable to other coals even of the same

types. The characteristics that affect equipment design are the heating value, ash melting

characteristics, hardness of both the coal and

its mineral matter (for grinding), and mineral

composition, which affects corrosion and fouling tendencies. Coal beneficiation can improve undesirable characteristics and reduce

the differences among coal types.

The sulfur content of coal became increasingly important when limits were imposed by

the Clean Air Act of 1970 on emissions from

combustion. New or modified powerplants

starting operation between 1974 and 1978 are

limited to emissions of 1.2 Ibs sulfur dioxide

(SO,)/million Btu of input. (More stringent

Table 8.—Coal Ranks and Typical Characteristics

Coal rank Coal analysis, bed moisture basis

Class Group State County M VM FC A S Btu

1. Anthracitic . . . . . . . . . . . . . . . 1.

2.

3.

Il. Bituminous . . . . . . . . . . . 1.

2.

3.

4.

5.

Ill. Subbduminous . . . . . . 1.

2.

3.

IV. Lignitic . . . . . . . . . . . . . . . . . . . . 1.

2.

Meta-anthracite

Anthracite

Semianthracite

Low-volatile bituminous

coal

Medium-volatile bituminous

coal

High-volatile A bituminous

coal

High-volatile B bituminous

coal

High-volatile C bitummous

coal

Subbitummous A coal

Subbituminous B coal

Subbituminous C coal

Lignite A

Lignite B

Pa.

Pa,

Va.

W.Va

Pa.

Pa.

Pa.

Pa.

Ky.

Ohio

Ill.

Utah

Ill.

Mont.

Wyo .

Wyo .

N.D.

Schuylkill

Lackawanna

Montgomery

McDowell

Cambria

Somerset

Indiana

Westmoreland

Pike

Belmont

Williamson

Emery

Vermilion

Musselshell

Sheridan

Campbell

Mercer

4,5 1.7 84.1 9.7 0.77

2,5 6.2 79.4 11.9 0.60

2.0 10.6 67.2 20.2 0.62

1.0 16,6 77.3 5.1 0.74

1,3 17,5 70.9 10,3 1.68

1.5 20.8 67.5 10.2 1.68

1.5 23.4 64.9 10.2 2.20

1.5 30.7 56,6 11.2 1.82

2.5 36,7 57.5 3.3 0.70

3.6 40.0 47.3 9.1 4.00

5.8 36.2 46.3 11.7 2,70

5.2 38,2 50.2 6.4 0.90

122 38,8 40.0 9.0 3.20

14.1 32.2 46.7 7.0 0.43

25.0 30,5 40,8 3.7 0.30

31.0 31.4 32.8 4.8 0.55

37.0 26.6 32.2 4.2 0.40

12,745

12,925

11,925

14,715

13,800

13,720

13,800

13,325

14,480

12,850

11,910

12,600

11,340

11,140

9,345

8,320

7,255

Data on coal (bed moisture basis)

M equilibrium moisture, %. VM volatile matter

FC fixed carbon, %. A ash %. S sulfur %

Btu = Btu/lb, high heating value

Calculations by Parr formulas

Adapted from Babcock and WIICOX, Steam, Its Generation and Use, p 5-11
58 ● The Direct Use of Coa/

regulations forthcoming from the Clean Air

Amendments of 1977 will eliminate the use of

low-sulfur coal as the sole means of compliance for new powerplants. ) Maximum sulfur in

coal to meet this emission standard without

other controls is approximately 0.6 percent for

coal with a heating value of 10,000 Btu/lb. For

each 1,000 Btu/lb higher or lower, the allowable sulfur content is changed about 0.06 percent (i. e., the sulfur Iimit for coal with 12,000

Btu/lb would be about 0.72 percent). Some

powerplants will be limited to more stringent

limits, as described in chapter IV. Other users,

such as industrial facilities, may be subject to

different standards. The availability of coal by

region as a function of SOX emissions is shown

in figure 5.

A large number of other substances have

been identified in coal. Many elements were

drawn up from the soil into the vegetation that

formed coal. Later streams and ocean poured

in over the rotting beds of vegetation carrying

in mud, sand, and other minerals. Thus, coal

can contain varying degrees of many elements.

Typical elements in the mineral matter of coal

are shown in table 9. The quantities listed are

averages based on many samples. The number

of samples is indicated at the heading of each

column. As with sulfur content, elemental

composition varies widely, not only among

samples from different beds but also among

those from the same mine. All of these elements are found elsewhere in the environment,

but are known to be damaging to the environment or to human health at certain concentrations and mode of entry into organisms. The

potential for the damage, if any, cannot be

reliably predicted because the mineral matter

of most coals has not yet been fully analyzed,

and the pathways of these trace elements

through the biosphere after combustion are

generally not known. The possible effect of

trace elements in the environment is discussed

in chapter V.

Coal Formations

Coal generally occurs in major structural

basins as shown in figure 6. The actual coalbeds are within these basins. Most beds are

broad and thin with most of the coal within

3,000 feet of the surface. A few in the Rocky

Mountain region were canted very steeply with

the upheaval of the mountains during their formation. Some reach depths of 30,000 feet.

Coalbeds exhibit the structural vagaries of

geological changes that have occurred since

their inception. An example of what can be expected in the structure of a bed is shown in

figure 7. Note that the coal is not uniform in

thickness in the roof or floor condition — nor

even continuous. These variations present a

changing pattern of mine problems and even

limit the amount of reserves that can be safely

and economically recovered, Other beds, however, are startlingly level and geometrically

uniform for miles in every direction. I n the Appalachian region, an area of ancient eroded

mountains, outcrops can often be found circumscribing adjacent mountains. Some beds

are split into several layers with intervening

rock layers. Beds quite unrelated geologically

can be stacked atop each other.

The most desirable commercial beds are

those that are thick, uniform, and very extensive. The Pittsburgh bed is minable over an

area of 6,000 square miles in Maryland, West

Virginia, Pennsylvania, and Ohio with a thickness of up to 22 feet. The edges thin out over a

much broader area. This bed presents a striking continuity over this vast region and has

yielded more than 20 percent of the U.S. coal

mined to date. Other Eastern beds also cover

several thousand square miles with coal 2 to 10

feet thick. Midwestern beds can be even

thicker and broader. Herrin (No. 6) in Illinois,

Indiana, and western Kentucky covers 15,000

square miles with a thickness of up to 14 feet.

The largest bed in the United States is the

Wyodak in the Powder River Basin of Wyoming and Montana. The average thickness is 50

to 100 feet and 150 feet has been observed.

.

Coal Distribution*

Coal deposits are dispersed over much of

the country. The major coal provinces are

‘Geological Survey Bulletin, 1412.

‘This section is drawn largely from “Coal Mining, ” by

the National Research Council, National Academy of

Science, 1978.
Ch. Ill—Coal Technology and Techniques 59

Figure 5.— Regional Recoverable Reserves That Burn With Emissions Equal or Less Than Indicated

1,000,000 r I

100,000

10,000

1,000

0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6 2.8 3.0 v 10

Sulfur oxide emissions (Ibs per million Btu)
60 ● The Direct Use of Coai

Table 9.—Geometric Mean (Expected Values) of 36 Trace. Elements in 601 Coal

Samples From Four Major Coal-Producing Regions, based on sequential ppm

(parts per million) values recorded from Eastern, Appalachian coals

Average

East Interior West Texas (601)

Element (331) + (194) + (93) i- (34) = samples

B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

v . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Li . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Cu . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Crr . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

200

70

70

60

30

20

20

18.8

16

15

15

12.8

11

10.9

7

7

5

3.5

3

3

2.8

2

2

1.3

1.2

1

1

.8

.7

.3

.14

.13

.093

.074

.052

.025

72

30

30

58

10

50

20

7

16.3

10

18

58

12

19

2

7

7

2.8

.7

3

1.6

1.5

2

.77

1.4

2.3

1.4

.8

.7

.12

.1

.11

.5

.04

.063

.026

34

300

100

37

15

70

7

4.3

7.4

3

2

12.8

2

4.3

3

3

1.5

.5

3

1.5

2.4

.3

1.5

.59

1.1

.45

.7

.4

.3

.2

.06

.028

.92

.037

.245

.1

51

150

150

91

50

100

30

14

20

15

15

28

5

2.8

7

15

5

5.8

2

5

3

2

.7

1.6

4.2

1.6

2.4

.7

1.5

.2

.13

.15

.6

.11

.17

.009

89.2

137.7

112.5

61.5

26.2

60

19.2

11

14.9

10.7

12.5

27.9

7.5

9.2

4,7

8

4.6

3.1

2.2

3.1

2.4

1.4

1.5

1.1

2

1.3

1.4

.7

.8

.2

.1

.1

.5

.1

.1

shown in figure 6. About 13 percent of the entire country has coal beneath the surface.

West Virginia and Illinois are about two-thirds

underlain, while North Dakota and Wyoming

are more than 40 percent. The deposits vary

widely in size and quality, as described in the

previous sections. It is useful to separate the

recoverable reserves by their likely means of

extraction, as the impacts of strip mining are

quite different from those of underground mining. Table 10 lists the recoverable reserves and

1976 production by mining method for each

State in units of tons and heat content The

reserves in each State are large enough that

production could be increased substantially

even though several States (Virginia, Tennessee, Alabama, and Kansas) have depleted more

than 40 percent of their original reserves.

Eastern Regions

Appalachian Region: Coal production in the

Appalachian region may be characterized as

being in the advanced stages of maturity (i.e.,

having annually supplied 60 percent or more

of total national production since coal mining
Ch. Ill—Coal Technology and Techniques ● 61

x

u

(n

5

.

Y -

c

(%
62 The Direct Use of Coa/

Figure 7.— Incline No. 1, Herrin (No. 6) Bed in Illinois

r

Pleistocene glacial drift

Danville (No. 7) Coal

began in the United States). The coal is obtained from a large number of mines of widely

varying sizes and from a large number of coalbeds, many of which occur in areas of steep

terrain.

The remaining recoverable underground reserves are large, but substantial portions may

remain unmined because they occur in uneconomical seams. Surface mine reserves are

probably insufficient to support even present

production rates for more than a decade. The

coal is generally the highest grades of bituminous, but it often has a high sulfur content.

Eastern Interior Region: Coal production in

the eastern interior region involves a small

number of individual mines with relatively

high annual production rates. Indiana, western

Kentucky, and Illinois have annually supplied

from 20 to 25 percent of total national production for many years.

The greatest portion of the total remaining

recoverable reserves for underground mining

occurs in beds underlying already mined-out

seams. Very large quantities remain, especially

in Illinois.

Surface mine production has remained essentially constant for a number of years. As

surface topography is generally favorable for

large-scale surface mining, it is likely that this

method wilI be further pursued (although at reduced annual rates from individual mines) in

thinner beds as reserves in the principal beds

become exhausted.

Prospects are favorable for substantial expansion of production from underground
Ch. Ill—Coal Technology and Techniques 63

mines, Surface mines should be able to main- nificant. The coalbeds are persistent but thin

tain their present rate for many years, The coal throughout the region, except in Iowa and the

tends to have a slightly lower heat content southern portion of Oklahoma, where some

- than Appalachian coal, and the sulfur content beds are of moderate thickness. Were it not for

can be quite high. local markets, it seems doubtful that much

coal would be mined in this region. Some coal

Western Interior Region: underground prooccurring under difficult mining conditions in

duction has entirely ceased in Arkansas, Kanthe southern portions of Oklahoma and Arkansas, and Oklahoma and has been very limited sas is of metallurgical and foundry grade and is

for manv years in Iowa. While surface produc- being mined and shipped out of the region.

tion has remained approximately constant in Production in this region is unlikely to inrecent years, the amount produced is not sig- crease significantly in the near future

Table 10.—Recoverable Reserves as of January 1, 1976

Under- 1976 production

ground Surface Unheat heat derground Surface Undercontent content minable minable ground Surface

quadrillion quadrillion million million million million

State Btu Btu Total tons tons Total tons tons Total

07

28

84

17

00

3

26

6

287

446

220

70

616

17

53

15

7,500

16,700

5,200

2,000

19,100

500

1,000

400

4,900

1,200

3,600

700

4,100

100

1,100

300

12,400

17,900

8,800

2,700

23,200

600

2,100

700

16.2

43,8

41.5

24.0

88.4

0.2

7.4

4.1

29.3

39.9

48.0

12.8

20.5

2.5

14.2

4,7

45.5

83.7

89.5

36.8

108,9

2,7

21.6

8.8

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . .

Pennsylvania . . . . . . . . .

Kentucky E . . . . . . . . . . . . . .

Virginia . . . . . . . . . . . . . . .

W. Virginia . . . . . . . . . . . . . . . . .

Maryland . . . . . . . . . . . . . .

Alabama . . . . . . . . . . . . . . . . .

Tennessee . . . . . . . . . . .

180

418

136

53

516

14

27

9

Total W. Interio r 62 95 157 2,600 4,500 7,100 0.3 9.5 9.8

Montana . . . . . . . . . . . . . . .

N. Dakota . . . . . . . . . . . . . . . . . . . .

Wyomin g

S. Dakota . . . . . . . . . . . . . . .

Colorado . . . . . . .

Utah . . .

Arizona . . . . . . . . . . . . .

N. Mexico . . . . . . . . . . . . . .

Texa s

Washington . . . . . . . . . . . . . . . . .

Alaska . . . . . . . . . . . . . . . . . . . .

898

—

421

794

118

404

4

61

5

5

42

52

1,692

118

825

4

220

~r 20

5

71

52

40,400

—

18,000

39,700

8,100

19,000

300

3,000

200

300

2,000

2,500

400

600

80,100

8,100

37,000

300

10,100

3,800

300

3,200

2,500

1,000

3!700

26.1

11,1

30.3

26.1

11.1

30.9

—

0.6

—

3.4

7.9

—

0.9

—

—

9.5

7.9

10.2

9.8

14.2

3.9

0.7

—

159

91—

29

—

7,100

3,600

—

1,200

—

6.1 —

10.2

8.9

14.2

3.9

0.7

—

600

3,100

— —

— —

Total Wes t 1,598 1,485 3,083 74,000 76,100 150,100 12.8 106.9 119.7

GRAND TOTAL . . . . . . . . . . . . . . . 3,931 2,307 6,238 169,000 113,900 282,900 292.6 367.3 659.9

SOURCE Based on Bureau of Mines data
64 ● The Direct Use of Coa/

Western Regions

Surface Minable Regions: The Western States

contain the most recoverable surface-minable

reserves (75 billion tons) and are virtually untouched (except for a few large active operations). The beds generally are thicker than beds

being surface-mined elsewhere in the country

(excluding Pennsylvania anthracite). In Washington and Arizona, surface-minable reserves

are essentially those remaining in the surface

mines now active in each State; in South Dakota and Utah, surface-minable reserves are relatively small, and in Colorado, surface-minable

reserves are largely confined to the two northwestern counties.

The sparsity of surface mining in these

States has been due to their remoteness from

large markets. In anticipation of future need,

intensive prospecting and acquisition by lease

or purchase was initiated about 10 years ago,

and many large individual mines already are

operating or have been planned. Contracts for

large annual shipments from some of these

unit areas to existing or contemplated new

powerplants have been negotiated, while other

units have been set aside for prospective gasification or liquefaction plants. Plans for new

or connecting transportation facilities have

been completed or are being developed.

Underground Reserves: Excluding Washington, New Mexico, and Alaska (where significant recovery of underground reserves is considered dubious), and North Dakota and Texas

(where the lignite beds are considered unsuitable for underground mining), the Western

States of Colorado, Utah, Montana, and Wyoming contain more than 69 billion tons of recoverable underground reserves. Although important portions of the coalfields of Utah, Colorado, and Wyoming have undergone substantial depletion, many relatively unmined areas

remain. Some of these may be comparatively

difficult to mine because of the degree of dip

or the excessive thickness of overlying cover,

but in many areas mining conditions are favorable.

Significant increases in underground production in Utah and Colorado can be expected

in the next few years. Similar interest in the underground reserves in Wyoming and Montana

may also develop, although underground recovery of as much as 50 percent of the thicker

beds may be difficult with present technology,

which is generally limited to bed thicknesses

not exceeding 15 feet. If or when additional

production becomes necessary, there is no reason why underground production could not be

conducted simultaneously or subsequent to

surfacemining.

Most Western coal is subbituminous or lignite. It has a substantially lower heat content

and a higher moisture content than Eastern

coal. The sulfur fraction is typicalIy low.

MINING AND PREPARATION

A wide variety of mining techniques exist to

exploit the different types of coal seams described in chapter 11, The two general methods,

surface (i. e., strip) and underground, are used

under quite different geological conditions,

and a number of mining techniques are utilized. The ultimate choice of method and specific technique depends on a number of factors such as geological conditions, safety, productivity rate, skills available in the labor

force, economics, etc. This section presents a

brief description of the technologies, the factors that suggest a particular methodology,

and the resuIting impacts.

Surface Mining

Surface mining involves exposure of the

seam by removal of the overlying soil and

rocks (overburden), The four basic methods are

area, open-pit, contour, and auger mining. Until about 1965 surface mining of coal was not

considered feasible unless the overburden-to-
Ch. Ill—Coal Technology and Techniques ● 65

seam thickness ratio was 10:1 or less. Thus, to

justify removing 50 feet of overburden, the

coal seam would have to be 5 or more feet

thick. Since 1965, this ratio has been increasing

and, depending on the nature and structure of

the overburden, coal within 150 feet of the surface may now be economically recoverable,

even when the overburden-to-seam thickness

ratio is as much as 30:1.3

Area mining, the major strip-mining method

used on Midwestern and some Western coal

lands, involves the development of large open

pits in a series of long narrow strips (usually

about 100 feet wide by a mile or more in

length). It is the preferred method in flat terrain where the coal seam is parallel to the surface, as it is for many Western coals. Before

mining begins, access roads and maintenance

and personnel facilities must be constructed.

This phase may require 5 years and about 200

workers. If all other components (preparation

plant, transportation, and customer facility)

are in place, the process can be compressed to

as little as 1 year with a much greater demand

for manpower. The actual mining starts with

the cutting of a trench across one end of the

strip, using bulldozers or a dragline. Top soil is

reserved for reclamation, and the remaining

overburden is placed in a spoil bank. Blasting

is often needed to fracture the overburden and

coal. A loading shovel lifts the coal into large

trucks, which take it to the crusher. The

scraper or dragline is moved to the next position and opens a new trench, transferring the

overburden to the mined-out trench. This cycle

is repeated to the Iimit of the mine boundaries.

Reclamation is accomplished by smoothing

the spoil, covering with top soil, and revegetating. Figure 8 illustrates the procedure.

Open-pit mining is somewhat similar except

that it involves the preparation of a larger

area, perhaps 1,000 by 2,000 feet wide. The

overburden is moved around in the pit by truck

and shovel to uncover the coal seams. This

technique is used primarily for the very thick

Western seams.

Contour strip mining is most commonly

‘Energy A Alternatives (University of OkIahoma, May}

1975), pp. 1-21

practiced where deposits outcrop from rolling

hills or mountains, particularly in Appalachia.

This method consists of removing the overburden above the bed by starting at the outcrop

and proceeding along the contour of the bed in

the hillside. After the deposit is exposed and

removed by this first cut, additional cuts are

made into the hill until the ratio of overburden

to product brings the operation to a halt. A variant on this technique is mountaintop removal,

when the seam Iies sufficiently near the top.

Contour mining creates a shelf, or “bench,”

on the hillside. The highwall borders it on the

inside, the downs lope on the other side. Before

the enactment of the Surface Mining Control

and Reclamation Act of 1977, or prior State requirements, the overburden, or spoil material,

sometimes caused severe environmental problems. Unless controlled or stabilized, this spoil

material can cause severe erosion, landslides,

and silting of streams. Contour mining is illustrated in figure 9.

The mining equipment used in contour mining is generally smaller than that used for area

mining and consists of bulldozers, shovels,

front-end loaders and trucks, all of a scale to

fit on a relatively narrow ledge.

Auger mining is employed in hilly terrain

where the slope above the coal is too steep or

high to allow normal contour mining. The usual procedure is to contour mine as far into the

hill as practical, then auger mine further. Huge

drills, with cutting heads up to 7 feet, are driven horizontally up to 200 feet into the coal

seam.

The types of equipment used in surface mining are shown in figures 8 and 9, These items of

equipment (except auger) are used to achieve

similar basic steps in each surface mining

method, The steps and equipment used are:

1. Topsoil removal using bulldozers and

loaders. Trucks convey it to a stockpile.

2. Overburden removal, using blasting to

loosen it if it is rock or shale, and scooping it out with bulldozers, stripping

shovels, bucketwheel excavators, or draglines. Walking draglines are used in some

contour mines, but their main use is in

area mines. They have buckets up to 200

44- [$12 ( I) - - I - ,,
66 The Direct Use of Coa/

Figure 8.–Strip Mining Method

cubic yards and boom lengths of 180 to The trucks are usually used only to take

375 feet. Stripping shovels can be used in the coal to a nearby processing facility.

any type of surface mine. Bucket wheel After crushing, and sometimes cleaning,

excavators can be used with stripping the coal is stored at the tipple awaiting

shovels when the overburden is soft. From transport to market.

1 to 40 tons of overburden must be moved 5. BackfiIling the overburden is generallv

for every ton of coal mined. done simultaneously with removing it

3. Coal fracturing is usually done by blast- from a fresh area. It is graded and coming, though some types can be scooped up pacted with bulldozers.

directly.

4. Coal loading and hauling, using mine 6. Topsoil is returned and spread.

shovels or front-end loaders and trucks. 7. The area is revegetated.
Ch. I/l—Coal Technology and Techniques 67

Photo credit OTA

Western surface mining. Dragline (background) exposes coal seam while front-end loaders

(foreground) dump it into trucks for haulage to rail spur or powerplant
68 ● The Direct Use of Coa/ b

is self-revealing

Stripper shovel, eastern Ohio
Ch. Ill—Coal Technology and Techniques 69

Figure 9.—Typical Contour Stripping Plus Auger Method

Underground Mining

Underground mining is considerably more

complex than surface mining. Rather than

simply scraping away the overburden and

trucking away the coal, underground miners

must work with the thick overburden above

them, connected to the outside world by shafts

and passageways sometimes thousands of feet

long. Problems nonexistent or unimportant on

the surface loom large underground: roof support, ventilation, lighting, drainage, methane

liberation, equipment access, and coal conveyance, among others, must be dealt with.

As with surface mines, the first step is the

construction of access roads and necessary

aboveground facilities. The next step is to construct a portal —the passageway to the seam.

The selection of location and type of portal

(generally shaft or slope) depends on the particular site. The mining plan must consider

costs of access and construction, personnel

transit, and coal haulage among other factors.

From the portal, parallel entries are driven into

the coal to provide corridors for haulage, ventilation, power, etc. Cross-corridors then reach

to the sides of the mine, leaving pillars in a

checkerboard pattern to support the roof. The
deeper the mine, the bigger the

relative to the mined-out areas

Contour strip mining in Martin County, Ky. Photo credit OTA

pillars must be

I n some cases,

less than 50 percent can be removed. In such

cases it may be desirable to mine the pillars as

the equipment retreats back towards the main

corridors. The roof must then be supported by

other means or alIowed to collapse.

Equipment used in underground mining

ranges from relatively simple up to highly

automated and productive machinery. The

oldest method, still in occasional use in very

small mines, is primarily hand labor. The coal

is undercut at the bottom of the face, and

blasting holes are drilled into the face above.

Explosives shear the coal loose by forcing it

down into the cut. It is then hand loaded into

shuttle cars. This method has been almost entirely replaced by conventional mining: mechanized undercutting, drilling, and loading. Undercutting is accomplished by huge chain saws

protruding from the bottom of self-propelled

vehicles. These cut a slot about 6 inches high,

perhaps 10 feet deep, into the coal and then

across the face, perhaps 20 feet. This machine

moves to the next face while the drilling machine takes its place. The coal drill is a self-propelled vehicle with a long auger attached to a

movable boom. It drills holes above and as

deep as the cut. One hole is required for a face

area 3 to 4 feet high and 4 to 5 feet wide. The

presence of rock in the coal may mandate

more holes. Blasting (called shooting) is done

with chemical explosives or compressed gas.

The latter is considered safer, but it is slower

because only one hole can be shot at a time.

The coal is loaded by a machine that slides it

onto a conveyor belt and dumps it into a shut-
Ch. 111—Coa/ Technology and Techniques ● 71

Photo credit OTA

Shoveling loose coal at Pittston’s Buffalo Mining Co., operation on Buffalo Creek, W. Va., 1975

tle car. These cars take the coal either to a

change point, where it is transferred to a conveyor belt or mine car, or directly out of the

m inc. Roof bolting also is an integral part of

the operation in order to maintain structural

integrity of the roof. A bolting machine drills

holes in the roof and inserts anchor bolts,

which firmly attach the roof to stronger overlying layers of rock through expansion shells or

resin. Bolts are generally required on a 4- by 4-

foot array. This is one of the most dangerous

activities in the mine. AlI these operations produce a large amount of dust and liberate methane trapped in the coal. Exposed areas are

rock-dusted to prevent coal dust explosions. I n

all seams, frequent methane testing is required

at the face. Continuous monitoring is required

under some conditions. Some machines must

be hooked to a water supply for a spray to control dust. In addition, time must be spent moving equipment, changing bits, hooking up electric power, and performing maintenance. A

typical conventional mining sequence is

shown in figure 10.

Continuous miners were developed to combine the operations of conventional mining,

thereby further increasing productivity. Many

different types of continuous miners are available, but al I operate on the same basic principle. A rotating head digs into the coal and

dislodges it while arms scoop it up onto a conveyor belt for loading. Thus, the multiple

cyclic transfers of machines from face to face

in conventional mining are greatly reduced.

Most continuous miners still must withdraw to

allow roof bolting and ventilating duct extension. The continuous mining method is ill us-
Figure 10.—Underground Mining

Conventional mining I Overburden I

I Overburden I I

, I

Plan view (continuous and conventional showing coal support pillars)
Ch. III--Coa/ Technology and Techniques ● 73

Photo credit OTA

End of shift in 30” coal at Cedar Coal Co.,

Logan County, W. Va.

trated in the lower portion of figure 10. The

continuous miner’s useful activity is limited to

20 to 30 percent of the time. Haulage of coal

away from the face is a major constraint on

operations.

Longwall mining is a significantly different

approach than both conventional and continuous mining work in the room and pillar system

described above. Longwall mining has been

used in Europe for many years and is now gaining popularity in the United States. Corridors

300 to 600 feet apart are driven into the coal

and interconnected. The Iongwall of the interconnection is then mined in slices. The roof is

held up by steel jacks while the cutter makes a

pass across the face. The roof jacks are advanced with the shearer to make a new pass.

The roof collapses in the mined-out area behind the jacks. Practically all the coal can be

extracted by this process. Figure 11 shows the

major elements. A variant of the IongwalI technique is known as the shortwall. It is conceptually similar, but the shorter side of the rectangle to be mined is attacked. This rarely exceeds 200 feet.

Ventilation is a major problem in modern

mines because the highly productive equipment produces high levels of dust and methane. Dust is reduced by water sprays at the

working face. (Further discussion about the impact of dust can be found in chapter Vi.) Methane must be diluted with air to less-than-flammable limits to avoid the possibility of underground explosions. In a few mines methane is

drained from the coal seam before mining. The

operation recovers methane (natural gas) for

use as fuel and reduces the danger of mine explosions. The legal ownership of the gas recovered before mining is not clear, as mineral

rights to the coal do not necessarily convey

rights to the gas or the gas may emanate from

undeterminable regions beyond the ownership

boundary. Generally the methane content of

the coal increases at greater depths because

the methane has less opportunity to diffuse to

the surface over geologic time. Thus, as the

shallower seams are depleted and the deeper

mines are developed, the safety problem will

worsen and the recovery opportunities increase. It has been estimated that 200 cubic

feet of methane are released for every ton of

coal mined. Hence the potential contribution

to our gas supply is not trivial if the legal questions can be resolved. ’

Coal Preparation

Coal preparation modifies the mined coal to

help meet the customers’ needs in terms of

size, moisture, mineral concentration, and

heat content. A preparation plant of some sort

is an integral part of most large mines and may

often serve a number of mines. I n some cases,

particularly in the West, the coal is only

crushed. About half the raw coal in the Nation

is cleaned to reduce impurities such as mineral

4“Degasification of Coal Beds–A Commercial Source

of Pipeline Gas, ” AGA Monthly, January 1974.

Ch. Ill—Coal Technology and Techniques ● 75

Figure 11 .—Longwall Mining System

Elevation view

Overburden

/

Mining Conveyor

machine

Plan view

.

Slumped

overburden

Conveyor

1

Mining

Supports

. machine

A

Tunnel

L Air Main tunnel
76 ● The Direct Use of Coa/

lion tons, or 41,2 percent of total production of

raw coal was cleaned at a pIant. This resulted

in a net production of 267 miIIion tons of processed coal and 107 million tons of refuse. The

refuse fraction has been increasing, as shown

in table 11. Two prominent phases of increase

are notable. The first, which lasted until about

1962, was mostly due to increased mining

automation that reduced selectivity of mining

coal between mineral partings at the face. The

second, which is still in evidence, seems to be

due to the mining of lower quality coal. This

rise also coincided with a decrease in the total

amount of coal being cleaned. Utilities began

finding cleaning less worthwhile, in part

because of the growth in mine-mouth plants,

which reap no transportation benefits from the

reduced weight of clean coal. Also, much of

the increased production has come from the

West, where most coal produced is not appropriate for cleaning. A typical cleaning plant includes the following steps:

Table 11 .—Mechanically Cleaned Bituminous Coal and Lignitea

(thousand short tons)

Total raw Percent Refuse

coal Cleaned of total resulting Percent

moved to Cleaned by Total production in refuse

cleaning by wet pneumatic Total produc- mechanically cleaning

Year

of raw

plants methods methods cleaned tion cleaned process coal

1940 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1945 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1950 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1955 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1956 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1957 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1958 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1959 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1960 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1961 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1962 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1963 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1964 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1965 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1966 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1967 . . . . . . . . . . . . . .

1968 . . . . . . . . . . . . . ..

1969 . . . . . . . . . . . . . .

1970 . . . . . . . . . . . . . .

1971 . . . . . . . . . . . . . .

1972 . . . . . . . . . . . . . .

1973 . . . . . . . . . . . . . .

1974 . . . . . . . . . . . . . .

1975 . . . . . . . . . . . . . .

115,692

172,899

238,391

335,458

359,378

376,546

320,898

337,138

337,686

328,200

339,408

362,141

388,134

419,046

435,040

448,024

438,030

435,356

426,606

361,168

398,678

397,646

363,334

374,094

87,290

130,470

183,170

252,420

268,054

279,259

240,153

251,538

255,030

247,020

252,929

269,527

288,803

306,872

316,421

328,135

324,123

315,596

305,594

256,892

281,119

278,413

257,592

260,289

14,980

17,416

15,529

20,295

24,311

24,768

18,882

18,249

18,139

17,691

18,704

19,935

21,400

25,384

24,205

21,268

16,804

19,163

17,855

14,506

11,710

10,505

7,557

6,704

102,270

147,886

198,699

272,715

292,365

304,027

259,035

269,787

273,169

264,711

271,633

289,462

310,203

332,256

340,626

349,402

304,923

334,761

323,452

271,401

292,829

288,918

265,150

266,993

460,771

577,617

516,311

464,633

500,874

492,704

410,446

412,028

415,512

402,977

422,149

458,928

486,998

512,088

533,881

552,626

545,245

560,505

602,936

552,192

595,387

591,737

603,406

648,438

22.2

25.6

38.5

58.7

58.4

61.7

63.1

65.5

65.7

65.7

64.3

63,1

63.7

64.9

63.8

63.2

62.5

59.7

53.6

49.1

49.2

48.8

43.9

41.2

13,422

25,013

39,692

62,743

67,013

72,519

61,863

67,351

65,517

63,489

67,775

72,679

77,931

86,790

94,414

98,624

97,107

100,593

103,159

89,766

105,850

108,728

98,184

107,101

11.6

14.5

16.6

18.7

18.6

19.2

19.3

20.0

19.4

19.4

20.0

20.0

20.1

20.1

21.7

22.0

22.2

23.1

24.2

24.9

26.5

27.3

27.0

28.6

aU.S. Bureau of Mines Yearbook, various years

l. Comminution (crushing) to liberate impurities and provide a product of appropriate

size.

2. Sizing (to ensure uniformity of size) with

screens or fluid classification.

3. Cleaning to remove impurities. Jigging is

the technique most used. A bed of raw

coal is stratified in water by pulsations

that move the light particles (coal) to the

top and the heavy refuse to the bottom.

The two products can then be collected

separately. Dense-medium processes, the

next most popular, effect a sharper separation. The coal is immersed in a heavy

fluid in which the coal floats and the

refuse sinks. The dense-medium cyclone is

a variant that uses centrifugal force to

assist the separation. Other techniques
Ch. Ill—Coal Technology and Techniques ● 77

4.

5.

are concentrating tables, froth flotation

and pneumatic methods. These are described in appendix I I of volume II.

Dewatering and drying reduce shipping

weight and problems of handling and

combustion. Dewatering, the mechanical

separation of water, is done with screens,

filters, and centrifuges of various types.

Drying uses heat to remove water. It is

relatively expensive and can cause air

pollution problems, which explains why

the practice has been declining.

Water clarification is the process of removing enough suspended coal from the

water that the water can be recycled. This

is usually done in settling tanks assisted

by fIocculents.

The coal preparation plant may itself become a significant source of pollution even

though it serves to reduce pollution where the

coal is burned. Refuse piles contain sufficient

coal to smoulder, causing

but this can be prevented

ment, Pneumatic cleaning

mal dryers are sources of

noxious emissions,

by proper managemethods and therparticulate matter,

and both are being phased out or equipped

with baghouses. The wash water has the potential of releasing large quantities of impurities

similar to acid mine drainage. As mentioned

above, the modern practice is to recycle the

water. Completely closed loops are coming

into practice. Leaching from the refuse piles is

prevented by compaction and layering.

Capital Costs

Before a mine can be opened, a considerable amount of capital must be committed,

and the operator must be sure of obtaining the

appropriate manpower, material, and equipment. New mines are quite expensive to open.

Costs vary significantly from site to site. A

1976 estimate gave the following results in dollars per annual ton capacity. ’

Illinois

AppaIachia Basin Western

Surface 47 50 18

Underground . 66 48 48

These figures are sharply higher than earlier

estimates, largely because of hyperinflation in

the heavy equipment market. Thus a new 2-

million ton/yr surface mine in Illinois would

cost $100 million. As described in chapter 11,

this mine would just meet the demand of one

large electric utility unit. In 1976 it would have

been the 46th largest mine in the country.

TRANSPORTATION AND TRANSMISSION

Once mined and processed, coal is transported to another site for combustion. Trucks

and belt conveyors serve nearby “minemouth” facilities. Highways, railroads, waterways, and slurry pipelines are the transportation mode for longer distances. Energy from

mine-mouth powerplants can be transmitted

by high-voltage transmission cable. The cost of

transportation is a major determinant of the

availability of specific mines or combustion

facility sites. Further, the revenues earned

from transporting coal will be very important

to the transportation industry. This section describes methods of long-distance transportation of the coal and transmission of electric

power.

The following description of rail, water, and

truck transport has been excerpted from a major section on coal in a comprehensive discussion of current energy transportation systems

and movements issued recently by the Congressional Research Service. b This report and

its accompanying maps are commended to the

‘George W Land , “Capital Requirements tor New

Mine Development, ” Third Conference on Mine ProductIvlty, Pennsylvania State University, April 1976

‘National Energy Transportation, vol. I and accompanying maps, prepared for Senate Committees on Energy

and Natural Resources and on Commerce, Science, and

Transportation (Washington, D C Congressional Research Service, 1977), maps prepared by U S Geological

Survey, Committee Print, Publlcatlon 95-15
78 ● The Direct Use of Coa/

reader. Additional material on unit trains and

coal slurry pipelines is taken from a previous

OTA report. ’

Railroads

About two-thirds of the coal produced in the

United States is transported in railroad cars.

Coal is moved by rail almost entirely in opentopped hopper cars or gondola cars, which can

be unloaded by turning the car completely

over, by opening ports, or more rarely, by unloading from the top. The cars are generally

loaded from the top at mine sidings or coalIoading installations central to a number of

mines. Coal from the mines is I if ted into silos

or onto storage piIes, travels by gravity or conveyer, and then moves through a chute into the

car.

The average hopper car carries about 75

tons of coal. Older cars average 55 tons, and

the newer ones move 100 tons at capacity. The

complete cycle of loading, hauling to the unloading point, unloading, and returning for

another cargo averages 13 days for each car.

Although this is a shorter turnaround time than

is experienced for any other type of bulk move

ment, inactivity is still a major factor in the

economics of coal movement by railroad. 8

The size of hopper cars that can be accommodated depends on roadbed conditions and the

weight the track can tolerate. Western coal

unit trains tend to use 100-ton hopper cars;

Eastern shipments often require the older 55-

ton hoppers.

Unloading facilities for hopper cars, Iike

loading facilities, are large-scale, permanent

installations. They may take the form of trestles running over storage piles, into which coal

is dumped from the bottom of moving cars, or

they may be rotary dumpers, which tip the entire car over, spilling its contents. Cars with

swivel couplings need not be uncoupled to un7 A Technology Assessment of Coal Slurry Pipelines,

(Washington, D. C. Office of Technology Assessment,

1978)

‘Railroad Freight Cars Requirement for Transporting

Energy, 1974-85, prepared for the Federal Energy Administration under contract by Peat, Marwick, Mitchell, and

Co Table of turnaround times at p. 11-11

load by rotating. Some loading and unloading

facilities can handle thousands of tons per

hour. As a coal trade journal reported: “A typical requirement today would be to load three

trains per day, each consisting of 100 cars of

100 tons net loading each; provide one and

one-half train loads of storage on hand at the

start of each loading and provide a loading

rate of 4,000 tons/hr. ”9

Track conditions dictate the types of equipment and the loads that can be hauled. No general compilation of conditions is available

because they vary substantially with maintenance, weather conditions, and other factors,

but it is generally accepted that younger track,

track in the West, and track operated by the

more solvent railroads tend to be in better condition; older track, track in the Northeast, and

track owned by railroads that are in financial

trouble tend to be in worse shape.

A particular type of rail service for ,major

shippers of coal and other bulk commodities is

provided by unit trains. This type of train, designed to take advantage of economies of

scale, generally carries a single commodity in

dedicated service between two points in sufficient volume to achieve cost savings. The cars

are designed for automated loading and unloading, and the train is operated by procedures that minimize switching and time-consuming delays in freight yards.

A typical coal unit train consists of six 3,000-

horsepower locomotives and 100 hopper cars

with carrying capacities of 100 tons each.

Roughly two such trains per week are therefore

required to deliver 1 million tons of coal per

year depending on the results involved. Speeds

vary considerably depending on track conditions, but 20 to 50 miles per hour is a common

range.

Waterways

The “hardware” of the shipment of coal by

barge or other water carrier includes the tugs,

“’From Mines to Market by Rail The Indispensable

Transport Mode, ” Coal Age, v. 7, pp. 102-112 at p 103.

McGraw-Hill Publications Provides a good technical description of unit train loading and unloading,
Ch. ///—Coal Technology and Techniques ● 79

Photo credit OTA

Coal tipple on Cabin Creek, W. Va.

or self-propelled vessels, which push the by 35 feet) open barge cost $70,000 in 1968 and

“tow,” composed of as many as 36 barges, usu- probably costs more than $125,000 today; the

ally of 1,500-ton capacity, 0 from a loading towboats cost many times more. II

dock to an unloading dock. A great variety of

shapes, drafts, and power capability The loading facilities used for barges resem- sizes, ble some rail loading facilities. They generally characterizes the towboat fleet. entail a conveyor belt carrying coal from a

Modern steel barges are of numerous de- stockpile to a movable chute, which can dump

signs to handle differing commodities. Their the coal into waiting barges along a pier. Unbows and sterns are usually formed to fit into a loading facilities are much different, however:

neat tow that presents an unbroken, low-fric- barges must be unloaded without the aid of

tion surface to the water. A jumbo-sized (195

‘‘ Transportation of Mineral Commodities on the Inland

“

)Natiortal Transportation Trend\ and Cholces (Wash- Waterways of the South Central States, Bureau of Mines

ington, D C U S Department of Transportation), p 256, information circular 8431 (Washington, D C U S De258 partment of the Interior, 1968), p 13.
gravity, usually by a crane equipped with a

clam shell bucket. The unloaded coal is generally moved by belt conveyors to storage yards.

One modern unloader consists of two revolving scoops, which can clean out a barge in

three passes. The cost of such facilities is in

the millions of dollars.

On the Great Lakes, oceans, and coastal

tidewaters, single self-propelled bulk cargo

carriers are used. Three Great Lakes vessels be

ing built to carry Western coal to a Detroit utility plant wilI be 1,000 feet long and will each

12“Using Waterways to Ship Coal No Cheaper Way

When Destination is Right,” Coal Age, vol. 79, No, 7, July

1974. Description of unloading plant for J M, Stuart Generating Station on Ohio River, pp. 122-123

carry 62,000 tons of coal. They will be self-unloading, using long conveyor belts traversing

the length of the ships. 3 The average lake carrier has about 20,000-ton capacity.

The inland waterways themselves have been

constructed and maintained by the Federal

Government, with the “exception of the New

York State Barge Canal. Since the first appropriation to the U.S. Army Corps of Engineers

for this purpose in 1824, billions of dollars

have been spent to make possible the largescale commercial traffic now using these internal waterways. In general, the improvement of

a waterway to make it navigable involves

deepening and widening the channel by dredg131 bid,, pp. 126-127,
Ch. III--Coal Technology and Techniques ● 81

ing and constructing dams and locks. Erosion

control along sections of the riverbank and

operation of the dams and locks are also part

of the Federal role. There were 255 navigation

locks and dams being operated by the Corps of

Engineers as of June 1, 1976 The size of the

locks available on the river systems is the primary Iimiting factor on river traffic. They are

sized to accommodate an expected volume of

traffic that generally tapers off toward the

source of the river system. Thus in the region

of the headwaters fewer tows can be managed;

this makes it less economical to operate the

carriers and less cost-beneficial to maintain

the waterway or justify improvements.

Highways

The fastest growing means of coal transportation is by truck. As opposed to the average

haul of 300 miles by railroad, and 480 miles by

barge, the average highway shipment of coal is

only 50 to 75 miIes.

The public highway trucks carry a total of 15

to 25 tons each. The standard diesel tractor is

used to pull one and sometimes two trailers,

depending on weight limitations, Much coal

movement to nearby powerplants takes place

on private roads using vehicles too large for

public highways; some of these vehicles can

carry up to 150 tons of coal. The trucks may

be loaded from a fixed chute, but are more

often loaded by shovels or front-end loaders

directly at the side of the coal seam in a surface mine. Most trucks are dumpers. Truck

shipments are sometimes used in connection

with deep-mine operations, but most often are

connected with strip-mine operations.

Slurry Pipelines

Transport by this mode involves three major

stages:

1. grinding the coal and mixing it with a liqu id (generally water) to form the SIurry;

2. transmission through the pipeline; and

3. dewatering the coal for use as a boiler

“Ibid , p 81

+ 1- 2 - - ‘1

Photo credit OTA

Coal-truck traffic, Kentucky

fuel, for storage or for transloading to

another transportation mode.

Problems involve condemnation rights to certain property, inter-basin transfer of water, and

the discharge or use of the separated (and contaiminated) water.

Coal is assembled from a mine or group of

mines at a single point where mixing, cleaning,

or other beneficiation may take place, and

where the slurry is prepared. Preparation

begins with impact crushing, followed by the

addition of water and further grinding to a

maximum particle size of one-eighth of an

inch. More water is then added to form a’ mixture that is about 50 percent dry coal by

weight, and the resulting slurry is stored in a

tank equipped with mechanical agitators to

prevent settling Water is not necessarily the

only slurry medium, and oil — as well as meth-
anol derived from the coal itself — has been

proposed.

The slurry from the agitated-storage tanks is

introduced into a buried steel pipe and propelled by pumps located at intervals of 50 to

150 miles, depending upon terrain, pipe size,

and other design considerations. The slurry

travels at about 6 ft/sec. Ideally, the flow is

maintained at a rate that minimizes power requirements while maintaining the coal in suspension. Once started, the flow must continue

uninterrupted or the coal will gradually settle

and possibly plug the pipe. Considerable technical controversy exists over the likelihood of

plugging and the ability to restart the pipeline

after given periods of downtime. To prevent

this type of settling, the operating pipeline at

Black Mesa, Ariz., has ponds into which the

pipeline can be emptied in the event of a break

or other interruption.

At the downstream end of the pipeline, the

slurry is again introduced into agitated tank

storage, from which it is fed into a dewatering

facility. Dewatering is accomplished by natural settling, vacuum filtration, or by centrifuge,

and the finely ground coal still suspended in

the water can be separated by chemical flocculation. Additional thermal drying is generally required before use. The reclaimed water

can be used in an electric-generating station’s

cooling system to condense steam — or it couId

theoreticalIy be recycled in a return pipeline.

Schematic of Slurry Pipellne System

Powerplant

so Barges
Ch. I//—Coal Technology and Techniques 83

A potential economic advantage of this

technology is that the volume of coal that can

be transported increases approximately as the

square of the pipeline diameter (which means

that a 2-foot diameter Iine can carry four times

the amount of coal as a l-foot diameter line),

while construction, power, and other operating

costs increase more slowly. If throughput volumes are high enough to take advantage of

this economy of scale, and if the pipeline is

long enough to recover the cost of gathering,

preparing, dewatering, and delivering the coal

at the termini, the pipeline can compete with

unit trains.

Electric Transmission

The principal means of transmitting large

blocks of electric power is by high-voltage

alternating current (AC) transmission. Electrical transmission will become more important

as the number of mine-mouth plants increases.

Electricity is usually generated at voltages of

12,000 to 22,000 volts(12 to 22 kV). However, it

is not economical to transmit electric energy

at these generated voltages because the high

current levels lead to excessive resistive losses

in the transmission system. The attainment of

higher and higher transmission voltages continues to be a major goal. An AC transmission

system requires, therefore, transformers to

step up the voltage from the generator and to

step it down where it feeds into the distribution system at the load. In addition, there are

towers, conductors, and devices to protect the

system in the event of short circuits and power

surges. The conductors are designed to minimize effects of high electric fields that occur

because of the high voltages. These effects,

which include corona formation and radio and

television interference, increase energy loss

and may create disturbances for the population near the powerline.

As of 1976, there were about 360,000 miles

of high-voltage (69 kV or higher) transmission

lines in the United States. These are the candidate voltages for long-distance, mine-mouth

plant transmission lines. Currently the highest

operating transmission voltage in the United

States is 765 kV. The upper voltage has increased by a factor of more than 2.5 since

1950. Technical and environmental problems

complicate development of transmission systems beyond 765 kV.

High-voltage direct current (DC) systems for

long-distance power transmission are becoming increasingly competitive relative to highvoltage AC. Although only one is operating in

the United States (on the west coast), other nations have more experience. The principal disadvantage of DC transmission is the difficulty

in varying the voltage levels as is done with AC

systems and transformers. Consequently, it is

necessary to convert the voltage from AC to

DC and back again at each end of the DC line.

This conversion process adds considerably to

the cost of a DC system. Until now, this has

greatly limited its use, but new developments

promise to facilitate the process. The great advantage of DC is that the Iine is capable of carrying considerably more power, about 1.5 to 2

times more, than an AC system of the same

voltage. In addition to the increased energy

density, DC lines produce less radio interference and the corona loss is considerably

smaller than equivalent capacity AC Iines.

Research is currently underway to increase

the energy and economic efficiency of highvoltage electric transmission and to develop

underground systems, gas-insulated lines, and

low-resistance (superconducting lines). Systems from 1,100 to 2,300 kV are being tested.

The principal technical problems are the development of adequate insulators and the

ability to protect against surge voltages. Other

uncertainties are the possible environmental

effects of very high electric fields.

Underground transmission exists in this

country to only a very limited extent. The principal roadblock is cost, owing to the need for

cable insulation and the difficulty of installing

and cooling cables underground. There is continuing interest in high-voltage underground

transmission, however, because of the technical, environmental, and social problems of expanding overhead networks. The utility industry is conducting R&D to lower costs and improve performance, but the introduction of underground high-voltage transmission as a costcompetitive technology is many years away.
84 ● The Direct Use of Coa/

Photo credit: Texas Power & L/ght

Southwestern Electric Power Company, Shreveport, La.; Weish Power plant, East Texas; units #1 and #2

Gas-insulated and low-resistance lines similarly are undergoing long-term development programs.

Transportation Patterns and Cost

Coal is seldom mined where the energy is

needed, so transportation is an important element of coal use. Table 12 indicates, by State

of origin and destination, the tonnages transported in 1976 to electric utilities, which consume about three-quarters of all domestic

steam coal. It also shows that the average ton

moved 368 miles in the Nation. Figure.12 shows

that railroads carry most of this coal, and this

share is increasing.

Two coal slurry pipelines have been constructed in this country; one is in operation,

carrying 4,8 million tons per year 273 miles

from northeastern Arizona to southern Nevada. (The other closed after the competing

railroad introduced unit train service and

lowered its rates.)

Unit trains and slurry pipelines are clearly

appropriate only for very large users of coal.

Smaller users generally rely on less regular

deliveries by train or truck, sometimes through

an intermediary retailer. Similarly, a small

mine operator could not fill a unit train, but

must load a few cars at a time and depend on
Ch. ///—Coal Technology and Techniques 85

Table 12.—Origin and Destination of Coal Deliveries to Electric Utilities in 1976

(in thousand tons)

Destination

Norther n Souther n

Appalachl a

i

Appalacht a

l

—

—

765

—

—

10

1327

—

—

44

770

12,019,3

8.6

—

—

—

—

—

753.2

1,8948

—

5.253.7

2,908,6

38,436.9

—

37,2255

3.7

—.

481

.

—

6656

—

23,307

6953

—

the railroads to fit them into their schedules.

Transportation is thus a major factor in the

high price charged by retailers, as discussed in

chapter Il.

Of the average cost of coal delivered by rail,

transportation represents about 20 percent.’ 5

Rough approximate costs of barge, rail and

truck transport are O.4-, l-, and 5-cents/ton-mile

“.US. Coal Development– Promises, Uncertainties

(Washington, DC U.S. General Accounting Office,

1977), p 55

18,0941

—

—.

4,324,6

13.4387

1,778,7

5,086.8

838

—

22,271.4

29

7,144,4

148.1

1,0565

534

—

—

—

637.9

—

484.4

16,678,6

—

8,5102

—

186,4

5.491

—

19,549

—

—

4,643.3

—

4,8133

1,984.4

—

—.————.

Midwest

—

.

—

1,553.4

1,163.9

21,784.4

21.989,1

3,070.5

2,259.9

3.0366 —

434,3

1,4364

520.3

19,043 —

12.5 —

—

—

—

1 —

166 —

—

—

27.0

1,002.3

—

—

5,0793

——. —

—

6,528,6

4,174 —

8,0197 —

—

—

—

—

—

—

—

18,867 —

—

—

—

—

—

—

234,9

7,088,9

—

—

—

11,217,9

3,270.7

3,553.2

1,172.5

—

—

1,710

8,911.5

—

979.1

2,316

1,839,6

820.5

—

—

—

—

—

6,884.9

9,758,6

598.8

—

—

2,459.7

—

903.9

1.869

—

3,600

—

3,389.9

8,459,4

respectively,’ b and slurry pipelines can cost

less than rail under some specific conditions.

These figures do not include an element of

public subsidy for barges and trucks in the

form of Government highway and waterway

expenditures.

F U eI is required for transportation, amounting on the average to 540 to 680 Btu/net-tonmile for barge, 536 to 791l Btu for rail, and

“lbl d
86 . The Direct Use of Coal

Figure 12.—Coal Distribution by Transportation Mode and End Use, January-September 1977

(Million short tons)

Transportation Consumer

Tramway, conveyor,

and private railroad

54 (11 0/0) Electric utilities

37, (77”/, )

1

All rail

257 (53°/0)

52 (11 0/0)

194 (40°/0)

81 (16°/0)

49 (1 00/0)

36 (7°/0)

26 (5 0

/0)

● 2

● 2

27 (6°/0)

● 4

14 (3°/0)

“ Less than 1 percent

a

Includes shipments partly transported by other modes. excludes oversea exports.

b

Includes retail

SOURCE Department of Energy, Bituminous Coal and Lignite Distribution, January .Septernber 1977, Feb 6.1978

2,518 to 2,800 Btu for highway shipment. 7 Unit rently require diesel fuel from petroleum. A

trains are somewhat more efficient than rail ton of 8,500 Btu/lb coal hauled 1,000 miles at

generally, and slurry pipelines, although more 600 Btu/net-ton-mile requires the equivalent of

energy intensive than unit trains, consume 31⁄2 percent of its energy value, usually in

electricity derived from a variety of fuels, in- diesel fuel. Hence, importation of low-sulfur

eluding coal, while the other three modes cur- coal can use more energy than flue-gas desulfurization applied to local high-sulfur coals.

“Congressional Research Service, 1977, op cit., p 85 (See the section on Air-Pollution Control Tech-
Ch. Ill—Coal Technology and Techniques ● 87

nology of this chapter for a further discussion

on fIue-gas desuIfurization. )

The regional pattern of production and distribution is also sensitive to transportation

costs, One study’a

simulated the purchasing

behavior of the electric utility industry under

two hypothetical scenarios, In one, the future

cost (in constant dollars) of mining coal was

assumed to increase by 25 percent whiIe transportation cost declined in the same proportion. The other case embodied the reverse

assumption, that transportation increased by

25 percent while mining declined by the same

relative amount. The second case resulted in a

predicted production level of Appalachian

coal in the year 2000 that was twice that

predicted by the first case. Western coal exhibited the reverse behavior, amounting to

twice the production in the first case as in the

second. The pattern was also sensitive to other

considerations, Iike the extent to which powerplants constructed after 1983 with mandatory

flue-gas desulfurization would be used only

for peakloads. Traditionally, electric companies use their lowest cost pIants for baseload

and successively add higher cost units for peak

demand. In this way they provide customers

with lowest cost energy. If new plants with

scrubbers become more costly than old plants

using low-sulfur Western coal, the pattern of

coal origin and distribution may be expected

to adjust accordingly,

One of the factors affecting the economies

of powerplant siting is the cost of delivering

the power to the load center. If a number of

suitable sites are available between the mine

and the load center, the utility may choose remote siting, with power transmission replacing

coal transportation. Typical costs of transmission as a function of voltage are:

Construction

cost per

mile Capacity

345 kv $213,000 750 MW

500 kv 267,000 1,500 MW

765 kv 400,000 3,000 MW

DC lines are less expensive than

same capacity because the lower

Cost per

k Wh

(500 miles)

O 43 cent

O 29 cent

O 23 cent

AC for the

voltage allows smaller rights-of-way, towers, and conductors. As previously stated, however, DC terminals are more expensive because of the conversion equipment. Hence DC is considered

only for long lines (at least several hundred

miles). New technology, such as very high-voltage AC or DC or new types of DC terminals,

may change the equation. Underground transmission will be several times as expensive as

overhead. DC may enjoy a relative advantage

if underground transmission is required.

As for comparison with other modes, a re

cent OTA study on coal slurry pipelines estimated costs of transporting coal by both rail

and pipeline for four different routes in the

United States. The cost estimates ranged from

$7 to $8/ton for distances of 500 miles. Assuming an energy content of 20 milIion Btu/ton and

a heat rate of 9,000 Btu/kWh for the powerplant at the end of the pipe-rail line, energy

delivery cost is about 3.0 to 3.5 mills/kWh.

Costs vary considerably but in general, electric

transmission is competitive with rail or pipeline for distances of up to 500 to 600 miles. Be

yond that point, rail and slurry costs increase

at a slower rate than electric transmission

costs. Federal policies can have a substantial

effect on relative pricing advantages through

differing tax advantages and subsidies.

COMBUSTION TECHNOLOGY AND METHODOLOGY

Three major factors influence the way coal

is burned. The first is the size of the facility to

be constructed, with utilities usually building

the biggest, industry substantially smaller, and

the residential/commercial sector the smallest.

1aTeknekron, Inc , Projections of Utility Coa/ Movement Patterns: 1980-2000, OTA, 1977

The latter units are responsible for such a

small fraction of coal burned that they are not

described here. A full description is included in

appendix I I I of volume 11. The second factor is

the set of environmental standards the facility

is required to meet, The rapidIy changing regulatory climate is radically changing coal use

patterns and forcing the development of new
88 ● The Direct Use of Coal

technologies Finally, the characteristics of the

coaI to be burned control some design parameters as discussed earlier in the section on Coal

Resou

Uti

sign f

rces.

Utility Boiler Furnaces

ity boiler furnaces generally have a dering rate greater than 250 million Btu/hr,

equivalent to about 10 tons of bituminous coal

per hour. The largest utility units burn as much

as 500 tons of coal each hour at fulI load. Industrial boilers usually range downward from

the smaller utility units, from 20 tons to about

3 tons of coal per hour. Large coal-fired utility

powerplants are much the same in principle today as they were in the 1920’s when pulverized

coal was first used to generate steam. Today’s

boiler furnaces are much larger, produce

steam at much higher temperatures and pressures than half a century ago, and are more efficient in converting the energy in coal into

steam. But the concept of grinding the coal to

very small size and blowing it with air into

large furnace cavities, where the cloud of coal

dust burns much like a fuel gas, is still the way

most coal is burned today.

Pulverized Coal-Fired Boiler Furnace

The principles of this most widely used

steam generator are relatively simple. Raw

crushed coal is fed continuously into pulverizers, where the coal is dried and ground so that

at Ieast 70 percent wiII pass a 200-mesh sieve

to form a combustible cloud of coal. Air,

heated by the spent products of combustion

before they enter the stack, is blown through

the pulverizers, drying the coal and conveying

it to the burners in the boiler furnace. At the

burners, additional heated air is mixed with the

airborne coal stream to provide a SIight excess

of oxygen to ensure complete combustion. The

coal burns in a long, luminous flame in the

huge furnace cavity at temperatures in the

flame of at least 2,7000 F. Heat energy from

this flame is transferred largely by radiation to

the relatively cool furnace walls. The heat is

transferred to water, which boils to generate

steam. The steam is separated from the unevaporated water in a steam drum at the top of

the boiler. The water is returned by “downcomers” to the bottom of the boiler, where it is

distributed by “headers” to the lower end of

the furnace wall tubes to pass once more

through the heated zone of the furnace,

Steam, separated from the unevaporated

water, flows through superheater tubes of lowalloy steel located at the furnace outlet. These

banks of tubes may be heated partly by radiation from the pulverized-coal flame, but usually mostly by convection from the hot furnace

gases, now cooled to about 2,0000 F. This

raises (superheats) the temperature of the

steam to about 1,0000 F as it leaves the boiler

for the steam turbine. After expanding in part

in the turbine and converting some of its heat

energy into shaft horsepower, the partially

cooled steam may be returned to the boiler

where it passes through another bank of boiler

tubes that reheat the steam. The steam at various stages of the turbine is bled in part to auxiIiary equipment to heat water or to power apparatus and finally to the condenser, which

reduces the final pressure at the exit of the turbine to below atmospheric pressure. The condensed water is pumped back through a series

of heaters and an economizer— a bank of

boiler tubes located downstream of the superheater and reheater. Here some of the heat in

the flue gas that otherwise might be wasted

raises the temperature of the boiIer feed water,

which passes once more into the boiIerdrum.

Flue gas leaving the economizer still contains appreciable heat energy, which is recovered in part by passing it through an air heater,

generally a massive array of mild-steel sheets

arranged in bundles or “baskets, ” which rotate

successively between ducts carrying the flue

gas to the stack and air to the furnace. Tubular

heat exchanges have been widely used as air

heaters, but rotating platetype regenerative

heaters described above are common. In either

type, metal heated by the flue gas passes the

heat to the incoming air, which usually is

raised to temperatures between 3000 and 6000

F. Because the overall efficiency of a steamgenerating unit as a whole will increase about

2.5 percent by raising this air temperature by
Ch. III—Coal Technology and Techniques ● 89

1000 F, it is obvious that the highest practical

temperature is sought.

Flue gas leaving the air heater contains particles of fly ash. Electrostatic precipitators,

under ideal conditions, can capture 99.9 percent of this fly ash. The flue gases consist of

carbon dioxide, nitrogen, oxygen, and lesser

amounts of nitrogen oxides, sulfur oxides, carbon monoxide, and hydrocarbons. Flue-gas desulfurization systems, mostly based on scrubbing the flue gas with chemically active solutions or with slurries of lime or limestone, are

being heavily promoted for controlling SOX

emissions.

Work now underway on alternative energy

sources and fuel systems will not be sufficiently advanced in the next 10 years to have a major impact on electric power generation methods using fossil fuels or their derivatives; the

use of pulverized coal-fired boiler furnaces

may be expected to dominate the fuel-burning

public-utility field during that time.

Characteristics of Pulverized Coal Furnaces

Furnaces for burning pulverized coal can be

very large. Configuration varies among the

four major boiler manufacturers, but basically

a furnace is a huge, hollow, rectangular box

made up of vertical water-filled mild-steel

tubes welded into panels to constitute the furnace walIs. For one typical boiIer furnace providing steam to an 800-MW turbine generator,

the height of this cavity is 160 feet, the width

45 feet, and the depth 90 feet. A vertical waterwalI panel divides the furnace into two halves,

each with a cross-section of 45 by 45 feet, Pulverized coal is blown tangentially into each

half of this split furnace at the corners by four

arrays of burners, aimed near the center of the

furnace to produce a rotating vortex flame pattern with a vertical axis. In some furnaces, the

burners can be tilted upward or downward to

adjust the location of the flame and to control

steam temperature. At full load, essentially the

entire bottom half of the furnace is filled with

flame, with the upper portion providing time

to complete the combustion reactions. Roughly half the total heat released when the coal is

burned is picked up by furnace wall tubes.

Other furnace configurations call for all the

burners to be arranged on one wall, firing horizontally into the furnace, or on opposite walls

to provide opposed firing. Many such variations are used to control the admission of air

and coal to the furnace, to develop good turbulence for complete combustion, to minimize problems with slagging and fouling of

furnace walIs and heat-receiving surfaces by

the ash in the coal, to utilize each square toot

of furnace walls as effectively as possible as

heat-receiving surfaces, and to permit control

of superheated temperature within the narrow

range demanded by the steam turbine.

The largest pulverized-coal-fired boiler,

which was contracted in 1976, is rated at 1,281

MW, It will provide nearly 10 million Ib s

steam/’hr at a pressure of 3,845 Ibs/in2 and at a

temperature of 1,0100 F with reheat to 1,0000

F. The surface area of the furnace walls is

146,000 ftz

, with 192,000 ftz in the superheater,

255,000 ft z in the reheater, 494,000 ft2 in the

economizer, and over a miIIion ft2 of surface in

the air preheater.20

Supercritical Boilers

A development of considerable importance

in recent years has been the design of utility

boilers to operate above the critical pressure

of 3,208 lbs/in2

. Above this pressure, water

behaves as a single-phase fluid, and there is no

distinction between liquid and steam, as there

is at lower pressures. In supercritical boilers,

water from the economizer enters the boiler

and is heated as it passes first through the wall

tubes and then through the superheater, without any change in phase, as by “boiling” for

subcritical boilers. There is no steam drum in a

supercritical boiler. Supercritical boilers are

also known as “once through” boilers, because

feed water is pumped into one end of the

boiler and “steam” exits from the other, The

outlet steam temperatures depends only on

the rate at which feed water is supplied to the

boiler and the amount of heat picked up in the

19 “Steam It's Generation and Use (Babcock & Wilcox,

1972), p. 13-4

201976 Annual Plant Design Report, ” Power, November 1976, p S-4.
90 The Direct Use of Coa/

furnace. Control of water quality is critical in

supercritical boilers, for without a steam drum

boiler, water that has accumulated impurities

entering with the feed water cannot be “blown

down” occasionally.

Supercritical units generally are large. In

1972, contracts were let for six such boilers,

the smallest rated at 520 MW. In 1973, there

were four supercritical boilers sold; in 1974,

seven; in 1975, six; in 1976, nine, and in 1977,

three. ” There is an apparent trend downward,

with 30 percent of the new boilers listed being

supercritical in 1971, 17 percent in 1976, and 9

percent in 1977. Such trends generally develop

as the utilities find by experience that reliability, operating problems, maintenance, startup,

or economic factors influence their choice of

equipment. There does not appear to be any

one reason for this falling off of interest in

supercritical boilers, although material limitations are a major factor.

Slagging and Fouling

Probably the single greatest problem in the

operation of coal-fired boiler furnaces is the

accumulation of coal ash on boiler surfaces.

All coal contains noncombustible inorganic

mineral matter. Some of it was an integral part

of the original vegetation that accumulated to

form coal seams; however, most of the mineral

matter associated with coal accumulated as

sediment from mineral-laden water that percolated through the coal deposits over eons of

time. The chemical composition of the mineral

matter varies widely and there are no “typical”

concentrations. About 95 percent of all the

noncombustible material in coal is made up of

kaolinite (A120, . 2Si0, .2 H, O), pyrites (FeS2

),

and calcite (CaCOJ).22 Many variations occur,

particularly in the clay minerals; probably a

hundred different minerals have been identified in coal.

This mineral matter causes three main problems when burned in larger boiler furnaces: 1)

buildup of ash on furnace wall tubes; 2) accumulation of small, sticky, molten particles

21 "Annual Plant Design Survey s,” Power, 1972-77

23 William T Reid, “External Corrosion and Deposits.

Boilers and Gas Turbines” (EIsevier, N Y , 1971), p 52

of ash on superheater and reheater tube banks;

and 3) corrosion.

Some of the mineral forms in coal melt in

the pulverized-coal flame, where the temperature may reach 3,0000 F. These tiny molten

droplets pick up other mineral forms by collision in the highly turbulent zone just beyond

the flame, forming larger drops of molten

“slag.” Some of these reach the wall tubes of

the furnace and, by some mechanism still not

fully understood, adhere to that metal surface,

even though the metal is cooler than about

8000 F. Gradual buildup of these slag droplets

eventually forms a solid layer of slag. Because

coal-ash slag does not conduct heat readily,

this layer of slag decreases the amount of heat

reaching the wall tube, and hence lowers the

quantity of steam produced at this point. PeriodicalIy, as the load changes, and there is a differential expansion between the wall tubes and

the slag layer, huge sheets of slag may peel off

the walls. But to control slag more effectively,

“wall blowers” are provided that use highvelocity jets of air or of steam, and occasionally streams of water, to dislodge the slag and

leave clean furnace walls. Occasionally, slag

accumulations may get so large that manual

cleaning is required, or large pieces of slag that

have fallen to the bottom of the furnace cannot be removed without breaking them by

hand. A furnace outage is then necessary, a

costly step that is avoided as far as possible.

Fouling occurs when very small particles of

ash are carried to the bundles of tubing making up the superheaters and reheaters. These

fly ash particles collect on the tube surface,

not only insulating the metal so that not

enough heat is transferred to raise the steam

temperature to design levels, but also accumulating so much that it plugs the normal

gas passages. “Soot blowers” are provided to

remove such ash deposits periodically, but

some coal ash may form dense adherent layers

very difficult to remove except by manual

cleaning.

The third problem is corrosion of the wall

tubes beneath a layer of slag or deposits. This

has been a serious problem in the past and remains a potential threat to uninterrupted

boiler operation.
Ch. Ill—Coal Technology and Techniques ● 91

Cyclone Furnaces

An innovation in boiler design in the late

1930’s was the “cyclone” furnace, a watercooled, slightly tilted horizontal cylinder with

combustion air blown in tangentially to provide a high level of turbulence to burn the centrally admitted crushed coal. Because of the

high combustion intensity, temperature exceeds 3,1000 F and the ash in the coal forms a

liquid slag covering the inside of the cylinder

and dripping from the lower end. Larger particles of the crushed coal are caught by this slag

layer and burn as these pieces of coal are contacted by the rapidly rotating tangential air

stream.

Advantages of the cyclone furnace are the

capture of a major part of the ash in the coal

as molten slag, the use of crushed rather than

more costly pulverized coal, and the smaller

furnace required for a given steam output.

With cyclone furnaces, 70 to 80 percent of the

ash is converted to slag, thereby greatly decreasing the fly ash in the secondary furnace,

compared with 20 percent ash recovery in a

dry-bottom, pulverized-coal-f i red furnace.

Crushed coal is simpler to handle and is appreciably cheaper than pulverized coal. And because of the very high combustion intensity in

the cyclone, the associated secondary furnace

serving as a heat-recovery system for several

cyclone furnaces can be significantly smaller

than a conventional furnace of the same output.

Shortcomings of the cyclone revolve mainly

around ash characteristics of the coal; the

viscosity of the molten slag must allow flow on

a horizontal surface. Because of the very high

temperatures in the combustor, NOX formation

is appreciable and difficult to control. Hence,

in recent years, cyclones have not been popular. But the growing demand for low-sulfur

Western coal, often containing coal ash that

forms such fluid slag at moderate furnace temperature as to cause serious problems with

slagging in dry-bottom furnaces, could bring

cyclone and other slag-tap furnaces back into

the market.

Industrial Boiler Furnaces

Industrial boilers are generally rated by

horsepower or steam output, ranging from

about 10,000 Ibs steam/hr to as much as 1 million Ibs steam/hr. The largest industrial boiler

contracted in 1977 will generate 840,000 Ibs

steam/hr, burning oil and gas. The largest coalburning industrial boiler ordered in 1977 is

rated at 550,000 Ibs steam/hr, with bark as a

supplementary fuel. 2

3

Based on earlier data24 for the various sizes

of industrial boilers fired with coal, travelinggrate, and underfeed stokers are most popular

in smalIer units, accounting for about 41 percent of the steam generated in boilers with output less than 20,000 Ibs steam/hr, and about 29

percent of the boilers rated under 100,000

lbs/hr. Spreader stokers dominate the midsize

industrial field, accounting for roughly half of

the steam generated in coal-fired boilers rated

at 200,000 lbs/hr and smaller. Pulverized coal

boilers dominate the largest industrial field,

providing 78 percent of the steam generated in

units larger than 200,000 lbs/hr,

Natural gas and fuel oil have been the preferred fuel for industrial boilers in smaller

sizes, in part because the cost and space requirements of such plants is much lower than

for coal firing. With the present unsettled fuel

supply situation, more companies may be willing to invest the greater costs for solid-fuel

boilers to take advantage of a more secure

source of energy.

Many industrial boilers are shop-assembled;

fabricated under conditions favoring low-cost

production methods. The largest size is dictated by shipping limitations. Such shop-assembled boiIers are completely assembled and

enclosed in a steel casing, eliminating even the

need for applying insulation or housing in the

23 “1977 Annual Plant Design Survey, ” Power, November 1977, p 5-12

24’’Evaluatlon of National Boiler Inventory, ” EnvironmentaI Protection Agency TechnicaI Series, E PA-600/

2-75-067, October 1975

0
92 ● The Direct Use of Coa/

field. Although generally fired with fuel oil or

natural gas, similar packaged units can be de

signed with grates and stokers to be fired with

coal. A coal-fired packaged boiIer was designed and built in the 1950’s, but only a few

units were installed because the growing availability then of low-cost natural gas and the

lesser attention by a fireman needed with gas

firing proved to be more economical. With a

change in fuel availability and costs, packaged

boilers fired with coal may see greater use.

Pulverized Coal-Fired Industrial Boiler

Furnaces

Industrial boilers fired with pulverized coal

are basically similar to utiIity units except that

the industrial boilers are smaller, steam output

is less, and steam pressure seldom exceeds

1,500 lbs/in2

. Because of costs for auxiliaries

such as pulverizers, the lowest practical steam

output for pulverized coal-firing is about

200,000 lbs/hr. The same problems with slagging and fouling occur in large industrial

boilers as in utility steam generators, and the

plant is more sophisticated and difficult to

operate than other industrial furnaces.

Spreader Stokers

These stokers are very popular for steam demand below that supplied by pulverized coal.

A spreader stoker can burn a variety of coals, it

responds rapidly to load changes, and it is

more economical in larger sizes than other

kinds of stokers.

The concept of the spreader stoker dates

back to 1822, as a way of feeding coal to a

grate without opening the furnace door. 25 The

same principle is used today. A mechanical

distributing device, either an assembly of

rotating paddles or a series of air jets arranged

at the end of the furnace, throws crushed coal

into the combustion zone of the furnace. The

smaller particles of coal burn in suspension

while the heavier ones fall onto a moving

grate, where they burn with air supplied upward through the grate. The grate moves slowly so that the ash from the coal is discharged at

25 Combustion Engineering (New York Combustion

Englneerlng, Inc , 1966), p 18-2

the end. Adjustment of the distribution assures

that the coal falling on the grate is properly

positioned to burn out completely by the time

the coal reaches the ash-discharge position.

Some spreader stokers use stationary sectioned grates that are dumped section by section into the ashpit as ash accumulates.

Roughly half the coal burns in suspension,

so there may be problems with emission of fly

ash and unburned carbon with spreader stokers. To minimize loss of boiler efficiency from

unburned carbon, fly ash collected in hoppers

is reinfected into the furnace. Erosion of boiler

tubes may be troublesome.

Traveling-Grate Stokers

These consist of a horizontal moving grid of

iron links connected to form an endless belt

driven by sprockets to move a fixed bed of

coal through a furnace. Coal is fed at one end

to a depth of 4 to 6 inches, ignites as it enters

the hot furnace by radiation from a furnace

arch and by recirculation of burning particles

of coal from farther in the furnace, burns as it

moves from the inlet, and eventually is

dumped as ash into the ashpit at the end of the

grate. The speed of the grate is adjusted to ensure complete combustion, and air is admitted

through the grate in zoned sections to control

combustion.

Traveling-grate stokers can burn a wide

variety of fuels, ranging from coal to garbage.

They are not well suited to coals that cake

strongly.

Underfeed Stokers

Whereas in traveling-grate stokers the coal

and the combustion air move in opposite directions (countercurrent flow), in underfeed

stokers the coal and the air move together in

the same direction into the combustion zone.

Coal is forced upward through a conical retort

topped with nozzles through which the air is

blown. This establishes the zone where ignition

occurs, the burning coal then moving onto stationary perforated grates, where combustion is

completed.

26 Temperatures are high and the

coal ash fuses into lumps., Unlike traveling-

“Ibid , p 18-8. I
Ch. III---Coal Technology and Techniques ● 93

grate stokers, strongly caking coals are han- bars, or flexing grates successively, to move

died readily in underfeed stokers. coal into a sloping fuel bed. As with travelingSingle-retort underfeed stokers are used in

small boilers, generally under about 30,000 Ibs

steam/hr. For greater output, multiple-retort

stokers have been built at ratings up to 500,000

Ibs steam/hr. These operate on the same principle of concurrent movement of coal and air

but with many engineering changes to accommodate the large fuel beds.

grate stokers, air moves upward through the

grates, so this is a special case of overfeed

burning. The same principle is used in grates

for burning municipal refuse. Vibrating-grate

stokers appear to be more popular in Europe

than in the United States, possibly because our

strongly caking bituminous coals are more

troublesome than the lower rank coals overseas.

Vibrating-Grate Stokers

These stokers depend upon oscillating grate

AIR POLLUTION CONTROL TECHNOLOGY

There are currently six “criteria” air pollutants–pollutants for which National Ambient Air Quality Standards (N AAQS) have been

promulgated: sulfur oxides (SOx, nitrogen oxides (NO X), particulate, carbon monoxide

(CO), hydrocarbons, and photochemical oxidants. Emissions of the first three can be reduced in the direct combustion of coal by

three methods. One is to remove containinants

before combustion, the second is capture them

during combustion, and the final is to remove

them from the flue gases after combustion.

The effectiveness and cost of removing any

one is in part dependent on the method and sequence of removal of the others. Because of

the wide variation in the composition and

makeup of the containinants in coal and because boilers are designed especially for the

fuel being fired, no universal method can be

prescribed that would be best for al I new or existing plants.

The level of emissions of CO and hydrocarbons in direct coal combustion is a result of

the completeness of combustion, regardless of

the coal quality. Oxidants are not directly produced by combustion but are the reaction

projects of hydrocarbons and NOx in the atmosphere.

Lowering the emissions of the first three

criteria pollutants by precombustion cleanup

and by new combustion technologies is described later in this chapter. The next section

focuses on control technology for their removal from flue gas.

Particulate Control

Stationary combustion sources burning coal

produce bottom ash, cinders, and slag, which

are removed from the furnace itself, and fly

ash, which is entrained in the flue gas.

Four types of systems are capable of removing particulate from flue gas: mechanical or

cyclone collectors, electrostatic precipitators,

wet scrubbers, and fabric filter baghouses.

Cyclone Collectors

Mechanical or cyclone collectors work on

the principle of gravitational, centrifugal, or

inertial forces to separate the particles from

the gas. One type consists of an enlarged

chamber, which slows the gases and allows the

particles to settle. Another form is cylindrical

with a tangential entrance that causes the

gases to swirl rapidly. The particles, heavier

than the gases, migrate by centrifugal force to

the walls of the vessel and drop to the bottom.

The clean gases exit at the top.

These units are simple, relatively maintenance free, reliable, low in pressure loss,

relatively low in both capital and operating

cost, and independent of operating tempera-
94 . The Direct Use o/ Coa/

ture. They are particularly effective in removing large particles and can handle high dust

loadings. However, their performance is sensitive to variable dust loading and gas velocity.

The efficiency of well-designed units ranges

from 80 to 90 percent, depending upon particle

size. Because of their low cost but inadequate

effectiveness to reduce small particles, they

are sometimes used as first-stage cleaners in

conjunction with other devices that are more

efficient and expensive. Their use may lower

the size and cost of the follow-on unit.

Electrostatic Precipitators

EIectrostatic precipitators are widely used in

large stationary combustion sources to remove

particulate from flue gas. Gas containing particulate is passed horizontally between a

number of high-voltage discharge electrodes

and electrically grounded collecting plates.

Dust particles are charged by the ions from the

discharge electrode and migrate to the

grounded collection plate, where they adhere

and agglomerate. As they do so, some become

heavy enough to fall into the collection hoppers. Other dust particles are moved downward by mechanical rapping of the collection

plates. The particles are then drawn from the

hoppers and sent to a central particulate collection area. After passing the multiple system

of electrodes, the clean gas exits the unit.

Electrostatic precipitators are capable of

collection efficiencies greater than 99.5 percent, and in some cases remove more than 99.9

percent of the dust from the flue gases. Pressure drop through electrostatic precipitators is

very low, resulting in low operating cost. Capital costs for large utility boilers burning

medium- to high-sulfur coal are on the order of

$25/kW.

Electrostatic precipitators are sensitive to

changes in the properties of the particles and

the flue gas. The changes can significantly affect their collection efficiencies; therefore,

their design must compensate for normal variations in fuel composition and flue-gas temperature.

Electrostatic precipitators designed for highsulfur fuels are adversely affected in their particulate collection efficiency by the use of lowsulfur fuels. For example, the Capitol Power

Plant in Washington, D. C., was originally designed to burn 3 percent sulfur coal. Because

of recent air pollution regulations the plant

now burns 1 percent sulfur coal. This reduction

in sulfur resulted in a change in the electrical

properties of the particulate produced, which

dropped electrostatic precipitator performance from 99 percent to about 76 percent.

High-sulfur coal has been the standard fuel

for the power industry. To comply with S0x

emission regulations the industry is using

greater quantities of low-sulfur coal. The ash

from low-sulfur coal is usually of high resistivity; with coal of a sulfur content of less than

1 percent, the naturally formed sulfur trioxide

(S0,) is seldom sufficient to reduce resistivity

of the fIy ash to a level (about 5 x 10’ 0 ohm-cm)

that permits the electrostatic precipitator to

function normally.

There are several methods of overcoming

these difficulties. Existing facilities can add to

the size of their precipitators (provided they

have the space, which is not always the case)

to compensate for the increased resistivity, or

chemically change the resistivity of the particles by “flue gas conditioning, ” described

below. New facilities have these and other options available. Since resistivity varies inversely with temperature, one option is to collect

the particles in a hotter environment. Precipitators are normally placed on the cool, exhaust

side of the air preheater (the heat exchanger

that transfers heat from the flue gas to the air

being drawn into the boiler to allow combustion), where average temperatures are 2500 to

3000 F. “Hot side” precipitators collect particulate matter on the intake side of the preheater, where the gases are at 500 to 7000 F and the

resistivity of the particles is in the same range

as that of higher sulfur coals at “cold side”

temperatures. For the Navajo Power Station in

Arizona, use of hot-side precipitators with lowsulfur coal caused turnkey capital costs for

meeting the particulate New Source Performance Standards (NSPS) to rise from $25/kW—

the cost of a “cold side” precipitator used with

medium- to high-sulfur coal — to about

$45/kW; the cost of simply using a larger pre
Ch. //l—Coal Technology and Techniques 95

cipitator would have been about $50/kW. 27

Other options would have been to use control

technologies such as wet scrubbers or baghouses that depend on the physical rather than

the electrical properties of the fly ash.

Flue-gas conditioning may be an attractive

option for existing plants because it minimizes

the additional machinery that must be added

to a facility. Flue-gas conditioning processes

inject artificially produced SOJ or some other

substance into the flue gas ahead of the precipitator. The “conditioner” becomes attached

to the particles in the flue gas, reduces the particles’ resistivity and thereby restores collection efficiency without increasing the size of

existing precipitators or the need for installing

oversized new ones. One manufacturer claims

that the incremental cost of using fIue-gas conditioning to meet particulate emission limitations when using low-sulfur coal is approximately one-tenth that of alternatives. 28 Inexpensive (about 3 cents/ton of coal burned) SO,

injection systems have been installed in at

Ieast 60 powerplants and are reported to be

working reliably, 29

Designers of new powerplants generally

have not used flue-gas conditioning as a solution to resistivity problems; they have used

hot-side precipitators or larger cold-side precipitators. Conditioners are apparently considered as “last resort” solutions if the precipitators fail to meet emission requirements. The

Environmental Protection Agency (EPA) has

tested the effects of various conditioning

agents and has found some evidence that conditioning can add some pollutants to the flue

gas while improving the particulate removal

efficiency; for example, in some instances a

significant percentage of S03 injected into the

gas was emitted. However, the effect does not

occur in every system and perhaps may be

eliminated by better design.

27Personal Communication with Les Sparks, U.S. E Environmental Protection Agency, Research Triangle Park,

N C

28Flue Gas Conditioning for Electrostatic Precipitators

(Santa Anna, Calif. WAHLCO, Inc.)

29 William E Archer, “ Fly Ash Conditioning Update, "

Power Engineering, vol. 81, No 6, June 1977, pp 76-78

Wet Scrubbers

Wet scrubbers utilize water or other liquids

to “rain out” the particles in the flue gas. Many

variations of the wet scrubber exist, each with

specific advantages. Although successful instalIations on large powerplants exist, the economics are not favorable except for low-sulfur

coals, and most utilities appear to prefer the

more traditional precipitators. Turnkey costs

are in the range of $50/kW. 30 Operating energy

costs become quite high if fine particulate

removal is required.

Fabric Filter Bag houses

Baghouses contain fabric bags suspended

vertically. The particulate-laden gas passes

through the fabric and the dust is filtered out.

Removal efficiency is usually in excess of 99.9

percent. Removal efficiency of fine particuIates can be greater than with other devices,

although the small size needed to achieve high

efficiency of these particulate increases pressure drop and operating costs. Although baghouses have a long history of use outside the

utility industry, their general use on boilers has

been slowed by problems of fabric clogging

and chemical damage, poor high-temperature

operation, and high maintenance costs, in addition to their expensive high-pressure drop.

Because bag replacement represents a major

maintenance cost, the recent development of

high-temperature bags made of teflon-coated

fiberglass has made baghouses more attractive

to utilities. More than 50 baghouse systems

have now been installed or ordered at coalfired powerplants. The next few years of experience with several large new facilities are IikeIy to be critical to their future.

Sulfur Oxide Control

Flue-Gas Desulfurization futilities

The removal of SOX from stack gases is

termed flue-gas desulfurization (FGD) and uses

devices commonly referred to as scrubbers.

The function of the scrubber is to bring the S0x

laden flue gases into contact with a liquid that

30Personal communication with Les Sparks, U S Environmental Protection Agency
96 “ The Direct Use of Coa/

will selectively react with the SOX. FGD processes are generalIy characterized by the chemical absorbent that is utilized, such as lime,

limestone, magnesium oxide, double alkali,

sodium carbonate, alkali flyash, and ammonia.

The processes are further characterized as

throwaway or regenerative. In the throwaway

processes, the absorbent and the S0x react to

form a product of iittle or no market value; it is

disposed of as a sludge or solid. By contrast,

the regenerative processes recover the absorbent in a separate unit for reuse in the scrubber

and generally produce a product with market

value (such as elemental sulfur or sulfuric

acid). However, if the product has Iittle or no

market value, it must be discarded as in the

throwaway processes.

FGD is used mainly by the utility industry.

Although there are a number of non-utility

FGD installations, their percentage of the total

power generating capacity is not significant. In

the U.S. utility industry, the technology is predominantly used on coal-fired boilers, whereas

its use on oil-fired units is prevalent in Japan.

Lime-1imestone scrubbing, a throwaway

process, is presently the dominant technology

for flue gas desulfurization in the United

States. A basic flowsheet for lime-limestone

scrubbing is shown in figure 13. The absorbent,

lime or limestone, is introduced into the reaction tank along with scrubber effluent slurry

and clear liquor recycle from the dewatering

section. The mixture, after holding in the tank

for a few minutes to allow reactions to take

place, is pumped to the top of the scrubber

and sprayed down into the gas. A bleed slurry

stream is tapped off from the scrubber effluent

and dewatered to give the product sludge.

Some 11,500 MW of coal-fired utility boiler

capacity have been fitted with FGD, as compared to roughly 200,000 MW that possibly

could be so equipped. Another 17,700 MW are

under construction and 27,200 MW are

planned, giving a total of 56,400 MW scheduled to be in operation by 1985, by which time

there will be about 300,000 MW of coal-fired

capacity that could use FGD (assuming existing units are retrofitted). Thus about 15 percent of the coal-fired capacity now operating

or under construction will have FGD.

The 1977 Clean Air Act Amendments passed

by Congress have considerably changed the

situation for new plants; a percentage reduction in SO, emission will be required that effectively rules out use of low-sulfur coal as a

sole means of compliance for new boilers. 1 n

view of this, it seems likely that all new boilers

for which construction is started after early

1978 will require FGD. The new capacity to be

installed in the 1980-2000 period is expected to

be on the order of 200,000 MW (although there

is considerable uncertainty about this projection).

Input Requirements

FGD systems require considerable amounts

of raw materials, energy, water, and manpower. If the effect of the 1977 amendments is to

greatly expand FGD use, then these requirements could have an impact on other sectors

of the economy.

1.

2

3.

Raw Materials. Although projections are

difficult, there is some indication that

limestone consumption (either as is or

calcined to produce I i me) could approach

100 million tons/yr by 2000. The limestone

industry should have no trouble in supplying the required amount of material,

assuming (as available evidence indicates)

that the lower grades of limestone are acceptable.

Water. FCD systems require from 0.5 to

1.5 tons of water/ton of coal burned. By

the year 2000, this could amount to as

much as 1 billion tons, or sIightly more

than 700,000 acre-feet/yr. In the west, FGD

water use must be considered a significant

addition to total water demand.

Energy. FGD systems require energy both

as electrical power to drive equipment

and as thermal energy to (when necessary)

reheat the flue gases that have been

cooled in the scrubber and have lost some

of their buoyancy. The former ranges

from 1.0 to 2.5 percent of the boiler

capacity (depending on the FGD process).

Reheat energy requirement is also variable, depending on the degree of reheat

attempted. A recent EPA study indicates

that total FGD energy requirements would
Ch. Ill—Coal Technology and Techniques ● 97

Figure 13.— Lime. Limestone Scrubbing System

Stack

n

ne

ID fan r

Boiler

m

Q

Precipitator

% 3 m

SOURCE OTA. based on EPA data

4.

increase U.S. power consumption over a

noncontrol situation by 0.7 percent in

1987 and 1.0 percent in 1997,

Manpower. The operating manpower required in the year 2000 may be on the

order of 10,000 workers, which does not

seem significant. The main problem is inability of vendors and manufacturers to

keep pace with scrubber demand. The

consensus is that designers and fabricators probably will not produce any bottlenecks but that without special measures

there may not be enough skilled workers

(welders, electricians, boilermakers, and

others) to keep construction projects on

schedule. This applies particularly to industrialized areas that already have a

shortage of ski I led labor.

cost

Although other impacts may be minor or uncertain, it is clear that the capital and operating costs of FGD systems will have a substantial impact. The systems are expensive to build

and operate, and overall cost will be a significant percentage of power production costs.

Many site-specific factors affect FGD cost,

and “average” costs must not be assumed to

apply to a particular plant. For new systems,

the capital cost will “typically” be in the $80 to

$120/kW range in 1975 dollars, with an annualized operating cost (capital charges plus operating and maintenance) of 4 to 7.5 mills/kWh.

In extreme cases the cost may be 10 mills/kWh

or greater. Assuming an average of $l00)/kW

for capital cost, the 200,000 MW projected to
98 ● The Direct Use of Coal

come online between 1985 and 2000 would require a capital outlay of $20 billion (based on

“current dollars”). If a cost of 5.5 mills/kWh is

assumed, boiler system operating costs would

be increased by about $6 billion/yr. These

estimates, which are rough at best, indicate

that a powerplant’s installation of FGD may

add 14 percent to investment cost and 18 percent to annualized operating cost if the alternative is no attempt at control of SOZ emissions. Site-specific conditions couId vary these

costs over a wide range. Back-fitting cost

would be even higher.

Alternative FGD Processes

Although conventionaI Iime-1imestone

scrubbing is now preferred, better FGD processes might be developed and could have

some impact on inputs and costs. The alternative nearest to commercial adoption appears

to be double-alkali scrubbing, which gains a

major advantage by reducing the scaling experienced with limestone.

One other recovery process, sodium scrubbing-thermal stripping (Wellman-Lord), has

been tested on a large scale. Current installations use natural gas as a reducing agent, but

the industry is testing coal as an alternative

agent. Disposal of sodium sulfate will be a

problem. Several other recovery methods have

promise but have not been developed far

enough to have much significance at the present time.

Flue-Gas Desulfurization — Industrial

Flue-gas desulfurization was first applied to

industrial boilers in the United States at the

General Motors plant in St. Louis, Mo. Two systems were installed on coal-fired boilers in

1972. At the close of 1977, 35 systems had been

or were being constructed at 15 industrial sites.

Twenty-four systems were operational, with

the remaining scheduled to begin operation

within a year. Of the 24, 18 were retrofitted to

existing boilers and the remaining 6 were installed on new boilers.

Thirteen of the operational systems use sodium hydroxide or sodium carbonate to absorb

S 02

. One uses Iimelimestone. The other 10

operational units are double-alkali systems.

Eleven additional double-alkali units are

scheduled to start within the year.

The sodium-based units produce a liquid

waste containing dissolved sodium compounds, which are either sent to a pond for

evaporation, or treated and disposed into a

municipal sewer. The double-alkali and the

lime-limestone systems produce a dewatered

calcium sulfite/sulfate material claimed to be

suitable for landfill; however, leaching may

stilI be a problem.

Operating availability of the industrial systems is reported to be greater than for FGD

systems on utility boilers. However, the problems that occur are similar to those associated

with prototype FGD systems on utility boilers.

They include corrosion, erosion, poorly sized

equipment due to lack of operating experience, and poor pH and gas flow control.

Capital costs range from $25 to $115/kW.

Capital costs are reported as lower than for

utility installations because capital costs for

pretreatment and disposal are not generally included in industrial systems. Although none

has been reported to date, operating costs

should be higher.

Nitrogen Oxide Control

Nitrogen oxides (NOx are formed during the

combustion of fuels. The nitrogen originates

from the nitrogen content of the fuel as well as

the nitrogen in the combustion air. Factors in

the formation of NOx are flame temperature,

amount of excess air in the flame, and the

length of time the combustion gases are maintained at the elevated temperature and subsequently quencheched. An increase in flame temperature and excess air favors an increase in

the formation of NOX

. A rapid cooling of NOX

by relatively cool boiler tubes tends to stabilize the NO, that was formed. Typical NOx

concentration in the flue gas is 500 to 1,000

parts per million (ppm) for coal, 200 to 500

ppm for oil, and 120 to 200 ppm for natural

gas.

Currently, the common practice for lowering

NO, emissions is to modify the design and/or
Ch. I/l—Coal Technology and Techniques ● 99

operating conditions of combustion equipment.

Some new furnaces have been designed for

two-stage combustion. I n the initial combustion stage, combustion is partially completed

with less air than is needed for complete burning. I n the second stage downstream the remaining fuel is burned completely, with secondary air injected through strategically

located ports. The technique has been successfully tried on a few coal-fired boilers as well as

applied to oil- and gas-fired units.

The location and spacing of burners influence NOx formation. Tighter spacing has a

tendency toward greater NOX formation, probably due to higher temperatures. Burners located in the corners of furnaces produce tangential flames with a somewhat lower flame

temperature. Tangential corner-fired boilers

may produce about half the NOX that is generated in either a front wall-fired or an opposingfired furnace.

Modification of operating conditions has

also proven effective in reducing NOX formation. The common techniques consist of lowering excess combustion air, recircuIating the

flue gas, and injecting steam or water into the

firebox. Reducing the excess air reduces the

quantity of atmospheric nitrogen available for

N OX formation. Flue-gas recirculation and

steam or water injection reduce flame temperature, which is an important factor in decreasing NOk production. Combinations of

these strategies have succeeded in lowering

NO, emissions from large utility boilers by 40

to 50 percent.

A promising technology for reducing NOx

emissions is a IO W- N OX burner currently under

development by E PA. Single-burner tests using

low-sulfur - coal have yielded an 85-percent

reduction in Nox emissions There appears to

be a good chance that similar reductions can

be achieved with a multiple-burner system (all

large boilers have multiple burners) However, tulI demonstration probably cannot be

achieved before the mid-l 1980’s.

This technology is of particular interest because, if proved successful, it will offer an efficient control of NOX for low cost on new plants

(the new burners may not be more costly than

current designs), and allow a moderate cost

retrofit to existing plants if this is considered

desirable.

Desulfurization of fuels may provide a concomitant, although small, reduction in the nitrogen content of the fuel. The lower nitrogen

content of the fuel can also reduce NOX formation during combustion.

Research and development (R&D) on the

control of NOX emission by stack-gas cleaning

is currently being conducted. Unfortunately,

none of the processes is commercially available for coal-fired units.

A number of dry processes are being developed. I n one, ammonia is injected at 1,4000 to

1,8000 F, which causes the conversion of 40 to

60 percent of the NOx to nitrogen and water In

other processes various solids are utilized to

effect NO removal, The more prominent solids

consist of copper oxide sorbent, base metal

catalysts, and activated carbon, In Japan the

capital costs of the dry processes range from

$60 to $100/kW and have a removal efficiency

between 40 and 70 percent. To date these processes have been developed for oil-fired units,

and problems caused by catalyst poisoning

could be expected in their application to coalfired plants.

A number of wet processes for the simultaneous removal of S0x and NOx are being developed. One process utiIizes magnesium oxide as an absorbent. other processes rely on

oxidants such as chlorine dioxide, ozone, and ‘

potassium permanganate to oxidize NO to

NOx for easier absorption. Capital costs are

said to be in the range of $60 to $90/kW in

Japan.
100 ● The Direct Use of Coa/

FUTURE TECHNOLOGIES

With coal the dominant fossil fuel for electrical generation, a great many R&D efforts are

being aimed at future ways of burning solid

fuels more effectively, and of substituting coal

for fuel oil and natural gas in applications

where these clean flu id fuels have been widely

used. Improvements in the “quality” of mined

coal are being made, new combustion schemes

are being evaluated, direct energy-conversion

systems based on coal are being investigated,

and serious attention is being given to combined cycles based on coal as the energy

source. These new technologies have much to

offer, but some of the problems will elude the

best efforts of fuel technologists for many

years. Nevertheless, if coal is to become a

more attractive fuel under stringent environmental regulations, new technologies are required, especially for the smaller industrial

users.

Upgrading

Coal Preparation

mined coal to improve coal’s usefulness or to minimize environmental problems is an old art. At one time, coal beneficiation began at the face in the coal mine, where

the miner had some control over what he

loaded into his mine car. But today’s highspeed mining machines cannot distinguish between coal and the rock partings within coal

seams. All goes to the surface. Handpicking

rock from coal moving on a belt or a shaking

table constituted coal preparation at one time.

Today, coal cleaning methods based on gravity

separation of the lighter coal particles from

the heavier rocks and pyrites is becoming more

important as the cost of coal increases in the

marketplace and environmental restrictions

are imposed on emissions from coal-burning

installations. Ordinary coal cleaning to remove

ash and rocks, etc., wherein sulfur removal is

incidental, is described in the section on Mining and Preparation. Advanced washing, which

can in some cases remove a substantial

amount of sulfur, is considered here. More

sophisticated chemical beneficiation methods

also are being developed. Further information

on coal cleaning and desulfurization is provided in appendix IV of volume 11.

Mechanical Coal Cleaning

Mechanical cleaning processes are based on

differences in specific gravity or surface characteristics of the materials being separated.

They can be designed to remove a large fraction of the pyritic sulfur, generally the major

part of the sulfur in high-sulfur coals. Pyritic

sulfur occurs as discrete particles. It is much

heavier than coal, with a specific gravity of

5.0, compared to coal’s 1.4. Hence when raw

coal is immersed in a dense medium, the coal

floats and the pyrites sink. This process is now

used to remove shale and rocks, etc. (specific

gravities from 2 to 5) but pyrite is more dispersed and finer crushing of the coal than is

now generally practiced is required to free it

for removal.

Two facilities for fine coal sulfur reduction

are about to begin commercial operation. The

Homer City Coal Preparation Plant in Pennsylvania uses dense-medium cyclones to produce

a primary coal stream of less than 0.6 percent

sulfur and an intermediate sulfur coal stream

to be used in areas outside of critical air

basins. The other plant, near Barnesboro, Pa.,

uses a two-stage froth flotation process to reduce pyritic sulfur by up to 90 percent. Both

plants are described in more detail in appendix

IV of volume II. Neither of these processes, nor

some other mechanical and chemical cleaning

processes intended for pyritic sulfur, affect the

organic sulfur. Hence, they will not be usable

without other control measures by utilities in

new plants. They may be of considerable interest in smaller or existing facilities that have

less stringent sulfur removal requirements. The

applicability of these processes will be determined by their cost and the environmental

regulations. To date, no reliable cost figures

are available.

Advanced Cleaning Processes

Several physical and/or chemical treatments
Ch. Ill—Coat Technology and Techniques ● 101

have been proposed for improved pyritic sulfur removal. These are:

1.

2.

3.

4.

5.

High-gradient magnetic separation

(HGMS)-separation of pyrite by exploiting its magnetic properties,

Magnex process— a “pretreatment” process allowing better magnetic separation.

Meyers process — a chemical leaching of

pyrite from the coal.

Otisca process–washing with a heavy liqu id rather than a water suspension.

Chemical comminution — a “pretreatment” process that chemically breaks

down the coal to smaller sizes.

-1-1 These processes

Their future role is

not remove much

vanced mechanical

dix IV of volume II

detail.

will be quite expensive.

unclear because they will

more sulfur than the adcleaning methods. Appenevaluates them in greater

Processes that attack organic sulfur in addition

1.

2.

3

4,

to pyritic sulfur include:

Ledgemont oxygen leaching process —dissolution of pyrites and some organic

sulfur using a process simulating the production of acid mine water.

Bureau of Mines/DOE oxidative desulfurization process — a higher temperature, air

instead of oxygen variation of the ledgemont process.

Battelle hydrothermal process— leaching

of pyrites and organic sulfur under high

pressure.

KVB process–gaseous reaction of the sulfur with nitric oxide.

These processes are claimed to remove substantially all of the pyritic and 25 to 70 percent

of the organic sulfur. All are still in the laboratory stage, so cost data are only conjectural. At

present, costs seem to be many times those

associated with physical coal cleaning.

Solvent-Refined Coal

Solvent-refined coal (SRC) involves dissolving crushed coal in a suitable solvent at moderately high temperature and pressure, treating

the solution with hydrogen to remove an appreciable part of the sulfur, filtering the hot

solution to remove the insoluble coal-ash minerals, and then driving off the solvent and recovering the demineralized, low-sulfur product. Two pilot plants have been running since

1973, a 6-ton-per-day unit at Wilsonville, Ala.,

and a 50-ton-per-day plant at Tacoma, Wash.

Together they have investigated the response

of a wide variety of coals to SRC processing,

and have produced sufficient product for

burning tests. Commercial-scale burning tests

were made at Georgia Power. General conclusions drawn from these combustion tests indicate that SRC is a premium fuel in regard to

heat value, ash, and sulfur content. Commercial-size SRC plants have been proposed.

Sustained operation for periods as long as 75

days has been achieved at Wilsonville, with

some 3,700 hours of operating time in its first

year. J1 In an early stage, Kentucky and an lllino is coal were treated with 90 to 95 percent recovery. The raw coals contained 8.9 to 11.1

percent ash and 3.1 percent sulfur. The SRC

product averaged 0.16 percent ash and 0.96

percent sulfur. The designs for a demonstration of a commercial-size module have been

proposed by the private sector in conjunction

with DOE.

Low-Btu Gas and Combined Cycles

Coal can be gasified to produce a low-Btu

gas. Since the gas cannot economically be

stored or shipped more than a few miles before

combustion, it is effectively a form of direct

combustion of coal. The gas is cleaned before

burning so that no emission controls are required at the combustion facility. Low-Btu gas

can be burned directly in a boiler to produce

steam for industrial use or for the production

of electricity in a conventional steam turbine.

Alternatively the gas generator can be integrated with a combined cycle plant.

The first option of direct firing of existing

boilers with clean, low-, or intermediate-Btu

gas is higher in overall capital and operating

‘

l

’’ Status Report of Wllsonville Solvent Refined Coal

Pilot Plant, ” EPR/ Interim Report 7234, May 1975, 40 pp

plus app.
102 ● The Direct Use of Coal

cost than conventional coal firing with stack

gas cleanup, as indicated in recent studies by

the Tennessee Valley Authority (TVA) for the

Electric Power Research Institute (EPRI). In addition, the option will probably be uneconomical for many industrial plants. Nevertheless,

gas producers may be practical for the production of chemicals or other industrial uses.

The second option is more attractive for

power generation. With this system crushed

coal, water, and compressed air are fed to a

gasifier. The hot gases that are produced pass

through a purification system to remove chemical contaminants and particulate matter. The

clean gases power a gas turbine engine that

produces electricity and compressed air for

the gasifier. The turbine exhaust gases travel

through a waste heat boiler driving a steam

electric generator before being exhausted to

the atmosphere.

Although the state of the art of turbine de

sign will allow efficient combined cycle operation, gas temperature to the turbine must be

as high as possible to obtain further efficiency

gains. Turbine research at up to 3,0000 F gas

temperature is being conducted, but the temperature of the commercially available metal

blades is limited by metallurgical problems to

1,0000 F. Blade temperature is kept low by

elaborate schemes to circulate cooling water

or air through the rotating blades. Research is

underway on blades that will withstand higher

temperatures and on improved cooling means.

Prospects for improved efficiency are good.

The low-Btu gasifier integrated with a combined-cycle turbine system has been identified

as promising from the standpoint of cost of

electricity, overall efficiency, and limitation of

emissions. New combined cycle plants fueled

by low-Btu gas may be 10 percent more efficient in converting fossil fuel to electricity

than are the most efficient conventional powerplants.

Fluidized-Bed Combustion

Fluidized-bed combustion (FBC) is an important technological alternative for industrial applications and perhaps coal-based power generation. Its basic principle involves the feeding

of crushed coal for combustion into a bed of

inert ash mixed with limestone or dolomite.

The bed is fluidized (held in suspension) by injection of air through the bottom of the bed at

a controlled rate great enough to cause the

bed to be agitated much like a boiling fluid.

The coal burns within the bed, and the SOX

formed during combustion react with the lime

Photo credit Department of Energy

This small-scale model of the coal. fired, fluidized bed, gas

turbine system is used to study the behavior of the fuel

mixture of coal and limestone in the production

of electrical power

stone or dolomite to form a dry calcium sulfate. To maintain high combustion efficiency,

high heat transfer rates, and efficient capture

of SOX

, the bed temperatures are maintained

between 1,5000 and 1,8000 F. Production of

N OX is minimized because of the low excess air

environment of the combustion zone and the

low generating temperature of the fluidized

bed compared to conventional combustion,

where the temperature may be in excess of

3,0000 F. In addition, in some combustion

processes burning certain coals, the ash melts

during combustion to form molten slag and
Ch. ///—Coa/ Technology and Techniques ● 103

clinkers, which foul the boiler tubes and the

furnace walls. At the temperature of the fluidized bed more of the ash remains solid, tending toward unimpeded, uniform operation.

Banks of boiler tubes are in contact with the

fluidized bed. The rate of combustion and production of heat in the bed is rapidly transferred to and through the tubes to produce

steam whiIe the bed is maintained at a constant temperature. As bed temperatures must

remain in a narrow range during operation, low

load is difficult. Consequently, the first commercial units are expected to consist of a series

of relatively small cells, only some of which

would operate during periods of low load.

The advantages visualized for FBC include:

●

●

●

●

●

●

FBC

the flexibility to burn a wide range of rank

and quality of coaIs,

a higher heat transfer rate than in conventional boilers, which reduces the requirements for boiler tube surface and furnace

size and also lowers capital costs,

an increased energy conversion efficiency

through the ability to operate without the

power requirements needed for a scrubber,

reduced emissions of SOX and NOX

,

a solid waste more readily amenable and

acceptable to disposal than that from a

wet-scrubber applied to conventional

boilers, and

the potential for operation at an elevated

pressure sufficient to use with a combined

gas-turbine/steam-turbine cycle for generating electricity at higher efficiency.

may make particular sense for small commercial and industrial facilities if emission

standards for smaller sources are relatively

stringent.

The fluidized bed can be adapted to a variety of modes to produce heat and power. Two

variations are prominent— atmospheric and

pressurized operation. The atmospheric FBC

can be used for generating electricity or for

process or space heating. The pressurized FBC

is slated for use with a combined cycle system

of gas and steam turbines.

A major concern with atmospheric FBC relates to adequate removal of fine particulate

matter prior to releasing the fIue gas to the atmosphere. The agitation of the ash and lime

stone in the bed results in their breakdown into

fine particles that readily entrain in the highvelocity flue gases. Attention is focused on the

effectiveness of cyclones, electrostatic precipitation, and fabric fiIters for particulate removal. The ash entrained in the flue gases may be

high in unburned carbon. The disposal of such

material wouId result in lower combustion efficiency and perhaps disposal problems. To prevent this loss of potential fuel, atmospheric

FBC units may employ a carbon burnup cell.

By passing the entrained particles through this

cell, which operates at a higher temperature

and with greater excess air than the primary

FBC cells, the residual carbon is consumed.

Considerable concern regarding corrosion and

erosion of the submerged tubes also exists.

R&D work is being conducted with atmospheric FBC in the United States and abroad. In

the United States a 30-MW atmospheric FBC

pilot plant began operations in 1976 at a utility

site in West Virginia. Atmospheric FBC is also

about to be demonstrated for the production

of process heat and steam in a number of industrial configurations.

In the pressurized variation of FBC, the combustion occurs in conditions similar to those in

the atmospheric version except that the furnace is maintained at 4 to 16 atmospheres of

pressure, The elevated pressure compresses

the flue gases, resulting in a dramatic reduction of furnace size from that of a comparably

rated atmospheric FBC. Although the development of pressurized FBC is less advanced than

that of atmospheric, it has a number of potential advantages: the efficiency of combustion

and the capture of S0x are higher; less absorbent (limestone or dolomite) is required for the

same sulfur capture; the furnace is smaller for

the same coal throughput, and NOX emissions

are expected to be lower. Its primary advantage, however, is in the potential for improved

plant efficiency by means of combined-cycle

operation. With no major advances in gas turbine technology, an increase in efficiency of 5

percent is possible for power generation.
104 ● The Direct Use of Coa/

With the integration of the pressurized FBC

with combined-cycle operation, the problem

of particulate removal becomes critical, as the

hot pressurized flue gases are expanded

through a gas turbine to recover a portion of

their energy. The solids suspended in the flue

gases are particularly corrosive and erosive of

gas turbine blades. More efficient particulate

removal systems capable of operating at high

temperatures need to be demonstrated to overcome this obstacle to higher efficiency by the

pressurized FBC system.

Development of combined-cycle FBC systems is underway. A 13-MW combined-cycle

pilot plant is being built to begin operation in

1980 at Woodridge, N.J. The International

Energy Agency (1EA) is constructing a test facility at Grimethorpe with joint participation of

the United Kingdom, the Federal Republic of

Germany, and the United States. Initial operations are expected in early 1979. The program

is expected to span 7 years including construction, and commercial utility application is not

anticipated until about 1995.

Although the fluidized-bed principle has

many attractive advantages, it is still an immature technology that must demonstrate a competitive position with the pulverized coal-fired

boiler. The fluidized bed may require additional process steps and have new problems not

common with today’s conventional utility boilers.

Magnetohydrodynamics (MHD)

The interest in MHD stems mainly from high

expected thermal efficiency for an entire system including a conventional steam cycle. In

MHD generators, a stream of very hot gas

(roughly 5,0000 F), flows through a magnetic

field at high velocity. Because the gas at high

temperatures is an electrical conductor, an

electrical current is produced through electrodes mounted in the sides of the gas duct. A

natural gas-fired MHD generator has been

tested in the U. S. S. R., and coal-fired systems

are still under development.

Coal-fired MHD poses special problems because of the ash in coal. At the high temperatures in the combustor, most of the constituents in ash are vaporized. As the gas cools in

passing through the system, the ash condenses.

The electrodes and the walls of the MHD channel must be cooled, thus coal-ash slag can accumulate on those surfaces, even at the nearsonic velocity of the gas stream. This slag layer

affects the way electrical current flows

through the gas stream from one electrode to

the other, hence the characteristics of the coal

ash are important. 32

It is unlikely that MHD will be widely used

in this century, for the remaining technological

problems are formidable. Progress is being

made, however, and MHD could become an

important adjunct to new coal-fired power stations.

Fuel Cells

In principle, a fuel cell consists of two electrodes immersed in a conducting electrolyte.

One electrode, the anode, is flooded with hydrogen, which reacts with ions in the electrolyte, typically a solution of potassium hydroxide, to release electrons. These electrons

flow through an external circuit–the electrical load —to the cathode, flooded with oxygen, where the electrons react with the electrolyte to form the ions that can react with

hydrogen. Hence the fuel cell is simply a battery, consuming chemical reactants and producing electricity. Unlike ordinary primary

batteries, however, fuel cells continue to produce electrical energy as long as hydrogen and

oxygen are supplied to their electrodes.

The voltage of a single fuel cell is low,

typically 0.8 V under load, but the power output can be high, as much as 100 W/ft2 of electrode area. The thermal efficiency of hydrogen

and oxygen fuel cells is excellent, well over 90

percent at room temperature and at low load.

With some fuels, the thermal efficiency is

greater than 100 percent, showing that a fuel

cell can produce additional electrical energy

from the heat absorbed from its surroundings.

Efficiency of power production remains high

‘

z

’’ In-Channel Observations on Coal Slag,” EPRI Contract 468-1 (Stanford University, 1976).
Ch. ///—Coa/ Technology and Techniques . 105

for widely varying loads, which is a very desirable characteristic

Although hydrogen is ideal for fuel cells,

carbon-based fuels, such as distillate and natural gas, as welI as producer gas from coal, or

other fuel gases containing carbon and hydrogen, are more readily attainable. I n such systems, an alkaline electrolyte, as in hydrogen

fuel cells, is not suitable, and a CO2-rejecting

electrolyte is needed. Phosphoric acid has

been used as an electrolyte in fuel cells at

about 4000 F, but a mixture of molten carbonate salts, at temperatures up to about

1,4000 F, allows the direct electrochemical oxidation even of natural gas;

Fuel cells can serve in a reverse fashion as an

eiectrolyzer to produce hydrogen from offpeak power, to store the hydrogen until a peak

demand develops, and then to convert that hydrogen back into electricity, A shortcoming is

that fuel cells produce DC, not AC, requiring

an inverter to match 60-cycle powerlines. That

technology exists today.

Another advantage of fuel cells is that,

above some moderate size, unit costs remain

about the same as the size of the installation

changes. This means that fuel cell “substations” serving a small group of consumers, say

50 to 100 residences, or a typical industrial

plant, could substitute for central-station powerplants and their extensive electrical distribution networks. The fuel cell substations would

get their energy as hydrogen, pipelined from a

coal gasification plant located in a remote

area. The fuel-cell electrical-generating plant

would emit no pollutants, probably could be

operated with no direct supervision, and might

also serve its nearby customers with hot water

from its waste-heat recovery system. A potential problem is the necessity to supply extreme

Iy clean fuel. The technology does not now exist to economically clean low-Btu gas from

coal to sufficient purity. Hydrogen would be

easier to use. The problems now are mainly of

an engineering nature, utilizing available data

on fuel cells to design, construct, and operate

a fuel-cell installation able to hold its own

economically and reliably with other energyconversion systems based on coal.
Chapter IV

FACTORS AFFECTING

COAL PRODUCTION AND USE
Chapter IV.— FACTORS AFFECTING COAL PRODUCTION AND USE

TABLES

13.

14.

15.

16.

17.

18.

19.

20.

21.

14.

15.

16.

17.

18.

FIGURE S

Sulfur Dioxide. . ..................16 3
Chapter IV

FACTORS AFFECTING

COAL PRODUCTION AND USE

Chapter I I shows a range of projections for coal use. Actual growth will depend on the

decisions of users and producers. The major factors affecting these decisions are the cost,

convenience, and availability of coaI relative to competing fuels.

Unlike oil and gas, coal will not be subject to absolute resource constraints or the resulting scarcity-induced price increases over the next few decades. But the availability of coaI

depends on much more than its presence in the ground. The legal right to mine a specific reserve must be established through ownership or leasing arrangements, A mining company

must decide whether it can sell its product profitably for the life of the mine. A number of

studies and extensive planning must be carried out, and a host of permits secured to comply

with various reguIatory processes. Arrangements must be made for adequate capital, equipment, and labor. Once mining starts, recent laws and reguIations (e. g., the Surface Mine Control and Reclamation Act (SMCRA) and the Coal Mine Health and Safety Act (CM HSA)) affect

methods and costs. Labor-managernent conflicts can Iimit coal availability and color

customers’ perceptions of future reliability. Transportation of coal is a problem in the East

and will demand attention in the West,

On the demand side, the Clean Air Act makes coal combustion more complicated and

costly and presents new problems of waste disposa1. SmaIIer users may have difficuIty i n

physicalIy accommodating the necessary equipment or obtaining regular coal supplies, Converting current oi1- and gas-f i red equipment to coal wiII be especialIy difficult. Public opposition to particular sites for surface mines or coal-burning facilities may cause substantial

delays or force expensive plant modifications. Other regulatory requirements do not impose

constraints on local combustion as severe as those of the Clean Air Act, but their cumuIative

impact will also make combustion more complicated and costly.

The factors Iisted above increase either the cost or the difficulty of producing and using

coal. (The environmental, health, and social benefits from these restrictions are discussed in

chapters V and VI. ) But powerful incentives are at work, on the other hand, for users to turn

to coal. Given favorable market conditions, many of the potential constraints on coal may

never materialize. Others, such as Government regulation, are not directly subject to market

pressures and may slow the growth in coal demand, especialIy in very high-growth scenarios.

This chapter analyzes the factors that affect the components of the coal system outlined in chapter I I I Analysis provides a framework for policy discussion of the problems of

increasing coal output and consumption and for determining the effect on coal development

of measures designed to ameliorate its negative impacts.

COAL AVAILABILITY

Coal is plentiful enough on a national basis

to meet even rapidly growing demand. As described in chapter 11, a massive increase of

Western coal production is underway because

of its low production cost and low-sulfur characteristic. Unlike Eastern reserves, however,

which are almost all privately owned and more

accessible, about 65 percent of all Western

reserves are owned by the Federal Government

and can be mined only under Federal lease.

Much of the remaining Western coal is owned

by States or Indian tribes. As more than half of

all domestic coal reserves are found in the

West, Federal leasing policy is an important

factor in determining long-run coal availability. Federal leasing law is analyzed in chapter

109
110 The Direct Use of Coa/

VI 1. This section discusses the eftect of current

leasing policy on Western coal production.

The Interior Department’s Bureau of Land

Management (BLM)–the agency responsible

for administering Federal leases–reports that

about 5 percent of federalIy owned coal resources has been competitively leased. This

now represents 17,3 bill ion tons of known coal

reserves. ’ About 9 billion tons is subject to

existing applications for preference-right

(noncompetitive) leases, obtained when a prospector demonstrates that commercial quantities of coal have been found in an area

previously not known to have any.

Since 1971 a Federal leasing moratorium has

been imposed and the amount of Ieased reserves has remained relatively constant (only

30,460 additional acres leased). Short-term (3-

year) leasing criteria were developed to allow

current coal producers to obtain mining rights

on adjacent Federal lands, but a successful suit

by the National Resources Defense Council

(NRDC) resulted in the criteria for short-term

leases being Iimited to those required to maintain an existing operation or to meet existing

contracts. The moratorium was imposed because most leaseholders were not mining their

leases. This gave rise to the charge that Federal

coal reserves were being held primarily for

speculative purposes. I n the mid-1 970’s, coal

production from leased reserves stepped up

considerably as rising coal prices and increasing demand made Western coal economical

and attractive. Western coal production has

more than tripled since 1971. About 166

milIion tons were mined there in 1977. One recent study reports that total output from the

67 active Federal coal leases in 1977 was 52.4

mill ion tons, a 241-percent increase since

1973. ’ Those leases represented about 14 percent of the total of all Federal leases. Federal

coal lands under lease contributed about 31

‘An Analysis of Existing Federal Coa/ Lease s

(Washington, D C U.S Department of the Interior,

Bureau of Land Management, 1976), p 6

‘Reserve Data System Report No. 2A (U.S. Department

of the Interior, Geological Survey, Dec 31, 1976).

‘James Cannon, Mine Control: Western Coal Leasing

and Development (New York, N Y.: CounciI on Economic

Priorities, 1978), p 7

percent of Western coal production in 1977.

Coal production on Indian lands doubled between 1973 and 1977 to almost 23 miiIion tons.

Because coal Ieases are often not contiguous, some operators have found it difficult to

assemble the 20 to 30 years’ worth of reserves

needed for a mine large enough to be economical. The moratorium and the NRDC suit have

created uncertainty among operators, who

may defer opening a new mine until they can

lease Federal coal adjacent to their current

holdings. Some operating mines must also

know soon whether they will be allowed to

move into adjacent areas or should plan to

close down when present leases are exhausted.

Regardless of what the Carter administration

chooses to do about leasing, prolonged uncertainty is a constraint on rapid Western coal expansion. A continuation of the moratorium

past 1980 will affect coal development if demand approaches current forecasts. In any

case, if leasing were to be resumed, regional

environmental impact statements would have

to be prepared before mining could begin, a

process that may take more than a year. Additional delay in the form of court challenges to

renewed Ieasing can also be expected. Despite

these constraints, sufficient Western coal has

been leased to meet anticipated increases in

demand through the 1980’s. However, currently leased reserves would not be adequate to

support expected coal production levels in the

1990’s. The long Ieadtime required to put a

mine into operation requires a resumption of

leasing in the early 1980’s to meet these levels.

There is littIe chance that a significant

number of new leases will be offered before

the 1980’s, according to the best available information. ’ The terms of any future leasing are

unresolved. If leasing is reinstituted, the new

criteria may limit the amount of coal available. If the administration chooses to initiate a

leasing policy soon, this coal would probably

be commercially available after 1985.

“’Completion of Interior’s Coal Leasing Program Targeted for Mid-1980,” U S Department of the Interior

News Release, Oct. 25, 1977,
Ch. IV—Factors Affecting Coal Product/on and Use ● 111

INDUSTRY PROFILE

Coal is mined by companies ranging from

major corporations to one-family operations.

The future of the coal industry depends in

large part on how these companies react to

changing conditions. This section describes

these companies and how they market their

coal. The competitive situation in the industry

is examined. FinalIy, the mechanisms for setting prices for coal are analyzed.

Ownership and Markets

The coal industry has evolved from a large

number of small- and medium-sized independent companies to a smalI number of very large

companies (most of whom are subsidiaries)

and a large number of smalI independents

Most major, noncaptive producers are now

owned by energy companies or conglomerates.

Of the top 15 coal producers in 1977, as shown

in table 13, only two were independent. Five

were captives of steel companies or utiIities,

three were subsidiaries of conglomerates, and

five were owned by integrated energy companies. Sixteen years ago, all major coal companies were independent except for those few

owned by industrials.

The terms “commercial” and “captive”

arose in an earlier time when companies could

be differentiated by their markets and whether

their product competed freely. “Commercial”

is a term that no longer means quite what it did

in the 1930’s and 1940’s. Then, a commercial

operator sold to a variety of customers and

often in several markets. As the utility market

ascended after 1950, big operators negotiated

long-term contracts with major utilities, a

trend that is stilI increasing. I n 1976, 86 percent

of all coal shipped to utilities was under longterm contract. Sometimes these contracts span

20 years or more and, in effect, turn “commercial” coal into dedicated or “capt[ve” coal, as

the coal no longer competes in an open market. Such coal is in market competition only

when the buyer is evaluating bids.

Most modern coal-supply agreements contain price-escalation provisions that allow upTable 13.—Top 15 Coal Producers and Parent Companies, 1977

1977

Coal company Tonnage Statusa Controlling company

Peabody Group .,.. . . . . . . . . . . . . . . . . . . . . . . . 65,425,088

47,994,000

28,127,161

16,749,859

14,309,049

13,959,000

12,600,000

11,988,906

10,609,970

10,298,630

10,223,000

9,773,700

9,720,447

8,905,203

8,202,640

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 278,886,654

c

e

c

e

i

s

e

u

s

c

u

u

e

I

e
112 ● The Direct Use of Coa/

ward price adjustments to offset the seller’s

cost of infIation, overhead, new labor agreements, and taxes. Some contracts have “market reopener” provisions, which allow either

party to reopen the contract’s negotiated price

when the market price for substantially similar

coal sold from relevant market areas rises or

falls. Typically, a coal supply agreement will

contain a force majeure cIause, which excuses

either party from meeting its obligations when

unforeseen or uncontrolIable events — such as

labor disputes, equipment breakdowns, faults

in the coal seam, or new laws — frustrate performance. Most long-term contracts run full

term with various price adjustments along the

way.

Coal is also sold in a “spot” market. Unlike

term contracts, spot sales are totally the

creature of short-term, supply and demand

forces, Most spot-market suppliers are smaller

companies operating small mines, though

some big mines sell excess production this

way. Many spot sellers enter the market when

prices rise. Between 1973 and 1978, the number of mines increased 33 percent from 4,650

to almost 6,200 as the average price per ton

rose 140 percent from $8,53 to $20.50. Spot

prices rose faster and went higher than contract coal because of the perceived fuel shortage created by the 1973 OPEC embargo and

other factors, Because many long-term contracts have reopener clauses pegged to spot

prices, industrywide coal prices can be pushed

up by very short-term or unique price pressures

in the spot market. Although reopener clauses

are supposed to work both ways, recent experience suggests that contract prices flow up

more readily than down.

Captive producers historically were organized as wholly owned subsidiaries of steelmaker, auto manufacturers, or utilities to

assure the parent company of a steady supply

of a certain kind of coal. UsualIy, most captive-produced coal was (and is) sold to the

parent company, In 1973, utilities mined about

8.9 percent of their total burn; in 1977, 14.5

percent. Many of the giant new strip mines in

the West are utility captives. The Federal

Power Commission (now absorbed into the Department of Energy (DOE)) estimated “captive” (utility) coal production will triple from

1975 to 1985, reaching 145.1 million tons per

year, about 18.8 percent of the projected 770

mill ion tons of coal to be consumed by the

electric utilities in 1985.”5 DOE estimated that

utilIties control led 11.6 biIIion tons of recoverable coal reserves as of December 31,

1975.

A utility reaps many advantages from mining its own coal, Supply is made more dependable. Protection is gained against noncostrelated price increases. Tax shelters are available, Leverage can be exercised in negotiations

with independent coal suppliers, Prices may be

adjusted to achieve the “potential for greater

return on equity than afforded by regulated

utiIity operations.”6

The economic implications of this “vertical

integration’ in the coal industry are disputed

and have not been studied adequately, Utilities argue that vertical integration allows

them to effect supply reliabiIity and cost control — both to the benefit of the consumer, In

return, critics say that utilities sometimes hold

back their captive production in order to justify rate increases. A second charge is that utilities have little incentive to keep down production costs in their captive mines as long as they

can be passed through to electricity consumers. Consumer advocates say some utilities

pay more for their own coal than do utiIities

without captive production, Utility profits are

increased through this inflationary process, it

is said. Further analysis is beyond the scope of

this report,

Horizontal integration, the ownership of

coal companies by companies that produce

other forms of energy, has received more attention than vertical integration. In 1963 Gulf

Oil took over Pittsburg & Midway Coal Co., beginning what became substantial energy-company (oil and gas producers) investment in

coal-producing companies and reserves. The

Congressional Research Service reported that

77 percent of all coal producers mining more
Ch. /V—Factors Affecting Coal Production and Use 113

than 3 million tons annually were controlled

by noncoal companies. 7

Heated debate over the significance of

energy-company ownership of coal producers

and reserves was sparked by the unprecedented increase in coal prices, which accelerated after the 1973 OPEC oil embargo.

Has horizontal integration of energy production affected coal supply, price, profits, investment, competitiveness, and markets? Did oilowned coal suppliers, for example, raise their

coal prices after the embargo to keep highpriced oil competitive with coal in the Atlantic

coast market? Does oil and gas ownership of

coal reserves mean anything for the future?

Conclusive answers to such questions cannot

be offered because the data are unavailable.

Some of the needed information may be considered proprietary by coal subsidiaries and

parent corporations. It is often difficult to

isolate the variable of oiI/gas ownership as being the only cause of coal production and

price patterns, as many other factors are also

at work. However, the general scope of horizontal ownership can be sketched,

Coal production by oil and gas company

subsidiaries totaled 166.6 million tons in 1976

(table 14), or 25 percent of national production. Of this, about 125 million tons was steam

coal, As much as 35 percent of noncaptive

steam coal is currently mined by oil- and gasowned coal producers.

Energy-company production is expected to

increase its share of the total in the years

ahead. All horizontalIy integrated producers

plan to increase production. In addition, a

number of other major energy companies,

such as Sun Oil Co,, Kerr-McGee, ARCO, Shell

Oil Co., Natural Gas Co., and Mobil Oil, a are in

the process of opening large surface mines in

the West.

Horizontally integrated energy companies

account for about 40 percent of all planned
114 ● The Direct Use of Coa/

Table 14.—Oil and Gas Ownership of Coal Producers

(In millions of tons produced, 1976)

1976

Coal company Parent company production

Total

1976

55.9

23.1

18.0

17.6

9.7

8.0

7.9

5.2

5.2

3.9

3.6

2.8

2.1

1.0

.9

.5

.4

.4

.3

.1

166.6
Ch. IV—Factors Affecting Coal Production and Use . 115

Table 15.— New Steam-Coal’ Capacity of Horizontally Integrated

Energy Companies by 1986 (In millions of tons)

(Continued)

State Tonnage State Tonnage

17,6

5.6

2

7.6

45.0

7.2

30.0

24.0

5.0

5.0

30.0

8.0

19,0

14.0

4.0

191.2

335.75

SOURCE 1978 Keystone Coal /ndustry Marrua/
116 ● The Direct Use of Coa/
Ch, /V—Factors Affecting Coa/ ProductIon and Use . 117

Patterns of reserve ownership may shape the

future structure of the coal industry, especially

if Federal leasing does not resume soon. Reserve ownership affects major market factors:

supply, price, and the ability of potential coal

producers to enter the field, Six of the top ten

reserve holders are wholly or partially owned

by energy companies: Continental Oil, EXXON,

El Paso Natural Gas, Standard Oil of California, occidental Petroleum, and Mobil. Energycompany representatives argue that coal reserves are widely dispersed, that the share of

total reserves controlled by oil companies is

not substantial, 4 that large reserve holdings are

necessary for long-range development plans,

and, finally, that supply, price, and competition have not been adversely affected by

energy-company ownership. As the Federal

Government still controls most reserves, industry spokesmen say any potential anticompetitive situations can be controlled by

Federal policy.

The research has not been done that would

confirm or deny the actual market implications of coal-reserve control by horizontally integrated energy companies. The major charge

against energy companies has been that by

speculating and waiting higher coal prices,

they did not develop their Western reserves in

the late 1960’s and early 1970’s. Had Western

coal been readily available in these years,

prices might not have increased. It is worth

noting that the major purchasers and Ieasers of

coal reserves in the last decade have been

energy companies. Conglomerates do not have

significant holdings. As energy companies add

to their reserves, it may be increasingly difficult for new entrants to acquire enough longterm reserves to justify the high start-up costs

of mining. Smaller companies may not be able

to compete with bigger companies because of

their capital constraints.

It is worth noting that the major purchasers

and Ieasers of coal reserves in the last decade

have been energy companies. Other conglomerates do not have significant holdings.
118 ● The Direct Use of Coal

Kentucky coal does not sell in the Northeast.

Further, high-grade metallurgical coals do not

generally compete against steam coals. Captive coal, moreover, does not generally compete against noncaptive coal. ” Similarly,

1 977’s 54 million tons of export coal – most of

which was metallurgical — does not compete

domestically, except when foreign demand

slumps. A true assessment of concentration in

the coal industry must disaggregate production data and look at concentration in much

more precisely defined markets.

DOE estimated that the top four noncaptive

suppliers will provide about 47 percent of new

noncaptive, electric utility supply now under

contract in 1985.20 The top eight noncaptive

producers will supply about 71 percent of this

tonnage. Production from the new key coal

States, Wyoming and Montana, will be more

concentrated: 70 percent for the top four and

92 percent for the top eight.21

The long-term contracts discussed above

also bear on competition. 1 n effect, these contracts reduce both the real amount of coal

available in the marketplace and the number

(and needs) of customers. The Federal Trade

Commission noted:

In manufacturing industries, productio n

concentration is also an indicator of the present supply alternatives open to potential buyers, If a firm produces 10,000 units of output

per year, it can be assumed that up to 10,000

units are available to any qualified buyer. This

is not the case in the coal industry, Due to the

prevalence of long-term contracts, the annual

production of a coal company may not be a

valid measure of the quantity of coal available

to potential buyers from that producer. 22

These contracts account for about 86-percent of coal’s utility sales. With some exceptions, once a contract of this sort is concluded
Ch. IV—Factors Affecting Coal Product/on and Use ● 119

coal producers, like much of American business, use “outside” boards of directors to

guide corporate policy. Directors are often

chosen because their expertise or primary affiliation will help a company do business profitably. Many mining companies and manufacturers include representatives of major financial institutions on their boards Major stockholders—which may include families, financial institutions, and other corporations — are

also represented. Direct interlocks — where one

individual serves as a director of at least two

corporations — are common between a coal

producer and a capital supplier. One coal producer may be indirectly interlocked with

others when a director of each sits on the

board of a third corporation. Indirect interlocks among coal producers, coal consumers (utilities and industrials, especially),

and capital suppliers are common. It is also

common to find representatives of major financial institutions sitting on the boards of

competing coal producers.

Distribution of voting rights differs from corporation to corporation. I n those cases where a

single family does not dominate a company,

bank trust departments, insurance companies,

and mutual funds often own the biggest blocks

of stock.2 G Where stockownership is dispersed,

holdings below 5 percent can constitute corporate control in some intances. If a single

company — a bank, for example— owns substantial voting rights in several coal producers,

some analysts argue that the potential for anticompetitive behavior is present.

Consolidation Coal –the Nation’s second

largest coal producer– is fairly typical of the

ownership patterns among energy-owned coal

producers Consol is a subsidiary of Continental Oil. Continental’s board was tied to 12 coalreserve holders or coal producers, 9 coal consumers, and 20 capital suppliers through at

least one indirect director interlock as of

1976 .

28 Continental shared a director with

Bankers Trust of New York, Continental IlIinois, and Equitable Life Assurance, (Equitable is a major stockholder in Peabody Coal,

the Nation’s biggest coal producer and fourth

largest reserve holder. ) Seven of the 20 capital

suppliers were among the company’s top 20

stock holders .29 Continental’s biggest stockholder, Newmont Mining Company (3.29 percent) is also the principal stockholder in

Peabody Coal (27.5 percent). Capital suppliers

with whom Continental shares a director are

major stockholders in other leading coal producers and reserve holders.30

It is fair to ask a simple question at this

point: What do these interlocks mean? The

fairest answer is equally simple: We are not

certain. The research needed to confirm or

deny the significance of this ownership network has not been done. Although the potential for antitrust abuse exists where corporations with common interests are interlocked,

no coal industry case study has been done to

determine whether this potential for abuse has

been used. Similarly, the implications of coal’s

stock holding distribution have not been

studied.
120 ● The Direct Use of Coa/

resources necessary to meet production goals. dented level of profitability in the mid-197C)’s

However, if the realized rate of return does not was due less to rising production than to the

meet investor expectations, capital is likely to’ price increases that followed the OPEC emflow into noncoal investments. Energy companies and conglomerates can choose between

alternative investments whereas a nondiversified coal company cannot. It is possible that

leading coal producers might attempt to encourage price increases and maximize their

rates of return by regulating supply. Deregulation of—and higher prices for—oil and gas

should lead to higher coal prices, although the

increases may not be identically proportional.

Higher prices should encourage coal investment and enable operators to spend more on

health and safety, environmental protection,

and community improvement.

The interaction among price, production

costs, profit, and capital investment is central

to expanding coal supply. The relationship

among these factors changed dramatically in

the 1970’s. All rose substantially over pre1970

levels, but production did not rise proportionately and productivity fell. The price per

ton quadrupled between 1968 and 1975 while

labor costs doubled in that period. ” The unit

labor cost share dropped from 58.5 percent in

1950 to 20,3 percent of per ton value in 1974. It

probably amounts to 25 to 30 percent of value

today due to increases in wages and benefits

and the leveling off of the coal price rise. Rising prices helped boost industry profits. Coal’s

return on net worth exceeded 11 percent only

once in the 1950-73 period, but it approached

30 percent in 1974 following the OPEC embargo. ” From 1971 through 1974, net coal income

of 24 leading coal producers rose 298 percent

from $128.4 million to $639.5 million, most of

which came in 1973-74. Coal’s unprecebargo and to a temporary surge in worldwide

demand for met coal.

A precise picture of the financial status of

the industry is difficult to develop because

much of the necessary data has not been available to the public. Parent companies have not

been required to separate financial data for

their coal subsidiaries in their reports to the

Securities and Exchange Commission, A check

of the financial data for the Pittston Corp.

(primarily a West Virginia-based metallurgical

coal producer) and North American Coal (an

eastern producer of met and steam coals) adds

case-study data to the gross statistics noted

above (see table 17). Despite declining productivity and slipping production, both companies

recorded increased net income after 1973. Net

income per employee increased in both cases,

suggesting that income productivity and labor

productivity do not necessarily coincide. Between 1970 and 1977, Pittston’s net income per

employee rose 252 percent and North American’s gained 73 percent (current dollars). Consolidation Coal, the second biggest coal producer and a subsidiary of Continental Oil,

showed coal revenues being five times greater

in 1977 than in 1970, although revenues for

1975 through 1977 were relative l

y u n -

changed. 35

Return on investment and profits slacked in

1978 because of the coal strike and demand

softness for certain coals. For most companies,

this should prove to be a temporary phenomenon.
Ch. 1 V— Factors Affecting Coal Production and Use “ 121

Table 17.—North American Coai and Pittston Corporations Profitability and Productivity

1970 1971 1972 1973 1974 1975 1976

LABOR PROFILE
122 The Direct Use of Coal

never do. Many are highly skilled; others underground mines. The perspective of all

aren’t. Their work environments range from UMWA presidents has been that of the deep

air-conditioned, bucket-seated dragline cabs miner. This experience has shaped coal’s colto 20-inch coal seams where the machine oper- Iective bargaining from the beginning.

ator lies nearly on his back most of the day.

Most coal labor– about 160,000 persons— belong to the United Mine Workers of America

(UMWA), which sets many of the wage and

benefit standards for the entire industry. Several thousand belong to the Progressive Mine

Workers (PMW), Southern Labor Union (SLU),

Operating Engineers, and other unions. More

than 40,000 probably belong to no union at all,

either from choice or lack of opportunity.

Important differences are found between

the two groups. Accident frequency, for example, is significantly lower for surface miners,

although some kinds of surface mines are less

safe than some deep mines. Surface miners are

generally older, work more days annually,

strike less, and are paid more than their underground counterparts. The average age of most

UMWA deep miners was 35 in 1976 compared

with 41 for most UMWA surface miners. 37 I n

Photo credit: Douglas Yarrow

Last shift comes out at Eccles #5 before the 1977 contract strike
Ch /V—Factors Affecting Coal ProductIon and Use ● 123

“Jean M Brett and Stephen B Goldberg, Wildcat

Strikes In the Bituminous Coal Mining/ndustry A Pre/iminarv Report (Northwestern U nlverslty, 1978), p 23

“Data suppl led by BCOA

40 Don R Richardson Associates, A Survey of W’est

V{rginla Coal Miners, 1977, p 26

“OTA made these estimates based on data supplied by

BCOA and MSHA
124 The Direct Use of Coal

Figure 14.— Distribution of Employees by Annual Earnings at Deep and Surface Mines

Number of

employees

35,000

30,000

25,000

20,000

15,000

10,000

Deep Mines

1976

1975

Surface Mines

● ● ● ● ● ● 1976

— 197 5

SOURCE Income data supplled by the Bltumlnous Coal Operators’ Assoclatlon, 1978

Earnings
Ch. I V— Factors Affecting Coal ProductIon and Use 125

Figure 15. —Distribution of UMWA Employees by Age—All Mines’ 1974-76

Number of

employees

25,000

20.000

15,000

10,000

5,000

0 Age

few cases of moving eastern miners and mine

management to the West have not been very

successfuI.

The fourth and perhaps most significant distinction is unionization Those who have not

spent time in the UMWA coal fields have a

hard time understanding the intensity of the

miners’ feeling for UMWA. Whether they are

disgusted or delighted with its performance,

they tee] it is theirs, built by them to serve their

interests As harsh as its internal critics are,

most believe that unionization is the only

thing standing between them and the coal

company. ”

Non-UMWA miners are located principally

in southern Appalachia (southwest Virginia,

east Kentucky, and east Tennessee) and west

of the Mississippi Few demographic or attitudinal data exist about them. Often they make

as much money as — or more than — UMWA

miners. This relatively recent phenomenon was

made possible by the higher profitability of

mining after the OPEC embargo. Most nonUMWA mines are relatively new, They do not

carry pension obligations to older miners and

retirees that UMWA-organized companies

carry Few of their workers have even retired,

and many of the smalIer, non-organized companies have small pension obligations, if any.
126 The Direct Use of Coa/

In big, non-UMWA mines health insurance

plans and other benefits are comparable to

UMWA standards. In a few western surface

mines, the benefits are more comprehensive,

What many nonunion miners lack contractually are job protections, a grievance procedure,

and some safety rights (including the right to

elect a safety committee and the right of the

individual to withdraw from danger). NonUMWA miners also lack a national voice. The

UMWA, whatever its tailings, speaks for the

Nation’s coal miners in Washington, D. C., NonUMWA miners are not represented, although

they benefit from legislation or regulatory initiatives UMWA is able to push through.

The extent of unionization varies in the

West. The majority of mines in the Carbon and

Emery Counties area of Utah is organized by

UMWA. On the other hand, only the captive

Wyodak Mine associated with the Wyodak

Power Plant in Campbell County, Wyo., is

organized (International Brotherhood of Electrical Workers (1BEW)). North Dakota mines

are organized by several unions. Consolidation

Coal and North American Coal have UMWA

contracts. Mines of the Knife River Coal Mining Company are organized by the PMW. The

Operating Engineers, the predominant union in

Colorado, does not represent mines in North

Dakota. The captive Baukol-Noonan Mine is

organized by the IBEW. The UMWA is a major

force in parts of the West. It is the dominant

union i n Utah underground mines. I t represents mines on the Navajo Reservation. It has

lost some of its power to other unions. Only

2,000 to 3,000 surface miners are UMWAorganized in the West. Most Western States

have right-to-work laws that limit unionization.

These demographic and social indicators reflect major structural changes that occurred in

the coal industry over the last decade. In these

years, surface production moved ahead of underground production. The locus of national

coal output moved westward, Oil companies

took over major coal producers, and most of

their effort centered on developing western

surface mines. The proportion of coal workers

who are UMWA members dropped from between 75 to 80 percent in the late 1960’s to

around 65 to 70 percent today .44 UMWA tonnage, however, has fallen to about 50 percent

of the total production owing to the increase

in nonunion, surface-mined coal.

Still, the heart of the coal industry is in the

East. And it is there that one must go to explain

labor-management instability and the attitudes that cause it. The 1960’s allowed management to become complacent about its

labor needs. Mechanization and layoffs meant

a large pool of experienced miners. Wildcat

strikes were infrequent because of the labor

surplus and organizational policy. Coal producers had few incentives to provide better

working conditions. Their ranks were not hospitable to policy innovators. An illusion set in

that all was well. It deprived management and

labor of a vital spirit that both need for continued health. Industry found that its lower

management consisted of men too old, too

timid, or simply too set in their ways to become good leaders. But as long as coal demand stagnated and prices were more or less

constant, the industry’s stabiIity was not upset.
Ch. III--Facfors Affecting Coa/ Production and Use . 127

COLLECTIVE BARGAINING: A STORMY HISTORY

Labor relations in the U.S coal industry have

been characterized by suspicion, acrimony,

violence, and, occasional I y, cooperation.

Throughout this century the unwillingness of

miners to accept the conditions of their work

has led to chronic unauthorized work stoppages, turmoil, and prolonged contract strikes.

The number, duration, and cost of wildcat

strikes have increased since 1970.45 The absence of equitable and stable labor-management relationships has hampered coal production and supply reliabillty. Coal miners’ income, benefits, and health care systems, have

been cut back. On the other hand, many miners say wiIdcat strikes are often the only way to

force an employer to deal quickly– and presumably favorably— with one of the miners’

concerns. The roots of today’s conflict Iie deep

in the past. But it is simplistic to believe that

current practices do not contribute. Many of

the sources of discontent are deeply embedded in coal economics and management

policies These may not change easily. Finally,

even though U.S. energy policy counts heavily

on coal, the advisabiIity of Federal intervention in the industry’s labor-management relations is not clear

Collective bargaining and labor relations

generally have been shaped by the economics

and structure of the industry. How miners were

treated by operators was often determined by

how operators treated each other and how

coal was treated in the marketplace. Free enterprise has never produced stable labor relations in coal. Competition, rather than

st rengthening industry stability, tended to

destroy it. Chronic labor unrest has been reIated to the cost-cutting pressures of competition amid demand stagnation. Periodically,

coal strikes erupted and dragged on for

months or even years. Strikes of national consequence occurred in 1902, the early 1920’s,

the late-l 940’s, and the mid-1 970’s. Often they

occurred when demand was strong. When demand surged and high prices encouraged

marginal operators to begin mining, the market was quickly oversupplied and a slump soon

followed Miners felt it opportune to press

their demands during these booms, and when

demand slacked, they struck to maintain their

gains. Understanding the boom-bust cycle as

they did, operators resisted labor’s demands

during both the short booms and the long

busts.

Apart from market factors, a second source

of labor-management strife originates from the

attitudes and conditions resulting from the

nature of the mine workplace and the work

process, The work environment of underground coal mining is unique. Danger is inherent, although control I able. Work has been

made easier by mechanization, but the workplace has not been made more pleasant.

Modern coal miners end their shifts wet, dirty,

often chilled, with mine dust embedded in

every pore. Often they work on their knees;

standing or kneeling in cold, oily water for

hours at a time; listening to the “working” of

the mountain above them. A roof that looks

safe may double-cross them in a second. Wariness and caution are essential.

Unlike assembly-line work, mining requires

workers — as individuals and as part of an interdependent team — to control much of their

own work. Miners must constantly adapt their

work to ever-changing environmental conditions. The mining process requires a good deal

of individual judgment and peer-coordination.

The pace of work is determined to a great extent by the miner’s minute-by-minute evacuation of physical conditions and machinery. Because so much of mining is a matter of judgment, miners and section supervisors often disagree. Disputes stem from the pace of work;

who is to do what; what needs — or doesn’t
128 ● The Direct Use of Coa/

need —to be done; what precautions must be

taken; and what kind of work miners can legitimately be asked to do. Miners and foremen

develop routines of interaction that are both

adversarial and cooperative. Both take pride in

“running” a lot of coal during their shifts. But

this shared goal is often subverted when management asserts authority in ways that miners

perceive to be arbitrary or as violating their job

rights. UMWA miners have developed elaborate work rules and codifications of their rights

to protect themselves from perceived management transgressions. If one of the commonly

understood rules is breached, miners close

ranks and resist.

Workplace-generated attitudes lend themselves to constant confrontations. First, miners

are proud of doing useful and dangerous work.

Pride is Iinked to self-confidence; both are

combined with a certain trucuIence against being told how to do their work. Second, the

danger of the workplace readies miners for turbulent conflict outside of it. Third, the work

process trains miners to work collectively. This

interdependence carries over to conflicts with

management. A wrong done to one miner is interpreted as a threat to all. Shared dangers and

interdependent work produce group cohesion

when the group is faced with a common threat.

It creates a “them and us” attitude. It enables

miners to stick together through prolonged

strikes.

The social environment of the coalfields is a

third factor contributing to the volatility of

labor-management relations. The basic form of

social organization in coal’s early years was

the company town. In these communities,

mine operators owned or controlled everything— housing, medical care, schools, the

law, churches, and commerce. Until the 1930’s

and 1940’s, miners were often forced as a condition of their employment to accept wages in

scrip instead of U.S. currency and to buy only

at the company store. The miner’s perception

of work victimization was compounded by this

same perception in a company-controlled

community. The work routine regulated coalcamp existence. Mine operators established

the quality of community life. Social equality

among mining families reflected the equality

of the workplace. When work conflict arose, it

quickly enveloped the camp’s entire social system. Mining was not only a job, it was a way of

life for workers and their families. Although

the coal-camp system was dismantled a generation ago (when mechanization cut employment and spendable income to the bone, thus

making the closed system unprofitable), many

of the facilities are used today, and the

psychology of the system remains.

Finally, industrial conflict plagues coal

because of the past. Coal camps were experiential hothouses; each perceived wrong,

each dispute became part of the community’s

history. The bitterness could never dissipate.

Children of miners absorbed — and continue to

absorb — the attitudes of their parents. There is

no quick remedy for this historical sensitivity;

it must be accepted.

The history that follows is necessary to understand present day labor-management relationships and how they will or will not be affected by Federal policy.

The Early History

Unlike other basic industrial activities, coal

production did not grow steadily over the first

70 years of this century. The industry’s capacity to produce did not change significantly

after 1918. As recently as 1974, the operators

produced only slightly more than they had in

1918 and less than in 1947. Demand stagnation

forced the industry to be acutely cost-conscious. This often translated into protracted

opposition to unionization and continued

pressure to reduce labor costs. Both policies

occasioned many strikes and much bitterness

in the 1920’s and 1930’s. A high level of market

competition among hundreds of suppliers intensified the cost-cutting pressures within the

industry. Because demand fluctuated but did

not grow, operators were less concerned about

mining more coal and more concerned about

continued lowering of their labor costs to

maintain competitiveness. The implications

for harmonious labor relations are apparent.

Coal’s industrial relations changed in the

1930’s and 1%0’s, until that period, the majori- ,
Ch. /V—Factors Affecting Coa/ ProductIon and Use 129

Operators’ Association

established unquestioned

by this time. His political

expelled or neutralized in

and file had lost its right

to ratify contracts. The union’s internal organization was under Lewis’ persona I direction.

Lewis and Love recognized that the demandlimited situation in 1949-50 threatened both

sides with a devastating circle of oversupply,

wage cuts, and layoffs — the very pattern that

had brought them close to ruin 20 years

before. The self-interest of each led to considering ways of saving the other,

Cooperation: 1950-72
130 ● The Direct Use of Coa/

other, he hoped that BCOA members could

sew up the blossoming utility market, the key

to coal’s future. Both objectives depended on

the ability of BCOA companies to increase

productivity and cut labor costs to maintain

their competitiveness with oil and gas and

eliminate low-priced coal suppliers.

Love and Lewis saw mechanization as the

way to increase productivity and reduce labor

costs. I n underground mining, mechanization

meant eliminating hand loading. Machines

could produce three times as much coal with

10 workers as 86 workers in a hand loading section. Mechanization also meant more surface

mining, which was more efficient than even

underground centinuous miners. Surfacemined production increased from 24 percent

of total output in 1950 to about 60 percent in

1977. Industrywide productivity almost tripled

between 1950 and 1969. However, coal-mine

employment fell 70 percent between 1950 and

1969, from 415,482 to 124,532.

The crucial factor in mechanizing coal was

John L. Lewis. If he had chosen to delay it, the

industry would have suffered. But Lewis championed mechanization, and had done so at

least since the 1925 publication of his only

book, where he wrote:

The policy of the United Mine Workers of

America will inevitably bring about the utmost

employment of machinery of which coal

mining is physically capable.

Fair wages and American standards of Iiving

are inextricably bound up with the progressive

substitutions of mechanical for human power.

It is no accident that fair wages and machinery

will walk hand in hand.47

in

Lewis reiterated his views on mechanization

the early 1950’s:

We decided that question [the UMWA’S

position on mechanization] long years ago

. . in return for encouraging modernization,

the utilization of machinery and power in the

mines and modern techniques, the union

. . . insists on a clear participation in the ad-

“John Lewis, The Miners’ Fight for American Standards,

(Indianapolis, Ind,. Bell Publishing Co., 1925) pp 108-109,

vantages of the machine and the improved

techniques.48

Mechanization was so I inked in Lewis’ thinking

to higher wages and benefits that he simply

shrugged off unemployment and other social

costs as the price of industrial rationalization.

With the UMWA supporting mechanization,

big BCOA operators were able to cut their labor costs, secure long-term contracts, and

maintain their profitability. Much of the new

machinery was financed by using the contracts

themselves as collateral, UMWA also loaned

money directly to a number of companies to

finance capital investment.

UMWA itself began reevaluating Lewis’

policy on mechanization in 1973:

A question which has persisted throughout

UMWA history is how closely related are the

welfare of the miner and of the coal industry.

The coal operators have always argued that

what’s good for Consolidation Coal Co. is good

for every mine worker, and that miners should

therefore refrain from asking for too big a

share of the profits, During most of his career,

John L. Lewis knew better. When he argued for

creation of the Welfare Fund, when he argued

for better safety laws, when he argued for

price controls during wartime wage controls,

he repeated his confidence that the coal industry had the wealth to meet the human

needs of those who supported it,

But in the 1950’s he went against that longtime judgment. Faced with mechanization of

the mines, Lewis, in his own words, ‘decided

it’s better to have a half a million men working

in the industry at good wages, high standards

of Iiving, than it is to have a mill ion men working in the industry in poverty and degradation, ’

It was a firm decision, and mechanization

with its drastic reduction of the work force

was carried out. Unfortunately, no provision

was made for the hundreds of thousands of

men who were put out of work. There were no

benefits, no retraining programs, no new industry brought in. A great many miners were

forced to take their families to northern cities

“Justin McCarthy, A Brief History of the United Mine

Workers of America (Washington, DC. United Mine

Workers of America, 1952), pp. 7-8.
Ch. IV—Factors Affecting Coal Production and Use • 131

like Detroit and Chicago, where most did not

fit in and did not want to.49

Lewis exacted a price from BCOA for supporting mechanization. Hourly wages were

increased — a I be it modestly–for working

miners in each round of bargaining after 1950,

The major concession Lewis received was the

establishment of the UMWA Welfare and Retirement Fund, which provided pensions and

near-comprehensive, first-dolIar medical coverage for UMWA members and their families.

The Fund was started in 1946, when Lewis persuaded Interior Secretary JuIius Krug (who was

administering the Nation’s mines after they

had been seized) of its merit. A modest tonnage royalty was levied, But the operators

fought the plan and its funding formula for the

next 5 years. Love committed the big operators

to support the Fund in 1950, A tonnage royalty

was fixed, and it did not rise between 1952 and

1971. Although the Fund was supposed to be

distinct from UMWA, Love gave Lewis de facto

control of the three-person board of trustees

when he accepted Josephine Roche, a longtime Lewis confidante, to serve as the neutral

trustee. The Fund did much good work in coalfield health care in the 1950’s and 1960’s.

Clinics were organized. A chain of hospitals

was built. Preventive services were encouraged. Controls over cost and quality of

health services were established. But the financial resources of the Fund were always dependent on the level of production of the BCOA

companies that paid the royalties. When demand fell in the late 1950’s and early 1960’s,

the Fund — living on an unchanged tonnage

royalty —was caught short. It had to sell its

hospitals and withdraw medical benefits from

thousands of miners who had been “mech -

anized ” out of their jobs. When the Fund’s

records began to show startling increases in

respiratory disease among its beneficiaries in

the 1960’s, Roche and Boyle refused to demand dust controls or an industrywide dust

standard. Lewis and Boyle might have negotiated a higher tonnage payment to cover Fund

49 The Year of the Rank and File: Officers’ Report to the

United Mine Workers of America 46th Constitutional

Convention, United Mine Workers of America, 1973, p,

68

needs, but that risked increasing the pressure

on BCOA members who were being battered

by low prices and demand stagnation

UMWA finally raised such criticisms of the

Fund in 1973:

The history of the [bituminous] Funds since

their early days is a mixed one. Many persons have been paid, but many men were cut

out by arbitrary and unfair rules while the hard

coal [anthracite] pension dropped to $30 per

month. Medical services were provided for

miners and their families, but were taken away

from disabled miners and widows. For almost

20 years the royalty stayed at 40 cents, while

up to $90 million of the soft coal Fund’s

money was kept in non-interest-bearing checking accounts at the union-owned National

Bank of Washington .’”

The scope of the Fund’s work grew increasingly

constricted over the years. Under the 1978 contract, medical insurance for working miners

was switched to private carriers, leaving the

Fund to administer health benefits and pensions only for retired miners.

As labor costs were lowered in the 1950’s

and 1960’s, the industry also externalized production costs. Social costs and externalized

costs were rarely assessed in these years. Reclamation standards for surface mines, for example, were not enacted until the late-1960’s.

Dust controls were not required in underground mines until 1970, when coal workers’

pneumonconiosis (CWP) was recognized as a

disabling occupational disease by Federal

legislation. Federal safety standards were

minimal. Industry was not expected to bear the

public costs of the unemployment produced

by mechanization. Systematic air pollution

controls had yet to be enacted; coal suppliers

sold relatively “dirty” coal to utilities. Finally,

coal field communities generally imposed

small tax burdens on local mine operators and

coal-reserve owners, fearing that even the

slightest additional economic pressure would

make local employers uncompetitive. When

demand picked up in the late 1960’s and early

1970’s, the industry was coincidentally expected to begin paying many of these social

costs through compliance with environmental

50 The Year of the Rank and File, p. 67.
132 • The Direct Use of Coal

regulations and health and safety standards.

The deficit of community services that had accumulated during the depressed 1950’s and

1960’s handicapped fast growth in the 1970’s,

when coal towns struggled to meet the needs

of hundreds of new miners.

The Love-Lewis contract of 1950 sought not

only to stabilize labor but to impose order on

coal suppliers. Surplus miners increased costs

of production while surplus operators drove

down prices. Both were seen as problems to be

solved. Lewis shared the BCOA’S attitude

toward the marginal independent suppliers, of

whom he said in 1950:

The smaller coal operators are just a drag on

the industry The constant tendency in this

country is going to be for the concentration of

production into fewer and fewer unit s

more obsolete units will fall by the board and

go out of production. 5 I

Lewis used UMWA resources to further the

competition-limiting ends of his partnership

with BCOA. His organizing drives in the 1950’s

focused on the small companies exclusively. It

appears that the real purpose of the union’s

campaign of dynamite and sabotage was less

to organize these companies than to eliminate

them. While battling the non-BCOA operators,

Lewis signed “sweetheart” contracts with a

number of BCOA members. These secret

agreements allowed the favored operator to

pay less than union-scale wages or suspend

royalty payments to the UMWA’s Welfare and

Retirement Fund. Coal companies often had

difficulty finding money to finance mechanization. Lewis solved this problem for certain BCOA companies by lending them $17

million from the UMWA-owned National Bank

of Washington and the Fund.

The small operators fought back against the

UMWA-BCOA squeeze. The 1950 contract established a single industrywide wage scale

(thus advantaging the most efficient companies), which was an economic handicap to

small suppliers. Other contractual provisions

devised over the years had the same intent and

effect. Small operators brought a number of

“ Lewis quoted In Thomas Bethell, Conspiracy in Coal,

(Huntington, W Va Appalachian Press, 1971), p. 17

antitrust suits against UMWA and BCOA in the

1960’s. Two succeeded in winning conspiracy

verdicts. I n Tennessee Consolidated Coal Company, the Supreme Court said the “union and

large coal operators, through their National

Wage Agreement and its Protective Wage

Clause, conspired in violation of the Sherman

Antitrust Act to drive small operators out of

business.” 52 Two months later, the Court affirmed a $7.2 million triple damages judgment

awarded to South-East Coal Company against

UMWA and Consol. The Court agreed with

South-East Coal that the two had engaged in a

“conspiracy . . designed to force South-East

and other small coal producers in eastern Kentucky out of the bituminous coal business.” 53

South-East’s brief charged that the BCOA “was

formed specifically to eliminate smaller

operators.” 54

The partnership did little to benefit the

union’s rank and file. Mechanization threw

several hundred thousand miners out of work

and cut many off from medical and pension

benefits. The annual income of those miners

who continued working in the 1950’s and

1960’s did not keep pace with workers in comparable industries such as steel and motor

vehicles. Increasing productivity did not lower

the frequency of mine fatalities among underground and surface miners. Injury frequency

did not improve between 1950 and 1970. Underground mechanization greatly increased

noise and dust levels. Unregulated dust conditions produced black lung disease in thousands of miners by the end of the 1960’s. Finally, the partnership seems to have required the

political disenfranchisement of UMWA’s rank

and file. The terms and consequences of the

partnership probably could not have borne the

scrutiny of democratic unionism. The UMWA

under Arnold Miller reviewed this touchy subject in this manner:

Under W. A.’’ Tony” Boyle, who followed

John L. Lewis and Thomas Kennedy, the

“Tennessee Consolidated Coal Company, 72 L R R M.

2312,1970

5 JSOU th.Eas t Coa / Company v Conso/ida tion Coal COmpany, 75 L.R R.M 2336, 1970.

“’’UMW and Coal Company Sued, ” Coal Age, Jun e

1966, 1) 52.
Ch. IV—Factors Affecting Coal Production and Use ● 133

UMWA leadership grew more and more out-oftouch. Boyle maintained the clamp on dissent

and the close coIlaboration with industry of

the late Lewis years, but in the three contracts

he negotiated he simply could not deliver as

Lewis had done. 5%

But the ordinary coal miner had no way o f

knowing about union loans to operators ,

sweetheart contracts, and other sleights-of -

hand. He could see that Lewis ran the union

autocratically, but so great was his trust in

John L. that demands for rank-and-file contract

ratification or local election of district officers

never elicited much support.

The 1950-70 period is often recalled as an

era of “labor peace” and “labor stability “

True, there were no contract strikes against the

BCOA between 19.50 and 1971 (and comparatively few wildcat strikes), but the peace appears to have benefited BCOA and UMWA at

the expense of small operators and many coal

miners. For non- BCOA companies, market uncertainties and cost pressures —which eliminated 4,779 mines between 1950 and 1973 —

and UMWA organizing campaigns, can hardly

be remembered as a golden age. For many

m i ners, “labor stability” meant unemployment, dust, disease, and fear.

But the UMWA-BCOA partnership did accomplish what it set out to do. Mechanization

and “labor peace” boosted productivity and

helped BCOA companies to ride out the hard

times. Competition was stabilized by eliminating marginal suppliers and through longterm contracts. It was also regulated by a

deliberate, coordinated merger movement that

began in 1954 among the major companies.

When the dust settled, each of the biggest

companies had combined with another major

producer. With both labor and operators stabilized, big producers were able to increase

profits despite a 20-year price freeze and stagnant demand. In 1955, for example, Consolidation Coal and Eastern Associated reported net

profits of $12 million and $2 million, respectively. Profits rose to $20 million and $4

m i I I ion, respective y, in 1960, and to $33

million and $8 mill ion in 1965, The alliance did

55 The Year of the Rank and F//e, p 70

one other thing. It created forces within the

workplace and labor force that led eventually

to the dismantling of the alliance itself. The instability that has characterized the coal industry in the 1970’s is part of the process of ending

the Lewis-Love partnership.

The Rebellion: 1969-77

The rebellion of UMWA miners over the

terms of the alliance was front-page news in

1969. Beginning with health and safety, the

revolt soon expanded to union reform, Fund

policies and collective bargaining. T w o

events — the West Virginia black lung strike

(1969) and the 78-victim Farmington mine

disaster–propelled coal health nd safety

problems directly into the public consciousness. I n the process, the structure of

labor-management relations began to be

u nvei led.

Coal workers’ pneumonoconiosis is a progressive, incurable and, in its last stages, fatal

disease caused by prolonged exposure to coalmine dust. (See chapter Vi. ) Although medical

authorities in England had recognized CWP as

occupationally related in 1942, most American

doctors refused to agree. The UMWA did not

demand or fund extensive research into the

disease in the 1950’s, even though the new continuous miners were increasing dust. The Fund

did, however, try— unsuccessfully — to persuade the American medical establishment

that CWP was a distinctive disease of the

trade. Expensive dust-control programs and

company-paid compensation for respiratory

disability would have undercut efforts to lower

production costs. By the late 1960’s, respiratory disease among working and retired

miners was widespread, Slowly, miners began

to I ink their disabiIity to the dust they “ate” on

the job. For years, coalfield doctors had told

them that coal dust was not harmful, and some

even said it prevented tuberculosis. West Virginia was especially ripe for a black lung protest as 80 percent of its production came from

underground mines and almost one-third of

the Nation’s miners worked there.

Compensation legislation was passed there

in February 1969 after a month-long wildcat
734 ● The Direct Use of Coal

strike that idled 42,000 miners, some of whom

marched on the West Virginia Capitol carrying

coffins. The final version did not incorporate

many of the innovative provisions of the original bill, which the Black Lung Association

(BLA), an ad hoc group of miners and their

allies, had supported.

The West Virginia protest pointed up

UMWA’s apparent lack of concern for occupational health. The BLA became one base in the

political movement by rank-and-file miners

over health and safety conditions, To the BLA

were added hundreds of disabled and retired

workers and their widows who objected to restrictive Fund policies that denied them health

and pension benefits.

Mine safety was thrust into the national

arena when a Consolidation Coal Co. mine at

Farmington, W. Va., blew up in November

1968, killing 78. UMWA president Tony Boyle

appeared at the mine and said: “As long as we

mine coal, there is always this inherent danger but Cononsolidation Coal was one of

the best companies to work with as far as

cooperation and safety are concerned. ” John

Roberts, Consol’s public relations director,

agreed: “This is somethin g we have to live

with. ”

Others did not share their fatalism. The

disaster prompted Joseph Yablonski, a UMWA

official, to challenge Boyle for the presidency.

Strong mine-safety legislation was introduced

in Congress that addressed the safety and

health problems dramatized by Farmington

and the black lung uprising. The UMWA’s complacency toward the disaster had discredited

Boyle and mobilized the reformers.

The Yablonski campaign merged the rebellion over health and safety with growing

dissatisfaction over the absence of union

democracy. Yablonski urged improved health

and safety, democratization, a merit system,

mandatory age-65 retirement for officers, a

better grievance procedure, a higher Fund

royalty, and an end to nepotism, The demand

for union democracy was a reaction to Lewis

and Boyle’s authoritarianism, which had become a prerequisite for maintainin g the alliance, Yablonski lost the election, 80,577 to

46,073, on December 9, 1969, Three weeks

later, he, his wife, and daughter wer e

assassinated by gunmen hired by Boyle and

paid from union funds. Because of “flagrant

and gross” violations of Federal law, the 1969

election was overturned by a Federal judge

and a rerun scheduled for 1972.

During the 1969 Campaign, Federal health

and safety legislation was being hammered out

in Congress. A reasonably strong bill emerged

from the year-long debate. It toughened safety

standards, gave the Interior Department broad

regulatory and enforcement powers, set dust

standards, and provided compensation for

black lung victims. The UMWA opposed the

strongest legislative measures, as did the

operators.

UMWA safety activists and union reformers

were bolstered by rank-a rid-fiIe disenchantment over the contracts Boyle signed in 1968

and 1971. Boyle touted the 1971 agreement as

the $50-a-day package. But the $50 came only

in the last year of the 3-year agreement and applied only to a small number of miners, Boyle

had finally broken the 20-year freeze on the

$0.40-tonnage royalty (raised to $0.80), but

most of the new revenue went to cover the

cost of the pension increase he had contrived

during the 1969 campaign. Other benefits

changed little.

As the dissidents escalated their campaign

against Boyle, some came to understand the

prerequisites of labor peace that Lewis had

worked out with Love. Some began to see

Boyle’s “corruption” more as an exaggerated

consequence of the union-industry partnership

than as a character flaw. This perspective is

reflected in the writings of UMWA officials

and staff following Boyle’s ouster.

The reformers organized themselves into the

Miners for Democracy (MFD) in 1972 and nominated Arnold Miller for president. Miller, a

disabled miner from Cabin Creek, W. Va,, had

worked with the BLA and other reform elements since 1969. He leaned heavily on the advice and skills of a dozen or so young, Iiberal

nonminers to organize the MFD campaign. The

MFD slate defeated the Boyle-led incumbents

handily in December 1972. The reform movement effected many changes in Miller’s first 5-

year term of office. Union programs in safety,
Ch. IV—Factors Affecting Coal Production and Use ● 135

political action, internal communications, lobbying, and research were begun or strengthened. New leadership was placed in the Fund.

District elections were democratized. The rank

and fiIe obtained the right to approve or disapprove negotiated contracts. Organizing—the

lifeblood of any union–was stepped up. Major wage and benefit gains were secured in the

1974 contract. Yet the 1973-77 period was also

one of tremendous rank-and-file unrest. Strikes

and absenteeism increased, As the old partnership between UMWA and BCOA dissolved,

“labor peace” was replaced by “labor instability. ” Miners began demanding the right to

strike (which they had in the late-l940’s and

which Lewis conceded in 1950), Some of the

discontent was focused on Miller’s handling of

UMWA. It came from UMWA liberals who

thought he was not moving fast enough in

many areas and from conservatives or Boyle

stalwarts who disliked the changes he was

making. Strikes and intra-UMWA turmoi l

escalated after the 1974 contact,

1974-78: An Overview of

Labor-Management Relations

The factors discussed above explain the

predisposition of miners and mine management to lock in what Lewis once called “a

deadly embrace. ” But the political and workplace struggles that came to the Appalachian

coal fields in the mid-1 970’s were qualitatively

and quantitatively different from the Lewis-led

contract strikes of the 1930’s and 1940’s. The

growing rebelliousness of UMWA miners culminated in the 31⁄2-month-long contract strike

in the winter of 1977-78. The roots of this confrontation went back to the MFD victory in

December 1972. Freed from what the MFD reformers called “the tragedy and corruption of

the Boyle years,”56 miners found the change in

union leadership stirred their long suppressed

yearnings for more say not only over UMWA

affairs but also over their working conditions

and communities. Democratizing the UMWA

also politicized hundreds of miners and led

them to believe that they could make other

social changes.

But neither UMWA nor the workplace lived

up to these new expectations. Many miners

56 ~~e~ear of the /?Eink and F//e, P 71

were frustrated by what they saw as failures of

the UMWA leaderhip to fulfill its early promises despite the gains of the 1974 contract.

Operators and miners clashed over control of

the workplace when companies failed to adjust to the new demands of their employees.

The conflict over mine health and safety

shifted from the hearing rooms of Washington

to the individual mine face as UMWA and

local mine safety committees pushed for

greater protection.

Management’s struggle with its employees

has been fought over many issues during these

years. Absenteeism and disputes over the

grievance procedure, compulsory overtime,

and job rights repeatedIy disrupted coal production. Miners saw management as trying to

take away job protections that they had won

through the 1974 contract, Federal law, and

local custom. Management saw UMWA job

rights as an impediment to steady output,

Operators believe Federal health and safety

regulations and UMWA work rules enabled

miners to encroach on traditional management

prerogatives. This, coupled with what they

perceive to be increasing Federal regulatory

“harassment,” impedes profitable mining, the

industry says.

The expectations raised by union democracy

were applied by miners to their communities

as well. High hourly wages were hard to reconciIe with the frequently dismal quality of community life in the coal fields. Why, miners

asked, did the roads have to be so bad? Why

wasn’t there decent housing? Why no water

and sewer hookups? Why the poor schools?

Why were the politicians unable or unwilling

to change this situation? The sense of deprivation miners felt in their communities was carried into the pits, where it emerged as hairtriggered combativeness over working conditions.

Wildcat strike activity was relatively constant between 1969 and 1974, accounting for

more than 550,000 worker-days-idle annually.

But, unauthorized work stoppages and lost

time jumped dramatically in 1975-77. Part of

the increase is attributable simply to the fact

that the work force increased 84 percent between 1969 and 1977. A second explanation is
136 ● The Direct Use of Coal

that miners were less afraid to assert themselves now that demand seemed to be expanding, labor was in demand, and wages were rising. A third explanation looks to the broad

range of unmet rising expectations miners developed in the course of union reform, safety

legislation, and political and social changes in

the coal fields. Finally, when other channels of

communication with mine management and

politicians seem to miners to be unproductive,

strikes are used as a way for one, often-unrepresented group to get its message across.

A recent study” of wildcat strikes in Appalachian coal mines found–among other

things — the following:

1.

2.

3.

4

5.

.

6.

Some companies had no strikes in 1976;

others had as many as 17 strikes per mine.

Even within the same company, some

mines have many more strikes than

others.

In a sample of four underground mines, it

was found that miners at low-strike mines

consistently reported better relations with

their section foreman than did miners at

high-strike operations.

Miners at high-strike mines believed it was

necessary for them to strike to get management to talk with them. Many miners

believed striking would help resolve

disputes in their favor. Miners at highstrike mines reported that management

was generally uncooperative with the

union and unwilling to settle a dispute

when the union had a good case.

Ninety percent of the miners believed that

one reason for wildcat strikes was the excessive delay in the grievance procedure.

Arbitrators were distrusted.

Local union officials do not lead strikes.

They are led by rank-and-file miners.

District presidents do not appear to have

the political strength to take any measures against wiIdcat strikes.

The findings suggest that wildcat strikes

are related

dealing with

to management practices in

employee matters.

“Jeanne M Brett and Stephen B. Goldberg, p 23 ff.

7. Many of the problems of the grievance

procedure, which may contribute to

strikes, can be reduced if management

and the union resolve more of their

disputes at the minesite, rather than

through recourse to arbitration.

Wildcat strike activity dropped in 1978. But

it is premature to conclude that coalfield

peace will reign. The effects of the 4-month

contract strike that ended in March left

UMWA miners in debt and anxious to work.

Thousands have been working on-again, offagain because of poor market conditions and a

10-week strike by railroad workers on the N&W

line. Absenteeism declines when the mines are

working short weeks, and rises when 6-day

weeks and lots of overtime are the rule. Further, miners can’t strike if they are not working. A truer indication of the mood of the work

force should develop in 1979 and beyond. It

would be an error to believe that steady

growth in demand for coal will necessarily

lead ro good labor-management relations.

Growth may, in fact, lead to more militant

demands and less concern for cooperating

with management.

1974 UMWA Contract

The 1974 BCOA-UMWA negotiations

place in new historical circumstances.

reform UMWA rejected partnership

took

The

with

BCOA. Demand was growing. Profits had risen

for 4 straight years as a result of price increases and the 1973 OPEC embargo. Net coal

income rose from $128.4 million to $639.5

million — a 398-percent increase — for 24 major

companies, the Bureau of Mines reported.

Many major coal companies had been absorbed by energy companies or conglomerates,

whose greater resources raised UMWA negotiating goals. The union came to the 1974

bargaining table with two basic purposes: 1) to

make up ground lost over the previous 20

years, and 2) to work out new terms for future

labor-management relations.

BCOA conceded an unprecedented wage

and benefit package in 1974. Wages were in-
Ch. IV— Factors Affectlng Coal Production and Use ● 137

creased more than ever before, A cost-of-1iving

escalator and paid sick leave were granted for

the first time. Miners were given the right to

withdraw individuaIIy from conditions any one

of them judged to be an “imminent danger. ”

Paid vacation days were increased significantly, but a two-track pension plan was introduced. Current retirees received a $75 to $100

monthly raise to $225 to $250, depending on

whether they received Fed era I black Iung compensation. But the pensions of miners who retired after 1975 were calculated according to a

sIiding-scale formula based on age at retirement and years of employment Their average

pension was $425 a month UMWA negotiators

believed this was the first step in phasing in a

benefits-accord ing-to-service principle they

thought fairer than the flat payment. Newly

retired miners Iiked their higher benefit levels,

but much bitterness arose among the 80,000

pensioners locked into the lower, flat rate.

BCOA agreed to continue providing firstdollar medical coverage for working and

retired miners and their dependents. Health

care and pensions had been administered by a

single UMWA Welfare and Retirement Fund

until 1974, when it was divided into four

separately funded but jointly administered

trusts. The two “1950” plans provided health

care and pensions to miners who had retired

before 1976 and were financed by a tonnagebased royalty. The 1974 plans were funded on

a tonnage and hours-worked basis. They provided benefits to working miners and new

retirees, Inasmuch as benefits were “tied into

production-related financing formulas, no

benefits were guaranteed. In the event that

future production did not meet the income

estimates used by the 1974 contract negotiators, the Funds would be unable to meet

their obligations.

This happened in the spring of 1977. Although the 1974 contract had increased Funds’

income 62 percent in 2 years, revenues were

still not adequate to continue services to the

more than 800,000 beneficiaries. 5“ Overly opti5H’’Report of the Hedlth and Retirement Committee, ”

Proceedings of the 47tfI Consecutive Constitutlona/ Convention of the United ~Mine Workers of America, Sept 23-

Oct 2, 1976, (United Mine Workers of America) pp 348

ff

mist i c production projections, inflatlon, lack

of adequate cost controls, the inability of the

UMWA to organize new mines, wildcat strikes,

and unexpectedly high growth in the beneficiary population — al I forced the Funds to retrench. Either benefits to miners or payments

to health providers had to be cut The Funds

chose to cut benefits by instituting deductibles, which ended the tradition of first-dollar

coverage established in 1950. Miners had to

pay up to $500 per famiIy for medical services.

The Funds also ended negotiated retainers

with about 50 coalfield clinics i n favor of feefor-service reimbursement This had the effect

of forcing the clinics to cut services Miners

throughout the East stopped work for 10 weeks

to protest these cutbacks. BCOA refused to

refinance the Funds because it felt that wildcat

strikes had caused the cash crisis.59 

BCOA also came to 1974 collective bargaining with a new strategy. The old union-management partnership that had glued the big operators together since 1950 was discarded. The

Lewis-Love alliance might be dead, but the operators hoped major wage and benefit concessions wouId buy labor stabiIity.

The BCOA strategy did not work. The

UMWA leadership was not strengthened by the

BCOA’S concessions in the 1974 contract. In

fact, the plan backfired. If anything, the improvements secured by the union raised the expectations of the membership more than ever.

The contract was ratified by 44,754 to 34,741.

The two-tier pension plan created animosity

and bitterness. The new grievance procedure

did not settle workplace disputes expeditiously. Thousands of cases were appealed to arbitrators. Many cases were not decided for

more than a year. Unauthorized work stoppages continued to increase in 1975 and 1976

despite contract gains. The number of days

lost in wildcat strikes in 1975 and 1976 more

than doubled the 1972-73 experience. Many

miners felt the 1974 contract should have

given them the right to strike over unsettled

“Although wildcat strikes contributed to the cash shortage, a story in the Wall Street journal (Dec. 3, 1977) correctly pointed out that production lost to such strikes

amounted to only 3 percent of projected Income, and

was not the prlnclpal cause ot the Funds’ financial

troubles
138 • The Direct Use of Coal

grievances, a right that Federal court decisions

had eliminated in the early 1970’s. Rather than

solidify Miller’s standing with the UMWA, the

1974 contract divided him from part of his constituency. Miller’s efforts to discipline wildcat

strikers further alienated some of his membership. Some observers see the 1977-78 coal

strike as an extension of the rank-and-file

dissatisfaction that had been building within

the UMWA and against the operators since

1974. UMWA spokesmen, on the other hand,

interpret the turbulence of the 1974-78 period

more as an acting out of newly discovered

strength unleashed by the reform victory than

as a refIection on MilIer’s leadership.

1977-78 Negotiations

BCOA was most concerned in the 1977 negotiations over reasserting management authority over labor at the minesite and curbing wildcat strikes, absenteeism, and certain work

rules. Related to this was the matter of productivity, which had fallen steadily since 1969.

BCOA negotiators abandoned their 1974 hope

that Miller could be transformed into an instrument of labor pacification akin to John L.

Lewis. From that reluctant conclusion, the

operators were

., grasping for something in 1977-78

negotiations. We realized the UMWA international had lost control of their people. We

were grasping for ways to put stabilization

into a contract.60 

BCOA hoped to effect “labor stability”

— a phrase the industry coined — by winning

these specific demands in 1977:

1. the unarbitrable right of the employer to

discharge an employee for alleged striki ng;

2. cash penalties against employees for

unexcused absences and striking;

3. the employer’s unarbitrable right to terminate a new employee during his first 30

days of employment;

4. the employer’s right to set up production

incentives;

‘“Allen Pack, “President of Cannelton Discusses Coal

Issues, ” Charleston Gazette, Apr 12,1978, p 1 C

5. the employer’s right to schedule production or processing work on Sundays;

6. the employer’s right to change shift starting times at his discretion;

7. reduction to 45 days of the 90-day protec8

tion period for new employees (w-ho are

not allowed to operate face machines or

work beyond sight and sound of an experienced employee), and

increased restrictions on the mine safety

committee. 61

BCOA also insisted on restructuring

UMWA’s health and pension system. BCOA demanded that the 1974 health trust (for working

miners) be replaced by private medical insurance arranged through individual operators.

UMWA was to lose its influence over coalfield

medical care by this change. BCOA also insisted that coinsurance be made permanent.

Coinsurance would save BCOA members $70

million to $75 million annually. Fund expenditures would go down as well. BCOA would not

consider equalizing pension levels or significantly increasing benefits. The union did not

demand pension equalization even though the

1976 UMWA Convention resolved that the

union’s “Bargaining Council . . give high

priority in the next national contract negotiations to equalizing pensions.”62

Finally, the operators did not like the idea

that miners felt UMWA was providing their

pensions and medical services. Employee

loyalty was not created by carrying a “UMWA

health card” or receiving a “UMWA pension”

each month. Operators saw no advantage to

them in the Funds’ subsidizing several dozen

clinics that everyone casually referred to as

“the miners’ clinics.” By switching to a strict

fee-for-service system based on operator-arranged insurance, BCOA hoped to save money

and build employee identification.

It is not easy to discern Miller’s 1977

negotiating goals and strategy. Certainly,

UMWA negotiators believed they were in a

‘

]

’’ Memorandum of Summary of Major Improvements

and Changes Contained in the Settlement Between the

United Mine Workers of American and the Bituminous

Coal Operator’s Association, ” Feb 6, 1978.

‘2 Proceedings of the UMWA 47th Constitutional Convention, pp 357-358.
Ch. IV—Factors Affecting Coal Production and Use ● 139

weaker position than in 1974. Miller entered

bargaining after narrowly winning re-election

in June 1977 with 40 percent of those voting in

a three-way race. UMWA lacked a research department and was not well prepared for bargaining. Perhaps the union’s biggest disadvantage was coal’s market situation.

Utilities had doubled their normal stockpiles.

Demand for Appalachian metallurgical coal

was weak. Prices for both steam and met coals

were generally static and, in some cases, falling. BCOA operators and customers could absorb a long strike, particuIarly as the long-term

effects were appraised as outweighing the

short-term losses.

According to newspaper accounts at the

time, Miller had two principal goals: winning

the right to strike at the local level and restoring first-dollar-coverage health benefits. The

UMWA won neither, ultimately. Wildcat

strikes had bedeviled Miller for 3 years, so

skeptics and others surmised that he planned

to trade the right-to-strike for softening of the

BCOA’S “labor stability” package. The right-tostrike was not included in any of the three negotiated agreements. Miller sought the restoration of health benefits to precutback levels

and their full guarantee over the course of the

contract. Apparently, high priority was not

given to opposing deductibles, private insurance plans, and clinic cutbacks.

By contrast, the bargaining priorities outlined by the more than 2,000 delegates to the

UMWA convention in 1976 were clear and aggressive. Most of all, they did not want to lose

any of the ground gained in 1974. That meant

no “labor stability” package, no deductibles,

and no reduction in benefits. The right to strike

had mixed support among the membership.

The convention strongly endorsed it for use in

“local issues threatening the safety, health,

working conditions, job security, and other

fundamental contract rights. ” Convention delegates also endorsed:

1.

2.

3.

4.

rank-and-file participation in the negotiating process;

across-the-board wage increases;

abolition of compuIsory overtime;

more personal and sick leave days;

5. a 1-cent-per-hour increase for every 0.2 increase in the Consumer Price Index;

6. no maximum (cap) to the Cost of Living

7

Adjustment;

seniority based on length of service alone

(rather than on the company-determined

ability to perform the work and seniority);

and

8. modifications of the grievance procedure. 63

Health and safety was another priority. The

delegates called for:

1.

2.

3.

4.

5.

6.

7.

8.

a full-time, company-paid health and safety committeeman at each mine;

a minimum of one UMWA miner trained

as an emergency medical technician on

every operating section on every shift at

each mine;

automatic, continuous dust sampling;

a UMWA miner employed as a full-time

dust weighman “with the authority to enforce dust standards;

strengthened language concerning the

shutdown powers of the mine safety committee;

no arbitration of safety committee decis ions;

tougher language protecting the right of

the individual miner to withdraw from

hazardous conditions;

a 90-day training period for new miners,

and a 30-day time Iimit on arbitrators’

decisions on safety and health disputes.

None of these was included in any of the tentative agreements. Obviously, the union’s negotiators were not expected to win this entire

shopping Iist of convention-endorsed objectives. But the scope and quality of the changes

envisaged by the rank-and-file delegates suggested they expected a feisty, offensive posture from their negotiators in the 1977 talks.

Perhaps the UMWA team lived up to this sentiment in private discussions with the BCOA, but

miners found the contracts presented to them

in February and early March 1978, did not

measure up.

“See “Collective Bargaining Committee Report, ” Proceedings of the 47th Consecutive Convention.
140 ● The Direct Use of Coal

UMWA miners were off the job for 109 days

in the winter of 1977-78. Two months after

their contract expired on December 6, 1977,

the union’s 39-member bargaining council rejected the first tentative agreement Miller and

BCOA had worked out. A month later, miners

rejected a second draft, 2-1. As this occurred,

newspapers were filled with administration

predictions of impending power shortages and

strike-caused unempIoyment of up to 31⁄2

million workers. No power shortages occurred,

and only one State— Indiana — seriously enforced mandatory power cutbacks. The Bureau of Labor Statistics in the Labor Department was reporting to the White House only

25,500 strike-related layoffs at the height of

the strike. ” Still, the administration sought

and received a temporary back-to-work order

under Taft-Hartley procedures invoked on

March 6. The prospect of increased Federal intervention in their affairs brought the two sides

together, and they hammered together a third

agreement. By that time, the Federal judge

who had issued the temporary Taft-Hartley

order refused to extend it on the grounds that

the administration had never proved the existence of a national emergency. On March 24,

56 percent of those miners voting accepted the

contract. The third contract softened some of

the BCOA’S demands embodied in the earlier

drafts. But it fell short of rank-and-file objectives in many areas. Why did miners accept it?

First, many were beginning to suffer economic hardship. The union had no national

strike fund, and the lengthy wildcat strikes of

1977 had cut into miners’ savings just months

before expiration of the 1974 contract. By midMarch there was an inverse relationship between a miner’s militance and the number of

mouths he or she had to feed. The contract

represented income.

Second, there was widespread distress about

health and pension benefits. As the strike wore

on, fears increased that the entire pension pro-

“The administration’s spurious estimates of unemployment and power shortages were examined by the General

Accounting Office in a report to Cong John Dingell, entitled, “improved Energy Contingency Planning is

Needed to Manage Future Energy Shortages More Effectively, ” Oct 10, 1978

gram might collapse. (Benefits had been suspended at the outset of the strike. )

Third, miners were increasingly vocal in expressing their lack of confidence in their own

negotiators. Summarized, their argument

seemed to be: “We can stop the operators

from taking away what we won before, but we

can’t make our negotiators get what we want. ”

This belief led to a sense of fatalism about

what could be accomplished by continued

striking.

Fourth, the ratification process itself

weighed in favor of getting a settlement sooner

rather than later. Miners understood that ratification involved at least 10 days. Rejection of

the third contract would mean more delay

before negotiations resumed, and then further

delay before new terms were agreed on.

All of these factors affected the ratification

vote. It is important to understand that in

casting his ballot a miner was not necessarily

taking the final step in a rational process of

assessing the objective advantages and disadvantages of the contract he had been asked to

consider.

What explains the protracted inability of the

negotiators to agree to a contract that the

miners would accept? One answer lies in the

ability of each side to endure a long shutdown

and the expectation that by doing so the final

offer could be a net improvement over any

earlier terms. A second is BCOA’S demand for

unprecedented changes in the status quo. The

magnitude of these changes, together with the

barely disguised threat to resort to companyby-company bargaining, was perceived by

miners as an all-out attack on their way of life,

its culture, and its protections, Third, the

perceived cleavage between Miller and his

membership encouraged BCOA to demand

drastic contract revisions. Had the union side

been united, the operators might have compromised sooner. Fourth, had BCOA not insisted

on “labor stability” penalties, it is arguable

that miners might have accepted BCOA’s other

demands more quickly as part of a package.

However, miners felt the BCOA’s stability

demands were a reassertion of the operator’s

wish to do as they pleased with their employees, The stalemate came to focus on the
Ch. IV—Factors Affecting Coal Production and Use . 141

Photo credit: Douglas Yarrow

UMWA coal miners protesting changes in medical benefits in Washington, D. C., during a month-long wildcat strike that

shutdown most Appalachian production, 1977

shared perception that “rights” were at stake:

the employee’s right to job protection, safety,

and security; and the operator’s right to manage his business according to his best judgment. When each side perceives that its rights

are challenged, wars of attrition are common.

Fifth, it appears that because of poor market

conditions, metallurgical coal producers and

some other eastern operators were not terribly

hurt by a long strike. Had there been no strike,

hundreds of mines would have shut down or

laid off workers because of excessive utility

stockpiles, static prices, and soft markets.

BCOA was not pleased with the final version, although it had won major changes in the

1974 contract. Miners saw the final product as

less punitive than earlier drafts but not as good

as the 1974 agreement in many respects, particuIarly with respect to heaIth benefits.

The 1978 Contract Terms

Discipline

The harsh language of the first two drafts

concerning management’s right to fine and discipline wildcat strikers was deleted. I n its

place, however, is a memorandum of understanding that continues decisions made by the

Arbitration Review Board (AR B). The ARB decision decided in October 1977, gives employers the right to discharge or selectively

discipline employees who advocate, promote,

or participate in a wildcat strike. ARB 108 is
142 • The Direct Use Of Coal

less punitive than the proposed “labor stability” provisions as employees can appeal

grievances through arbitration.

No significant work stoppages have occurred since the 1978 contract went into effect. Some mines report less absenteeism. Are

these short-term phenomena, or are they

trends that are likely to continue and if so, to

what extent are they traceable to the provisions of the new contract?

The second question is the easier. The recent

decrease in work stoppages and absenteeism

probably cannot be credited solely to the new

contract because, with one exception, no new

terms bear directly on this issue. The sole exception occurs in the article governing settlement of disputes — the grievance procedure. A

small but significant change was written into

the first step. A section foremen now has the

authority to settle a complaint at the minesite

within 24 hours. His decision no longer sets any

precedents in the handling of other grievances.

Formerly, mine management delayed conceding a point in one matter for fear that it

would be binding for the duration of the contract. Although individual miners seem to be

getting grievances settled faster than before,

redundant disputes over the same points may

be occurring. A spot check of different

districts in June 1978 produced no definitive

information about dispute frequency but did

confirm that foremen had more latitude on

grievance handling. The officers of the union’s

largest and most strike-prone district (District

17 in southern West Virginia) reported then a

very sharp drop in the number of grievances

being referred to union representatives. The

layoffs and short weeks that idled thousands

of miners in Appalachia in the past year probably discourage grievances being filed and

wildcat strikes from happening. If demand

perks up in these areas, grievances may rise

proportionately.

Whether the reduction in wildcat strikes is a

short-term phenomenon is a much more difficult question. Miners are still recovering from

a strike that lasted much longer than expected.

They have been concerned with retiring large

debts and replacing whatever savings they had

built up. Like other Americans, they have also

been troubled by continuing inflation. Perhaps

the best explanation, again, is simply that

miners can’t strike if they don’t work. Almost

20,000 Appalachian miners were laid off in the

summer of 1978 because of soft metallurgicalcoal markets, productivity-boosting plans, and

the strike against the N&W railroad. About half

that number were working irregularly in the

winter of 1978-79. On the other side, many of

BCOA’s larger members appear to have made

a special effort to resolve grievances as

promptly as possible. Some claim that because

of the new clause, more grievances are being

resolved in the miner’s favor. I n any case, experience with the 1978 contract is insufficient

to permit drawing many meaningful conclusions about whether it will lead to a sustained

reduction in the number and frequency of

wildcat strikes and absenteeism.

In the long run, wildcat strikes and absenteeism are unlikely to be brought under

lasting control until the union’s internal situation stabilizes and the industry adopts a more

generally enlightened attitude toward labor

relations. It is too soon to know whether either

wilI occur.

Productivity Incentive Plans

The UMWA had traditionally opposed plans

to increase production by offering cas h

bonuses for tonnage over a stated quota. The

union argued against bonus plans on two

grounds. First, if bonus plans succeeded in

significantly increasing a worker’s real spendable income, the union would find negotiation

increasingly difficult for substantial acrossthe-board wage gains. The union feared that

wages would be shifted from an hourly basis to

piece rates, which is considered regressive.

Second, UMWA argued that bonus systems encourage risky short-cuts, lack of proper equipment maintenance, and speed up— all leading

to more accidents and disease. BCOA made incentive systems a central demand in its

negotiating. The post-1 969 decline in productivity might be turned around, the operators

thought, if cash bonus plans were adopted.

UMWA agreed to this change.

The new contract language provides for a

majority vote (among those miners voting)

before an operator can adopt a bonus plan.
Ch. IV—Factors Affecting Coal Production and Use ● 143

Once accepted, it cannot be rescinded by the

employees. Each plan would provide monetary

incentives for production or productivity increases. (The contract language does not specify what the cash bonus is pegged to). One of

the conditions of the plan is that it “does not

lessen safety standards as established by applicable law and regulations. ” Some operators

and some miners may not interpret safety

“standards” as being the same as safety performance (that is, fatality and injury rates and

numbers). I t is possible that accident frequency could rise, but so long as management

standards or number of injuries did not

change, the bonus system would not be

voided. Nothing is included about health

standards or experience. The cash bonus

system will be popular with many miners, but

its adverse impact on workplace health and

safety may be significant.

Operators have adopted two different approaches to increasing productivity in recent

months. Consolidation Coal has won acceptance at four mines of plans that tie the level of

the cash bonus to increased tonnage and number of injuries. It is too early to tell if this approach will raise output without compromising

safety. Some union officials are worried that

both miners and operators will fail to report injuries in order to preserve the cash bonuses. A

second approach taken by another operator

seeks to raise productivity by eliminating nearly 2,100 jobs, representing about one-sixth of

its work force in West Virginia. A company

spokesman said that reduction was not

prompted by poor market conditions; rather

“ it’s strictly to improve productivity. ” This

company hopes to maintain the same level of

output after the layoffs, thus increasing productility. ”

Aggregate productivity statistics over the

next 2 to 3 years will tell relatively little about

the effects, if any, of the new incentive clause.

Meaningful evaluation will require close monitorin g of individual mines where incentive

plans are put into effect to determine relationships between these plans and changes in productivity, accident frequency, and dust levels,

‘5Coa/ /ndustry News, Sept 18, 1978

Health Care

The most dramatic change in the 1974 contract involved the refinancing and control of

UMWA’s health plan. Under the 1978 agreement, all working miners and recent retirees

shifted to company-specific, private insurance

plans. A Funds medical plan will exist for

pre-1976 retirees only. Coinsurance— up to

$200 per year per family–was instituted. All

services, including those provided by the clinics, wiII be reimbursed on a fee-for-service

basis. Health benefits are supposedly guaranteed, but uncertainty remains in some areas

about what these guarantees mean in practice.

The imposition of deductibles for working

miners and retirees ends first-dollar coverage,

which had been the rule since 1950. Because

they apply only to physician care and medication, some health analysts believe miners will

be discouraged from buying preventive physician care. The experience of other medical systems—the Stanford University Group Health

plan and the Saskatchewan plan — suggests

that the introduction of coinsurance reduces

demand for physician services. ” The entire

health-benefits package is now seen by many

miners as having been seriously compromised.

They were widely dissatisfied with the administration of the Funds, and the current situation is commonly perceived as substantially

worse. Strikes over the insurance reimbursement issue have been narrowly averted several

times over the last year. The dismantling of the

Funds is also an emotional issue that is unlikely to dissipate during the term of the 1978

agreement. For management and union leadership alike, it will remain a difficult problem.

Strikes over coalfield health care are likely.

Occupational Health and Safety

None of UMWA’s occupational health and

safety demands survived the bargaining. The

1974 language continues in force, At each

UMWA mine, a health and safety committee is

elected (generally three miners), Committee

members are entitled to special training. They

have the right to close sections of the mine

“Anne A Scltovsky and Nelda McCall, “CoInsurance

and Demand for Physician Services. Four Years Later, ”

Socla/ Secur~ty f?u//efln, May 1977
144 ● The Direct Use of Coal

when they find conditions of “imminent danger,” If their employer challenges their judgment, Federal or State inspectors may be

called in to settle the question, or the issue

may be taken through arbitration. The committee’s action can be reversed only after the fact.

This provision, stronger than most labor agreements, dates back to 1946, when John L. Lewis

won it when the mines were under Federal control. If an arbitrator upholds an employer’s accusation that a committee member acted “arbitrarily and capriciously, ” the miner may be

removed from the committee but cannot be

fired or otherwise disciplined for his official

actions.

These provisions contrast starkly with those

generalIy in effect at non-UMWA mines, where

the safety committee, if one exists at all, is

often reluctant to enforce standards for fear of

jeopardizing its members’ jobs.

Workplace Relations

The basic issues that created friction under

previous agreements were not resolved and

can be expected to cause difficulties in the

future.

For example, management retains the right

to operate mines 6 days a week (a BCOA proposal to permit operation 7 days a week

failed). The compulsory sixth shift is a primary

source of discontent among miners at operations where the 6-day week is scheduled. Compulsory shift rotation is another source of

widespread discontent. Wildcat strikes have

erupted over it. Some miners believe management routinely awards preferred jobs on the

basis of favoritism, and that the contract

language does not protect a miner’s right to be

awarded a job on the basis of seniority and

ability to perform the work. Some of these conflicts might be resolved if each side were willing to meet and work out a compromise. It is

still too early to telI whether this will happen

u rider the 1978 agreement.

Education and Training

Education and training have been foreign

concepts in the coal industry through much of

its history. Both are inextricably tied to improving workplace relations. The significance

of the changes that have taken place in the industry’s work force over the past decade are

difficult to exaggerate. The industry Iaid off 70

percent of its work force between 1950 and

1970, then turned around and began hiring

again in record numbers when demand picked

up Today, most miners are in their 20’s and

30’s The supervisory work force is also overwhelmingly young. In some mines, informal

alliances between young foremen and young

miners have reportedly occurred in response to

perceived intransigence by upper management. Low-level supervisory skills are no longer

sufficient, Most industry spokesmen acknowledge the shortage of experienced mine

foremen who are able to maintain good rapport with hourly employees. Some companies

are trying to upgrade supervisory skills; others

hope to get by with what they have. The likely

safety and production payoffs of more

capable foremen cannot be understated.

The 1978 contract provides for employer-developed orientation programs of not less than

4 days for inexperienced miners and not less

than 1 day for experienced workers. The contract specifies that each program should emphasize health and safety. The trainee period — during which a new miner cannot operate mobile equipment or work beyond sight

and sound of another miner — was cut from 90

to 45 days.

Education and training for miners can take

many forms. A sample list of priority objectives might include:

●

●

●

●

Machine-specific training beyond basic

requirements of State and Federal law.

Training in dispute settlement directed at

both supervisors and members of the

UMWA Mine Committee.

Training for the Health and Safety Committee to familiarize them with occupational health and safety hazards and

Government regulations.

Interchangeable skills for work crews

within the mine. The benefits from such

training are obvious. Safe working habits

are encouraged. The impact of absenteeism is blunted when a miner can step into
Ch. IV—Factors Affecting Coal Production and Use . 145

the job of an absent worker without exposing himself and other crew members to

hazards arising from unfamiliarity with a

machine or work procedure. Recent Federal regulations on miner training are a

step in this direction, but critics argue that

they are inadequate in many respects.

Wages

Most miners approved the wage package.

Unadjusted standard wage rates rose from

1977’s $55.68 per day for the top-paid miner to

$74.32 per day in the first year. The lowest paid

underground miner went from $50.38 to $64.78

per day in the first year. The gap between lowest- and highest-paid miners is $8.64 per day, as

it was in the previous contract.

The 1974 agreement initiated a capped costof-living escalator pegged to increases in the

Consumer Price Index. In the final adjustment

period (November 1977), the maximum inflation adjustment was $0.98 per hour. The new

contract includes no inflation adjustment

mechanism in the first year, and a $0.30 maximum per hour raise in the second and third

years. Although the 3-year, hourly wage increase amounts to about 30 percent, the increase in real income is likely to be closer to 3

percent after inflation, deductibles, and higher

tax payments are taken into account.

Union-Industry Relations

In the last round of negotiations, some coal

operators were encouraged by the Carter administration to break from the BCOA bargaining structure and conclude contracts with

UMWA miners on a company or geographical

basis. Proponents of this innovation argue that

decentralization would reduce the impact of

contract strikes because no common contractual expiration date would exist. Some also believe that the more profitable companies

could buy “labor stability” through comparatively “fat” packages, leaving less-profitable

companies to settle as best they can. Many

newer companies — as welI as some miners —

feel the pension obligations of older BCOA

companies limit the size of wage gains that

can be negotiated. The other side of the

debate argues that regional or company-specific bargaining will create more problems

than it promises to solve. They point out that

this kind of bargaining historically has destablized this industry. The signing of a

number of agreements (each of which embodies a different set of wages and benefits)

would create strike conditions because of the

differences. It is improbable that miners at one

mine wiII work very long for less than miners at

an adjacent mine. It is also likely that miners

who strike when their contract expires will

“picket out” other mines in order to increase

economic pressure on their employer. This

chain reaction could go on indefinitely as staggered expiration dates are reached. It is debatable whether decentralization would produce

a net reduction in time lost to strikes. Had the

31A -month strike actually imperiled the country, solid ground would have been established

for a radical restructuring of the UMWA-BCOA

structure. But as a national emergency never

existed — and is even less likely to in the

future– it does not appear to be imperative to

change the status quo.

Community Development

Community development problems are beyond the scope of the collective bargaining

process, but they must be addressed more effectively over the term of the 1978 agreement

or the basic unrest that has characterized coalfield life will not abate. The most significant

difference in strike activity in the 1970’s from

earlier periods was that the former sometimes

was triggered by nonworkplace social and economic conditions, such as a gasoline rationing

plan in West Virginia, controversial school

textbooks, unsafe coal-waste impoundments,

Federal court decisions, pending Federal black

lung legislation, and cutbacks in health benefits. Before the 1970’s, strikes were rarely

caused by matters other than those arising

over working conditions or contract terms. Recent field studies suggest that inadequate,

unstable living conditions contribute to absenteeism, wildcat strikes, and lower productivity. The President’s Commission on Coal,

which began its investigation in September

1978, is exploring the relationship between living conditions and work relations, as well as
146 ● The Direct Use of Coal

possible strategies for improving the quality of

coal field life.

Non-UMWA Labor

Roughly 30 percent of 1977’s 230,000 coal

workers did not belong to UMWA. Some belong to other unions, such as the International

Operating Engineers or PMU. The rest belong

to company-approved associations or to no

labor organization at all. In the East, most nonUMWA labor is found in small, mostly nonunion mines in eastern Kentucky, Virginia, and

Tennessee. PMU is based in Illinois. In the

West, miners generally are either unorganized

or non-UMWA. With a few exceptions, UMWA

mines there are underground operations.

Still, UMWA exerts a good deal of indirect

influence over non-UMWA operations. In the

1977-78 strike, much non-UMWA production in

the East was shut down, too. Wages and benefits in non-UMWA mines are often pegged to

UMWA rates. Non-UMWA operators will often

offer higher wages than the UMWA scale in

order to keep UMWA from organizing its

miners, Three UMWA contract provisions appear most objectionable to non-UMWA operators: job security protections, safety and

health rights, and benefits for retired miners. If .

UMWA succeeds in upgrading its western surface-mine agreements to prevailing nonUMWA standards, it will probably have better

organizing success among western surface

miners as nonwage issues take on increasing

importance.

Conclusion

The 1977-78 shutdown was one episode in a

long-running coalfield drama; it was not the

final act. Labor peace is not unreasonable for a

coal operator to expect, but it is unlikely to be

achieved by the approach adopted by BCOA

in the recent talks. Too much bitter history and

too many contemporary conflicts exist to

enable threats and penalties to promote

stability, let alone peace. Any long-term approach requires recognition that many of the

problems have become embedded in the

American system of coal mining— its production process, work relations, work environment, communities, and culture. Changing the

consequences of this system — absenteeism,

strikes, distrust, arbitrariness — means changing the components of the system that produce

confIict.

REGULATORY RESTRICTIONS ON MINING

Federally mandated permits and operating

methods have become significant factors for

the mining industry. The principal requirements arise under the Surface Mining Control

and Reclamation Act (SMCRA), the Mine Safety and Health Act, and the Clean Water Act.

These are discussed in detail in chapter VII.

This section addresses the ways these regulations affect mine operators as well as their

potential to affect the supply of coal. The major areas of concern are the increased Ieadtime

required to open a new mine, increased capital

and operating expenses, the designation of certain areas as unsuitable for mining, and a sense

of “harassment” within the industry.

A longer Ieadtime for opening new mines

could result from the need for additional planning, design work, and permits to comply with

Federal regulations. Permits are required under

SMCRA, the Clean Water Act, and the Resource Conservation and Recovery Act (RCRA).

SMCRA mandates State permit systems in accordance with Federal guidelines that include

comprehensive performance standards for surface mining operations and for the surface effects of underground mining. These standards

are intended to prevent adverse environmental

impacts such as ground and surface water contamination, degradation of land quality, and

subsidence. Mine operators must demonstrate,

as a prerequisite to obtaining a mining permit,

that the land can be restored to a postmining

land use equal to or greater than the premining

use. The Clean Water Act and RCRA also mandate State permit systems in accordance with

Federal guidelines. Under the Clean Water Act,
Ch. /V—Factors Affectlng Coal Production and Use ● 147

Federal effluent limitations designed to

achieve national water quality goals apply to

all active mining areas (surface and deep) including secondary recovery facilities and preparation plants. Solid waste disposal standards

under RCRA are designed to control open

dumping; substantial constraints could be imposed on the disposal of mine wastes if they

were declared to be hazardous. Additional

design restrictions may be imposed by the requirements of the Mine Safety and Health Act.

In addition, the planning stage for leases involving federalIy owned coal or for mines on

Federal lands may include the preparation of

an environmental impact statement under the

National Environmental Policy Act (NE PA) or

the Federal leasing program.

Before the implementation of these environmental and health and safety regulations,

a mine could be opened in Iittle more time

than that required to conduct geologic surveys, assemble the tract, order equipment, and

prepare the site, This process typically might

have required 5 years. However, permitting

and review and other mandated planning have

added significantly to this Ieadtime. Coal

operators now estimate that the opening of

some new mines couId require 8 to 16 years

from initial exploration to full production,

depending on the characteristics of the mine

site and the resources of the mining company

(see figure 16). However, if many of the required activities proceed simultaneously, and

if full compliance with applicable legislation is

achieved at the outset, the Ieadtime shouId not

be increased substantially.

However, if greatly increased Ieadtimes

become the norm, they could constrain coal

supplies for the high-growth scenario by the

late 1980’s, when a rapidly expanding coal industry would need new mines not yet in the

planning stage. Supplies should be more than

adequate for all scenarios until then. In addition, substantial delays in the opening of new

mines could alter the structure of the industry.

Because utilities will not contract for coal not

needed for many years, coal mine planning

would have to begin without an identified

market. Larger mining companies can maintain

fully permitted nonoperating mines for potential customers, but smaller companies could

lose their historic ease of access into the

market because the planning and permitting

costs would be incurred so far in advance of a

return. The flexibility of coal supplies also

could be reduced greatly because only those

mines that are welI into the planning stage

couId be considered viable suppliers.

Increased capital and operating expenses

for surface mines would result primarily from

reclamation and other environmental protection requirements For underground mines

both environmental and occupational health

and safety requirements increase production

costs. Before passage of SMCRA, surface mine

reclamation costs averaged $3,000 to $5,000

per acre. Depending on seam thickness, this

cost translates to a range of about $0.20 to

$1.00 per ton. Industry estimates of the increased costs attributable to SMCRA vary

widely, depending on the characteristics of the

site.

Any cost increases probably will not limit

the industry’s ability to supply coal, but they

will make coal more expensive and could force

small, capital-short companies out of business.

In addition, coal operators could have difficulty obtaining reclamation bonds for areas that

are difficult to reclaim because of the stringent, detailed SMCRA requirements for these

sites. Federal programs are available to help

small companies meet these increased costs,

but it is unclear whether they will be adequate.

A third concern raised by regulatory restrictions is the designation of areas as unsuitable

for mining. Except for valid existing rights,

SMCRA prohibits surface mining on Federal

lands valuable for recreation or other purposes

(such as national parks, wildlife refuges, wilderness areas, wild and scenic rivers) and on

much of the national forest lands. I n addition,

SMCRA requires the States to institute planning processes for designating areas unsuitable

for all or certain types of surface mining. These

include areas where reclamation wouId not be

technologically or economically feasible;

where mining wouId be incompatible with existing land use plans; where it would adversely

affect important historic, cuItural, scientific,

and aesthetic values; where it would result in
Figure 16. —Permitting Network for Surface Mines

+

P,,+.re & S.bn,, San,twy La.dl!ll 4PPllCat10n Supply Aad,!,orw 1.16 As Requested

S.PPIY Addmonal Inlo

Wcmo. Made to Issue D,an P.xnw

Process 404 Ac@,caI,on

Announce P.t),c Process

Fed EIS

Fed R R RW ~wm~ E,R

2

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1

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2 Pr.3Pa,e & Subm,l Aw8cal,o. 10 Co.s!ruc!

Mcxj,ty or OWate A,, PoI1uI,on %.,.,

2

I

I

I

I

Preliminary Work

Phase 1, 11, Ill, Exploration Permit

Coal Analysis

Resolution Surface Control

Engineering/Marketing

Studies K

112.5 Mo.

Permitting

46 h40.

=7

Construct ion Build Up To

Training Production

Budget Approval

/

r

a

46 Mo.

18 Mo. 24 Mo.

.-i
Ch. IV—Factors Affecting Coal Product/on and Use • 149

substantial loss or reduction in long-range productivity of water supplies or food or fiber

products; or where it would endanger Iife or

property in areas subject to flooding or unstable geology. Until these State planning

processes have been established, it is not clear

to what extent they could Iimit coal supplies.

The final factor related to Government regulations is the sense of “harassment” en -

gendered within the industry by Federal regulation of what historically had been the industry’s prerogatives. This hostility can result

from the concerns discussed above (delays in

mine openings, increased costs) or from interference in mining practices by Federal inspectors, and it can occur among mine operators as

welI as between operators and miners or the

public. Mine operators may perceive frequent

inspections as harassment, especially if the

operators feel that they are making a reasonable effort to comply with the regulations

or that the reguIations are counterproductive.

For example, mine health and safety inspectors

may be seen by management as allied with

labor or by labor as cohorts of management,

resulting in increased tension between these

groups. Similarly, SMCRA inspectors may be

perceived by mine operators as allied with the

“environmentalists ” and vice versa. On the

other hand, all three groups — mine operators,

miners, and environmentalists — may feel that

the inspectors are incompetent and do not protect any interests adequately.

An additional source of hostility within the

industry is the automatic citation provision of

the Mine Safety and Health Act, which requires an inspector to cite every violation regardless of its severity or its potential for immediate correction. Automatic citations and

civil penalties are intended to deter noncompliance. However, as with frequent inspections, they may be perceived as harassment by

operators who feel they are making a goodfaith effort to comply with regulations. On the

other hand, miners claim, that Federal inspectors do not always issue the automatic citations because their experience tells them that

the specific circumstances do not warrant it.

Probably most inspectors use judgment in issuing citations; some are too lenient, others are

too literal.

PRODUCTIVITY

Productivity is a measure of the efficiency

of an industrial process. It expresses a relationship between a unit of output and the effort

that goes into it. In coal mining, productivity is

expressed as tonnage mined per worker per

shift.

Production is not the same as productivity.

Production refers to total output or tonnage; it

says nothing about the efficiency of a coal

mine or industry. The two concepts are related.

Coal production can rise through increasing

productivity; that is, by more efficiently using

labor, capital, management, technology, and

raw resources. But output will also increase

without any improvement in productivity

when more units of production are employed.

Increasingly productive companies usually reflect an ever more efficient use of economic

resources. When a company is able to raise its

productivity, it should be able to lower its production costs, better compensate its labor, sell

more cheaply, and show a better return on investment. Although it is often imperative for

an individual company to raise its productivity

each year, that imperative may be much less

strong for the industry as a whole. Where supply (and capacity to produce) exceeds demand

as it does in the coal industry, higher productivity leading to more output may hurt coal

suppliers who already have more coal than

they can sell.

Mining productivity–output per worker

shift—expresses efficiency in terms of labor

productivity. Coal (labor) productivity is calculated by dividing total tonnage mined by the

number of employees. This formula can be

misleading. Actually, productivity reflects the

efficiency of how many factors work together
750 ● The Direct Use of Coal

to produce a ton of coal. When coal mining

was a labor-intensive industry and labor costs

accounted for as much as 70 percent of total

production costs, this way of measuring efficiency made sense. Then, each miner was paid

on a piecework basis — so many cents per ton

mined — and mining systems required many

workers, Iittle capital, and simple tools. Today,

coal mining— both surface and underground

systems— is capital intensive, and productivity

rises or falls according to how many variables

interact, labor being only one. A more useful

indicator of mining productivity today might

be derived by measuring capital efficiency (in

constant dollars), mining system efficiency, individual machine efficiency, or total-factor ef -

ficiency.

The decline in coal productivity since 1969

has received much attention. That decline has

been dramatized because it reversed a steeply

rising productivity curve that had characterized the industry since 1950. I n that year, productivity was calculated at 6.77 tons per

worker shift compared with 19.9 tons in 1969.

Productivity almost tripled over that 20-year

period. But annual production never matched

the 1950-51 level until the late-l 960’s. Rising

productivity did not result in increased production. (In fact, more bituminous and anthracite coal was mined in 1920— 655.5 million

tons—at a productivity level of 4 tons per

worker shift than was mined in 1975 —654.6

miIIion tons — at 13‘A tons per worker shift. )

Productivity improvement in the 1950’s and

1960’s did, however, allow the biggest coal

companies to survive a protracted demand

slump. The spectacular rise of coal productivity in these years was the result of mechanization of underground mining, increased surface

mining, the absence of environmental controls

on surface mining, and inadequate mine safety

standards. Productivity improved statistically

because 70 percent fewer miners were working

in 1969 as were in 1950 while production increased slightly. As the numerator (tonnage) remained relatively constant in these two

decades, the denominator (workers) dropped”

steadily, resulting in ever higher productivity.

In the 1970’s, production went up, but e m -

ployment rose at an even faster rate. Consequently, productivity declined. Underground

productivity fell from 15.6 tons per worker

shift in 1969 to 8.7 tons in 1977. Surface mining

productivity dropped from 35.7 tons to about

26 tons. Production rose from about 560

miIion tons in 1969 to about 688 milIion tons

in 1977, a 23-percent gain. But employment increased 84 percent from 125,000 in 1969 to

almost 230,000 in 1977.

Industrywide productivity data must be

used with caution because of numerous inconsistencies and uncertainties in the numerator

(tonnage) and denominator (workers) of the

productivity formula.

Tonnage, for example, is reported differently by different companies—and even within

the same company. Productivity is affected by

whether operators report tonnage “as sold” or

“as mined. ” The latter represents raw coal as it

comes directly from the mine face. The former

represents both raw coal (sold as is) and

cleaned coal. Productivity falls in proportion

to the amount of cleaned coal reported because wastage (which has been increasing—

see chapter 11) is subtracted from “as mined”

output. Because tonnage data include different definitions of output, productivity

statistics may not be measuring efficiency in

the same way.

The data also do not distinguish between

steam and metallurgical coals. Met coal and

steam coal prices were about the same in the

1960’s, but met prices have been roughly double steam prices in the 1970’s. High prices

enabled inefficient met coal mines to operate

profitably. The effect of high met prices has

been to lower industrywide productivity.

Another data weakness involves the concept

of tonnage itself. Coals differ in quality, and

tonnage simply measures weight. If, for example, the numerator in the productivity formula

were Btu instead of tonnage, underground and

eastern productivity would rise relative to surface mine and western productivity.

The raw data may also be misleading because coal companies count their workers differently. Some count only hourly employees;

others include office workers. Obviously, the

larger the denominator (workers), the lower the
Ch. IV—Factors Affecting Coal Production and Use ● 151

productivity rate. Another weakness involves

the definition of a working shift. Actual shift

times range from 7‘A hours to as much as 12

hours, Generally, surface miners work more

overtime than underground miners. The typical surface shift may be longer than the

average underground shift. in this fashion,

long-shift mines would show higher productivity than short-shift operations, other things being equal. This wouId tend to show surfacemine productivity higher and underground productivity lower on an aggregate basis,

perhaps the single most serious flaw in the

data is that they often grossly combine the performance of vastly different mining systems.

Coal mines range from huge investments producing 10 to 15 million tons annually to tiny

“dogholes” punched into a hillside, producing

1,000 tons or less. Shovel size runs from 130

yd’ down to a No. 4 hand shovel. Coal is

moved by 650 hp jumbo trucks as well as one

pony-power railcars. The industry is made up

of very different parts, and in analyzing productivity the differences may be more relevant

than the simiIarities.

The most obvious distinction is between surface and underground mining. Surface mines

are roughly three times as productive as deep

mines. The productivity advantage of surface

mining is inherent in its extraction technology

and geologic conditions, As more and more

surface-mined production comes from the tremendously efficient open-pit mines in the

West, surface mining productivity should rise

and to a lesser extent, industrywide productivity as well. Although OTA estimates that the

60/40 ratio of strip to deep production is not

likely to change over the next 20 years, industrywide productivity would rise considerably if

this ratio does increase (as it has since 1950).

Even within similar mining systems, variations in productivity occur according to seam

thickness and accessibility, mining techniques,

and equipment size, among other factors. Underground productivity rates range from 31A

tons from a thin-seam in southern West Virginia to 30 tons or more in a thick-seam. Similarly, surface productivity ranges from about

20 tons in east Kentucky to 100 tons or more in

Wyoming,

A second crucial distinction needs to be

drawn between new mines and old mines. The

productivity of new underground mines averaged about 18 tons per shift compared with 11

tons for existing deep mines in 1974. 67 Similarly, new strip mines averaged about 70 tons per

worker shift — and in some Western operations

approached 150 tons— compared with about

36 tons for existing surface mines. 68 lndustrywide productivity will increase as new

mines replace old mines.

To be analytically useful, productivity data

must compare Iike things — mining systems,

machines, geologic conditions, etc. Mine-bymine data that include all the variables involved in productivity are needed. The absence of such data impedes sound policy making.

The productivity decline since 1969 must be

seen in Iight of these data problems; the

unique factors causing the productivity increase between 1950 and 1970, and the equally

unique factors causing the uneven gains in tonnage and employment since 1970.

The rise in productivity in the 1950-69 period

was the result of a combination of conditions

that are unlikely to be repeated. Significant advances in underground and surface mining

technology maintained output levels while

sharply reducing labor needs, (Indeed, the

labor cost per ton of coal dropped from 58.5

percent of value in 1950 to 38.3 percent in

1969. ’9 Further, the environmental and safety

costs of mining were not well regulated by

State or Federal law, Productivity rose but at a

social cost. The combination of shrinking demand for labor and the cooperative arrangements between UMWA and BCOA kept strike

activity to a minimum. Finally, poor market

conditions in the 1950’s and 1960’s weeded out

several thousand small, inefficient mines, thus

boosting industrywide productivity, Unemployment, black lung, environmental damage,

and accidents were the hidden costs of rising

product ivity.

“Coa/ TasL Force Report for Project /ndependence(U S

Department of the Interior, November 1974), p 29

’“1 bld

“Joe Baker, “Coal Mine Labor Productivity, ” p 8
152 • The Direct Use of Coal

What happened after 1969 to reduce productivity? The explanation for the decline cannot be pinned to a single cause. A number of

demographic, economic, and regulatory developments contributed.

First, innovations in mining technology

topped out both in reducing labor and in

expanding output. Continuous-miner technology has not changed significantly since 1969

and, by that year, almost 96 percent of underground output was mechanically loaded. The

onIy productivity enhancing change in

underground mining has been the introduction

of Iongwall systems, 70 which mined about 4

percent of all underground coal in 1977.

Although surface mining expanded its share of

national production, its technology has not

changed significantly in scale or concept.

Second, as coal prices rose to unprecedented levels, hundreds of small, inefficient

mines opened, adding many employees but relatively little tonnage to the industry’s aggregate. 71 Inflated coal prices enabled these

mines to operate profitably despite their relative inefficiency. Conditions and policies that

encourage marginal mining wilI lower aggregate productivity. As long as coal prices remained constant in the 1950’s and 1960’s, productivity rose steadily, But when prices rose

sharply in the 1970’s, productivity fell.

Third, clean air legislation and relatively

steady metallurgical demand in the 1970’s

meant coal had to be cleaned, sometimes

cleaner than before 1969. More than 100

mill ion tons of waste (the equivalent of 15 percent of 1977’s total output) was cleaned from

run-of-the-mine output. Although this material

70 Longwalls can mine more coal with fewer miners, but

they are expensive and workable only in certain geologic

conditions. About two-thirds of the 77 units operating i n

1977 were In metallurgical mines, where high product

price justified high capital investment.

“The biggest single employment category In 1975 was

miners [n underground and surface mines producing fewer than 25,000 tons annual Iy 46,695 miners in these

mines (about 24 percent of all miners) produced only

141 million tons (about 2 percent of all output) Calculated from, /njury Experience in Coa/ Mining, 1975, informational Report, 1077 (Department of Labor, Mining

Safety and Health Administration, 1978), p 77.

is taken from the ground, much of it is not

counted in productivity calcuIations. For a

number of reasons, deep-mined coal is more

often and more thoroughly cleaned than surface-mined coal, which further lowers deepmine productivity. Productivity at individual

mines may be substantially affected by this

factor. For example, one underground mine

OTA visited was routinely discarding 56 percent of material taken from the mine in order

to fulfill coal-quality specifications in its supply contract. Productivity at this mine was

about 3 1/2 tons per worker shift. I f its production had not had to be cleaned, productivity

would have doubled. Throughout the 1970’s,

the percentage of refuse-to-raw coal has

inched upward. This reflects either dirtier raw

coal or stricter customer specifications, and

possibly both. Assuming that the Environmental Protection Agency (E PA) finally promulgates a 0.2-lb/85-percent sulfur removal limitation, the amount of coal cleaned is likely to increase as the utility market expands. Also, as

the more marginal seams are mined, the

amount of waste extracted in mining may increase. Both factors retard productivity gains,

Fourth, the labor force has changed dramatically since 1969. Both miners and supervisors

are young, often inexperienced and inefficient.

Almost half of the experienced 1969 work

force retired in the 1970’s and 65 percent of today’s work force has been hired in the 1970’s.

The industry has had trouble transferring the

practical wisdom of its older miners to this

new generation. Absenteeism has also reduced

productivity. Few hard data exist on the actual

extent of absenteeism or its root causes. One

way of offsetting absenteeism is to train

miners to have interchangeable skills so that

each can do every job on the crew. But few

coal companies do this. Nor do many companies employ “utility” workers as the automakers do, whose job it is to substitute for

absentee workers. The industry may be able to

improve productivity by adopting such

changes if permitted by union work rules.

Finally, an estimated 5,000 miners were hired

after 1974, when the new UMWA contract required helpers on underground face equipment. Helpers safen the operation of mobile

equipment by moving high-voltage trailing
Ch. I V—Factors Affecting Coal Production and Use ● 153

cables out of the way, watching roof and rib

conditions, helping the machine operator

maneuver, and being around in case of trouble. Helpers also receive training in machine

operation from experienced miners during

their apprenticeship, which allows them —

after 120 training days — to operate equipment

when the regular operator is not present. The

addition of 5,000 helper jobs lowered productivity statistics. But the industry may recoup

these statistical losses in the future by having a

pool of trained machine operators ready to

step in at a moment’s notice. Although the productivity decline has its qualitative side (such

as inexperience or anti-company attitude), the

simple quantitative aspect— more miners— is

its real cause.

Fifth, disabling injuries lower productivity to

the extent they disrupt production teams and

require extra personnel. Disabling injuries have

risen since 1969. I n that year, 8,358 underground injuries and 967 surface injuries were

recorded. I n 1977, underground disabling injuries had risen 40 percent to 11,724 and surface injuries had gone up 132 percent to 2,246

(see Workplace Safety, table 35). The amount

of lost time from disabling injuries is substantial. Average severity of an injury refers to the

average number of calendar days lost by an injured worker. I n 1977, underground miners experienced 146 permanent partial injuries costing an average of 297 lost days and 11,575 temporary total injuries with an average cost of 73

work days. 72 Surface miners experienced 66

permanent partial injuries with an average loss

of 529 days each and 2,211 temporary total injuries with an average loss of 58 days each.

Together, underground and surface injuries

resulted in the loss of 1,051,489 calendar days

in 1977, which meant 751,079 lost production

days. That represents 3,391 lost worker years. ”

In one form or another, an equivalent amount

of labor had to be hired to substitute for these

injured workers to maintain production. This

represented extra personnel and extra dolIar

costs to mine operators, as well as reduced

productivity. To put 3,391 lost worker years in

a comparative perspective, it represents more

‘iData supplled by MS HA’S Data Analys[s Center ,

January 1979 Excludes permanent total injuries

than 30 percent of time lost from wildcat

strikes in 1977.

Sixth, the 1970’s saw extensive legislative

and administrative regulation of the coal industry. States began to require surface

operators to reclaim land and control landslides and water runoff. This forced the industry to hire more workers and buy new

equipment. This added effort was “social [y

productive” from a national and public perspective but lowered the economic productivity of the individual operator and the industry.

Neither the Federal Office of Surface Mining

nor industry associations could supply data on

the percentage of the Nation’s 64,000 surface

miners that were engaged in reclamation work,

A major regulatory initiative that affected

underground mining was the 1969 Coal Mine

Health and Safety Act. Federal health and

safety standards forced operators to devote

more personnel and equipment time to ventilation, rockdusting, methane and dust monitoring, roof control, maintenance, and retrofitting

machinery with safety features. Safer operating procedures require equipment to be

moved in and out of the working place more

frequently than before. Had these practices

not been adopted, it is reasonable to suppose

that coal’s safety record would have been substantially worse. Some new personnel were

needed to handle the employee-training and

administrative aspects of the Act. Other governmental regulations required new safety and

environmental personnel. Office workers —

professional and clerical –were needed to ob73 Calculated In the fol Iowlng manner Multlply number

of lnjur[es by the average number of days lost to get tota I

number of lost days To f Ind the number of lost work

days, subtract two-sevenths of the total number of lost

days (representing weekend time) from the total number

of lost days Divide this sum by the average number ot

working days each year– 22o (underground), 230

(surf ace)–to get the number of work-year equivalents

lost to dlsabllng injuries. For underground mlnlng, this

formula finds 888,337 lost calendar days reduces to

634,539 lost work days, or 2,884 lost worker vears For

surface mlnlng, there were 163, 152 lo\t calendar days or

116,.539 lost work d~ys, the equ Iva lent of 507 lost worker

years Adding underground and surface lo~t worker years

gives a total of 3,391 lost worker yedrs from m Ine Inju rles

I n 1977 Data for worker$ I n m I ne construct Ion, prepa ration plants, etc are not Included
154 ● The Direct Use of Coal

tain permits, develop plans and administer

them at the minesite. In 1969, for example,

operators reported 2,640 office workers of all

kinds at minesites; that figure rose to 7,037 in

1977, an increase of 167 percent. Presumably,

all of these management employees do necessary work. But they lower a mine’s productivity when they are included as workers in the

productivity equation. It has not been possible

to determine how many officeworkers are routinely counted in productivity calculations,

but anecdotal evidence suggests the number is

substantial.

Other factors may contribute to declining

productivity. Operators may have trouble getting capital. Delays in replacing mining equipment may reduce output. Underground haulage technology has not kept pace with cutting

technology. These systems often break down.

In older mines haulage and ground-control

problems tend to be more troublesome. Transportation problems from mine to market slow

down production when logjams develop. Primitive coal field social conditions and public service deficiencies have been cited in several recent studies as contributing to hig h

absenteeism and hostile labor-management

relations, which lower productivity.

What of the Future?

The decline in coal mine productivity has

probably bottomed out. Gradual improvement

over the next decade should occur if many of

today’s trends continue. Some of these trends

are mentioned here. Western surface mining

will account for an increasing share of total

production. Its productivity ranges from 50 to

150 tons per worker shift. Many of the personnel needed to handle the requirements of

Federal environmental and safety regulations

are already hired. Major legislative initiatives

in both areas requiring many more salaried or

hourly employees are not likely. The big hiring

surge of young workers has already taken

place. They are likely to spend the next 20

years or so in mining as highly skilled, experienced employees. Marginal, inefficient

mines will probably close if coal prices

stabilize and big companies expand. New big

mines with high productivity rates will open;

old, smaller mines will close. Finally, it is likely

that many operators will try to improve their

training programs and labor relations, which

should help raise productivity.

However, increasing productivity may be a

mixed blessing. Strategies to enhance productivity directly affect the health and safety of

coal workers and the quality of community Iife

in the coalfields. Production can be boosted

through one of four productivity-enhancing

strategies, each of which carries a different set

of workplace and social consequences.

These strategies are:

1. Use fewer workers to mine more coal.

2. Speed the pace of work so that each

miner produces more tonnage.

3. Invest capital in more efficient equipment

to enable each worker to produce more.

4. Make the work process more efficient by

redesigning jobs, improving morale and

motivation or improving coordination in

the production cycle.

The first two approaches can have substantial health, safety, and social costs, depending

on how the work force is expected to maintain

production levels. If labor-saving equipment is

purchased, health and safety may be improved

because fewer workers will be exposed to dangerous conditions. However, if the remaining

employees are simply expected to work faster

or spend less time taking safety precautions,

accident frequency or health conditions may

worsen. One major West Virginia operator recently announced the layoff of 2,100 workers

to improve productivity. This operator who

hopes to maintain output with fewer workers

consistently shows extremely high disablinginjury rates, and the safety and heaIth consequences of this change may be substantial. Inefficient sections of these mines may close

down entirely, or “nonproductive” jobs related

to mine housekeeping, rock dusting, and ventilation work may be eliminated.

Speedup strategies (#2) may involve heavy

safety and health costs. Recently, a number of

mines have adopted cash bonus systems

whereby a miner can receive extra income if a

tonnage quota is exceeded. One union official

in the United Kingdom, where a similar plan
Ch. /V—Factors Affecting Coal Production and Use • 155

was begun in 1977, reported a 50-percent increase in fatalities at mines that switched to

the incentive plans. The American experience

with these plans is too recent to assess. Some

U.S. plans tie the cash bonus to both safety

(defined as disabling injuries) and productivity.

Clearly, this is a commendable approach. But

the plans may encourage miners and management to undercount i n juries i n order to preserve the bonus payoff Even plans that tie production to safety ignore possible health costs.

If miners work faster at producing coal, they

may take less time to maintain workplace conditions that protect their health. As there is no

way to measure a worker’s immediate respone

to increased dust or noise, bonus plans may be

encouraging workers to buy short-term extra

dollars in return for their long-term health.

Investing capital for greater productivity (#

3) can take two forms. First, a mine operator

may upgrade his mining system by replacing

existing machines with newer, more efficient

models. The costs and benefits of this investment — in productivity, health and safety— are

generally well-known. A second form of productivity investment is the purchasing of a new

product that has recently been commercialized. The productivity advantages of new technology are usually more easily estimated than

any possible health and safety costs. Congress

stated clearly that one of the purposes of the

1969 Act was “ . . to prevent newly created

hazards resulting from new technology in coal

mining. ” The industry is aware that new technology sometimes may increase productivity

at the expense of safety. Joseph Brennan, president of BCOA, noted that “any new mining

technology developed to aid in boosting productivity should also incorporate safety as one

of its key features.”74 It is likely that the safest

productivity strategy would be one that removed the most workers from the workplace,

but the unemployment implications of this approach would be immense.

Although rising productivity brings economic benefits to management and labor,

greater production is the primary goal of a na74’’Productivlty and the BCOA, ” Coal Age, july 1975, p

97

tional energy policy. Increasing coal production is related to— but is not necessarily the

same as — raising productivity, Each objective

entails a different set of economic and social

implications. Price, for example, affects productivity and production differently. High coal

prices lower industrywide productivity but

raise production; low prices do the reverse.

Federal policy has yet to specify the desired

blend of production and productivity. Private

policy, if the 1978 UMWA-BCOA contract is

any indication, appears to have shifted toward

productivity enhancement as a way of increasing production. Before decisions are made that

commit Federal policy to either direction, major research is needed into the relationships

among productivity, safety and market conditions on a mine-by-mine basis, together with a

re-evaluation of productivity measurements

themselves. Most Federal research personnel

do not feel that a radical technological breakthrough— something like in-situ combustion

for power generation or a surface-controlled,

automated underground mining system — are

in the offing. If it were, Federal and local officials would face the social dislocation of

thousands of unemployed miners and possibly

the economic devastation of hundreds of coal

mining communities akin to that of the 1950’s

and 1960’s. The state of coal mining technology is such that production can double or triple without any major technological innovations. Specific aspects of the mining cycle can

benefit from technological innovation, but

viewed as a whole, no compelling or urgent

need exists to commercialize new technologies

to meet anticipated production goals,

Restructuring the production process and

better training and education (#4) may offer

the most promise for productivity improvement over the next decade. Little research and

experimentation has been done on better ways

of organizing work and managing production

crews. Similarly, little attention has been given

to determining the most effective safety and

job training and education programs. Both efficiency and safety are Iikely to increase in relation to the relevance of their training and the

involvement miners feel they have in its practical application.
156 ● The Direct Use of Coal

WATER AVAILABILITY

Water is an essential resource for almost all

phases of energy development. The availability of sufficient water to meet energy

needs is more than a function of the presence

of large quantities of water; it depends on the

political acceptability of using the physically

available supply, the economic competition

from other users, the legal system controlling

water rights, environmental factors, and other

i nfIuences.

Irrigated agriculture is the major consumptive water use in the United States. Most agricultural water is consumed west of the Mississippi. Improved irrigation efficiency can reduce consumptive use of water, with a portion

of this savings made available to the energy

sector in the West. The SoiI Conservation Service (SCS) estimates that in a dry year 195 million acre-feet of water is diverted for irrigation,

of which 103 m i II ion acre-feet of depletion is

charged to irrigated agriculture. Of this, 78

million acre-feet (76 percent) is consumptively

used by the growing crop and the remaining 24

miIIion acre-feet is lost to “incidental” causes.

SCS estimates that, by the year 2000, 8-million acre-feet of the water that is presently

“lost” each year can be salvaged by improving

irrigation efficiency. (A bonus of improved efficiency would be a 48-million acre-feet reduction in withdrawals and a similar reduction in

return flows, yielding a substantial improvement in water quality. ) Depending on its location, part of this water could become available

to energy developers. However, agriculture

pays such a low price for water ($I5 to $40/-

acre-foot) that little incentive exists for its efficient use.

Besides improving irrigation efficiency, a

number of other agriculture water conservation alternatives exist, including:

● crops witching (from water-intensive

crops, such as alfalfa, to less intensive

crops such as wheat, oats, and barley);

● improvement of cuItivation procedures;

● removing marginal lands from production; and

● removal of water-using natural vegetation. 75

None of these alternatives is applied universally; some have potentially undesirable side

effects. Crop switching depends on available

markets and proper farming conditions. Removing marginal lands from production can

lead to unemployment and other social problems. Natural vegetation (“phreatophyte”)

removal can harm wildlife habitat and erode

affected lands.

A major policy problem is that incentives to

conserve agricultural water have been so low

that minimal research and analysis have been

done to illuminate the tradeoffs among alternative water use policies. This lack of knowledge, coupled with extreme resistance to any

change in water policy, has hampered intelligent reform of water management practices

for agriculture.

Meanwhile, without management reform to

make water more readily available, the energy

industry can afford to pay far more for water

than a farmer can. In the Western States, some

owners are selling their agricultural land and

its associated water rights for coal mining and

energy development. If this process of converting agricultural land and water resources to

the energy sector continues and accelerates, it

may become an important political issue in the

West. It seems improbable that State governments will allow wholesale replacement of

agriculture by energy. It is clear, however, that

the heavy subsidies paid to marginal farmers

by selling them water at a small fraction of actual costs is a very expensive policy.

One possible compromise would be to establish a partnership between farmers and the

energy sector with the cooperation of the State

governments. The energy sector could finance

water conservation measures and use the

water that is saved. Although cost estimates

are unavailable, the cost seems likely to be

considerably less than other alternatives being

‘

5S Plotkin, et al., “Water and Energy In the Western

Coal Lands, ” Water Resources 13u//etin, February 1979
Ch. IV—Factors Affecting Coal ProductIon and Use . 157

considered, such as the diversion of water

from the Oahe reservoir in South Dakota to

Gillette, Wyo., at an estimated cost of $700 to

$900/per acre-foot, or the changing of technology in electric power from wet-cooling to drycooling systems at an estimated minimum

equivalent cost of $900 per acre foot.76 

Inter-basin transfers are often hampered by

legal and institutional complaints that have

emotional overtones. Congress has the power

either to prohibit or require an interstate interbasin water transfer. As part of the Colorado

River Basin Project Act (Public Law 90-537,

also known as the Central Arizona Project Act),

Congress in 1968 declared a 10-year moratorium on studies on the importation of water

into the Colorado River Basin. Many questions

remain unsettled on this issue. Water rights remain unadjudicated for many river basins in

the West—particularly in the Northwest; the

total allocation of water within many basins

remains unknown, and conflicts have not been

settled for many multiple uses. Questions remain unresolved on the amount of water required for instream purposes; regional goals

have not yet been backed by local goals and

policies on land use, economic growth, and

population growth, making uncertain the prediction of water requirements.

Indian tribes are increasingly exercising their

water rights in the West. The present confusion

over Indian water rights may be detrimental to

the planning of water and related land resources in general, and to energy development

in the West in particular. The key to Indian

water rights is a 1908 U.S. Supreme Court case

that produced what is widely known as the

“Winters Doctrine. ” The case involved a dispute between Indians of the Fort Belknap Reservation and non-Indian appropriators over

waters of the MiIk River, a nonnavigable Montana waterway. The Court held that, although

it was not explicitly mentioned in the 1888

documents creating the Fort Belknap Reservation, there existed an implied reservation of

rights to the use of waters that originate on,

traverse, or border on the Indian land, with a

priority dating from the time the treaty created

the reservation. The Court’s language has led

“1 bld

to two interpretations of the source of the

right. One line of reasoning argues that, with

regard to Indian reservations created by treaty

(or executive orders), water rights were retained by the Indians at the time of the treaty.

Moreover, the document is silent on the question because the Indians did not intend to

transfer the water rights. The alternative view

holds that the water rights were in fact transferred, but that the Federal Government, under

its own powers, “reserved” an amount of water

from proximate streams to support an agricultural existence for the Indians. In Arizona v.

California, the U.S. Supreme Court approved

water allocations to various Colorado River

Basin Indian reservations. Water quantities

demanded and ultimately adjudicated for lndian reservations remain to be determined,

Whatever the amounts, the water will come off

the top of the available water in the Colorado

River Basin, reducing the amounts remaining

to the States for allocation to agricultural,

energy development, municipal, recreational,

and other uses.

Ground water currently supplies about 20

percent of all freshwater used in the United

States. The estimated storage capacity of aquifers (underground reservoirs) is nearly 20 times

the combined volume of all of the Nation’s

rivers, ponds, and other surface water. Ground

water serves about 80 percent of municipal

water systems and supplies 95 percent of rural

needs; in all, it serves 50 percent of the Nation’s population. Irrigation accounts for more

than half of ground water use. In many parts of

the country ground water mining (pumping

water from an aquifer faster than the water in

the aquifer is replenished) is occurring. The

tendency to use saline water for energy development may add to the overall problem of soil

subsidence, salt water intrusion, and the lowering of the water table in many aquifers. In

many States, ground water law, Iike riparian

surface water law, is inadequate to allocate

the resource among competing users and is

unresponsive to the problem of excessive use.

The first defect results from vagueness of the

rule of allocation (“reasonable use”) and the

second from failure of the legal system to perceive that the ground water is often a common-pool resource for which there is Iittle in-
158 • The Direct Use of Coal

centive to save an exhaustible supply for use

tomorrow. Any user who seeks to save it is subject to having his savings captured by another

pumper from the same aquifer.

In virgin or undepleted conditions it is estimated that the average annual surface runoff

or yield of the stream systems of the 11 Western States totaled 427 mill ion acre-feet, including 50 miIlion acre-feet of inflow from

Canada. Today, owing to the cumulative activities of man, this virgin water supply has been

depleted by 83 million acre-feet of consumptive water use annually, leaving 344 million

acre-feet or about 81 percent of the virgin

yield still unconsumed. Within this western

region are large areas such as the Upper Rio

Grande and the Gila River Basins, where the

total annual surface water supply, for all practical purposes, is completely consumed. In the

Colorado River Basin this condition will be

reached when the Central Arizona project is

completed. The Missouri River and its tributaries in Montana and northern Wyoming appear to have sufficient unused water supplies

to meet needs for the foreseeable future. The

Platte River tributaries in Wyoming, and particularly in Colorado, are approaching the

saturation point in water use.

Present and projected water demands for

1985 and 2000 indicate, on one hand, severe

regional water shortages and problems, and on

the other hand adequate water availability to

meet energy needs on a nationwide basis. According to the 1975 National Assessment of the

U.S. Water Resources Council, the Nation’s

freshwater withdrawals in 1975 from ground

and surface water sources for all purposes

average about 404 miIIion acre-feet/year

(mafy). Of this amount, 125 mafy were consumed through evaporation or incorporation

into products, and the remainder was returned

to surface water sources for possible reuse in

downstream locations. By 2000, total withdrawals are projected to be about 348 mafy,

with about 151 mafy being consumed — a 14-

percent reduction in withdrawal, but a 20-

percent increase in the amount consumed.

The production of energy and the extraction

of fuels from which energy is produced constituted 27 percent of the total U.S. water

withdrawals and 3 percent of total consumption in 1975. By 2000, mining and energy production (excluding synthetic fuels) will constitute 27 percent of the U.S. withdrawals and

10 percent of total consumption.

The geographic and temporal distribution of

the Nation’s surface waters is so variable as to

pose substantial problems for energy development where billion dollar localities depend on

a continuous supply of water. Rainfall varies

widely from region to region, from season to

season, and from year to year. Similar variations occur in runoff and streamflows. For example, within a normal year, the ratio of maximum flow to minimum flow may be 500 to 1

or greater. Year to year variations in the average flow also are substantial. Even in areas of

high precipitation and runoff, a series of dry

years may occur, resulting in serious drought

problems such as those in the Northwest from

1961 to 1966 and in the Pacific Northwest in

1976 and 1977.

The United States appears to have enough

water available to supply its most urgent

needs, but there are numerous legal, institutional, and political constraints on its use, and

many areas may have severe water shortages

unless concrete physical measures — restraints

on development, water conservation requirements, construction of additional storage,

etc. — are taken. Some critical elements of

legal/institutional change include:

●

●

●

resolving the problems of Indian wate r

rights;

making the price of water commensurate

with its cost whiIe recognizing the nonprice value to a locale of alternative types

of development; and

developing a cooperative, instead of competitive, relationship between energy and

agricuIture.
Ch. IV—Factors Affecting Coal Production and Use • 159

CAPITAL AVAILABILITY

The costs of coal production and conversion

facilities have increased rapidly because of hyperinflation in the equipment market and the

addition-of environmental protection controls.

Coupled with the rapid growth expected, much

more capital wilI be needed. The constraints

and uncertainties discussed in other sections

wilI make financing more difficult by increasing overalI production costs. Nevertheless, if

demand for coal actually develops, financing

the new mines probably will not raise insurmountable problems. As discussed previously

in the Industry Profile section, changes legislated in the industry structure will have an unpredictable effect in this area. Utilities may

have more difficulty raising capital for a variety of reasons, which this report has not studied

in detail, but most analysts feel the problems

will not be insurmountable. If necessary, a

number of different incentives could be considered to make all the necessary financing

available. These could include tax incentives,

loan guarantees, guaranteed purchase prices

for products, investment tax credits, and a

more uniform application of regulatory policy.

EQUIPMENT

Most studies of the potential availability of

mining equipment to meet expanded coal demands have concluded that equipment can be

supplied as needed. The one exception is the

long Ieadtime for delivery on large draglines

used to strip mine Western coal. However,

these conclusions were based on the expectation that much of the expansion of production

would come from Western coals. If there is a

shift toward more production from Eastern underground mines, the dragline delays may not

be serious but deliveries of underground

equipment could be delayed.

Little information is available on the condition of existing mining capacity and how much

upgrading will be required to meet new underground production targets. There are few

mining equipment suppliers and most are

small; a sudden increase in demand for new

equipment would strain their ability to supply

the industry’s needs and they may have difficulty raising the capital to expand their production to meet the new demand.

TRANSPORTATION

On a national scale, coal development probably will not be constrained by the availability

of transportation for the period under study.

Minor capacity expansions will be required by

1985, and more significant ones will be needed

thereafter. However, transportation facilities

can be planned and constructed within the

same amount of time as powerplants or large

mines, so that with adequate investment and

planning, improvements wilI take place as

needed,

Rather than reduce the total level of national coal production and use, transportation

bottlenecks that do develop will tend to alter

the pattern of mining, shipment, and consumption. Routes and mode choices will be adjusted

to alleviate capacity limitations, for example,

and mining and power generation will tend to

be expanded only where transportation service

is adequate.

At the local level, however, availability of

the means of transporting coal, or the electric

power derived from it, will be significant. The

following limiting factors may serve to inhibit

coal growth in specific regions.
160 ● The Direct Use of Coal

Rail

Some northeastern and Midwestern railroads are characterized by poor financial performance and deteriorated track conditions.

Without either public or private investment in

right-of-way improvements, particularly in Appalachia, growth in mining in this region may

be inhibited, truck use increased, and mlne-

. .

mouth power generation expanded.

Western coal-producing areas are served by

railroads in somewhat better financial condition, but there rail lines must be extended to

serve new mines.

Highway

Investment in Appalachian coal roads has

also not kept up with increases in truck traffic.

Deteriorated roads, like deteriorated rail lines,

may eventually inhibit coal production in affected localities.

Waterway

Barge transportation is ultimately limited by

the capacity of channels and locks, which are

constructed and maintained by the Army

Corps of Engineers. Major extensions and improvements to the waterway system are authorized by Congress; failure to undertake

projects as capacity limitations are reached

also will affect regional production

ket patterns and will tend to divert

raiIroads.

Slurry Pipelines

and martraffic to

Slurry pipelines become an alternative to

railroads only where rights-of-way and water

rights can be acquired. Slurry pipeline enterprises do not enjoy the power of eminent domain in many States, and opposition by railroads and other landowners can impede development of this type of facility. Also western

coal-producing States are characterized by

scarcity of water, which may not be made

available by local authorities for slurr y

pipelines.

High-Voltage Transmission

Installation of long-distance transmission

lines generally requires Federal approval,

which provides an opportunity for opponents

to intervene, particularly on environmental

grounds. Siting powerplants to take strategic

advantage of this means of transporting power

may also be difficult, particularly in western

coal-producing areas. Regulations to prevent

significant deterioration of pristine air quality

under the Clean Air Act and local opposition

to water use and other environmental impacts

serve to inhibit mine-mouth power generation,

for which long-distance transmission generally

is suited.

REGULATORY RESTRICTIONS ON COMBUSTION

Federal agencies indirectly regulate the

siting of large new coal combustion facilites

and directly regulate the construction and

operation of these facilities as well as the

disposal of combustion wastes. The principal

constraints are imposed by the Clean Air Act;

additional considerations include the Clean

Water Act, the National Environmental Policy

Act (N EPA), the Resource Conservation and

Recovery Act (RCRA), the Endangered Species

Act, and regulations governing the use of

Federal lands and of navigable waters. The

legal framework of most of these provisions is

discussed in chapter VIl. This section addresses the constraints imposed by these

regulations on coal users; the next section

discusses the options available for operating

within those constraints.

Facility Siting

Facility siting is affected primarily by the

Clean Air Act; other considerations may arise

under the Clean Water Act, NE PA, the Endangered Species Act, and regulations related

to the use of Federal lands.
Ch. IV—Factors Affecting Coal Production and Use . 161

The Clean Air Act is structured around National Ambient Air Quality Standards (NAAQS)

(see table 18), which are implemented through

a variety of regulatory programs designed to

Iimit emissions of airborne polIutants from stationary and mobile sources. Programs applicable to stationary sources primarily use

control technology requirements and numerical emission limitations to regulate polIution

from new and existing facilities, from facilities

located in clean and dirty air areas, and from

facilities located near scenic areas such as national parks.

Table 18.—National Ambient Air Quality Standards

Averaging

Pollutant time

ParticuIate

matter Annual (geometric mean)

24-hour

Sulfur 3-hour

dioxide . . . Annual (arithmetic mean) “

24-hour

Primary

standard

75 ug/m3

260 ug/m3

—

80 ug/m3

365 ug/m3

3-hour

Nitrogen

dioxide . . Annual (arithmetic mean)

24-hour

3-hour

-.

As of 1977, 116 of 24 7

regions (AQCRS) reported

primary annual particulate

reported violations of the

Secondary

standard

60 uglm3

150 ug/mJ

—

—

—

— 1,300 ug/m3

100 ug/m3

100 ~g/m3

— —

— —

air quality control

violations of the

standard while 108

24-hour standard.

Similarly, 12 AQCRs reported violations of the

primary annual SO2 standard while 37 reported

violations of the 24-hour standard. These

regions are designated nonattainment areas

for these pollutants, as shown in figures 17 and

18. Many of the AQCRS that are shown as

nonattainment areas may only have localized

violations with the remainder of the AQCR in

compliance. The States are responsible for

developing control strategies for areas showing violations that wilI provide for the attainment of the primary NAAQS as expeditiously

as practicable, but not later than December

31, 1982, The State strategy must require significant annual incremental emission reductions

from existing stationary sources in areas that

show violations, as welI as permits for the construction and operation of new or modified

sources that would exacerbate existing NAAQS

violations.

Nonattainment programs will impose severe

constraints not only on increased coal use but

on all growth in these areas. As mentioned

above, most of the AQCRS have not attained

the primary particulate standards, while 15

percent have not met the S02 standards. Wherever a new source would exacerbate an existing NAAQS violation, the permit applicant

must apply the lowest achievable emission

rate (LAER) and must secure from existing

sources in the area emission reductions that

more than offset the emissions from the proposed facility. The cost of meeting these two

requirements is high, and securing the offsetting emission reductions is difficult. Consequently, new sources are more likely to be

located in rural areas where the NAAQS have

been achieved. In addition, major modifications to existing sources in nonattainment

areas probably would be rejected in favor of

new sources in clean air areas.

However, the Clean Air Act also includes

comprehensive provisions to prevent the significant deterioration (P SD) of air quality in

areas where the air is cleaner than the NAAQS

require, The PSD increments for Class I areas

(usually parks or monuments, or wilderness

areas) allow the lowest increase in ambient

concentrations over the baseline, and thus the

fewest new stationary sources, while the Class

I I I increments allow the greatest increase (see

table 19). In no event may a new source located in a clean air area cause the concentration of any pollutant to exceed either the national primary or secondary ambient air quality standard, whichever concentration is lower.

At present the PSD regulations apply only to

emissions of particulate matter and SO2

.

Regulations for NO2

, hydrocarbons, photochemical oxidants, and carbon monoxide are

to be promulgated by August 1979.

To obtain a permit to locate a new source in

an area subject to the PSD regulations, the applicant must demonstrate that the source will

meet all applicable emission limitations under

the State implementation plan (SIP) as well as

performance standards for new sources and

emission standards for hazardous pollutants,

and that the source will apply the best

available control technology (BACT). BACT is
Figure 17.—AQCRs Status of Compliance With Ambient Air Quality Standards for Suspended Particulate

. .**.

SOURCE U S Enwronmental ProtectIon Agency 1976a

determined on a case-by-case basis, taking into

account energy, environmental, and economic

impacts and other costs. In addition, the applicant must demonstrate, based on air quality

monitoring data and modeling techniques,

that allowable emissions from the source will

not cause or contribute to air pollution in

violation of the NAAQS or PSD increments.

The permit applicant also must provide an

analysis of the source’s air-quality-related impacts on visibility, soils, vegetation, and anticipated induced industrial, commercial, and

residential growth.

Under the 1977 Clean Air Act amendments,

PSD provisions apply to a source in any of 28

categories (including fossil-fuel-fired steam

❑ Areas with violations

v

Areas with inadequate data.

Status unknown

electric generating units of more than 250

million Btu/hr heat input and coal-cleaning

plants with thermal dryers) with uncontrolled

emissions of 100 tons per year, or to any source

with uncontrolled emissions of 250 tons per

year. Previous regulations applied only to

sources in 19 specified categories. However,

under the new regulations, only those sources

with controlled emissions of 50 tons/yr or

greater or that would affect a Class I area or an

area where the increment is known to be violated, will be subject to full PSD review.

Sources with controlled emissions of less than

50 tons per year need only demonstrate that

they will meet all applicable emission limitations. Each SIP must include a program to

assess periodically whether emissions from
Ch. IV—Factors Affecting Coal Production and Use ● 163

Figure 18.—AQCRS Status of Compliance With Ambient Air Quality Standards for Sulfur Dioxide

%

,

.

9

. ,

*

..- . +-

0

n)

SOURCE U S Enwronmental ProtectIon Agency. 1976a

‘a’ ❑ Areas (n compliance

these small, exempt sources, and from any

other sources that may be unreviewed because

of their date of construction, are endangering

PSD increments.

Because the 1977 PSD provisions apply to a

wider range of sources, they are expected to increase the costs of facility siting significantly.

EPA estimates that 1,600 sources of all types

will be subject to the permit requirements

each year (as compared to 164 per year under

the previous regulations). In addition, there are

two situations in which facility siting probably

will be constrained, First, PSD permits will not

be available for large new sources in areas

where the difference between the baseline

concentration and the NAAQS already is less

Areas with violations

❑ Areas with Inadequate data

Status unknown

than the allowable increment. Second, where

there are several sources that are exempt from

the PSD requirements because of their size or

date of construction, these exempt and unreviewed sources may capture the available increments and foreclose siting for larger new

facilities, as mentioned above, States are required to assess periodically the emissions

from these exempt and unreviewed sources.

Finally, provisions in the Clean Air Act designed to protect visibility in areas primarily

important for scenic values, such as national

parks, are expected to affect the siting of coalfired facilities. EPA’s regulations, to be promuIgated not later than August 1979, are to require SIP revisions in order to achieve visibility
164 • The Direct Use of Coal

Table 19.—Ambient Air Increments

Maximum

allowable

increase

Pollutant (~9mY

Class I

Particulate matter .

Annual geometric mean . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

24-hr maximum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Sulfur dioxide

Annual arithmetic mean . . . . . . . . . . . . . .

24-hr maximum .........=. . . . . . . . . . . .

3-hr maximum .~.-.-~.-..-..-ti.

Classll

Particulate matter

Annual geometric mean . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

24-hr maximum ~~.fi.fi.fi.fiti.ti.~ti-=ti..

Sulfur dioxide

Annual Arithmetic mean . . . . . . . . . . . . . . ..

24-hr maximum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-hr maximum titi.-.--ti.-~ti--.tifiti..ti..

Class Ill

Particulate matter

Annual geometric mean . . . . . . . . . . . . . . .

24-hr maximum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Sulfur dioxide

Annual arithmetic mean . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

24-hr maximum ~.~.~.-.f~.---~-.-titi-.~-

3-hr maximum ..fi..ti..-~.~tititifitifi

5

10

2

5

25

19

37

20

91

512

37

75

40

182

700

improvement by retrofitting plants in existence

for less than 15 years as well as by adopting a

long-term strategy for progress toward a national visibility goal. Proposed fossil-fuel-fired

powerplants with a design capacity of more

than 750 MW must demonstrate that they will

not cause or contribute to the significant impairment of visibility in any of the specified

areas. However, until the visibility regulations

have been promulgated, it is not possible to

determine their impact on the costs of, or site

selection for, coal-fired facilities.

Additional, less significant constraints on

siting are imposed by the permit requirements

of the Clean Water Act, the Army Corps of Engineers, and agencies having jurisdiction over

Federal Iands, as well as by the general requirements of NEPA, the National Historic Preservation Act(NHPA) the Fish and Wildlife Coordination Act (FWCA), and the Endangered Species Act. The Clean Water Act is structured

around the quality of water necessary for a

variety of uses, including public water supplies, propagation of fish and wildlife, recreational, agricultural, industrial and other purposes, and navigation. New facilities must obtain a permit under the National Pollution Discharge Elimination System (NPDES). The permit incorporates all applicable effluent limitations and water quality standards promulgated

under the Clean Water Act, and an applicant

must demonstrate that these limitations and

standards will be met. In addition, if the plans

for a combustion facility require any structure

to be built in navigable waters (such as a cooling-water intake structure or barge unloading

facility), a permit must be obtained from the

Army Corps of Engineers. Corps regulations

stipulate that no such permit may be issued until the applicant demonstrates that all other

necessary Federal, State, and local permits,

certifications, or other authorizations have

been obtained. Finally, if the coal combustion

unit or any of its support facilities (such as

transmission lines) are to be located on Federal

land, a permit must be obtained from the agency having jurisdiction over that land.

Most federally issued permits for coal combustion facilities will trigger the environmental

impact statement (E IS) requirements of NE PA.

Although the E IS is prepared by the agency issuing the permit, it is based on analyses submitted by the applicant, and the length of time

required to prepare the E IS depends on the

quality and completeness of those analyses. In

addition, before issuing a permit an agency

must obtain a certification from the Secretary

of the Interior that the faciIity wilI not jeopardize the continued existence of an endangered

species. Under the FWCA, when a federally

permitted project would result in the modification of any water body (for example, reduction

of water flow through consumption by cooling

towers), the permitting agency must consult

with the Fish and Wildlife Service and with the

State agency having supervisory authority over

fish and wildlife prior to issuing the permit. Issuance of the permit may be enjoined until

consultation and coordination has occurred,

and serious consideration must be given to

recommendations for mitigation of impacts to
Ch. IV—Factors Affecting Coal Production and Use • 165

fish and wildlife. Finally, regulations promulgated under the NHPA require all permitting

agencies to determine whether there are historic, archeological, architectural, or cultural

resources affected by the proposed action that

are listed in the National Register of Historic

Places or are eligible for listing. If any of these

resources may be affected, the permitting

agency must obtain comments from the Advisory Council on Historic Preservation. I n most

cases, however, historic and other sites must

only be studied, not necessarily preserved.

Of all these requirements, the Clean Air Act

wiII have the most far-reaching consequences

in terms of the number of sites foreclosed to

coal combustion facilities. However, the cumulative effect of all provisions, each with extensive interagency and public participation

requirements, will be to lengthen significantly

the time necessary for site approval. When numerous State and local permits and other requirements are added in, this Ieadtime can become costly.

Combustion

As with siting, the Clean Air Act imposes the

most significant constraints on increased coal

combustion. other limitations include the

Clean Water Act and the RCRA. The Clean Air

Act affects coal combustion through standards

of performance for new sources and through

the provisions related to nonattainment areas

and the prevention of significant deterioration.

Standards of performance for new or substantially modified facilities establish al lowable emission limitations for those facilities

and require the achievement of a percentage

reduction in emissions from those that would

have resulted from the use of untreated fuels.

Under the 1977 amendments to the Clean Air

Act, these standards must reflect the degree of

emission limitation and the percentage reduction achievable through application of the best

technological system of continuous emission

reduction that has been demonstrated adequately (taking into consideration the cost of

achieving the reduction and any health and environmental impacts and energy requirements

not related to air quality). That is, New Source

Performance Standards (NSPS) must be met

through the use of a technological method of

control, such as a scrubber or precombustion

treatment of the fuel, rather than through alternative fuels such as oil or Iow-suIfur coal.

The principal coal combustion facilities for

which NSPS have been promulgated include

steam electric-generating plants of more than

250 million Btu/hr heat input, large industrial

boilers, and coal preparation pIants (including

any facility that prepares coal by breaking,

crushing, screening, wet or dry cleaning, and/or

thermal drying). The standards for these

sources are shown in table 20. EPA plans to announce new standards for large industrial

boilers in 1980.

Each SIP must include a procedure for

preconstruction review of new sources to ensure that NSPS will be met. In addition,

sources that undergo a modification that will

increase the kind or amount of polIutants emitted must undergo a similar NSPS review. However, the provisions relating to source modifications do not apply to facilities subject to a

coal conversion order under the National

Energy Act.

Although NSPS restrictions will eventually

apply to most boilers that could emit at least

100 tons of a pollutant per year, it will be

several years before these regulations are promulgated. Meanwhile, smalI boilers are regulated only by State and local authorities and

do not require a Federal permit. A utility could

be concerned that a number of small units

could start up between the time of a powerplant’s permit application and the time of permit award and make it impossible for the plant

to operate without violating air quality restrictions. For example, six 250-million Btu/hr

boilers, each burning 50,000 tons of 3 percent

sulfur coal (without control) can release the

same amount of S02 as a large powerplant

burning 2 million tons of the same coal with

85-percent control. Because small coal plants

can be ordered as package units with short

delivery schedules, this scenario may be

plausible. The Clean Air Act requires the States

to monitor small sources to prevent them from
166 • The Direct Use of Coal

Table 20.—New Source Performance Standards

Pollutant

Particulate matter Sulfur dioxide Nitrogen dioxide

Emission Emission Emission Emission Emission Emission

Source limitation reduction limitation reduction limitation reduction

Coal-fired steam

generator

Coal Preparation:

Thermal dryer gases

Pneumatic coalcleaning equipment

gases

Other

0.03 lb/106 Btu 99 percent 1.2 lb /106 Btu 85 percent 0.60 lb /106 Btu 65 percent

and 20-

percent

opacity

0.031 gr/dscf

and 20-

percent

opacity

0.018 gr/dscf

and 10-

percent

opacity

20-percent

opacity

“using up” available air quality increments,

but State enforcement programs may, in some

cases, have difficulty complying with these requirements.

EPA’s proposed regulations under the 1977

NSPS provisions have become controversial.

The principal issue is whether a plant burning

low-sulfur coal should be required to achieve

the same percentage reduction in potential

SO, emissions as one burning higher sulfur

coal. E PA’s proposed regulations for steam

electric-generating units set forth a full or

uniform control requirement regardless of the

sulfur content of the fuel, but with a 3-day-permonth exemption from the percentage reduction to accommodate high-sulfur Midwestern

coals. Alternative proposals considered by

EPA include a sliding-scale standard under

which the required percentage reduction decIines proportional to the sulfur content of the

coal, and monthly, rather than daily, averaging

of the percentage reduction requirement. In

addition, the General Accounting Office

(GAO) has recommended that EPA continue to

allow supplementary controls until mandated

studies of SO2

, sulfates, and fine particulates

are completed in Iate 1980.77

A variety of considerations will affect the

“Sixteen Air and Water Pollution Issues Facing the Nation (Washington, DC.: General Accounting Office, U.S

Comptroller General, October 1978),

final NSPS regulations. Under most circumstances, the proposed full-control requirement

would achieve the greatest reduction in SO2

emissions, but would increase the amount of

scrubber sludge from approximately 12 miIIion

metric tons dry basis under the previous NSPS

to around 55 million tons in 1985. A fullcontrol requirement would promote the use of

locally available, higher sulfur coals, especially in the Midwest, and discourage the use of

more expensive low-sulfur coals. Partial scrubbing would reduce flue-gas desulfurization

(FGD) costs and permit the bypassing of a portion of the flue gas and thus alleviate the need

for plume reheat and associated energy costs.

Full scrubbing would delay the construction of

new plants causing existing coal- and oil-fired

plants to be utilized more than they would

have been without the proposed standards,

thus causing an increase in emissions from existing plants in the short-term future that

would partially offset reductions achieved by

new plants.

The provisions of the Clean Air Act related

to nonattainment areas and the prevention of

significant deterioration (as described above)

also affect emissions from existing facilities.

The offset policy included in the requirements

for nonattainment areas and the availability of

PSD increments will put pressure on existing

sources to install costly polIution control tech-
Ch. /V—Factors Affecting Coal Production and Use ● 167

nology. I n addition, each SIP must include a

control strategy for existing sources in order to

achieve and maintain the national standards.

The Clean Water Act imposes effluent limitations on quantities, rates, and concentrations of chemical, physical, biological, and

other constituents that are discharged from

coal combustion facilities. Limitations have

been established for total suspended solids, oil

and grease, copper, iron, hydrogen-ion concentration (p H), free available chlorine, and

materials used for corrosion inhibition including zinc, chromium, and phosphorus.

These limitations are implemented primarily

through NPDES. As mentioned above, a facility may be issued an NPDES permit for a discharge on the condition that it will meet al I applicable water quality requirements. However,

these Iimitations are not as difficuIt to achieve

as the air quality standard, and the necessary

controls do not add significantly to the cost of

a coal combustion facility.

Finally, the Federal Government regulates

disposal of combustion byproducts–ash and

scrubber sludge— under RCRA. The Act establishes guidelines for the identification, transportation, and disposal of hazardous and nonhazardous solid wastes. The extent to which

RCRA will constrain increased coal combustion is unclear until all final regulations have

been promulgated. However, a preliminary industry analysis indicates that both ash and

sludge meet at least one criterion for the

“hazardous” designation. 78 If either were

listed as hazardous it would have to be disposed of in accordance with a State plan, and

the generator of the waste would be subject to

extensive record keeping provisions. If both ash

and sludge were listed as hazardous, RCRA

could prohibit the use of sludge ponds, increase the cost of waste disposal by as much as

84 percent, and foreclose the sale and/or use of

the wastes either directly or by making them

noncompetitive with raw materials.

COMPLYING WITH THE CLEAN AIR ACT

The three major strategies for complying

with the provisions of the Clean A i r Act are appropriate siting, pollution controls, and new

combustion technologies. The range of pollution controls and combustion technologies

avaiIable to minimize emissions from coal conversion are summarized in table 21.

Theoretically, complying with Federal emission restrictions should not be a problem. EPA

is supposed to set the restrictions for new

plants on the basis of demonstrated BACT.

BACT for control of particulate and NO,

emissions is relatively noncontroversial, although more stringent control measures could

be enacted in the future. SOX emission control,

however, is a matter of acrimonious dispute.

The proposed NSPS for S0x requires all new

coal-fired powerplants begun after September

1978 to use continuous technological controls,

For the immediate future, this is in essence a

requirement for FGD. This technology is described in chapter I I 1. The controversy surrounding its technological adequacy is analyzed here along with alternatives under development. The environmental costs and benefits

of applying it are discussed in chapter V.

The FGD Controvers y

The recent history of FGD has been one of

substantial disagreement between EPA and the

utility industry over reliability, secondary effects, and costs and benefits of scrubbers.

Most, though not all, of the operating FGD systems have experienced rather severe operating

difficulties such as scaling of calcium sulfate

on scrubber surfaces, corrosion of operating

parts, erosion of stack liners, and acid fallout

around the powerplants. Lime/limestone systems, the technologies that have been ordered

by most powerplants, produce large quantities

of calcium sulfite sludge that, unless specially

treated, has poor structural strength (and thus

does not provide a stable foundation) and represents a potential water pollution problem.

FinalIy, the forced installation of FGD wilI cost

78 The Impact o! RCRA (Public Law 94-580) on Utility

Solid Wastes (E Iectrlc Power Research Institute, E PRI

FP-878, TPS 78-779, August 1978)
168 ● The Direct Use of Coal

Table 21 .—Applicability and Status of Pollution Control Technologies

Pollutant

Applicability

reduction Residential

Pollutants and efficiency and

control technology (%) Utility Industrial commercial cost

s o2

Mechanical beneficiation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20-40

Low-sulfur coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Varies

Flue-gas desulfurization (FGD) . . . . . . . . . . . . . . . . . . 85-95

Current

Current

Current

Current

Current

Current (large

installations)

Very near term or

current

Post-1 980

Current

Current

Not suitable for

small boilers.

Not evaluated

Low

Variesa

High

Fluid bed combustion (FBC) . . . . . . . . . . . . . . . . . . . . . . . 80-90 1985’ Low to

moderate

Moderate to

high

Moderate to

high

Chemical coal cleaning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40-60 Post-1 980 Post-1 980

Solvent-refined coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70-90 Post-1 980 Post-1 980 Post-1 980

Coal gasification

Low BTU . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90–95 Post-1 980

(preferable for

new units)

Post-1 980 (larger

units) or industrial

parks.

Probably not

applicable

except in

commercial

centers

Post-1 980

(highly

applicable)

Post-1 985

Probably not

applicable

Not applicable

Moderate to

high

Post-1 980 (highly

applicable)

High BTU . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90-95 Post-1 980 High to very

high

Post-1 985

1980

Post-1 985

1980

High

Low

Coal liquefaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90-95

Coal-oil slurry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . varies

Magnetohydrodynamics (MHD) . . . . . . . ..9 0

FGD combined with mechanical

beneficiation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85–95

Post 1990 Nonapplicable

Current Current (large

installations)

Not suitable for

small boilers

Moderate to

high

NOX

Combustion modification . . . . . . . . . . . . ..20-8 0 Current for

some units

Post-1985

Current

Post-1985

Partially

applicable

Not suitable for

small boilers

Low

Flue-gas denitrification . . . . . . . . . . . . . . . . . .60-9 5 High

Particulate

inertial devices .-.~~=~-ti~-fi.-.-~~fi~fi.. 90

Electrostatic precipitators . . . . . . . . . . . . . ..9 9

Current

Current

Current

Current

Low

Moderate to

high

Moderate to

high

Fabric filters (bag houses) . . . . . . . . . . . . 9 9 Current Current

Scrubbers -.-....=.=..~.-.fi.....fi . . Current Current

a when western low-suff~r coal is used at thesource, the costlslow

bTvA(spresenfly plann[ngfora FBC powerplantwhtch Is expected tocome Onlmeln 1985

c Strictly speaking this IS not a sulfur oxide control technology, but rather a technology to utdue coal m boders designed foroti wfih mmlmal changes m boflerdeslgn If a hlghor

medium sulfur coal IS used, then the S02em@lonsWIH be higher than Ifod alone were burned

billions of dollars over what would have been a serious ecological problem in the Northeast.

required under the old NSPS, as well as several Finally, EPA claims that the issue of sludge

percentage points in lost electrical conversion disposal is more of an enforcement and cost

efficiency. Industry will acknowledge no sig- problem than a technological one; that technificant benefits from such an investment. On niques for stabilizing the sludge have been

the other hand, EPA can point to smoothly run- demonstrated; and that the volume, although

ning FGD units in Japan as well as a steady im- extremely large in absolute terms, is not disprovement in scrubber reliability in this coun- proportional to the volume of fly ash that the

try as counterweights to the industry’s reliabili- industry has been handling for many years. Enty arguments. In addition, EPA can point to the vironmentalists who either support EPA’s posirole of S02 as a precursor of acid rain, which is tion or who want stricter standards, point to
Ch. IV—Factors Affecting Coal Production and Use ● 169

the possibility, strongly disputed by the industry and by many in the health community,

that further controls on SO2 will lower mortality rates (see Health Effects, chapter V).

The level of controversy over these issues

has become so intense that it was felt necessary to add a discussion of the technological

arguments over the problems of FGD. The

health and ecological effects of SOx are discussed in chapter V, as are the mechanics of

disposal and the potential environmental problems associated with the sludge. The various

FGD systems are described in chapter I I 1.

FGD Status

The first FGD instalIation was made in

England in the 1930’s (the Battersea A powerplant, a 228-MW unit using alkaline Thames

River water as the scrubbing medium). In 1968

the Union EIectric Meremac Unit became the

first U.S. commercial installation, using dry

limestone injection in the boiler followed by

wet scrubbing Between 1968 and 1972, five

utilities had installed this type of system, but

al I encountered operating difficulties in the

form of plugging of boiler tubes, low removal

efficiency, and interference with particulate

colIection efficiency This technology is no

longer sold, and the five original systems are

either shut down or being converted to other

systems. This record, along with operational

difficulties with newer scrubber systems, has

created the basis for years of arguments and

controversy between EPA and the utility industry.

As of March 1978 there were 34 operating

FGD systems, totaling 11,508 MW, 42 systems

under construction (17,741 MW), and plans for

installation of 56 other units (27,230 MW), Of

the systems installed since 1968, EPA counts 15

(all “demonstration units”) as having been terminated. 79 With only a few exceptions, utilities

have chosen direct scrubbing with lime or

limestone as the scrubbing medium, Most of

the new systems have been retrofitted to ex7“’Summary of the Opera blllty of FGD Technology”

(Washington, D C U S Fnvlronmental Protection Agency, Office of Energy, Mlneral$, and Industry, Sept 14,

1977)

isting boilers, although this situation should

change within the next few years with the construction of new plants, which must comply

with the percentage removal requirements

stipulated by the 1977 Clean Air Act amendments.

Although EPA and the utility industry would

agree that most of the existing scrubber

systems have encountered operational problems, their viewpoints then diverge widely.

What follows is a simplified, abbreviated summary of the major EPA and industry arguments

about scrubbers. Note, however, that the utility industry is hardly a monolithic structure,

and thus the summary “industry argument”

shouId be interpreted accordingly. Some segments of the industry have found scrubbers to

be the best alternative for their plants and are

trying to make them work well,

The Industry Viewpoint

As electric power demand grows, constraints

on capacity growth will demand high levels of

reliability for individual units. The industry

contends that scrubbers are unreliable and

their use endangers the system reliability of

the powerplants they serve. They take the view

that virtually every scrubber that has been installed on a major unit in the United States has

had severe operating difficulties and major

shutdowns. I n many cases, these shutdowns

wouId have forced reductions in boiIer capacity except for the utility’s ability to bypass the

scrubber, New EPA regulations, if approved,

wilI eliminate these bypasses. EPA points to a

few smoothly operating scrubber systems, but

the industry counters that in every case these

systems have unique properties that avoid

problems that most plants have to face. In

some cases, this “smooth” operation is due to

almost continuous maintenance, such as nightly cleaning of the unit, which the industry does

not feel is practical or reasonable for the

average plant.

Case studies of individual plants illuminate

these problems (for more detailed descriptions

of actual operating experience at a number of

plants from an industry perspective, see appendix V of volume I l). For instance, the Southwest plant (Springfield City UtiIities), with 200
170 • The Direct Use of Coal

MW of scrubber capacity, started up in April

1977. Operation has been poor; only one of the

two scrubbers has been kept in service. The

operating scrubber is only 60-percent reliable,

with problems such as: (1) mist eliminator plugging, (2) corrosion of dampers, (3) failure of the

lining materials in the scrubber duct work and

stack, and (4) damage to nozzles and pumps

from foreign material in the Iimestone.

Another problem is that, due to a lack of

reheating for the cooled gas coming from the

scrubber, acid fallout around the plant has occurred. Another plant, the 830-MW Mansfield

powerplant (Penn Power), ran well for its first

year of operation because of the ability to cut

boilers back and thus maintain the scrubbers,

but it was reduced to half capacity after

failure of the stack liner, a problem that has

occurred elsewhere. Operation of this plant

has been said to be simplified because its

ponded wastes are being discharged to the

river rather than recycled. This has been said

to reduce scaling problems because the concentration of dissolved solids in the scrubber

circuit is kept low.

As noted above, some of the better experiences with scrubbers are felt by the industry

to be unique and inapplicable to general experience. For example, Paddy’s Run (Louisville

Gas & Electric) has received special attention

because it operates reliably and is quite effective in SO2 removal. However, critics point to a

number of factors that raise questions about

the validity of extrapolating the Paddy’s Run

design to larger installations (the units are only

35 MW each). The operation is said to be

atypical because the plant has a low load factor. Moreover, unlike other installations, the

unusually low-chloride content of the coal reduces problems associated with chloride buildup in the scrubber. Finally, the lime employed

by the system is a byproduct that is not

generally available and appears to have

unique properties that provide better operation than standard Iime.

Some of the major scrubber problems identified by the industry are:

. Achievement of high SO2 removal efficiency: Although high SO2 removal efficiency can be achieved, the problem of

achieving high levels without incurring excessive costs becomes very complicated

for the high removal levels that may be required by EPA. The major complicating

factors include the wide variety of scrubber types and selection of type and

amount of absorbent.

Wet-dry interface deposition: Drops or

slugs of slurry become detached, splash

back into the gas stream, and stick to surfaces.

Plugging and scaling of mist eliminators.

Gas reheat: The requirement to reheat the

scrubber gas to increase its buoyancy requires several percent of the total plant

output.

Corrosion/erosion: Especially due to the

chloride concentrations in the scrubber

liquids. Failure of the stack lining is a

common problem, as are plugging, erosion and corrosion of the reheater.

In short, industry feels that a commitment to

FGD is premature because the technology

creates problems that are substantially more

severe than those utilities have historically had

to face, the units require maintenance and

system debugging of a kind and intensity the

industry has heretofore been spared, and the

reliability of the units is seen as unacceptably

low or unproven.

Beyond technological problems, however,

the industry has severe economic problems

with scrubbers. They are the most capital-intensive controls it has ever been asked to install — in an industry that is currently undergoing capital shortages. The industry is being

asked to increase its power costs by as much as

15 to 20 percent even when no ambient air

quality standards or PSD increments are being

threatened. Moreover, where control of existing plants is required, the industry is almost

forced by the nature of its regulatory system to

prefer increases in fuel costs (i.e., switching to

low-sulfur coal) to installing capital-intensive

equipment. While general rate increases usually involve a lengthy hearing procedure, fuel adjustment clauses in many States allow the utilities to recoup immediately the cost of a fuel

switch.
Ch. IV—Factors Affecting Coal Production and Use ● 171

The EPA Viewpoint

EPA justifies its very strong support for FGD

systems despite the severe operating problems

by the following points:

● T h e industry, in its description of

“problems,” is said to ignore the progressive improvements both in debugging

existing scrubbers and designing new

ones. EPA concludes that the performance of utility FCD systems has consistently improved over the last 5 years, that

many of the problems described in the literature either are essentialIy solved or are

more in the nature of startup problems requiring differing degrees of “fine-tuning”

at each instalIation. Features of the newer

systems (improved mist eliminators and

reheaters, a trend toward open scrubber

types, high scrubber liquid to gas ratios,

improved materials) and newer systems

(double alkali, magnesium oxide) should

prevent many of the operational problems

of the past. EPA asks that the viability of

its FGD requirements be judged on the

basis of what designers can achieve today

and in the future, rather than on the basis

of units that were designed several years

ago and that were often improperly

operated and maintained.

● The Japanese experience with FGD is frequently cited as an indication that FGD in

this country could achieve far higher reliability if more optimum designs and more

intensive maintenance programs were

utilized, Japan has five exemplary coalfired facilities operating at greater than

90-percent removal efficiencies and 95-

percent operabilities. All are greater than

150 MW in size, and four burn 2 to 2.5 percent sulfur coal. A recent interagency report on these scrubbers80 notes their extremely high operability (degree to which

the scrubber is used when the boiIer is operating) and performance, while also concluding that their operating conditions are

not at all dissimilar to those applicable in

‘OM A Maxwell, et al , Sulfur Oxides Control

Technology in )apan, report prepared for Henry M

jackson, Chairman, Senate Committee on Energy and

Natural Resources, ) une 1978

●

●

the United States, In fact, some of the systems were designed and installed by U.S.

vendors. E PA can point to the Japanese

experience as one where basically the

same physical problem existed, but where

a completely dissimilar industry attitude

(one of commitment to scrubber success),

recognit ion of the need for careful

maintenance and chemical expertise in

operation, and a conservative attitude

towards design, materials, and contractor

accountability led to an extremely successfuI scrubber-based control system.

Utility industry shortcomings (EPA contends) are a major cause of FGD problems:

– Utilities’ tendency to select the lowest

bid regardless of vendor experience or

system design.

— Inexperience in dealing with complex

chemical processes, and unwillingness

or inability to hire trained operating

and maintenance personnel.

EPA notes that FGD units can build in redundancy, allowing a more intensive

maintenance program and compensating

for any unexpected failures. This translates a reliability problem into an

economic one.

Although EPA is concerned about the substantial economic impact of scrubber requirements, E PA’s viewpoint is different from that

of the industry. EPA is much more likely to

consider the public at large rather than utility

shareholders as its major “cons tituents,” and

thus will not automatically prefer a strategy

that will raise operating costs over capital

costs as the industry does. Second, EPA must

respond to the wording of the 1977 Clean Air

Act amendments, which stipulates the use of

technological controls for power production.

Interpretation

The substantial improvements in operating

experience of scrubbers in the United States,

the availability of new designs and new and

improved systems, and the excellent operability of the scrubbing systems on Japanese coalfired powerplants represent substantial evidence that FGD is both a perfectible technol-
172 ● The Direct Use of Coal

ogy and one that U.S. powerplants can install

with reasonable confidence that high levels of

reliability can be obtained.

The experience at the La Cygne (Kansas City

Power & Light) powerplant illustrates the improvement that has occurred with experience

in scrubber systems. The scrubber, which is

designed to remove 80 percent of the SO, and

most of the particulate matter from a very

“dirty” coal (5 percent sulfur, 30 percent ash),

was installed in June 1973 and initially experienced a very low 31-percent reliability.

This reliability has been gradually increased

over the past several years with experience in

proper operation and the appropriate materials to use in critical components. The current

reliability is 92 to 93 percent, and the manager

of the plant sees no reason why this level

should not be maintained or improved in the

future. a

’ This experience also is being applied

to scrubbers now being designed. The significance of this experience is that many of the

problems described by the industry are important only in a historical context, or in the context of understanding the problems that can

develop if utmost care is not taken in equipment design and maintenance.

The Japanese experience, as EPA claims, appears to indicate that the major FGD problems

are avoidable. Although many in the utility industry continue to challenge the applicability

of this experience to the U.S. situation, the

evidence indicates that the two most visible

criticisms — that the Japanese success has been

with oil-fired plants, and that their scrubbers

run in an open loop mode that is inapplicable

to U.S. utilities— are, respectively, no longer

true and incorrect. Although the highest sulfur

coal used in the Japanese facilities is only the

equivalent of a 3 percent sulfur Midwest or

Eastern coal, the La Cygne experience indicates that the problems of scrubbing very highsuIfur coal are not insurmountable.

The EPA proposal for an NSPS for S0x con -

trol of utility boilers asks for an 85-percent

reduction in SO2 emissions determined on a 24-

hour daily basis for most coals. A reduction in

‘

l Personal communication with Mr Cliff McDaniel,

Dec 4,1978

control efficiency to 75-percent removal is allowed for a maximum of 3 days per month. Although all of the existing Japanese coal-fired

plants meet these requirements, recently designed U.S plants have not been required to

meet them and have not met them. It would be

naive to expect that the problems associated

with scrubbers will evaporate even when (and

if) U.S. powerplants are asked to satisfy the

EPA standards. U.S. coal characteristics, utility

operating practices, and plant conditions vary

enough to ensure that each scrubber will require carefully tuned design and operation to

attain satisfactory performance. U.S. utility

operators must emphasize conservative design, extremely carefuI and constant maintenance, use of trained operating and maintenance personnel, and pressure on FGD vendors– just as the Japanese and the successful

U.S. operators have. To the extent that utilities

do not take these requirements seriously, they

invite scrubber breakdowns and consequent

loss of system reliability. At the same time,

EPA should share the responsibility for ensuring scrubber success by acting in a watchdog

capacity over vendor design and installation

and utility operations. EPA must take an extremely vigorous position in disseminating its

substantial experience; at a minimum, it

should sponsor a series of courses or seminars

for utility personnel who are responsible for

ordering FGD systems, to assist them in selecting systems appropriate to their needs.

In conclusion, existing evidence points to

FGD as a viable technology, albeit one with remaining problems. I n most situations, scrubbers should be able to obtain sufficiently high

levels of both control efficiency and reliability

to satisfy EPA and utility requirements. Some

doubt remains about satisfying EPA requirements for very high-sulfur coals, and both DOE

and the Utility Air Regulatory Group (UARG)

have expressed concerns about the need for

scrubber bypass capability for plants using

these coals.

Given the technological viability of FGD,

there remains the critical question of its costs.

Present estimates range from $80 to $120/kW

out of a total plant cost of about $800/kW.

Some utilities report higher FGD capital costs
Ch. IV—Factors Affecting Coal Production and Use • 173

wilI be necessary to achieve adequate reliability, DOE and EPA estimate the cost of the EPA

NSPS proposal by 1990 to be on the order of

$22 billion over and above the cost of the

previous standard. The accuracy of these and

other estimates is very much in doubt, given

the rapidly changing state of the art of scrubber design, the substantial degree of uncertainty as to the degree of scrubber module redundancy that will be needed to maintain the required reliability, the uncertainty as to how

risk-averse the utilities wilI be in their scrubber

purchases and operating programs, and the extent to which systems other than Iime/limestone are used Nevertheless, the order of

magnitude of the estimate is certainly correct,

and it demonstrates how much is at stake in

the current argument over NSPS. Both DOE

and UARG have proposed alternative standards that would reduce costs substantialIy with

smalI increases in emissions, However, none of

the actors in the regulatory process appears to

have analyzed the probable air quality effects

of any of these alternatives. The existing

analyses are based on gross emissions, which

are an inadequate measure of benefit. E PA, in

turn, has satisfied the requirements of section

I I I of the Clean Air Act by analyzing the

“nonair quality health and environmental impact” of the proposed standard, but it has not

attempted an analysis of the actual environmental benefits of the SOX reductions it

proposes to achieve. Thus, neither DOE nor

EPA has evaluated the relative costs and

benefits of the alternative NSPS options. This

raises some interesting questions about the

adequacy and policy orientation of the environmental research programs sponsored by

these agencies, as well as their attitude toward

the need to attempt to balance costs and

benefits.

Other SOX Control Options

In the immediate future the only significant

variant to the use of FGD as the total S0x control mechanism will be the use of physical

desulfurization in conjunction with the scrubber. Any sulfur removed in cleaning counts

toward the continuous removal required by

the Clean Air Act. Very few coals can undergo

sufficient sulfur removal to affect FGD designs

significantly. If 30 percent is removed in cleaning, FGD stilI has to remove 80 percent to meet

an 85-percent standard. However, despite its

failure to reduce significantly FGD removal requirements, coal cleaning does allow a significant reduction in limestone and sludge handling requirements and an improved operating

environment for the scrubber. FGD units are

sensitive to the variability of the sulfur in raw

coal and the presence of other contaminants

that may be partially removed by cleaning. For

some new plants, this combination of frontand tail-end cleaning can be economically advantageous. EPA82 has shown that, under some

limited conditions, physically cleaning the

coal before scrubbing lowers the total cost of

S OX control.

Current FGD technology may be inappropriate for control of smalIer, intermittently operated industrial boilers. Unit capital costs rise

sharply with decreasing size, and if a boiler is

used only 20 percent of the time, capital costs

alone make FGD prohibitively expensive. The

emissions standards for industrial boilers have

not been promulgated yet. If they are similar

to utility limitations, only the largest industrial

units will be able to comply; until new coal

combustion technologies are developed,

smaller units simply will not burn coal. If these

facilities and the even smaller residential/

commercial-size equipment are to burn coal

cleanly in the short term, it will be possible

only by feeding them “clean” coal and accepting a higher level of pollution per ton than

from utilities.

The list of options should lengthen considerably in the future. Fluidized bed combustion (FBC) is an efficient method of burning

coal while simultaneously controlling SOx

emissions. FBC furnaces can be smaller than

conventional ones; this should lower capital

costs. The residue of ash and sulfur compound

is dry, simplifying disposal. FBC currently is

developed to the stage that some industrialsize units are offered commercially. Utilitysize units stiII pose substantial design prob82Coal Cleaning With Scrubbing for Sulfur Contro l

(Washington, D C : U S Environmental Protection AgenCy, August 1977), E PA-600/9-77-017
174 • The Direct Use of Coal

Iems and may never offer any cost advantages

over FGD. Although the technology is expected to be able to meet all new emission limitations, the performance has not been demonstrated on a large scale. If FGD is required as

an add-on to FBC, as could theoretically happen, there would be little incentive to undertake FBC. The initial (and possibly sole) application would appear to be in industrial

units. If the units now on order work out as expected (and the British experience indicates

they will) a very rapid expansion could follow.

Low-Btu gasification is an intriguing nearterm development concept for utilities and industry. A combined-cycle facility should prove

more efficient than powerplants now in use,

and the economics look attractive. Industry

should find gasification more convenient than

direct coal use.

Solvent-refined coal, chemical coal cleaning, coal gasification (both low- and high-Btu),

and coal liquefaction are processes to produce

coal-related fuels that are clean enough to

meet emission limitations on combustion without the addition of FGD. “Clean” fuels assure

that emissions limitations always are being

met as long as the boiler is operating, regardless of load level. Those utilities that are least

favored in the capital market are relieved of

the capital costs burden of limiting emissions.

Instead, the capital burden would be on a coalrefining industry that, Iike the oil-refining industry, can operate at constant load factor

over the Iife of the equipment. Utilities are

constrained to follow the load demands of

their customers, and therefore have less flexibility even when output is reduced, which increases unit cost for pollution control. “Cleaning” of fuel, therefore, is in some ways more attractive than FGD — but the economics still are

questionable. “Clean” fuels also are applicable over a wider range of boiler sizes than

FGD. They provide greater flexibility in siting

coal-fired units. Existing units are more likely

to be adaptable to “clean” fuels than to FGD.

All the processes are currently under development except the Fischer Tropsch coal liquefaction technology, which has been in continuous operation in the Union of South Africa.

The costs for U.S. construction and operation

of this process, as well as most of the other

“clean” coal processes, are the major uncertainty. Thus, none of the processes is expected

to begin making much impact until the late1980’s. Chemical cleaning of coal is the only

one of the “clean” coal processes that would

require other control technologies in tandem

since none of these methods removes sufficient sulfur to comply with new NSPS. This

deficiency could limit its use.

NOX Strategies

The control techniques now in use in the

United States predominately involve combustion modifications. These techniques appear

adequate to meet present standards without

excessive economic penalty. Development of

IO W- N OX burners is underway, and if successful, could reduce NOX emissions still further (to 85-percent control) at little cost.

The “clean” fuel technologies remove various degrees of nitrogen along with the sulfur.

Coal gasification and liquefaction achieve

almost complete removal. Chemical cleaning

and solvent-refined coal are less effective in

nitrogen removal as currently operated.

FBC produces lower NOx emissions than

pulverized coal combustion because of its

lower operating temperature and larger coal

size. The first factor reduces atmospheric

nitrogen reactions and the latter controls fuel

bound nitrogen. This may prove to be a major

attraction of the technology.

Flue gas denitrification processes are in

various stages of development— mostly in

Japan– and are designed for oil-fired units.

Their commercial availability is not expected

for coal-fired units in the United States until

after 1985. These processes are considerably

more expensive than combustion modifications.

Particulate

EIectrostatic precipitators (ESPS) are the major particulate control technology for large industrial and utility boilers. They are likely to
Ch. IV—Factors Affecting Coal Production and Use • 175

remain the technology of choice for utilities

burning high- and medium-sulfur coal unless a

stringent standard for fine particuIates is promulgated. Such a standard is an eventual possibility because fine particuIates are suspected

of playing a role in health and ecosystem

damage that is disproportionate to their

weight fraction of the aerosol complex.

Baghouses have recently been installed on a

few utility units, They can be efficient collectors of fine particulate (ESPs are not) and they

do not suffer performance degradations when

low-sulfur coal is used, as do ESPs. Industry

has extensive successful experience with baghouses, but this experience is not fully applicable to utility requirements. Thus a testing

period is necessary, but there is no reason to

believe that baghouses cannot be applied successfuIIy to utiIity boiIers.

Control System/Fuel Compatibility

Coal-burning facilities must be designed as

integrated systems. Thus, change in one part

can affect others, and the switch of an existing

plant to lower sulfur coal can cause a large

loss to the efficiency of ESP’s. This particular

problem can be alleviated by use of flue-gas

conditioning, but other changes in control may

call for some extensive modifications. Existing

facilities might find a conversion to baghouses

from ESPs virtually impossible because of the

increased space and pressure drop requirement.

New plants must consider the effect of the

technology selected for control of each pollutant on all the other controls. Thus the use of

low-sulfur coal may force the use of hot side

precipitators at double the cost of a cold side

ESP with high-sulfur coal.

PUBLIC CONCERN

Expressions of public concern about energy

development are relatively recent. Until the

mid-l 960’s, active and organized opposition to

energy projects arose primarily among property owners over mining or combustion methods

that created nuisance-like conditions. In recent years, however, the increasing knowledge

about the effects of energy development, as

welI as the growing distrust of large institutions of all kinds and the general concern for

environmental quality and for future generations, has led to increasing opposition to

energy-related projects, This opposition is not

unique in American history; in many ways it

echoes late-19th century populist revolts

against the railroads and other large industries.

I n general, individuals appear to be increasingly unwilling to suffer personal and environmental risks, especially when they feel those

risks have been forced on them with few or no

counterbalancing benefits,

Initially, opposition to energy development

focused on nuclear power and surface mining,

but in recent years the trend has been spreading to coal-fired powerplants, transmission

lines, and coal transportation systems. Opposition at first was limited to environmental

groups, but recently such diverse groups as

agriculture, labor, Indians, and local governments are acting to protect their interests when

they perceive them to be threatened. In the

past, this opposition has been constructive

because it has focused national attention on

the problems and has resulted in remedial

legislation. For example, mine workers’ protests about occupational hazards resulted in

mine health and safety legislation and black

lung benefits; public protests about the environmental degradation from strip mining

brought the Surface Mining Control and Reclamation Act (SMCRA). However, even when

concerns have been addressed by legislation,

opposition to coal development can continue.

For example, many Appalachians continue to

oppose increased strip mining as well as

mining not covered by SMCRA.

I n order to devise more effective ways of addressing public concerns about coal growth,

better ways must be devised to involve affected parties in the decisionmaking process.

Federal, State, and local agencies that regulate
176 ● The Direct Use of Coal

energy development already have included in

their regulations extensive interagency consultation and public participation procedures to

ensure that all parties to development are

identified and their interests heard. Most

energy, natural resource, and environmental

legislation provides for citizens’ suits to ensure

that the purposes of the legislation are attained. In many situations these mechanisms

have adequately addressed public concerns

about coal development. I n others, however,

the parties have found that they lack the

resources to articulate or substantiate their

concerns in public hearings or that their

recourse lies with the legislature rather than

the courts. In these cases, delaying tactics and

civil disobedience have continued long after

the conventional mechanisms for resolving

disputes have been exhausted.

This section examines several cases in which

public concerns have not been addressed adequately and discusses some alternate approaches to resolving energy development disputes. It should be noted that these cases were

chosen because they do not fit the stereotype

of zealous environmentalists blocking development to protect scenic areas far from their

homes. Rather, these examples reflect disputes

that emerged spontaneously among people

concerned about their day-to-day quality of

life and their long-term economic well-being.

One of the most dramatic examples of the

failure of traditional citizen involvement

mechanisms to resolve public concerns about

coal-related development is the confict over a

transmission line in Minnesota and North

Dakota. The 470-mile, 400-kV direct current

transmission line being constructed by two

rural electric cooperatives (United Power

Association and Cooperative Power Association) will be the largest of its kind in the country. Any high-voltage line on farmland will

modify field work and irrigation patterns, Iimit

future land use, disrupt drainage patterns and

sometimes reduce the value of the land. The

line’s extra-high, direct-current voltage may involve health and environmental problems not

previously encountered. Uncertainties about

the potential health effects of the line’s electrostatic field make the farmers feeI their

families are being used as guinea pigs.

Much of the conflict surrounding the line

stems from the planning process by which the

route was selected. The line was routed under

the 1973 Minnesota powerplant and powerline

siting legislation, which authorizes the State

Environmental Quality Council (EQC) to determine routes based on recommendations from

utiIities and citizens. The Iegislation precluded

the use of parks and wildlife areas or highway

and raiIroad rights-of-way, thus forcing the Iine

onto farmland. Alternatives such as smaller

decentralized powerplants built near the load

center (rather than at the mine mouth) or underground transmission lines were not considered. The cooperatives misinformed EQC

about the line’s point of entry into Minnesota,

limiting EQC’s obligation to consider alternative corridors that might have crossed less

productive, less populated lands.

Minnesota officials feel they have a siting

process that protects individual rights and the

environment whiIe assuring timely and responsible energy development. The farmers were

included in extensive public hearings during

the siting process, and their Iawsuits have been

heard throughout the State court system. The

Governor and church officials tried (separately) to negotiate settlements between the farmers and the cooperatives through mediation.

The farmers received compensation for their

easements, and the siting legislation has been

amended to protect farmland in future route

selections. Yet the farmers continued to oppose the line, often using civil disobedience

tactics such as standing in front of surveyors’

transits. Although they are pleased that farmland will be protected in future routings, that

protection will not prevent this Iine from crossing their land. In addition, they object to the

use of heavy-handed tactics and mis-information by the rural electric cooperatives to force

acceptance of plans for energy development.

To the energy industry such continued resistance seems not only irrational but selfish

and irresponsible, given the role of northern

Great Plains coal in the administration’s

energy plan. Thus, where an extensive public

participation process was intended to produce
Ch. /V—Factors Affecting Coal Production and Use ● 777

consensus, instead the participants have

emerged from the process even more firmly entrenched in their individual and opposing positions.

A second example of public concerns that

have not been alleviated through the traditional mechanisms is the conflict over the

community impacts of Western coal development. Concern about these impacts has risen in

western towns such as Craig, Co I.; Rock Spring,

Gillette, and Wheat land, Wyo.; Colstrip,

Mont ; Farmington, N. Mex.; Moab, Utah; and

Page, Ariz, The rapid development occurring

in these areas creates confIicts among longterm residents, newcomers, coal operators,

and utilities, primarily over changes in quality

of life as well as the nature of the growth and

the responsibility for its adverse impacts. Longterm residents feel that their sense of community and continuity has been lost; coal miners

# .: j , . ‘ “ ,

. :

and plant construction workers often are not

included in community activities because they

are perceived as transients. Those who will

profit are in favor of the rapid growth; lowerincome groups that will not share significantly

in the community’s increased wealth are opposed. Long-term residents and local government officials, who are aware of the historic

cycle of booms and busts in the history of the

West, are skeptical of rapid temporary growth

but do not know how to control it. Coal developers, who could contribute to planned, orderly growth, tend to feel that the solution must

come from government.

Although the impacts of rapid development

of Western energy resources and the resulting

patterns of conflict have received widespread

publicity, little has been done to resolve them

beyond conducting studies and holding public

hearings. Rather, the early planning processes

,

Photo credit: EpA-Llocumerlca

John and Bud Redding with a chunk of the sub-bituminous coal that underlies their land and some

25,000 square miles of Montana and Wyoming

44- I(I2 [) - 7 I - ,?
178 • The Direct Use of Coal

in more recently developed areas continue to

repeat patterns that already have proved inadequate, such as minimal company support

(sometimes in the form of company towns that

provide housing but little more), ineffective or

misdirected government assistance, and a lack

of local money. Little effort has been directed

toward determining the region’s long-term

comparative advantages (as opposed to relatively temporary, “boom and bust” growth) or

toward accumulating resource tax monies that

could be used to promote long-term improvement. Unless means of adequately addressing

these concerns are found, active and organized opposition could develop in smal l

western towns slated for coal development.

Opposition to Western coal development already has arisen among ranchers and farmers,

who also are concerned about their quality of

life and sense of continuity. Many ranchers are

working land that has been in their families for

three and four generations. They are proud to

know that they were not pushed aside or

bought out by a corporation. They also resent

the extra taxes that have been imposed on

their land and their cattle to pay for coal

development in neighboring boomtowns. In

addition, ranchers are concerned about the

uncertainties associated with reclaiming arid

and semiarid western land, and especially

about potential disturbances to hydrologic

systems vital to agriculture. Yet the ranchers

are unable to counter effectively the influence

exerted by large energy companies. Again, little has been done to resolve these conflicts

beyond energy companies offering more and

more money to buy out ranchers, ranchers

expending large amounts of time and money to

educate themselves about environmental and

energy issues and to prepare for court battles,

and local government continuing to increase

cattle and property taxes rather than coal

severance taxes.

In these and other instances of public opposition to coal and related energy development, the most common mechanisms for attempting to resolve disputes have been public

relations campaigns, public meetings and heari rigs, studies, lawsuits, and legislation.

However, as is seen in the above examples,

none of these has been entirely successful.

Public relations campaigns present only one

side of a conflict and do not contribute to its

resolution. Although public meetings and hearings are designed to present all sides of an

issue, those opposing development generally

lack the resources to debate energy companies

effectively. Studies can be designed to explore

al I facets of development, yet they cannot analyze changes in quality of life adequately, and

they quickly become outdated. Lawsuits are

costly and time-consuming and often merely

serve to demonstrate to the parties that their

relief actually rests with the legislature. Yet

seeking new or amended legislation also can

be time consuming and usually only affords relief in future conflicts. And while lawsuits or

new legislation are being considered, uncertainties delay investments and increase economic risks.

Although each of these mechanisms may, to

some extent, reach a result that favors what

may be termed a common good or the majority view, present-day society increasingly seeks

to protect the rights of minorities and increasingly questions the definition of “common”

good. Yet an issue or conflict does not lend

itself to a simple resolution that simultaneously pleases both the majority and all minorities,

and no other traditional mechanisms are able

to respond when the minority continues to

rebel. This is especially true when the conflict

arises over ethical questions such as whether a

large corporation should be allowed to exploit

energy resources for profit without paying

local costs, as well as over questions related to

national long-term priorities, such as energy

versus agriculture.

However, some of the traditional mechanisms are amenable to modifications that

could eliminate or mitigate some future disputes. For example, in the case of the Minnesota powerline, if farmers had been given an

opportunity for public participation in the

planning stages of the development–rather

than at the permitting stage, when the cooperatives already had a vested interest in a particular route— the conflict might have been

resolved. Similarly, in the case of the community impacts from Western coal development,
Ch. IV—Factors Affecting Coal Production and Use ● 179

tax revenues could be used to ensure that the

affected States and localities receive an adequate share of the benefits of development to

promote long-term economic improvement.

New methods for preventing or resolving

conflicts must be devised. Two recent cases

that show promise are greater local control

over the manner in which development occurs,

as typified by the Navajo experience, and

mediation, such as the compromises negotiated during the National Coal Policy project.

The Navajo Nation owns an estimated 20

percent of U.S. strippable coal reserves. The

Black Mesa coal mining complex, one of the

largest in the world, is located on Navajo-Hopi

lands, as are major existing and planned coalfired powerplants. Yet Navajo per capita income remains at about one-third of the U.S.

average, their unemployment rate is about 40

percent, and they are becoming increasingly

concerned about the air quality and other environmental effects of coal use. The Navajos

have indicated that in the future they will demand more favorable leasing arrangements as

well as needed social and environmental benefits such as jobs, management training, and

pollution controls as prerequisites to energy

development on tribal lands. They already

have won the right to impose a possessor interest tax equivalent to a property tax on

powerplants and other energy development, as

welI as a business activities tax. They also are

attempting to institute an emissions charge

system in order to resolve their concerns about

the air quality effects of coal combustion. In

effect, the Navajos are ensuring their participation early in the planning stages of

energy development as well as ensuring that

revenue wilI be available for needed social and

economic benefits.

An even more promising mechanism is mediation of public concerns outside the courts,

legislatures, and bureaucracies in which developers and parties-at-interest negotiate a compromise. For example, a group based at the

University of Washington has successfully mediated a controversy over the route and size of

a major freeway. Recently a foundation-supported nonprofit corporation called RESOLVE

was formed to help -settle environmental disputes at the national level. In the energy area,

the National Coal Policy project was intended

to produce agreements on how coal can be

mined and burned without unacceptable externalities. In a series of meetings, leading conservationists and executives from coal-mining

and coal-consuming industries agreed in principle but not necessarily in practice on a variety of public concerns. For example, industry

accepted the principle that environmentally

sensitive areas should be closed to mining; the

environmentalists agreed to back off from

their insistence that surface miners always

must level off high walls. The environmentalists also agreed that their standard delaying

tactics in powerplant siting and licensing procedures are counterproductive and concurred

in a recommendation for one-step licensing. Industry representatives agreed that the public

should be notified in advance of license applications and assented to the principle that

qualified public interest groups participating

in mine and powerplant hearings should receive public financial support. The two sides

also agreed in principle that powerplants

should be sited near the area where the bulk of

the power would be sold, rather than at the

mine mouth or in a remote rural area. Some of

these and other agreements may require new

or amended legislation, but many could be implemented privately.

The National Coal Policy project has been

criticized because it did not include some of

the parties at interest and because the participants failed to agree on all the issues.

However, its example of conciliatory behavior

provides a model for speedier and wiser

alleviation of public concerns about energy

development. This and other models for constructive public participation in both shortand long-term energy planning must become

more common. Yet it must be recognized that

some public concerns about coal and related

development reflect basic value conflicts

rather than objections to specific projects.

Where these value conflicts exist, some people

wi I I continue to believe their rights are not protected. Thus, in some instances, even when

energy companies make every effort to an-
180 ● The Direct Use of Coal

ticipate and address legitimate concerns and considered, opposition in the form of lawsuits

to demonstrate that all alternatives have been and civiI disobedience will continue.

CONCLUSIONS

Many of the factors affecting coal production discussed in this chapter may limit the

pace of coal expansion in the future. Some

manifest themselves as temporary impediments to production — e.g., strikes and siting

disputes–while others have become ground

rules within which the industry must work. A

number of these factors enable coal to be produced, but become constraints in certain circumstances. For example, coal cannot be

mined without labor, but prolonged strikes by

miners can disrupt coal supplies. Rail transport

carries the bulk of the Nation’s coal each year,

but bottlenecks and car shortages slow down

the tonnage carried from mine to market.

The most important constraint on coal production has been lack of demand; it is likely to

continue to be the most important for at least

the next decade despite the rapid growth in demand projected in chapter II. The Clean Air

Act has been said to be a major constraint on

meeting national goals for coal development,

in part because of the requisite emission control equipment. This report does not concur.

The now mandatory SOX controls on new coalfired powerplants obviously increase the costs

of burning coal, but the evidence indicates

that the new standards can be met. This

evidence, it must be noted, is based on a

relatively few plants operating for only a few

years. Hence some utilities may experience difficulties with their control equipment, especially if they have not made the necessary

commitment of capital and manpower.

Despite the burden of regulations, labormanagement unrest, transportation breakdowns, and other constraints, most operators

report they can mine as much coal as they can

sell. 83 If coal demand grows faster than the

scenarios outlined in chapter II suggest, supply

constraints may become significant. If these

constraints do materialize, they are likely to be

found among the factors analyzed in this

chapter.

No insurmountable supply constraints now

exist. However, Federal leasing will have to

resume in the 1980’s for Western coal production to meet expected demand in the 1990’s.

Coal transportation systems need upgrading

and expansion, as is being planned. Existing

data are insufficient to determine whether industry structure has been or will be a constraint on production. I n recent years, poor

labor-management relations have cut into coal

production. However, as more and more coal

is mined in the West and from non-UMWA operations, this factor should become less important nationally. Even during the 3 IA-month

UMWA-BCOA strike in the winter of 1977-78,

few power shortages occurred and only 25,500

workers were laid off at the height of the shutdown. Further, wildcat strikes slacked off in

1978. Labor-management relations may either

be improving or each side may be regrouping.

The highest growth scenario would require

almost all supply and demand factors to work

out well. No new complex environmental control strategies could be accommodated in all

probability. All the major resources required

for production and use would have to be available. This situation is plausible, but it probably

will not occur without additional Federal

policy actions that promote the use of coal.

8JSee testimony of Stonie Barker, Jr., E B. Leisenring,

Jr., and Robert H, Quenon (coal operators) before the

President’s Commission on Coal, Oct 20,1978
Chapter V

ENVIRONMENTAL IMPACTS
Chapter V.- ENVIRONMENTAL IMPACTS

introduction . . . . . . . . . . . . . . . . . . . . . . . . . 183

Air Pollution Impacts ● *********8*.***** 186

Pollutant Emissions. . ...............186

Coal Activities Other Than

Combustion.. . . . ..............186

Combustion . . . . . . . ..............187

Sensitivity of Emission Estimates to

Assumptions. . . . . . . . . . . . . . . . ..195

Chemical and Physical Transformation

and Removal. . . . . . . . . . . . . . . . . . . .196

AtmosphericTransport. . ............198

Health Effects. . . . .................202

Introduction. . . .................202

Evaluating Health Effects. . ........202

Effects of Specific Combustion

Pollutants . ...................204

Effects of Air Pollution on Death

Rates . . . . . . . . . . ..............233

Quantitative Assessments of Health

Damage From Future Pollution

Levels . ......................21 6

Research Needs. .. .. .. ... ... ... ..21$

Conclusions. . . . . ................219

Ecological Effects. . ................220

Sulfur Oxides . ..................220

Nitrogen Oxides . ................222

Acid Rain . .....................222

Visibility Reduction . . . . . . . . . ....225

Particulates and Associated Trace

Elements . . . . . . . . . . . ..........225

Carbon Dioxide. . ................226

Effects of Materials . ...............230

Regulations. . . . . ..................230

lmpacts to Water Systems . .............232

Sources, Effects, and Control of Water

Pollution . . . . . . . ................232

Coal Mining and Cleaning. . ........232

Transportation . .................237

Coal Combustion . ...............237

Wastes From Coal Combustion. .. ...240

Regulations. . . . . ..................244

Impacts to the Land 246

Sources, Effects and Control of Land

Impacts. ...... . ...............246

Surface Mines. . . . ...............246

Underground Mines . .............249

Regional Factors. . ...............250

Mines Wastes . ..................251

Transportation and Transmission ....251

Coal Combustion . ...............252

Regulations. . . . . ..................252-

22.

23.

24.

25.

26.

27.

28.

29.

30.

31.

32.

33.

34.

35.

36.

TABLES

Page

Energy Demand Projection Used to

Develop DOE’s’’National Environmental Forecast No.1” . ............186

Environmental Control Assumptions

Used to Develop DOE’s’’National

Environmental Forecast No. 1“.. .....186

Gases Emitted From Burning Coal

Mine Refuse Banks in 1968 . . . . . . . . .,187

Distribution of Trace Elements in Coal

Combustion Residues . .............194

Reactions in the Atmosphere ., .,..,.197

Some Gaseous and Particulate

Substances From Coal Combustion. ...205

Nitrogen Dioxide: Levels and Effects ..209

Ozone(O3

) Levels and Effects . ......210

Health Effects of Sulfur Dioxide .. ....212

Health Effects of Sulfates. . .........214

Annual Projected Mortality From Coal

Combustion. . . . . .................218

Biological Concentration Factors for

Selected Trace Elements in Aquatic

and Terrestrial Environments . .......227

Acid Drainage in Mines. . ..........234

Water Requirements for Coal System

Activities. . . . . . . . . . . . . . . . . . . . . . ..237

Land Affected by Coal Utilization ..,.246

FIGURES

Page

19. Environmental Disturbances From

Coal-Related Activities. . ...........184

20. Jurisdiction of Federal Control

Legislation . . . . . ... ................185

21. SO2 Emission Contours—Emission

Densities in g/m

2

/year . .............189

22. Yearly Average Sulfate Concentrations)- 

ug/ m

3

. . . . . . . . . . ........... ..190

23. Nationwide Ambient NO3

Levels ug/m3 . . . . . . . . . . . . . . . . ..,191

24. National NOx Emission Densities, .

. 

g/m2

/year. . . . . . . . . . . . . . . . . . . . . . . . . . 192.,

25. Flow Diagram of Sulfur Transmossion ..-

Through the Atmosphere . . . . . . . . . . . . . 198

26. Annual Concentrations of Sulfate for a

1990 25.7 Quads Coal-Use Scenario 217

27. Regional lmpact of Acid Rainfall .. 223-

28. Heat Radiation Emitted to ..

Space by C 02. ... ... ... .. ..f.;,. .227.
Chapter V

ENVIRONMENTAL IMPACTS

Memories of the era when

soot-laden cities, discolored

INTRODUCTION

coal dominated the U.S. energy supply are blackened by visions of

streams, and scarred landscapes. Since the heyday of coal,

Americans have become not only “spoiled” by the cleaner fossil fuels —oil and natural gas — but

also more protective of their natural environment. They want to breathe clean air and drink pure

water, and they insist that, after its resources have been removed, the land remain capable of supporting both natural ecologies and a thriving agricultural economy. Thus, if coal is to return to

prominence in U.S. energy plans, its comeback must be staged under environmentally sound

methods of extraction, cleaning, transportation, and combustion.

The “residuals ’’-unintended products that

may affect the environment — from each operation involved in handling coal are illustrated

in figure 19. The avenues of disturbances to

the environment are abundant, and the intensity of even the minor disturbances will be magnified by the large quantities of coal forecast

by most current energy projections. The most

vociferous objections to coal use have

stemmed from concerns about the pollutants

released to the air during combustion and the

variety of damages to land and water that result from mining. Most of these impacts are

now addressed by Federal legislation, as indicated in figure 20. In general the legislation

establishes either ambient air, land, and water

quality standards, or minimum pollution control performance standards that can be

achieved economically and effectively by the

best state-of-the-art technology. In response to

the passage of this large body of environmental legislation, public attention is shifting to

questions of whether the new laws and technology are adequate, whether they are effectively enforced, and whether they are themselves the cause of environmental problems—

such as the pollution of one environmental

medium by the wastes collected to protect

another.

Figure 19 summarizes only the byproducts

of coal-related activities and not the resulting

effect on public health or on the ecosystem at

large. These effects may vary in their severity — from the annoyance and property damage

of blasting to a possible tragic increase in illness or mortality from air pollution. The effects also vary in their temporal and regional

extent— from the short-term creation of dust

at a local minesite to the possible long-term

global alteration of climate by carbon dioxide

(CO,). The environmental effects of coal also

differ from region to region, not only because

of the unequal concentrations of coal extraction and combustion activities but also because of the difference in geologic, demographic, topographic, and climatic factors.

Thus, for example, surface mining may be

more benign in the lignite fields of Texas than

on the steep slopes of Kentucky. As another example, the most significant impact of a coalfired powerplant in New England might be to

worsen the urban air breathed by millions,

while that of a utility in Utah might be to

degrade the quality and visibility of the clean

air that is a major resource in that region.

Figure 19 emphasizes that each environmental impact may be envisioned as primarily affecting one of the three media–air, land, and

water. This viewpoint is adopted as the organizational structure for this chapter, although it

should not obscure the very extensive interactions among the three media. Each of the next

three sections examines the impacts of coal

use on one of the three media, describes the

resulting effects on health or ecosystems, and

assesses the ability of relevant legislation and

control technology to mitigate these effects.

This chapter draws selectively on analysis of

future energy impacts available in the liter183
184 ● The Direct Use of Coal

Figure 19.– Environmental Disturbances From Coal= Related Activities

AIR

Polycyclic organic material

I Sulfur

Patiicles CO

Dust

\ ~ compounds

t Fumes from fires

Topsoil I Mine Waste

Polycyclic

organic material

t

Particles CO

4

Fumes from

t

Polycyclic

Trace elements Radionuclides organic material

Sulfur

compounds

/

fires

Coal dust

II Exhaust I Plant wast e +

t

Erosion

Flood danger

LAND Barge

Slurry pipeline

Land use

Changes and disruption,

ecological displacement

t

Thermal

n

discharge

+ f

Industry

Home

Waste

disposal

problem

ature — and especially on the 1978 National En- which assumes medium economic growth,

vironmental Forecast No. 1 (NEF #l)’ —to illustrate the level of residuals that would be generated by future increases in coal development.

The forecast uses a “business as usual” scenario developed by the Department of Energy’s

(DOE) Energy Information Administration,

‘1978 National Environmental Forecast No. 1, Division

of Environmental Impacts, U.S. Department of Energy,

September 1978 (draft).

medium energy supply expansion, and constant (corrected for inflation) world oil prices.

The scenario assumes an electricity growth of

4.8 percent per year, with total energy demand

growing from 70.6 quadrillion Btu (Quads) in

1975 to 94.6 Quads in 1985 and 108.5 Quads in

1990 (see table 22 for a more complete breakdown of the projections). Coal use is assumed

to double by 1990 to 25.4 Quads, from 12.8

Quads in 1975. Table 23 presents the environ-
Ch. V—Environmental Impacts ● 185

mental control assumptions used to predict Iutants. This projection is similar to scenario B

future emissions of the three principal air pol- in chapter II.

Figure 20.—Jurisdiction of Federal Control Legislation
786 ● The Direct Llse of Coal

Table 22.—Energy Demand Projection Used to

Develop DOE’S “National Environmental Forecast

No. 1“

(quadrillion Btu per year)

1975 1985 1990

Domestic Consumption

Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32.8 43.9 48.5

Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . 20.0 19.1 19.3

Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.8 21.2 25.4

Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.8 6.2 10.3

Hydro & geothermal . . . . . . . . . . . . . 3.2 4.2 5.0

Table 23.—Environmental Control Assumptions

Used to Develop DOE’S ’’National Environmental

Forecast No.1”

Revised NSPS

Industrial Industrial

boilers boilers

25MWe under

Pollutant Electric Utilities or greater 25 MWe

TSP Revised NSPS

.05 lbs/MM Btu

so, Revised NSPS

(scrubber

efficiency 89

percent)

NO, NSPS (.7 lbs/

MM Btu)

Schedule: For

revised NSPS,

all new utilities

on line in 1984

and after.

Pollutant Emissions

Coal Activities Other Than Combustion

Most concern about air emissions from the

coal fuel cycle centers on coal combustion,

the emissions of which can affect natural

ecosystems as well as human health and welfare over a broad region. The other portions of

the fuel cycle also have important impacts on

man and nature, although these impacts tend

to be confined to a more local area. Mining impacts involve primarily the fugitive dust from

surface and underground mines. After combustion, the dry disposal of ash or waste from fluegas treatment produces particulate loadings

that can be, on the site, in excess of Federal

standards.

2 This dust problem is naturally of

‘Report of the Committee on Health and Environmerita/

Effects of Increased Coal Utilization (“Rail Report”), F. R.,

vol. 43, no. 10, Jan. 16, 1978; “App. on Coal Ash and FGD

Sludges, ” U.S. Environmental Protection Agency,

Revised NSPS

.05 lbs/MM Btu

Revised NSPS

(scrubber

efficiency 89

percent)

NSPS (,7 lbs/

MM Btu)

Schedule: For

revised NSPS,

all new boilers

on line in 1981

and after.

Revised

NSPS .05

lbs/MM Btu

Revised

NSPS 1.5

Ibs S02/M M

Btu

None

Schedule:

For revised

NSPS, all

new boilers

on line in

1981 and

after.

AIR POLLUTION IMPACTS

greater intensity in arid climates. Other

sources of particulate are the construction activities at each stage of the fuel cycle, the

transportation of coal in open hopper cars or

on barges, the storage of coal or coal wastes in

piles, and coal processing and cleaning. All

particulate emissions that include either coal

dust or ash contain quantities of trace elements and radionuclides that may exacerbate

the health and environmental impact of these

emissions.

Additional releases can result from uncontrolled fires at mines or within mine piles. Such

fires, not uncommon, may smolder for years.

In January 1973, a survey counted 59 uncontrolled fires in abandoned mines in Appalachia

and 185 uncontrolled fires in unmined coal

seams in the West. 3 Another survey by the

‘Underground Coal Mining: An Assessment of Technology, EIectrical Power Research Institute, AF-219, July

1976,
Ch. V—Environmental Impacts . 187

Bureau of Mines in 1968 registered 292 fires in

coal refuse banks, principally in Appalachia.4

Because such fires burn under oxygen-deficient conditions, they generate a somewhat

different spectrum of air pollutants than coalfired boilers. Table 24 presents a crude

estimate of the emissions of carbon monoxide

(CO), hydrocarbons, sulfur oxides (S0x),

nitrogen oxides (NOx, and fine particulate

due to such fires. Other releases include

hydrogen sulfide and ammonia. It is reasonable to speculate that a significant portion of

the hydrocarbon emissions couId be polycyclic

organic matter, which is particularly dangerous; however, appropriate data are not available.

Table 24.—Gases Emitted From Burning Coal Mine

Refuse Banks in 1968

Percent of total

Emissions — nationwide

10’ tons emissions

Carbon monoxide. . . . . . 1.2 1.2

Sulfur oxides. . . . . . . . . . 0.6 1.8

Hydrocarbons. . . . . . . . . 0.2 0.6

Nitrogen oxides . . . . . . . 0.2 1.0

Fine particulate. . . . . . . 0.4 1.4

SOURCE Natlonwlde Inventory of Alr Pollutant Emlsslons. 1968, National Alr

Pollution Control Administration, AP-73, August 1970

Development of controls for these air emissions has not received the attention given to

air emissions from combustion. Dust from mining operations is not always completely controlled, and may be a serious occupational

health problem. Coal dust from trains can be

avoided by covering the hopper cars if spontaneous combustion of the coal can be

avoided. The dust from waste disposal sites

can be kept to a minimum by wetting agents

and its impact reduced by a buffer zone

around the site. Dust from coal hauling usually

is controlled by watering the roadbeds. Unfortunately, most of these controls are not required by Federal regulations, and State and

local requirements vary widely and often are

not strictly enforced.

The general techniques for prevention of

mine or refuse piIe fires are to reduce air cir4Coal Refuse fires, An Environmental Hazard (Washington, D. C.: U.S. Department of the Interior, Bureau of

Mines, 1971) I.C 8515

culation to the combustible material, minimize the concentration of combustible material, and promote cooling. For abandoned mines

these techniques may not always be possible

to apply. The best means of prevention is to

remove the excess combustible material and

seal holes where feasible. The Surface Mining

Control and Reclamation Act of 1977 requires

that combustible materials exposed, used, or

produced in underground mining (including exposed coal seams) be treated, if necessary, and

covered. The Act also requires that all openings to the surface be capped, sealed, or

backfilled when no longer needed for mining.

Presumably, enforcement of these provisions

will substantially decrease the incidence of

new-mine fires.

Combustion

The air pollutants released in large quantities by combustion units include the oxides

of sulfur, nitrogen, and carbon, as well as particles of ash that become entrained in the hot

flue gases. Smaller quantities of trace inorganic elements, radionuclides, and hydrocarbons are also emitted; these are often adsorbed on the surface of the ash particles.

Once emitted to the atmosphere, most of these

substances may be transformed by a variety of

chemical reactions, and all will be transported

and deposited under a variety of different

meteorological conditions. The polIutants may

react with other polIutants from the same or

different source or with natural atmospheric

components. The nature and extent of resulting human health hazards and environmental

damage depend on the types and rates of reactions in conjunction with the atmospheric

transport and deposition, as well as the nature

of the “receptor” —the ecosystem and/or

human population. This discussion examines

the emissions of each coal stack component.

The following sections discuss the transport

and transformation of each component.

Understanding of these factors is crucial to

predicting and mitigating the health or environmental impacts of coal combustion.

Sulfur oxides receive more attention than any

other emission from the combustion of coal,

primarily because of the large quantity of
188 ● The Direct Use of Coal

emissions, the diversity of and controversy surrounding the potential impacts (human health

effects, acid rain, crop damage, etc.), and the

great expense involved in SOX controls.

Coal combustion is a major source of mancaused sulfur emissions, and all of these

sources may now exceed the emission of sulfur

compounds from natural processes worldwide. 5 Estimates of the fraction of man-caused

sulfur emissions range from about one-third to

about two-thirds. b In industrialized parts of the

United States the man-caused emissions may

be at least an order of magnitude greater than

natural emissions. 7

Coal burning contributes more than half of

man-caused sulfur emissions and 80 percent of

the sulfur emitted from stationary fossil fuel

combustion. All stationary combustion

sources together release 70 percent of mancaused sulfur, with industrial processes running a distant second.8

The regional sulfur dioxide (SO2 “emissions

densities” (emissions per unit area) shown in

figure 21 exhibit a wide geographic variation.

The peaks in emission density do not necessarily correspond to peaks in ambient sulfate concentrations shown in figure 22, because of

complex transport phenomena that may carry

pollutants far from their source.

Total emissions of S0x may be expected to

decline slightly in the next decade if current

State implementation plans (SIPs) for air pollution control are strictly enforced, because the

effect of existing sources coming into compliance with local regulations in the next few

5R. B. Husar, et al., “Report on the International Symposium on Sulfur in the Atmosphere,” Third National

Conference on the Interagency Energy/Environment R&D

Program, 1978, p. 77.

‘E. Robinson and R. C. Robbins, “Gaseous Sulfur Pollutants From Urban and Natural Sources,” J. Air Pollut.

Assn. 20, 1970; Kellog, et al., 1972, “The Sulfur Cycle,”

Science, 175; and J. P. Friend, “The Global Sulfur Cycle”

in Chemistry of the Lower Atmosphere, S. 1. Rapeol (ed.)

(New York: Plenum Press, 1973).

‘R. B. Husar, personal communication.

‘Preliminary Emissions Assessment of Conventional

Stationary Combustion Sources: Volume II-Final Report,

GCA Corporation, GCA/Technology Division, EPA-600 2-

76-046b, U.S. Environmental Protection Agency, March

1976.

years should more than balance the addition

of new sources. NEF #l computes the following total SOX emissions for its moderate coal

use scenario:

1975 ....., . .........29.9 million tons

1985 . . . . . . . . . . . . . . . . 28.8 million tons

1990 . . . . . . . . . . . . . . . . 30.6 million tons

After full compliance has been achieved, SOX

emissions will begin to creep upwards. Coal

burning– and especially that from the electric

utility industry— plays a major part of this

trend. Electric utilities and industrial boilers

burning coal are projected to remain at their

present 70 percent of the total emissions

through 1990. Existing coal-fired powerplants

had 1975 emissions of 18.7 million tons; these

will decline to about 15 million tons if full

compliance is achieved, then drop only as existing plants are decommissioned. Utilities

commissioned after 1975 would have a maximum (no control) emission of 15 million tons

by 1990 under moderate growth conditions;

given the strong controls listed in table 23, actual net emissions will be about 3 million tons.

This imbalance between old and new source

emissions is a critical point, because it illustrates the need to consider existing sources in

devising a national S0x control strategy. Proposed New Source Performance Standards

(NSPS) for steam electric utility boilers will

cost tens of billions of dollars over the next

few decades but will reduce total emissions

less than 10 percent under emissions produced

under the current standards (as projected by

the Environmental Protection Agency (EPA)

and DOE in a joint, ongoing analysis). Meanwhile, the major sources of S02 emissions for

the next several decades—coal-fired powerplants already in existence— are allowed to

operate with far less control —and sometimes

none.

Industrial coal combustion also plays an important role in SOX emissions. Because industrial use of coal is expected to grow substantially in the next few decades, the NSPS will affect a higher percentage of the total emissions

than is the case with powerplants. Existing industrial plants emit about 2 million tons of

SOx/year . By 1990, new plants will emit about

half this amount if maximum control is as-
Ch. V—Environmental Impacts ● 189

Figure 21 .—S02 Emission Contours—Emission Densities in g/m2

/year

o

0.3

/

\ I

/

SOURCE Report on the International Symposium on Sulfates in the Atmosphere, in EPA-600/9-78-022, Energy/Environment Ill, U.S. Environmental Protection

Offfice of Research & Development, October 1978.

sumed. However, final emission standards for

industrial sources have not been established.

More than two-thirds of the S0x emissions

occur in the industrialized Middle and South

Atlantic States and in the Midwest, both in

1975 and 1990, although emissions will decline

in the Middle Atlantic and Midwest if existing

sources comply with local standards according

to schedule. Substantial emission increases

should occur in the Southwest and Northwest

as coal begins to replace natural gas as the

dominant fuel.

Nitrogen oxides from coal combustion are

associated with some plant damage, possible

health effects, acid rain, and production of

deleterious secondary pollutants. Unlike the

sulfur compounds, however, man-caused

sources produce only 10 percent of total NOX

emissions (50 million tons per year compared

to 500 million tons per year from natural

sources). NOX in the atmosphere consist priAgency,

marily of nitric oxide (NO), nitrogen dioxide

( N O2

), and small amounts of nitrous oxides.

About 95 percent of the NO, of manmade

origin is emitted from fossil fuel combustion.

The direct product is primarily NO, which is

readily converted in the atmosphere to the

more toxic NO2 and corrosive nitric acid

(HN 03

).

The amount of NO produced is determined

partly by the composition of the fuel itself.

Coal has considerable fuel-bound nitrogen,

and most of the NO produced by a normal

boiler is created by the reaction of this nitrogen with the oxygen in the combustion air. NO

is also produced by the high-temperature reaction between the oxygen and nitrogen in air;

this reaction is the sole NO source from the

combustion of nitrogen-free fuels (such as

natural gas). Coal’s high nitrogen content explains the major NOX control strategy for coal

boilers, which is to burn the coal initially in a
190 ● The Direct Use of Coal

Figure 22.— Yearly Average Sulfate Concentrations, μg/m3

10

SOURCE : Report on the International Symposium on Sulfates in the Atmosphere. in EPA-600/9-78-022, Energy/Environment Ill, U.S. Environmental Protection Agency,

Office of Research & Development, October 1978.

fuel-rich condition that promotes reduction of

NO to nitrogen gas (N2

), and then to allow

complete combustion after the fuel-bound

nitrogen has been depleted.

Combustion of coal accounts for 24 percent

of all NOX produced by man, and about 49 percent of NOX from stationary fossil fuel combustion. Mobile and stationary sources contribute about equally to the NOx national emissions. Although manmade sources are only 10

percent of all NOx sources globally, they can

result in high local concentrations. Thus,

although the natural background for NOX is

about 8μg/m3

, the national standard is

1 OOμg/m3, on an annual average, and shortterm local concentrations can be much higher.

Figure 23 shows the 1973 national emissions

densities for NOX

.

9 Spatial variability of NOx

‘National Emissions Report 1973: National Emissions

Data System (NDES) of the Aerometric and Emissions

Reporting Systems (A EROS) (Washington, D C.: U.S. Environmental Protection Agency, 1976), E PA-450/2-76-O07.

levels and composition is related to the quantities emitted, the availability of ultraviolet

light to affect chemical transformation, meteorological conditions, and the presence of

other contaminants in the atmosphere.

Because of the very large amounts of NOx

emitted by stationary and mobile sources, urban areas tend to have the highest NOX levels.

Figure 24 shows the ambient N03 concentrations on a nationwide basis, averaged by State.

Levels of NOX are subject to temporal as

well as spatial variation, because of the complex relationship of NO and NO2 to light intensities as welI as to the variation in time of emission levels from industrial and automotive

sources (strong time-of-day variations have

been observed and some evidence exists for

seasonal variations).

Although NOx emissions from automobiles

are supposed to decline in the next few decades, the lack of effective controls on station-
Ch. V—Environmental Impacts ● 191

Figure 23.— Nationwide Ambient NO3 Levels, μ9/m3

\

2

. . . . .

SOURCE: “Air Quality Data for Non-Metalllc Inorganic LOSS 1971-1974 from the National Air Surveillance Networks,” Gerald G. Akland,

EPA-600/4-77-003, Research Triangle Park, NC

ary sources wilI lead to a substantial increase

in total emissions. N E F #1 projects national

emissions to increase by 21 percent by 1990,

from 19,4 million to 23.5 million tons, reflecting both increased energy production and a

shift from gas to coal (coal combustion produces more NOx than natural gas combustion;

although the ratio varies, it is about 3:1 for

powerplants). Coal combustion by electric utilities and industrial boilers will play an increasing role in these emissions. In 1975, these

sources produced 4.6 million tons of NOX

, or

24 percent of total emissions; with a moderate

growth in coal use they will produce 8.7 million tons or 37 percent of the total by 1990. The

shift in emissions away from automobiles and

toward powerplants and industry should be accompanied by an increase in NOX concentrations in rural areas and possibly a slight

decrease in urban areas.

Coal combustion produces particulate

either by direct emission of primary particles

(fIy ash) or by release of gases that are “precursors” to the formation of secondary particles.

Secondary particulate include sulfates, nitrates, and particulate hydrocarbons.

Although particulate emissions from fuel

combustion sources are generally well controlled, the most common control mechanisms

are less efficient in controlIing fine particulate (those less than 3 μm in diameter). Thus,

proportionately more particles in this size

range escape capture and are emitted. In addition to this direct emission, most secondary

particles (particles formed by chemical transformation of gaseous pollutants) are also in

this size range.

Fine particulate have a greater impact on

visibility and are more Iikely than coarse particulate to become lodged deep in the lungs

and to travel great distances. I n addition,

directly emitted fine particulate have a larger

surface area than an equal weight of larger
192 The Direct Use of Coal

Figure 24.—National NOX Emission Densities, g/m2/year

SOURCE : “National Emissions Report 1973,” National Emissions Data System of the Aerometric and Emissions Reporting System,

EPA-450/2-76-007, Research Triangle Park, NC

particles and thus tend to adsorb on their surfaces a disproportionate share of the toxic elements in the flue gas.

Present regulations and measurement techniques are based on total concentrations of

particles, which may have little relevance to

their chemical or biological behavior. In recognition of this, EPA has recommended setting

a standard for particulate matter of less than

15 μm, and examination of the effects of particles smaller than 2 pm. Information gathered

by this examination may provide the basis for a

new “ inhalable particulate matter” standard. 10

Natural sources of particulate far outweigh

manmade sources but are difficult to measure.

Coal combustion yields 33 percent of the man-

‘“’’Health Effects Considerations for Establishing a

Standard for Inhaled Particulate Matter, ” EPA-HERL, internal publication, January 1978

made particulate and 90 percent of those

from stationary fossil fuel combustion sources.

All stationary combustion sources account for

36 percent of U.S. emissions, the second largest source after industrial processes, which

constitute 49 percent (NE F ##1 ).

Because compliance with all SIPs is far from

complete today, total particulate emissions

may decline quite significantly despite continued economic growth if compliance is

achieved according to schedule. NEF #1 projects a decrease in the total emissions from

14.5 million tons in 1975 to 8.2 million tons in

1985, with a rise (to 9.1 million tons in 1990)

thereafter that is characteristic of the assumption that future controls on both existing and

new emission sources will not change. Clearly,

at some point controls on particulate and

other pollutants will have to become stricter if

continued growth without unacceptable en-
Ch. V—Environmental impacts ● 193

vironmental degradation is to occur. Also,

none of these projections is likely to hold for

fine particulate, where emissions could increase sharply unless control strategies shift to

devices that are more efficient in collecting

particles in this size range.

The role of utilities and industrial boilers

will shrink from its present one-third contribution of total national emissions to one-fourth

by 1990 despite the substantial shift to coal.

The major portion of these particulate is contributed by coal combustion.

These trends differ substantially by region.

Slight increases in particulate emissions are expected in New England and the Southwest,

while substantial decreases should occur in

those regions that now have many noncomplying sources —the Middle Atlantic and Midwest.

Hydrocarbons from coal combustion may be

divided into two main groupings, corresponding to the way they are emitted. First, there is a

volatile fraction composed mostly of low molecular weight species that are emitted as

vapors. Second, there is a fraction of higher

molecular weight species that are emitted as

fine particulate or are preferentially adsorbed

on the surfaces of fine particulate. Although

EPA has recently increased its efforts to characterize these emissions, little reliable information exists on their composition. Available data indicate that for moderate to large

boilers (greater than about 25 MW), the volatile fraction (measured as methane) and particulate fraction (measured as benzene soluble

organics) are emitted in amounts of the order

of only a few milIigrams per cubic meter in the

flue gas. Emissions of polycyclic organic matter (POM), species of which are known carcinogens, are emitted in quantities considerably

smaller. The available data indicate, however,

that both the total hydrocarbons and the proportion of POM to the total may increase

substantially as boiler or furnace size decreases. For example, hydrocarbon concentrations in the flue gas of boilers less than 1 MW

in capacity were found to be more than 60

‘‘N. Dean Smith, Organic Emmissions from Conventional Stationary Combustion Sources (Research Triangle

Park, N C , U S Environmental Protection Agency,

August 1977)

times as great as those from utility boilers

more than 500 MW, while POM concentrations

were several thousand times as great (but still

less than 1 percent of the total hydrocarbon

emissions). 2

Recent EPA-sponsored tests on a

10-MW industrial boiler, on the other hand, indicated that POM emissions were either zero

or below the limits of detection of the

available equipment. 3 There are now 12 million tons of coal burned each year in the

residential/commercial sector, presumably in

small boilers and furnaces in populated areas.

The potential of these units, and additional

units in the future, to generate quantities of

the more toxic hydrocarbons is uncertain but a

source of concern.

Coal combustion plays only a minor role in

total hydrocarbon emission and will continue

to do so in the future. In 1975, coal-fired utility

and industrial boilers emitted about 70,000

tons of hydrocarbons, only one-half of 1 percent of national emissions. By 1990 these

boilers may double their hydrocarbon emissions and increase their share of the total to 1.4

percent. During this time, strict automotive

controls should (if the standards are successfulIy enforced) cause a sharp decline in national emissions from about 14 million tons in

1975 to 10 million in 1990. A notable exception

to this sharp decline will occur in those areas

slated for new petroleum and organic chemicals development. Thus, hydrocarbon emissions in Louisiana will increase somewhat in

the next decade, while emissions in Texas and

Delaware, sites of expected new refineries, will

remain relatively stable.

Inorganic trace elements and radionuclides are

emitted during coal combustion in particulate

form or as vapors that can condense or be adsorbed on the particulate in the flue gas as it

cools. These elements can be divided into

three classes:

1. those that are not volatilized and thus are

either left in the slag and bottom ash or

become entrained in the flue gas as particulates,

‘ ‘Ibid

“Personal communication with Wade Ponder, U S Environmental Protect Ion Agency, Research Triangle Park,

N C.
194 ● The Direct Use of Coal

2. those that are volatilized and are absorbed on the fly ash as the flue gas cools,

and

3. those that are volatilized and remain in

vapor form (see table 25).

Those elements that volatilize and become adsorbed are (as are the volatile hydrocarbons)

preferentially concentrated on smaller particles because, as noted above, fine particulate offer greater surface area than an

equal weight of larger particles for condensation and adsorption to occur. This presents a

serious problem in controlling trace element

(and hydrocarbon) emissions, as conventional

particulate control equipment grows progressively less efficient as particle size

decreases.

Table 25.—Distribution of Trace Elements in Coal

Combustion Residues

Concentrations of both trace elements and

radionuclides vary considerably among different coals. For instance, thorium concentrations are quite high in Pennsylvania anthracite

and low in interior bituminous coal (4.7 versus

1.6 parts per million (ppm), mean concentrations) while uranium varies from a high (mean)

concentration of 2.4 ppm in Gulf lignite to a

low of 0.7 ppm in northern Great Plains

coals. 4

Looking at different coal qualities or

14R, I van Hook, “Appendix on Trace Elements and Radionuclides, Oak Ridge National Laboratory, Rail Report.

“ranks,” lignite has the highest concentrations

of both radionuclides. This is unfortunate

because lignite is the lowest rank coal and requires the most tonnage to generate a unit

amount of electricity. Substantial variation

also exists between different coal deposits of

equivalent rank in the same region; some Wyoming and New Mexico coals are so high in uranium (up to 6,200 ppm) that the coal is essentially uranium ore.

Total emissions of most trace elements are

expected to decline between 1975 and 1990,

mainly because of increased particulate controls. The importance of such controls is demonstrated by an examination of arsenic emissions; electric powerplants produce more than

half of the gross (uncontrolled) national emissions but less than one-sixth of the total actually emitted (NEF #1), owing to the high particulate control levels in powerplants.

NEF ##l projects future trace metal emission

increases only in arsenic, cadmium, fluorine,

and selenium (however, it is not clear that

these projections account for increases in fineparticulate emissions); of the four, utilities and

industrial combustion are the major source

only of selenium. Selenium emissions are projected to increase from 1,270 tons in 1975 to

2,900 tons in 1990, nearly all from coal combustion. Although coal combustion is a substantial source of other trace elements, and its

emissions are unlikely to decline much in view

of the future growth of coal, controls on other

sources — such as smelters —wiII drive down

total emissions.

Carbon dioxide extracted during photosynthesis many millions of years ago is returned to

the atmosphere by combustion of fossil fuels.

Although CO, is naturally recycled through absorption by plants and by the oceans, the rapidly growing worldwide consumption of fossil

fuels could lead to increased concentrations of

CO, in the atmosphere. In fact, measurements

in Hawaii have shown approximately a 5-percent increase in COZ levels since 1958. Fossil

fuel combustion facilities may be the largest

manmade source of this emission with coal

yielding 11 percent more CO, than oil and 67
Ch. V—Environmental Impacts ● 195

percent more than natural gas for the same

energy value. 5 By projecting worldwide uses

of fossil fuels and by modeling COZ exchange

processes between the atmosphere and the

oceans and the biosphere, a number of studies

have developed estimates of atmospheric CO,

levels over the next several centuries. Most

show peak levels in the 21st and 22nd centuries

from two to eight times higher than today.

However, these estimates and their projected

effects are subject to considerable uncertainty. (See C02 under Ecological Effects.-)

Sensitivity of Emission Estimates

to Assumptions

Predictions of emissions are sensitive to

assumptions about rates of growth, energy

technologies used, environmental controls installed, quality of fuels burned, and other factors. Changes in the following assumptions are

especially important:

●

●

State Implementation Plan compliance. -

Virtually all forecasts of future emissions

assume full compliance by 1985 with existing State standards. There is substantial

pressure in many States to revise emission

standards upwards, especialIy for powerplants. The Mitchell and Kammer plants

in West Virginia recently won adjustments

in their SOX emissions reduction requirements, and the requirements for several

large plants, including Cliftie Creek in lndiana and Labadie near St. Louis, Me., are

under review. Also, assumptions of compliance for other sources—especially for

automobiles — may be too optimistic.

Growth rate.–The growth rates of electricity and coal demand are critical factors in determining emissions, yet are

highly uncertain. As an example of the effect of varying growth rates, emissions

from a “moderate growth” scenario (5.8-

percent electricity demand growth for

1975-85, 3.4-percent growth for 1986 to

2000, 1 billion tons of utility coal demand

by 2000) and a “high growth” scenario (5.8

percent for 1975-85, 5,5 percent for 1986

15Analysis of the Proposed National Energy Plan (Washington, D C : U.S. Congress, Office of Technology Assessment, 1977), p 161.

●

to 2000, 1,900 million tons demand by

2000) are compared for the year 2000.

Utility Emissions, Millions of Tons/Year16

Moderate High

SO, 140 171 (assuming 90-percent control

for new plants)

156 207 (assuming 80-percent control).

NO, 95 17 5

Higher growth rates will have a maximum

effect on those pollutants that are not efficiently controlled by available equip -

ment. Thus , ( N Ox and fine-particulat e

emissions are of particular concern in a

high-growth situation .

Environmental controls. -Most forecasts examine different versions of soon-to-be-enacted New Source Performance Standards

(NSPS) for steam-electric powerplants but

assume constant control levels after enactment. This is unlikely, as EPA must

periodically review these standards. The

very high levels of control achieved in

Japan for scrubbers imply that future SO,

emission standards may become more

stringent, thus lowering national SOZ

emissions below expected levels. Other

control variations that would affect emissions levels are:

—“Ful/ scrubbing” versus “sliding scale. ”

Although national utility S02 emissions

are not significantly different (in 1990,

19.6 million tons versus 20.2 million

tons) for the EPA proposal (for a

uniform percentage removal requirement) and the DOE proposal (to allow

utilities using low-sulfur coal to apply

only partial scrubbing), SOZ emissions

would be significantly higher in Western clean air areas under the DOE proposal.

— NOx controls. Since NOZ emissions are

expected to increase substantially from

expanded coal use, pressure for further

controls is likely to increase. The probability of such additional control depends primarily on the success of EPA’s

“Review of New Source Performance Standards for

Coal-Fired Utility Boilers, vol 1 (Washington, D C.: U.S.

Environmental Protection Agency, August 1978),

E PA-60017-78- 155A.
196 ● The Direct Use of Coal

NO, control program. A particularly

promising control technology appears

to be a IoW - N OX burner that has

achieved 85-percent emission reductions on a single full-size burner in the

laboratory. Preliminary indications are

that there may be little or no cost penalty for using these burners in a new facility. However, it is unlikely that sufficient full-size demonstrations can be

completed and an NSPS promulgated

before the mid-1980’s.

— Particulate standards. Electrostatic precipitators (ESPs) are less effective at

capturing fine particulate than are

baghouses (fabric filters) but are generally less expensive and can achieve required emission reductions except

when used with low-sulfur coals. Thus,

the effect of S02 standards on low-sulfur coal use will also affect particulate

control choices and, consequently, fineparticulate emissions.

It is clear that certain future conditions

could lead to levels of emissions substantially

greater than those projected. For example, a

greater than expected level of coal development coupled with a significant relaxation of

SIP control requirements could lead to significant increases in emissions of SOX and fine

particulate. NOX emissions would be significantly increased if energy demand increased at

a more rapid rate than projected.

Chemical and Physical

Transformation and Removal

As soon as each of the pollutants considered

here is released to the atmosphere, it is free to

participate in a complex series of chemical

and/or physical processes that alter its form

and location. Before the specifics of atmospheric chemistry are addressed, the following

general relationships and conditions should be

understood:

. Individual pollutants in the atmosphere

are not static. That is, they react with

other polIutants to give more or less harmful products, they decay, and they are ultimately deposited to varying degrees on

●

●

●

soil, waterbodies, forests, farms, residential developments, and all other areas of

the Earth’s surface.

On a large spatial scale, pollutants in the

atmosphere are not well mixed. Consequently, many air pollution problems are

localized over cities and large metropolitan regions. Further, climatological phenomena (such as inversions), topographic

features (such as the Los Angeles Basin

and the Appalachian Chain), and development patterns (such as the concentration of powerplants along the Ohio River)

can influence what pollutants are present,

in what quantities, and what types of reactions are taking place.

The nature of the atmospheric chemical

reactions is exceedingly complex and, at

present, incompletely understood. Important factors that determine the rate at

which the reactions occur are:

— The form of the reactants (gases or aerosols).

– The presence of catalysts (metals, light,

and other reactants). Some of these

may be present in the same emission as

the reacting substance, or may come

from other emission sources (including

natural sources); some may exist only at

certain times of the day or in certain

seasons.

– The concentration of reactants and type

of reaction. Doubling or halving the

amount of a particular pollutant present in the atmosphere will not necessarily double or halve the rate of formation of reaction products; reactions

often are nonlinear with respect to concentrations. This same nonlinearity applies to the eventual atmospheric concentration of the reaction products;

thus, reductions in “precursor” pollutants could, depending on the circumstance, produce proportionately greater

or lesser reductions in ambient concentrations of the secondary pollutants.

Considerable uncertainty exists as to

which chemical reactions predominate

under various atmospheric conditions.

This uncertainty results in severe difficulties in predicting the effects of new con-
Ch. V—Environmental Impacts . 197

trol strategies on concentrations of secondary polIutants.

Reactions involving S0x have been the most

intensely studied to date. The predominant set

of reactions involves the conversion of SOZ t o

some form of sulfate. The reactions believed

to be of major importance are summarized in

table 26. The importance of understanding the

mechanism of production is quite obvious

from the table. For example, indirect photooxidation requires free radicals often present

in a polluted atmosphere, and indicates that

conversion to sulfates may then proceed more

rapidly in urban centers, especially in daylight

or summer conditions. As another example, the

fourth reaction requires ammonia to convert

suIfuric acid to a sulfate salt. This buffering action could be important where acid rain was an

important problem; in such circumstances,

controlIing atmospheric ammonia couId be undesirable.

Removal of sulfur pollutants from the atmosphere takes place by gaseous, dry, and wet

deposition. Dry deposition (particles settling

out or coIIiding with surfaces) occurs continually, and is more important close to the

S OX source. Wet deposition (scrubbing of the

atmosphere by precipitation) is sporadic and

may be more important in regions remote from

the source. The relative importance of the two

mechanisms depends on the climate and the

form of the sulfur pollutant. However, from

observed data in temperate climates, wet and

dry removal of all S0x is believed to be of

roughly equal importance. 7 The relative importance of each deposition mechanism is different for each sulfur species, however; wet

deposition is 10 times more important for

sulfates than for SOZ

. Thus, keeping track of

precipitation is crucial in considering longrange transport of sulfates.

The mean residence time in the atmosphere

for SO, is about 1 day. For sulfates it is 3 to 5

17R. B Husar, et al., see note 5

Table 26.—Reactions in the Atmosphere

Catalyst/special

Reaction type Reaction conditions Comments

Heterogeneous catalytic

oxidation

Liquid water; metal ions

Water droplets

Water droplets
198 The Direct Use of Coal

days and for particulate S, about 2 to 3 days.

At a speed of 500 km/day, which is typical in

the Midwest, half the particles or molecules

would travel over 500 km, 1,500 to 2,500 km,

and 1,000 to 1,500 km respectively. 8 I n

temperate climates, 20 to 50 percent of SOZ is

converted to the sulfate ion before removal.

Overall rates of conversion ordinarily range

from about 1 to 4 percent per hour during the

day and less than 0.5 percent per hour at night

for an average daily rate of 1 to 2 percent per

hour during the summer. ’9 This gives a summertime S02 half-life of from about 11/2 to 3

days, Figure 25 shows, in schematic form,

sulfur removal mechanisms and the relative

contribution of wet and dry deposition.

The transformation of NO from coal combustion is less well understood than that of

S0x Although a variety of reactions involving

N OX are known, no reaction rates for actual atmospheric conditions can yet be assigned to

them. Important inorganic reactions involve

transformations between the oxides NO and

N O2 formation of N2 0 5 and reaction with

water to form HNO3. Organic reactions of NOX

‘81bid.

191 bid,

are particularly important. These result in

various complex organic nitrogen species, including peroxyacyl nitrate (PAN) and peroxybenzoyl nitrate (PBN). PAN and PBN are extremely damaging to plants and irritating to

animal tissues.

Gaseous, wet, and dry deposition are the

sinks for atmospheric NOX

, with the first two of

roughly equal importance and the dry deposition somewhat less important.

The chemistry of formation of polycyclic

hydrocarbons is both complex and incompletely understood. This subject requires more research, especially with respect to formation of

benzo(a)pyrene and other species of POM

from advanced coal technologies.

Atmospheric Transport

Superimposed on the chemical interactions

just discussed are the largely physical

mechanisms that govern not only the degree

and duration of the mixing among pollutants

but also the direction and distance to which

the reaction products are transported. These

physical factors may be divided roughly into

mechanisms that primariIy affect shorter range

transport and those that determine the extent

of long-range transport.

Figure 25.— Flow Diagram of Sulfur Transmission Through the Atmosphere. Over Half of the SO2 is Removed

or Transformed to Sulfate During the First Day of Its Atmospheric Residence

S04 Aerosol

SOURCE: Report on the International Symposium on Sulfates in the Atmosphere, in EPA-600/9-78-022, Energy/Environment Ill, U.S. Environmental Protection Agency,

Office of Research & Development, October 1978
Ch. V—Environmental Impacts ● 199

The short-range geometry of the plume is

critical to both short- and long-range transport.

Under some conditions, the plume spreads

quickly to the ground level (“fumigation”) and

high concentrations of primary pollutants may

result. Under other conditions, the plume remains isolated in a narrow vertical layer that

disperses little and travels far (“fanning”), carrying high levels of secondary products far

from the source. A variety of other possibilities

falls between these two. Each type of plume

behavior is associated with different atmospheric conditions.

An important factor in the short-term dispersion of pollutants is the vertical temperature

variation with altitude. I n daylight hours of intense sunlight, air that is heated by the warm

surface continually rises, causing the atmosphere to be unstable and well mixed. These

conditions promote the local deposition of

pollutants, especially when persistent surface

winds are Iight. Under the conditions of a temperature inversion (warmer temperatures at

higher altitudes)–whether it is caused by

nighttime cooling of the surface faster than

the air or by a cold air mass sliding under a

warm air mass—the air layers are stable and

do not mix. At these times, effIuents from moderate stack heights may be trapped below the

inversion, while those from tall stacks may

become embedded in the layers above, and

hence subject to longer range transport. Nighttime conditions often lead to fanning plumes

that remain in a narrow region and may be

transported especially rapidly by a nighttime

jet stream.

Other local factors determine the extent of,

vertical mixing of a plume. One is the wind turbulence caused by rough terrain, surface obstacles, or variation of wind speed with altitude. Another is the local wind pattern, such as

the urban-rural wind or the land-sea breeze. If

the local wind system becomes a temporary

closed loop, pollutants can be sloshed back

and forth with no real dispersal, and production of secondary products can further deteriorate the air quality until the cycle is broken.

Once the plume type has been determined

by short-range transport mechanisms, several

long-range factors govern the way the pollutants travel. Before 1973 there was little documented evidence to suggest that air polIutants

were transported in significant quantities to

regions remote from their origin.

Numerous studies since then have confirmed that this phenomenon does indeed occur.

One such example is the plume of the

Labadie Power Plant, outside of St. Louis, Me.,

which has been extensively tracked by the

EPA’s Project MI STT. This plume has been

followed for more than 180 miles, and at that

distance its width was not much greater than

15 miles. Other examples include the Electric

Power Research Institute’s (EPRI) SURE program’s observations that sulfate episodes in

West Virginia occurred only when the air mass

over the area had first traveled over highemission regions; satellite tracking of “hazy

blobs,” masses of polluted air that have been

observed over the Midwestern and Eastern

United States, lasting for more than a week;

and observations and analyses of acid rain in

Europe, where Scandinavian rivers and lakes

have apparently been degraded by long-range

transport of NOX and S0x from the United

Kingdom and other Western European countries .20

One of the four factors important in longrange transport is the blend of local factors,

discussed above, that determine dispersal of

pollutants from a given source. Local conditions promoting long-range transport are tall

stacks, nighttime or cloudy conditions, and

relative constancy of wind speed and direction

with altitude.

A second factor is the persistence of surface

winds, These have been studied in great detail

at many stations in recent years. It has been

found that many regions are characterized by

surface winds that persist for 6 hours or more

in a given direction (or, to be more accurate,

within a narrow anguIar sector). They help determine the dominant direction(s) of transport.

A third factor is the type of winds prevailing

at the altitude typical of plant stack heights.

These, too, are characterized by dominant directions that often may differ only slightly

20 Altshuller, et al, “Appendix on Transport and Fate, ”

Rail Report.
200 ● The Direct Use of Coal

Photo credit: EPA —Documerica

Conditions leading to long-range transport of a plume from a coal-fired powerplant: persistent winds,

and a stable atmosphere

from that of the persistent surface winds. Thus,

the two often couple positively to carry pollutants still longer distances from their point of

generation.

These last two factors can contribute to the

additive effect of pollutants from several

sources. Because the winds tend to blow more

frequently in some directions than others, any

emission sources Iined up in the same direction

will contribute to intensification of pollution

concentrations. For example, powerplants

clustered along the Ohio River are also in line

with prevailing winds blowing to the northeast;

occurrence of these winds has been correlated

with high pollutant concentrations in Pennsylvania and other States to the northeast.

A final factor is the large-scale meteorological conditions resulting from the relative

movements of low- and high-pressure systems.

These conditions can create large regional

areas of stagnation.

Several research organizations are developing long-range transport models and are currently using such models primarily in an experimental mode. Models in current use have

not undergone extensive peer review and thus

are not Iikely to be immediately acceptable for

regulatory purposes. This situation could

change drastically within a short time— perhaps a year– and conceivably lead to greater

regulatory attention to long-range transport

problems.

Although long-range transport models are

still not fully verified, regions of the United

States can be surveyed for some of the key factors in long-range transport mentioned above.

Data compiled by Teknekron for EPA on re-
Ch. V—Environmental Impacts ● 201

gional air quality and aerometric parameters

yield the following brief survey .2’

One potential air quality problem lies in the

West, especially in the northern Great Plains

and southeastern Utah, an area slated for considerable future powerplant development.

Many areas nearby currently are designated as

Class I (i.e., areas where air quality is to be

strictly protected, with very Iittle development

allowed), and many of these lie in the direction

of extremely persistent winds coming from

21An Integrated Assessment of EIectrlc Utlllty Energy

Systems Briefing Material s,” prepared for EPA/NASA

Meeting on Cooperative Program on Synoptic Regional

Air Pollution Problems, Sept 11-12, 1978, by Teknekron

Inc , Berkeley, CaIif , and Waltham, Mass/pt 2, Aerometric Data Compilation and Analyses for Regional Sulfate Modeling

areas with a large number of current and projected urban and utility emissions sources. In

addition, the prevailing winds tend to be from

the south and may entrain elevated levels of

sulfates from smelters in the Southwestern

United States.

The gulf coast is expected to increase its

utilization of coal, partly in response to the

growing development of lignite fields. These

fields lie primarily in eastern Texas and are

alined approximately parallel to the prevailing

wind direction (from southwest to northeast).

If powerplants develop along the same line, intensification of concentrations may result.

The region that has been the most heavily

studied for air pollution transport is the Ohio

River Basin. This region not only contains a

large cluster of coal-fired powerplants but also
202 ● The Direct Use of Coal

exemplifies some of the meteorological factors that contribute to long-range transport. Extremely persistent winds in the Basin lead to

intensification of pollution levels from a string

of sources. Prevailing winds in the Upper Basin

blow predominantly east and north, carrying

polluted air as far east as Pennsylvania and

beyond, while winds in the Lower Basin carry

pollutants north into Canada.

Several regions in the Eastern United States

have been found to be susceptible to prolonged atmospheric stagnation. Many of those

cases are centered over a line from southern

West Virginia to Georgia. Although emissions

are generalIy low along this region, they are expected to grow.

Health Effects**

Introduction

It is known that very high levels of air pollution cause illness and death. Present ambient

air standards are well below these levels, and it

is unlikely that episodes of high concentrations of “criteria pollutants” similar to the

notorious catastrophes that occurred in

Donora, Pa., in 1948 and London in 1952 will

be repeated in this country. However, occasional episodes of adverse meteorological conditions such as those that occurred in the

Northeast during November 1966 could lead to

high (and possibly dangerous) levels of currently unregulated pollutants. Also, elimination of

acute, high-concentration episodes does not

preclude the possibility of chronic damage and

life shortening as a result of exposure to low

levels of pollution. The existence of these

types of effects is quite difficult to establish

because the damages may take the form of

common illnesses (e. g., bronchitis, asthma,

cancer) that are known to have other causes

and would not necessarily be attributed to air

pollution. The effects, if any occur, would also

tend to be masked by the very widespread dis-

‘

2

This section summarizes a detailed and extensively

referenced report on health effects to be published

separately as an appendix to this report. Full referencing

of source material was considered impractical for this

summary

tribution of air pollution and the large number

of different polIutants usualIy present.

Increased coal combustion will eventually

increase the ambient concentrations of SOX

,

N OX

, fine particulate, and other pollutants, as

discussed in the previous section. The population exposed to the increased concentrations

will be large because pollutants travel long

distances and, due to prevailing wind patterns,

will be concentrated along the heavily populated Eastern seaboard. The present regulatory

structure fails to address this problem directly.

If present and projected levels of ambient

pollutant concentrations are shown to cause

severe chronic effects, the implications for

coal use and the degree of control to which it

is likely to be subjected wilI be profound.

Evaluating Health Effects

The determination of the potential of a substance for causing adverse health effects can

be accomplished by combining the results of:

1 ) short-term tests, 2) animal bioassays, 3)

chamber exposures to human beings, and 4)

epidemiologic studies on human populations.

Short-term tests expose tissue, cellular, and

microbial cultures to controlled levels of pollution to measure toxic effects, such as cellular or bacterial death, or mutagenic changes

refIecting alterations in genetic structure.

Animal bioassays are used to measure acute

and certain chronic effects. Tests for acute toxicity may measure the dose that causes death

or impairment of target organs such as the

lungs, kidneys, liver, reproductive system, etc.

Chronic effects might include gradual impairment of target organs (e. g., chronic bronchitis

through long-term insult to the lungs), teratogenic effects, or carcinogenesis.

Exposure studies using human beings are restricted, for ethical and legal reasons, to

(usually) short durations and exposure levels

no greater than might be expected in the normal working or outdoor environment. Further,

“health effects” induced by controlled human

exposures are limited to those responses that

are known to be reversible, such as increased

carboxy-hemoglobin levels in the blood or
Ch. V—Environmental Impacts ● 203

changes in airway resistance. Controlled

studies of the short-term effects of air pollutant exposures to human beings provide a vital

link between toxicologic animal studies and

large population epidemiologic studies.

Photo credit: EPA — Documerica

Tests on mice are used to measure acute and chronic

health effects

Photo credit. EPA —Documenca

Clinical studies on humans are limited to pollution

levels that result in treatable health problems

Epidemiologic studies are statistical examinations of illness and death rates, air pollution

levels, and other variables–studies that seek

to discover whether there is a direct correlation between a suspect air pollutant and adverse health effects. As such, they extend beyond the function of short-term tests and animal bioassays that are used to identify the

mechanism of damage and the dose response

function of the substance under study, and attempt to quantify those effects in human

beings.

All of these methods of assessing health effects are necessary to establish the damage

potential of a substance. Animal tests are insufficient by themselves because a biological

effect in any living system cannot always be

applied to a biological effect in others.

Although the cellular or subcellular effect may

be similar, the clinical effect may be quite different. The chamber tests can show human

sensitivity to the substance, but it is impossible

to infer from studies exposing 5 to 20 subjects

to low levels of the substance for relatively

short times what the chronic morbidity or mortality effects on the entire population may be,

Finally, epidemiologic studies can establish

statistical associations between a substance

and damage to human beings, but they cannot

prove cause and effect; the short-term and animal tests, by establishing the existence of

damage mechanisms, and the chamber tests,

by demonstrating human sensitivity, provide

credibiIity to the cause-and-effect argument,

The epidemiologic studies have proven to be

a weak link in the analytical chain needed to

establish air pollution standards that wil l

guard against chronic health effects. The

studies that have attempted to examine the effects of low levels of pollution on the health of

the general population have run into several

problems:

heterogeneous populations with different

thresholds to particular toxic substances

and different socioeconomic characteristics;

very poor measurements of pollution levels — in most cases, the limited number of

monitoring sites and the failure to incorporate levels of pollution indoors lead

to poor determination of the pollution

levels that the population is actually exposed to;

outright failure to measure some potentially important pollutants (such as fine

particulate);

lack of data on variables (such as smoking

habits) that are important determinants of

health;

wide variations of pollution levels with

time, raising the question whether any

observed health effects are caused by the

mean levels or the occasional peaks; and
204 ● The Direct Use of Coai

● presence of multiple pollutants that might

act in combination.

Some of these problems are discussed in more

detail later in the context of epidemiologic

studies of sulfate damage to human health.

Effects of Specific Combustion Pollutants

Coal combustion releases a mixture of gases

and particles into the atmosphere. These include sulfur compounds, nitrogen compounds,

fly-ash particulate, CO, CO2

, hydrocarbon

vapors and particulate, radionuclides, and

many trace metals. These emissions may lead

to the formation of secondary pollutants, including photo-oxidants and particulate.

Human beings are exposed to a complicated

mixture that may act additively, competitively,

or synergistically. However, clinical studies

have seldom examined more than two pollutants in combination. Even epidemiologic

studies, in which the populations are exposed

to the entire gas-aerosol mixture, rarely attempt to sort the effects of more than two of

the pollutants of the mix. This adds to the

uncertainty of predicting health effects from

future coal use.

The following discussion summarizes the

health effects of specific pollutants from combustion. Table 27 presents the acute and

chronic effects of specific gases, elements, and

particulate compounds that are emitted from

coal combustion. Little is known about the actual magnitude of the effects attributable to

increased coal use. The ambient concentrations of radionuclides, organic compounds,

and various trace metals due to increased coal

combustion are projected to be very low. However, these polIutants are stilI a concern because of multiple exposures from other

sources. Health effects from these pollutants

are Iikely to appear first in the population

working in coal conversion or related technologies because exposures wilI be higher.

Total suspended particulate (TSP) are composed of many different substances. The ambient aerosol (suspension of solid and liquid particles in air) includes trace metals, radionuclides, and organic compounds, as well as silica and other minerals. TSP can be roughly

divided into fine (usually defined as less than 2

or 3 pm in diameter) and large particulate.

This differentiation is important because:

1. Fine particulate are not explicitly regulated and are not as efficiently controlled

by existing technologies as the large particles.

2. The most significant route of exposure to

air pollutants is through inhalation. Fine

particulate can pass through the filtering

mechanisms of the upper respiratory tract

and penetrate deeply into the lungs. Several studies using zinc ammonium sulfate

and sulfuric acid aerosols have demonstrated that small particles result in

greater functional and structural changes

in the lungs than result from larger particles of the same substance.

3. Toxic substances, either gases or recondensed metal vapors, can be transported

into lung tissues by inhaled fine particles.

A unit mass of fine particulate has a

greater total surface area than the same

mass of large particulate, hence can

transport more toxic material on its surface.

Thus, although there is not much explicit

evidence defining their impacts on health,

fine-particulate emissions are a primary concern in considering the impacts of expanded

coal combustion.

Both chemically inert and active aerosols

have been shown to alter the mechanical

behavior of the lungs, The principal response

of different aerosols as measured by animal

and human control led studies is to increase air

flow resistance in the lungs, This indicates that

lung airways are in some way altered. Several

physical mechanisms are known to cause thi s

symptom: reflex constriction of the trachea

and bronchi, excessive secretions of mucus,

edema, and local enzyme stimulation causing

smooth muscle constriction. In general the

deeper that relatively insoluble particles are

deposited in the lungs, the longer the time required for their clearance, Some particles,

such as asbestos fibers, penetrate the lung lining and lodge in the interstitial space or are

carried by the lymphatic and circulatory sysens to other body sites. In these cases, the
Ch. V—Environmental Impacts ● 205

manifest health effects may not be respiratory,

but rather carcinogenic or systemic. The toxic

elements contained in insoluble aerosols may

uItimately affect extrapuImonary tissue irrespective of where they enter the body.

Besides changing airway resistance or causing systemic changes, aerosols can cause harm

by altering lung clearance, transporting dissolved gases that may damage lung tissue, and

affecting the compliance (tissue elasticity) of

the lung (the importance of the transport of

dissolved gases makes it very difficult to consider the health effects of specific chemical

compounds or particulate in general without

considering gas-aerosol interactions). A number of coal-related aerosols have been studied

in animals and human beings. These include

several sulfates, chemically inert dusts, metal

oxides, and fly ash. Surprisingly, the effects of

nitrate aerosols have not been reported.

Table 27.—Some Gaseous and Particulate Substances From Coal Combustiona

Toxicity

Sources of Environmental

Substanceb Acute Chronic Pollution standards Comments

Sulfates Increased

respiratory

disease;

breathing

difficulty in

asthmatics.

Organic matter Unknown for

many compounds.

Specific

toxicity for

others.

Pulmonary irritation,

chronic

obstructive and

restrictive lung

disease.

Respiratory disease

and increased

mortality

suspected.

Long-term is potentially carcinogenic

and mutagenic.
206 ● The Direct Use of Coal

Table 27.—Some Gaseous and Particulate Substances From Coal Combustiona–Continued

Toxicity

Sources of Environmental

Substanceb Acute Chronic Pollution standards Comments

Beryllium

Cadmium

Arsenic (oxide forms) Effects large to

small

depending on

form and

route of

exposure;

rarely seen.

Short-term

poison at high

concentrations,

especially

toxic by inhalation.

Very toxic at

high

concentrations; to

animals

and aquatic

life. Toxic by

all routes of

exposures.

Chromium

Mercury

Selenium

Carcinogen, and

teratogenic

cumulative

poison.

Long-term systemic

poison at low

concentrations;

carcinogenic in

experimental

animals

Possible

carcinogen,

cumulative

poison;

associated with

hypertension,

cardiovascular

disease, kidney

damage

Weathering; mining,

and smelting; coal

combustion;

pesticides;

detergents.

Industrial; combustion

of coal, rocket fuels.

Weathering; mining

and smeiting,

especially of zinc;

iron and steel

industry; coal

combustion; urban

runoff; phosphate

fertilizers.

0.05 mg/1

drinking

water.

0.01 pg/m3

hazardous air

pollutant

0.010 mg/1

drinking water

40 ~g/1/day

proposed

effluent

standard

(withdrawn)

. .

Methyl mercury

and mercury

fumes very

toxic; other

forms of

variable

toxicity

Soluble

compounds

are highly

Probable

carcinogen; also

essential for life.

No chromium now

mined in U.S.

Emissions from

industrial processes,

including

electroplating,

tanning, dyes; coal

combustion.

Weathering; volcanoes;

mining and smelting;

industrial;

pharmaceuticals;

coal combustion;

sewage sludge;

urban runoff;

fungicides.

Natural; mining and

smelting; industrial

process; coal

0.05 mg/i

drinking water

Chronic cadmium

poisoning resulting in

illness and death

has occurred in

Japan, where

cadmium mobilized

by mining

contaminated daily

diet. Margin of

safety—measured

levels of cadmium in

renal cortex

compared to

threshold for renal

dysfunction-is low:

4 to 12.5.

Environmental pollution

leading to

contamination of fish

and shell fish caused

illness and death in

Japan;

contamination of fish

in U.S. has caused

closure of waters to

commercial fishing.

interacts with other

metals, increasing or

decreasing toxicity.

toxic combustion.
Ch. V—Environmental Impacts ● 207

Table 27.-Some Gaseous and Particulate Substances From Coal Combustiona —Continued

Toxicity

Sources of Environmental

Substanceb Acute Chrome Pollution standards Comments

Gases

Sulfur dioxide Increased

respiratory

impairment—

morbidity and

mortality-in

combination

with

particulate.

Nitrogen dioxide Increase

respiratory

infections

Ozone

Carbon monoxide Behavior

changes,

nausea,

drowsiness,

headaches,

coma, death

Increased

respiratory

infection, eye

irritation,

headaches,

chest pain,

impaired

pulmonary

function

Aromatic hydrocarbons Fatigue,

weakness,

skin

paresthesia

(> 100 ppm)

Increased

respiratory

disease and

decreased

respiratory

function with

parlculates.

Changes suspected

in lung function;

emphysema.

Increase risk of

coronary heart

disease-arterial

sclerosis

suspected

Unknown

Irritation,

Ieukopenia and

anemia. Certain

compounds are

mutagens and

carcinogens.

Sulfur contained in

fossil fuels, smelters,

volcanoes

Nitrogen fixation in

high temperature

combustion, and

from nitrogen

contained in fossil

fuels: coal, oil,

gasoline combustion.

Incomplete combustion

of fossil fuels: coal,

oil, gas, gasoline

combustion.

Photochemical

reactions involving

hydrocarbons,

nitrogen oxide and

other compounds in

lower atmosphere;

reaction of atomic

oxygen and oxygen

in upper

atmosphere.

A broad class of

compounds naturally

evolved from organic

material, and from

the evaporation and

combustion of fossil

fuels and other

organic industrial

chemicals.

a This table is provided merely to indicate some of the substances which are potential environmental hazards along with some Information on each regarding toxicity, sources,

standards, etc. It IS not to be interpreted as definitive.

b The substance listed is not necessarily the form in which it becomes a potential environmental threat in some cases the oxide or some metabolite, rather than the substance

Itself, IS the culprit

Controlled exposures to sulfates represent

the vast majority of aerosol-health effects exposure studies. Overall, the aerosol studies

report “health effects” at levels many times

higher than common urban levels. There is

evidence that chronic exposures below these

levels adversely affect health by increasing

respiratory disease (although a recent review

of health effects literature concluded that

“research on the toxicity of aerosols has not infrequently led to an overinterpretation of

technically weak or insufficient data. ” 23 Some

studies suggest that particulate pollution,

23Airborne Particles, National Academy of Sciences,

National Research Council (Baltimore University Park

Press, 1978)
208 The Direct Use of Coal

much of which is sulfur compounds, can initiate the development and progression of bronchitis and emphysema. Ambient particulate

pollution has been associated with the development of lung cancer; the benzo(a)pyrene

component of soot has been advanced as the

causal factor. Although benzo(a)pyrene is a

known carcinogenic material, it may be serving as a surrogate for a class of hazardous

organic compounds found in urban aerosol

samples.

Polycyclic organic matter (POM) is a fractional constituent of particulate matter

emitted during coal combustion. POM emissions appear to vary inversely with combustion

efficiency. There is a factor of approximately

10,000 difference between POM emission factors (emissions per pound of coal) for handstoked coal stoves and large new utility coal

boilers. 24 Therefore, the major health risk of

POM is not from the large sources but with the

older, less efficient utility and industrial

boilers near populated areas. Depending on

dispersion characteristics, POM from these

coal sources may add to POM concentrations

from other sources such as refuse burning,

coke production, and motor vehicles. Also,

any substantial increase in residential and

other small-source coal combustion could aggravate problems with POM emissions.

Nitrogen dioxide health effects are normally

associated with exposures close to the pollution source, because N02 is reactive and takes

part in complex reactions within the atmosphere that produce ozone, PAN, and other

complex organic nitrogen species.

The Clean Air Act Amendments of 1977 require EPA to promulgate a short-term N02

standard (not more than a 3-hour averaging

time) by 1980. An extensive review of N02 is

reported in the EPA Office of Research and

Development’s draft document “Health Effects for Short-Term Exposures to Nitrogen

Dioxide,” March 1978. Although this draft

document does not contain a synthesis, it does

contain extensive review with some critical interpretations and serves as a draft criteria

document. EPA has requested public comment

24N, Dean Smith, see note 11
Ch. V—Environmental Impacts ● 209

Table 28.—Nitrogen Dioxide: Levels and Effects

Comments Concentrations Reported Effects (exposure time)

EPA lowest

400

t -

.2

SOURCE Health Effects Appendix

Although there is extensive literature on experiments relating health effects of ozone and

other oxidants, assessment of a safe standard

is difficult. The problems parallel similar difficulties with interpreting health effects from

other pollutants. First, questions are raised by

the specificity and accuracy of ambient monitoring used in epidemiological studies. Second, there are uncertainties in extrapolating

from cell and organ studies, as well as from

whole animal studies, to estimates of human

damage. Finally, field studies measure only the

ozone component of total oxidant levels but

are actually observing the effects of all oxidants. The evidence is consistent that nose,

throat, and eye irritation occurs in the range of

200 to 294 pg/m3 (0.1 to 0.15 ppm) of measured

ozone. Breathing difficulties in exercising

adults and chest pain in children exposed to

ozone have been reported in the range of 200

to 400 pg/m3 (0.1 to 0.2 ppm). Decreased running performance has been associated with

similar ozone levels. More severe symptoms of

chest discomfort and coughing have been reported in healthy young adults at measured

ozone levels of about 725 μg/m3 (0.36 ppm)

and at 490 μg/m3 (0.25 ppm) in hypersensitive

individuals, Levels high enough to cause these

more severe symptoms occur in Washington,

D. C., Houston, Tex., Philadelphia, Pa., and Los

Angeles, Cal if., with some regularity.

Japanese investigators have observed that

the frequencies of several symptoms in school

chiIdren, including sore throat, headache,

cough, and

maximum

equaled or

dyspnea, are higher on days when

hourly oxidant concentrations

exceeded 0.15 ppm than on days

44-102 [) - -i~ - 15
210 ● The Direct Use of Coa/

Table 29.-Ozone (OJ: Levels and Effects

SOURCE: Health Effects Appendix.

—

1200

1100

1000

800

700

600

500

400

300

200

100

0

—

— . 5

4

— . 4

- i

— . 3

- i

i

— . 2

i

when corresponding concentrations were below 0.10 ppm.25 in Japanese studies, the number of individuals experiencing symptoms has

generally been more strongly associated with

ozone concentrations than with total oxidant

concentrations. The Japanese studies also suggest that people with allergic tendencies are

more susceptible to short-term photochemical

oxidant exposure than are other segments of

the population.

Japanese studies have generally shown oxidant- or ozone-associated effects at lower oxidant or ozone concentration than have Ameri25J. Kagawa and T. Toyama, “Photochemical Air Pollution: Its Affects on Respiratory Function of Elementary

Schoolchildren, ” Archives of Environmental Health, 30:

117-122,1975.

can studies. The consistent difference between

Japanese and American findings raises several

questions, including whether the components

of oxidant pollution in Japan are different

from those in Los Angeles, or indeed, from

those in any U.S. location. It is possible, for instance, that oxidants in Japan are accompanied by higher SOX levels than in the United

States. In any case, the Japanese results

underscore the point that epidemiological

results gathered in one area can be generalized

to other areas only with the greatest caution.

The Japanese results also demonstrate the

need to gather comprehensive data in U.S.

locations other than Los Angeles.

Because the discrepancy among these resuits is along national lines, it is of particular
Ch. V—Environmental Impacts 211

interest to note the results of a study on nine

new arrivals to the Los Angeles area. 2G The y

showed substantial decreases in pulmonary

function for ozone exposures of 800 μg/m3 for

2 hours, whereas six local residents did not

show measurable effects. In a further study, 27

four southern Californians and four Canadians

were exposed to 700 μg/m3 for 2 hours with

light intermittent exercise. The Canadians exhibited discernible decreases in lung function,

but the Californians did not. Thus, either a

possible adaptation or a “selective migration”

effect is inferred. (“Selective migration” occurs when people moving into or out of an

area show a sensitivity to a pollutant that is

markedly different from the average). Any

adaptation would indicate an altered lung surface due to air pollution, which is an effect

that should arouse considerable concern. This

observation is consistent with the observation

that at low ozone levels smokers are generally

less reactive than nonsmokers. An alteration in

the lung would also be consistent with deactivated surface cells in the bronchi, which may

lead to long-term respiratory problems.

In his comprehensive review of health effects from exposure to low levels of air pollution, Ferris concludes:

Because of the highly reactive character of

0 3, prudence dictates that we should abide by

the present standard until more valid data

have been collected. Chamber studies will be

useful to define acute or short-term effects but

cannot identify subtle long-term effects. For

these we shall have to turn to epidemiologic

studies which have many confounding variables. To date there is no evidence that health

effects result from chronic exposure to levels

of oxidants that currently occur in Los

Angeles, but careful studies to confirm this

have yet to be done. ”

26 J. D.Hackney, et al , “Studies in Adaptation to Ambient Oxident Air Pollution: Effects of Ozone Exposures

in Los Angeles Residents vs New Arrival s,” in E n -

vironmental Health Perspectives, 18: 141-146, 1976.

27). D Hackney, et al., “Effects of Ozone Exposure in

Canadians and Southern Californians, ” Archives of Environmental Health, 32: 110-116, 1977.

28 B. G. Ferris, Jr., “Health Effects of Exposure to Low

Levels of Regulated Air Pollutants, A Critical Review, ” ).

Air Poll. Control Assoc., 28:482 (1978).

As yet, no convincing association has been

shown between short-term oxidant exposures

and rates of mortality due to any cause. Although a positive association has been observed in one study, a re-analysis appears to

negate this conclusion. Interpretation of mortality studies has been hampered by limitations in statistical methodology. It has not

been possible to fully separate the effects on

mortality of oxidants, other polIutants, and

meteorologic factors, most notably temperature.

Sulfur dioxide.–Although there have been

many studies of SOZ

, there is little evidence of

acute adverse effects at ambient levels (usually below 0.4 ppm). The gas is soluble and

removed almost entirely by the upper airways.

At levels much higher than the ambient standard of 0.14 ppm for 24 hours, controlled exposure studies have demonstrated increased

airways resistance in subjects. These and other

reversible effects occurred at 1 ppm (2- to 3-

hour exposures) and higher. Long-term animal

exposures in the range of 340 to 15,000 pg/m3

(0.1 3 to 5.72 ppm) show no functional or structural lung damage. All long-term exposure

studies on human beings have involved a

simultaneous exposure to the gas-aerosol mixture. However, it would appear on the basis of

a lack of cumulative functional or structural

impairment of the lungs from high-SOz animal

exposures that SOZ alone at ambient levels is

not hazardous for human beings. The observed

effects are shown in table 30.

Sulfur dioxide and particulates.-Exposure to

S 02 virtually always occurs in the presence of

particulate and other gases. Generally, there

is a heightened response from the dual exposure that is not observed from single exposures. A popular explanation of this synergism

is that the aerosol acts as a carrier for the S02

(which would otherwise be screened by the

lung’s defenses), thereby delivering a higher

fraction of the gas to the deep recesses of the

lungs. An alternative explanation is that chemical reactions can occur between the gas and

particle, forming new compounds (such as sulfuric acid) that are more toxic. Both explanations are supported by laboratory animal .
272 ● The Direct Use of Coal

Table W.—Health Effects of Sulfur Dioxide

SOURCE: Health Effects Appendix.

studies using combined exposure of SO2 a n d

various particles.

Gas-aerosol interactions have been documented in the laboratory and observed in

population studies at levels slightly higher

than the present standards. Given that these

potentially harmful reactions are quite complex, perhaps impossible to understand com-

, pletely, violations of National Ambient Air

Quality Standards (NAAQS) by coal combustion may be damaging to human health.

Sulfate particulates. -Over the past decade

emissions of SOZ have remained fairly stable,

but their distribution has changed substantially. Urban SOZ levels have decreased considerably as powerplants and other sources have

either moved away or come into emissions

compliance. At the same time, however, sulfate levels in most cities have not declined.

This can be attributed to the formation of

sulfate from the SOZ emitted by new rural

sources, and its long-range transport to the urban areas. Sulfate particulate can travel more

than 1,000 km, with atmospheric residence

time of between 2 and 4 days. The available

data indicate that large regional reductions in

total SOZ emissions would be required to reduce sulfates. Thus, current policies designed

to reduce ambient pollutant concentrations

are not fully successful because they inade-
Ch. V—Environmental impacts 213

quately deal with long-distance transport of

pollutants across jurisdictional and international boundaries.

Review of the available human experiments

and epidemiologic studies indicates that high

levels of some sulfates irritate eyes and the

respiratory tract, decrease lung function, aggravate emphysema, asthma, and chronic

bronchitis, and may increase mortality.

Research seems to indicate that sulfates

function independently of SO, in producing

health and ecological effects. Sulfates exist as

several chemical species. Sulfuric acid mist

and several species of sulfate particles have

been demonstrated to be more toxic than SO2

,

as measured by flow resistance in pulmonary

airways in animals, while at least two sulfate

species appear less toxic than the S02 gas. It

has also been demonstrated that for a given

concentration of a sulfate compound, toxicity

increases with decreasing particle size. Atmospheric sampling has repeatedly shown that

more than half of the mass concentration of

sulfate is found in the aerosol fraction of particles less than 1.0 μm in diameter.

The most extensive epidemiological study of

S 02 and sulfate is the Community Health and

Environmental Surveillance System (CHESS)

study conducted by EPA.29 As a consequence

of many valid criticisms, it is generalIy felt that

insufficient information exists in the CHESS results to propose a standard for sulfate.30 Upon

re-analysis, the CHESS results do not substantiate the original conclusions that ambient sulfate levels are associated with respiratory

symptoms in asthmatic adults and acute lower

respiratory illness in children. However, other

CHESS results are not inconsistent with other

findings and represent a large body of epidemiological data. 31

29 Health Consequences of Sulfur Oxides: A Report

From CHESS, 1970-71 (Washington D. C.: U.S. Environmental Protection Agency, May 1974), E PA-650/l-74-004.

30B. G. Ferris, Jr., see note 23.

31 “R. S. Chapman, discussion in: “Health Effects of Exposure to Low Levels of Regulated Air PolIutants: Discussion Papers, ” Journal of the Air Pollution Control Association, vol 28, no 9, September 1978, pp. 887-889

Laboratory studies provide mixed evidence

on the adverse health effects of sulfates on

both human beings and experimental animals.

Airway resistance has been measured in animals at sulfate levels higher than those experienced in ambient exposures. Impaired lung

clearance in animals has been reported in the

upper range of ambient exposures. Some

human studies show effects at levels below 100

μg/m3 for short-term exposures. However, these

observations are not confirmed in other

studies. Table 31 summarizes the data available over the range of ambient exposures.

In summary, animal and human respiratory

studies indicate health effects for sulfates by

themselves and in combination with other

gaseous pollutants at levels higher than current ambient exposure. Further, these studies

distinguish among sulfate compounds. Ammonium sulfate, the principle constituent of airborne sulfates, is less hazardous than other

sulfate compounds. Sulfuric acid aerosol, also

detected in urban atmospheres, is the most

hazardous. At times, urban and rural sulfate

levels are almost exclusively comprised of

sulfuric acid.

Effects of Air Pollution on Death Rates

Several epidemiologic studies of mortality

(death) rates have shown an association between sulfate and TSP levels and community

mortality rates. Most of these studies are

“cross-sectional;” that is, they examined differences in mortality, air pollution, and other

variables among geographical areas over one

time period. Increased levels of mortality are

observed at or near air pollution levels that

prevail in urban regions of the United States.

Although different studies show a considerable range of pollution/death rate associations, the majority of these studies derived

coefficients of air pollution-induced mortality

(deaths per unit population exposed per unit of

pollutant concentration, or annual number of

deaths that would be expected to occur if

100,000 persons were exposed to an average of

1 μg/m3 of pollution) that indicate that several

tens of thousands of premature deaths annually are associated with current pollution levels.

Owing in part to limitations in the pollutant
214 ● The Direct Use of Coal

Table 31.—Health Effects of Sulfates

Cone. (μglm

500

100

25

10

5

0

- ) Health Effects

measurements (several important pollutants

were unmeasured), it is impossible to determine from these studies whether sulfates and

suspended particulate are the true causes of

the statistically observed deaths, or whether

they serve as a measure of some other pollutant or combination of pollutants. In the

absence of a plausible alternative hypotheses,

however, any other causative pollutants appear likely to have been the products of the

same (fossil fuel combustion) sources that produced the sulfates and TSP.

These studies have been widely criticized in

the health community for deficiencies similar

to those described earlier on pages 202 to 204,

and their results have been rejected by many.

Statements of the more frequent arguments

against the studies and discussions of the arguments’ validity are presented below:

1. These studies typically use data from a

single monitoring station to represent the

exposure to the residents of a metropolitan region. Measurements taken at a

single point are a poor measure of the

mean exposure of the population.

Discussion: The effect of using poor

data is, if the error is random, to bias

downward the estimated coefficient of

2

3

the independent variable being measured.

It is likely that the error introduced by

using central station data as measures of

population exposure would make it less

likely that the analyst would find a positive association between air pollution and

mortality. Thus, this is not a logical argument against a positive finding.

The single monitoring station is typically

located in the center of the urban area,

which often coincides with the areas of

highest pollution exposure. This biases

results.

Discussion: The bias produced by location of monitors in areas of relatively high

pollution may be either positive or negative, depending upon the relative gradients of exposure among the cities under

consideration.

It is unlikely that current air pollution exposure is an adequate exposure parameter. Past exposure or cumulative history

of exposure is undoubtedly more relevant.

Discussion: It can be demonstrated that

regardless of whether air pollution levels

are increasing or decreasing, it is possible

that this bias could operate in either direction. To the extent that present exposures

are less than perfectly colinear with past
Ch. V—Environmental Impacts ● 215

4

exposures, there will be a tendency to underestimate the true magnitude of the

relationship. Also, efforts to include measures of cumulative exposure have generally failed to increase the explanatory

power of air pollution mortality models.

The studies have been confounded by the

similarity of patterns of certain critical

socioeconomic variables with patterns of

air pollution. Whereas the researchers

believe that they are seeing the relationship of death rates to pollution, they are

actually seeing the relationship of death

rates to occupation and other factors that

happen to be somewhat colinear with pollution in the United States. If these variables were taken into account, the pollution/mortality association would disappear.

Discussion: Confounding is possible in

any epidemiologic study. This can influence results in two ways: either an important variable is not included or two or

more seemingly independent variables are

really measures of the same thing. In statistical studies on mortality and air pollution, smoking and occupation are frequently cited as confounding variables

left out of regression analyses. The effect

of confounding would be the production

of seemingly valid but spurious association. For confounding to occur, the variable must be a cause of disease, and must

be highly correlated with the variable of

interest, air polIution.

a. Smoking. It is certainly reasonable to

argue that smoking may be confounding

the results. Data on the smoking habits of

metropolitan populations are virtually

nonexistent. It is generally accepted that

smoking can induce lung cancer, induce

and/or exacerbate bronchitis and emphysema, and reduce life expectancy. Therefore, if there were substantial differences

in the amount of smoking across metropolitan areas–differences that varied

similarly to air pollution — then smoking

may be the real cause of mortality now attributed to air pollution. There is mixed

evidence on this issue. Several investigators have independently examined the

mortality experience of men and women

in relation to air pollution exposure. In

most of this work, air pollution exposure

appears to have a stronger effect on men

than women. Combining this with the

knowledge that historically men in the

United States smoke more heavily (and

more men smoke) than women, two hypotheses become possible:

i. smoking is confounding the association;

ii. smokers have more respiratory diseases, and thus are more susceptible

to air polIution.

Because of a lack of data on community

smoking habits, cross-sectional studies

can do little to resolve these two hypotheses. However, it is important to note that

a very high correlation between air pollution and the smoking habits of entire urban populations would be required to account for the mortality differences now

attributed to air pollution. It is unlikely

that this is true.

b. Occupational exposure. It is argued

that the regional differences in heavy

manufacturing and other industrial activities vary simiIarly to the air polIution concentrations and that the differences in

mortality reflect the hazards of working

rather than breathing outdoor air.

When occupational variables such as

the percentage of the work force employed in each of the following categories — agriculture, construction, manufacturing, transportation, trade, finance, education, white collar, and public administration —are added to regressions, the

amount of mortality associated with air

pollution is reduced. This indicates that

adequate accounting for the occupational

variable could reduce the effect attributed to air pollution. Lave and Seskin32

suggest an alternative interpretation.

They argue that occupational variables

are surrogates for unmeasured air pollutants that affect the general population. If

differences in occupation patterns are

correlated with air pollution levels, this

32L. B. Lave and E. T. Seskin, Air Pollution and Human

Health, John Hopkins U. Press, Baltimore and London,

1977
216 ● The Direct Use of Coal

represents a limitation of the air pollution

mortality associations derived from crosssectional studies. Currently available data

do not permit resolution of this issue.

c. Differential/ migration. Occasionally

it is argued that people have been moving

out of the heavily polluted Northeast and

East Central United States to the less

polluted Southeast, South, Mountain

States, and West. It is well established

that those who move tend to be relatively

young and healthy. Thus it is possible that

selective outmigration from the polluted

areas might result in a spurious association between air pollution and mortality.

Lave and Seskin have approached this

problem by splitting their data base into

areas of “high” and “low” migration and

performing independent analyses on these

two groups. The coefficients of air-pollution-induced mortality derived from the

low-migration data set were about half as

large as those from the high-migration

data. Differential migration may be partially confounding the results, but a positive association remains for air pollution.

These arguments are the most important of

many criticisms of cross-sectional studies of

air-pollution-induced mortality. Others are

considered in volume 11, appendix IX. Although

the findings and interpretations of these crosssectional studies are still being debated, a

positive relationship between air pollution and

mortality cannot be rejected.

Quantitative Assessments of Health Damage

From Future Pollution Levels

The coefficients of air-pollution-induced

mortality derived from the studies discussed

above can be used to project the deaths that

might result from future coal development. In

conducting such a projection, the analyst must

develop a “scenario” that describes the

development, compute its air quality effects,

and overlay those effects on the population.

The Biomedical and Environmental Assessment and the Atmospheric Sciences Divisions

of Brookhaven National Laboratory (BNL) have

developed a methodology for quantifying the

mortality associated with fossil-fuel-derived

air pollution. 33 The Atmospheric Sciences Division has applied a long-distance trajectory

model to predict the ground-level concentrations of a number of pollutants emitted from

coal combustion. The model is capable of incorporating alternative siting and emission

patterns to show the air quality implications of

various scenarios. The modeling effort:

1

2

3.

projects pollutant emission from 1,088

coal-fired sources (71 1 industrial point

sources and 377 utility point sources)

using 1985 and 1990 emissions projections, and assuming 80-percent SOX control for existing sources and 85-percent

SO control for new sources;

computes the resulting ground-level air

quality concentrations with a model

which accounts for long-range transport

and chemical conversion (i. e., SOZ a n d

S0x concentrations are calculated by the

BNL model); and

ca l c u I ates the annual population

weighted sulfate exposure with 32 x 32 km

grids for the entire country.

Figure 26 displays the calculated sulfate annual concentrations for the 1990, 25.7 Quads

coal-use scenario. The pattern reflects very

high sulfate concentrations in the Northeast

with peak levels in the region of eastern Ohio,

western Pennsylvania, and West Virginia. After

obtaining population sulfate exposure, BNL

applied to them a mortality coefficient of 3.25

deaths per year for every 100,000 people exposed to a 1 μg/m3 annual averaged sulfate

level. This coefficient is a “most likely” coefficient of mortality derived from BNL’s examination of the available cross-sectional mortality

studies and their data bases. In the BNL work

the mortality coefficient is expressed in a probability function that ranges from no health effects (actually a negative coefficient) to four

times this “most likely value. ” In this way the

‘

] For example, see L. D. Hamilton, “Alternative

Sources and Health, ” in CRC forum on Energy, e d .

Robert. T, Budnitz, by CRC Press, Cleveland, 1977 and

M. G. Morgan, et al, “A Probabilistic Methodology for

Estimating Air Pollution Health Effects from Coal-Fired

Power Plants, ” in Energy Systems and Policy, vol. 2, No. 3,

Crane Russak & Co., Inc., 1978
Ch. V—Environmental Impacts ● 217

Figure 26.—Annual Concentrations of Sulfate for a 199025.7 Quads Coal-Use Scenario

(Brookhaven National Laboratory, 1978)

BNL excess mortality, as shown in table 32, is

approximately the 50th percentile. That is,

there is a 50-percent chance that the actual expected mortality is greater than the estimates

presented, based on the BNL probability function for the mortality coefficient.

The implications of the estimates shown in

table 32 are startling. First, they imply that

coal emissions are responsible for approximately 2.5 percent (48,000 deaths) of the total

annual mortality in this country. The second

implication is that an increase in coal use

could raise the air-pollution-caused annual

mortality by approximately 7,000 in 1990. I n

comparison to the more than doubling in coal

use, the projected annual air pollution mortality would increase by less than 20 percent over

the current air pollution mortality estimates.

This increase is approximately 0.4 percent of

the annual total U.S. mortality.

The credibility of estimates of this type has

been severely challenged by many in the

health community. As noted above, there is

widespread skepticism that any air pollutants

at current levels of concentration are killing

people in large numbers, Furthermore, even

the supporters of the air pollution/mortality

associations used in the analysis generally

agree that sulfates may not be the “guilty”

pollutant. Other problems with the analysis include potential inaccuracies in the sulfate projections and the use of a simple linear model

for health effects. However, this work is the

first comprehensive attempt to formulate a
218 ● The Direct Use of Coal

Table 32.-Annual Projected Mortality From Coal Combustion

Year Quads of coal use Expected mortality

1975. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.3 48,120

1985. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.5 49,543

1990. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.7 55,835

NOTE: Proportional Mortality Model—3.25 deaths/y r/100,000 populations/(1 μg/m3—annual average for

sulfate).

SOURCE: Based on population exposures from: Meyers, R. E., Cedarwall, R. T., Kleinman, L. l., Schwartz,

S. E., and McCoy M., “Constraints on coal utilization with respect to alr pollution production and

transport over long dtstances: summary,” Oct. 2, 1978 (draft report), Brookhaven National

Laboratory.

quantitative methodology for assessing air

pollution health effects. Even if the damage

coefficient is not accepted, the model can

identify population exposures to sulfates and

related pollutants and can identify the relationships between regions of high exposures

and regions with multiple pollution sources;

this information can be used to evaluate the

relative effects of alternative siting patterns.

Research Needs

DOE, EPA, the National Institutes of Health

(NIH), and other agencies support air pollution

health effects research in areas of bioscreening

for hazardous substances, cellular toxicology,

animal toxicology, human exposure studies,

and risk analyses. This research is funded

through the Federal Interagency Energy Environmental Research and Development Program, as well as the basic contract and grant

programs of various agencies. Health effects

research programs related to fossil fuels are reviewed in volume 11, appendix IX.

Quantification of mortality and morbidity

from fossil fuel air pollutants is currently

limited because:

1. Population exposures to pollutants are

poorly defined.

2. The mechanisms of biological injury induced by specific pollutants are not adequately understood.

3. Insufficient epidemiologic evidence exists

to relate mortality and/or morbidity to

ambient levels of air polIution.

Significant improvement in the ability to quantify the effects of coal combustion is contingent upon continued development in exposure assessment, health effects research,

and quantitative applications.

Exposure.-Comprehensive pollutant monitoring is fundamental to epidemiologic

studies. Present monitoring assesses outdoor

concentrations of relatively few pollutants.

Particulate, for instance, are determined on a

weight basis only and are not differentiated by

size or chemical composition. Encouragingly,

EPA is conducting a nationwide fine-particulate monitoring program. The relationship of

outdoor air pollution to indoor exposures and,

in fact, the total integrated dose of pollutants

to the individual are not understood. lntegrated exposure assessments that measure

the human body burden from multiple exposures to pollutants are urgently needed.

Moreover, to facilitate epidemiologic work,

the exposure of entire urban populations must

be better characterized by implementation of

more “dense” monitoring networks, including

personal monitors.

Damages.-The specific mechanisms causing

biological injury from many atmospheric pol-
Ch. V—Environmental Impacts ● 219

Iutants are unknown. Knowledge of these

mechanisms will provide a firmer scientific

basis for epidemiologic investigation of

specific health damages and pollutants and,

consequently, a foundation for effective

pollutant-specific control strategies.

Ideally, understanding of the biochemical

and metabolic fate of pollutants is desired.

However, the precise fate of pollutants is often

impossible to determine. When this is the case,

research must be focused on understanding

the grosser, aggregate effects of pollutant insults. For example, pollutant effects may manifest themselves as increased susceptibility to

infect ion, or as inhibition of lung-clearing

mechanisms. In pursuit of a better understanding of these effects, new techniques and traditional research for assessing defense mechanism inhibition should be expanded. New techniques are currently being developed for noninvasive methods for mapping particulate deposition and particle retention in the lungs.

These techniques would permit rapid surveying of pollutant loadings in human lungs; they

may allow the detection of health effects in

human populations before the onset of clinical

symptoms.

As the result of suggestive evidence on

synergistic interactions of multiple pollutants,

additional studies examining the combined effects of two or more pollutants should be

begun. Few clinical studies of this type have

been done. Federal health organizations as

well as EPRI have recently recognized this

fact. A few animal and human studies of multiple pollutant exposures have started; however,

more such studies should be encouraged. In

addition, there have been too few controlled

exposure studies on subjects under stress.

Stress may be induced by exercise or with

medication. Stress-pollutant studies are important in determining biomedical effects in sensitive individuals.

Epidemiology .-Epidemiologic studies will be

necessary for monitoring possible changes in

morbidity and mortality as the total population exposure to coal-related air pollution increases. Such studies must receive long-term

funding commitment to comprehensively examine multiple health indicators whiIe properly assessing pollutant exposures.

Until direct information from controlled toxicologic and epidemiologic studies is available, quantitative assessments of health impacts from fossil fuel combustion must rely on

cross-sectionaI statistical studies. These

studies can be improved by a more accurate

measurement of socioeconomic variables. For

example, as noted above, differences in regional smoking habits have not been adequately

accounted for. This deficiency could be corrected if social, economic, and geographic

smoking patterns were assessed as part of the

National Census.

In order to resolve the question of whether

long-term health effects are caused by peak exposure or are the cumulative effect of mean

exposures, studies should be undertaken of the

effects of periodic exposures to sulfate, nitrate, ozone, and fine particulate. Summertime “episodes,” where these and other pollutants are elevated for hours to days over large

areas of the Northeast, have been documented

in ongoing field monitoring studies. Selected

populations must be closely monitored for respiratory and other physiological changes before, during, and after such episodes.

Conclusions

The discussions in this section and in appendix IX indicate that there are grounds for

speculation (for example, our knowledge of

the ability of fine particulate to penetrate

deeply into the lungs) and some positive but

not conclusive statistical evidence that current

and expected future concentrations of coalrelated polIutants may be dangerous to human

health. A significant segment of the health

community considers the statistical evidence

to be meaningless. Several of the objections

they raise are valid but do not appear to justify

rejection of the evidence.
220 The Direct Use of Coal

Policy makers are faced with a difficult

tradeoff. More stringent regulation of air pollution can involve very large costs and can

even incur new environmental damages. For

example, an insistence on full scrubbing will

cost several tens of billions of dollars by 1990

and create a substantial disposal requirement

for millions of tons of scrubber sludge. On the

other hand, a failure to control incurs the risk

that significant health damages may occur.

The tradeoff is complicated by the current inability to definitely associate the (statistically

observed) health effects with one specific pollutant; although sulfates have been implicated

by most of the statistical analyses, they may be

an indicator for another pollutant or mixture

of polIutants.

Uncertainty in environmental policymaking

is inevitable. However, the level of uncertainty

and the stakes in coal policy are very high.

There is thus a high premium on reducing the

uncertainty by improving predictions of future

coal-related health effects. The research needs

identified above (increased monitoring, improvement in the capability to conduct crosssectional and time series statistical studies,

and expanded investigations of the mechanisms of pollution-caused biological injury) are

critical elements in this process.

Ecological Effects

Sulfur Oxides

As emphasized in the discussion of pollutant

transformation and transport, SOZ may retain

its chemical identity or may convert in the atmosphere to sulfuric acid or to a variety of

sulfate salts. Within about 40 km of a coalfired powerplant, the form of sulfur most likely

to be deposited is S02

. To place experimental

evidence in proper perspective, one must compare levels at which damage is observed both

to levels mandated by the current air quality

standards and to those actualIy prevaiIing near

and far from powerplants. The secondary

NAAQS SOZ standard is 0.5 ppm (3-hour average) and the primary standards are 0.14 ppm

(24-hour average) and 0.03 ppm (annual average). In the United States as a whole in 1975,
Ch. V—Environmental Impacts . 221

Although ambient levels near powerplants

usualIy are below the current secondary standards, much higher values can occur during

plume touchdowns. The S02 levels during a

touchdown, as well as the frequency of

touchdowns, strongly depends on local factors

surrounding a given powerplant. Measurements of concentrations during these episodes

are scarce, although measurements 3.6 miles

from an Indiana powerplant showed nearly 100

episodes per year of l-hour SOZ concentrations

above 100 pg/m 3 (.037 ppm) in the direction of

persistent winds. 39 Better documentation exist s

for the actual damage done by plume touchdowns, or fumigations, from coal-fired powerplants and industrialized sources. These fumigations have caused acute foliage burning to

commercial soy beans,40 ponderosa and lodgepole pine forests, Douglas fir forests, ” and to

other plants.

Damage caused by mixtures of pollutants

have been shown in the field and in chamber

studies over a wide range of environmental

conditions, including variations in soil type,

temperature, light, and humidity. Combined

effects appear to take place through several

mechanisms. The most common seems to be

that the combination of pollutants reduces the

plant’s threshold of injury; frequently the effect of the more toxic of two pollutants is

enhanced.

A wide variety of field, vegetable, fruit, nut,

forage, and forest crops have been shown to be

sensitive to SOZ —even at levels below the

Federal secondary standard – in mixtures with

common pollutants (ozone, nitrous oxides,

hydrofluoric acid, and peroxyacetyl nitrate).

Such pollutant mixtures disrupt critical pIant

functions, including growth, yield, root/shoot

ratios, photosynthesis, and respiration. The

physical appearance of produce can also be injured by the combined impact of different air

pollutants. As a result, the marketability of

vegetables and ornamental may be reduced.

Damage to animals occurs at far higher

doses of SO, than those levels at which plants

are affected. Rather than being affected directly by S02

, animals may be more seriously

endangered by its indirect effect; sulfur compounds can destroy or alter their natural

habitat. 42

S 02 is transformed in the atmosphere to

various forms of sulfate that are damaging to

plantlife. Plants are directly injured when excessive sulfates accumulate in their tissues.

The rate at which this occurs varies according

to the plant species and according to the

amount of sulfur already available in the soil

(some possibly stemming from chemical fertilization). The California Air Resources Board

has reported growth and yield reductions from

sulfate accumulation in cotton, oats, rye,

tomatoes, barley, and in forests in New Hampshire. Other studies have shown damage to

spruce needles from sulfate accumulation

over periods of time as brief as 10 to 100 days.

Some sulfates, notably ammonium sulfate,

can act as plant fertilizers. Nevertheless, even

apparently beneficial sulfate compounds may

be deposited at times not conducive to good

farming practices, and the deposition of such

sulfates may interfere with the individual farmer’s schedule of chemical fertilization.

As discussed previously, the emission of SOX

from all sources may be relatively stable in the

next 10 years (at moderate coal use growth

rates), although emissions may begin to grow

again unless controls are placed on older

powerplants. DOE projections show that the

emissions in the eastern portion of the United

States will generally decline during this period.

This is fortunate because that is where the

brunt of SOX impact is now borne. However,

some impacts –for example, the acidifying effects of acid rain – may be somewhat cumulative and thus could become more intense unless changes in control strategies are forth4ZN. R. Glass, cd., “Appendix on Ecological Effects, ”

U.S. Environmental Protection Agency, p 6, Rail Report.
222 ● The Direct Use of Coal

coming. An intensification of SOX controls on

existing combustion sources is the only practical alternative available, as the proposed

NSPS is near the present limits of control

technology and increased requirements on

new plant facilities would have only minor effects in this period.

Nitrogen Oxides

The direct action of man-caused NOX on the

ecosystem is difficult to analyze because

nitrogen is an element essential to all biological systems and because natural sources of

NOx (especially anaerobic bacterial action and

chemical decomposition of nitrate) account

for more than 90 percent of global levels.43 The

limited evidence suggests that NO, is more toxic than NO and that the most susceptible receptors in the terrestrial ecosystem are the

higher plants, among them oats, barley, tobacco, apples, and lettuce. Still, the threshold for

almost all observed effects on ecosystems is

well above the NOX levels in most U.S. cities.

NOx is not nearly as obviously damaging to

vegetation as either SOX or photochemical oxidants at similar levels of concentration. Also,

very high NOZ concentrations are required to

produce morbidity or mortality in most animals, 44

However, there are some poorly understood

areas of ecosystem effects that may be a cause

for concern. For example, soils absorb NO and

N OZ quite readily and change them to nitrate,

decreasing soil pH and possibly affecting the

micro-organisms in the soil. The effects of

chronic low-level or intermittent NOZ exposures on vegetation also deserve attention.

The role of NOX in the formation of photochemical oxidants is of greater concern than

NO, by itself, for oxidants are the most damaging air pollutants affecting agriculture and

forestry in the United States. 45 NO, is the one

primary “criteria pollutant” (pollutant regulated by a NAAQS under the Clean Air Act)

that is likely to increase significantly in the

next few decades. The 21-percent increase in

NO, projected for 1990 by DOE (NEF #l) may

“I bid,, p. 10.

“I bid., p. 13.

‘

s Ibid., p. 19.

lead to an increase in concentrations of ozone

and peroxyacyl nitrates. However, the degree

of increase is complicated by a certain degree

of quenching of oxidants by NOX and by an expected decline in hydrocarbon emissions,

which are also oxidant precursors and may be

the limiting component for oxidant production.

Any increase in oxidants appears particularly worrisome when it is recognized that elevated ozone concentrations caused by longrange transport of pollutants from urban areas

have become a severe regional problem

throughout the United States. “Repeated episodes during 4 to 6 months of the year . . .

cause obvious foliage injury, impaired photo

synthesis, and growth reductions of sensitive

species populations, in both agricultural and

forest ecosystems.’’” Oxidants have caused

well-documented damage to agricultural

crops, forests, and native vegetation in southern California as well as widespread damage to

crops in the East, and have become a new

stress on ecosystems in the Southwest. Although animals do not appear to be sensitive

to existing levels of oxidants, they are affected

by the loss of cover and food accompanying

such levels.

N OX

, like SOX, has the potential for synergistic effects. It may facilitate the creation of

nitrosamines, which are known carcinogens,

and it also seems to have more adverse effects

when present together with SOX

.

Finally, the most serious effect of NOX m a y

be its involvement with SOX in the formation of

acid rain, which is discussed separately below.

Acid Rain

Both NOX and SOX are implicated in the occurrence of acid rainfall at many locations

around the world. “Normal” precipitation is

expected to have a pH of about 5.7, based on

theoretical calculations that postulate an

equilibrium with CO2 .

47 Precipitation samples

from various points in the United States indicate that in large portions of the Eastern

“Ibid.

“J. N. Galloway, C. E. Likens, and E. S. Edgerton,

Science, 194, p. 722,1976.
Ch. V—Environmental Impacts 223

United States, the pH falls between 3 and 548

(see figure 27). In northwestern Europe, where

acid rain has been more intensely studied, a

network of monitoring stations yields evidence

that the pH of the precipitation has dropped

over the past 20 years.4g It has been widely

stated that the region of acid precipitation in

the United States is extending westward and

southwestward. 50 The data available are

strongly suggestive of this statement, but are

neither systematic nor extensive enough to be

considered conclusive. EPA and the Forest

Service are currently establishing networks of

monitoring stations that will provide better

data in the future.

One effect of acid precipitation is to lower

the pH of bodies of water into which it falls. If

the pH dips below 5.0, fish such as trout or

salmon may perish, for they are very sensitive

to pH. Fish kills have in fact been reported in

areas such as New York’s Adirondack Mountains, where 51 percent of the lakes now have a

pH below 5.0, and where 90 percent of these

support no fish populations.5

’ A valuable recreational trout industry has thus been endangered. In Norway the losses to the salmon fisheries attributed to acid rain are estimated in

the tens of millions of dollars.52 Other aquatic

effects include reduction in algal communiFigure 27.–Regional Impact of Acid Rainfall

San F

pH greater than 5.5

pi-i between 50 and 5.5

pH between 4,0 and 5.0

New Orleans-

\

pH less than 4.0 . . . . . .

A
224 The Direct Use of Coal

ties, growth of thick mats of benthic moss, and

hindrance of nutrient recycling.

The evidence for damage to terrestrial vegetation is somewhat more elusive. An association has been postulated between acid precipitation and the decline in forest growth

observed in both the Northeastern United

States and in southern Sweden, where growth

declined between 2 and 7 percent from 1950 to

1965 .

5

’ The ecosystem is unfortunately too

complex for the cause to be laid so unequivocalIy at the door of just one of many environmental stresses. Nevertheless, numerous experimental studies have shown that acid rain

can harm terrestrial systems in several ways: it

may “damage foliage; accelerate cuticular

erosion; alter responses to associated pathogens, symbionts, and saprophytes; affect the

germination of conifer and hardwood seeds

and the establishment of seedlings; affect the

availability of nitrogen in the soil; decrease

soil respiration; and increase leaching of nutrient ions from the soil. ”54 Acid rains have been

strongly implicated in causing extensive damage to Christmas tree farms in West Virginia

downwind of the Kyger Creek coal-fired

powerplant in Ohio. The disease afflicting the

trees has been duplicated in at Ieast two independent laboratory studies using sulfuric acid

mists. In other studies, several important food

crops and trees were adversely affected by

simulated acid rain and mist. It has also been

shown that increasing acidity of rain significantly increases the uptake of cadmium and

other toxic substances by plants that may subsequently be included in human and animal

diet. 55

The effects of acid precipitation depend

largely on the buffering capacity of the region

on which the rain falls. The damage may be

quite dramatic in Scandinavia, for example,

because 80 percent of the forest land in Sweden is acid podzolic soil and thousands of its

lakes are underlaid with granitic bedrock. 5

’ By

“Ibid , p I105

“L S Dochinger, see note 49

’

5

1 Shen-Miller, M B Hunter, and J Miller, “Simulated Acid Rain on Growth and Cadmium Uptake in Soybeans, ” Plant Physiology, vol 57 (1976), p 50

“L S Dochinger, T A Seliga, p 1104

contrast, in the Western United States, where

indications are that rainfall may be growing

more acidic and may continue to do so, the effects may never become serious because the

soils and lakes are so alkaline. More studies

must be initiated to identify sensitive regions

with low buffering capacity and to understand

the processes that affect the buffering capacity of soils, such as acidification by natural

processes and by chemical fertilization.

Any increase in soil acidity may alter the

delicate balance of soil calcium, magnesium,

and potassium to aluminum. Essential nutrients, including nitrogen, potassium, and phosphorus, can form compounds that are not useful to plants, or they may be leached from the

soil altogether. The living organisms of the soil

are very sensitive to pH changes in their environment, and these include not only important

lower plant forms such as algae, lichens, and

fungal associates of higher plants, but also the

nitrogen-fixing bacteria, which are essential if

airborne nitrogen is to be made available for

use as a nutrient by plants. Current high nutrient erosion rates from soils subjected to acid

precipitation of 4.0 pH or less in remote forested areas of the Adirondack Mountains57 and

elsewhere are evidence that forest soils in the

Northeastern United States are becoming

acidic at an accelerated rate.

Fossil-fueled powerplants may be major

contributors to the occurrence of acid rain

through their generation of NOX and SOX

. Researchers in Scandinavia attribute its acid rain

to the long-range transport of sulfates from the

heavily industrialized areas of northern Europe

and England. Data from New York and New

England indicate that about 60 to 70 percent

of the acidity in precipitation there is caused

by sulfuric acid, with the contribution from

nitric acid becoming increasingly important.58

Because the background of air pollutants from

stationary and mobile sources varies with locale, these figures may not universally represent the composition of acid rain.

“C W. Cronan, R C. Reynolds, Jr,, and G, E Lang,

“Forest Floor Leaching: Contributions From Mineral,

Organic, and Carbonic Acids in New Hampshire Subalplne Forests, ” Science, vol. 200 (1978), pp 309-11.

58 G. D Likens, “AC id Precipitation, ” Chemical and

Engineering News 22,1976.
Ch. V—Environmental Impacts ● 225

Future increases in energy development, and

in coal use, may seriously aggravate acid rain

problems through two mechanisms. First, although tall-stack emissions of SOZ will not increase rapidly if best available controls are applied, serious increases in NO, emissions will

be inevitable if Federal emission standards–

which require only about 50-percent control —

are continued. As noted earlier, success of

EPA’s IO W- N OX burner will be a primary determinant of this required control level. Second,

there is a possibility that the fraction of sulfates and nitrates that are in the strong acid

form – currently thought to be about one quarter– may rise because of exhaustion of the

neutralizing capacity of the atmosphere. If exhaustion occurs, a l-percent increase in emissions would subsequently lead to a 4-percent

increase in acid rain. 59 Very little is known

about the atmosphere’s neutralization capacity. Finally, as some of the impact of acid rain

may be cumulative, even a stable level of acidity may lead to an increase in acid rain damages.

Visibility Reduction

S0x emissions from coal combustion have

been strongly implicated as a major factor in

the occurrence of visibiIity reductions

throughout the United States. The evidence

consists of the following.

●

●

●

●

Sulfate particles formed as the result of

the atmospheric transformation of SOZ

emissions tend to be in the size range of

fine particles that are most effective in

scattering light and hence in producing

haze.

Field studies by EPA indicate that powerplant S02 emissions are converted to sulfates at significant rates.

Sulfates account for about half of the particles in the “maximum light scattering”

size range in industrial regions.60

Visibility reductions and sulfate concentrations have been strongly correlated; for

example, large-scale polIuted air masses

characterized by decreased visibility, or

“hazy blobs, ” as they are sometimes

59’’Appendlx on Transport and Fate, ” Rail Report.

‘“’’ Appendix on Ecological Effects, ” Rail Report

●

called, have been tracked over periods

longer than a week as they moved over

large portions of the United States. These

“blobs” are correlated closely with sulfate

level s.”

Visibility substantially increased during

44-102 0 - ;rl - 15
226 ● The Direct Use of Coal

caused almost exclusively by fine particulate

and the associated trace elements and hydrocarbons that are preferentially adsorbed on

their surfaces. Although total particulate loadings will be substantially reduced in the future

as the result of strict controls on new plants

and progress in obtaining conformance with

State regulations from existing pIants, emissions of fine particulate are unlikely to

decline unless controls that are effective on

fine particulate (such as baghouses) are retrofitted on older plants as well as being installed

on new ones.

Fine-particulate effects on ecosystems may

be more of a regional than a local problem.

Glass” notes that more than 95 percent of the

particulate emissions from a large powerplant

with an ESP travel beyond a 20 km radius, and

most studies of trace element contamination

near powerplants have shown few significant

effects. 65

Soils are the principal repository for fine

particulate, and there is some concern that

the heavy metals contained within or on the

surface of the particles could eventually alter

the normal soil processes associated with

nutrient recycling and with soil micro-organisms. Plants are also an important sink for

fine particulate, which are captured by the

fine hairs on plant surfaces. Plants are generally not considered to be endangered by such

pollution; Van Hookbb notes that “there is no

reason to expect acute effects on plants . . .

the potential chronic toxicity is relatively low

except in local areas already enriched with a

particular element. ” However, more subtle effects, such as reduction in photosynthesis due

to reduced light or interference with stomatal

function, and foliar lesions have been attributed to fIy ash. b

’

Both inorganic trace elements and trace

hydrocarbons present a potential danger to

animals in water and on land. Biomagnification, whereby trace materials can be concentrated as they move up the food chain, is a par-

“’’Appendix on Ecological Effects, ” Rall Report

‘

s

’’ Appendix on Trace EIements,” Rail Report.

“Ibid.

“’’Appendix on Ecological Effects,” Rall Report.

ticular problem in aquatic ecosystems (see

table 33). Another source of concern is the extent to which trace element impacts are cumulative; logic argues that many will be cumulative, although the ambient levels caused by

coal combustion are not likely to be high in

most instances. Although the uncertainty surrounding these effects is very great, concentrations of polycyclic aromatic hydrocarbons that

have been demonstrated to be damaging to

fish have been observed in Norwegian rainwater.

68 However, the potential for significant

impacts on either terrestrial or aquatic ecosystems is clearly a very speculative area that requires considerably more evidence before firm

conclusions can be drawn.

Carbon Dioxide

C OZ concentrations measured at Mauna

Loa, Hawaii, and elsewhere have increased at a

rate that appears to be tied to fossil fuel combustion. b

’ The combustion of coal yields 11

percent more CO, than oil and 67 percent

more than natural gas. 70 The confluence of

these two facts has led to concern about the

role that increased coal development might

play in altering the Earth’s climate.

C O2 is relatively transparent to short-wave

radiation (sunlight), but absorbs long-wave (infrared or heat) radiation. Thus, atmospheric

C O2 admits incoming sunlight that warms the

Earth, but absorbs a portion of the infrared

heat radiation coming from the surface of the

warmed Earth and re-radiates part of it back to

the surface. The heat is “trapped” in the atmosphere in the same way that heat is trapped

inside a greenhouse, or an automobile with its

windows closed; hence the “greenhouse effeet. ” (See figure 28). Although no effects on

global temperatures have yet been measured,

most scientists believe that a continued increase in COZ levels must eventually affect the

Earth’s temperature.

“Ibid.

“C. Marland, and R. M. Rotty, “The Question Mark

Over Coal; Pollution, Politics and CO, ” Futures, February

1978,

‘“Analysis of the Proposed National Energy Plan, 1977.
Ch. V—Environmental Impacts ● 227

Table 33.—Biological Concentration Factors for Selected Trace Elements in Aquatic and

Terrestrial Environments

Biological Concentration Factor”

As Cd Hg Pb Zn

a concentration in organism to concentration in substrate.

SOURCE Van Hook, R 1, ‘Transport and transformation pathways of hazardous chemicals from solid waste disposal," Environ. Health Perspectives (in repress)

Figure 28.— Heat Radiation Emitted to Space by CO2

SOURCE: Mitchell J. Murray, Jr., “Carbon Dioxide and Future Climate,’’ EDS,

March, 1977 cited in Norwine, J., “A Question Climate,” Environment,

Vol. 19, N0. 8, November 1977.
228 ● The Direct Use of Coai

The legitimacy of environmental concern

over the climatic influence of coal production

hinges on the answers to two critical questions:

● How wiII future atmospheric C02 concentrations be affected by fossil fuel combustion and other activities such as forest

clearing?

● What effect wilI increased C02 in the atmosphere have on global climate?

Considerable uncertainty clouds both quest ions.

C 02 Concentrations.–There is general agreement about the amounts of carbon currently

being released as C02 through fossil fuel combustion (about 5 billion kilograms per year)

and the increase in the amount of carbon in

the atmosphere (about 2.3 billion kilograms

per year) .7’ Until recently, scientists thought

they could readily explain where the remaining

2.7 billion kilograms per year went; a maximum of about 2.5 billion kilograms per year

was thought to be absorbed by the oceans, and

the remainder by the biota-forests, grasslands,

etc. A number of researchers have now challenged this view based on evidence that the

largest and most intensive pool of carbon in

the biosphere— the forests (both the trees

themselves and their humus floors)— are

shrinking significantly in area because of wood

harvesting and clearing for agriculture and

other development. This is especially true of

the tropical rain forests such as those in the

Amazon Basin, which are said72 to play the major role in carbon storage in the biosphere.

Thus, a net carbon release rather than a net absorption now is theorized. Woodwell 73 estimates this release from the biosphere to be

about 8 billion kilograms, although he estimates the range due to uncertainty to be 2 billion to 18 billion kilograms per year. Other researchers have developed lower estimates,

ranging from about one-tenth to one-third of

the fossil fuel contribution. 74

“G. M. Woodwell, “The Carbon Dioxide Question,”

Scientific American, January 1978, vol 238, No 1.

“lb Id.

“Ibi d

“R A. Kerr, “Carbon Dioxide and Climate: Carbon

Budget Still Unbalanced, ” Science, vol. 197, pp.

1352-1353, Sept 30,1977.

Accepting even the lower value still leaves

an enormous gap in the existing models of carbon balance; it is not known where all this excess carbon is going. However, if Woodwell is

correct that the biosphere is a C02 source

rather than a “sink, ” this means that an unknown mechanism, capable of removing and

storing atmospheric C02 at a substantial rate,

must exist and might be available to remove

excess C02 from fossil fuel combustion if the

shrinkage of the forests could be halted

Uncertainty also is added by a lack of full

understanding of the various known mechanisms involved in oceanic uptake of COZ

. For

instance, carbonate ions in the surface layers

of the ocean react with and remove atmospheric C02

. As the pressure of C02 increases

and the carbonate ions are used up faster than

they can be replaced by mixing, the ocean’s

absorption of COZ from the atmosphere could

slow and the atmospheric COZ buildup could

accelerate. On the other hand, increased acidity of surface waters caused by greater dissolved C02 concentrations could increase the

dissolution of calcium carbonate and thus increase the supply of carbonate ions. The extent

of these potential changes presently is

unknown. Uncertainty also is caused by the

lack of understanding of the effects of increased C02 on ecosystems and the corresponding effect on their photosynthetic production and carbon storage capacities.

Any changes in these factors would alter the

capacity of the biosphere to act as a sink — or

source — of atmospheric COZ

.

Despite these uncertainties, however, probably few scientists would disagree with the

statement that continued reliance on fossil

fuels, in the absence of drastic measures to

change worldwide development patterns that

are radically altering the biosphere, will result

in substantially increased levels of COZ in the

atmosphere. Kellogg’s75 estimate of a 400-ppm

C 02 concentration by 2000 and a doubling of

that level by 2040 (if fossil energy trends continue) should be taken quite seriously.

“W. W Kellogg, “Global Influence of Mankind on the

Climate,” in Climate Change, J. Gibbin, cd,, Cambridge

University Press, 1978.
Ch. V—Environmental Impacts ● 229

Climatic Effects. -Even if precise forecasts of

future atmospheric C02 concentrations were

possible, the effects of these concentrations

on the climate and on man would be uncertain

owing to several confounding factors. One factor is that the climate, with or without man’s

influence, may be changing as part of a natural

cycle. Scientists disagree as to the nature of

these changes. Secondly, the “anthropogenic ”

(man-caused) effect on global temperatures includes several effects aside from the “greenhouse effect. ” Their role complicates the calcuIation of the temperature effect of man’s activities. Finally, the translation of more precise

knowledge of the “greenhouse effect” and the

other temperature-changing factors into a

global climatic effect is a modeling problem

that requires considerably more knowledge

and sophistication than is currently available.

It is the distribution of temperature and other

effects, rather than the global average temperature effect, that is critical to understanding the changes that will occur in actual

Iiving conditions.

There are three major schools of thought on

the nature of future climatic cycles. ‘b The first

is that the recent climatic record is not sufficient to allow accurate forecasts of future climate. The second is that the Earth is due for a

short period of cooling followed in the early

21st century by mild warming, and that man’s

activities will not affect these trends. The third

and most widely accepted is that global warming will occur sometime in the next century or

so as a result of man’s activities, and that any

manifestation of natural climatic cycles will

eventually be overwhelmed by this induced

warming.

In addition to the “greenhouse effect, ” the

other man-created effects that may affect

global temperatures” include:

● Change in reflectance of the Earth: continued injection of particles into the upper atmosphere will lead to increased

●

●

A

reflection of incoming solar energy and,

consequently, a cooling effect.

Changes in cloud cover: the increasing

level of fine particulate (which act as

condensation nuclei), the increasing areas

of irrigation projects, the expanded use of

cooling towers, and any warming trend

(leading to increased evaporation rates)

would al I tend to increase the cloud cover

of the Earth and increase its reflectance.

This provides a “negative feedback” to

compensate for the greenhouse effect,

Thermal pollution of the atmosphere: by

the year 2050, the total heat added to the

Earth’s atmosphere by energy production

wilI approach 10’ 9 Btu per year, which is

on the order of one-half of 1 percent of

the solar energy reaching the Earth’s surface. A 1- percent increase in this energy

“flux” would generate about a 10 F increase in global temperatures.

reliable computation of the climatic
230 ● The Direct Use of Coal

community generalIy agrees that the probability of significant global warming and other

climatic changes is sufficiently high to warrant

exceptional attention in form of expanded research and monitoring, and caution in weighing any decisions that might tend to tie us irrevocably to a fossil-based energy economy.

It must be stressed that the “scenarios”

postulated by the more pessimistic researchers

would involve massive disruption of the world

economy and well-being. A 20 to 30 C change

in mean world temperatures could lead to

melting of the polar icecaps sufficient to cause

flooding of coastal regions. Another critical effect would be significant shifts in the viability

of the world’s food-producing areas owing to

massive shifts in rainfall distribution. 1 n the

long run, such shifts might not lead to a net

decrease in potential worldwide productivity.

However, the transient effects would be

severe. Given appropriate climatic conditions,

overalI agricuItural viability depends upon existing land use, ownership patterns, transportation, water, and other resource availability,

etc. These factors represent a massive physical

and societal infrastructure that would have to

be virtually torn down and rebuilt to make a

successful transition to a warmer climate.

Problems with such a transition process could

mean food shortages and social and economic

disruption on a massive role.

Effects on Materials

Although human health and ecological effects are the most serious problems associated

with air pollution from the coal fuel cycle,

damage to nonliving materials from this pollution is substantial today and may remain a potent policy issue because of memories of

coal’s past. The soiling problem commonly

associated with coal combustion has been all

but eliminated by extensive controls on particulate emissions and the phasing out of most

of the small coal-fired furnaces. However,

problems that remain include the deterioration

of building materials and works of art, fading

of dyes, weathering of textiles, and corrosion

of metals.

A 1970 estimate of total damage to materials from air polIutants (not limited to emissions

from powerplants or coal combustion sources)

is $2.2 billion per year. The relative contributions of the four major pollutant components

are: SOX— 41 percent, particulates —27 percent, ozone —26 percent, and NOX—6 percent. 80

There are five major causes of damage:

●

●

●

●

●

abrasion by high-velocity and/or sharpedged particles,

direct chemical attack,

indirect chemical attack —where the pollutant becomes harmful only after a transformation when in contact with the material,

electrochemical corrosion —where pollution increases conductivity of thin surface

films of moisture and helps to destroy protective films on material surfaces, and

discoloration by particulate.

Each mechanism depends on a variety of independent variables, including moisture, temperature, sunlight, etc. If estimates of future

pollution levels are a guide, one might expect

that acid rain and ozone damage caused by

powerplant NO, emissions will rise in the

future, that SOX-caused damage will not undergo radical changes if best available control

technology (scrubbers) is enforced, that particulate soiIing damage should decrease with substantial decreases in particulate emissions as

all new powerplants control to better than 99-

percent efficiency and existing particulate

emitters comply with State and local control

requirements, and that chemical damage due

to particulate might increase because of increases in emissions of fine particulate.

Regulations

Air pollution from coal combustion is regulated under the Clean Air Act, which sets ambient air quality standards and establishes

limits on the emissions from a variety of

sources in order to achieve and maintain those

standards. The legal framework of the Clean

Air Act is discussed in chapter VI 1; this section

80T E Waddell, “The Economic Damages of Alr Pollution, ” U S Environmental Protection Agency,

E PA-600/5-74-012, May 1974
Ch. V—Environmental Impacts ● 231

summarizes the way the Act seeks to regulate

the health and ecological effects of the pollutants.

National Ambient Air Quality Standards

(NAAQS) have been promulgated under the

Clean Air Act for six pollutants: S0x particulate matter, NOZ

, photochemical oxidants,

hydrocarbons, and CO. There are two types of

NAAQS: primary standards are those needed

to protect public health, allowing an adequate

margin of safety. The secondary standards are

intended to protect the public welfare from

pollution damage to soil, plants, animals,

materials, and other factors not directly

related to human health. The NAAQS are

based on air quality criteria that reflect the

latest scientific knowledge useful in indicating

the kind and extent of identifiable effects of a

pollutant on public health or welfare. These

criteria must include information about variable factors, such as atmospheric conditions

that may alter the effects of a pollutant, and

about interactive effects among polIutants.

The Clean Air Act is implemented at the

State level through a variety of regulatory programs designed to achieve and maintain the

NAAQS. First, State Implementation Plans

(SIPS) must include control strategies designed

to reduce the contribution of existing sources

to airborne pollutant loadings, generally

through the application of reasonably available control methods. Second, the Act establishes performance standards for large new

sources that mandate the use of the best technological system of continuous emission reduction as well as a percentage reduction in

emissions over those from the uncontrolled

combustion of untreated fuel. Third, in those

areas where air quality now exceeds the

NAAQS (nonattainment areas), new sources

must meet the lowest achievable emission rate

(LAER) by applying stringent technological

controls and must secure emission reductions

from existing sources in the area that will more

than offset the emissions from the proposed

facility. Fourth, in order to prevent significant

deterioration of air quality in areas where the

air currently is cleaner than the national standards, the Clean Air Act specifies maximum allowable increases in pollutant concentrations

as well as ceilings for ambient concentrations,

and requires large new sources to use the best

available control technology. Finally, the Act

requires the retrofitting of polIution control

technology on existing large sources near areas

primarily important for scenic values (such as

national parks) in order to protect visibiIity.

There are problems associated with implementation of the Clean Air Act to protect public health and welfare. As of mid-1976, 178 of

the 313 air quality control regions (AQCRS) or

State portions thereof had not attained the primary particulate standard, while 46 had not

achieved the primary S02 standard. Most conventional stationary sources (such as coal-fired

powerplants) in these nonattainment areas are

either in compliance with the standards or are

on compliance schedules. The particulate violations tend to arise because of fugitive emissions, fugitive dust, and fine particulate, alI of

which are more clifficuIt to monitor and control, and which are not now explicitly regulated under the Clean Air Act.

No deadlines have been set for attainment

of the more stringent secondary standards.

Rather, the States are given a reasonable time

to achieve the secondary standards, where

“reasonable time” depends on the degree of

emission reduction needed to attain the standards and on the social, economic, and technological problems involved in implementing a

control strategy adequate to achieve and

maintain the standard. Thus the secondary

standards are not being enforced, and soil,

plants, animals, materials, and other environmental factors are unprotected to the extent

they require greater protection then that afforded by the primary standard.

The air quality criteria on which the NAAQS

are based were published in 1969-71 and reflect the scientific knowledge current at that

time about the effects of the various pollutants. However, in 1969-71 the phenomena of

pollutant transformations and long-range

pollutant transport had not been documented.

Consequently, the Clean Air Act and the regulatory programs that implement the Act generalIy treat S02 and particulate matter as static

pollutants that do not convert. The transformation products, such as sulfates and acid

precipitation, are not regulated. In addition,

current EPA regulations limit the applicability
232 ● The Direct Use of Coal

of air quality modeling techniques to a downwind distance of not more than 50 km from the

source (because of EPA’s judgment that the

models are not reliable beyond this distance).

Although the 1977 amendments to the Clean

Air Act include procedures for the prevention

and abatement of interstate air polIution problems attributable to particular sources, longer

range transport that may contribute to air

quality problems farther than 50 km downwind

currently is unregulated.

The 1977 amendments to the Clean Air Act

include two provisions designed to remedy

these problems. First, they require EPA to

review the NAAQS and the criteria on which

they are based, and revise them if necessary by

1980 and every 5 years thereafter. Thus more

recent evidence on health effects and on pollutant transformations and transport should be

reflected within a couple of years in the standards and in the programs that implement them.

Second, the amendments require the States to

revise their implementation plans by 1979 in

order to provide for achievement of the primary standards by 1982. However, this requirement may be largely moot if the standards are

made more stringent in 1980, and it does not

address the problem of implementing the secondary standards.

IMPACTS TO WATER SYSTEMS

The impurities in coal that are released to

the air and land in all stages of the fuel cycle

may wend their way eventualIy into the waterways. Thus water may become the ultimate repository for many of the byproducts of coal

activities. The water system can transport

these impurities both geographically—from

the local source to distant sites—and blologically —from micro-organisms on up the food

chain, often in ever-increasing concentration.

The uses for which our water systems are

needed include — roughly in order of increasing demand for water purity — navigation, recreation, irrigation, industrial processing, watering of stock and wildlife, maintenance of aquatic life, and drinking water supply. A lowering

of water quality may affect these uses and

consequently the health, economy, or quality

of Iife within a community.

The various activities of the coal fuel cycle

affect not only water quality but also water

quantity and hydrology. For example, mining

can cause stream flows to change and water

tables to decline, and in some instances may

affect the intensity of floods. Of particular

concern is the potential alteration of the

ground water system.

Sources, Effects, and

Control of Water Pollution

Coal Mining and Cleaning

Surface Water Impacts. -In mining, huge

slices are made into the earth, and layers once

deeply buried are brought to the surface to be

deposited, often only temporarily. In surface

mining, the top layers of overburden are

placed in “spoil banks” until time for reclamation. In underground mining, the waste material is heaped at the surface, and the mine walls

often remain exposed when the mine is abandoned. At the preparation plant, where impurities are removed from the coal, still more

waste piles are generated. As long as these

once-buried materials remain exposed and unstabilized, they are subject to runoff and erosion, and become the source of chemical and

physical alteration of local streams. These impacts are addressed by a variety of State laws

and, as discussed later, by Federal water pollution and surface mining laws.

Within the coal production waste piles are

many soluble components that dissolve as rain

water percolates through them. A consequence is an elevation of total dissolved so/ids
Ch. V—Environmental Impacts ● 233

(TDS) within the local watershed. TDS is a parameter of water quality that very generalIy indicates the presence of soluble ions such as (in

the case of coal waste runoff) sulfates, calcium, carbonates, and bicarbonates (hardness).

Elevated concentrations of these ions make

water largely unpotable by altering its taste

but otherwise have only minor human health

effects. TDS and hardness can also degrade

the use of water for agricultural and industrial

uses. Regions that will absorb substantial TDS

as a result of expanded coal mining are the

Middle Atlantic (sulfate and fluoride fro m

underground mining), and the Midwest and

North Central (sulfate from strip mining).

Acid mine drainage is a particularly severe

byproduct of mining in those regions –AppaIachia and parts of the interior mining region

(Indiana, Illinois, Western Kentucky )–where

the coal seams are rich in pyrite (iron disulfide), The mining process exposes the pyrite to

water and air, causing a reaction that forms

sulfuric acid and iron. The lowered pH also

tends to dissolve heavy metal compounds,

adding metal ions (aluminum, manganese,

zinc, nickel, etc. ) to the acidic drainage water.

Acid drainage is a problem with active and

inactive mines, and with both surface and

underground mines. Recent data are not readily available, but in the 1960’s underground

mining accounted for fully three quarters of

the problem (see table 34). About 10,000 miles

of streams and rivers, principally in Appalachia, have been degraded by acid drainage. The

effects are most severe in Pennsylvania and

Photo credit. EPA —Documerlca

Acid mine drainage from abandoned underground mines and other sources still affects thousands

of miles of streams in Appalachia
234 The Direct Use of Coal

West Virginia, while less severe in southern Appalachia. ”

Table 34.—Acid Drainage in Mines

Acidity

Source 1,000 lb/day Percent

614 9

1,712 53

28 01

361 11

60 02

238 07

245 07

3,258 100

alncludes sources where underground could not be separated from surface

The environmental effects of acid mine

drainage are severe. The acid and heavy

metals are directly toxic to aquatic life, and

render the water unfit for domestic and industrial use. Zinc and nickel, often present in

substantial quantities, are known carcinogens. 82 Other carcinogenic trace elements are

present in smaller concentrations but may

have additive effects.

Many of the metals found in acid mine

drainage can become concentrated as they

move up the food chain. Adsorption of these

metals can occur on the surfaces of small suspended solids and sediments; thus, the largest

reservoir of trace contaminants resides in the

bottom sediment and is available to the rest of

the ecosystem according to a complex web of

factors. An additional ecosystem impact is the

smothering of stream bottom-dwelling organisms by precipitated iron salts.

The acid content of the mine drainage also

causes substantial material damage by eating

away metal structures and destroying concrete.

A variety of measures exists to control acid

mine drainage from active and inactive surface and underground mines. All involve preventing the formation of acid by controlling

oxygen flow to the pyrites, preventing a discharge by controlling water flow in the mine,

or treating the discharge by neutralizing the

acid (or by using reverse osmosis or ion exchange techniques, at much higher costs).

Although neutralization treatment can increase hardness and dissolved sol ids content,

it is the commonly used method for controlling

acid mine drainage from active surface and

underground mines and is considered an effective control. Surface mines also must utilize

drainage control and special mining techniques to properly control acid drainage.

The only major problem facing successful

control of acid damage from active surface

mines is enforcement, which has been a longstanding problem with the smaller mines. This

situation is essentially duplicated with the control of inactive surface mines: available reclamation techniques can control acid drainage

from most inactive mines, but enforcement efforts on small mines must be strengthened to

ensure adequate control. Also, a small percentage of mining situations still defy acid control

attempts. For instance, a few mines in West

Virginia have been found to produce acid

seepage from horizontal water movement

through buried spoils. However, strict enforcement by the new Office of Surface Mining and

continued development of control techniques

for the remaining problem situations should

ensure an acceptable degree of control.

Unfortunately, available controls for inactive underground mines are not likely to be as

successful. When an underground mine is being closed, the techniques for stopping acid

drainage are:

●

●

●

●

●

sealing the mine to prevent air infiltration;

filling the mine with water;

preventing water infiltration by grading,

sealing, aquifer control, etc.;

backfilling the mine; and

removing mine pillars and allowing the

mine to collapse.

Although these techniques can be effective in

some circumstances, success in preventing a

continuing significant flow of water has been

intermittent; the technology available to control acid drainage from most inactive underground mines must be considered inadequate.
Ch. V—Environmental Impacts ● 235
236 ● The Direct Use of Coal

cline significantly in the future. For example,

loadings in the Middle Atlantic are projected

to decrease to one-third of 1975 levels by 1990.

One notable exception to this trend may occur

in the North-Central region, where sediment

loadings may increase sharply by 1990 unless

better controls are devised and implemented.

Flooding potential is affected by several factors related to surface mining:

. permeability of land surface,

. vegetation cover of surface, and

● carrying capacity of streams.

The mining and reclamation process may act

to increase surface permeability and thus

allow the ground to soak up more water in a

given period than the premined surface could.

The loss of vegetative cover that acted as a

water retention mechanism will tend to counteract this effect. In addition, increased erosion and consequent siltation lead to decreased carrying capacity of streams and

greater flooding potential. Studies of the effect of surface mining on flooding potential

thus have tended to conflict, with one study of

strip-mined watersheds in Kentucky showing

increased flooding potential and studies in lndiana indicating the reverse.85 An examination

of these factors leads to the tentative conclusion that flooding potential may be decreased

by area mines, while contour mines may cause

increased flooding. Indeed, several studies

now appear to support the association of surface mines with flooding in steep terrain. More

studies, of surface mine hydrology, soil mechanics, revegetation techniques, and the positive impacts of methods to stabilize benches

are needed to settle this issue. However, the

only practical control of this problem in some

flood-prone areas may be a limit on surface

mining.

A final group of impacts is the alteration of

the hydrology of local water systems. Surface

streams often are diverted around mines to

lessen the degree of siltation or acid or alkaline drainage. Some surface water may have to

be impounded for entrapment of silt or sludge

*

s

’’ Appendix on Reclamation, ” Coal Extraction Land

Reclamation Group, ” Argonne National Laboratory, Rail

Report.

from treatment of acid mine drainage. More

water also may be demanded for irrigation of

revegetated surface mines, especially in the

West where reclamation is more difficult. The

quantities of water are comparatively small

(see table 35) but may nevertheless become a

public concern in arid regions where competition for water is becoming critical. However,

the potential for water conservation in the

West is great enough to offset any potential

regional shortages if the legal and political barriers to conservation can be dealt with (see

chapter IV, Water Availability).

Ground Water Impacts. -Mining is likely to

have significant effects on ground water as

well as surface waters. Mining operations can

both contaminate ground water and cause severe physical dislocations of aquifers,

A primary mechanism of ground water contamination is the seepage of acid mine drainage into aquifers via joints and fractures in the

rock or via direct interception of the aquifer.

Inadvertent connection of two aquifers also

can lead to contamination; this is more of a

problem in the West, where deep saline aquifers abound. Coal spoil banks also can be the

source of this contamination through leaching

and penetration of the soil. Investigations of

ground water contamination typically have

shown high local effects but extremely variable effects some distance from the m inc.

Direct interception of aquifers and other

physical disturbances can substantially affect

the quantity of ground water as well as its

quality. Where a mine is located below the

water table, seepage of water into a mine pit

can lower the water table and dry up wells in

the vicinity. (Thus, the trend towards deeper

mines, identified as providing a benefit in

reducing acid drainage, can cause additional

ground water problems.) Blasting may rupture

the impermeable strata below an aquifer and

cause water to seep to a lower level, or may inadvertently connect two aquifers. The process

of mining and reclamation will change the permeability of the overlying soil, altering the rate

of ground water recharge, and affecting flooding potentials (as discussed in the preceding

section).
Ch, V—Environmental Impacts ● 237

Table 35.-Water Requirements for Coal System Activities

Peak water requirements

Water consumed by

associated with

population increases’

energy facility

Peak

Acre-ft Gallonsl/106 Construction Operation

Coal activity Size per year Btu in product (acre-ft yr) (acre/ft/yr)

Surface mine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 MMtpy

Underground mine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . —

Power generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,000 MWe

Lurgi gasification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 250 MMscfd

Synthane gasification . . . . . . . . . . . . . . . . .250 MMscf d

Synthol liquefaction . . . . . . . . . . . . . . . . . . .. I00,000Bbl

day

Slurry pipeline -...-..=. . . . . . . . . . . . . . . 25MMmtpy

3,400 4

0 0

29,000 54 (thermal)

157 (electric)

6,700 28

9,100 38

17,500 28

18,400 14

71

275

853

1570

1570

1750

Not

considered

323

1490

260

350

350

1800

Not

considered

aAssumes 150 gallons per capita per day, multiplier of 2 to account for added service personnel during construction, and a multiplier of 3.5 to account

for families and service personnel during operation.

SOURCE White et al., ’’Energy from the West’’, EPA-6OO/7-77.O72a, July 1977

Transportation

Coal energy transportation systems—trucks,

railroads, coal slurry pipelines, barges, and

transmission lines– can directly or indirectly

affect water quality. New clearing of rights-ofway and construction of facilities will increase

sediment loadings. Where herbicides are used

for clearing and maintenance, excess application can lead to both surface and ground water

contamination. Both coal slurry pipelines and

barge transportation on canals “consume”

water, the former by exporting water (approximately 500 acre-feet per mill ion tons of coal)

out of arid regions, the latter by exposing more

water surface to evaporation.

Transmission generally has insignificant

direct effects on water quality. The major indirect effect is associated with powerplant

siting. A mine-mouth plant with long-distance

transmission lines may be sited in an arid

region, where the impact on water availability

is greater than if the coal were shipped to

another site with abundant water.

Coal Combustion

Coal combustion releases thermal as well as

chemical effluents into water systems. The

waste heat from a coal-fired boiler represents

that percentage of the energy originally present in the coal (about 60 percent in a modern

utility) that is not converted to electricity. This

thermal energy is transferred to an adjacent

river, lake, or cooling pond and to the local atmosphere, in proportions depending on the

cooling system. The thermal pollution problem

is not unique to coal-fired utilities but is shared

to the same degree with oil and gas plants and

to a greater degree by nuclear plants (which

currently are less efficient than fossil-f uel-f i red

plants and thus produce more waste heat).

The large quantity of heat that emanates

from a coal-fired utility boiler is bound to affect at least the local environment. If heat is

released in an open cooling cycle (that is,

water is withdrawn from a source such as a

river, lake, or ocean, circulated within the

plant’s heat exchanger, and released at higher

temperature, usually to the original source),

many properties of the receiving waters are

altered by the resulting temperature rise.

Changes occur in such properties as salinity,

vapor pressure, etc.; the amount of dissolved

oxygen in the water will decrease owing t o

lowered volubility and re-aeration rates, while

TDS will increase because of the increased

volubility of many compounds with increasing

temperature. These changes in turn alter the

life functions of organisms within the water.
238 ● The Direct Use of Coal

Higher temperatures also may elevate metabolic rates of organisms, thus influencing oxygen demand, total energy needs, foraging

ability, reproduction, migration, and susceptibility to disease. Heated effluents accelerate

the consumption of dissolved oxygen by organisms; when coupled with lower oxygen levels

as a result of the physical mechanisms noted

above, oxygen content can become critically

low within the thermal plumes.

In addition to the thermal effect, physical

impacts are caused by small organisms or even

fish eggs and larva being drawn through the

cooling system of the plant. This entrainment

may damage these organisms and affect not

only their own lifespans but those of large fish

that feed on them.

These impacts can be mitigated by careful

siting of powerplants and construction of cooling intakes and outflows. However, complete

control can be obtained only with cooling systems that emit heat into the atmosphere or

into a small artificial body of water. These are

called “closed-cycle” cooling systems.

Current Federal regulations require that,

with certain exceptions, closed-cycle cooling

systems be used in large, steam electric-generating plants built after 1970 and certain

smaller units built after 1974. Thus, closedcycle systems will be essentially standard

equipment on new powerplants, and opencycle (“once through”) systems will be used

only in the Iimited cases where exemptions can

be obtained (see chapter VII, section on Present Federal Coal Policy).

The two major water impacts of closed-cycle, or evaporative, cooling systems stem from

water consumption and “blowdown” disposal.

Although water consumption by evaporative

cooling towers and cooling ponds depends on

many site-specific and design factors, in

general the evaporative systems associated

with powerplants are the largest water consumers in the coal fuel cycle (see table 35).

Their widespread use causes the issue of water

use for energy to be a major concern nationwide, and especially in the arid Southwest (see

Water Availability, chapter IV). However, the

use of relatively water-’ ’conserving” oncethrough (open-cycle) cooling, in those areas

where a sufficient volume of water would be

available, would still consume a large amount

of water (50 to 60 percent of evaporative tower

consumption) because of the evaporative cooling that takes place in the river or other body

of water into which the heated water is discharged. This fact has not always been considered by critics of the current requirements for

closed-cycle systems.

The environmental effect of massive consumption of water by powerplant cooling systems is twofold:

●

●

The

The amount of water available to dilute

downstream discharges is reduced, and

water quality is thus degraded. This effect

is especially evident in the Colorado

River, where massive water consumption

(by agriculture, in this case) coupled with

substantial pollution loadings have elevated salt concentrations in the River to

the point where desalinization plants are

required to keep water quality within

standards.

In critical watersheds, the physical quantity of water remaining in the streams may

fall below that needed to support the water ecosystem. The recognition that this

“instream use” of water is a “beneficial

use” within the legal system established

for allocating water rights is a recent one,

and thus protection of water ecosystems

from destruction by sheer lack of water is

a recent development.

concentrating effect of evaporation increases the levels of mineral salts in the circulating water of an evaporative cooling system.

This water must be continually bled from the

system and replaced with freshwater to maintain system operation. This bleed water, which

is extremely high in salt concentration, is

called “blowdown. ” Although the majority of

the “pollution” in the blowdown water is the

same mix of salts as in the water source (with a

small concentration of biocides to keep the

tower clear of fungae and algae, and some

dust scrubbed out of the air), this water can be

damaging locally because of the high salt concentration levels, or when the water enters

ground water or surface water other than the

source. In some cases, the local effects of the

biocides may be more damaging than those of

the high salt concentration.
Ch. V—Environmental Impacts ● 239

Photo credit: EPA — Documerlca

The enormous quantity of water that must be evaporated to cool a large generating facility

is graphically illustrated by these cooling tower “plumes”, which overshadow the plume from the plant’s stacks

Uncertainty about the precise level of controls that will be required is considerable. Present EPA effluent guidelines forbid the discharge of biocides but allow the discharge of

the salts originally present in the intake water.

However, if the cooling process uses a significant portion of the water source, the blowdown could violate water quality standards by

substantially increasing the overall salt concentration; in these cases, some level of treatment will be required. Also effluent standards

for new powerplants in some parts of the West

require totally closed-cycle operations, with

blowdown being concentrated and either discharged to evaporation ponds or else undergoing further treatment and disposal as a sludge.

Disposal problems are similar to those associated with disposal of fIy ash and fIue-gas

desulfurization (FGD) sludge, except that trace

elements should not be a problem.

The dissolved solids loading that electric

utiIities impose on the Nation’s waterways as a

result of blowdown (from both the cooling system and the boiler) is extremely large. Utilities

produced nearly 6 million tons, or nearly 28

percent of the total national dissolved solids

discharge in 1975 and may increase this to 10

milIion tons by 1990. The share of this burden

contributed by coal-fired utilities was nearly 4

million tons in 1975 and will be around 6.6

million tons in 1990 with moderate coal

growth. Increases in utility coal burning play

important roles in the projected substantial

growth in TDS by 1990 both nationally and in

several regions: South Atlantic, Midwest,

North-Central, and Central.

The large water requirements associated

with operation of a coal-fired powerplant can

be reduced substantially by the use of air-
240 ● The Direct Use of Coal

cooled or “dry” cooling systems, either by

themselves or in combination with evaporative

systems. In the combination or “wet/dry”

system, the air-cooled tower may fulfill the

total cooling requirements of the powerplant

in winter and be supplemented by the wet

tower when weather conditions lower the cooling capacity of the ambient air. Using either

system, the cost of building and operating the

powerplant increases substantially because of

the large capital cost of the cooling systems,

lessened efficiency of the pIant due to a lower

cooling capability, and the increased capital

cost of turbines designed to operate in a higher

pressure environment. In a strictly economic

tradeoff, a decision to use these systems would

be correct if the cost of water began to approach $700 to $1 ,000/acre-foot. In few circumstances would this tradeoff be made today, but these systems still might be utilized

where water is unavailable for physical or political reasons.

In addition to the environmental impacts

associated with their cooling systems, powerplants generate additional water pollutants in

the form of a blowdown from the boiler and

acid drainage from coal storage piles. However, these pollutant sources are relatively

minor compared to their counterparts from the

cooling and extraction portion, respectively, of

the fuel cycle

Wastes From Coal Combustion

Under current and future combustion control technologies, coal impurities are removed

from the air– onIy to reappear in solid or slurried form. An air pollution problem is thereby

transformed into a waste disposal problem.

The concentrations of undesirable constituents within the wastes demand strict attention

to disposal methods to prevent contamination

of surface or ground waters.

The wastes generated by coal combustion

facilities are the fly ash from particulate control devices: the bottom ash and slag from the

boilers, and the sludge from FGD systems. In

the future these wastes may include spent sorbent from fluidized-bed combustion (FBC)

units. By 1985, the quantities of ash and slag

requiring disposal may total 80 million tons,

and that of sludge may be 19 million tons

assuming moderate coal growth. These wastes

represent approximately half of the Nation’s

total noncombustible solid waste and industrial sludges, respectively. By 1990, the

quantities of coal combustion waste requiring

disposal may grow to 90 million tons of ash

and slag, and 35 million tons of scrubber

sludge (NE F #1).

The major ash-producing areas are the Middle and South Atlantic and Midwestern States.

By the end of the century, the Southwest is expected to join these regions as a major ash producer. With the exception of New England and

the Northwest, the rest of the country should

also experience substantial increases in ash

production in the near future. Although sludge

production is relatively minor now, by the end

of the century the South Atlantic and Midwestern States should be major sludge producers,

with the New York/New Jersey, Middle Atlantic, Southwest, and Central regions being major contributors.8 G

The potential disruption of water quality by

these ash and FGD wastes depends largely on

their chemical and physical structure. The ash

is an alkaline material consisting primarily of

insoluble inorganic elements (most of which

are enriched in concentration compared to

their natural abundance), as well as elevated

levels of radionuclides. Up to 10 percent of the

ash consists of water soluble species, principally calcium, magnesium, potassium, sulfate,

and chloride. The presence of these materials

creates a strong potential for leaching of ash

components into surface and ground waters

unless the ash is carefulIy disposed. a

’

The sludge from FGD systems varies with the

scrubber design and operation but in general

consists primarily of calcium sulfite or calcium

sulfate with some carbonates, inert elements,

and insoluble ions.88 Calcium sulfite hemihydrate (the major species in the lime/limestone

scrubbers) consists of small, thin crystals that

settle very slowly, making the sludge difficult

to dewater and contributing to its physical instability.

‘

b

’’ Appendix on Ash and Sludge, ” Rail Report.

“Ibid , p. 11,

881 bid., p. 13
Ch, V—Environmental Impacts ● 241

FGD sludge pond–Commonwealth

The concentration of trace elements in FGD

sludge is much smaller than that in fly ash;

those that are present tend to be elements that

escaped the ESP in gaseous form or that came

from the sorbent used. Often fly ash and FGD

sludge are combined for disposal, and the mixture may be referred to as flue-gas cleaning

(FCC) wastes. The ash helps increase the solids

content of the sludge but also contributes a

substantial load of trace elements to the mixture.

Whether these undesirable elements in FCC

wastes enter surface or ground water depends

on the disposal method used. The disposal

methods traditionalIy used for ash and currently being considered for FGD are impoundments (ponds), landfill, and utilization, in

decreasing order of common use for ash.

Open-cycle ponds allow direct discharge of

Photo credit: EPA — Documer/ca

Edison’s Will County powerplant

ash transport water to receiving streams. Some

of the solids and trace metals that are not in

solution in the alkaline ash medium may dissolve as the pH is lowered in the receiving

stream. If the ash transport water pH exceeds

9, it may have to be treated with sulfuric acid,

causing the formation of a precipitate (floe)

that can affect the receiving stream.

In addition to direct discharge to surface

waters, ponded wastes may leach to ground

water. In the case of sludge, the leaching

comes both from the fluid (liquor) initially

present and from the dissolution of sludge

solids once the fluid is gone, The major soluble

species in most FCC (combined) wastes are

chlorides and sulfates (primarily in calcium,

sodium, and magnesium salts). 89 These species

“Ibid , p 11
242 The Direct Use of Coal

have been found in high levels in FCC leachates and would increase the TDS of ground

and surface waters if leaching or surface

discharges occurred. In addition, trace elements present in the ash may be leached out

and added to the potential groundwater containination.

The characteristics of FCC discharges that

are most important from an environmental impact standpoint are the:

● presence of small particles,

• high trace element concentrations, and

● reducing capacity of sulfite-rich sludge.90

Trace element contamination of surface and

ground water can lead to ingestion by aquatic

organisms and contamination of soils (and, in

turn, crops). Iron oxide floe and the FCC sludge

itself can coat the bottom of streams and disrupt bottom communities. The oxygen demand

of sulfite-rich sludge can cause serious stresses

on aquatic Iife by depleting oxygen supplies.

These and other impacts, coupled with the

very substantial increases expected in FCC

waste generation, focus attention on the importance of appropriate specification of required controls for waste disposal.

Virtually all of the above pollution impacts

of waste disposal are controllable with available techniques, as discussed below, and both

surface discharge and leaching to ground

water fall under existing regulations (discussed

in the following section). Although leaching of

salts and trace elements into ground water

generally is considered a major problem with

FCC disposal, the actual impact is extremely

dependent on site-specific factors. In some

cases, it could be quite small because of the

attenuation of pollutants as they pass through

soil layers. Unfortunately, gaps in our knowledge of the pollutants present, the attenuative

nature of different soils, and the actual physical characteristics of ground water systems

complicate the specification of potential environmental effects.

As noted previously, the options for coal

combustion waste disposal include impoundment, landfill, and utilization. Considerable experience exists with the disposal of ash by all

of these methods. Pending has been the most

common because it is the easiest and cheapest

method; ash is sluiced to a lagoon near the

plant, and the water is either returned or discharged. The imminent restrictions on ash

transport water discharge and the declining

availability of land near powerplants may discourage future use of ponds (at least opencycle ponds) for ash disposal.

Ponds are less satisfactory for disposal of

FGD sludge (either alone or mixed with ash)

than they are for ash. The use of a pond for

sludge disposal represents a long-term commitment of the land; pending of untreated sludge

(and perhaps even some treated sludge) does

not result in the degree of settling that would

be required for future development on the site.

The problems of leaching associated with

pending of wastes mandate attention to possible lining of the pond, selection of a pond site

with highly impermeable soil, and treatment of

the sludge itself to reduce its porosity and

permeability. In addition, continual removal

of the surface layer of water that develops in

the pond from rainwater or other runoff is

necessary.

These problems with pending appear to be

turning more plant operators in the direction

of landfill for FCC wastes,9

’ despite its higher

cost. For landfill purposes the ash is collected

dry and the sludge is dewatered and/or treated

to improve its structural properties. In this

form the wastes are more easily transportable

than the wet sludge, allowing the landfill site

to be further from the powerplant, perhaps in a

less valuable location. However, the cost of

transporting the dried and treated sludge is

high, and onsite disposal will be favored where

it is possible. Land impacts are decreased with

landfill because of the smaller area and shorter

retention time required before the land can be

developed. As a tradeoff, the air pollution

from fugitive dust (especially for a dry ash

landfill in an arid climate) is greater during

9[)1 bid

“J. Jones, “Disposal of Power Plan:t Wastes, ” pre

-

sented at the Third National Interagency Energy/Envirorrmental R&D Conference, Washington, D.C, June 1978
Ch. V—Environmental Impacts ● 243

transport and disposal. This effect is highly

local and may be mitigated by use of a wetting

agent or by a buffer zone around the site.

Before sludge may be used for landfill it

must undergo some physical or chemical treatment to improve its structural stability and

reduce its volume, permeability, and porosity.

One method is to alter the operation of the

scrubber itself to force the oxidation of sulfite

to gypsum. Alternatively, one might exploit the

finding that some modes of scrubber operation

seem to produce forms of calcium sulfite that

are easier to dewater. 92

The FGC wastes may be dewatered by several physical techniques such as vacuum filtration, centrifugation, or gravity settling in order

to increase the percentage of solids (65 to 70

percent is desirable). Adding ash to the sludge

also increases the solids content and lends

structural strength.

Several commercial chemical sludge treatment processes have been developed and are

being used by coal-fired plants. Field tests of

chemically treated wastes demonstrate significant structural improvement and a reduction

in permeability, as well as a reduction in the

concentration of dissolved solids in the leachate and a decrease in the actual volume of

leachate. ” An additional benefit of sludge

treatment is the improvement in handling

characteristics, which allows better sludge

placement and thus additional control of

leaching.

Another disposal method for FCC wastes is

burial with the mine wastes. This technique is

felt to be too expensive for underground mines

but may be feasible for surface mines. The

concept is made more appealing by the coal

transportation link that connects a mine with a

plant. Alternatively, the plant may be a minemouth plant with close ties, both geographically and economically, to the mine. The mine

may welcome the wastes as additional fill to

restore the original land contour and, in the

East, as alkaline material to help neutralize

some of the acid wastes. It is not known

92lbld , p 12

‘

]

’’ Appendix on Ash and Sludge, ” Rail Report

whether the economics and institutional links

between mine and plant are favorable enough

on a large scale to promote widespread use of

this disposal method.

Another disposal method for FCC wastes is

to dump them in the ocean. The idea is appealing for northeastern utilities that are close to

the coast but have little space to store wastes.

The concept is further encouraged by the fact

that the major chemical constituents in FCC

wastes are already in relatively high concentrations in seawater. Promising forms of disposal

are concentration of treated FCC wastes in

bricklike form or dispersion of treated or

sulfate-rich FCC wastes in either deep ocean or

on the Outer Continental Shelf .94 The environmental impacts of ocean disposal are being

investigated by EPA.

The utilization of wastes is more appealing

from a resource conservation standpoint than

is disposal, but it is not always as economicalIy

attractive. About 20 percent of all ash is now

used for some purpose, and the National Ash

Association is actively pursuing new uses for

ash. The most promising use is in the manufacture of portland cement. Approximately onethird of the 1980 fly ash production could be

used for this single application .95 Other uses

are as a light aggregate for construction, as a

filler for asphalt, as an abrasive, and as a soil

additive. In addition, extraction of valuable

minerals from the ash may be economically

feasible.

The potential uses for sludge are not as

numerous. In Japan, scrubbers are operated so

as to produce gypsum, which is then used for

wallboard and portland cement. However, the

economics are not favorable enough for FCC

wastes to penetrate the market in this country .

9 6

An alternative to sludge disposal is to avoid

sludge generation altogether. Several “regenerable” systems have been developed for FGD.

These typically produce elemental su!fur or

sulfuric acid. Some wastes are emitted as a

“J. Jones, “Disposal of Flue-Gas Cleaning Waste, ”

Chemical Engineering, Feb. 15, 1977

“Jones, R&D Cont., p 1

“Ibid , p 2
244 ● The Direct Use of Coal

bleed stream, but the volume is far less than

wastes from nonregenerable systems. Sulfur is

unfortunately not a scarce element but may

become valuable when present sources are

depleted.

Only general statements can be made about

the waste disposal problems associated with

the spent sorbent from FBC, because no largescale demonstration yet exists. The amount of

sorbent waste generated will depend on the

chemical balance needed to assure adequate

removal of sulfur in the coal, but indications

now are that the volume will be greater than

that of sludge for a plant of comparable size

burning the same coal. By contrast with

SIudge, however, the sorbent has a much

higher solids content and greater structural

stability. Among the possible uses being investigated is as an agricultural fertilizer.

A key to the actual waste disposal alternative selected will be the application of the Resource Conservation and Recovery Act (RCRA)

described in the following section. Designation

of sludge as a “hazardous” material under

RCRA will result in extensive use of liners,

chemical fixation, and landfill disposal of

scrubber sludge. DOE has estimated that such

a designation could increase sludge disposal

costs by about 20 percent over costs incurred

by a “nonhazardous” designation” to a total

of about $600 million per year by 1990. Similarly, designation of ash as hazardous material is

estimated to yield a 30-percent increase over

the costs incurred with a nonhazardous designation, to a total of about $1 billion by 1990

for utilities. As even a nonhazardous designation will require an upgrading from present

practice, the total cost of disposal for sludge

and ash is estimated to increase up to 45 percent over present practice for a nonhazardous

designation, and up to 84 percent if both are

designated hazardous. The incremental cost of

waste disposal on electric generation was

estimated to range from 1.22 to 2.01 mils/kWh

under RCRA; in comparison, continuation of

current practice would cost approximately 1

mil/kWh (NEF#l). All of these cost estimates

have been challenged by the utility industry as

“National Environmental Forecast No 1.

being severe underestimates of the costs that

wilI have to be borne under RCRA.

These costs must be balanced against the

protection of ground waters and reduction in

Iand use impacts provided by the increased

controls. An unfortunate side effect of a hazardous designation for ash might be the elimination of the ash byproduct market, but this is

clearly dependent upon the precise nature of

EPA’s regulatory stance,

Regulations

Impacts to water systems are regulated

under the Clean Water Act, the Surface Mining

Control and Reclamation Act (SMCRA), and

RCRA. These are discussed in detail in chapter

VII and summarized below.

The Clean Water Act sets effluent limitations for chemical and physical discharges

from steam electric-generating plants, coal

preparation plants, and coal mines. For generating units, limitations have been established

for discharges of: total suspended solids and

oil and grease from low-volume waste sources,

ash transport water, metal-cleaning wastes,

and boiler blowdown; copper and iron from

metal-cleaning wastes and boiler blowdown;

free available chlorine from once-through

cooling water and cooling tower blowdown;

and materials added for corrosion inhibition,

including zinc, chromium, and phosphorus,

from cooling tower blowdown. In addition, discharges of total suspended SO I ids from material storage and construction runoff are regulated.

For coal mines and coal preparation plants,

limitations have been established for discharges of iron and total suspended solids

from acidic and alkaline mine drainage, and

for manganese from alkaline drainage. In addition, the pH of all discharges from generating

units, mines, and preparation plants must be in

the range of 6.0 to 9.0.

The Clean Water Act also limits thermal discharges from steam electric-generating plants.

Standards of performance for new units provide that there shall be no discharge of heat

from the main condensers; existing units (with
Ch. V—Environmental Impacts ● 245

some exceptions) must meet this limit by 1981.

In addition, the Act requires that the location,

design, construction, and capacity of cooling

water intake structures reflect the best technology available for minimizing adverse environmental impacts such as impingement and

entrainment of organisms.

Effluent sources must obtain a permit under

the National Pollutant Discharge Elimination

System (NPDES), which includes all applicable

effluent limitations. Variances are available

only for sources that can demonstrate that factors related to the equipment or facilities involved, the process applied, or nonwater quality impacts (such as economic factors) are fundamentally different from the factors considered by EPA in establishing the effluent limitations.

For the most part, the effluent limitations

established under the Clean Water Act are intended to achieve a water quality goal that

provides for the protection and propagation of

fish, shellfish, and wildlife and for recreation

in and on the water by 1983. Stricter I imitations designed to eliminate all pollutant discharges will not be enforced until at least the

late 1980’s.

No Federal regulations deal with water consumption by coal combustion facilities. Water

rights traditionally have been regulated by the

States, and the means of allocation vary widely by region. The 1977 amendments to the

Clean Water Act reaffirmed this system by

stating that the Act in no way impairs the authority of each State to allocate quantities of

water within its jurisdiction. However, the Act

does require that water resource management

be considered in State water quality planning.

SMCRA sets performance standards for surface mines and for the surface operations of

underground mines that are designed to prevent acid and other toxic drainage as well as

runoff containing suspended sol ids, and to prevent disruptions in local water supplies. Mandated practices to control surface minerelated water pollution include stabilizing

disturbed areas, diverting runoff, regulating

the channel velocity of water, lining drainage

channels, mulching, selectively placing and

sealing acid-forming and toxic-forming materials, selectively placing waste materials in

backfill areas, achieving rapid revegetation

and, where necessary, maintaining water treatment facilities. In addition, all surface drainage from disturbed areas must be passed

through at least one sedimentation pond.

Additional requirements for underground

mines include designing mines to prevent gravity drainage of acid waters and sealing and

controlling subsidence. Similar provisions apply to support facilities such as coal loading

and storage facilities, roads and other

transportation faciIities, and mine buildings.

SMCRA also requires mine operators to

minimize hydrologic disturbances. Overland

flows and stream channels may be diverted

when necessary to comply with other performance standards in the Act and when the diversion meets specified engineering standards. In

addition, mine reclamation must restore the

premining capability of the area to transmit

water to the ground water system. The mine

operator also must replace water supplies used

for domestic, agricultural, industrial, or other

uses when they become contaminated, diminished, or interrupted as a result of mining activity.

In order to obtain a mining permit, the mine

operator must demonstrate that these requirements will be met and that they will be adequate to comply with all applicable Federal

and State water quality standards and effluent

limitations.

The disposal of combustion byproducts is

regulated under the Clean Water Act and

RCRA. Where the wastes are discharged to

receiving waters, they come under the Clean

Water Act; an example, as discussed above, is

ash transport water. Land disposal of the

wastes is regulated under RCRA, which seeks

to control open dumping of wastes under a

system of State plans and permits for waste

disposal. The Act distinguishes hazardous and

nonhazardous wastes and places more stringent restrictions on the former. If either ash or

scrubber sludge is determined to be hazardous, the disposal options for these substances

are constrained. For example, sludge ponds
246 ● The Direct Use of Coa/

would have to be constructed in a manner that

would prevent any leaching to the ground

water. Similarly, burial of wastes or their use in

landfills or in roadbeds would be prohibited

where there is any possibility of leaching. In

addition, disposal of hazardous wastes would

be prohibited in wetlands or floodplains

(where most large combustion facilities such

as powerplants are located), adding substantial

transportation costs to the waste disposal

costs.

IMPACTS TO THE LAND

The impacts from air pollution provide an

interesting contrast to the direct impacts to the

land caused by the use of coal. The air emissions from the coal fuel cycle stem primarily

from coal combustion. Many of the impacts

are subtle or are masked by other factors;

others take a long time to become manifest.

By contrast, the land impacts of the use of

coal stem primarily from the mining and waste

disposal portions of the fuel cycle. These impacts are more site specific and often cause

acute and drastic alterations of a local area.

The land impacts of mine activities are more

likely to damage plantlife, animals, or human

beings by mechanical harm (such as that resulting from removal of habitat or from landslides and floods) than by chemically induced

damage. Some land disruptions, such as blasting damage, may be short term. Others, such

as subsidence, may Iinger for many years.

A variety of impacts to other media result indirectly from perturbation of the Iand by coal

extraction and waste disposal. These include

air pollution from coal mine fires and fugitive

dust or water pollution from waste pile runoff.

Although the specific details are treated in the

sections concerned with the air and water

media, the interaction of the three media

shouId not be forgotten.

Sources, Effects, and

Control of Land Impacts

Surface Mines

Although estimated future coal production

levels, and therefore land use impacts, vary

considerably with assumptions about environmental policy and economic conditions, most

studies show a very substantial increase in surface mining in the northern Great Plains and,

to a lesser extent, in the Southwest. Surface

production in the Midwest fluctuates widely in

the long term with varying assumptions, although it is unlikely to increase much by 1985.

As shown in table 36, Western surface mining disturbs considerably less land per ton of

coal extracted than do Eastern and Central surface mining. This occurs because many Western coal seams are over 50 feet thick, allowing

extraction of more tons per mined acre.

The most obvious land impact of a surface

mine, while it remains active, is the complete

removal of the land from its normal uses. The

Table 36.—Land Affected by Coal Utilization

Acres over

30-year

Facility period

Mining: 10T5 Btu’s per yeara

Western strip ..........................................4...

Central strip . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Central room and pillaP . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Eastern contour . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Eastern room and pillarb . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Gob and refuse disposalc 

. . . . . . . . . . . . . . . . . . . . . . . . . . .

Combustion/Conversion: c Input of 10’5 Btu’s/

year

Powerplants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lurgi gasification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Synthoil liquefaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

15,000-96,000

216,000

525,000

470,000

560,000

15,000

13,600

6,500

6,300

SOURCE: Calculated from White et al , “Energy from the West”, EPA—60017-77.

072a, July 1977.
Ch. V—Environmental Impacts ● 247

surface covering, which may have been agricultural crops, range land, forests, or desert, is

replaced by the sights of excavation and the

sounds of blasting. Wildlife, deprived of food

and cover, must migrate if possible to other

areas. The unsightliness may degrade both

property and scenic values, impacting a distance beyond the mine equal to the extent of

the vista. Thus the surface mining of one

mountain can alter the recreational quality of

a large geographical area.

Once the coal resource has been extracted

from a given area, the land generally can be

recontoured and revegetated so that it can

support former uses. There is sufficient reclamation experience with most of the coal-producing areas to suggest that successful reclamation will occur with the appropriate commitment of resources. Doubts about the success of reclamation procedures, however, have

been fostered by the poor attention given to

reclamation in the past. Some 420,000 acres of

mine lands are unreclaimed. Although more

stringent reguIations and keener public awareness should produce a better record in the

future, the past can serve as a reminder of the

importance of constant monitoring. Doubts

about reclamation also stem from lack of experience in reclaiming some of the more ecologically fragile regions to be mined in the

future. In particular, experience with revegetating strip mines in the arid or semiarid

regions of the West is not extensive. A key

issue here is whether apparently successful

reclamation efforts may degrade over time, especialIy in the face of periodic droughts.

The concern over reclamation centers on

lands that play a unique vital role in a region,

and many of these critical lands are protected

by the 1977 SMCRA. Among these are the alluvial valleys, which often form the backbone of

the ranching and farming economy in semiarid regions. Even though only 3 percent of the

coal leases in an eight-State area of the West

underlie such valleys, the shallow overburden

there makes these lands most attractive for

mining. ” Some fear that even strip mining in

the lands adjacent to alluvial valleys, where 10

percent of the strippable coal exists, may have

9“’Appendix on Reclamation, ” Rall Report, p 27

hydrological impacts that would affect the

agricultural productivity of the valley floors.

As discussed below, SMCRA strictly regulates

mining on alluvial valley floors, but interpretation and enforcement of the law’s provisions is

critical to the actual degree of protection afforded these lands.

Another type of land where surface mining

might threaten the resumption of a vital function is the agricultural farmland of the Midwest. Before passage of SMCRA, new strip mining would have encroached on prime agricultural lands. For example, in 1976, about 75 percent of the surface mine permits issued in 11-

Iinois were for lands classified as prime agricuItural lands by the Soil Conservation Service . The main concern surrounding agricultural lands is that the ecology of the soil system is too little understood for the success of

reclamation to be guaranteed. Only recently

have researchers begun to treat soil as an

ecosystem rather than as a mineral. 00 It is not

known whether the soil productivity deteriorates as the soil layers are removed, separated, piled, and stored.

Some concern also centers on stands of

hardwood timber in southern Appalachia that

require decades or even centuries of natural

forest succession to become re-established.

The Ponderosa pine forests in the West also

are believed to be quite difficuIt to reestablish. A final concern is that some areas

(southern Appalachia in particular) have such

steep slopes that reclamation is unfeasible.

The rapid erosion of soil prevents successful

rooting of vegetation.

Surface mine reclamation usually proceeds

in parallel with excavation; the overburden

and topsoil from the active area are placed in

the area of the previous cut. The overburden is

backfilled, graded, and compacted. The topsoil is removed and replaced as a separate

layer. The land is then replanted with some

species of vegetation.

Besides merely replacing topsoil and overburden separately, these materials must be

“Department of Mines and Minerals, “1976 Annua l

Report – Surface Mine Land Conservation and Reclamation, ” Springfield, III , 1976

1

100’’Appendix on Reclamation, ” Rail Report, p 35
replaced properly: toxic or acid-producing

layers in the overburden must be identified

and covered by sufficient depth of acceptable

material to prevent containinants from entering the aquatic environment; layers must be

ordered to prevent fine topsoil particles from

being swallowed by coarse particles. Finally, a

thick layer of subsoil must underlie the topsoil.

All plans for soil layer replacement must be

based on thorough analysis of the overburden

in the area.

In prime agricultural lands, the permanent

provisions of SMCRA require the segregation

of topsoiI horizons so that the root zone can

be reestablished. Before a permit is granted for

a new surface mine in such areas, the operator

must demonstrate that the original soil productivity will be restored. Some operators currently mining prime farmlands contend that they

have indeed done this, but the regulations require proof in the form of scientifically valid

experiments.

The provision to return land to its approximate original contour will help minimize any

permanent disruption by surface mining in

most locations. However, universal application of this requirement may be inappropriate.

I n the steep terrain of Appalachia, reclamation

of slopes greater than 300 may be hindered if

the land must be returned to its original slope,

as the long, uninterrupted slopes will promote

erosion. (The law does, however, allow the use

of terracing and other erosion control measures to alleviate this problem. ) In other areas,

local governments and residents might prefer

alternative configurations to allow new uses

(or enhance old uses) of the land. For instance,

land contour shaping can be used to trap water

and allow growth of important wildlife cover

in portions of the arid West.
Ch. V—Environmental Impacts ● 249

Underground Mines

Although less conspicuous than surface

mines, deep mines nevertheless can have severe impacts on the land. Aside from their impacts on hydrology, underground mines have a

potential for subsidence. This problem occurs

when the support of the mine roof either shifts

or CO I lapses. While subsidence can occur during the active operation of a mine, it is more

likely to be delayed for many years as the mine

pillars slowly erode and collapse. The altered

ground slopes can damage roads, water and

gas lines, and buildings. The subsidence may

further change natural drainage patterns and

river flows, intercept aquifers and existing

springs, or create new springs and seeps.

The extent, severity, and timing of the subsidence are complex functions of soil composition, overburden thickness, and mining method, to name only a few relevant factors. The

difficulty in predicting and preventing subsidence complicates land use planning greatly.

Just the potential for subsidence may reduce

the land available for construction of homes

and businesses. Even farming of the land may

be discouraged by possible future unevenness

of the surface.

Unfortunately, reliable surveys of subsidence do not exist, although a sizeable percent of the 8 milIion acres undermined to date

have experienced some degree of subsidence,

and more of this acreage may yet subside in

years to come. Future subsidence impacts will

depend heavily on the success of preplanning

and control measures, and upon the degree to

which underground mines will contribute to

the future U.S. coal supply. A Bureau of Mines

report estimates that a potential 1.5 million

acres would be affected by subsidence by

2000. 101 A study of the environmental impact

of the National Energy Plan assumed that 35

percent of coal production would come from

underground mines by 2000. The study predicted that, in that year, underground mines

would account for three-fifths of the land

disturbance by total coal production. Most of

the impact would be in the Middle and South

‘“’’’ Appendix on Acid Mine Drainage and Subsidence,” Rail Report, p 37.

Atlantic regions, where underground mines

could affect up to a few percent of the total

land in those regions. 102

The amount of land potentially disturbed by

underground mines is greater than that for surface mines of the same production capacity,

as illustrated in table 36. This table compares

the land affected by 30 years of various types

of coal activity that produce or consume 1

Quad of energy. This comparison between the

effects of surface and deep mines must be

made cautiously. Surface mining disturbs all

the land, but for a limited time. For deep

mines, one can cite only the maximum amount

of land that could be disturbed, with the actual acreage, duration, and degree of disruption subject to greater uncertainty.

Subsidence problems can be addressed by

both preventive and corrective measures. The

common preventive measure for subsidence is

to leave a considerable portion of the coal

itself — sometimes as much as half — in place

as a roof support.

Another strategy is to allow subsidence to

occur but in a controlled manner. In this

scheme, called longwall mining (see chapter

I II) each section of the mine is collapsed after

all the coal is extracted. This allows surface

subsidence to occur sooner than with room

and pillar mining, and the subsidence also occurs more evenly with major disruptions only

at the perimeter of the mined area. Thus,

future plans for the land may be made with

greater certainty. Longwall mining is used extensively in Europe, but there has been less experience in the United States.

One of the few corrective measures that can

be applied to existing mines is to backfill them

with mine waste or other materials (including

FGD sludge). At first glance this suggestion

seems to solve the waste disposal and subsidence problems at the same time. More extensive studies, however, reveal that this method

is quite expensive, involves considerable

hazard to workers and may release contami-

‘

[

’

2 Annual Environmental Analysis Report, Vo/ume I

Technical Summary (Washington D C U S Energy

Research and Development Administration, Office Of

Environment and Safety, September 1977)
250 ● The Direct Use of Coal

nants into the ground water. I n addition, some

mine wastes and untreated sludge lack the

structural strength to provide the needed support for the mine roof. An additional technique that is quite feasible for some of the

shallower mines is “daylighting;” it involves

surface mining to obtain the remaining coal

and reclaiming the entire area. This technique

is a cure for acid mine drainage as well as subsidence in abandoned mines.

Regional Factors

The regional variation of the extent of land

disturbed is largely a function of the thickness

of the predominant coal seams. Western coal,

although low in heating value (and thus at a

certain disadvantage when comparing impacts

on a unit energy basis), affects strikingly less

acreage than either Eastern or Central coal

because of the extreme thickness of the coal

seams (seams greater than 50 feet in thickness

are not uncommon). On the other hand, many

Appalachian seams are only a few feet thick

and thus require the disturbance of considerably greater acreage to extract the same coal

energy. In fact, virtually all of the effects of

mining vary greatly with geographical factors,

so it is instructive to give an overview of the

pertinent characteristics of each general provi rice.

The major coal-producing area in the East –

Appalachia —can be divided into two regions,

based on differing concerns over mining. In

northern Appalachia, stretching upwards from

the northern coalfields of West Virginia, the

topography is not rugged, and the soils contain

substantial acid-forming materials. The region

is densely settled, and the land is dotted with

small farms and forested primarily with softwoods. By comparison, southern Appalachia

has more steep, rugged terrain and smaller

concentrations of acid-forming strata. The

population is less dense and the forests are

mainly hardwoods.

These characteristics make the impacts of

acid drainage more severe in the northern region and necessitate careful attention to proper management of toxic spoil banks there. In

addition, the subsidence problem is of greater

impact in northern Appalachia, for more lands

are subject to residential or agricultural development. A considerable fraction of the subsidence problem in Pennsylvania has resulted

from the underground mines in the urban areas

of the anthracite region.

The problems of surface mining are more severe in southern Appalachia because of steep

slopes and heavy rainfalls. The stands of hardwood forests require much longer times to reestablish than do the softwood forests of the

northern region.

Surface mining in the Illinois Basin will be

limited in those portions that are designated as

prime farmland, as discussed earlier. In other

regions, reclamation is facilitated by relatively

flat topography and favorable rainfall. The impact of subsidence from underground mining

in this region is relatively unknown, but subsidence may pose serious problems for agricultural lands.

Over the next several decades, surface mining is expected to dominate coal extraction in

the northern Great Plains. The key problem in

reclamation will be the scarce water supply

and rainfall, coupled with the lack of experience with reclamation in this region. The

alluvial valleys in these regions are protected

by the SMCRA, as discussed earlier.

Surface mining also will be the dominant

mining method in the gulf coast, where lignite

reserves are concentrated in Texas. Except in

the areas south of the Colorado River, rainfall

appears adequate and potential land impacts

minimal.

In the Rocky Mountains, most mines in western Wyoming, western Colorado, and Utah will

be underground. The low population density

and infrequent farms should minimize economic damage from subsidence. By contrast,

the subbituminous coal deposits in New Mexico and Arizona will most likely be surface

mined. The limited rainfall could hamper

reclamation efforts, but some mines have been

successfully revegetated when irrigated.

Therefore, the surface mine impact there is

uncertain.
Ch. V—Environmental Impacts ● 251

Mine Waste s

Both surface and underground mines gener -

ate large quantities of wastes that impact both

water and land. The waste is of three types:

1. the solid waste from underground mines,

which commonly is called “gob” and corresponds in composition to the overburden removed in surface mining;

2. the refuse from coal washing and preparation, which consists of coal waste and

other impurities; and

3. the sludge resulting from treatment of

acid mine drainage.

The total amount of solid waste generated

by coal mines in 1975 was estimated to be

almost 50 milIion tons.

Although the percentage of coal that is

washed has decreased from about 65 to 41 percent between 1965 and 1975, the fraction of

coal that is discarded has increased from

about 20 percent to around 29 percent. One

reason for the larger quantity of waste from

coal cleaning is the greater use of automated

equipment that digs less selectively than the

hand-mining methods of the past. A second

reason is that most coal is now being extracted

from seams that are less rich and hence contain more impurities. More than 3 billion tons

of waste Iie in 3,000 to 5,000 refuse banks in

Eastern coalfields.

One of the most obvious impacts of these

unsightly wastes is the degradation of local

property values and destruction of esthetics.

The land used for waste disposal, unless reclaimed, is no longer available for other uses.

Furthermore, the gob, refuse, and sludge create dangers of many kinds if effective disposal

techniques are not applied to them. First, the

refuse piles contain flammable material that

makes them susceptible to spontaneous combustion. They are also vulnerable to landslides

and erosion because they usually are comprised of mixed, poorly graded, and uncompacted material. These wastes have been used

to construct dams near the minesite for impoundment of water or slurry, a use to which

they are poorly suited. The danger of this practice was dramatized in 1971 when such an impoundment, in Buffalo Creek, W. Va., broke

during a heavy rainstorm and flooded the valley below, causing more than 125 deaths and

millions of dollars in property damage. A 1974

study of dams in the East, only 40 percent completed, found 30 similar water impoundments

that were classified as imminent flood hazards

and 176 additional structures that were classified as potential flood hazards ‘“3

A major concern about coal gob and refuse

piles — especially in the eastern regions — is

their content of acid-producing materials. Exposure of these layers to air and water causes

the leaching of coal impurities into surface

and ground waters. Erosion of these wastes

also contributes sediment and dissolved sol ids

to local waterways, as was discussed in the section on water impacts.

Transportation and Transmission

The key factors determining the land requirements for the various coal energy transportation modes are the right-of-way requirements, disturbances outside the right-of-way,

the directness of the route, barriers created,

other uses of the right-of-way, and other uses

of the mode. Transmission and waterways generally require the widest paths, typically about

200 feet. Waterways may also produce flooding for a much wider distance, or require extensive areas for disposing of dredged material,

Slurry pipelines may disturb large areas during

construction. Rails, waterways, and highways

may act as barriers to people or wildlife. These

three modes can be useful for other purposes,

while slurry and transmission lines are dedicated to one product. The rights-of-way of the

latter, as well as those of waterways, however,

may have multiple uses such as pathways or

farming, which may provide a Iand benefit. In

the case of very high-voltage transmission

lines, multiple use may be compromised because of the possibility of electrical effects.

The existence of these effects remains a controversial issue.

‘“’ The National Strip Mine Study– Vol. 1, Summary Report, (U S Department of the Army, Corp of Engineers,

Washington, D.C. 1974)
252 ● The Direct Use of Coal

Coal Combustion

AS noted earlier, both the ash and the scrubber sludge produced by utility and industrial

boilers represent a very sizable disposal problem. With particulate collectors on most large

coal-fired boilers, 92 percent of all fly ash generated in the United States is now collected.

This collection efficiency should increase with

time because Federal standards now require

greater than 99-percent collection for moderate and large boilers. Also, provisions for requiring technological controls for SOx will

yield increasingly large amounts of scrubber

sludge requiring disposal. As noted in the previous section, the total solid waste— fly ash,

bottom ash, and slag–generated in 1985 is

projected to be approximately 80 million tons

per year, while scrubber sludge is expected to

be about 19 million tons assuming moderate

coal growth. ’04 Although this weight of sludge

is only about one-quarter of that projected for

ash wastes, the two materials may necessitate

comparable storage volumes because of the

high water content of the sludge. For example,

the sludge produced in 1 year by a “typical”

1,000-MW powerplant (3.5 percent sulfur, 90

percent SO2 removal, 12 percent ash, 6,400

hrs/yr, 20 percent excess lime, 50 percent oxidation, 0.88 lb coal/kWh) requires 630 acre-feet

of pond volume if it is 40-percent solids and

270 acre-feet if the sludge is dewatered to 70-

percent solids. The ash produced in 1 year

would occupy about 140 acre-feet. Over a 30-

year lifetime, the plant would require about

600 acres for waste disposal (assuming the ash

and dewatered sludge are mixed and placed in

a 20 feet thick storage area). By the year 2000

or so, the cumulative storage area devoted to

these wastes could approach 100,000 acres, or

welI over 100 square miles (based on the same

assumptions).

Although the land use requirements for

sludge disposal are similar to those for ash

disposal, the actual land impact attributed to

the sludge could be considerably greater than

that of the ash if pending remains a predominant sludge storage mechanism; in that case,

the land utilized will be unavailable for devel-

‘(’’National Environmental Forecast No. 1.

opment for a considerable period. The choice

of disposal technique, if not dictated by RCRA,

should depend largely on the value of land, Of

the major sludge-producing regions, the more

densely populated ones–the Midwestern,

New York/New Jersey, and MiddIe Atlantic

regions — might be expected to lean heavily

toward landfill disposal. As the major problems associated with obtaining suitable land

disposal sites may fall on industrial coal users

rather than on utilities — because the industrial

plants may be expected to locate closer to urban centers– industrial users may also be expected to lean more heavily toward landfills.

However, other factors, such as the importance and vulnerability of ground water and

the State and local regulatory climate, should

play a major role in disposal decisions.

Regulations

The land impacts of coal production and use

are regulated primarily under SMCRA and

RCRA, which are directed at mining and waste

disposal practices that tend to cause land impacts. In addition, a variety of provisions cover

the potential land impacts of transportation

and transmission. These laws are summarized

below and discussed in detail in chapter VI 1.

The primary purposes of SMCRA are:

●

●

●

to ensure that surface coal mining operations are conducted in a manner that protects the environment,

to ensure that adequate procedures are

undertaken to reclaim surface areas as

contemporaneously as possible with mining operations, and

to strike a balance between protection of

the environment and agricultural productivity and the Nation’s need for coal as an

essential source of energy.

i o accomplish these ends, SMCRA mandates State permit systems in accordance with

Federal guidelines that include comprehensive

performance standards for surface mining

operations and for the control of surface effects of underground mining.
Ch. V—Environmental Impacts ● 253

For surface mining, the environmental performance standards regulate the removal, storage, and redistribution of topsoil; siting, erosion control, drainage, and restoration of coal

haul roads; protection of water quality and the

hydrologic balance; waste disposal; backfilling

, grading, and revegetation, and postmining

land uses. This section discusses those provisions of SMCRA that relate to areas of special

concern, such as alluvial valleys and prime

farmland. The overall legal framework of the

Act is discussed in chapter VI 1.

Minimum performance and reclamation

standards for alluvial valley floors in the arid

and semiarid areas in the Western United

States are intended to preserve existing or

potential agricultural uses and productivity.

An applicant for a mining permit in these areas

must demonstrate that the operations will preserve the essential hydrologic functions of an

alIuvial valIey floor by maintaining the geologic, hydrologic, and biologic characteristics

that support those functions. These requirements apply both to disturbed and adjacent

undisturbed areas. I n addition, surface mining

and reclamation operations may not interrupt,

discontinue, or preclude farming on alluvial

valley floors unless the premining land use is

undeveloped rangeland or the area affected is

small and production is negligible. The mine

operator must conduct environmental monitoring to ensure that these requirements are

met; where the monitoring shows they are being violated, mining must cease until approved

remedial measures are taken. However, mines

that were permitted or in production before

August 1977 are exempt from these SMCRA requirements.

SMCRA also includes regulations designed

to minimize the effects of surface mining on

prime farmland so that the land will have

equal productivity after mining and is not lost

as a resource. Each soil horizon used in reconstruction of the soil must be removed before

drilling, blasting, or mining in a manner that

prevents mixing or contaminating the soil horizon with undesirable material. When replaced

and reconstructed, the soil material must be at

least 48 inches deep and must create a final

root zone of comparable depth and quality to

that which existed prior to mining. In addition,

the surface soil horizon must be replaced in a

manner that prevents excessive compaction

and reduction of permeability and that protects against wind and water erosion. Finally,

the operator must apply nutrients and soil

amendments as needed to establish quick

vegetative growth.

Protection of timber stands under SMCRA is

not as rigorous as that afforded to alluvial

valley floors and prime farmland. In general,

mine operators must establish a diverse, effective, and permanent vegetative cover of species that are native to the area or that support

the approved postmining land use. Introduced

species may be substituted only if they are of

equal or superior utility for the postmining

land use and if they meet the requirements of

State or Federal laws. Specific provisions for

forest land in the Eastern United States, as

measured 5 years after planting, require an

average of 600 trees of commercial species of

at least 3 years of age per acre. I n the Western

United States, where shelter belts, wildlife

habitat, or commercial or other forest land is

the approved postmining land use, the operator must conduct a premining and postmining

inventory of vegetation. The density and number per unit area of trees and shrubs on the

restored land must be equal to or greater than

90 percent of the premining density and number. The success of the reforestation, in terms

of species, diversity, distribution, seasonal

variety, vigor, and regenerative capacity of the

vegetation, is evaluated on the basis of the

results that reasonably could be expected from

the approved reclamation plan.

Finally, reguIations promulgated under

SMCRA provide special environmental performance standards for operations on steep

slopes. Spoil and waste materials may not be

placed on the downslope; the highwall must be

completely covered with compacted soil and

graded to the original contour; land above the

highwall may not be disturbed; woody materials may not be buried in the backfill area, and

unlined or unprotected drainage channels may

not be constructed on backfiiIs unless they are

stable and not subject to erosion.
254 The Direct Use of Coal

Photo credit: Union Pacific

COAL MINING.—This was a coal mine pit 3 years ago. Arch Mineral, operator of the Medicine Bow Coal Mine in Wyoming,

follows rigorous reclamation, regrading worked over areas into gentle contours and reseeding with native grasses
Ch. V—Environmental Impacts . 255

105D Willard, et al “Land Use Changes Resulting from

Strip Mining in the Ohio River Basin Energy Study

Region” (Draft Report, unpublished) October 1978
Chapter VI

WORKPLACE AND COMMUNITY

IMPLICATIONS

44-102 0-79 - 18

Chapter VI

WORKPLACE AND COMMUNITY IMPLICATIONS

INTRODUCTION

This chapter discusses the occupational and social implications of increased

coal production and use. It seeks to identify likely problem areas and enable policymakers to assess the need for remedial action. The trends in mine health and safety

performance are traced and estimated future costs of increased coal production are

presented. The socioeconomic impacts of more coal development differ in the East

and West. Separate sections are devoted to the current experience in each region,

and likely patterns of development are described.

WORKPLACE HEALTH AND SAFETY

Health

Background

Coal mines are inherently unhealthy places

to work. Mortality studies of mineworkers who

were employed in the 1940’s, 1950’s, and 1960’s

suggest that they died more often than others

from respiratory diseases (influenza, emphysema, asthma, and tuberculosis), stomach and

lung cancer, and hypertension. I Pneumoconiosis and bronchitis were underlying causes of

death in a significant number of fatalities attributed to nonmalignant respiratory diseases.

Since 1969, Federal officials, mine operators,

and coal workers have sought to minimize exposure to coal mine dusts and noise, and they

have succeeded to a degree. If current dust

standards are met on a daily basis, coal workers’ pneumoconiosis (CWP) should disable far

fewer workers 20 years hence than today.

Many occupational diseases require two or

three decades to become manifest. Because

about half of the total coal work force is under

34 years of age, the actual results of today’s

dust-control efforts will not be known until the

1990’s and beyond. Efforts focused on CWP

after 1969 have lowered the amounts of respirable dust that miners now breathe on the job.

But other hazards were overshadowed in the

debate over CWP. This section discusses CWP

and the programs to control the respirable dust

that causes it, as well as other relevant health

hazards.

The costs of occupational illness from coal

mining have been immense. More than 420,000

coal workers “. . . who are totally disabled due

to pneumocniosis . . .“2 or their widows were

awarded Federal black lung compensation between January 1,1970, and December 31, 1977.

That number of beneficiaries equals the total

number of coal workers employed industrywide in 1950. Occupational health officials at

the United Mine Workers of America (UMWA)

estimate that 4,000 Federal black lung beneficiaries have died from black lung disease

each year since 1969. other work-related illnesses– hearing loss, bronchitis, and breathing

difficuIties – are impossible to estimate.

Occupational illness usually affects older or

retired workers, leaving them financially and

psychologically strapped. For every worker

disabled by CWP, two or three family members

are also affected. Stress is created. Work

schedules must be readjusted. Family income

‘Public Law 91-173, Federal Coal Mine Health and

Safety Act of 1969, title IV, pt. A.

259
260 ● The Direct Use of Coa/

is reduced. Bills from doctors and hospitals

rise.

Discussions of occupational disease often

dwell on numbers, percentages, and sanitized

scientific terminology. To the victim, black

lung can bean overwhelming fact of life:

At work you [coal miners] are covered with

dust. It’s in your hair, your clothes, and your

skin. The rims of your eyes are coated with it.

It gets between your teeth and you swallow it.

You suck so much of it in your lungs that until

you die you never stop spitting up coal dust.

Some of you cough so hard that you wonder if

you have a lung left. Slowly you notice you are

getting short of breath when you walk up a

hill. On the job, you stop more often to catch

your breath. Finally, just walking across the

room at home is an effort because it makes

you so short of breath. J

The cost of mineworker occupational illness

are also borne by the public and, to a lesser

extent, by the coal industry. Black lung compensation has been administered by the Social

Security Administration and, since July 1973,

by the Department of Labor. Table 37 summarizes the 8-year dollar cost of this program. Of

the $5.569 billion paid to miners and their survivors from 1970 through 1977, the Federal

Government paid $5.567 million, or almost 100

percent. An operator-paid tonnage tax was

enacted by Congress in 1977 to provide for

future benefits. Compensation is from funds

contributed by the “last responsible operator. ”

Labor Department spokesmen say coal companies contest many — if not most — determinations of their responsibility to pay. If the current trend continues, most new black lung

claims may be paid from Federal resources.

Recent legislation allows coal companies to

deduct their contributions to the black lung

trust fund from their Federal taxes. The deduction cannot exceed 38 percent of the company’s payroll, which means, in practice, that

many operators will be able to write off their

black lung contribution.

Some health risks of mining are common to

underground and surface miners, but they are

magnified many times for the deep miner. In

an underground mine the dangers of dust,

fumes, noise, and other contaminants are intensified by close quarters and artificial ventilation. Surface miners, too, face health hazards. The outdoor work environment of these

heavy equipment operators, truck drivers, supply workers, welders, electricians, and mechanics exposes them to dusts, heat and cold, diesel

and welding fumes, whole-body vibration,

noise, and stress. Because the underground environment is so clearly more hazardous, comparatively little research has focused on surface miners.

Table 37.— Eight”Year Summary of Black Lung

Compensation

(Jan. 1, 1970-Dec. 31, 1977)

Claims filed:

Social Security . . . . . . . . . . . . . 586,400

Labor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124,200

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 710,600

Claims approved:

Social Security . . . . . . . . . . . . . 415,20 0

Labor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,74 4

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 420,944

Claims denied:

Social Security . . . . . . . . . . . . . . . . . . . 171,200

Labor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68,062

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 239,262

Total federally paid benefits:

Social Security . . . . . . . . . . . . . . . . . . . $5,513,712,000

Labor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54,000,000

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $5,567,712,000

Preventive measures in the workplace are

the most effective approach to controlling occupational disease. Prevention of all work-related diseases requires a holistic approach to

analyzing hazards and controlling them, This

approach recognizes that disability results

from cumulative, total exposure. Unfortunately, most occupational disease research and
Ch. VI— Workplace and Community Implications ● 261

prevention programs dwell on the effects of

single hazards. The cumulative and synergistic

impacts of workplace hazards — that is, the

way human beings experience them — have not

been well researched.

Photo credit: Douglas Yarrow

Jan Chapin, a nurse with the Cabin Creek Medical Center,

examines miner at minesite on Cabin Creek, W. Va., 1977

The Federal Role

Congressional concern for coal miners’

health–as distinguished from safety– is relatively recent. The 1969 Coal Act established

the Mining Enforcement and Safety Administration (MESA) to develop health standards

and enforcement procedures. When the agency was shifted from the Interior to the Labor

Department in the spring of 1978, it was renamed the Mine Safety and Health Administration (MSHA), seemingly promising a new emphasis on workplace health.

The 1969 Act regulated four health hazards — respirable coal mine dust, dust from

rock drilling, respirable coal dust when quartz

is present, and noise. Compensation for black

lung was started. The 1969 Act failed to address other potentially significant hazards

such as diesel emissions, heat, “nonrespirable ”

coal mine dust, and harmful fumes. As single

factors, some of these may have little effect,

but coupled with known hazards from respirable dust and noise, their total health consequences may be substantial. Enforcement of

the standards since 1970 has been marked by

litigation, technical problems, unsympathetic

Federal administrators, and insufficient funds. ’

MSHA’S task is made more difficult by the

lack of data on the health effects of coal mining. MSHA requires operators to report all occupational illnesses. The agency distributes

form 6-347, listing seven categories of reportable occupational illness: occupational skin

diseases, dust diseases of the lungs, respiratory

diseases (toxic agents), poisoning, disorders

(physical agents), disorders (repeated trauma),

and all other occupational illnesses.5 When a

computer printout was sought from MSHA on

disease experience for the 1972-76 period, data

were available for only two categories — occupational skin diseases and all other occupational illnesses. MSHA statisticians said the

other data were not available because the

operators do not report them — and that even

the available data were probably not very accurate. Without this information, policy -

makers are blocked from evaluating current

prevention strategies.
262 ● The Direct Use of Coa/

Mortality

Disease recognition and prevention are hampered by the time required for many occupationally linked diseases to appear. The most recent mortality study surveyed more than

23,000 UMWA miners—of whom 7,628 had

died – between 1959 and 1971. Rockette found

coal miners died more often than the U.S. male

population from respiratory disease (pneumoconiosis, influenza, emphysema, asthma, and

tuberculosis), accidents, hypertension, and

stomach and lung cancer, b

Rockette’s data may be used cautiously to

correlate coal mine employment with excess

mortality from certain diseases. It is clear that

death from accidents, pneumoconiosis, and

nonmalignant respiratory ailments are associated with coal mining. Hypertension may be.

Lung and stomach cancer may or may not be.

It is conceivable that the combination of coal

dust, trace-element exposure, noxious fumes

and gases, and other irritants (including cigarette smoking and tobacco chewing) are related to excessive cancer among coal miners. 7

Dust—The Greatest Hazard

All mine dusts–of which coal dust is the

most prominent — are classified as either respirable or nonrespirable according to the size

of the dust particles. It is generally accepted

that only the smallest particles (smaller than 5

pg in size) are respirable. They alone are retained in the alveoli —the gas-exchanging sacs

of the lungs — and cause pneumoconiosis. Generally, the larger particles (nonrespirable dust)

do not penetrate the alveoli and are not

thought to cause CWP.

While the distinction between respirable

and nonrespirable dust is scientifically valid, it

is clear that both sizes can impair lung function when inhaled in quantity over time. The

larger particles are probably linked to bronchitis among coal miners. Although these particles are generally not retained in the lung,

continuous exposure to them during the normal work year produces a more or less constant irritation of the upper respiratory tract.

Breathlessness has also been found to be sigPhoto credit: Douglas Yarrow

Black lung victim using vaporizer at the Cabin Creek

Medical Center, Cabin Creek, W. Va., 1977

nificant among miners who do not show X-ray

evidence of CWP. All researchers believe that

breathlessness is related to chronic, nonspecific, obstructive bronchopulmonary disease.

Some investigators, in addition to CWP and

bronchopulmonary disease, have found a

third, as yet unidentified disease process, that

reduces the ability of the lungs to exchange
Ch. VI— workplace and Community Implications ● 263

gases. ’ Black lung disease has come to represent a broad definition of occupational respiratory disabilities in miners, of which CWP is

one major component. The 1969 Act regulated

respirable dust exposure but did not Iimit exposure to nonrespirable dust. Respirable dust,

which is invisible to the unaided eye, accounts

for less than 1 percent of the dust in a mine

workplace. It is not clear how much nonrespirable dust is retained in the lungs when the

Federal standard for respirable dust –2 mg/m3

of air — is being met.

Because compensable black lung is associated with other factors in addition to respirable coal mine dusts, prevention programs

aimed exclusively at that hazard are likely to

reduce CWP but may not reduce black lung

disability proportionately.

Coal Workers’ Pneumoconiosis

The 1969 Act defined CWP as a “chronic

dust disease of the lung arising out of employment in an underground coal mine. ”9 It is

caused by the inhalation and retention of respirable coal mine dust in the lower lungs. After

a dozen years or so of exposure, a noticeable

dose-response relationship may appear. CWP

is classified by X-ray diagnosis into levels of

ascending severity, from simple to complicated. If dust exposure continues, simple CWP

can progress into more advanced stages.

Miners with advanced CWP (characterized as

progressive massive fibrosis) are usually totally

disabled. Miners breathing high dust concentrations may be disabled after only a few years

of exposure. Some miners seem more vulnerable than others, and this variability has yet to

be explained. Cigarette smoking contributes to

lung impairment among miners as in the population generally. Considerable controversy exists over the role smoking plays in miners’ lung

impairment compared to occupational factors.
264 ● The Direct Use of Coal

The second round of this study in 1973-75

found CWP prevalence to be about 11.5 percent. J Of miners X-rayed in both rounds,

about 6 percent showed disease progression.

Some controversy exists over the reliability of

these findings, however. Critics say the results

should be considered with several caveats.

First, different X-ray classification schemes

were used in each round and side-by-side X-ray

readings using one system were not performed.

Second, although X-ray diagnosis is the accepted (and only) method for diagnosing CWP,

it is not foolproof. The quality of X-rays is

directly linked to the conditions in which they

are taken. Critics say that differences in conditions were not weighed in the final evaluation.

Third, only 40 to 50 percent of the miners Xrayed in the first round were X-rayed again in

the second round. This has led some to argue

that the second-round data reflect CWP prevalence for a “survivor population and the slightly lower prevalence rate between round 1 and

round 2 reflects the “healthy worker” effect,

that is, workers who are not healthy are forced

out of the labor force leaving only healthy

workers to be surveyed for CWP. The 50 to 60

percent of round 1 miners who were not Xrayed in round 2 may consequently have a considerably higher prevalence of CWP than those

miners who continued working and were Xrayed in both rounds. ” (Many of the first-round

CWP cases may not have been examined because they no longer worked in the mines or refused to be examined because they feared job

discrimination if they had a “bad” X-ray.) Finally, dust exposures cannot always be correlated

to X-ray results with a great deal of confidence,

making it difficult to say anything conclusive

about the safeness of the Federal 2-mg dust

standard using these data.

Rough estimates of CWP prevalence for

1976, 1985, and 2000 appear in table 38. Actual

prevalence of CWP in the future will differ

from these projections according to the actual

numbers of miners employed and actual prevalence rate. These estimates assume the existing

Federal dust standard will significantly reduce

13 Status of Mandated Programs, Receiving Center, National Institute for Occupational Safety and Health, unpublished reports, end of second round of examinations,

1975

CWP prevalence in the future. Thus, each of

the three scenarios forecasts steadily lower

prevalence rates. However, even if prevalence

declines, more workers will be exposed. Assuming 230,000 coal miners will be working in

1985, the number of likely CWP cases ranges

from almost 13,700 to almost 18,800. Assuming

about 411,000 miners will be employed in

2000, CWP cases might range from 10,600 to

about 18,000.

Both the optimistic and pessimistic cases

probably err on the side of optimism because

they assume more or less full compliance with

the 2-mg dust standard on a daily basis. If

every mine strictly complies with this standard

between 1975 and 2000, the prevalence rate

may be 3-percent underground and l-percent

surface in that year. The current standard will

not eliminate CWP, but it is likely to cut significantly the probability of its occurrence.

Along with CWP, coal miners will continue

to experience other black lung diseases —

bronchitis, severe dyspnea (shortness of

breath), and airways obstruction. Much of this

illness will be work-related and some of it will

be caused or worsened by cigarette smoking.

For every case of CWP, about three cases of

bronchitis, one case of dyspnea, and two cases

of airways obstruction may be found. These

cases are not exclusive, and are often found in

combination.

NIOSH calculated the health effects of increased coal production using current prevalence rates and higher estimates of the future

work force. NIOSH estimated there were

19,400 cases of CWP in 1975, rising to about

28,500 in 1985, and 45,500 in 2000 (table 39).

Cases of chronic bronchitis, dyspnea, and airways obstruction are estimated to increase

proportionately. Both OTA and NOSH estimates deal only with the illniess found an-tong

working miners. Retired and disabled workers

do not appear in these estimates. This group,

which will be eligible for black lung compensation, is likely to be large.

Questions relevant to congressional policy

include: 1 ) Are these estimated health costs of

increased coal production unacceptably high?

2) If so, what can be done to reduce these
Ch. VI—Workplace and Community Implications ● 265

Table 38.— Estimates of CWP Among Working Miners, 1976,1985, and 2000

Optimlstlc Prevalence Rates Pesslmistlc

Underground Surfacea Underground Surfacea

Table 39.—Projected Health Effects of lncreased Coal Production

Millions of Cases of” b Cases of’b Cases of’b

tons produced Number of Cases’ chronic severe airways

Year (quads) employees of CWP bronchitis dyspnea obstruction

1975 estimates

Underground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 279 ( 7,3) 139,500 18,100 41,800 11,200 41,800

Strip auger . . . . . . . . . . . . . . . . . . . . . . . . . . . 332 ( 7.9) 52,500 1,300 15,700 4,200 10,000

1985 estimates

2000 estimates

Underground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 630 (15.7) 315,000 40,900 94,400 25,300 94,400

Strip auger . . . . . . . . . . . . . . . . . . . . . . . . . . .. 1,170 (29.2) 185,000 4,600 66,300 14,800 35,200
266 ● The Direct Use of Coa/

costs? 3) Who should bear the costs of reducing dust levels? 4) How may tradeoffs be determined between miners’ health and dollars

spent on prevention?

Enforcement of Federal Dust Standard

The current dust-control program has four

components: 1) the federally established 2-

mg/ m

3 dust standard, 2) dust suppression efforts in the mine, 3) monitoring dust levels in

the work environment, and 4) enforcement

strategies for compliance with the Federal

standard. The Federal dust standard refers only

to respirable coal mine dust.

The Federal Government plays an important

role in each of these components. Ventilation

standards are federally established. Federally

sponsored research has helped develop water

sprays and other dust-control techniques.

Operators must have Federal approval of their

dust-control plans. Monitoring the work environment is now a joint Federal and industry responsibility. Mine operators are required to

submit dust samples to MSHA several times a

year. These samples are weighed and the operator is told several weeks later whether the

sample complied on the day it was taken. If

the sample exceeds the standard, the operator

must redo it until it complies. MSHA inspectors take their own samples two or three times

a year. If the operator is out of compliance, he

will be issued a notice of violation and may be

assessed a civil penalty. The average assessed

penalty was between $150 and $175 for a respirable dust violation in 1978, and the average

amount collected was about $120.

The adequacy of the current 2-mg/m3 respirable dust standard is one key assumption that

will determine the prevalence of respiratory

disease among coal miners in the future. Although the U.S. standard is probably the strictest in the world, its inherent safeness is not entirely certain. When the 2-mg standard was

mandated in the 1969 Coal Act, Congress assumed that full and comprehensive compliance would effect foolproof prevention, based

on the best evidence available at the time.

That evidence deserves renewed scrutiny.

Congress based the 2-mg standard on British

research done in the 1960’s. More than 4,000

British miners were studied over a 10-year period. The study’s methodology— how its data

were collected and how they were used — may

raise questions as to the soundness of its final

conclusions. 5 Dust exposure of each miner

was not monitored daily. Rather, a stratified

random-sampling procedure was used, which

took 50 to 250 samples annually at each of 20

mines. The dust sampler used in the study is no

longer used. The exposure data were converted

from particles to weight, but the conversion

factors were developed experimentally rather

than from in-mine measurement. Average 8-

hour exposures for each job at the face were

calculated from the stratified random sampling. Calculating a mean from a set of averages twice removes statistical results from

reality. Probability curves were then constructed that related 10-year mean exposures

to X-ray evidence of CWP. The probability

curves suggest the current standard is reasonably safe (at 2 mg, 1 to 3 of every 100 miners

would show X-ray evidence of CWP after 35

years exposure)<” However, if the data collection and statistical manipulations were not

totally sound, then the curves are flawed. The

safeness of the 2-mg standard has never been

confirmed by a long-term epidemiological

study. A recent British update of the 1969 re

suits showed that in 10 mines the “earlier predictions underestimated 35-year working-life

risks [the probability of developing simple

pneumoconiosis] by 1 to 2 percentage probability units.’” 7 Researchers could not explain
Ch. VI— Workplace and Community Implications . 267

why CWP risks were five to six times higher

than average at one mine, where the mean concentration of airborne dust to which the miners

were exposed was 2.9 mg/m3

, compared with

another mine, where the CWP risks were about

one-ninth the average but the mean dust concentration was 4.4 mg/m3

. A 1979 draft of a

NIOSH report, “Criteria for a Recommended

Standard . . . Chest Roentgenographic Surveillance of Surface Coal Miners,” on X-ray monitoring of surface miners said the “current U.S.

permissible exposure limit for coal mine dust

of 2 mg/m3 does not assure a zero risk for the

development of either simple or complicated

pneumoconios is.” The draft said the current

standard is “. . . insufficient to eliminate the

development of CWP in a small portion of

American coal miners . . . .“ The risk of

developing more advanced stages of simple

pneumoconiosis approaches zero at an average coal mine dust exposure concentration of

1 mg/m3 and below, NIOSH reported. Since the

average dust sample submitted to MSHA in

1978 indicates that concentration levels of

slightly over 1 mg/m3 are being achieved, Congress may wish to consider lowering the standard to attain zero CWP risk. I n light of the large

numbers of young miners joining the coal

labor force in the 1970’s, prudence suggests

that new research confirm or change the 2-mg

standard as soon as possible.

Assuming, for the moment, that 2 mg is low

enough to prevent CWP, it is apparent that

dust control depends on reliable monitoring of

the work environment. MSHA says that more

than 90 percent of the operator-submitted

samples of mine sections have been in compliance since 1973. This seemingly encouraging

record leads to the conclusion that CWP

should be almost eliminated in the future. Yet

the sampling system is so burdened by uncertainty and flaws that such a conclusion may

prove to be unwarranted.

The dust-monitoring process has been criticized on a number of grounds. First, the sampling is performed only on perhaps 2 percent of

the days worked each year. Second, the samplers used to monitor the dust are not always

reliable. Third, control of the sampling program at each mine is exercised by the operator

rather than the miners or MS HA. Serious misuse of this responsibility has been reported, including deliberate falsification of sample results. Miners express little faith in a sampling

system managed by their employers—whose

interest, they claim, is not served by submitting

noncompliance samples to MS HA. Fourth, a

lag of 2 to 6 weeks often occurs before the

operator is apprised of the results of his sample. By that time, the work environment has

changed considerably, for better or worse.

Behavioral factors influence the representativeness of the samples. Miners don’t like to

wear the samplers because they are noisy, awkward, and heavy. Both the company and the

miner have incentives to take “good” samples

(by tampering with the sampler or leaving it in

a nondusty place). If a noncompliance sample

is submitted to MS HA, the individual miner

must take 10 more samples, which is considered a nuisance. The miner may not wear his

sampler to minimize his inconvenience or possibly to appease an anxious supervisor. Management may try to distort the sampling, too.

In one case, two company technicians at a

mine of a major operator were found guilty—

and then innocent—of deliberately falsifying

samples once miners had turned them in at the

end of their shift. The samplers themselves are

far from perfect. MSHA stopped the use of the

most common sampler in 1976 because it

gained weight artificially. In the past, samplers

were also found to lose weight for no apparent

reason.

The General Accounting Office (GAO)

found:

. . . many weaknesses in the dust-sampling

program which affected the accuracy and validity of the results and made it virtually impossible to determine how many mine sections

were in compliance with statutorily established dust standards.

GAO said factors that affected sample accuracy were: sampling practices used by operators and miners, dust-sampling equipment,

weight loss of sampling cassettes, and weighing of cassettes by MESA and cassette manufacturers.

‘‘Improvements Still Needed In Coal Mine Dlust-SamplIng Program and PenaIty Assessments and Collections

(Washington, D C U S Congress, General Accounting

Off Ice, Dec 31, 1975), p I.

191 bid , p 15
268 ● The Direct Use of Coal

A National Bureau of Standards (NBS) study

found:

when the miners and mine operators perform” and supervise the sampling and when the

weighings are made in the normal manner

. . . the uncertainty [of accurate, actual measurements of dust concentrations] is estimated

to be as large as 31 percent .. .20

No followup study on the accuracy of the

sampling program has been done since the

GAO and NBS reports were released in December 1975. Both investigations noted that MSHA

and NIOSH officials have made efforts to improve.

A recent study of underground mines in east

Kentucky found that:

Both the interviews and the Federal dust

records suggest that many dust samples are

being collected incorrectly. In some instances,

extra dust has been added; but in substantially

more cases, the samples are too low. One explanation for the inaccurate sampling, of

course, lies in the fact that the mineowners

control sampling in their own mines. Since the

penalty for exceeding Federal standards may

be to close the mine, coal operators have a

strong incentive to err in the direction of

samples showing less than the actual dust

levels. The 1969 law attempts to circumvent

this possibility by requiring that all samples be

collected by actual miners on the assumption

that, since their own health is at stake, coal

miners will have a vested interest in insuring

the accuracy of samples taken at their workplace. For various reasons, however, that

assumption has proven wrong. 21

Sharp found 27 percent of the 680 face and

high-risk samples he studied were at the 0.1

and 0.2 mg levels, which are generally considered to be impossibly low. (That level represents dust levels in fresh, intake air. ) About 23

percent of equipment operator’s samples were

also found to be inaccurate (low). Operator attitude toward the sampling program has an important effect on sampling accuracy, Sharp

concluded.

“An Evaluation of the Accuracy of the Coal Mine DustSampling Program Administered by the Department of the

Interior, a Final Report to the Senate Committee on Labor

and Public Welfare (Washington, D.C. : Department of

Commerce, National Bureau of Standards, 1975), p. iii

“Gerald Sharp, “Dust Monitoring and Control in the

Underground Coal Mines of Eastern Kentucky, ” masters

thesis, University of Kentucky, November 1968, p 4.
Ch. VI— Workplace and Community Implications ● 269

gers an automatic power cutoff when dust

levels are too high. Such a system is being

developed but is several years away from commercialization, the Bureau of Mines says.

Longwall mining, in particular, needs more effective dust control s.”

Other Mine Dusts

The 2-mg dust limit covers all respirable coal

mine dust, not only coal dust. Coal mine dusts

contain a wide range of noncoal constituents,

including silica and hazardous substances

such as benzenes, phenols, and naptha lenes.

Shultz, et al.,24 found 13 polynuclear aromatic

hydrocarbons in the respirable mine dusts they

studied. Polynu clear aromatic hydrocarbons

are listed among NIOSH’S suspected carcinogens. *5 Arsenic beryllium, cadmium, fIuorine,

lead, mercury, ‘and selenium are all found in

coal and alI appear on the Environmental Protection Agency’s (EPA) list of hazardous elements. At even one part per million, a mine

producing 1 million tons of coal generates 1

ton of each element annually. As coal is cut

from the face, some of each element will be

liberated as dust or gas in the workplace.

Table 40 provides information on seven

trace-element concentrations in various coals.

The permissible levels of workplace air contaminants as developed by the Occupational

Safety and Health Administration (OSHA) are

also included in the table. The median concentration levels of these seven elements in uncleaned coal almost uniformly exceed OSHA’S

standards. Research has not determined how

much of each element is actually liberated in

the mining process or, further, how much of

that is inhaled by miners. One sample of West

Virginia miners found their lungs to contain an

excess of beryllium, cobalt, copper, and other

minerals, but was unable to determine the significance of these excesses. 26 An autopsy stud y

found miners’ lungs contain higher than normal concentrations of aluminum, barium,

boron, chromium, germanium, iron, lead, magnesium, manganese, nickel, silver, tin, titanium, and vanadium — al I common coal constituents. 2

7

Little research has been done on the health

effects of trace-element dust or trace-element

compounds generated in coal extraction.

Trace elements may have a role in producing

black lung disability, either alone or synergistically. They may also play a role in the excess

lung and stomach cancer found in miners.

Harmful Fumes and Gases

Hazardous fumes and gases are often produced in underground mines under both normal and abnormal conditions. Common gases

include nitrogen and its oxides, carbon dioxide

(C02

), methane and other hydrocarbons, sulfur

dioxide (S02

), and hydrogen sulfide. If ventila-
270 ● The Direct Use of Coa/

Table 40.—Median Trace Element Concentrations by Coal Type

(parts per million dry weight, uncleaned basis)

Type of coal

(OSHA permissible level)”

Asb

Be Cd F Pb Hg Se

(0.4) (1.6) (.2) (.2) (.2) (.1) (.2)

23.00

25.00

31.00

26.50

26.50

NA

NA

1.00

2.00

7.69

2.40

1.80

1.80

2.50

1.10

1.50

1.10

0.90

0.04

0.38

0.45

0.20

NA

2.90

11.00

0.40

1.10

NA

NA

NA

83.50

50.00

103.00

75.00

92.50

65.00

NA

131.00

130.00

NA

9.00

9.00

9.00

11.00

4.00

7.00

NA

7.50

7.50

NA

0.22

0.12

0.17

0.13

0.19

0.07

3.15

0.05

0.05

3.08

3.40

3.00

NA

2.00

2.90

0.80

neg.

1.60

1.85

NA

tion is maintained at required levels, these

gases will be diluted and carried quickly from

the workplace. Miners are often exposed to

noxious or poisonous fumes from fires in machinery, insulated electric cables, conveyor

belts, lubricating oils, and various synthetic

materials. Friction from moving parts and electricalfaults are common fire sources. Close observation of equipment by miners and supervisors and compliance with Federal equipment

standards are well-known ways of preventing

fires. Stil several hundred probably occur

each year.

Hartstein and Forshey28 analyzed coal mine

combustion products from brattice cloth, ventilation tubing, belts, insulation, resins, foams,

and oils— products commonly found in mines.

Hazardous emissions identified were polyvinyl

chlorides, neoprenes, and other chemical compounds plus hydrogen chloride, carbon monoxide (CO), SOZ

, and hydrogen sulfide. When

fires occur, these substances are liberated

simultaneously in large doses. Harmful synergism with ambient dust may occur. No morbidity study has been done to assess the cumulative health impact of these substances.

Noise

Noise is a proven hazard to both underground and surface miners. NIOSH believes

occupational noise has these actual, or possible, effects: temporary or permanent loss in

hearing sensitivity, physical and psychological

disorders, interference with speech communications or the reception of other wanted

sounds, and disruption of job performance. 29

Excessive noise may also cause changes in cardiovascular, endocrine, necrologic, and other

psychologic functions.30

NIOSH completed the most comprehensive

survey of hearing loss in the underground coal

mining industry in June 1976.3’ It found that

“mining operations cause 20 to 30 percent of

all miners to be exposed to noise that is potentially hazardous to their hearing. ”32 However,

disagreement was noted as to the proportion

of miners suffering actual hearing loss as a

consequence of exposure. Occupational hearing loss in the studies NIOSH surveyed ranged

from 9 to 29 percent. 33 “The results of this

study indicate that coal miners have measurably worse hearing than the national average, ” 34 NIOSH concluded. MSHA has not con-
Ch. VI— Workplace and Community Implications 271

ducted an equivalent noise survey for surface

miners, although comparable data suggest

similar hearing risk for truck operators and

earth-moving equipment drivers. Data on active and retired miners covered by the UMWA

Health and Retirement Funds in 1974 indicated

that the Funds male population has a prevalence rate for hearing aids of 1.5 percent compared with a l-percent rate for all U.S. males.

Operators of underground and surface

equipment are usually exposed to high, often

intermittent noise levels. I n surface operations, where machinery is in continuous operation, noise is often excessive. Miners are rotated in and out of the workplace to limit exposure. The Federal noise level of 90 dBA average for an 8-hour period permits higher exposures for shorter periods of time. However,

convincing evidence is not at hand to indicate

the 90 dBA level is sufficiently safe. NIOSH

has recommended that the permissible exposure level be lowered to 85 dBA; UMWA health

advocates have urged a 75 dBA Iimit.

Operators are required to submit noise-sampling data to MSHA. Samples are taken only

once or twice a year in most cases. The results

indicate almost total compliance with the Federal standards. MSHA issues even fewer notices of noise violations than the small number

of noncompliance samples warrant. MSHA has

no way of systematically checking the reliability of the operator-submitted noise samples.

MSHA inspectors are required to sample

noise during inspections. But the agency does

not tabulate its inspectors’ measurements.

Thus no way exists to compare the operators’

data with MSHA’S.

Without reliable noise exposure data, it is

impossible to predict the extent of hearing impairment miners will experience in the future.

It is reasonably clear that a significant number

of today’s miners is exposed to and impaired

by noise. Noise-related accidents are not uncommon. Lowering the Federal noise standard

to 85 dBA, for example, and instituting a reliable monitoring and enforcement system

would probably minimize future hearing impairment and accidents. Noise control at the

90 dBA level or lower requires careful engineering of equipment and design of the work

process. Exposure can be reduced by providing

personal protective headgear, but this approach is usually less reliable than engineering

control and may increase accidents. Machine

modifications to achieve a lower noise standard would involve retrofit expenditures and

perhaps increase the cost of new equipment.

Concern for inflationary impact and engineering considerations have discouraged Federal

safety agencies from promulgating the recommended 85 d BA standard.

Diesels in Underground Coal Mines

Diesel-powered equipment is commonly

found in surface coal mines throughout the

United States. However, only 200 diesel units

operate in underground coal mines. About 160

of those pieces of equipment are found in the

West; most of the others are used in east Kentucky. Only 10 or 12 pieces are found in mines

organized by UMWA.

Health hazards to both surface and underground coal miners from diesel emissions have

not been studied definitively. I n fact, no longterm epidemiological study of diesel exposure

has been done of any work group. A preliminary survey covering a 6-year period that

matched 772 diesel-exposed miners with an

equal number of “controls” reported that the

diesel miners reported significantly more

symptoms of persistent cough, phlegm and exacerbations of cough and phlegm. Their pulmonary function performance was generally

poorer, but they reported fewer symptoms of

moderate to severe dyspnea and wheezing. 35

NIOSH expressed concern about the health

hazards of diesels underground, but has not

yet been able to justify a recommendation that

diesels be prohibited. However, mine operators have been cautioned not to invest heavily in underground diesels pending further research. NIOSH is currently working up a crite

ria document, which surveys the Iiterature and
272 The Direct Use of Coal

recommends a standard, for diesel emissions.

This should be issued within 2 years.

Diesel engines produce emissions that are

known to be health hazards: CO, unburned hydrocarbons, oxides of nitrogen, particulate,

polynuclear aromatic hydrocarbons, phenols,

aldehydes, oxides of sulfur, trace metals, nitrogen compounds, smoke, and light hydrocarbons. ”

With exhaust scrubbers, rigorous maintenance, and massive ventilation these emissions

can be minimized. However, Federal researchers point out that diesel particulate (which include carcinogens and mutagens) and oxides

of nitrogen cannot be trapped within the combustion process. The safeguard standard is

8,000 to 17,000 ft3 per minute of air per piece

of diesel equipment. NormalIy, only 9,000 ft 3

per minute is required in each section (and

3,000 ft3 per minute across each working face).

The tremendous volumes of air required for

diesel operation probably precludes their use

in most older mines.

NIOSH’S current assessment of the potential

health effects of diesels underground is

pessimistic.

Although acute or subchronic health effects” are important, chronic health effects are

the central issue. The principal organ likely to

be affected by diesel emission products is the

lung, In addition to coal mine dust, many of

the individual pollutants associated with diesel exhaust are known to cause chronic adverse respiratory effects after prolonged exposures. The introduction of carcinogenic materials into the mine environment through the

use of diesel engines provides yet another insidious potential for chronic illness and death.

These chronic effects may take years to manifest themselves. Thus, the real human impacts

of introducing diesels into mines today may

not be determinable for several decades. It

must be emphasized that currrent or proposed

standards for these individual pollutants offer

no assurance of protection when the contaminants are found in combination with other toxic substances .

. . . from a health protection posture it is obviously undesirable to use diesel engines in underground coal mines. However, it is also recognized that safety and productivity considerations could potentially provide overall gains

in protection of the miners’ well-being. Unfortunately, none of the potentially positive

aspects of diesel use have been scientifically

and objectively documented at this time. Conversely, there are valid investigations which

clearly demonstrate that toxic substances are

introduced into underground coal mines from

diesel engine exhaust such exposures

would not be expected to produce a healthy

work ing environment. 37

Shift Work

Several studies have linked shift work–especially rotating shifts—to a wide range of

adverse health effects. Most U.S. mines operate on either two or three shifts,38 and about

one-third rotate shift times every week or two,

according to BCOA. Larger and newer mines

tend to use rotating shifts more than smaller

and older mines. More than 30,000 Appalachian miners struck in protest for several weeks

in 1973 over compulsory shift work. Miners’

wives picketed at a number of northern West

Virginia mines in 1978 over the family disruption caused by rotating shifts.

Akerstedt summarized the literature in 1975

and found:

. . . the studies . . seem to indicate that shift

workers have:

● An excess of sleep problems including

short sleep time, difficulties of falling

asleep and retaining sleep, not feeling

refreshed after sleep, etc. The problems

occur mainly in the nightwork period and

often are associated with tiredness, bad

mood, restlessness, digestive problems,

etc.

● An excess of minor nervous disturbance

states.

● An excess of gastrointestinal disturbances. 39

“Gamble, et al., Health Implicattions, p. 87.

“’UMWA conventions in recent years have urged adoption of a 4-shift, 6-hour-per-shift pattern in order to increase job opportunities and safety The fourth shift

would be designated a safety and maintenance shift

‘

9 Torbojorn Akerstedt, “Shift Work and Health – interdisciplinary Aspects, ” Shift Work and Health (Washington, D.C..: DHEW, National Institute for Occupational

Safety and Health), p. 180.
Ch. VI— Workplace and Community Implications ● 273

Akerstedt noted that “shift workers suffer from

a host of social handicaps . that can be expected to affect physchological aspects of

well-being, e.g., anxiety, tension, self-esteem,

and simiIar parameters. 40

The most recent NIOSH study by Taste, et

al., found that workers on a rotating-shift system experience significantly more accidents

than those working either straight-day shift or

a fixed-shift pattern .4’

Several important questions about shift

work remain to be studied. What are the biological costs of adaptation? What is the longterm cost of the “wear and tear” on the body

as a consequence of repeated attempts to adjust or simply of being active at times when

physiological preparedness for activity is at its

lowest? What are the long-term consequences

of being active during those portions of the 24

hours when the resistance to noxious agents is

lowest? Do rotating shifts contribute to absenteeism and labor-management antagonisms?

Health Effects of Job Stress

Job stress is produced by a miner’s work environment. Working conditions that either

make unattainable demands on the miner or

do not fulfill his needs create stress. Strain is a

psychological reaction to stress—that is, a

deviation from normal responses. Although a

recent NIOSH study found that miners do not

perceive their work environments to be more

stressful than the perceptions of other blue-

-collar workers, miners experienced more

strain — irritation, anxiety, depression, and

physical com pa i n ts — t ha n their counterperts.

42 AS measures of job stress are subjective [workers’ perceptions of their own environment), it is less useful to ask “How stressful is

mine work?” than to ask what possible stressrelated health effects are found among miners.

The findings of the 1977 NIOSH study on

stress “. . . provided support for the argument

that strain produces illness. ”43 The reported incidence of circulatory and gastrointestinal

problems, nervous system disorders, urinary

tract conditions, or musculoskeletal problems

. . were associated with pyschological strain,

and those miners with these disorders reported

significantly higher strain than workers who

did not experience these problems. 44 Whe n

high- and low-accident mines were compared,

it was found that miners in high-accident

mines reported more illness than those in lowaccident mines .45 Miners were found to experience higher morbidity and mortality from

stress-related illnesses than expected.4b

Negative health effects are likely to increase

where newly initiated productivity plans increase job stress. Although some of the incentive plans tie cash bonuses to safety, none apparently tie them to illness. NIOSH concludes:

. . . it can be expected that there wiII be an increase in the number of health and safety

problems related to behavioral factors if coal

production is increased.’’”

Conclusions

This catalog of occupational health hazards

is long and discouraging. It is difficult to pinpoint the extent of occupational disease

among working miners. MSHA’S data are incomplete and unreliable. Epidemiological

studies suggest an excess of respiratory disease, hypertension, lung and stomach cancer,

and hearing impairment. But no one knows

how many working miners die prematurely or

suffer work-related illness. No one knows how

many retired miners eventually die of work-related diseases. No one knows the extent of psychological and social stress a miner’s ilIness inflicts on him and his family.

‘

i

Ibid , p 63

“Ibi d

“lbld , pp 124-125

“C M Pfelfer, J F Stafanski, and C B, Grether, Psychological job Stress and Health, Contractor Report

#C DC99-74-60 (Washington, D.C. DHEW, National Institute for Occupational Safety and Health, 1975 )

“Occupational Safety and Health Implications of lrlcreased Coal Utilization (Washington, D.C. DHEW, National Institute for Occupational Safety and Health,

Nov 4, 1977), Iines 848-850
274 ● The Direct Use of Coal

Estimates of the future number of CWP and

black lung cases vary widely depending on

assumptions about numbers of workers and

disease prevalence. These estimates range

from about 14,000 cases of CWP among working miners to 28,500 in 1985; from 10,600 CWP

cases to 45,500 in 2000. A proportional range

exists for bronchitis, severe dyspnea, and air

obstruction. Thousands of additional cases of

respiratory disability will be found among

retired workers especialIy over the next decade

(that is, among those who spent most of their

work Iives in uncontrolled dust conditions).

Other uncertainties must be added to this

list. The safeness of the 2-mg dust standard is

open to question. If 2 mg eventually proves to

be too high, miners and compensators alike

wiII pay a higher price for coal production.

Further, the full health effects of coal-mine

dusts are not clear. Lung and stomach cancer,

skin disease, and gastrointestinal problems

may be related to various noncoal constituents. While respirable dust is a known hazard,

the degree of risk associated with nonrespirable dust has not been fully explored. Uncertainty also exists about whether (and to what

extent) mine health hazards work synergistically. Do diesel emissions underground

worsen the respiratory impact of coal mine

dusts? Do large– but short –doses of mine-fire

smoke increase respiratory disability?

This list of unknowns and uncertainties suggests a heavy research agenda before thousands of new miners are hired underground.

Essentially, a list of research priorities can be

grouped according to factors that need to be

known and ways of doing things better.

TO BE KNOWN

Dust. –

1.

2.

3.

4.

Safeness of the current 2-mg/m3 Federal

standard for respirable dust.

Need for a standard for nonrespirable

dust.

Need for a standard on trace-element and

combustion-product exposure.

Possible relationship between mine dust

both respirable and nonrespirable, coal

and noncoal constituents with stomach

and lung cancer.

5.

6.

7.

8.

Epidemiological study (including synergistic potentials) of underground coal miners

exposed to diesel emissions.

Extent of work-related bronchitis and emphysema; causes and controls.

Epidemiological survey of respiratory diseases–both CWP and black lung–

among surface miners and preparation

plant workers.

Health effects of radioactive trace elements in underground coal miners.

Others. –

1.

2.

3.

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

Health effects—synergistic and otherwise — of shift rotation in coal miners.

Epidemiological study of health effects of

job stress.

Possible unique health effects of mining

on women miners.

TO BE DONE BETTER

Data collection and analysis of occupational disease.

Reorganization of the respirable dustsampling program.

Noise sampling.

Training of miners and management in

health hazard recognition and control.

Nonrespirable dust control.

Dust control on Iongwall mining units.48

Involvement of miners in occupational

disease prevention programs such as hazard monitoring.

Engineering production systems and

equipment with health-hazard control in

mind.

Training MSHA inspectors in health matters.

Sampler design (both area and personal

samplers should be able to give miners

and management immediate feedback on

dust levels).

Congress faces several obvious policy questions in the area of coal mine health. First, is

‘*In recent hearings on MSHA’S dust-sampling procedures, industry health specialists said mine operators

have yet to succeed in bringing long-wall units into compliance, To comply with Federal standards, mine operators are forced to rotate miners onto the mining

machine for short periods to comply with the Federal 8-

hour standard
Ch. V/— Workplace and Community Implications ● 275

the current program of Federal standards and

enforcement adequate? Second, are the projected levels of miner occupational disease acceptable? Third, if the estimated health costs

of increased production are unacceptably

high, what additional legislation, if any, may

be needed to reduce workplace exposure to

health hazards?

Safety

Concern for the safety of American coal

workers” has been expressed repeatedly by

labor, coal operators, and public officials over

the years. The reason is simple: mining is a

dangerous job.

Mining is undoubtedly safer today than it

was during the first three decades of this century. In 1926-30, for example, 11,175 miners

were kiIled on the job compared with 715 fatalities in 1971-75. I n 1977, 139 coal worker fatalities were recorded. Altogether, coal mining

has claimed a recorded 110,833 lives since

1900 and more than 11⁄2 million disabling injuries since 1930. In some respects, mining is

safer today than it was 10 years ago but in

other ways — the number and rate of disabling

injuries, for instance– no improvement has

been seen.

Congress passed five major pieces of mine

safety legislation in this century, each one

coming on the heels of a major mine disaster.

Each law strengthened its predecessor. The

1969 Federal Coal Mine Health and Safety Act

established the current legal framework following a 78-victim explosion at a Consolidation Coal mine in northern West Virginia in November 1968.50 The 1969 Act mandated safety

practices to prevent future methane explosions. The Act has reduced disaster-caused fatalities from 158 in 1965-70 to 37 in 1971-76.

But the 1969 Act did not address specifically

the problem of injury prevention. In 1977,

229,000 coal workers experienced almost

“Coal worker refers to all workers in the coal Industry,

includlng miners (underground and surface) and workers

in preparation plants, shops, and contract construction

(shaft drillers, for example)

50 Publlc Law 91-173

15,000 disabling injuries and 10,000 nondisabling injuries (which did not result in an extra

shift lost time). The actual number of injuries

has increased each year since 1975. Injury frequency in underground mines has risen after a

2-year (1974-75) improvement. In 1977, the rate

was 50.86 disabling injuries per milIion hours

of exposure, about what it was throughout the

1950’s and 1960’s. About 60 coal workers experience a disabling injury every production

day. Injuries rose in the 1970’s because almost

100,000 additional coal workers were hired

since 1969 and because the underground injury

rate has not improved. If underground production in 1977 had accounted for the same share

of total national output that it did in 1969 (62

percent), the industry’s overall safety record

would show Iittle improvement at al 1.

The safety costs of producing coal are borne

by mine operators, taxpayers, and miners and

their families. The dollar costs alone are

substantial. A recent study found that the

average annual cost of each coal mine fatality

was $125,000 (in 1974 dolIars) and $4,000 for

each disabling injury. 51 Mining companies paid

about 41 percent of the total as compensation

payments, lost production, and investigative

costs. Wage losses to the injured miner and his

family amounted to about 47 percent. Public

agencies paid the remaining 12 percent as

compensation and investigative costs. In 1977

dollars

sz each fatality would have cost

$153,000 and each disabling injury $4,900. That

means a cost of more than $73 million for

15,000 coal worker injuries in 1977 and more

than $21 million for 139 fatalities. Added to

these dollar costs (paid after the accident) are

the expenditures for research, training, and

equipment paid by operators, UMWA, and

public agencies to prevent accidents from happening. The human costs of accidents— pain,

mental anguish, lost opportunities, disorientation— cannot be calculated in dollars and

cents.
276 ● The Direct Use of Coal

Mine safety can be measured in different

ways. Most obvious is the actual number of

recorded fatalities and injuries. This number

depends on the number of workers in the labor

force and the accident frequency rates. Rates

for fatalities and injuries (both disabling and

nondisabling) can be expressed as per million

hours of worker exposure or per million tons of

coal mined. Rates in exposure are more common and express accident risk from the workers’ viewpoint. Accidents expressed in terms of

output show directly the human costs incurred

per unit of coal produced. Accidents are also

measured in terms of severity— the average

number of calendar days lost because of the

injury. Finally, accidents are grouped according to mining method, underground or surface.

Underground mining employs more workers

per unit of production than surface mining and

about three times as many industrywide.

Underground mining has resulted in more

fatalities and higher fatal frequency rates

historically than surface mining (table 41). Between 1952 and 1970, both underground and

surface fatality rates (measured in hours of exposure) did not change although actual fatalities declined because the work force was reduced by 70 percent. Since 1970, both rates

have fallen: the 1977 underground fatality rate

is about one-third the 1970 level; the surface

rate about one-half. The gap between underground and surface fatality rates has narrowed

as underground mining made proportionately

greater improvement.

Post-1969 improvement in fatality reduction

is not matched by a similar trend in disabling

injuries. Underground mining has been consistently more than twice as hazardous as surface mining in the frequency of disabling injuries (table 42). Underground mines injure

more than five times as many miners as surface

operations each year. Except for 1974 and

1975, no improvement in underground disablTable 41.— Fatalities in U.S. Coal Mines, 1952-77

(hours of exposure)

Underground Surface Surface

fatalities as a

percentage of

Year Fatalities Ratea

Fatalities Ratea

underground

1952

1953

1954

1955

1956

1957

1958

1959

1960

1961

1962

1963

1964

1965

1966

1967

1968

1969

1970

1971

1972

1973

1974

1975

1976

1977

514

440

374

391

417

451

334

268

295

275

265

257

224

240

202

186

276

163

220

149

128

105

97

111

109

100

.97

.96

1.10

1.06

1.11

1.30

1.26

1.11

1.29

1.34

1.34

1.28

1.12

1.21

1.12

1.05

1.63

.95

1.20

.86

.68

.56

.51

.47

.45

.43

33

21

22

25

28

22

19

20

24

17

20

22

15

18

23

22

24

28

29

23

20

16

24

32

23

27

.55

.39

.48

.51

.52

.42

.39

.43

.52

.39

.46

.49

.33

.40

.55

.52

.57

.63

.55

.39

.38

.28

.33

.33

.22

.23

60/0

5

6

6

7

5

6

7

8

6

8

9

7

8

11

12

9

17

13

15

16

15

25

29

21

27
Ch. VI— Workplace and Community Implications . 277

ing injury rates has occurred since 1952. The

underground disabling rate and actual number

of disabling injuries have risen each of the last

3 years. Modest improvement is seen in surface

injury rates since 197o, although this trend

seems to have bottomed out since 1973. The

actual number of surface injuries has been rising as more miners are employed, In 1977,

about 142,000 underground miners experienced 50 disabling injuries per miIIion hours of

exposure— that is, about 55 injuries every

working day. I n contrast, 65,000 surface miners

experienced roughly 18 injuries per million

hours of exposure, or about 10 injuries every

working day.

Underground mining generally produces

more severe disabling injuries than surface

mining. I n 1977, for example, the average

severity of all temporary total disabling injuries in all underground mines was 73 calendar days per injury compared with 58 days for

surface mines.53 Although the average disabling injury idles a miner for 2 months or more,

98 percent are temporary total disabilities that

do not produce permanent impairment. Of the

14,989 disabling injuries in 1977 for all coal

production (mining, dredging, preparation, and

shopwork), only 3 permanent totally disabling

injuries were recorded and 225 permanent partial disabling injuries.

Measured in terms of output rather than exposure, a somewhat different perspective on

safety is gained When expressed in output, the

productivity advantages of surface mining

(more tons for less exposure) show it to be five

times safer than underground mining in fatality frequency and almost nine times safer in injury frequency in 1977 (table 43). In 1977,

underground mining showed 0.39 fatalities per

million tons compared with 0.07 fatalities in

surface operations. Surface mining showed a

42-percent decline in its fatality rate in 1967-77

compared with a 26-percent decline for underground mining. On the other hand, the injury

rate in surface mining only registered a 10-percent increase in 1967-77 while underground

53 Mine Safety and Health Adminlstratlon, “ln]ury Experience at All Coal Mines in the United States, by

General Work Location, 1977, ” table 7

mining showed a 90-percent increase! I n 1977,

underground mining registered 46 injuries per

miIIion tons compared with 6 injuries for surface mining.

Safety data measured by output and exposure are compared in table 44. Fatality and injury rates are higher when expressed in exposure than in output. Rate comparisons for 1977

appear in table 45.

A central relationship in coal’s future is that

of productivity and safety. Productivity (tonnage mined per worker per shift) can be increased in different ways. Each produces a

unique set of safety consequences. For example, the introduction of continuous-miner

systems in the 1950’s raised productivity by

maintaining output and reducing the labor

force. This had the effect of lowering the actual number of accidents (since fewer workers

were exposed) but not accident rates.

A rough index relating safety and productivity for 1967-77 appears in table 46. Safety is expressed as fatalities and injuries per million

tons of coal mined. Productivity is expressed in

two distinct ways: first, as tonnage produced

per worker per shift (labor productivity), and

second, as tonnage produced per production

day. By calculating and tracing the number of

fatalities and injuries that occur every production day, safety can be associated with productivity.

The steady 43-percent decline in underground labor productivity since 1967 is

matched by a 43-percent decline in the number

of underground fatalities per production day.

However, underground injuries per production

day increased 47 percent, from 38 in 1967 to 55

in 1977. Surface productivity dropped 22 percent in this period, but surface fatalities per

production day rose 20 percent from 0.10 to

0.12, and injuries rose 134 percent from 4 to 10

(table 46). If underground and surface mines

are compared on a productivity-safety index, it

is clear that surface mining is three times more

productive, four times safer in fatalities, and

almost six times safer in injuries per production day.
278 ● The Direct Use of Coal

Table 42.—Nonfatal Disabling Injuries in U.S. Coal Mines, 1952.77

(hours of exposure)

Underground Surface

Injuries Ratea

Injuries Ratea

28,353

22,622

16,360

17,699

18,342

17,076

12,743

10,868

10,520

9,909

9,700

9,744

9,692

9,705

8,766

8,417

7,972

8,358

9,531

9,756

10,375

9,206

6,689

8,687

11,390

11,724

53.26

49.38

47.98

48.10

48.88

49.23

47.94

44.90

46.09

48.19

48.88

48.62

48.35

49.09

48.78

47.57

46.99

48.77

51.79

56.40

55.32

48.80

34.95

37.13

47.09

50.86

1,698

1,604

1,342

1,140

1,318

1,339

1,150

1,054

1,125

1,052

1,027

1,099

1,116

1,178

1,043

949

1,039

967

1,346

1,564

1,305

1,208

1,229

1,714

2,071

2,246

28.11

29.48

29.01

23.14

24.31

25.72

23.86

22.64

24.45

24.44

23.50

24.25

24.75

26.12

25.00

22.43

24.59

21.84

25.67

26.54

24.84

20.94

16.83

17.74

20.04

18.91

Table 43.— Fatality and Disabling injury Rates for U.S. Coai Mines, 1967-77a

(tons mined)

Underground Surface”

Fatality Injury Fatality Injury

Tonnageb

rate’ rated

Tonnage rate rate
Ch. V/— Workplace and Community Implications ● 279

Table 44.—Accident Rate Comparisons for U.S. Coal Mines, 1967-77

Fatality Rates Injury Rates

Underground Surface Underground Surface

Table 45.—Accident Rate Comparison, 1977

Hours Tons

Fatality Ratea

Underground . . . . . . . . . . . . . . 0.43 0.39

Surface . . . . . . . . . . . . . . . . . . . 0.23 0.07

In]ury rate’

Underground . . . . . . . . . . . . . . 50.86 45.54

Surface . . . . . . . . . . . . . . . . . . .. 18.91 5.53

about the same throughout this period. This

means that any rise in recorded injuries will

show up dramatically as a rise in injuries per

production day.

The decline in underground productivity

was matched by a decline in underground production per day. The 23-percent reduction in

underground production per day coincided

with a 43-percent decline in underground fatalities per production day. But it also coincided

with a 47-percent increase in underground injuries per production day. Surface mining

showed a Ill-percent increase in production

per day that coincided with a 20-percent increase in fatalities per day and a 134-percent

increase in injuries per day. The productionper-day (raw output) measure may be a better

predictor of likely accident experience than

labor productivity (efficiency of output)

because of the great number of variables that

affect labor productivity rates and the definitional problems in the concept itself (see

chapter lV, Productivity).

Several ways of increasing labor productivety can be discussed in terms of safety. First,

productivity can be increased by cutting the

labor force without reducing current production. Since fewer miners are employed, the

number of accidents will probably fall. But the

rate of accidents—that is, the risk to the

worker—may rise because of increased pro-
280 ● The Direct Use of Coa/

Table 46.—Accident and Productivity Experience, for U.S. Coal Mines, 1967.77

(tons mined)

Fatalitye Injuryf

Estimatedd

per pro- per

Fatality a Injury” production duction production

rate rate Productivity b Employees per day day day

Percent change 1967–77 . . . . . . . . . ..

1967

1968

1969

1970

1971

1972

1973

1974

1975

1976

1977

.53

.80

.47

.65

.54

.44

.37

.37

.40

.39

.39

–26%

.12

.13

.14

.12

.09

.08

.06

.08

.10

.06

.07

Underground

24.02

23.13

24.04

28.07

35.09

36.06

32.20

25.34

31.18

40.53

45.54

15.07

15.40

15.61

13.76

12.03

11.91

11.66

11.31

9.54

8.50

8.58c

+90°A –43~o

4.99

5.49

4.79

5.42

5.91

5.53

4.63

4.20

5.28

5.78

5.53

Surface

35.17

34.24

35.71

36.26

35.88

36.33

36.67

33.16

26.69

25.50

27.34c

Percent change 1967–77 . . . . . . . . . .. –420/o +lOO

/o –22”/0

103,993

98,831

97,395

102,379

97,740

109,396

100,843

113,169

137,060

137,316

141,411

+36°10

24,064

24,400

25,323

31,103

33,344

35,364

30,475

44,491

57,562

55,993

65,254

+1710/o

1,567,175

1,521,997

1,520,336

1,408,735

1,175,812

1,302,906

1,175,829

1,279,941

1,307,552

1,167,186

1,213,306

846,331

835,456

904,284

1,127,795

1,196,383

1,284,774

1,117,518

1,475,322

1,536,330

1,427,822

1,784,044

+lll%

.83

1.22

.71

.92

.63

.57

.44

.47

.52

.46

,47

–43%

.10

.11

.13

.14

.11

.10

.07

.12

.15

.09

.12

+20%

37.64

35.20

36.55

39.54

41.26

46.98

37.86

32.43

40.77

47,31

55.25

+470/o

4.22

4.59

4.33

6.11

7.07

7.10

5.17

6.20

8.11 -

8.25

9.87

+134%

existing work force. The safety implications of

these alternative approaches vary and deserve

study before being embraced.

To illustrate this point it is useful to work

out the possible safety costs of a hypothetical

case of higher productivity leading to higher

production. If 1977 underground productivity

(8.58 tons per worker shift) had been what it

was in 1967 (15.07 tons)- production would

have increased from 255 million to 449 million

tons (assuming 210 production clays and

141,752 miners) Similarly, if 1977 surface productility (27.34 tons per worker shift) was the

1967 rate (35.17 tons), production would have

increased from 407 million to 524 million tons
Ch. V/— Workplace and Community Implications ● 281

(assuming 230 production days and 64,753

workers). Total national coal production

would have increased from about 688 milIion

to 973 miIIion tons, a figure in Iine with current

national goals for 1985. Underground fatalities

would have risen from 0.48 per production day

to 0.83 per production day; annually from 100

to 174.54 Underground injuries would have

risen from 55 per production day to 97, annually from 11,535 to 20,370. Similarly, surface

fatalities would have gone from 28 (actually

29) to 37 annually, injuries from 2,146 to 2,760.

This illustration, of course, is suggestive rather

than definitive.

Productivity strategies that reduce the work

force or increase production may prove to

have substantial safety costs. However, other

ways of improving productivity— technological innovation, redesign of the work process,

or more efficient production systems— may

actually improve safety performance either by

making the production process safer or by

reducing human exposure. The particular

method of productivity enhancement will

determine the level of safety costs. Analysis of

safety and productivity is handicapped by the

total lack of comparable mine-specific data

that would lend itself to deriving hard-and-fast

causal relationships between alternative

productivity-enhancing strategies and safety,

Such research is critically important to any national policy aimed at greater coal production

and productivity.

Types of Accidents

Three major kinds of conditions are now

associated with underground fatalities — roof

falls, haulage, and machinery. One of the major pre-1 969 causes of fatalities — mine disasters — has been sharply curtailed. The 1969 Act

outlined some general roof-control requirements — prohibiting activity under an unsupported roof, requiring a roof-control plan,

etc. –that have helped reduce roof-fall fatalities. Comparatively little legislative attention

was paid to machinery and haulage, although

some regulations — cabs and canopies, for example– have been promulgated since 1970. As

a percentage of the total, roof-falI fatalities

have declined from a 1956-60 average of 50

percent to a 1971-75 average of 34 percent.

However, haulage and machinery fatalities are

increasing as a share of total annual fatalities.

Such accidents are often caused by speeding

up production, taking short cuts, poor training,

inadequate equipment maintenance, and not

using caution as a regular part of the production process. Haulage and machinery are also

the leading categories of surface mine fatalities.

Underground disabling injuries are most

often associated with material handling, haulage, and machinery. Surface injuries are most

often slips or falls (of persons), handling

material, and machinery. Reducing injuries

from these causes may be more related to

altering production patterns, work routines,

and workload/work pace pressures than to new

equipment standards. 55

On the whole, the larger the underground

mine, the lower its fatality rate both in terms of

exposure and output. Underground mines producing more than 500,000 tons a year generally

had lower injury rates than smaller operations

in 1975. Strip mines producing more than 1

million tons annually had the lowest fatality

and injury rates of all (with one exception).
282 ● The Direct Use of Coal

Auger mines— none of which produced more

than 250,000 tons annually— had an extremely

high fatality rate. The smallest underground

and surface mines — producing less than

250,000 tons a year –generally had very high

fatality and injury rates. Most coal production — both surface and underground — comes

from mines producing 250,000 tons or more annually. Table 47 compares accident frequency

rates for 1975 by mine size. At every size—

with one exception — strip mines were safer

than underground mines whether measured in

exposure or output. I n most cases, larger mines

were safer than smaller mines, both underground and strip. Smaller mines are usually the

most marginal economically. Their equipment

is often older and they work more difficult

seams. Large mines in the East are usually

organized by UMWA, which has safety requirements negotiated into its contract. 56 Management attitude in small mines may affect safety

as much as market economics, safety economies of scale, and worker participation.

What Makes Mining Safe?

Certain economic and mine conditions appear to be associated with safe mining. Three

economic variables —technology, price, and

Federal regulations — are discussed below.

1. New extraction technology does not

necessarily lower fatality and injury frequency. When continuous miners were

phased in underground (1950-70), the fatality rate rose slightly and the disabling

injury rate remained relatively constant,

Longwall mining may reduce fatalities but

not necessarily injuries. 57 Contour strip

mining used in the Appalachian mountains is generally less safe than open-pit

mining found in the Midwest and West,

but the difference is due more to terrain

than to equipment used in each system.

Mining technology can be engineered

for safety as well as productivity. Current

underground mine technology — uninsulated electric powerlines, opaque ventilation curtains, belt haulage, electric-powered track haulage, cable-reel shuttle cars,

and conventional mining machinery— deserve safety analysis. I n surface mining,

comparisons between different flatland

excavating methods (power shovel vs.

draglines) and mountain-stripping systems

(auger vs. contour vs. mountaintop removal) would be instructive.

2. Coal price appears to be related to acci3

dent frequency. Both price and accident

rates were relatively constant in the 1950’s

and 1960’s. When prices rose after 1969,

fatality rates, at least, declined. The coal

industry’s two lowest years in injury frequency were 1974 and 1975, the same

years that coal prices hit record highs.

Prices stabilized in 1976 and 1977, and so

did fatality rates. But injury frequency–

especially underground —went up. This

pattern implies that operators are able to

take extra steps to safen their mines when

their profit margins are large and, conversely, do less when margins are

squeezed.

Federal mine safety regulation has three

components: setting standards, inspections, and civil penalties. Each component, however, does not appear to have

had equal impact on safety performance.

Both miners and operators generally

agree that most Federal regulations setting out electrical standards and minimum conditions and practices have

safened mining. But many aspects of

systems. Leslie Boden, “ Coal Mine Accidents and Gov -

ernment Enforcement of Safety Regulation s,” Ph D dissertation, Massachusetts Institute of Technology, 1977

Another found that no significant difference in injury

trends among the various mining methods See, D P

Schlick, R G Peluso, and K Thirumalal, “U S Coal Mining Accidents and Seam Thickness, ” The Aus. IMM Central Queensland Branch, Symposium on Thick Seam Mining by Underground Methods, September 1976
Ch, V/— Workplace and Community Implications ● 283

Table 47.—Injury Experience in Bituminous Coal Mines by Production Size, 1975

—

Per mill ion hours of exposure Per million tons of coal mined — — — ———

Nonfatal

Fatal disabling injury

.72

1.25

.56

.45

.47

.50

.33

,34

.34 —

.48

.58

.35

.38

.35

.64

.09

.42

.22

.19

—

.33

.42

26.94

48.11

45.86

55.74

50.06

46.46

30.12

32.00

28.68 —

37.11

10.10

15.49

17.42

15.33

18,46

22.72

18.55

22.18

16.22

-—

17.05

29.89

Nonfatal

Fatal disabling injury

4.27

.92

.44

.36

.42

.46

.26

.25

.18

159.00

35.17

36.12

44.38

44.82

42.64

23.96

23.40

15.49

.40 31.11

.85

.18

.17

.14

.25

.03

.13

.05

.03

.

‘.1O

14.74

8.11

7.86

6.32

7.19

7.67

5.81

5.23

2.73

5.01

.25 17.91

aDoes not Include auger mining and other miscellaneous surface mining.

— —

SOURCE Mine Safety and Health Administration Injury Experience in Coal Mining. 197, p. 77.

mining machinery have no standards set

for them. Some in the industry challenge

the inherent safeness of particular standards, such as underground lighting, temporary roof support, or cabs and canopies in thin seams. Often, a complaint

against a standard is based on the costs

of implementation rather than its intrinsic worth. Since compliance is basically

a matter of management policy, it is reasonable to conclude that post-1 969 improvement has resulted from operators

complying with standards.

Federal inspection is the principal minesite

enforcement tool. Several studies have found

that safety improved with the frequency of

Federal inspection. Boden’s study of 539 bituminous underground mines producing more

than 100,000 tons annually indicated that inspection leads to fewer injuries. A 50-percent

increase in Federal inspection rates in this sample was predicted to lead to 11 fewer fatalities,

2,400 fewer disabling injuries, and 3,800 fewer

nondisabling injuries per year. 56 Another study

estimated that one more Federal inspection

per mine would decrease annual fatalities by 4

and nonfatal injuries by 52.59

It is difficult to discern the real effect of

MSHA’S civil penalty program on safety. The

average assessed penalty in 1978 was about

$180, of which about $150 was collected, according to MS HA. Both the average assessment and average collection in 1978 was about

twice the level of earlier years. MSHA also has

a “special” penalty program for serious

violations—those involving negligence, and

unwarrantable failure to comply, and viola-

‘

8 Boden, “Coal Mine Accidents “

‘

9 Louise Julian, “Output, Productivity, and Accidents

and Fatalities Under the Coal Mine Health and Safety

Act, ” mimeographed (University Park, Pa The Pennsylvania State University, circa 1978)
284 ● The Direct Use of Coal

(steel-owned) are generally safer than noncaptive mines, but this may have as much to

do with reporting practices as safe operations. b2 No clear relationship is demonstrated

between safety and unionization. Large, captive underground mines (almost all of which

are organized by UMWA) are safer than small,

non captive underground mines (many of

which are non-UMWA), but it is not clear that

the unionization variable makes the difference.

Several conclusions may be drawn from the

available data. First, since surface mining is

demonstrably safer than underground mining,

additional research and enforcement should

be directed at the latter. Research is needed to

determine what combination of underground

mine factors— equipment, management attitude, worker role, and so forth —safen operations. Since small underground mines are generally less safe than large mines, research and

enforcement should be focused there.

Second, worsening underground injury experience needs to be addressed specifically.

Injury-producing accidents appear to be linked

to the interaction of three factors:

1. an incredibly narrow margin for error in

the work environment,

2. inadequately trained workers who may

not know how to— or are not permitted

to–work safely, and

3. production-oriented supervisors who accelerate the normal pace of work and fail

to maintain equipment properly. b3

“Theodore Barry and Associates, Industrial Engineering Study of Hazards Associated With Underground Coal

Mine Production, 1971

“Ibid Management skill and management policy are

variables of acknowledged importance In maintaining

safety, but neither has received the necessary attention

One exception was the Barry study of mine accidents

which found:

almost every operator interviewed cited the

insufficient numbers of high-quality operating

supervisors, and the resultant loss of supervisory effectiveness at the working face, as one of the major

problems confronting the industry today in terms of

both safety and production. (p 259)

too many foremen are not safety conscious

(continued)
Ch. VI— Workplace and Community Implications 285

Smaller mining machines that build in safety

features, pneumatic, battery-powered, chaintype, or hydraulic face-to-portal haulage systems; packaging supplies in smaller, lighter

units are al I areas where research and development might reduce accidents. Behavioral factors also require examination. Job pressure, insufficient training, inexperienced supervision,

inadequate hazard-recognition education, inappropriate worker and management attitudes— all may bear more heavily on injuryproducing conditions than those more easily

recognizable conditions that produce fatalities. Injury prevention may not be achievable

by more rigorous enforcement of existing Federal standards if, as seems to be the case, current standards don’t come to grips with the

causes of mine injuries.

Third, mine safety may be improved considerably by changing certain psychological,

behavioral, and organizational factors in the

workplace. A recent report found significant

differences in such areas between high- and

low-accident mines.64 Some of its major findings were:

● It appears that coal companies, especially

high-accident mines, need to formalize

safety as an organizational goal, and

subsequently communicate to workers

both verbally and through the behavior of

management the relative importance of

safety . . . if coal companies truly do

value safety over production, the message

is apparently not reaching miners. If coal

companies do not, in fact, value safety

over production, then a more fundamental problem exists in terms of overall goals

and orientation of the organization. Results indicate that in high-accident mines,

problems stem from safety never having

been adopted as an organizational goal.

● . , . a second area that deserves consideration in the coal industry is work organization and job design. It has been established in the literature that jobs which are

designed with an awareness of worker

needs for recognition, responsibility, and

variety tend to contribute to higher

worker satisfaction and improved work

quality, including safety performance.

● Survey results substantiate the need for

training by providing empirical evidence

that good training is related to a low-accident record. Underground miners in lowaccident mines indicated that their training in dealing with hazards such as gas,

dust, and noise was significantly . . . better than the training in high-accident

mines . the fact that foremen could

use additional training is evident from the

fact that many foremen do not use safety

equipment when necessary,

● I n comparing high- with low-accident

mines, two disorders were significantly

more prevalent in miners working in highaccident mines — high blood pressure (29

percent versus 10 percent respectively)

and ‘nervous trouble’ (16 percent versus 2

percent respectively) . . . it would seem

that a program designed to reduce occupational stress could have a significant

impact on the safety, health, and wellbeing of coal mining personnel. ’s

In the past, the cause of mine safety has

been driven by headline-grabbing, multivictim

disasters. In the future, this driving force is not

likely to exist, yet fatalities and injuries are

likely to rise steadily. While management reserves the right to determine the balance between production and safety, higher numbers

’

5

1 bld
286 ● The Direct Use of Coa/

of mine accidents may lead Congress to find it

prudent to encourage modifications in management attitudes and priorities. A comprehensive injury-prevent ion program woul d

equip miners with the knowledge, skills, and

rights to protect themselves. Because so much

of mining is a matter of individual miners

adapting to ever-changing conditions, enfranchising them in this manner may prove to be an

inexpensive and effective way of reducing accidents.

Data Analysis

Coal mine injury and fatality data are imperfect and incomplete. A clear bias toward

undercounting appears. bb The actual human

costs of coal production have been understated historically. Accurate data are crucial

to wise policymaking. Valid projections of

future human costs associated with increased

coal production must be based on the most accurate data obtainable. It is probably reasonable to assume that fatalities have been undercounted by as much as 3 to 6 percent annually

and disabling injuries by 25 percent. Both, admittedly, are “guesstimates. ” The Mine Safety

appendix in volume I I discusses the shortcomings in the reporting and counting of workplace accidents. That argument is highlighted

here:

Fatalities.— Accidents involving employees

of independent contractors, such as mine construction workers, were excluded from MSHA

data until last year. Perhaps as many as 20,000

workers fall into this category. UMWA sources

estimated that 32 coal construction workers

died between 1970 and the end of 1976. A reasoned guess is that an average of four or five

construct ion/contractor fatalities may not

have been counted each year. MSHA is now

trying to include contractor accidents in its

“Both the General Accounting Office and the Department of the Interior have reached this conclusion after

studying MSHA’S system Every major study of occupational injury and disease reporting supports this finding

See for example, Jerome B Gordon, Al Ian Akman, and

Michael L Brooks, Industrial Safety Statistics. A Re- Examination, A Critical Report Prepared for the U.S. Department of Labor (New York Praeger, 1971), and Nicholas

Ashford, Crlsls In the Workplace (New York Quadrangle,

1976)

data base, but it is too early to evaluate the effectiveness of the effort.

Other reporting loopholes exist. For example, persons who die from “an event at a mine”

but who are not at the mine when the event occurs should be counted as mine fatalities.

Usually, they are not. The 125 deaths that

resulted from the collapse of a coal-waste impoundment on Buffalo Creek, W. Va., in 1972

were not reported in MSHA fatality data. Offsite fatalities that occur from boulders and

debris launched by surface-mine blasting

would not be usually reported. When a fatality

from occupational illness occurs at a mine, it is

usually not reported despite clear Federal regulations requiring the operator to do so. Determining whether such a fatality was caused by

coal mine employment is medically difficult;

consequently, an attempt is rarely made.

MSHA data show no fatalities from occupational illness reported since 1972. For these

reasons and others, puzzling discrepancies exist between Federal fatality data and those

recorded by State worker-compensation programs. Finally, MSHA defined coal workers in

such a way that when three of its own inspectors were killed at the Scotia mine in 1976 they

were not counted as mine fatalities.

Injuries. – Until 1978, MSHA defined a

disabling injury as “any work injury which does

not result in death but which either results in

any permanent impairment to the injured person or causes the injured person to lose 1 full

day or more from work after the day of the injury. ”b7 A nondisabling injury did not result in

a lost shift after the day of the injury. The

distinction between disabling and nondisabling is important. Insurance premiums are

linked to the former, but not the latter. Corporate safety performance is measured in the

same fashion. Thus, employers had incentives

to show as few disabling injuries as possible.

Some mines and companies, therefore,

adopted “light-duty” policies whereby an injured miner was encouraged to come to work

on the day after an injury to be assigned light

work. Miners call this “bench warming” or the

“bandaid brigaid.” The injury was reported as

“Department of the Interior, Bureau of Mines, title 30,

pt 80 l(e)(f)
Ch. VI— Workplace and Community Implications ● 287

nondisabling rather than disabling. Miners fits that were less than normal pay. But by not

often agreed to Iight-duty assignments because reporting the injury as disabling, the worker

they feared job reprisals. It was also far less lost any claim to future compensation. In a

bother

Iect an

file for

to go along with the company and col- case — such as a back injury — that may worsen

uninterrupted paycheck than it was to over time, the miner could be severely penalworkers’ compensation and await bene- ized.

Photo credit: Earl Dotter

Disabled UMWA miner and family on strike in Harlan County, Ky., 1974
288 ● The Direct Use of Coal

Injury data may also be affected by how individual companies choose to interpret their

Federal accident-reporting obligations. Interior

Department investigations in 1975 found extensive misclassification of accidents. b8 lnterior found in its sample that only about 17

percent of all injuries were ever reported to

MSHA’S data collection center. ’9 About 39 percent of disabling injuries were not reported, including: 1) finger amputated to first joint (8

lost workdays); 2) foot bruised with complication (13 lost workdays); and 3) knee bruised

and infected, fractured fingers, and cracked

rib. About 44 percent of nondisabling injuries

were not reported. Underreporting resulted

from oversight, misinterpretation, and deliberate circumvention of reporting regulations. An

Interior update of the 1975 survey turned up

similar findings. ’” In 1975 and 1976, nearly 65

percent of all active mines did not report a

single injury. Underreporting was most suspect

at larger mines and less suspect at smaller

ones. Interior’s “basic conclusion” was that

MSHA’S “accident/injury data submitted by

mine operations cannot be relied on as reasonably accurate. ” Suspect reporting was the

result of “corporate policy on reporting practices,” Interior said. Recent survey-research of

30 underground mines found that “foremen in

low-accident mines were reported to turn in inaccurate safety reports more often than foremen in high-accident mines. ”7’

Within the last year, MSHA has tightened its

definition of disabling injuries to reduce underreporting. MSHA believes that the new definitions of disabling injury has cut underreporting by two-thirds. Some MSHA officials say unofficially that more than 80 percent of all in-

“’’Review of Accident/Injury and Production/Manhour reporting under the Federal Coal Mine Health and

Safety Act of 1969 administered by the Mining Enforcement and Safety Administration, ” U.S. Department of

the Interior, Office of Audit and Investigation, memorandum of Nov 19,1975.

‘glbld,, p 5.

“’Opportunities to Improve the Effectiveness of Mining

Enforcement and Safety Administration Accident/Injury

and Employment Production Data Information Systems

(Washington, D C.: U.S. Department of the Interior, Office of Audit and Investigation, 1977), pp. 6,15.

7’ Westinghouse Behavioral Service Center, Psychological. . . Factors, p. 84.

juries are now being reported under the new

system. Some observers argue that accidents

were undercounted by as much as 60 percent

under the old definitions. 72 The 1975 Interior

audit found 39-percent undercounting of disabling injuries. A correction factor of 25 percent is used in table 48 to illustrate possible accident experience for 1967-77. Underreporting

of tonnage and accidents lowers productivity,

distorts accident data (thereby confusing policy analysis), understates future compensation

costs, and lowers worker morale and respect

for Federal safety efforts.

Safety Projections. —The safety implications

of increased coal production are critically important to Congress. The dollar costs of fatalities ($1 53,000 each) and injuries ($4,900 each)

are immense. Production and productivity are

reduced when accidents occur. Coal workers

and their families experience pain and suffering. For these reasons and others, Congress has

expressed sustained interest in minimizing coal

mine accidents. Unfortunately, fatalities and

injuries will increase as more coal is mined

unless steps are taken to reduce accident frequency.

The likely range of fatalities and injuries

associated with higher production levels is

shown in table 49. These estimates assume no

change in certain variables — production pressure, productivity rates, accident reporting reliability, seam conditions, and work force and

management characteristics. Those variables

that have been considered are: number of coal

workers and production levels.

Fatality and injury rates for 1977 were used

to calculate the number of fatalities and injuries in 1985 and 2000. These rates may go

down. If they are lowered sufficiently, they

will offset the increasing number of workers

exposed to safety hazards, thereby reducing

estimated accident totals. However, if the

rates improve only modestly, the actual num72L. Thomas Galloway of the Center for Law and Social

Policy argued that the MESA injury rates did not reflect

up to 60 percent of al I coal mine accidents because of

underreporting. See GalIoway testimony in U S Senate,

Federal Mine Safety Health Amendments of 1976, hearings on S. 1302, 94th Cong , 2d sess., Mar, 24, 25, 30, and

31,1976, p. 920,
Ch. VI— Workplace and Community Implications ● 289

Table 48.–All U.S. Coal Estimated Accident Experience, 1967.77

(hours of exposure)

Unrecorded

Nonfatal Nonfatal

disabling Rate as disabling Estimated

injuries calculated by injuries, adjusted

recorded’ MSHAb

additional rate d

10,115

9,639

9,917

11,552

11,916

12,329

11,220

8,545

11,107

14,389

14,989

41.84

41.12

41.76

44.40

46.89

46.08

40.41

28.79

30.17

37.55

38.37est.

2,529

2,410

2,479

2,888

2,979

3,082

2,805

2,136

2,777

3,486

3,698

51.82

51.13

54.70

62.32

53.70

52.53

36.58

34.28

45.51

47.82

45.68est.

Table 49.—Mine Worker Fatality and injury Estimates

1985b 2000

1977 Low High Low High

29

2,281

25

1,954

30

2,401

32

2,515

46

3,634

100

11,724

118

13,907

140

16,513

203

24,012

291

34,405

Other Coal workersa

Fatalities . . . . . . . . . . . . . . . . . . . . . . . . . . ..

Injuries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

10

984

14

1,586

17

1.891

24

2,653

34

3,804

139

14,989

157

17,447

187

20,805

259

29,180

371

41,843

ber of fatalities and injuries will still rise over Between 157 and 187 coal workers are likely

current levels because of the Iarger number of to be killed and between 17,400 and 20,800 inworkers employed. Accident frequency rates jured in 1985. That represents a 13- to 35-perhave not improved substantially for several cent increase in fatalities over 1977 and a 17-

years, and it may be that the 1969 Act will not to 39-percent increase in injuries. By 2000, behave any additional impact on lowering them. tween 259 and 37I coal workers preestimated
290 The Direct Use of Coal

to be killed and between 29,200 and 41,800 injured. These estimates represent an 86- to 167-

percent increase in fatalities over 1977 and a

95- to 180-percent increase in injuries. These

calculations assume no underreporting and undercounting. The 25-year total (1976-2000) of

mine fatalities may exceed 5,000 and injuries

may exceed 500,000.

Conclusion

These estimates of future fatality and injury

costs are disquieting. No one likes to measure

the cost of electricity in human life and limb.

Yet it is clear that coal production two to three

times higher than current levels will greatly increase the number of fatalities and injuries

unless frequency rates are cut sharply or productivity rises spectacularly (which would

mean fewer workers exposed). Neither seem

likely to materialize in the next 10 years assuming “business as usual. ” Frequency rates have

not improved since the mid-l 970’s. Productivity is Iikely to rise in the future, but very slowly.

Introduction

Congress clearly stated its position in the 1969

Act, which provided for the “attainment of the

highest degree of safety protection for miners. ” The Act recognized that “deaths and serious injuries from unsafe . conditions and

practices in the coal mines cause grief and suffering to the miners and their families. ” They

also cost money and coal,

Thousands of hours of production will be

lost because of injuries. Productivity will be

lowered. Hundreds of millions of dollars in

worker compensation benefits will be paid.

Coal workers and their allies may increase

their resistance to management over safety

issues. Absenteeism and wildcat strikes may

erupt. Congress may again become the object

of intense pressure for even more stringent

mine safety legislation. For all of these reasons, the effort to step up coal production and

productivity ought to be accompanied by increased efforts to minimize fatalities and injuries. So far, this has not occurred.

COMMUNITY IMPACTS

Coal mining shapes the social, economic,

and political life of the communities in which

it occurs. The scope and intensity of coal’s

local impacts differ from region to region”

depending on the nature of the precoal economy, the extent of local coal development,

and the level and regularity of demand for the

local product. Local and regional impacts were

also determined by the kinds of mining methods employed, level of mechanization, size of

the mines, extent of economic diversification,

local sociopolitical structures, company ownership patterns (local or absentee), presence or

absence of unionization, and topography.

“Coal production has been centered historically in

three regional coal fields the Appalachian fields ranging

from Pennsylvania to Alabama: the Midwestern fields including IIlinols, Indiana, west Kentucky, and portions of

Kansas and Iowa; and the Western fields covering Colorado, Wyoming, Montana, Utah, New Mexico, and

Arizona

Mining has usually occurred in remote

areas, where industrialization and other forms

of commerce were not well-developed. Often,

coal became the only “cash crop. ” One-crop

economies–be they cotton, cocoa, or coal–

often mean many social and environmental

costs are externalized. Where mining was the

principal economic activity, its effect on community life was greatest. Where mining was

part of a diversified economy, its impact was

less broad and less deep.

Appalachia has been America’s bituminous

coal bucket for a century; it is there that coal

has impacted most heavily. What strikes the

observer of coal field Appalachia is the near

total absence of other primary economic enterprise. The Iand itself was not hospitable to

much more than subsistence farming, so mining quickly replaced existing socioeconomic

structures. I n Ohio, IIIinois, and western Kentucky the agricultural base was sufficient to

resist being supplanted. Yet even there, other
Ch. V/— Workplace and Community Implications ● 291

industrial activity did not generally follow the

development of local coal resources.

Coal operators often had to build not only

mining and transportation systems, but also

whole towns, complete with commercial and

professional services, housing, roads, cultural

activities, and political systems. Each community was almost totally dependent on the

marketplace success of its local operator. The

public infrastructure in these communities—

its institutions, services, and personnel —was

an adjunctive activity for the operators, whose

principal concern was the profitability of their

coal business. Company town were often a

profitmaking business for a coal company

even in slack times. Many times the town’s

profits were the only ones an operator could

show for being in the coal business. I n some

cases, operators saw community social investment as an unproductive and unprofitable use

of scarce capital. When competition was intense and demand slack — as it was for most of

the 20th century— support for community institutions was often the first economy operators effected.

The pattern of coal development in the Midwest and West differed less in manner than

scope. There, too, the company-town model

was used, but it was less frequent and less pervasive. More often, coal commercialization

occurred in existing towns whose Iifeblood was

agriculture, which continued alongside coal

production. Coal development in the Midwest

did not snuff out traditional economies and

social systems as it did in much of Appalachia.

Economic diversity enabled Midwestern communities to survive coal’s lean times. Finally,

because the demand for Midwestern and Western coals was generalIy less than for Appalachian coals, mining never dominated these

regions as it did Appalachia.

Rocky Mountain coal development was

even slower and less comprehensive than that

of either the Midwest or Appalachia, although

it impacted specific communities with equal

intensity. Markets were generally limited to

steam-grade coal for railroads and industrial

activity. Mining towns and boomtowns existed

in the West prior to coal development; coal

continued the boomtown pattern. As the

seams played out or demand evaporated, the

jerry-built boomtowns tended to be abandoned. In contrast, Appalachians tended to

stay where they were despite cyclical coal demand.

Coal development shaped the political

structures and culture that evolved in coal

towns. Coal entrepreneurs had economic reasons for developing harmonious relationships

with the local officials who administered the

legal apparatus, tax system, and public services. In many cases, coal operators had to

create a political system because none existed,

often tying the public sector directly into the

administration of the mining enterprise. As a

result, the political culture that took root was

widely perceived by residents to be the public

expression of the local coal company.

In terms of social structure, in much of the

Eastern coalfields, coal’s method of industrialization meant that communities were divided

into two basic classes: management and labor.

The antagonisms produced in the mine workplace never dissipated in the environs of the

company town where the workplace division

was maintained socially. Miners’ grievances

have usually been played out through on-thejob militancy rather than in electoral politics

because miners believed their power was more

effective in the workplace.

The two-class structure prevented a noncoal

middle class from forming. In other parts of

America where an independent middle class

developed, civic reform was forced on entrenched political elites. Had an independent

middle class existed, it is reasonable to suppose that coalfield politics would have been

pluralized and more adaptive to change. As it

was, however, civic improvement was left to

the discretion of individual coal companies.

Some companies made good-faith efforts to

supply their employees with decent housing,

medical attention, education, and public services. The majority, however, could not or did

not spare the money and effort. Yet even

where operators made a good-faith effort, they

did soon their terms.
292 ● The Direct Use of Coal

For these reasons and others, public administration in many coalfield communities today–particularly in Appalachia– is often

characterized by a lack of professional skills

and institutions. Local politics is often tied to

political machines and personalities. Corruption and inefficiency are not unknown. In the

slack years of the 1950’s and 1960’s, public administration was heavily influenced by patronage considerations, as the public sector often

replaced the private sector as the major local

employer. Because the political system was so

much an extension of local economics, public

authority could do little to regulate the widespread cost externalizations of mining.

These historic patterns of underdevelopment have produced in much of the Eastern

coalfields stunted private and public infrastructures that cannot respond to the needs of

rapid coal expansion.

Because underground mining is the most

common system in Appalachia, the community impacts there have been far greater in proportion to output than in the West where surface mining dominates and requires far fewer

miners per unit of output. Even though most

new coal output is scheduled to come from

surface mines west of the Mississippi River,

five times as many miners will work in the East

than in the West in 1985 (chapter 11, table 6). If

the impact problems of increasing coal production were to be translated into one simple

concept —more people— the socioeconomic

impacts will be predictably greater in the East,

and especially in central Appalachia, than in

the West.

Coal mining brings benefits and costs alike

to local communities. Both have a private and

a public side. Further, both have a dollar side

and a nondollar side. In developing a mine,

however, the cost-benefit calculus lies entirely

with the individual entrepreneur. He establishes the scope of the project, its methods,

and its rate of development. It is his ratio of

(private) dollar costs to dollar benefits that

determines whether a project is begun. it is on

the assumption of profitability (that is, benefits over costs) that he ventures capital. The

costs in this case are those that the company

pays (internalizes) to produce coal at a profit.

Public costs are generally not evaluated by the

mine developer because they are not directly

relevant to his balance sheet.

The local private sector bears a share of the

costs of increased coal development. The private sector in this instance consists of three

parties: the operator, his employees, and local

private interests. Private costs can be divided

into three categories: costs of production that

are internalized by the operator, costs of production that are externalized and absorbed

either by the workers or by local private interests, and opportunity costs. Internalized

production costs are carefully projected and

regulated by mine operators and are a normal

part of doing business. Externalized costs and

opportunity costs are not readily quantifiable

but may be gauged by looking at occupational

injuries and disease (including compensation

programs), private health care utilization patterns and costs, lack of economic diversification, shortage of local investment capital,

stress on community values and social structure, etc. Opportunity costs include all of the

existing local business that ends as a result of

coal mining, together with all noncoal business

that might have occurred had mining not happened.

Coal production directly benefits its employees and their communities through wages

and fringe benefits. The public sector also

benefits from production. Economic growth

helps a community prosper. Taxes may be

levied on coal property, wages, sales, corporate income, and on the product itself to

support public services. Presumably, a relationship can be drawn between the level of

private sector benefits on one hand with public-sector benefits on the other. It might reasonably be expected that where the private

sector–both owners and employees–benefits, the public also gains.

But such a relationship has not always held

in the Eastern coalfields throughout much of

this century because of the volatility of coal

demand, the boom-bust cycle, and other

unique factors. In the first two decades, the

level of public benefits was determined by the

coal operator who owned the community. The

public interest was defined by the private sec-
Ch. V/— Workplace and Community Implications ● 293

tor. The company-town model polarized the

private sector into “company men” and employees; neither group was capable of advocating an independent public interest. Even today as increased spendable income from mine

employment reflects “economic growth”, the

development of community services and institutions lags. Growth is not synonymous with –

and may not lead to—development. Community polarization continued long after companies liquidated company towns. For these

reasons, increasing private benefits have not

been matched by increasing public benefits.

Public benefits from coal production have also

been circumscribed historically by protracted

demand stagnation. Even as America’s consumption of energy quadrupled from 1920 to

1970, coal’s share dropped from about 78 percent of the total energy market to 19 percent. 74

Stagnating demand meant that coal towns

were never able to levy reasonable taxes on

their principal local business for fear of shutting it down. Thus they never had the money to

provide adequate public services. Studies of

taxation patterns in coal counties find historical patterns of underassessment of undeveloped coal property and undertaxation of that

which is assessed. States passed severance

taxes in the early 1970’s with great difficulty,

and only when demand and prices were rising.

Low taxation functioned as a public subsidy to

local operators. Whatever the merits of the

subsidy, it resulted in the chronic underdevelopment of coalfield public services and institutions. The public sector—especially at the

local level –was thus forced to bear disproportionately high costs while reaping disproportionately few benefits from coal development

through the 1960’s. On the other hand, whatever public benefits that existed in these areas

came from coal. To that extent, coal development was a source of both community benefit

and community deficit.

Similarly, local governments rarely regulated coal’s social costs. Operators often sited

“See National Coal Association, Coal Facts ,

1974-1975, pp 58-59 In 1920, about 592 mllllon tons of

bituminous and anthracite coal were consumed whereas

In 1970, only 524 mill ion tons were used domestically.

Domestic consumption of bituminous coal was 509 mllI ion tons in 1920 and 516 mllllon tons in 197o

their mines outside of incorporated areas to

avoid taxation and land-use restrictions. State

legislatures and Governors rarely chose to do

battle with politically powerful, economically

imperiled coal operators. These economic realities and attitudes inhibited predictable and

sustained development of public services in

coal communities. Long-term planning was not

undertaken. Eventually, coal field expectations

about public services became permanently

undervalued. What people never had, they

were encouraged never to expect. Doing without became the norm.

Congress has debated an energy-impact assistance bill in recent sessions. Funds would be

provided from general Federal revenues rather

than through a national severance tax. The

Farmers Home Administration (Fm HA) proposed guidelines to disperse $20 million to

coal- and uranium-impacted communities in

March 1979. The assistance would be used for

growth-management plans, housing plans,

housing, public facilities, and services. However, little of this aid will find its way to Appalachian communities because the FmHA

growth requirement— 8 percent or more in

coal employment in the year following the

base year— is too high to qualify the wellsettled, high-employment areas there. Congress may increase appropriations for this purpose orconsider a coal-financed contribution.

Much of this history is discouraging and pessimistic. Perhaps sustained, increasing coal demand will correct these problems. If that is to

happen, policy makers need a clear picture of

current coal field conditions and the reasons

why things are as they are. The following sections describe these conditions in the East and

West.

Impacts on Eastern Communities

More than 90 percent of all of the coal ever

mined in the United States has come from

States east of the Mississippi River. Nearly 50

percent of the Nation’s remaining demonstrated coal reserves are found there. Billions

of dollars of coal have been —and will be—

mined from under the Appalachian Mountains

and the fields of the IIlinois Basin.

The visitor to the Central Appalachian coalfields is struck by its contrasts. Trains of 100
294 The Direct Use of Coal

cars regularly haul hundreds of thousands of

dollars worth of coal past grimy, railside

shacks. Yet amid the dingy grimness of many

old coalfield towns, the visitor wilI sometimes

come upon a bustling county seat that has

been turned into a multicounty, commercial

center within the last 5 years. The natural

beauty of the mountains contrasts starkly with

the scars and blemishes they bear from past

mining practices. Finally, the visitor will meet

at least three distinct groups of people: the

very poor, the middle-income working miner,

and the well-to-do.

The typical Central Appalachian coalfield

community is small, congested, and lies along

a stream or smalI river. Mountains often circumscribe the town and define its growth.

Here and there comfortable ranch-style brick

houses appear. Most buildings are old and

rarely renovated, except for an occasional new

fast-food restaurant or quick-service grocery, a

modern brick post office, or public building,

The roads linking the outlying hollows to the

towns (and the towns to each other) are often

narrow, poorly engineered, dangerous, and

falling apart. Mobile homes are wedged between mountain and highway wherever a flat

place can be found or bulldozed. Yet the

visitor will also see a meticulously tended

garden beside each house. Well-kept churches

and cemeteries are the rule. Evidence that this

is coal country appears frequently: a tipple; a

portal; an old strip mine highwall or slag heap;

a bumper sticker that says, “We dig coal. ”

Within a typical community it is common to

find severely inadequate water and sewage

systems, a low level of most public services, an

almost complete absence of public transportation, a shortage of adequate housing, undercapitalized financial institutions, limited education programs, and a general feeling that the

quality of community life is not what it could

be. Although coal miners make $17,000 or

more in a normal year, many find it difficult to

purchase quality goods and services that nonAppalachians with similar incomes take for

granted. Thus coaifield residents often feel individually deprived and publicly disadvantaged. As a result, there is a general ambivalence about the coal industry. On one hand,

miners feel an intense pride in their profession

and appreciate its wages and benefits. On the

other, many believe they and their communities have been victimized by the ups and

downs of coal demand and the cost-consciousness of their employers.

North into Pennsylvania and west through

Ohio, Indiana, Illinois, and Kentucky, the coal

towns change. The mountains flatten out. The

visual impact of old strip mines is less severe.

The towns are less cramped and seem more

prosperous. Farming coexists with mining. In

the Ohio River Basin, manufacturing and other

businesses make coal less important. Public

services appear to be closer to national norms.

The towns are less coal towns than towns

where coal mining occurs along with other

businesses. The distinction is significant. In

one, community life is totally dependent on

the fortunes of a single industry. In the other,

economic development is balanced and has

been cushioned from the consequences of

coal’s quick booms and long busts. Finally,

miners here appear to enjoy a better quality of

community life and seem able to use their incomes more efficiently. One sees fewer very

poor or very affIuent.

Coal mining’s impact on community life

varies with conditions in the marketplace, terrain, the extent of economic diversification,

and the kind of industrial socialization each

community experienced when coal was developed. Generally, the social, political, and economic effects of coal mining have been most

severe where communities were totally dependent on coal, where the terrain was inhospitable to other activity, and where mining was

the principal socializing force in community

life. When these factors were less dominant,

the public benefits of mining were greater.

The extensive underdevelopment of much

of the Appalachian coalfields is not difficult to

explain. First, demand for coal has remained

stagnant for most of the last 55 years. This

placed tremendous cost-cutting pressure on

coal companies. Economy was effected by

holding down labor costs, mechanizing, and

minimizing tax burdens through the exercise of

political power at the local and State levels.

Neither miners nor indigenous coal operators
Ch. V/— Workplace and Community Implications ● 295

Photo credit: Earl Dotter

Coalfield housing located in the Cityview area of Logan County, W. Va.
296 ● The Direct Use 01 Coa/

got very far ahead until the 1970’s. That meant

coal field communities lacked investment capital, tax resources, and spendable income.

Second, mining companies were forced to

externalize production costs in order to survive. Thus strip mines and slag heaps were not

reclaimed; coal-haul roads were abused;

streams were polluted. Most State and local efforts to internalize these costs through taxation and regulation were fought and generally

defeated until the 1970’s. Had such efforts

been successful, some marginal companies

would have gone under and others would have

had a harder time.

Third, Appalachia has served America as a

resource exporter. Coal mining did not stimulate investment in manufacturing, often limited development of other economic activity.

Coal users usually did not locate their manufacturing and processing near coal mines.

Again, a diversified economic base did not

take hold.

Fourth, the biggest mining operations were

usually owned by nonindigenous companies.

Some of these companies developed adequate

communities to service their mines; others did

not. Mining profits— such as they were—were

not deposited in coalfield banks, so mining’s

financial benefits to coal towns were limited

principally to wage and salary income. Consequently, the private sector in many coalfield

communities has been chronically short of

cash. Native entrepreneurs usually engaged in

the most marginal kinds of business, mining

and otherwise, because capital was so hard to

assemble. These two factors— initial inadequacies in community-building and subsequent capital shortages— left coal towns with

chronically unmet needs and lacking the ability to solve their own problems.

Any analysis of the future socioeconomic

impacts of increasing Eastern coal production

must confront the social legacy of past coal

development. The post-1973 Appalachian

“coal boom” has not been based on increased

production. Indeed, production has falIen–

particularly underground tonnage. The boom

was one of price and profit on management’s

side and wages and jobs on Iabor’s. That combination, lacking as it does the necessary

premise of more output, cannot be and has not

been sustained. Even as the promise of coal

growth beckoned, 5,000 to 10,000 miners were

laid off or placed on short work weeks in recent months as metallurgical demand dropped

and because utilities chose to meet air pollution standards by using low-sulfur coals rather

than through installing scrubbers or other

sulfur control measures.

With these shifting developments, it is difficult to forecast a uniform set of socioeconomic implications from increased Appalachian coal mining. Two to three dozen counties may find it extremely difficult to manage

either growth or stagnation, as neither condition is predictable. For other coal counties,

production will expand steadily and a range of

growth-related social and economic issues will

demand attention. As a result, Federal policy

will need to be flexible and address three coalrelated issues of Appalachian community development:

1.

2.

3.

The current residual deficit in facilities

and services in both stagnating and expanding communities.

The problem of continued uneven coal

demand affecting particular communities

or sub-State areas.

The problems of rapid coal development.

The capacity of any community to benefit

from coal expansion depends to a great extent

on the seriousness of its existing underdevelopment. Where this deficit is greatest, expansion

will produce the most problems; where it is

least, growth will be accommodated and the

ability of communities to cope with associated

social problems will be greatest.

Scope of Eastern Coal Expansion

Estimates of new Eastern coal production

vary, rising or falling according to the optimism and assumptions of the estimator. One

survey forecast 255 miIIion tons of new capacity in 11 Eastern States by 1987, of which 197

million tons would be deep-mined and 58 mil-
Ch. V/— Workplace and Community Implications ● 297

lion tons surface-mined, ” This report estimates 212 million tons of planned capacity

east of the Mississippi by 1985 (chapter 11,

table 5). More significantly, no net increase in

Eastern coal production is foreseen through

1985.

Appalachia produced 390 million tons in

1977, (had there not been a 10-week wildcat

strike that summer and a month-long shutdown in December, output would have been

around 425 mill ion tons). Appalachian production in 1985 should range from 355 million to

415 million tons and in 2000 from 510 million

to 680 million tons (chapter 11, table 5). The

three remaining Eastern States — IIlinois, lndiana, and Kentucky (west) –produced 133

million tons in 1977. Actual production should

range between 128 miIIion and 164 miiIion tons

in 1985. Substantial expansion of eastern production is likely to occur after 1985. From 510

miIIion to 680 miIIion tons of Appalachian production and 206 million to 299 million tons

from IIlinois, Indiana, and western Kentucky is

expected by 2000.

These estimates suggest that the East as a

coal-producing region has 6 years in which to

plan for higher production. However, some

communities will be heavily affected by coalrelated growth within these 6 years. Others wilI

not experience any expanded production but

will probably be required to absorb additional

coal-related employment.

Forecasting community impacts of increased coal production hinges on the amount

of coal actually produced in the future (rather

than theoretical capacity) and the proportion

of new production mined by strip and deep

methods. Underground mining now requires

roughly 550 miners to produce 1 million tons;

surface mining uses about 160 miners for the

same amount at current productivity rates. Accordingly, between 144,000 and 167,000 miners

will be employed in Appalachia in 1985. No increase in net Appalachian mine employment is

forecast for the next 6 years, although in-

“George F Nielsen, “Keystone forecasts 765 Million

Tons of New Coal Capacity by 1987, ” Coal Age, February

1978, pp 113-134 The 11 States are Alabama, Georgia, IIIInols, Indiana, Kentucky, Maryland, Ohio, Pennsylvania,

Tennessee, Vlrglnla, and West VIrglnla

dividual counties may show net gains of

miners. In Illinois, Indiana, and western Kentucky between 29,000 and 38,000 miners

shouId be employed in 1985. As net production

increases between 1985 and 2000, mine employment will probably increase proportionately. These projections assume no change in

productivity and do not include nonminer coal

workers, such as mine construction workers,

and those who work in preparation plants, tipples, and shops.

For each new miner, it can be assumed that

five other persons– spouse, children, and secondary-employees —wiII be added to local

communities. The net population increase

from coal production in the East is likely to

range from zero to 100,000 persons by 1985.

Specific counties will be most heavily affected

when new deep mines are put in where the existing social deficit is greatest. The most impacted counties will probably be in southern

West Virginia, eastern Kentucky, southwestern

Pennsylvania, and some areas of the Illinois

Basin,

Existing Conditions

Social and economic conditions in Eastern

coal field counties differ widely. Compared

with the United States as a whole, the 50 leading coal counties in the East showed gross deficits in income, educational attainment, and

housing in the 1970 census. ” Central Appa-
298 ● The Direct Use of Coa/

Iachian counties had the highest deficit, IlIinois Basin counties the next highest, and

northern Appalachian counties the least when

compared with the other two. Measures of

poverty have historically been higher in coal

counties than in most noncoal counties. The

more dependent a county has been on coal,

the higher its poverty index. In the 1920’s and

1930’s, this was the result of the industry’s lowwage policies and slumping demand. In the

1950’s and 1960’s, mineworker unemployment

and lack of economic diversification caused

poverty to increase. The 50-county coal region

had a 43-percent greater incidence of poverty

than the United States as a whole in 1970,

while family poverty was 53-percent higher

than the national average. 77 The comparatively strong showing of northern Appalachian

coal counties is due to their diversified economies — especially high-wage industries such

as iron and steel, chemicals, metal products,

glass, transportation, and electric power. By

contrast, much noncoal economic activity in

the IIlinois Basin is agricultural.

The range of social problems coinciding

with poverty places extra burdens on communities whose tax resources are already limited.

The 1970 census data show that much of the

Eastern coalfields entered the mid-1970’s

“boom” with few financial resources. Despite

the gains in mining wages, personal income in

the Appalachian region was below the national

7’ (continued)

coal miners. Many were unemployed miners, retired and

disabled miners, and widows of miners Some portion of

the coal field poor had nothing to do with the coal industry. Although miners’ pensions have improved since 1974

and Federal black lung benefits now pump dollars into

coal towns, there remains a thick slice of mining-related

residents who Iive on modest fixed incomes They are disadvantaged by coal-boom inflation. They do not contribute as much to local tax revenues on a per capita basis as

active miners Each coal fieid community must absorb

some of costs of providing services to this group. Even as

coal growth brings income gains to working miners, a

class of poor and lower income residents will remain.

They will be economically and psychologically disadvantaged by the coal-based advancement of their neighbors

“Calculated from County and City Data Book, 1972

(Washington, D C : U.S. Department of Commerce,

Bureau of the Census, 1973), tables 1 and 2 See vol. 11,

app. Xl 1.

average in 1975. From Kentucky’s low of 66

percent of the national average, with Virginia

(73 percent), Ohio (79 percent), Alabama (82

percent), and West Virginia (84 percent) in between.

Similarly, the 50 coal counties had nearly

one-fourth more than their share of persons

with less than a high school education. About

59 percent of persons 25 years and older

lacked a high school diploma. Northern Appalachian coal counties had the lowest incidence

of poverty and the lowest percentage of those

with less than a high school education. Central

Appalachian counties had the highest incidence of both.

One reflection of educational quality in Appalachia is provided by comparing regional

achievement test scores with National or State

rankings (see table 50). The widest discrepancies between county performance and National/State reading and math standards occur in

Central Appalachia, principally a coalfield

area. There, 69 percent of those counties reporting were below National/State standards

on reading achievement in 1976-77 and 94 percent were substandard on math. Students in

northern and southern Appalachia performed

better than National/State standards on

reading, but did less well in math.

Rapid population expansion from coal development will add to problems of educational

quality. In Raleigh County, W. Va., for example, even though a $20-million construction

program was begun in 1973, the county superintendent admits that “in four or five cases

we’ve had to put two teachers in one classroom with 50 kids. ” He anticipates “this sort of

thing . , . will probably occur more often in the

future.” In Greene County, Pa., local school officials feel that school construction should be

postponed until after the population expands,

with portable classrooms used in the interim.

When a large number of young, married coal

miners settles near new coal mines, local

school systems will face front-end financing

problems in building facilities. Educational

quality will be adversely affected by overcrowding, inadequate facilities, and teacher

shortages.
Ch. V/— Workplace and Community Implications ● 299

Table 50.—County Rankings on Achievement Tests, 1976-77

(3rd or 4th grades)

Reading Math

Percent of Percent of

Percent of counties at counties at Percent of

Appalachian or above Percent of or above counties

counties National/State counties below National/State below

Geographic region Reporting standard standard standard standard

Housing is crucial to expanding coal production. Coalfield housing is of low quality compared with national norms. More than 31 percent of the Central Appalachian housing units

surveyed in 1970 lacked plumbing facilities;

15.6 percent lacked them in the Illinois Basin;

and 8.6 percent in northern Appalachia. But

coalfield housing is more complicated than

plumbing inadequacies, although they are a

good index of housing quality. The most urgent

issue is supply. Every study of coal field housing finds the existing housing stock insufficient. It is not likely to expand fast enough to

house adequately additional mining-related

population. The current housing deficit is the

product of the coal slump of the 1950-70 period when few units were built. It is compounded today by a lack of adequate water

and sewage facilities, an absence of private

builders, a shortage of mortgage capital, an

unwillingness of coal field banks to make housing loans, and, most fundamentally, the unavailabiIity of land on which to build.

Water and sewage systems are expensive.

They do not exist in many Appalachian coal

towns. In Raleigh County, W. Va., only half the

population is served by public sewage facilities, The rest use septic tanks, package plants,

outhouses, or the nearest stream. The head of

the local chamber of commerce says a total

moratorium on new construction could be imposed by health agencies because of sewage

problems. One local health official says the

only thing preventing a typhoid epidemic from

striking some sewer less hollows is the acid

mine drainage that kills the bacteria in the

befouled creeks. A recent West Virginia State

health department study found that 70 percent

of the water from public suppIies in the county

was substandard. Raleigh County residents

complain of tapwater the color of orange pop.

In Mingo County, W. Va., primary sewage

treatment faciIities exist in only two communities. Drinking water for Williamson, the county

seat, comes from the Tug River, which the

county says is polluted by acid mine drainage,

preparation discharges, and diesel-oil runoff

from adjacent railroad yards. Williamson’s

treatment plant is old and overloaded. The city

is seeking State and Federal funds to replace it.

In Breathitt County, Ky., only Jackson, the

county seat, has sewage service. The pervasive

lack of water and sewage facilities makes

coal field housing development costly. It is

especially difficult when State and Federal

reguIations require such services.

In many coal counties, most of the land is

owned by a handfuI of corporations, which are

reluctant to sell, preferring to hold the land for

future development. The underlying coal

makes the land worth considerably more than

sale for housing would justify, especially when

taxes are low. One study found that in the 14

major coal-producing counties in West Virginia, the top 25 landowners — all of whom are

connected to the coal industry —owned as

much as 2.1 million acres of land, or nearly 44

percent of all of the land in these counties.78

The top 10 landowners who owned 31 percent

Jj Davltt McAteer, Coal Mine Health and Safety The

Case of West Virginia (New York Praeger, 1973), p 163.
300 The Direct Use of Coa/

of the land in West Virginia, were, by rank:

Pocahontas Land Corporation (a wholly owned

subsidiary of the N&W Railroad), Consolidation Coal, the Chessie System, Georgia-Pacific

Corporation, Eastern Associated Coal Corporation, Island Creek Coal Company, Bethlehem

Steel, Charleston National Bank, Berwind Corporation, and Union Carbide. Nine of the top

10 Iandowners in these 14 counties had headquarters outside of West Virginia. 79 This study

reported that the top 25 landowners had their

property assessed at about one-fifth of the 14-

county total assessment. A second study in

West Virginia found that “two dozen out-ofState corporations and land companies–all

tied directly or indirectly to mineral industries — own a third of the State’s 12 million

privately held acres."80 This report found that

“in almost 50 percent of West Virginia counties, at least half the land is owned by out-ofState corporate interests . . . [that often pay] as

little as $2 per acre in annual property taxes. ”

The most recent study found that nearly 80

percent of the land in Mingo County, W. Va., is

owned by major corporations, most of which

were related to coal mining and natural resources. 82 The Appalachian Regional Commission has recently funded a major landownership survey to facilitate housing and economic

development.

Given the steep terrain and the flood-proneness of the valleys, flat land suitable for permanent housing is inherently limited. Mountainside housing is possible in many areas, but

development costs (for water, sewage, and

roads) are high. Individual homebuilders can

rarely afford to build there. Federal programs

have not adequately explored using this type

of land for coalfield housing. Although the

coal fields are rural, their population is congested along narrow creek bottoms. Without

additional land, the population density of

coalfield towns and hollows will continue to

increase or miners wilI be forced to commute

“ibid , pp 140-149

‘“Tom D. Miller, “Who Owns West Virginia?, ” Huntington, W Va , Huntington Hera/d-Dispatch, 1974, pp 2, 23.

a’ Ibid

“Study prepared by the staff of the Tug Valley Recovery Center and the Sandy New Era, published in the Sandy New Era, Feb 1, 1979

long distances; this, in turn, leads to absenteeism at work.

A few landholders have begun to make some

housing Iand available. The Beth-Elkhorn

Corp., a subsidiary of Bethlehem Steel, is

located in Jenkins, Ky. In 1976, Beth-Elkhorn

provided title in fee simple to 92 acres of land

on an abandoned strip mine bench for residential development to contain 48 single-family,

62-multifamily, and 33-clustered housing units.

Unfortunately, the development costs of using

surface-mined land make this apparently logical solution of limited feasibility in many

places. Island Creek announced an even bigger

housing development for southwestern Virginia. Another example is the Raleigh Countybased Coalfield Housing Corporation (CHC), a

joint industry-union effort begun in March

1977. CHC has 26 units under construction and

210 additional units scheduled. Land availability, financing, and lack of builders have been

its three major obstacles. The CHC model has

not been repeated elsewhere in the coal fields.

Recently West Virginia Governor John D.

Rockefeller IV initiated land condemnation

proceedings against the Philadelphia-based

Cotiga Land Co., which refused to sell land to

the State at what the Governor considered a

reasonable price for victims of the 1977 Tug

River flood.

Housing and land shortages force miners to

remodel old coal-camp houses or purchase

mobile homes instead of permanent residences. These are bunched in towns or strung

closely together along valley floors. Mobile

homes may shortchange local tax coffers, as

their owners use a full range of community

services but often pay personal rather than

real property taxes on their dwellings. Their

owners often complain about construction

quality, rapid deterioration, fire hazards, and

low resale value. Some of the newer and more

expensive models address these concerns.

Many residents believe that coal companies

prefer to have their workers housed in mobile

homes so that they can be moved out of the

way when a mine needs the land. On the other

hand, some coal executives believe one solution to wildcat strikes is to have miners buy

quality housing that comes with a long and
Ch. VI— Workplace and Community Implications ● 301

Photo credit: Douglas Yarrow

Flood damage in Wyoming County, W. Va., 1977
302 The Direct Use of Coa/

heavy mortgage. If significant production is

expected from the eastern fields after 1985,

land must be made available for single-family

housing, and a housing construction industry

must be created.

Coalfield underdevelopment is reflected in

the quantity and quality of other public services. For example, the Appalachian Regional

Commission funded an assessment of the impact of coal movement on Appalachian highways. 83 This study found that coal movement

by truck affected more than 14,300 miles of

Appalachian roadway in 1974. Of that total,

6,880 miles of coal-haul roads were inadequate

to meet the present volume of coal-truck traffic. Between 897 and 1,103 bridges were inadequate. The cost of maintenance was placed at

$66 million to $81 million annnually (1977 dollars), bridge replacement at $59I million to

$726 million, and roadway reconstruction and

rehabilitation at $4.1 to $4.9 bilIion.84 Only a

tiny fraction of these sums is now spent to

maintain, replace, and reconstruct coal-haul

roads. These numbers do not adequately convey the visible wreckage of the public road

system in many Appalachian coal counties.

Some portions have simply slid down a mountainside. Spillage and coal dust from overloaded trucks have caused problems for

motorists and landowners. Major secondary

lines must be traveled with a sharp eye for

axle-breaking potholes. Taxpayers pay for the

constant upkeep on coal-haul roads while consumers pay repair bills for their vehicles. The

main cause of the problem — apart from the

initial shortcomings in construction and

upkeep — is the illegal overloading of coal

trucks. Numerous studies of this phenomena

have reached the same conclusion: coal trucks

regularly exceed legal axle weights, offenders

are rarely cited, and fines are so low as to be

no deterrent at all. State officials are reluctant

to tighten up on enforcement. Federal officials

are reluctant to use Federal law—which requires States to enforce Federal gross and axle

“

]Research Triangle Institute, An Assessment of the Effects of Coa/ Movement on the Highways in the Appalachian Region (Washington, D. C.: Appalachian Regional

Commission, November 1977)

841 bid , p. vi,

weights on interstate highways in their boundaries or suffer a cutoff of Federal highway aid.

Without strict enforcement of weight limits,

road repair money will have little long-term

value.

Coalfield health care is generally inadequate and extremely vulnerable to overloading

from rapid population growth. The Appalachian Regional Commission reports that most of

coalfield Appalachia is underserved by physicians, dentists, nurses, and hospital beds compared with the U.S. average. Many measures of

community health— infant mortality, fluoridated water, prenatal care, per capita public

health expenditures, immunizations, etc. – indicate that much of coalfield Appalachia falls

below national standards. Many of these same

problems were first brought to national attention in 1947 when the Department of the interior published a comprehensive survey of coalfield health, under the leadership of Administrator Joel T. Boone.85 Much improvement has

been recorded since the Boone report, but current data reveal many unmet needs. In 1950,

UMWA won an operator supported system of

medical insurance and health services providing near comprehensive benefits to UMWA

miners and their families. Hospitals and clinics

were built. Preventive medicine and group

practice were encouraged. The Fund brought

dozens of doctors and hundreds of other

health professionals into the coalfields. Today,

part of this system is floundering, and some of

the rest is uncertain. Severe health care curtailments have already been recorded at about

four dozen Funds-dependent clinics. The cutback in clinic services resulted from the Funds

ending first-dollar coverage for miners along

with replacing retainer payments to the clinics

with fee-for-service reimbursement. The West

Virginia University Department of Community

Medicine found that total doctor office visits

fell 31 percent since the imposition of copayments on physician care in the five clinics

surveyed. The financial condition of the clinics

worsened measurably. Where utilization fell,

receivables rose — by as much as 190 percent in

“ 5

A Medical Survey of the Bituminous Coal Industry

(Washington, D.C : U.S Department of the Interior, Coal

Mine Administration, 1947).
Ch. VI— Workplace and Community Implications . 303

Photo credit: Douglas Yarrow

Shopping center construction, Beckley, W. Va., 1977

one clinic. Operating deficits were recorded in

each quarter studied. Physician staffing declined by 42 percent from July 1977 through

September 1978. Nonphysician staff declined

by 25 percent. Special preventive health programs have been eliminated. Facilities and

equipment are not being adequately maintained. Pharmacy and medical supply inventories have plummeted .8’

The Funds population had a higher-thannormal hospitalization rate, which may be related to the shortage of ambulatory physican

care. Some operators and physicians interpret

8

’William Kissick and American Health Management

and Consulting Corp , “West Virginla Primary Care Study

Group Problems of Reimbursement, ” Department of

Community Medicine, West Virglnla University, update,

November 1978 See also Virginia Gemmell and Jane

Ray, Physician Loss in Central Appalachian Coal field

Hospitals and Clinics, draft report by the Appalachian

Regional Commlsslon, 1978, and Charles Holland, et al ,

West Virglnla Primary Care Clinics, 1978

high hospitalization rates as being a reflection

of a kind of "cultural hypochondria” that

predisposes Appalachian miners and their

families to overuse medical facilities. Hospital

utilization will be encouraged by the physician

drain that began with the Funds cutbacks in

the summer of 1977 and by implementation of

the 1978 UMWA contract, which imposes coinsurance payments on physician care but not on

hospitalization.

Coalfield health care issues revolve around

questions of availability and quality. In most

coal counties —with certain prominent exceptions—there are too few quality doctors and

health care extenders, facilities, and prevention programs. Much of this shortage is due to

the remoteness and isolation of these counties,

and the lack of certain kinds of cultural and

recreational facilities for health professionals.

But these limitations were overcome by the

UMWA Fund in the 1950’s and do not present

an overwhelming obstacle to recruitment to-
304 ● The Direct Use of Coal

day. Federal and State programs designed to

encourage general physician care in rural areas

have had some success. But even where new

doctors with rural-practice specialization go

into coal towns, communities have trouble retaining them. Where significant expansion of

the coal population occurs rapidly, currently

overloaded treatment systems will function

even less adequately.

The system of group-practice clinics and

regional hospitals initiated by the UMWA Fund

may still serve as a model for coalfield health

care. The Fund recruited health personnel

carefully. Quality control on services was

maintained on non-Fund providers. Outpatient

and community outreach programs were emphasized. The entire system was supported by

an operator-paid tonnage royalty. When demand was steady or rising, the system worked

well. Only when demand felI steadily over a

period of years, did the Fund falter. If future

demand increases as most estimates predict, a

coal-supported health system of this kind may

again prove to be the most practical solution.

Six Case Studies

Six high-growth Eastern coal counties were

examined to determine their socioeconomic

problems related to coal development and to

assess their capacity to manage additional

mining (volume 11, appendix Xl l). Most Eastern

coal counties have had to cope with some

level of mining-related population growth even

though, in many cases, production did not increase at all. These six counties represent the

spectrum of capabilities and problems that exist in the Eastern fields.

The picture that emerges suggests that–to

various degrees — short-term coal expansion

has already overloaded Raleigh and Mingo

Counties, W. Va., and Breathitt County, Ky.

Greene County, Pa., Tuscaloosa County, Ala.,

and Perry County, I Il., have been less coaldependent historically and appear to be able

to manage increased coal production with little disorientation.

Although coal production has not increased

significantly in Raleigh County, its county seat,

Beckley, has been turned into a regional

growth center for southern West Virginia. The

price rise of metallurgical coal during the mid1970’s turned Beckley into a boomtown. The

city is trying desperately to manage a host of

housing, water, sewage, and transportation

problems. Although Raleigh has been a fairsized coal producer for decades, the fact that

Beckley has been turned into a center of regional commerce and finance has broadened

the county’s economic base. Yet prosperity

continues to be keyed to coal. Because of

Beckley’s regional importance, its resources

are greater than most coal field county seats.

Raleigh County is now, ironically, experiencing

a severe economic slump that came with slack

demand for local metallurgical coal. With little noncoal industry in the county, its economic fortunes rise and fall with demand for local

coal. Little attention appears to have been

given to economic diversification during the

short-1ived boom.

Mingo County, W. Va., has not expanded

production, although more miners have been

hired in the last 6 years. Some new mines have

opened, but others have cut back. A flood

swept through Williamson, the county seat, in

1977, devastating the community. The economy was slow to recover. A report to President

Carter in March 1978 found that:

It has been almost impossible to acquire

land to accommodate coal mining familie s

whose homes were ruined in early 1977 floods

or who are coming in for additional coal employment. The land not on steep slopes or on

flood plains is largely held by landowners unwilling to sell their land for housing, preferring

to hold it for speculation or resource development, 87

As nearly 80 percent of Mingo County’s land is

owned by nonlocal, coal-owning corporations,

tight land policies present major roadlocks to

efficent growth management. Many public

services — education, water, sewage, recreation, and health– are inadequate. More flooding has occurred since 1977. The viability of

the coal industry in the Tug River Basin rests

partly on better flood-prevention measures.

Breathitt County, Ky., experienced a 109-

percent increase in coal production between

1970 and 1976. Almost all of its output is sur87 Report to the President on Energy Impacts Assistance

(Washington, D C U S Department of Energy, Energy

Impact Assistance Steering Croup, March 1978), app. A ,

p 3
Ch. VI—— Workplace and Community Implications ● 305

faced mined. Mining accounts for 40 percent

of all public and private employment there.

Production is expected to increase by 50 to 75

percent by 1986. Breathitt County was one of

America’s poorest counties; coal growth is

welcomed by its residents. Still because of

earlier underdevelopment, Breathitt is experiencing adverse impacts. (Because the expansion is in surface mining, the population impacts are expected to be less severe than if significant underground production were scheduled.) Breathitt County lacks many services. It

has no hospital. Sewage treatment is found

only in the county seat, No public transportation system exists. The County has a comparatively high tax rate, but its base is very small.

Unmined coal was assessed at only $11.3 million in 1976, or about $0.025 per ton of recoverable coal (441 miIIion tons). The State has increased assessments in recent years, but revenue is unlikely to cover needed services.

Greene County, Pa., is a deep-mining, coal

county where almost 25,000 coal-related additional persons are estimated to be living by

1996— a number equal to the county’s current

population. A Westinghouse study of Greene

County projects a total population increase of

118,300 by 1996.88 The county is not well prepared to handle the impacts of massive and

rapid growth.

In contrast, Perry County, Ill., and Tuscaloosa County, Ala., appear generally to be able

to benefit from anticipated expansion, Both

counties have diversified coal economies, with

mining representing 1 percent of Tuscaloosa’s

employment and 17 percent of Perry ’s. The

rate of coal expansion and its extent are more

modest than those in Greene or Breathitt

Counties, which enable growth to be managed

more effectively. Individual communities in

each county may be seriously affected by the

opening of a mine, but this appears to be little

cause for concern countywide.

Any rendition of the historical impacts of

mining on Appalachia obscures the benefits

that coal has brought and the region’s growth

potential. Several factors will work to facilitate eastern growth. First, there exists a tradition and orientation among the population

toward coal mining. Miners tend to be the

children of miners. The lore of the work is

handed down from generation to generation.

The problems of the craft are understood by

wives and families. Local schools are geared

toward mining-related training programs.

Local colleges usually offer mine engineering

degrees. A second strong point is the production infrastructure that already exists. Despite

the problems of coal-haul roads and rail and

bargeline bottlenecks, a mine-to-market transportation system is in place. Further, there is

an adequate support system consisting of

equipment manufacturers, repair shops, and

supply retailers, who can respond to increased

mining. Local lawyers and brokers understand

the coal business. The operators know the lay

of the land both literally and figuratively. Coal

resources are well known. The components of

a production system are familiar. Problems of

expanded development are not new. What is

not greatly in evidence is the recognition that

the ability to expand coal production is linked

to the ability of mining communities to benefit

from that expansion.

Since the early 1970’s many eastern communities have experienced expanding mining popuIations and/or increased production. The seriousness of community impacts varies according to the variables discussed above. Most coal

counties are aware that coal impacts will increase, but few have begun to do the necessary

planning and resource accumulation that impact-management requires because of the dollar costs and time involved. To be effective,

planning must occur before coal impacts

begin. Existing Federal programs have not met

the planning and front-end financing needs of

coal-affected communities. Planning and resource management push communities to

evaluate their tax systems, revenues, servicedelivery systems, and likely sources of nonlocal assistance. As coal impacts have fallen

on coalfield governments, communities are becoming aware that local taxation systems are

inadequate. First, they rarely generate sufficient income to provide adequate public services. Second, they do not adequately tax the
306 The Direct Use of Coa/

community’s main assets: undeveloped mineral wealth and current coal production .89 I n

Mingo County, for example, coal and land

companies —which own almost 80 percent of

the land — had an aggregated property tax levy

in 1978 of $231,000 compared with $960,000

for private residents and local businesses. 90

Many coal counties assessed undeveloped

coal at only a penny or two per ton, and tax

revenues amounted to only a few dollars per

acre each year. Individual counties and States

have been reluctant to impose burdensome

coal-related taxes. They feared the increased

cost of local coal would disadvantage local

operators in the marketplace. Nevertheless,

many counties needing to raise substantial additional revenue are now eyeing local coal

resources. Coal companies are challenging

higher assessments in several counties. From a

national perspective, differential tax burdens

(from State to State) may create inefficient incentives for wise resource development.

Perhaps the most severe coal impact that

communities have been unable to resolve is

the issue of Iand availability and housing, Coal

operators have generally chosen to stay out of

the housing business and are reluctant to assist

private developers. The private housing market is inadequate to build middle-income housing. Most coal counties have had little experience in public housing. Multiunit townhouses

or high-rise developments do not fit the housing expectations of local residents. The stopgap solution of mobile homes is not likely to

produce community stability and growth or to

benefit the industry in terms of employee

morale and absenteeism,

The level of current and future costs and

benefits partly depends on the extent of existing underdevelopment. As plans are carried

out to increase Eastern coal production, community development strategies will be required to achieve a positive ratio of benefits to

89Some Eastern States such as West Virginia have undertaken a comprehensive reevaluation and assessment

program that promises to bring more coal-related tax

revenues to coal field governments. But West Virginia tax

officials admit that the higher valuations of undeveloped

coal property will not produce sufficient income to

finance the range of needed services

‘“See Sandy New Era, Feb. 1,1979.

costs. Strategies of this sort are likely to call

for economic diversification in coalfield communities, citizen participation, new land and

taxation policies, regulated growth, and fewer

cost externalizations. Strategies of this sort

may slow the rate of coal development initially, but advance the East’s ability to produce

coal over the long term.

Impacts on Western Communities

Introduction

Coal development is occurring in eight

States of the northern Creat Plains, the Rocky

Mountains, and the Southwest– North Dakota, Montana, Wyoming, Colorado, Utah, Texas,

New Mexico, and Arizona. (Limited development is also found in the State of Washington. )

Coal production in these States amounted to

some 166 mill ion tons, or nearly 24 percent of

the Nation’s coal output in 1977. By 1985,

some 630 million additional tons of annual

capacity may be available there. Currently,

about 17,000 miners are employed in Western

coal mining. Between 34,000 and 42,000 miners

will work in this region in 1985. Coal mining is

only one cause of coal-related impacts in the

West. The construction and operation of coalcombustion facilities, such as coal-fired

powerplants and coal-gasification plants, also

affect isolated communities,

The West shares some characteristics with

the Appalachian coalfields, but significant differences stand out. Both regions export raw

materials, although the variety of Western re

sources extracted is far greater. Both regions

have depended on imported capital to develop

their resources. As the economic return to

communities where minerals are extracted is

often less than most other industrial activities,

both areas have experienced relatively limited

growth rates. Finally, each region has evolved

an identity and cohesiveness that come, in

part, from the collective perception of economic dependency or subservience to the rest

of the Nation.

The West is not a homogeneous region geographically or socially. Its coal-producin g

areas are characterized by widely scattered
Ch. VI— Workplace and Community Implications ● 307

towns, with typical populations of 5,000 persons or fewer. The counties are much larger in

area than counties in the East and exhibit a

varied topography. Much of the area is subject

to Federal jurisdiction. Roughly 44 percent of

the land area in the major Western coal States

is owned either by the U.S. Government or by

various Indian tribes .9’ Actual land control,

owing to Federal coal-leasing policy, is even

higher.

In contrast to the relative cultural homogeneity of the Appalachian coal region, the Western fields encompass a majority white population and three major cultural subgroups: lndians, Hispanic Americans, and members of

the Church of Jesus Christ of Latter Day Saints

(Mormons). Regionwide generalizations about

attitudes toward growth are risky given this

cultural mosaic. For historical and cultural

reasons, attitudes toward coal development by

minorities may differ from those of coal producers. The problems faced by Indian communities in managing coal-related development

and the governing structure of the reservation

system are unique. They are considered separately in this chapter.

Water is a prized commodity in the arid

West. The ability of communities and coal

operators to obtain sufficient water will shape

the extent of coal development. There is little

or no western water that is not already al located to existing water-rights holders, primarily

agricultural users. Obtaining water rights for

coal development may occur smoothly

through negotiated purchase. But in some

areas of high water demand, or where State

policies promote conservation of the agricultural sector, conflicts may develop between

private and public entities, In market competition for scarce water, energy developers will

almost always be able to offer higher prices

than agricultural and ranching interests.

Special protection for certain groups of water

consumers may be warranted in this regard.

Identification of Impacted Communities

With one exception, the distribution of new

production throughout the West will be relatively uniform. Six States–Colorado, Montana, New Mexico, North Dakota, Texas, and

Utah– are each expected to add 55 million to

61 million tons of new annual capacity be -

tween 1977 and 1987, according to estimates

presented by Coal Age. 92 (These estimates are

referred to as the “Keystone Case” throughout

the remainder of this discuss ion.) The exception is Wyoming, which Keystone estimates to

be able to produce more than 270 million additional tons annually by 1987. Campbell County, Wyo., alone is scheduled to have an annual

production capacity of nearly 203 million tons

per year over its 1976 level. Arizona and Washington are expected to have minor increases in

capacity of 3 million and 1 million tons per

year, respectively. Table 51 presents a countyby-county breakdown of estimated additional

western capacity by 1987, by both surface and

underground mining methods, developed from

the Keystone data.

These estimates are generally considered to

be optimistic. They are derived from a survey

of coal producers on projected new mines and

planned expansions of existing mines. Many of

the proposed mines have not begun to acquire

the necessary permits and approvals. Some capacity will never materialize because of unfavorable market conditions or unanticipated

problems.

In order to evaluate more accurately the

likely range of impacts on western communities, a low-production “case” (the OTA case)

was calculated by State and county. Likely

slippages in each State’s production, owing to

a slowdown in coal gasification efforts, reluctance to resume large-scale Federal coal leasing, and other factors were identified. (See

volume 11, appendix Xl 1 I for complete discussion of statistical methodology). Total new

miner requirements for both production estimates, along with the 1976 population estimate for each county, are presented in table

52.

Public Land Statistics, 1975 (Washington, D C. U S

Department of the Interior, Bureau of Land Management, 1976)

‘

zGeorge F Nielsen, “Keystone Forecasts 765 Million

Tons of New Capacity by 1987, ” Coal Age, February

1978, pp 113-114
308 The Direct Use of Coa/

Table 51 .–New Western Coal Production Capacity by County, 1977-86

(in millions of tons)

Keystone case OTA low-production case

State and county Surface Underground Total Surface Underground Total

Arizona

Navajo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Colorado

Montana

New Mexico

Colfax . . . . . . . . . . . . . . . . . . . . . . . . . .

McKinley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

San Juan . . . . . . . . . . . . . . . . . . . . . . . .

North Dakota

Texas

3.30 3.30 0.00 0.00

12.50

0.10

0.25

1.80

3.00

0.10

3.00

6.30

3.60

1.80

3.70

3.25

8.85

1.85

1.50

4.20

4.30

0.30

12,50

0.10

2.05

1.80

3.00

3.70

0.10

3.00

3.25

8.85

8.15

1.50

4.20

7.90

0.30

2.44

0.10

0.25

1.80

0.40

0.10

3.00

6.30

3.60

1.02

0.27

0.96

3.76

1.85

1.29

1.81

2.74

0.30

2.44

0.10

1.27

1.80

0.40

0.27

0.10

3.00

0.96

3.76

8.15

1.29

1,81

6.34

0.30

30.65 29.75 60.40 17,99 14.00 31.99

35.50 35.50 14.28 14.28

13.00 13.00

5.00 5.00

1.20 1.20 0.17 0.17

0.10 0.10 0.10 0.10

8.16 8.16 4.09 4.09

62.96 62.96 18.64 18.64

0.50 1.50 2.00 0.50 0.50

20.70 20.70 11.13 11.13

37.70 37.70 15.37 15.37

58.90 1.50 60.40 27.00 27.00

0.60 0.60 0.60 0.60

14.00 14.00 4.07 4.07

1.50 1.50 0.44 0.44

22.00 22.00 11.34 11.34

11.80 4.00 15.80 5.63 2.00 7,63

2.60 2.60 2.60 2.60

0.46 0.46 0.32 0.32

52.96 4.00 56.96 25.00 2.00 27.00

6.00 6.00 2.98 2.98

2.50 2.50

0.60 0.60 0.60 0.60

4.00 4.00 0.18 0.18

8.80 8.80

0.18 0.18 0.18 0.18

9.60 9.60 3.57 3.57
Ch. VI— Workplace and Community Implications ● 309

Table 51 .–New Western Coal Production Capacity by County, 1977=86 (continued)

(in millions of tons)

Keystone case OTA low-production case

State and county Surface Underground Total Surface Underground Total

Panoca . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.00 16.00 11.98 11.98

Robertson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.00 6.00 1.98 1.98

Titus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.60 4,60 4.60 4.60

58.28 58.28 26.07 26.07

Utah

10.20 10.20 7.00 7.00

4.00 15.00 19.00 2.19 8.86 11,05

11.00 6.00 17.00 6.03 6.03

8.25 8.25 4.33 4.33

1.00 1.00 0.77 .77

16.00 39.45 55.45 8.99 19.99 29.18

Washington

1,00 1.00 2.00 2.00

Wyoming

202.50

17.10

13.00

1,00

7.60

7,00

10.25

3.00

7,90

202.50

25.00

13,00

1.00

7.60

7.00

11.20

3.00

112.73

6.80

3.43

0.78

5.69

6.04

7.89

2.63

112.73

6.80

3.43

0.78

5.69

6.04

8.84

2.63

0.95 0.95

Table 52.–Additional Manpower Requirements for Western Coal Development, 1977-86

(Keystone case and OTA low case)

Annual population growth

Manpower Requirements rate, ”/0/year

1976est Keystone OTA Keystone OTA

State and county pop. case Iowcase case Iowcase

Arizona

Navajo . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61,200 184 0 0.18 0.00

Colorado

19,100

8,800

16,200

65,400

8,900

9,600

5,300

10,200

624

1,068

1,217

3,051

576

544

762

987

353

78

360

1,297

576

413

1.81

5.62

3.79

2.50

3.34

2.97

6.42

4.68

1.06

0.52

1.26

1.11

3.34

2.32

3.21

3.80

328

769
310 The Direct Use of Coa/

Table 52.–Additional Manpower Requirements for Western Coal Development, 1977-86 (continued)

(Keystone case and OTA low case)

Annual population growth

Manpower Requirements rate, ‘/o/year

1976 est. Keystone OTA Keystone OTA

State and county pop. case low case case low case

10,600

2,383

2,700

9,900

1,804 727

661 0

333 0

538 270

7.29

10.30

5.70

2.86

3.51

0.00

0.00

1.53

1.61

0.82

0.47

0.21

1.04

2.57

5.95

1.95

0.58

0.20

0.06

0.00

0.69

2.28

0.54

0.97

5.93

13.43

5.48

5.60

0.16

9.29

1.23

1.36

1.86

0.88

0.83

—

3,336 997

13,300

56,000

67,700

430 383

1,478 794

1,336 545

1.79

1,48

1.13

3,244 1,722

4,200

4,800

11,800

6,700

2,400

15 15

300 87

1,100 567

1,764 874

85 85

0.21

3.24

4.54

9.94

1.95

3,264 1,628

19,800

12,100

12,200

30,600

19,900

16,400

14,300

18,000

396

40

264

582

634

926

396

304

197

40

12

1.14

0.20

1.23

1.09

1.76

2.96

1.55

0.97

236

692

131

304

3,542 1,612

19,100

7,600

3,400

12,400

3,617 2,482

5,437 3,200

2,796 399

2,855 1,498

7.89

18.13

19.49

9.06

14,705 7,579

48,900 66 132 0.08

14,500

17,200

9,400

10,500

21,100

31,300

6,237 3,459

1,410 372

858 226

473 355

371 321

522 448

13.61

4.08

4.46

2.42

1.01

0.96

9,871 5,181

47,041 23,025
Ch. VI— Workplace and Community Implications . 31 I

The real population growth associated with

coal development encompasses not only the

miners themselves, but their spouses and

children. Secondary employment is also generated. An average family size of three for both

primary and secondary workers, coupled with

an assumption of one local service job per primary job, yields an estimate of five additional

persons per mining job. Projected annual

growth rate in total population for each of the

affected counties is presented in table 44

Some officials on the scene in Western States

say the available estimates of county population severely understate reality. Where this is

true, it hinders their efforts to secure outside

aid based on population. It also would have

the effect of lowering estimated growth rates

(because the base population is higher than the

number used in these calculations).

Population growth that exceeds a rate of 5

to 10 percent annually is considered to generate significant socioeconomic consequences.

Table 52 shows that 11 counties in the West

will achieve growth rates exceeding 5 percent

per year in the Keystone case. Four of these

counties will have growth rates exceeding 10

percent per year over the 10-year period. (Highgrowth county data are in bold face. ) Under

the Keystone assumptions, the Utah counties

of Emery and Kane, where underground mines

are planned, are the most impacted, with

growth rates of 18 and 19 percent, respectively. Coal development in Campbell County,

Wyo., yields a population growth rate of nearly 14 percent per year. (It is assumed that

population impacts of coal development are

felt only in the county in which development

occurs. When miners do not reside in the county where they work, this assumption needs adjustment.)

When the OTA low-production case is used,

only six western counties appear to be vuInerable to rapid growth. Four of these counties —

Carbon, Emery, Kane, and Sevier– are in Utah.

The others—Campbell and Mercer —are in

Wyoming and North Dakota respectively. The

OTA case removes both Colorado counties

and the three Montana counties from the

highly vulnerable list.

The list of vulnerable counties grows slightly

if the time frame shifts from 1977-86 to

1977-81. With Keystone’s assumptions, three

more Colorado counties— Moffat, Pitkin, and

Routt — are now experiencing rapid population

growth. The shorter time frame does not add

counties to the OTA estimates.

Two other factors should be considered.

Mine construction workers appear 2 to 5 years

earlier than the mine-operating work force.

Construction crews are about the same size as

mine-operating crews, so actual popuIation effects are moved ahead in time but not increased in magnitude. Second, some utilities

have located mine-mouth powerplants near

coal mines. Powerplant construction crews are

from 5 to 10 times larger than operating crews.

Some communities have had trouble adjusting

to the short-term impacts of these crews, (e. g.,

Rock Springs, Colstrip, Huntington, Craig, and

Gillette) and if coal development continues, so

will many of their problems. Only eight counties will experience both new coal production

and operational powerplants after 1981 (table

53), according to these forecasts. When individual plant situations are investigated,

these eight can be pruned because of timephased unit construction (which maintains a

semipermanent construction work force in a

general area) and time lags between startup

and operation. Mercer County, N. Oak., and

Emery County, Utah, have already been identified in both cases as high-growth areas. The

powerplant construction variable adds several

Texas counties to the list of impacted communities. However, since all of these Texas

counties have relatively high populations

(ranging from 12,000 to 30,000) and are within

100 miles of Dallas or Houston, local population growth will probably be spread out and

absorbed without great clifficulty.

In sum, this analysis shows that from 6 to 11

western counties will show rapid population

growth from coal development in 1977-86. The

population effects will stem from coal mine

construction and operation rather than from

powerplant development. I n both the Keystone

and OTA cases, four counties in Utah are identified. Mercer County, N. Dak., and Campbell
312 ● The Direct Use of Coa/

Table 53.—Western Counties With Both New Coal

Production and Powerplants to Come Online After

1981

State County Online date

North Dakota . . . . . . . . . Mercer

Texas . . . . . . . . . . . . . . . . . . . . Freestone

Grimes

Henderson

Morris

Robertson

Titus

Utah . . . . . . . . . . . . . . . . . . . . . . . Emery

1981, 1984

1983, 1984

1982

1982

1980, 1982

1984, 1985

1982

1978, 1980, 1983,

1985

County, Wyo., are also singled out in bot h

cases. Most of these counties have small populations, the range being between 2,383 on the

Crow Reservation to 19,100 in Carbon County,

Utah. The four Utah counties and Campbell

County, Wyo., will experience the fastest rates

of growth. Several dozen western towns are

also Iikely to grow rapidly from coal development even though their respective counties do

not appear in the high-growth Iists.

Boomtown Effects

How any particular community is affected

by rapid coal development depends on the size

of the mining enterprise, mining method, size

and quality of existing public and private inf restructures, rapidity of development, tax

structure, and ratio of transient to permanent

employees among other variables. The duration of coal impacts is likely to run for 10 to 30

years at one or another level of intensity.

Coal impacts can be grouped according to

broad subject classifications (economic, political, and social). Both public and private sectors are affected. But it is impossible for two

reasons to calculate a definitive, cost-benefit

bottom line. First, all of the costs and benefits

are not translatable into dollars. Second, costs

and benefits are distributed unevenly among

private-sector groups (workers, owners, and

others) and public-sector interests (local communities, national energy needs, etc. ) Therefore, although policy makers can become

aware of the implications of various coal policies, there is no neat formula for weighing one

kind of cost against another kind of benefit.

The ensuing discussion talks about the costs

and benefits of Western coal production, but

does not make generalizations about when

costs equal benefits, when costs exceed benefits, and when they are less.

Private Sector: Costs and Benefits

It is possible to make very rough calculations of some of the private-sector, economic

impacts of projected coal development.

Annual coal-related wage income and benefits are the principal economic gain from Western coal development in local communities.

Assuming that each new miner will earn

$25,000 annually ($100 per day times 250 work

days), the 34,000 to 42,000 additional miners in

1985 will earn between $850 million and $1 billion per year in pretax income. To this must be

added the wages paid to workers involved in

secondary coal employment.

Coal development does not bring large inputs of local capital investment or large profit

returns to coal areas, Almost all of the major

mines in the West are being opened by nonlocal investors, usually utilities, energy companies, or conglomerates. Apart from costs of

acquiring the minable coal resources, the major capital expense involved in opening a new

mine is equipment, almost all of which comes

from nonlocal manufacturers. Once a mine is

operating, net income is either reinvested or

distributed as profits to stockholders. Little of

the mine’s economic surplus can be used by

local banks or local entrepreneurs and residents. The surplus that is likely to remain in

local communities is hard to quantify, but is

likely to be insignificant in most cases. However, where a mine-mouth generating plant is

part of the coal development, the local return

increases even though the profit distribution

pattern is not likely to change.

Coal development will affect existing business sectors in western communities. Many

will be able to expand their sales and profits.

But for some it will be a mixed blessing, and

for others no blessing at all. Noncoal wage income does not rise as quickly as miners’ wage

rates. Local businesses will have difficulty retaining current employees and recruiting new
Ch. V/— Workplace and Community Implications 313

ones, Secondly, local entrepreneurs may want

to expand their business, but local loan capital

may be tight. There is also the prospect of increased competition from new business started

by local or, more likely, out-of-State entrepreneurs or national chains. Some local business

may be wiped out.

In the past, the short-term costs of rapid

coal development to the private sector have

been high. The experience of Rock Springs,

Wyo., is a dramatic example. When coal development increased the population of Rock

Springs rapidly, its quality of life deteriorated.

9J The preboom ratio of two service jobs

to every one primary job declined leaving local

business without sufficient personnel to maintain services. Workforce turnover was high.

Mining and construction caused inflation,

bringing financial hardships to noncoal employees and residents on fixed incomes. After

the initial disruption the ratio of local service

jobs to primary jobs tended to normalize as

they did in Gillette. Coal-induced inflation frequently pinches the wallets of noncoal employees and fixed-income residents. 94 High

turnover rates among both coal and noncoal

workers is often seen. People leave the community, although a net increase may be registered in the census. Much social stress occurs.

In the Rock Springs case, the costs of boomIike coal development to many new miners

and noncoal local residents may have outweighed the benefits.

The most significant private-sector problem

in boomtowns is housing. UsualIy, there are

few local builders capable of undertaking

large developments. Often local banks cannot

finance major housing projects. Many small

banks are reluctant to tie up their capital in

“John S. Gilmore and Mary K Duff, Boom Tow n

Growth Management: Rock Springs-Green River, Wyo.-

ming (Boulder Westvlew Press, 1975)

“4 Interviews with bankers in northwestern Colorado

found that fixed-income residents were borrowing to

meet Increased Iiving costs by using the appreciating

value of their homes as CO I lateral Such short-term loans

are rolled over each year to repay previous loans and obtain additional money for rising living expenses This pattern, the bankers predicted, will certainly end in economic disaster for some of those Involved Don Kash, Mike

Devlne, and Allyn Borsz, Impacts on Western Coa/-Producing Communities, OTA contractor report, April 1978

housing loans, as higher interest rates can be

charged on personal and consumer loans. Consequently, housing costs skyrocket. In western

boomtowns the average $50,000 price of a new

home is about 30 percent higher than the national average for nonmetropolitan areas.

Apartment rents are nearly double the median

national figure of $120 per month. With the

housing supply inadequate and costly, new

residents are forced into mobile homes. Little

property tax revenue is generated by these

units in some States because they are bought

and owned as personal rather than real property. State legislatures can remedy this. The

shortage and high price of housing are also

caused by the natural reluctance of local

builders to risk major investment on the basis

of promised coal expansion; the West has seen

its share of booms burst.

The uncertainty of demand for western

boomtown housing is a major part of the housing supply problem. Lenders, housing developers, and builders are reluctant to rely on the

announced schedules for new energy projects.

They fear being stuck with unsold homes if

projects are delayed or canceled. The private,

primary mortgage market is composed principally of savings and loan associations and the

secondary mortgage market is insurance companies and other investors. These capital

lenders may be unwilling to back investments

that are not in low-risk categories.

The reluctance of local lenders is attributable partly to the funds available. Local

financial markets in the West are unable to accommodate the demand for new mortgages in

rapidly growing smalI communities. Outside financing is constrained by the absence of financial relationships with out-of-State institutions

and the inability of local financial institutions

to accumulate large enough blocks of mortgages to sell in secondary mortgage markets.

These shortcomings of the mortgage market in

the rural West may become a greater problem

in the future. Fm HA recently announced guidelines for providing assistance to energy-impacted areas where energy employment increases 8 percent or more in a year, a housing

shortage exists and local and State financial

resources are inadequate. Only $20 million is

available under this program which applies to
both coal and uranium production, processing,

and transportation.

The potential demand for new homes is

somewhat more certain in larger towns, such

as Gillette and Farmington, where large numbers of energy executives or administrative

personnel live. However, even in these larger

towns the temporary nature of powerplant

construction and uncertainty about future

energy development result in a fear of overbuilding. This is particularly true of towns that

have had previous booms collapse.

Several coal developers have provided housing for construction worker and mineworker

families. Much of this has been planned

mobile-home developments. Arco is building a

planned town (Wright, W. Va. ) primarily for

employees of its Black Thunder MineWright’s

single-family housing is expensive — in the

$50,000-and-up range— and most miners seem

to be opting for the cheaper, more readily

available mobile home. By living closer to the

mine than they would have in Gillette, the only

town in Campbell County, workers will commute shorter distances. Wright will cost ARCO

about $18 milIion.

The company-town approach is one alternative to chronic housing shortages. But the cost

of building and operating such towns discourages most companies from trying it. More common is a catch-as-catch-can approach to housing, Coal developers will offer some assistance

to towns or to their employees, but principal

responsibility is left to local authorities and individuals. Several examples illustrate the

mixed record of western towns in coping with

housing needs.

In Emery County, Utah, housing is desperately needed. One cause of the shortage is a

deficient public infrastructure, Without water

and sewer hookups, housing of any kind can-
Ch. V/—Workplace and Community Implications ● 315

not be built. Another problem has been Emery

County’s lack of licensed contractors. Inflated

costs, housing shortage, and the limited supply

of contractors has significantly changed the

composition of the housing inventory. In 1977

mobile homes were 41 percent of Emery County’s housing supply. In Huntington, where in

1970 there were only two mobile homes, 375

were counted in 1976. The Southeastern Utah

Association of Governments sees mobile

homes as the only housing choice available to

new households. A somewhat different pattern

is found in Gillette, Wyo., where there were no

large-scale builders or developers before the

coal boom. Market uncertainties and the

possibility of environmental litigation over

Federal coal leasing presented an unattractive

level of risk for large-scale land developers and

creditors. These initial problems have been

alleviated. Many developers now see a singlefamily housing market in Gillette. The risks involved in large subdivisions have been largely

absorbed by the coal companies. In some instances, the companies have acted as land developers; in others they have either guaranteed

the sale of lots and/or houses or guaranteed

the credit of a housing subdivider. Yet singlefamily housing production has not increased

substantially. The primary barriers are the

delays and high costs of producing new units

of acceptable quality and the relationship between the cost of producing the types of dwellings desired by the newcomers and their abiIity

to pay for the desired units. ’s Many residents

are forced to Iive in mobiIe homes, which have

become the fastest-growing housing alternative in Campbell County. Sixty percent of

the increase in housing since 1970 has been in

mobile homes. Currently 67 percent of the

housing in the county outside the Gillette city

Iimits is mobile homes.9

’

951n a recent Wyoming survey, 67 percent of the respondents preferred a single-famiIy unit and 56 percent

Indicated both the willingness and ability to purchase

one, but only 45 percent had achieved the goal of owning

a single-famiIy unlt (DaIe Pernula, 1977 Citizen Policy

Survey (GlltetteCampbell County Department of PIannlng and Development, 1977) )

“Keith D Moore and Carrie Loom Is, Housing Market

Dynamics in Campbell County, Wyoming and the Impacts of the Proposed Mobi/-Consol Pronghorn Mine, a

Denver Research Institute report prepared for the U S

Geological Survey, 1977

Housing on Indian reservations raises several problems that are different from those discussed above. A boomtown syndrome probably won’t occur on most reservations, although

the social stress created may be similar. The

number of new miners that will be involved in

Indian coal production will not be more than

several thousand. Most of these will be Indians

already living on reservation land if the tribes

succeed in making the coal companies give hiring preference to local Indians. The housing

problem on the reservations is less one of

shortage and more one of adequacy. The serious deficiencies in Indian housing are wellknown –to Indians, at least. Table 54 presents

a snapshot summary of Indian housing quality— including the Navajo Reservation — where

housing needs are most severe,

I n sum, the distribution of private costs and

benefits of increasing Western coal production

vary. Coal workers and mineowners will obviously benefit from new employment opportunities. Coal-related services will establish

themselves in regional centers, and locally

owned commercial enterprise may expand.

Spendable income in local communities will

increase rapidly. The material quality of life

will rise for some.

On the other hand, these private benefits are

not distributed evenly. Local capital liquidity

is unlikely to increase significantly, apart from

the savings deposited by wage earners. Local

businessmen may not be able to expand or

modernize their services, and national chains

may take over their markets. Opportunity

costs may be high in Western coal development. Ranching, farming, and tourism may be

curtailed in coal areas. Local inflation penalizes those on fixed incomes and those whose

wages are independent of the coal business.

Data are not available comparing boomtown

inflation rates with national or regional rates,

although anecdotal evidence suggests that the

former is abnormally high. Coal profits will not

generally be distributed locally. Much investment will not be spent locally, either.

One important and relatively unexplored

issue is the dolIar cost of impact internaliza-
316 ● The Direct Use of Coal

Table 54.—Housing Conditions of Indians in

Three Western Regional BIA Areas—1973

BIA area office

Billingsa Navajo Albuquerque

Total number of

families . . . . . . . . . . . . . . . . 6,071 23,801 8,349

Number of standard

units . . . . . . . . . . . . . . . . . . . . . 3,335 3,126 3,180

Number of

substandard units 2,269 19,242 2,841

Families doubled up 467 1,433 2,328

Total need as

percent of families 45.1 86.9 61.9

New units needed . . . . 1,861 7,324 3,332

Rehabilitations

needed . . . . . . . . . . . . . . . . . 875 13,351 1,837

tions on the dollar cost of producing Western

coal. Coal companies in the West generally offer extremely high wages to attract labor. To

the degree that rapid coal expansion decreases

quality of life, operators may be forced either

to offer increased monetary incentives to retain workers or to become directly involved in

the costly business of providing community

services. 97 If coal operators absorb the capital

costs of, for example, a water and sewage system, their product prices will rise. It is debatable whether price-escalator provisions in utility contracts can be invoked. If the labor force

perceives coal development as the source of

quality-of-life decline, workers may seek

unionization and even higher monetary rewards or community development clauses in

collective bargaining. State and local governments may impose taxes on coal developers to

finance needed services. To the degree that

coal-related public costs are paid by tax revenues on Western coal, higher coal taxes may

lower company profits and raise coal prices.

Western communities have had much experience coping with the short-term stresses created by booms and the long-term depressions

left by the “busts.” From today’s perspective,

it appears that Western coal growth, based as

97 Richard Nehring and Benjamin Zycher, Coa/ Deve/-

oprnent and Governrnent Regulation in the Northern

Great Plains (Santa Monica, Cal if RAND Corp , 1976), p

127

it is on long-term utility contracts, wilI smooth

out the boom-bust cycle. However, it is likely

that a considerable lag will occur in the

perceptions of local residents as they weigh

this boom against those of the past. Their caution is justifiable because economic diversification and planning for the postcoal years

are not occurring. A long boom followed by an

even longer bust may be in store. In any case,

boom growth is the least preferable path of

economic development. Slower and more

steady growth is less disruptive and more beneficial to more people over a longer period of

time. However, because coal projects are usually matters of corporate decision making,

many western communities may have no

choice. If this perception is shared by westerners it would not be surprising to observe a

political backlash against current coal development by citizens who see their long-term interests depreciated by rapid coal developments.

Public Infrastructures: Costs and Benefits

The balance between public costs and benefits of Western coal development changes over

time. In the 5 years needed for a mine to be

developed, public services in small communities will be strained by the rapid increase in

population. Demand for more and better services will usualIy exceed a community’s tax

revenue and ability to deliver services. Where

county or State tax revenue increases but

heavily impacted towns can’t get a fair share,

the financial situation is aggravated. Antitax

feeling, expressed in Proposition 13-type movements, further binds local governments.

Coal development also strains local physical

infrastructures — roads and bridges, water supplies and purification plants, sewage facilities,

schools, and fire and police protection. Existing service systems are likely to be severely

stretched and weakened. Individual pieces of

these systems may collapse entirely. Shortterm public costs may also be expressed in

terms of community destabilization, cultural

strain, social disorganization, and a general

perception of decline in the quality of life.

As the mine reaches full capacity some public costs will become less serious. Tax revenue
Ch. VI— Workplace and Community Implications ● 317

wiII generalIy increase; services shouId expand.

The pace of growth will slow. The rate at which

any given community begins to normalize demand for services with its ability to deliver

them depends on a number of local factors.

The most important of these are: the degree of

predevelopment need, tax policy, rate of

development, priorities and attitudes of the

coal producer, reliability of demand for local

coal, skilI of local officials, extent of economic

diversification, and ability of State and county

governments to adapt their policies to meet

the needs of localities. In some communities

front-end problems, such as lack of revenue,

may extend for years. The deficit may never be

eliminated with available resources. These

problems will be solved in some communities,

to be sure, but western history shows a spectrum of success and failure concerning the

ability of communities to assemble public

capital and meet boomtown needs.

Western mineral development also starkly

portrays the common “back-end” problem of

resource depletion and community decay.

When mines play out or market conditions

force closure, local communities are “busted.”

When communities were tied to a single company or industry in the past, back-end problems were often disastrous. Since western

mines have operational Iives of 20 to 60 years,

planning and diversified development of Western coal areas may be needed to avoid the

worst public cost of earlier mineral development: ghost towns.

Most impacted western communities are

now struggling to cope with the front-end problems of coal development. Such communities

face the necessity of either expanding existing

public services or building them from scratch.

In either case, a period of 2 to 5 years exists

before those services appear. Most western

communities do not have adequate funds in

the early stages of coal development to plan

their growth and seek Federal assistance.

Where coal-processing or electric-generating

plants are being constructed, front-end financial problems are magnified by the overnight

appearance of the temporary plant-construction crew. State-administered severance-tax income does not return to local communities on

a dollar-for-dollar basis and does not begin at

all until coal is actually sold.

Aside from education, public services that

usually need expansion in boomtowns include

fire and police protection, roads, water and

sewage treatment, solid-waste collection and

disposal, health-care facilities and services,

detention facilities, county and municipal

facilities, and recreation. For each new resident, between $1,500 to $2,300 (1975 dollars) is

estimated to be required for just the capital

costs of these facilities. Of this amount,

roughly 75 percent is devoted to water and

sewage treatment. A hypothetical town of

2,500 persons with an annual municipal budget

of $20,000 would require between $1.5 milIion

and $2.3 million capital investment if its population were to increase 40 percent (1 ,000 persons). Clearly, the front-end costs are huge in

comparison to local tax revenues and bonding

capacity.

Existing transportation facilities may be suddenly overloaded when coal mining grows fast.

Highways break down. Coal haulage disrupts

small towns. Unit trains bisect communities. A

recent Colorado Department of Highways

study,

98 estimated that more than $250 million

would be required for primary and secondary

highway construction by 1985. In six energyimpacted counties, more than four times the

annual level of construction for primary and

secondary highways in all 63 counties of Colorado, is needed. It has also been estimated

that at least 30 new grade separations are required to maintain intracommunity access in

communities suddenly beset by unit trains.

Current funding in Colorado provides for one

or two new grade separations per year for all

purposes.

Boomtown problems are aggravated where

the coal project creates revenues for one jurisdiction while the social impacts of the new

mine occur in another. jurisdictional mismatches are one of the most intractable problems. The most common mismatch occurs

when coal mines or powerplants are located

outside a town’s Iimits. The county collects the

tax dollars while the municipality struggles to

‘

8 Briefing to commissioners by staff of Colorado

Highway Dept
318 The Direct Use of Coa/

meet the needs of new miners. But the jurisdictional mismatches within a county are more

easily handled than those occurring across

county or State Iines. There are no examples of

where this inequity has been addressed except

through usually meager State impact assistance programs.

The evolving balance between public benefits and public costs depends largely on local

and State coal tax policies. The level and equity of public revenues depend on the mix of

taxes imposed, the level of each tax, and the

efficiency of the collection system. These matters often involve two or three levels of government and are always matters of political debate. Local authorities rarely impose a corporate income tax on local business. Property

tax usually generates most local revenue. This

burden often falls more heavily on residential

and agricultural property owners than on mineral-resource owners. Leasers of publicly

owned coal pay no property tax although they

pay a tax on leasehold value based on production. Some counties impose specific taxes on

coal. For example, most coal counties in Illinois have imposed a l-percent sales tax at the

mine mouth; local and county taxes in Montana average about 5 percent; Wyoming counties average about 6.3-percent ad valorem tax

based on production; counties in other Western States impose no coal-specific taxes. States

differ significantly in their coal taxation

schemes. These Western States impose coal

taxes: Wyoming (10.1 percent in 1978); North

Dakota (65 cents/ton with an inflation escalator); New Mexico (38 cents/ton steam coal and

18 cents/ton metallurgical coal); Montana (30

percent on the value of the coal at the mine

mouth); Colorado (30 cents/ton for deep-mined

coal and 60 cents/ton surface-mined coal) .99

Utah, South Dakota, Texas, and Oklahoma

have no coal taxes. Western States also use different formulas to redistribute State-collected

severance taxes to counties of origin. State and

local tax policies do not seem to be a criteria

for mine siting. Depending on the level of predevelopment need in each community, future

tax income may or may not be sufficient to

“Coal Week, Apr 17 and 24,1978

provide adequate public services following initial coal development.

The net public gain or loss from coal growth

also depends on how much system deficit is

present when development begins, the extent

of the overload, and the level of services perceived necessary to meet the perceived need.

Communities that are created from scratch

have extremely high startup costs and may

need subsidies for many years. But they may

be ultimately more successful in providing

services and achieving a net gain The more

common western pattern appears to be coalgrowth overloads of existing systems, which

may already be below par. I n such cases, arithmetic gains in population may require geometric increases and investments in services.

(For example, a 50-percent increase in population may require a doubling of the local

police budget.) The greater the existing deficit

and the greater the development impacts, it is

more probable that there will be a small net

public gain. Conversely, the smaller the existing service deficit and the smalIer the development impact, the more probable that public

benefits will be greater. The level of public

services differs from town to town. A few examples suggest the range of experience.

Craig, Colo., is a typical rural community on

Colorado’s western slope. Preboom services

provided by the community cost $208 per capita and were considered adequate by most residents. The 1979 estimated per capita expenditure is $344 (in constant 1973 dollars). With

coal development the water system was expanded to serve a population of 15,000 but is

almost at capacity with 11,000. The sewer system will be expanded to a 20,000-population

capacity. Craig was not able to finance these

capital projects totally with local revenue.

Most of the money came from Federal and

State sources, along with some industry contributions. The city has not yet resolved the issue

of how to pay for a new reservoir (estimated to

cost $10 mill ion).

The public infrastructure in Emery County,

Utah, communities was not ready to absorb

the coal-based growth that came. In some

cases, services were not even adequate for the
Ch. VI——— Workplace and Community Implications ● 319

existing population. Many of the small towns

in the county were not required by the State to

prepare annual budgets. Those that did often

had budgets only l-page long. Little planning

or forecasting of capital expenditures occurred. A 1978 report by the Southeastern Association of Utah Governments said that almost every town in the county needs a new

municipal building. Many need to upgrade

their water and sewer facilities; others need

sanitary IandfiII operations. Every town is in

need of a fire station and new equipment, and

many need a massive street improvement program. 00

Gillette, Wyo., had energy-related growth in

the oil and gas boom of the 1960’s and the coal

development of the 1970’s. Even with this

growth, the city’s tax base has fallen further

and further behind the county’s, Gillette has

not always had the capital needed to improve

its public services. I n the 1960’s GilIette’s

bonds were issued piecemeal, with no provision for long-range planning of financial strategies. The result was poor use of the city’s existing tax base in creating bonding capacity.

For a time, this severely limited what the city

could do. However, through the efforts of a

bond counsel and a new professional town

manager, these debts were largely refinanced

in 1977

101

Gillette and Campbell County have been

fortunate in receiving assistance from industry

in the form of in-kind contributions such as

loans of equipment to clean streets or help

with digging the foundation for the hospital.

The members of the industrial subcommittee

of the chamber of commerce have also contributed money that has been used for studies

and plans for long-term city projects. 102

Education

Public education is usually financed by

State and county governments, with special

100 Morrograph Series: Local Government (Price, Utah:

Southeastern Association of Utah Governments and Development District, 1978)

101 From 1976 and 1977 Interviews with Mike Enzl,

Mayor of Gillette and a 1977 Interview with Flip McConnaughey, City Manager

‘“’From 1978 Interview with Dave Bell, Director, GiIIette Chamber of Commerce

categories of assistance provided through Federal programs. The local school system’s ability to manage coal-generated enrolIment depends on the preboom use of existing facilities,

the rate of expansion and size of the new student population, and the financial ability of

the community to provide additional facilities

and services.

School costs are usually the largest portion

of local public expenditures. Per capita expenditures for education in the West are

already high. For example, the capital costs for

each additional student in Gillette, Wyo., are

projected to be approximately $2,500. An increase of 500 in the school population would

amount to $1.25 million more in capita I expenditures. Operating expenditures are about

$2,000 per student, so that 500 new students

would require an additional yearly operating

expenditure of $1 million. 103

The long-term financial demands for education in Western coal communities are substantial. Whether this situation poses serious financial problems will be determined by how soon

the school-age population begins to expand

rapidly. Where school-age populations do not

grow until coal facilities are operating, school

districts may have surplus revenue. An example of this favorable situation is found in Rosebud County, Mont., where school districts are

expected to enjoy substantial financial surplus

at current tax rates. However, this is the exception.

Typically, the increase in school enrollment

from coal-related work occurs before any increase in ad valorem tax receipts. This may

cause operating expenditures per pupil to

decrease. However, most States “guarantee”

that these expenditures wilI not falI below a set

amount fixed by the legislature. Therefore, the

operating portion of the budget is not the main

cause for concern; rather, it is capital expenditures. For example, if additional permanent

classrooms are to be built or temporary ones

purchased, the existing population pays, not

the newcomers or the coal companies. These

initial problems may be corrected if mines and
320 ● The Direct Use of Coal

powerplants are placed on the tax rolls and no

jurisdictional mismatches are involved.

In Moffat County, Colo., for example, school

enrollment increased 29 percent from 1976-78.

In the same period assessed property valuation

increased 144 percent. While these statistics

may suggest optimism, the fact is that the

county’s schools are overcrowded. Increases in

enrollment have put the total student body at

about 300 students over capacity. 1 n October

1978, a $9 million bond issue was finally

passed (after having failed twice) for construction of a new high school. I n addition to overcrowded conditions, the school district lost 35

teachers in the summer of 1978 for a variety of

reasons. A number went to work in higher paying coal projects. Although the positions were

filled, there were problems in attracting new

teachers, mainly owing to the high cost of living in Craig.

Much of the locally perceived impact on

education involves subjective judgments

about what constitutes good education.

“Quality” education is an intuitively meaningful concept to most parents, but it is hard to

quantify. Different communities may have different collective perceptions as to what “it” is

and whether their children are currently getting “it.” To the difficult question of educational quality must be added the question of

who pays for it. Long-time residents sometimes

object to higher property taxes and more indebtedness to pay for the education of the

children of “newcomers. ” Moreover, coal development pressures may inflame residents

over what is perceived as a lessening of educational quality. This may diminish over time as

new facilities are built. But the absence of

front-end monies and the high costs of permanent school facilities make the process of

resolving this problem difficult. Adaption to

boom conditions may take the form of increasing student-teacher ratios, shifting to half-day

sessions and installation of temporary school

trailers. This is likely to keep the issue of coal

and education alive indefinitely. Other problems may be perceived. New teachers will have

to be hired, and some, at least, may have nonlocal educational values and methods. The

education system may be perceived as becoming less personal and more bureaucratic, hence

less accountable. The destabilizing effects of

rapid economic growth may be played out in

school disruptions and student stress.

Boomtown educational needs have both a

quantitative and qualitative dimension. Quantitatively, the problem is finding capital and

personnel to sustain and expand existing facilities and programs. Qualitatively, the problem

is matching perceptions of preboom and postboom reality with the changing nature of local

education. The concern of the community

about the “quality” of their boomtime education will vary according to the precise mix of

short-term adaptation mechanisms and longer

term expansion of services that authorities are

able to orchestrate. Both newcomers and oldtimers may continue to be dissatisfied with

their educational system for different reasons.

Both groups may have legitimate grievances. It

may be unlikely that quantitative improvement in the local educational system will produce a one-for-one, stepped increase in the

community’s perception that education has

improved.

Health Care

Both the public and private sectors are involved in health care delivery and financing,

Coal development will enlarge the healthtreatment needs of local communities in various ways: more people need more care; more

people need a wider range of health care; coal

miners have special health needs.

Health services, which are often inadequate

in rural communities before development

starts, are among the most difficult to maintain in boomtowns. Medical needs typically expand at least as rapidly as population, and

faster when a large proportion of the new residents are young children. If health services are

limited, a smaller proportion of children may

be immunized against preventable diseases.

Fewer screening tests may occur. Inability to

obtain early treatment may permit disease to

become more serious.

The health care delivery system in western

communities is limited and, by national standards, less than adequate. One eight-State study
Ch. VI— Workplace and Community Implications ● 321

of 185 potentialIy impacted western towns

found that fewer than half (87) had a resident

doctor and about one-third (60) had a hospital. 104 Generally, the doctor/popuIation ratio is

much lower in western towns than in the country overall. Like other rural areas, the West has

difficulty attracting and holding physicians.

Apart from the availability of physicians and

health care extenders, health care norms depend on the quality of care provided and the

rate of use, both of which depend to a greater

or lesser part on the individual’s ability to pay.

It is easy to understand the frustration coal

miners and others feel when “good” health

care is unavailable even though adequate insurance plans cover them.

Recent survey research in Sweetwater County, Wyo,, sheds Iight on the importance of adequate health services. Fully 82 percent of the

157 newcomers interviewed ranked medical

and mental health services in their top five

community priorities. Sixty percent of the sample said they would leave town if these services were not improved. These opinions were

acted on: “The labor turnover rate was running

up to 150 percent as mining employees were

leaving the area because of dissatisfaction

with the quality of Iife. ” 105

IllIness-prevention systems are even less developed than treatment systems. Prevention

programs are provided by both the public and

private sectors. In small, rural communities,

public health services are minimal, where they

exist at al 1. Immunizations, water and sewage

treatment, prenatal and postnatal care, and

nutrition education are not well developed.

Adequate systems are even less likely to be

found on many Indian reservations. Much preventive care depends on an individual’s awareness of its importance and his ability to pay.

Absence of prevention measures often results

in higher treatment costs, some of which are

borne by public agencies. Generally, the

104Regional Profile: Energy-Impacted Cornmunities

(Lakewood, Colo Federal Energy Administration, Socioeconomic Program Data Collection Office, 1 977)

‘(’’John S Gllmore, et al , Analysis of Financing Problems in Coa/ and Oil Shale Boom Towns (Denver Colo

University of Denver Research Instltute and Bickert,,

Browne, Coddington & Assoc., Inc., 1976), p 72

public and private prevention systems in Western coal towns are haphazard and not well synchronized.

Coal miners have special health needs stemming from their occupation. Although western

surf ace mining is statistically safer and

healthier overall than underground mining,

surface miners stilI experience a significant

level of industrial injury and disease, Respiratory and pulmonary disease, hearing loss, and

stress are found more frequently in miners

than in the population generally, Coal’s accident rate requires adequate emergency medical services at the mines and fast transportation to treatment centers. Provision of emergency services— including the training of

miners as emergency medical technicians — is

not required under Federal law or by most

States. Some coal operators provide such training and service; others don’t. Specialists in

miners’ occupational health problems are not

found in the newer, Western coal development

areas. Some practice in the older coal fields of

Utah and Colorado, where UMWA and the

UMWA Fund established clinics after 1950.

Other health-related services are required in

stressful boom conditions, including treatment

and counseling for alcoholism, child abuse,

marital strain, juvenile delinquency, and mental health The rapid infusion of newcomers

into welI-established communities creates

stressful situations among natives and newcomers alike. The smaller the community, the

less likely that such services are available.

However, high absenteeism and turnover rates

in Western coal towns suggest that services are

needed to treat the symptoms and consequences of growth-related stress.

Political Impacts

The political impacts of Western coal development may be extensive, both from the perspective of boomtown residents and in terms

of the politics of further coal expansion.

Rapid population growth often generates

conflict between antigrowth and progrowth

factions, newcomers and oldtimers, labor and

management, environmentalists and prodevel-
322 ● The Direct Use of Coa/

opment factions, high-wage jobholders and

fixed-income or low-wage persons, transients

and permanents, and coal-related business and

local business. These conflicts may benefit

local communities in the long run if they mobilize political interest constructively and create pressure for better public services. Yet

more public services almost always involve

more Government regulation, which may itself

become a political issue. Political cleavages

resulting from coal development may shatter

community life. In company towns, coal developers may dominate local politics, for better

or worse. I n other places, two-party competition may result from the introduction of new

interest groups. One-party systems may be fictionalized. Tightly run political machines may

develop. The conflict that change produces

may interact with economic and social conditions to produce widespread community disintegration and dissatisfaction. But, on the

other hand, growth can create conditions

where political cooperation is required to meet

new demands.

Coal-impacted western communities vary

tremendously with respect to attitudes toward

politics and coal development, so that regional

generalizations are especially risky. Nonetheless, it is reasonable to assume that some communities will eventually group themselves into

two polarized alliances: progrowth and less

growth. As the rate and scope of development

increase, polarization is probably more likely

to occur and be irreconcilable. But exceptions

will be found. Some Mormons of Utah, for example, favor coal development without reservation. This prodevelopment view comes from

the desire for economic development and

from a set of socioreligious values arising from

the Mormon experience. —

Although procoal factions among Indians

and Mormons may favor procoal Federal policy, they may also oppose the Federal regulation that often accompanies such policies.

Western hostility toward Federal policy may

be intensified by the lack of applicability of

Federal aid to western boomtowns. Most relevant Federal programs make funds available to

States and local governments only to remedy

problems of economic stagnation or natural

disasters. These conditions do not exist in

Western coal communities. Hence, most Federal impact assistance funds are unavailable to

Western coal towns.

Western rural county governments are largely dominated by farmer/rancher interests.

County commissioners deal with few major

conflict-producing issues. Those they do handle usually concern the level and distribution

of taxes and public expenditures. Because of

the western populist tradition and the prevalent skepticism of government in general, rural

officials tend to be ambivalent toward land

use planning and zoning. Their ranching and

landowning constituents are strongly opposed

to any intervention in their control of their

property. 106

In Gillette, Wyo., it was not until 1976 that

the Gillette/Campbell County planning office

really became active when the need to handle

boom conditions became obvious. When planning and zoning codes were established, a 3-

by 5-mile box was drawn around Gillette. The

planning department’s control is much greater

within this area than in the rest of the county.

Outside the box, the planning commission can

only make recommendations to the county

commissioners, who need not (and do not

always) follow them. 1

07

Coal growth is apt to cause drastic changes

in existing political structures. Whether these

changes are seen as good or bad depends on

the observer’s point of view. Eventually, ranching interests may lose their role as the dominant political force in local politics. Newcomers may share power with older residents,

or they may supplant them entirely. Newcomers are likely to bring with them different

‘“’’’ Our findings reveal that a significant feature of the

study area is Its traditional rural abhorrence of planning

The area’s residents consistently and strongly resist the

Idea of telling people what they can and cannot do

with/on their land Almost 60 percent state that no one

but the owner should have any say about how privately

owned resources are used. ” Community Service Program, University of Montana, A Study of Social Impact of

Coa/ Development in the Decker-/Birney Ash/and Area

(Helena, Mont,: Montana Energy Advisory Council, Office of the Lieutenant Governor, 1975), p. 20

‘“’ Based on a 1978 interview with Dave Ebertz, former

part-time City Manager, Gillette
Ch. V/— Workplace and Community Implications ● 323

values and expectations that may be at odds

with those of the existing residents. Political

change in coal communities is driven by the influx of new residents. One study of southeastern Montana found that newcomers and oldtimers tend to stay apart. For the most part,

newcomers have not been accepted into established social structures.

Often, changes in boomtown political culture will not come easily. Conflicts may occur

between newcomers and oldtimers. There may

be more urban vs. rural strain, as well as an increase in industry vs. environment issues.

There may be more concern over and need for

Federal intervention as urbanization takes

place. Unions r-nay become more of an issue

and possibly a political force.

It is difficult to predict whether such

changes wilI be beneficial to the community in

the long run. Many preboom residents will not

favor them. Conflict may not be viewed favorably by either oldtimer or newcomer. Yet as

assimilation and adaptation occur, conflicts

may be resolved.

Social Impacts

In preboom western towns, informal social

controls shape community social structure. 08

Doors are rarely locked because everyone

knows everyone else. Family violence occurs

less often. Teenage drug usage may not be a

serious problem because of stable and familiar

social norms and the community’s isolation.

Alcoholism is considered more an individual

than a community problem. This kind of social

structure is vulnerable in boomtowns. Some of

the changes that occur are not beneficial.

High-growth communities often have increased crime and mental health problems.

juvenile delinquency grows. Divorce and family disruptions are more common.

‘

O

’ Sociologist William Freudenberg has concluded

that the primary reason for stablllty in small communities IS because there IS a kind of “social buffering” at a

very localized small group/primary acquaintance level,

which provides a source of continuity for feellngs of personal worth and social Integration Wllllam Freudenberg,

The Social Impact of Energy Boom Development on Rural

Communities: A Review of the Literature and Some

Predictions, paper presented for the American Sociological Associatlon, session 77, August 1976.

In response, communities usually expand

their official control mechanisms to compensate for the loosening of informal social controls. Police forces are enlarged. Mental health

clinics either increase in number or add to

their caseloads. The emergency room of the

hospital and social service agencies are busier

than before.

Craig, Colo., provides a good example of

what can happen to a community impacted by

a large construction work force. Rapid population growth (a 47-percent increase between

1973-76) coincided with an increase in negative

social behavior, as suggested by the following: 09

Percent increase

Problem area 1973-76

Substance abuse 623

Family disturbance 352

Self-respected emotional

disorde r 45

Child abuse/negiect 130

Child behavior problems 1,000

Crimes against property 222

Crimes against persons 900

While negative social impacts are frequently

reported, they represent only part of the picture. The other part involves many examples of

citizens organizing to provide social, recreational, and cultural activities. Many residents

of coal-impacted communities speak with

pride and satisfaction of the informal initiatives they have taken to improve the quality of

life in their communities. Mayor Enzi of Gillette reflects this pride. “Gillette is virtually in

the process of building a new town, and there

is room for everyone’s participation. In Gillette, the only newcomer is the spectator who

is unwiIIing to pitch in. ”

The farmer/rancher interests also have ambivalent attitudes toward coal. Development

may make marginal farmland valuable for

future housing sites, thus giving its owners the

opportunity to sell at a great profit. The farmer/rancher who does not want to selI may work

his place part time and seek full-time employment in the mines. On the other hand, ranchers

109 Includes cases reported to law enforcement, social

services, hospital and mental health clinic in Craig The

number of cases was averaged from November/December 1973 and November/December 1976 Denver Research Institute, Impacts on Western Communities (OTA

contractor Report, 1978), p 63
324 The Direct Use of Coa/

and farmers may not be able to replace their

workers who switch over to high-paying jobs.

Also, they may resent using good agricultural

land for mining. Fruit growers around Paonia,

Colo., were unhappy about orchards being

taken out of production. Finally, they may be

skeptical about different kinds of people moving into a homogeneous community.

Utah’s policy favors energy development

almost without qualification because of the

State’s desire for economic expansion. As a

whole, Mormon communities share this desire,

but some have reservations. Rural, somewhat

isolated Utah towns that have high percentages of Mormons may not welcome outsiders.

Newcomers are not easily integrated. Residents of Kane County, Utah, wanted the

Kaiparowits powerplant built but did not want

plantworkers to live in their communities.

They persuaded coal developers to plan a new

community to house the outsiders.

People in places like Gillette, Wyo., which

can now be classified as mid boom, see coal

development as inevitable. They know their

county contains vast coal resources and that

new mines wilI inevitably open. According to

Mayor Enzi, the people in Gillette no longer

challenge growth but have accepted it. This attitude has taken 10 years to evolve.

Some westerners see no real benefits from

coal development. Those who have left an urban environment and have settled in beautiful,

small western communities are often against

development. They have chosen their new

home, typically on Colorado’s western slope,

because of its environment. They do not want

it changed. I n a few places on the western

slope, miners with Brooklyn accents can be

found working in the mines and arguing for no

more growth. Their attitudes are not contradictory. Their feelings are often shared by some

long-time residents and their children, who are

concerned about the influx of outsiders and

environmental protection. They often form or

ally themselves with environmental organizations on issues like air and water quality and

degradation of the quality of life. Sportsmen

‘‘°From a 1978 interview with Flip McConnaughey,

City Manager, Gillete, Wyo

and outdoorsmen are often against development because they do not want to lose their

hunting, fishing, and backpacking areas to the

coal industry.

The tourist industry shares these concerns. It

may face competition for employees and loss

of land for recreational purposes, as well as a

lessening of the area’s attractiveness to tourists. Tourism may suffer from the increased demand for temporary accommodations caused

by transient construction workers.

The elderly may or may not have definite

feelings about coal development, but they are

usually hit hard. Some rural communities have

a relatively high proportion of retired people

living on fixed incomes. As the town booms,

prices (particularly rents) are inflated, squeezing those with low or fixed incomes.

The degree to which prodevelopment, goSlOW development, or antidevelopment attitudes exist in a given area depends on the

makeup of the community and the characteristics of the coal project. Articulate, politically

active newcomers can play an important role

in deciding whether or how much coal development will take place.

The one point that can be drawn from the

sparse information on the social impacts of

Western coal development is that instability is

created. Sometimes this appears to be as much

a result of the uncertainty attending coal

development as from any actual changes that

have occurred. Social change will come with

coal development, but it is doubtful that it will

affect western towns uniformly. Some towns

will ultimately benefit from this change; others

probably will not.

Coal Development on Indian Lands

Present and Potential Production

It is estimated that some 100 to 200 billion

tons of recoverable coal lie beneath Indian

lands in the West. There are currently 10 coal

leases on 239,402 acres of Indian land.

Although they are only a fraction of the total

coal under lease in the West, Indian leases

have a special importance because of their
Ch. VI— Workplace and Community Implications ● 325

size and coherence. The average Indian lease

covers almost 24,000 acres —16 times larger

than the average Federal and 25 times larger

than the average Western State lease. Each lndian lease is large enough to support largescaIemining projects,

Five mines now operate on Indian land. Four

of these mines rank in the top 10 largest in the

country. They produced approximately 22.9

million tons of coal in 1977, almost 14 percent

of the coal mined in the West,

Three reservations— Navajo, Hopi, and

Crow– now host coal mines. Several others—

Southern Ute, Uintah and Ouray, Fort Berthold, Northern Cheyenne, and Zuni — have excellent potential for coal mining. The Department of the Interior Iists 25 Indian reservations

as coal owning. Estimates of surface- minable

capacity on these reservations ranges from 217

million to 326 million tons per year by the midto late-1980’s. Actual production, however ,

may be considerably less.

The extent to which Indian coal is developed

wiII depend on decisions made by each tribe,

A key to understanding how — and under

what conditions— coal development will take

place may be found in the history of coal leasing and mining on Indian lands. The legal

framework within which coal development has

been conducted is shaped by the unique trust

relationship between the Federal Government

and tribes.

The basis of the Federal-Indian relationship

may be found in the treaties, congressional

acts, and executive orders that began in colonial days. Treaties were used primarily to

secure lands for white settlement and to maintain peace with the tribes. In return, some

lands–a small portion of the land the tribes

once owned —were reserved for Indian tribes,

with guarantees of protection and certain services from the Federal Government.

Among the services provided by the Federal

Government is advising the tribes on the management of their resources. I n the past, Indian

coal was developed under standard-form

leases arranged for and managed by the

Bureau of Indian Affairs (B IA) in the Department of the Interior. BIA advised the tribes as

to whether, to what extent, and under what

terms their coal would be developed. Tribes

are no longer satisfied to rely on BIA for decisions regarding their resources.

In March 1973, one tribe—the Northern

Cheyenne– became so dissatisfied with leases

it had signed with B 1A advice, that it petitioned the Secretary of the Interior to cancel

all outstanding coal leases and permits on its

reservation. A year later, the Secretary ruled in

favor of the Northern Cheyenne and declared

the leases “technicalIy invalid. ”

Since this ruling, other lease-holding tribes

have tried to renegotiate or cancel contracts,

accusing Interior of violating its trust responsibilities to protect tribal interests.

Despite the controversy surrounding these

contracts, many tribes see coal development

as an opportunity to bring badly needed revenues to tribal governments as welI as income

and jobs to tribal members, Most feel, however, that they will not realize the potential

benefits of coal development unless they develop the capability to manage development

themselves. Tribes are building their own staff

capabilities so that they can determine the

quantity and quality of their resources,

analyze the impacts of potential development,

make informed decisions concerning their resources, and manage and regulate coal production activities and impacts.

Coal Development Impact

Rapid or extensive coal development often

causes adverse social, economic, and environmental impacts. This is especially true on lndian reservations.

Most reservations are sparsely populated

and have few towns. I n a few cases, coal mining may spawn the growth of instant towns to

provide support services for new mines. Even if

future tribal contracts provide for Indian hiring preferences, non-Indians wiII be drawn to

the mines as technicians and other management personnel. Non-Indian businessmen may

open stores on or near reservations. Although

only 5,000 to 10,000 miners are Iikely to be in-
326 The Direct Use of Coa/

volved in Indian coal development over the

next 10 years, the ripple effect of their newfound income, work habits, and social relations are likely to be disproportionately large

on established Indian societies.

Coal development would also affect tribes

more than other rural communities because

the reservations have a dearth of services and

facilities, such as sewers, housing, schools, etc.

Any population increase—even a small one—

would strain already-overburdened systems.

Cultural differences between the tribal members and outsiders who migrate to the area to

work on the project can augment the problem.

In addition, coal development impacts lndians more than other rural residents because of

the importance of the land to Indian tribes. For

some tribes Iand has religious significance; for

others, certain areas are sacred. For all of the

tribes, land is an important tie to their history

and future.

Finally, coal development will affect tribes

more than most small, isolated communities

because tribal governments have great difficulty generating revenues needed to offset demands created by development. Conventional

methods of raising revenues, such as taxation,

issuing bonds, obtaining private financing, or

receiving Federal funds directly, are either not

available or difficuIt for tribes.

All of these impacts can serve as deterrents

to the development of Indian coal unless tribes

can effectively manage them.

Conclusion

Coal development on Indian reservations is

likely to increase as tribes gain greater control

over their own resources.

Tribes are building up their staff capabilities

so they can determine the quality and quantity

of their coal reserves, negotiate with energy

companies, and regulate the companies’ operations. Tribes are looking at alternatives to the

standard form lease used in the past. Tribal

coal holdings are attractive to energy companies because of their large size and the quality

of the minerals. And coal development— if

carefully managed by the tribe— is attractive

to many Indian leaders as a solution to their

dire poverty — average per capita income is between $1,000 and $1,500 annually— and unemployment–40 to 70 percent depending on the

reservation. However, many energy projects on

the reservation have been met with bitter

grass-root protests.

Coal development will have major socioeconomic and cultural impacts on Indians. The

reservations lack public infrastructures

capable of absorbing mining-related population. The tribes have difficulty raising revenues

to manage the impacts of coal development.

Tribal leaders interviewed agree on several

conditions for coal development. First, that the

majority of coal-related jobs be filled by lndians. Second, that fair market value is obtained

for the coal. Third, that coal development will

enhance tribal sovereignty by recognizing tribal jurisdiction over environmental standards

and by preserving the integrity of Indian land

and cuIture. Tribes want to ensure that coal development is not a one-crop economic development that leaves them several decades from

now without any resources, with scarred lands

and shattered cultures. Thus, tribes are expected to demand higher coal royalties, more

control over the conditions of mining, and

more social benefits from coal development.

Social Impacts of Transportation

Much of the increase in mine-to-market coal

traffic will probably make use of existing

routes. Expanded operation, rather than new

construction, involves additional safety and

environmental costs to the public.

All forms of moving coal –or coal-fired

electricity – have social costs. Trains interrupt

motor vehicle traffic and contribute to accidents at grade crossings. More than 1,900

persons were killed and almost 21,000 injured

in railroad accidents in 1974.1 Most of these

accidents were at grade crossings. Perhaps, 15

percent or more of all train accidents involved

coal-hauling trains. Truck haulage, which is

‘‘ ‘Compiled by OTA from Federal Railway Administration data.

“*Coal represents about 20 percent of all rail traffic,

but for reasons such as frequency of grade crossings and

routes, coal traffic probably accounts for less than 20

percent of rail accidents compiled
Ch. VI— Workplace and Community Implications ● 327

extensive in Appalachia, adds to highway hazards and congestion. The big trucks accelerate

the deterioration of the roadways, especially

when weight limits are not enforced. Trucks

and trains are noisy. They disturb large numbers of people where they pass through heavily

populated areas. Barge haulage is safer to the

public than either truck or rail carriers, but it

adversely affects recreational boating, fishing,

and swimming to some degree. Barge wakes

may erode river shores and islands. Highvoltage transmission lines may produce harmful electric-field effects.

Railroads now carry about 65 percent of all

coal from mine to consumer. This pattern is

likely to continue. Aside from the needs to improve rail-haulage capability, safety and environmental costs may require attention. Two

problems, in particular, stand out. First, disruption to community life caused by rail traffic

through population centers will increase as

large mines are developed in the West for customers several hundred miles distant. Haulage

through a given point may approach the equivalent of 18 hours a day in some heavily used

areas. Rerouting may be desirable in some

communities to minimize this inconvenience.

Second, grade-crossing accidents will increase as haulage increases unless remedial

steps are taken. Underpasses and overpasses

are standard ways of eliminating rail-haulage

risks in population centers. Automatic, lighted

barrier gates are safety features at crossings

that are often not found at rural crossings.

Because of the cost and inconvenience, railroads are often reluctant to reconstruct their

lines or add safety features, such as lights and

mechanical crossing guards. Table 55 illustrates four costs— noise, vehicle delay, injuries, and deaths– associated with a hypothetical 36-percent increase in coal trains per

day (measured in ton miles) between a Montana mine and a Wisconsin utility. At 26.6

trains per day, 53,000 persons would be exposed to excessive noise; 983 hours of vehicle

delay per year would occur; and 9 fatalities

and 37 injuries wouId happen at grade crossings. Yet it should be noted that the increase in

noise and accidents is not proportional to the

increase in volume although vehicular delay is

greater.

Deaths and injuries associated with the total

transport component of the coal cycle were

calculated in a recent study. 3 For a 1,000-MW

coal-fired powerplant with a 0.75 load factor,

MITRE estimates 2.3 fatalities and 23.4 injuries

occur annually. That translates nationally to

about 460 deaths and 4,680 injuries each year

from coal transport. As coal production increases, the scale of human costs will grow

unless countermeasures are initiated.

The alternative to coal haulage is high-voltage electric transmission, which carries its own

costs. Intense electric fields surrounding these

lines disturb people living along their rights-ofway. Noise and radio interference have been

noted.

Concern has developed about health and

safety near the Iines. Tests are now underway

to measure the effect of high electric fields on

plants and animals. For voltages up to 500 kV,

no evidence exists to indicate health hazards,

but very little is known about the long-term effects of low-voltage electric fields on human

health. At higher voltages–say at 765 kV–adverse reactions have been reported that may

have been caused by the fields. As the voltages

increase, potential health effects may increase. Much work is needed to determine the

possible health costs of high-voltage transmission lines carrying more than 765 kV. DC

presents fewer potential problems because it

carries an equivalent amount of AC power at

lower voltages. But because the character of

DC electric fields differs from AC fields, other

human health effects may occur. Objects near

DC lines may be charged with voltages of 20 to

40 kV, enough to cause annoying shock.

Impacts on Coal-Utilization

Communities
o

328 ● The Direct Use of Coal

Table 55.—impacts of Increased Coal Train Traffic Carrying an Assumed Added

Volume of 13.5 Million Tons Per Year from Colstrip, Montana to the Vicinity of

Becker, Wis.

Percent

Present Future increase

Trains per day (average) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.6 26.6 36

Population exposed to noise levels exceeding

EPA community Guidelinesa . . . . . . . . . . . . . . . . . . . . . . . . . . . 45,000 53,000 18

Vehicle hours delay per year at grade

crossings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 602 983 63

Injuries per year at grade crossings . . . . . . . . . . . . . . . . . . . 33.1 36.6 11

Deaths per year at grade crossings . . . . . . . . . . . . . . . . . . . 8.6 9.4 9

1977

the extraction phase, i.e., on coal mine communities where new facilities for the preparation and combustion of coal are located.

A general knowledge of the coal industry

suggests a number of categories of potential

impact. These can be divided roughly into

those that should be on balance beneficial to

the host community and those that will be

predominantly harmful. The former consists

mainly of economic impacts. The establishment of a coal preparation plant or powerplant can be expected to provide employment

opportunities in the construction, operation,

and maintenance of the plant and in supporting community services. The plant may also

contribute substantialIy to the county tax base

and benefit other local taxpayers.

The major potential negative impacts would

appear under the headings of environment,

public safety, and convenience. The first category includes air and water pollution, noise,

esthetic (i. e., visual) impacts, and possible concerns relating to the health effects of highvoltage transmission Iines from powerplants.

Safety and convenience refers to concerns

such as coal-carrying truck or rail traffic and

the potential disruption of recreational and

other community activities.
Ch. VI— Workplace and Community Implications ● 329

Surprisingly, virtually no attempt has been

made to ascertain public attitudes toward existing coal powerplants. At a minimum, such

information shouId be usefuI in developing

siting strategies for future instalIations. Consequently, OTA undertook a survey of residents

living near three coal-fired powerplants in the

Middle Atlantic region: the Chalk Point plant

in Maryland, the Chesterfield plant in Virginia,

and the Bruce Mansfield plant in Pennsylvania.

The results of that survey indicate that the

public regards increased employment opportunities as the most significant advantage of Iiving near such a plant (table 56). Other advantages cited by the public included the perception that coal-generated electric power is more

economical than other sources of energy such

as oiI and gas. The public also perceived benefits to the Nation in shifting from imported oil

to domestic coal. A relatively smalI percentage

of respondents cited tax benefits and the

perception that coal-fired plants were safer

than nuclear. On the negative side, a large percentage of the public (52.3 percent) cited air

pollution as the most significant disadvantage

associated with Iiving near a coal-fired powerplant, regardless of plant location or distance.

Other disadvantages cited were water pollution, noise, adverse visual impacts, and recreational impacts (fishing, boating, and swimming). I n an attempt to measure the air and

water pollution impact, respondents were

asked to rate the level of pollution in their

communities and indicate the impact the plant

had on that level. Almost half of the respondents indicated the air and water pollution

levels were severe but only a smalI percentage

thought the plant was largely responsible (6.4

percent for air; 4.8 percent for water), The disparity between the level of impact and its

perception is due in part to the fact that respondents felt that industries located in the

same area contributed to the pollution problem. A relatively small percentage of respondents indicated that traffic to and from the

plant had a negative impact. In an effort to

elicit an overalI summary judgment concerning the local impact of such a plant, respondents were asked their attitude regarding construction of an additional coal-fired powerplant in or near their community. In all three

cases, a large percentage of respondents living

within 3 miles of the plants opposed the construction of a new plant. I n addition, whe n

given a choice between coal and nuclear

powerplants, the public did not express a

strong preference for either (39.3 percent preferred coal; 36,8 percent preferred nuclear). In

many cases the preference for coal was attributed to perceptions that nuclear powerplants

were unsafe and fear of radioactive fallout. In

general, the balance of positive and negative

attitudes toward coal plants correlated more

closely with the distance respondents lived

from the plant than with any other variable, including the degree of plant compliance with

State environmental standards.

Table 56.—Survey Results

Percentages

—

-- —— — ——— — .—

Chalk Pt. Chester. B. Mansfield — — — — — .— —

3. Air pollution level

28.2 17,5 8.1 Not a problem.

37.2 34.1 24.3 Some, but does not disturb anyone.

23.8 42.7 46.8 ——— Occasionally reaches severe levels.

1.1 3.3 12,7 - Usually severe and interferes with some community activities.

9.7 2.5 8.1 Cannot rate level.

4. Plant impact on air pollution

4.8 2.0 13.8 Severe with frequent odor, dust, or damage,

29. 7 18.7 34. 3 . Moderate with occasional odor, dust, or damag e

31. 5 28. 0 27. 0 Sllght with little odor, dust, or damage.

34.1 51. 3 24. 9 No noticeable impact .
330 ● The Direct Use of Coal

Table 56.–Survey Results (continued)

Percentages — . .

Chalk Pt. Chester. B. Mansfield

8.6

33.0

24.4

16.8

17.2

7.9

25.7

29.4

37.0

19.3

35.0

2.5

41.4

7.5

13.2

0

4.1

79.0

15.7

1.1

3.0

5.2

79.9

10.4

1.5

.7

6.2

35.4

38.0

19.7

.4

2.2

47.6

35.4

14.4

1.1

17.8

14.4

61.0

56.6

2.9

5.4

23.3

33.9

27.0

15.5

11.5

12.1

2.9

13.1

31.1

52.9

6.0

21.9

4.1

23.8

6.8

18.9

0

1.5

84.0

13.3

1.2

4.7

9.4

79.8

5.3

.9

.6

1.7

61.2

30.1

6.4

.6

2.3

52.9

38.8

5.5

3.8

16.8

11.2

63.5

64.6

1.7

.3

13.6

8.6

25.5

27.6

14.8

23.4

5.1

24.3

27.5

43.1

6.1

33.7

7.5

31.6

22.1

10.5

.7

3.0

61.1

29.3

5.9

3.6

8.0

50.0

29.6

8.8

3.9

11.0

24.9

32.4

27.8

1.8

5.1

46.9

30.7

15.5

.7

19.2

30.8

42.0

0

49.4

.4

8.2

5. Water pollution level

Usually severe and interferes with some community activities.

— –. Occasionally reaches severe levels and sometimes interferes with

community activities.

Some, but does not disturb anyone.

Not a problem.

Cannot rate level.

6a. Plant impact on water pollution

—— Severe with major changes in temperature, level, or chemicals in the

water.

Moderate with some changes in temperature, level, or chemicals in the

water.

Slight with minor changes in temperature, level, or chemicals in the

water.

No noticeable impact .

6b. If plant has impact on water pollution, which of the following apply?

—— — Fishing is better.

— — . Fishing is not as good.

Boating and swimming are better.

Boating and swimming are not as good.

Drinking water is polluted.

— Other, please specify.

7. Plant impact on public health

— . — Public health very much better.

Public health somewhat better.

No difference in public health.

Public health is somewhat worse.

— — Public health very much worse.

8. Plant impact on public safety or convenience

— Public safety or convenience very much better.

— — . Public safety or convenience somewhat better.

No difference in public safety or convenience.

Public safety or convenience somewhat worse.

Public safety or convenience very much worse.

9. PIant impact on area attractiveness

— -- Very much more attractive.

— — Somewhat more attractive.

- No difference in attractiveness.

Somewhat less attractive.

.- Very much less attractive.

10. Impact of power transmission lines on area

Very desirable effect.

—– Somewhat desirable effect.

—--- No noticeable effect.

——— Somewhat undesirable effect.

Very undesirable effect.

11. Plant impact on area activities

——— Plant grounds and facilities available for community use.

Plant tax payments prevent taxes on home from being higher.

——- Noise or air pollution or water pollution discourage community activities.

No noticeable impact.

12a. Mode of transportation

Train.

Barge.

Truck.

Don’t know.
Ch. VI— Workplace and Community implications ● 331

Table 56.—Survey Results (continued) —

Percentages —.

Chalk Pt. Chester. B. Mansfield — —

6.1 2.8

93.9 97.2

28.2 11.8

21.1 16,7

24.6 33.4

14,6 23.0

11,4 15.1

34.4 46.7

41.1 39.0

24,4 14.3

31,4 9.3

27.1 38.5

22.5 29.2

14,3 13.9

4,6 9.0

.

22.9

77.1

23.6

21.6

27.7

12.7

13.4

38.7

33.9

27.4

61.9

27.9

4.8

1.0

4.4

12b. Transportation impact on community

— Yes.

---- No.

13. Favor/oppose construction of new plant

Strongly oppose.

— Somewhat oppose.

– Neither favor nor oppose.

- Somewhat favor.

Stongly favor,

14. Preference for coal or nuclear plant

-. Coal-fired.

— Nuclear,

-- Don’t know.

15. Distance from home to plant

--- Less than 3 miles.

—– Between 3 and 6 miles.

– Between 6 and 10 miles.

– --- More than 10 mtles.

-.— Don’t know.

———
332 ● The Direct Use of Coa/

ESTHETIC IMPACTS

Introduction

The esthetic impacts of increased coal utilization are difficult to quantify and evaluate

because procedures for measuring esthetic impacts have not been established. In part this is

a result of the subjective nature of esthetics.

For example, Webster defines esthetics as

“beauty or sensitivity to beauty. ” The response

to an esthetic impact, positive or negative, is

largely dependent on value judgments.

Consequently, a great deal of uncertainty

exists regarding the role esthetics should play

in affecting public policy.

Section I02(2)(B) of the National Environmental Policy Act calls for the consideration

of esthetic impacts in decisionmaking but does

not provide assistance in determining what

methods and procedures should be developed

to facilitate that consideration. Some attention has been given to the formulation of quantifiable indicators but these are still in the very

early stages of development, Table 57 illustrates work in this area.

The most obvious problem is the fact that

esthetic impacts are perceived differently by

different individuals and groups. Although no

one finds strip mines esthetically pleasing,

there are individuals who feel that the construction and operation of coal utilization

facilities will have a positive impact. For example, some feel reclamation is an opportunity

for improving the landscape. Others argue,

however, that the construction and operation

of coal utilization facilities will have adverse

esthetic impacts; changing the natural characteristics of an area and its ecosystems is

viewed as detrimental. Furthermore, in some

instances esthetic impacts can be used as a

surrogate for other concerns, such as opposition to government and industry, and resistance to outsiders. An example of this is the

Kaiparowits controversy where fear of esthetic

impacts were used as a basis to mobilize support from a broad-based national constituency. Although strong local support was given

to the development of the Kaiparowits plant, a

national constituency that views air polIution

impacts on nearby pristine areas as unacceptable actively opposed the plant.

The variable most often used to measure esthetic impact is change. Present EISs generally

reflect the view that changes in the environment are negative. In addition, esthetic impacts identified in EISs appear to be of an immediate or first-order kind; EISs do not identify

beneficial second-order esthetic impact associated with social and economical benefits (libraries, theaters, etc.). Legislation also appears

to embody the assumption that change is negative. This is evident in the language of the

prevention of significant deterioration standards for air quality. There does not appear to

be any firm basis for defining all change from

the natural state to be bad, however.

Table 57.—Esthetic Judgment Categories

Esthetic judgment

Equality of

esthetic

Air esthetics Water esthetics Landscape esthetics Biota esthetics Sound esthetics opportunity

Visibility Clarity Urban dominated Population Background sound

Odor Floaters Mountain dominated Variety Intermittent sound

Irritants Odors Desert dominated Health

Agriculture dominated Location

Forest dominated

Water dominated

— — —

SOURCE. Adapted~rom Gum, et al , 1974” 34.
Ch. VI— Workplace and Community implications ● 333

Photo credft: Earl Dotter

Ellsworth, Pa. Slag pile in the background

Minin g

A major concern in the West is whether reclaimed land can be revegetated in an area

with Iimited rainfalI Although simiIar concerns are expressed in the Central and Eastern

regions, revegetation is easier there because of

the higher levels of rainfall and thicker soil

profiIes Because of thin coal seams, however,

as much as 10 times more land in the East must

be stripped in order to provide the same quantity of coal as in the West. Contour mining in

mountainous areas produces stiII another serious esthetic impact. Often the highwalI is visible for miles. Reclamation of contour mining is

costly and difficult and may appear sIightly artificial. But if properly reclaimed, nonmountainous land can be used for many purposes,

including agricuIture, recreation, forestry,

housing, and industrial development. Another

impact associated with strip mining is a reduction in visibility due to dust. This impact is

probably of greater concern in the West where

rainfall is Iimited Noise is another impact

from mining. Although blasting noise is not

identified as a serious problem, it is an annoyance to individuals who Iive near the m inc. The

most significant visual impact resulting from

underground mining is subsidence (uneven

sinking of land surfaces). This impact is a significant concern in the Central and Eastern

coal regions.

Transportation

Several esthetic impacts result from the

transportation of coal. Unit trains produce a

noise level of about 9S decibels; these levels

may remain as high as 55 decibels within onehalf mile of the track. At present, noise from

transportation affects trackside residents and

as rail haulage increases with expanded production, noise, and dust will become more fre-
334 The Direct Use of Coa/

quent and more serious annoyances. Highways

also contribute to noise pollution, and both

highways and railroads may be considered unsightly. However, the most obvious visual

transportation impact is from transmission

lines. The lines are especially unsightly in

scenic and residential areas and are visible for

miles. Tower design as well as proper siting

couId possibly reduce the impact.

Combustion

Visually, coal-fired electric powerplants are

rarely pleasing to the eye. Often stacks are visible for miles. In addition, coal piles surrounding the plant are unsightly and may produce

dust. Large-scale coal utilization facilities can

significantly reduce visibility and alter the

natural coloration of the sky. During an inversion, visibility may be reduced even more.

Gray skies associated with heavily industrialized areas may suggest what is to come if coal

utilization is accelerated. Individuals living in

close proximity to the facility may experience

noise and odor impacts, but these do not appear to be a serious concern at this time.
Chapter Vll .

PRESENT FEDERAL COAL POLICY
Chapter VII- PRESENT FEDERAL COAL POLICY

Page

Policy Evolution ● .*** ... ,.. ,.. ... *.. m**. *.. ,.. a m....... * 337

National Environmental Policy Act . . . . . . . . ., . ...........338

Federal Coal Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ..339

Past Leasing Law and Practice . . . . . . . . . . . . . . . . . . . . .. ..340

Development of a New Federal Coal Leasing Policy . ......341

Problem Areas . . . . . . . . . . . . . . . . . . . . . ...............342

Surface Mining Control and Reclamation Act of 1977........343

The Federal Mine Safety and Health Act of 1977............345

The Clean Air Act. , . . . . . . . . . . . . . . . . . . . . . . ...........349

Background and History. . . . . . . . . . . . . . . . . . . . . . . . . . .. .349

National Ambient Air Quality Standards . . . . . . . . . . . . . . . .349

New Source Performance Standards . . . . . . . . . . . . . . . , .. .350

Nonattainment Areas. . . . . . . . . . . . . . . . . . . . . . .........351

Prevention of Significant Deterioration/Visibility Protection. 352

EPA Studies and Potential New Standards . . . . . . . . . . . . . . . 353

Interface with Energy Legislation . . . . . . . . . . . . . . , .. ....353

Implementation of the Amendments . ..................354

The Clean Water Act . . . . . . . . . . . . . . . . . . . . . ............355

Water Quality Standards . . . . . . . . . . . . . . . . . . . . . .......356

Effluent Limitations . . . . . . . . . . . . . . . . . . . . , . ..........356

Thermal Discharges . . . . . . . . . . . . . . . . . . . . . ............358

Permit Systems. . . . . . . . . . . . . . . . . . . . . , . . . . . . . , .. ....359

Areawide Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .,359

Resource Conservation and Recovery Act of 1976. . ., .......360

Coal Conversion Authority. . . . . . . . . . . . . . . . . . . . . . ....,..361

Other Federal Policy Actions . . . . . . . . . . . . . . . . . . . . . . . . ...363

Implementation ● .*..*. . . . . . . . . . . . . . . . . . . . . . . . . ● 0....., , 365

Institutional Factors, ..., ., . . . . . . . . . . . . . . . . . . . . . . . . , ..365

Environmental and Social Impacts. . . . . . . . . . . . . . . . .. ...365

The Promotion of Coal Use . . . . . . . . . . . . ., . . . . . . . . . i ..368

Evaluation . . . . . . . . . . . . ., . . . . . . . . . . . . . . . . . . .........368

TABLE S

Page

58. Standards for Particulate Matter, Sulfur Dioxide, and

Nitrogen Dioxide ., . . . . . . . . . . . . . . . . . . . . . . . . . . . . , ....350

59. Effluent Limitations: Steam Electric Power Generating Units .357

60. Effluent Limitations: Coal Mining Point Source Category ....358

61. Potential Sludgeand Ash Disposal Costs Under RCRA. .. ....361
Chapter Vll

PRESENT FEDERAL COAL POLICY

Neither Congress nor the President has yet articulated a comprehensive and consistent

policy for coal. Nevertheless, the major elements of such a policy are in place. The National

Energy Act of 1978 and the earlier Energy Supply and Environmental Coordination Act of

1974 promote the use of coal to increase the Nation’s capability to use domestic energy

sources. The National Environmental Policy Act, the Clean Air Act and Amendments, the

Clean Water Act, the Surface Mine Control and Reclamation Act, and other Federal policy

actions minimize environmental degradation resulting from, among other causes, the production and use of coal. The Mine Safety and Health Act is intended to reduce the hazards to

miners, while black lung benefits compensate for past abuses. Various provisions also have

been made to assist communities experiencing rapid growth as a result of coal development.

Thus coal policy might be summarized briefly as: When fossil fuel is to be used, coal shall be

the choice wherever practical, but it must be mined and burned in ways that minimize the

negative environmental and human impacts. These goals are obviously contradictory, but

they need not be mutually exclusive.

Because Congress has never legislated a national coal policy, the current Federal role

has evolved incrementally as part of a continuing political process where different interests – both inside and outside of Government–compete for influence. This competition involves lobbying Congress, media campaigns, gaining access to policy makers, researching

issues, bargaining with the opposition, and mobilizing and targeting pressure. The consequence of this process is that Federal policy is often contradictory, frequently delayed by

legal challenges, occasionally jarred by legislative initiatives, and rarely settled once and for

all.

This chapter explores the present structure of Federal coal policy and how it is being implemented. The next chapter analyzes policy strategies that may be considered in the future.

POLICY EVOLUTION

At the end of World War 11, coal supplied

about half the Nation’s energy needs. By 1950,

it had been eclipsed by oil, and natural gas surpassed it in 1958. Such a rapid decline in absolute as well as relative importance indicates

that more was occurring than an industry succumbing to stronger competition. Both market

prices and Federal policies discouraged the

use of coal relative to oil and gas. Similarly,

the negative impacts of coal were not of paramount concern to the Federal Government except in so far as they contributed to the tilt

toward oil and gas. Federal coal on western

lands was made easily available, but little

development was expected to take place.

In the last decade, the realization of the resource limitations of oil and gas has renewed

interest in coal as the logical substitute, result44-11, .! ( 1 - 7 ~ - 23

ing in a variety of Federal policies related to

coal. Federal legislation first addressed the occupational health and safety risks of coal mining. Subsequent Federal policy directives addressed the air and water quality effects of

mining and combustion on human health and

the environment, Recently, the disposal of

mine and combustion wastes and the reclamation of surface mines have come under Federal

jurisdiction. However, there are many points in

the entire pattern of coal production and use

where the different goals — increased production, environmental protection, and maximum

social benefit— conflict. Both Congress and

the executive branch have sought to fashion

policies and administrative frameworks that

can resolve these conflicts, but they often are

frustrated by overlapping and conflicting mandates that result in inconsistent or fragmented

337
338 The Direct Use of Coa/

policies. For example, an adequate water supply is crucial to mining operations but the lack

of a comprehensive Federal water policy offers

little direct support to a policy of increased

coal development.

The Federal legislation that constitutes the

major elements of a national coal policy are

analyzed below, categorized according to

their goals: environmental and social impact

management, and the promotion of coal use.

National Environmental Policy Act

The National Environmental Policy Act of

1969’ (NE PA) was intended to restructure Federal agency decision making in favor of an interdisciplinary approach to ensure that environmental amenities and values would receive appropriate consideration along with the

traditional economic and technical factors.

NEPA was the first major environmental legislation passed by Congress and it has remained

the most far-reaching in scope.

In general, NE PA has a threefold purpose: to

declare a national policy to create and maintain conditions under which man and nature

can exist in productive harmony and can fulfilI

the social, economic, and other requirements

of present and future generations; to increase

the understanding of ecological systems and

natural resources; and to promote efforts that

will prevent or eliminate damage to the environment. As one means of achieving these purposes, NEPA requires all Federal agencies to

include a detailed environmental impact statement (E I S) in every recommendation or report

on proposals for legislation and other major

Federal actions significantly affecting the

quality of the human environment. The E IS requirement has been held to be applicable to a

wide variety of Federal actions, ranging from

the construction of a Federal building to the issuance of a construction permit for a nuclear

powerplant.

An E IS is required to include detailed information about:

’42 U. SC. 4321 et seq

●

●

●

●

●

the environmental impact of the proposed

action,

any adverse environmental effects that

cannot be avoided should the proposal be

implemented,

alternatives to the proposed action,

the relationship between local short-term

uses of man’s environment and the maintenance and enhancement of long-term

productivity, and

any irreversible and irretrievable commitments of resources that would be involved

in the proposed action should it be implemen ted.

In addition, the Council on Environmental

Quality (CEQ) regulations for the preparation

of EISs require discussions of indirect effects,

such as population and growth; energy requirements and the conservation potential of various alternatives and mitigation measures; and

possible conflicts between the proposed action and the objectives of other Federal, regional, State, tribal, or local policies.

All coal-related activities that have a significant impact on the environment and that need

Federal authorization require an E IS. This includes coal leases on Federal lands and large

coal combustion facilities. Although permits

issued by the Environmental Protection Agency (EPA) under the Clean Air and Water Acts

are exempt from the E IS requirement, those

Acts require separate analyses of a project’s

impact on the environment.

The original CEQ regulations implementing

NEPA were limited to the preparation of E1Ss

and did not address NE PA’s other provisions intended to improve agency planning and decisionmaking. In addition, CEQ’S guidelines for

preparing EISs were only advisory; more than

70 different sets of agency regulations were

promulgated to implement the guidelines. As a

result, agency practices varied widely and the

EIS tended to become an end in itself rather

than a means to making better decisions. The

NEPA process was criticized by environmentalists for its attention to procedure rather than

substance, by permitters for delays it caused

in project authorization, and by Government

officials for the amount of paperwork it required.
Ch. V1l—Present Federal Coal Policy ● 339

In 1977, CEQ was given the authority to

issue binding regulations to replace its advisory guidelines and the various agency regulations. The new CEQ requirements, which were

published in November 1978, are designed to

produce better agency decisions and to reduce

delays and paperwork. 2

The new CEQ regulations are intended to

comply with the original intent of NE PA that

the E IS be an action-forcing procedure to implement the substantive requirements of the

Act and thus to produce better agency decisionmaking. They require agencies to publish a

concise public record that indicates how the

E IS was used in making a decision, This record

must indicate which alternative is preferable

on environmental grounds. If that alternative

is not the one chosen, the record must identify

the essential considerations of national policy

that were balanced in making the decision, including factors not related to environmental

quality such as economic and technical considerations or legislative mandates, and must

explain why the environmental considerations

were outweighed by these other factors. A second provision of the new regulations, which is

intended to produce better decisions, requires

agencies to monitor projects to ensure that

mitigation procedures and other conditions established in the EIS are implemented. Finally,

the new regulations require that a list of the

people who helped prepare an EIS and their

professional qualifications be included in the

statement to encourage accuracy and professional responsibility and to ensure that an interdisciplinary approach was followed,

To reduce paperwork, the regulations require agencies to reduce the length of EISs

(CEQ suggests 150 pages as the limit for a normal E IS), prepare analytic rather than encyclopedic statements, use plain language, follow a

clear format, and reduce emphasis on background material. In addition, Federal agencies

can eliminate duplication by preparing EISs

jointly with State and local agencies that require similar assessments. The regulations also

institute a new “scoping” procedure for deciding which issues should be emphasized in

2

43 F R 55978 (Nov. 29, 1978)

the E IS and how the responsibility for the E IS

should be apportioned among the agencies involved. This scoping procedure is to begin as

early as possible in the N EPA review and must

be integrated with other planning.

Provisions of the regulations designed to reduce delays in project authorizations include

emphasizing interagency cooperation before

the E IS is prepared rather than submission of

adversary comments on a completed draft, establishing time limits for E IS preparation, and

using categorical exclusions to define actions

that are exempt from the E IS requirement. In

addition, the regulations calI for a “tiered” approach in which material common to a broad

program or a related series of actions is included in broader EISs, such as national program or policy statements, and then summarized and incorporated by reference in successively narrower EISs, such as regional or

basinwide program assessments and, ultimately, site-specific statements. Finally, many of

the regulations intended to reduce paperwork

also will reduce delays, such as the scoping

process and the elimination of duplicate statements.

It is too soon to tell whether these regulations will restructure agency decision making in

order to implement fulIy NE PA’s environmental policy goals. However, the regulations

should significantly reduce the resources required to comply with the Act and thus prevent N EPA from becoming a Iimiting factor in

decisions related to coal development.

Federal Coal Leasing

The National Energy Plan calls for expanded

reliance on coal. Some commentators have

suggested that Federal coal reserves will be a

key factor in determining whether the Nation

wilI meet its energy goals. Western coal comprises roughly half of the total U.S. coal

reserves; the Federal Government owns 65 percent of Western coal and indirectly controls

another 20 percent. On the other hand, the

1977 amendments to the Clean Air Act may

considerably reduce the advantages that have

accrued to low-sulfur Western coal in the past

if those amendments require pollution con-
340 ● The Direct Use of Coa/

trols regardless of the sulfur content of the

fuel.

Even if Western coal is required to meet national energy goals, it is not clear how many

new Federal coal leases would be needed. Sixteen billion tons of Federal coal already are

under lease and another 9 bi1Iion are subject to

existing applications for preference-right

leases. In addition, there are an estimated 93.4

billion tons of recoverable coal reserves on

private lands in the West.

Thus it is unclear how important Federal

coal will be to the Nation in the future or

whether additional Federal leasing is needed.

Yet no comprehensive Federal coal leasing policy currently exists, and even if more Federal

coal is required to meet the Nation’s energy

goals, it probably will not be able to play a

central role until the early 1980’s. This section

reviews the history of Federal coal leasing, examines recent congressional action, and outlines the major obstacles to a rational leasing

policy.

Past Leasing Law and Practice

Originally, the Federal Government sold or

gave away its coal-bearing lands. Then, under

the Mineral Leasing Act of 1920,3 it became

Federal policy to issue leases for prospecting

and mining. Where there were known coal deposits, leasing tracts were awarded by competitive bidding. In other areas, the Department of the Interior issues 2-year prospecting

permits. If commercial quantities of coal were

discovered during those 2 years, the permittee

was entitled to a preference-right lease for all

or part of the land.

Although the 1920 Act contained numerous

provisions designed to protect the public interest and to ensure a fair return to the Government, most leases were issued on an ad hoc

basis without regard to energy needs or environmental factors. Much of the leased land fell

into the hands of a few large companies that

were interested only in speculation. The Federal Government often charged lower royalties

than private lessors and Government leases

~30 USC. 181 et seq.

could be held without development at little

cost and transferred at will.

Leasing generally was based on a site-by-site

response to applications, usually at the State

level with no National policy guidance. Consequently, what mining did occur was hampered

by irrational landownership patterns in the

Western coalfields. Areas that logically should

have been mined as single units were divided

among private owners and Federal lessees.

Similarly, there was often a split in ownership

of surface and mineral rights. In addition, data

necessary to develop a coherent National policy, such as information on the location and

extent of coal deposits, were not available.

In November 1970, the Bureau of Land Management (BLM) released a study that summarized the results of these abuses. 4

The study

found that while the number of acres being

leased was rising, production from leased

lands was dropping; 91 percent of all coal

leases were not producing anything. BLM concluded that “existing policies and procedures

with respect to the development of federally

managed coal resources are inadequate to encourage their development. ” As a result of this

study, the Department of the Interior imposed

a moratorium on coal leasing while it reassessed its own policies. In February 1973, interior announced that a new long-term policy

was under development and in the interim no

new prospecting permits would be issued and

coal would be Ieased only where certain

“short-term” criteria were met.

The short-term criteria were designed to prevent undue hardship to companies as a result

of the moratorium. Initially, they permitted

coal leasing when necessary to maintain an existing operation or to serve as a reserve for production in the near future. Unfortunately,

these criteria were abused and received scathing criticism from the General Accounting Office.

5 The criteria were revised in July 1977;

2 months later they were included in an in4Holdings and Development of Federal Coal Leases,

(U.S. Department of the interior, Bureau of Land Management, unpublished, November 1970).

5

Further Action Needed on Recommendtions for Improving the Administration of Federal Coa/-Leasing Program (Washington, D. C.: General Accounting Office, U.S.

Comptroller General, April 1975).
Ch. V/i—Present Federal Coal Policy ● 341

junction issued by a Federal court against the

entire Federal Ieasing program. b At present,

short-term leasing is permitted only when necessary to maintain the level of production at

an existing mine or to meet existing contracts

and when the extent of the lease is not greater

than required to meet these conditions for 3

years.

Short-term leasing has produced little coal.

Only 12 leases covering 30,459 acres have been

issued since 1973. Industry is reluctant to commit itself to short-term coal leases and the

court’s criteria are difficuIt to meet.

Over the same period, the Federal Government’s long-term leasing program has gone

through two stages, known as EMARS I and

EMARS 11. In May 1974, the Department of the

Interior issued a draft programmatic EIS, outlining its plans for a long-term leasing program,

or Energy Minerals Allocation Recommendation System (EMARS l), which required the

Government to set leasing targets based on national energy needs. Under EMARS 1, leasing

tracts were to be nominated by the Government based on land use plans. Environmental

impact assessments were to be performed on

the nominated tracts and those that were suitable for leasing put up for competitive bidding.

In September 1975, after a comment period

on the impact statement and EMARS 1, the Department of the Interior issued the final programmatic E IS. The impact statement adopted

an Energy Minerals Activity Recommendation

System (EMARS II) instead of the Allocation

System contained in the draft statement.

Under EMARS II, industry would nominate

leasing tracts, indicating the type, amount, and

location.

Both the final impact statement and the

EMARS II program were criticized severely.

The General Accounting Office noted, among

other deficiencies, that the Department of the

Interior was assumin g its traditional role of

reacting to industry proposals rather than manbNatural Resources Defense Council v, Hughes, 7 E.L..R.

20785 (D. D. C., 1977).

aging national energy resources. 7 In September

1977, a Federal court enjoined Interior from

taking any steps whatsover, directly or indirectly, to implement the new coal leasing

program, and ordered the Department to correct the deficiencies in the final EIS and to circulate the revised statement for review and

comment.

8 Until the new E IS is completed —

which Interior indicates will be not earlier than

mid-1 979 — no long-term Federal coal leasing

will occur.

Development of a New Federal Coal

Leasing Policy

In 1976, Congress passed the Federal Coal

Leasing Amendments Act’ to address the deficiencies of the Mineral Leasing Act of 1920.

The 1976 amendments discourage speculation

by making leases more difficult to obtain and

to hold cheaply. Federal leases now must be

developed within 10 years or they terminate

automatically, they cannot be issued for less

than their fair market value, and mimum royalties are set. In addition, all leasing must be

by competitive bidding with 50 percent leased

under a deferred bonus bidding system that

makes it easier for small companies to compete. Preference-right leases are abolished,

and no person or corporation may hold more

than 100,000 acres of leases.

The amendments also contain various provisions to encourage land use and environmental

planning, including the creation of “logical

mining units. ” In addition, one-half of all

royalties must be turned over to the States to

provide public services and mitigate community impacts. Finally, the Department of the interior is directed to conduct a comprehensive

exploratory program to determine the extent

of Federal coal reserves.

In 1977, BLM promulgated regulations to implement the Federal Coal Leasing Amendments

Act. Because they are so recent and because

7Ro/e of Federa/ Coa/ Resources in Meeting Nationa/

Energy Coals Needs To Be Determined and the Leasing

Process Improved (Washington, D. C.: General Accounting Office, U.S. Comptroller General, April 1976)

aNRDC v. Hughes.

9

30 USC. 201-209.
342 ● The Direct Use of Coal

new leasing has been almost nonexistent since

1970, the degree to which they will remedy

past abuses is unclear. However, it already is

obvious that a number of the regulations are

confusing and may have to be clarified or revised.

In his May 1977 environmental message,

President Carter directed the Secretary of the

Interior to undertake a major review of Federal

coal leasing policy. In particular, the Secretary was directed to ensure that the Department of the Interior could respond to reasonable production goals while leasing only those

areas where mining is environmentally acceptable and is compatible with other land uses.

Special attention is to be given to existing

leases that are nonproducing or environmentally unacceptable.

In response to this directive and to a request

by the court that enjoined EMARS II, the Department of the Interior created a Federal Coal

Management Review Policy Committee. ’ The

committee has undertaken 13 management

tasks in response to the Presidential directive.

One of its first products is a paper that outlines

three options for an overall approach to longterm leasing: industry nomination of both

areas and tracts for leasing, Government identification of areas with industry nomination of

specific tracts, and Government selection of

both areas and tracts. 2

Until the committee’s work is complete, it is

unclear what direction the new Federal coal

leasing policy will take, or which, if any, of

these three options will be adopted. However,

the Secretary of the Interior has stated that the

new Federal policy will restrict coal Ieasing to

those areas where the Federal Government

owns the surface rights. 3

‘“ The President’s Environmental Program (Washington,

D C : Council on Environmental Quality, 1977).

11Federal Coal Management Review Policy P/an (U.S.

Department of the Interior, unpublished, July 25, 1977),

12 Memorandum to the Secretary of the Interior From

the Deputy Executive Secretary on Department/ Approach for the Long-Term Coal Leasing Program: Decisionmaking (unpublished, Oct. 17, 1977)

13 ’220 Energy Users Report 24 (Oct. 22, 1977).

Problem Areas

Many of the problems that still must be resolved by the Federal Coal Management Re

view Policy Committee, the Department of the

Interior, and Congress are carryovers from

earlier leasing policy. They include logical

mining units, preference-right lease applications, the requirements of diligent development and continued operation, estimated

recoverable reserves, advance royalty payments, and the exchange of environmentally

sensitive leased lands for other unleased

Federal land.

A logical mining unit (LMU) is a contiguous

area of coal land under the control of one

operator that can be developed effectively

and mined within a defined period of time. The

theory of LMU makes sense; it asserts that national Ieasing policy should consider the

nature of the coal resource in each case and

then assemble the physical resources necessary to produce the coal economically while

preserving environmental safeguards. However, the regulations promulgated by BLM to

implement the Federal Coal Leasing Amendments Act depart from this theory in two respects. First, under the regulations, boundaries

of an LMU are set according to the legal

boundaries of leases rather than according to

natural formations of the coal seam. Second,

an LMU is required to produce a fixed amount

of coal each year without regard to the individual characteristics of each coal mining operat ion.

Technical problems also surround the formation of LMUS. The Secretary of the Interior

does not appear to have the authority to order

private, State, or Indian lands to be combined

with Federal leases to form an LMU nor does

the Secretary have the authority to divide existing leases into several LMUS. In addition,

practical and legal problems may arise from

the requirements that all lands in an LMU be

contiguous and that the holders of existing

leases must consent to their inclusion in an

LMU. Finally, industry representatives have

argued that the congressional mandate that all

reserves in an LMU be mined within a 40-year

period may result in inefficiencies in some circumstances.
Ch. V1l—Present federal Coal Policy ● 343

Much uncertainty and controversy also surrounds the preference-right lease applications

(PRLAs). At present, there are approximately

180 outstanding PRLAs covering an estimated

9 billion tons of coal on 446,000 acres. The Department of the Interior contends that it must

issue a PRLA when a permittee has established

that the land contains commercial quantities

of coal. “Commercial quantities” was interpreted as coal “of such character and quantity

that a prudent person would be justified in the

further expenditure of his labor and means

with a reasonable prospect of success in developing a valuable mine . .’”14 Some critics have

questioned the appropriateness of the prudent

person test and suggested the substitution of a

“workabiIity” or “paying quantities” concept.

Others have asserted that, in addition to the

commercial quantities test, Interior must consider environmental impacts before issuing a

PRLA. Finally, even if all the foregoing issues

are resolved quickly, it wiII take years to process the pending applications. It appears that a

minimum of 5 to 7 years will pass before any

coal can be produced from PRLA tracts.

A number of problems also exists in the regulations that implement the requirements for

diligent development and continued operation

of leases. First, the reguIations define those requirements in terms of LMUS, yet old leases

cannot be designated as LMUS without the

consent of the lessees. The Department of the

Interior has taken the position that it can designate an old lease as an LMU when it is readjusted despite statutory language that suggests

that the consent of the lessee is required. Second, it is not clear that the present definition

of diligent development, which does not require periodic reports, will prevent lessees

from holding land for long periods of time

without substantial development.

Additional problems exist in implementing

the concept of estimated recoverable reserves.

Many of the key terms in the coal leasing

regulations are defined in terms of this concept, but there is no commonly accepted definition of “estimated recoverable reserves” and

various organizations compute reserves in dif -

“41 F R 18847 (May 7, 1976)

ferent ways at different times, As a result, industry and Government estimates can vary by

as much as 100 percent. Moreover, the present

regulatory scheme provides Federal leaseholders with strong incentives to underestimate

their recoverable reserves.

Finally, problems exist in the regulations

designed to implement those portions of the

1976 amendments that relate to advance royalty payments and exchanges of land or leasing

rights. The protection afforded by advance

royalty provisions of the amendments appears

to have been diluted by the Department of the

Interior regulations that grant the Mining

Supervisor blanket authority to permit advance royalty payments in lieu of continued

operation without requiring a specific finding

that such a substitution would be in the public

interest. I n addition, Interior currently is

developing regulations that would authorize

the exchange of Federal land under lease or

subject to a PRLA for future bidding rights. The

Department would prefer the broader authority to exchange leases in environmentally sensitive areas for other unleased land as well as

for future bidding rights.

Surface Mining Control and

Reclamation Act of 1977

Many surface mining operations result in

disturbances that adversely affect commerce

and the public welfare by destroying or diminishing the utility of land for commercial, industrial, residential, recreational, agricultural, and

forestry purposes. Many operations have

caused erosion and landslides, contributed to

floods, polluted the water, destroyed fish and

wildlife habitats, impaired natural beauty,

damaged private property, and undercut Government policies and programs to conserve

soil, water, and other natural resources. The

existing State regulatory programs intended to

deal with these impacts varied widely and

often were not enforced adequately. These

findings, and others, formed the basis for congressional action leading to passage of the Sur- “

face Mining Control and Reclamation Act

(SMCRA) of 1977. ’5 A detailed analysis is

presented in volume 11, appendix XVI 1.

‘ 5

30 U S C 1201 et seq
344 The Direct Use of Coal

Based on the assumption that mining should

be a temporary activity, the Act was intended

to change coal mining practices that generate

severe social and environmental costs and to

prohibit mining operations in areas that cannot

be reclaimed. To accomplish these goals, the

Act mandates State permit programs for surface mines and for the surface operations of

underground mines and State procedures for

designating areas unsuitable for mining. In the

interim, or in the event of a State’s failure to

establish an adequate program, the Federal

Government will retain regulatory authority. In

addition, the Act establishes a fund for the reclamation of abandoned mines.

This section discusses the permit programs

for surface and underground mining. Mandated procedures for designating areas as unsuitable for mining are discussed in chapter IV.

Each application for a surface coal mining

and reclamation permit must include detailed

information about the type and method of

coal mining operation, engineering techniques,

and equipment to be used; the probable hydrologic consequences of the mining and reclamation, both on and off the minesite; any manmade features or significant archeological

sites that may be affected by mining; the geological and physical characteristics of the coal,

including a chemical analysis of potentially

acid- or toxic-forming strata; a soil survey of

potential prime farmland; and the reclamation

plan.

The probable hydrologic consequences of

mining and reclamation must be determined

relative to the hydrologic regime and the quantity and quality of surface and ground water

systems including dissolved and suspended

solids under seasonal flow conditions. Sufficient data must be collected to enable the

regulatory agency to assess the probable

cumulative impacts of all mining in the area

on hydrology and water availability.

The reclamation plan must describe the condition of the land prior to mining including its

existing and potential land uses and its productivity as well as its average yield of food, fiber,

forage, or wood products under optimum management. The plan also must specify the proposed postmining land use and describe in

detail how this use will be achieved including

the engineering techniques and equipment to

be used, the cost per acre of reclamation, and

a detailed timetable for accomplishing reclamation. In addition, the plan must describe

the means of compliance with applicable air

and water quality and health and safety regulations.

All surface mining permits issued under the

Act must require that the coal mining operations meet all applicable environmental protection performance standards. These standards govern the maximum recovery of fuel; restoration of the land to its original contour; use

of explosives; waste disposal, including the use

of waste piles as dams or embankments; construction of access roads; and revegetation.

Additional, more stringent standards apply to

environmentally sensitive areas such as prime

farmland, steep slopes, alluvial valleys, and

timber lands.

Permits for underground mining must also

require the mine operator to prevent subsidence to the extent possible, seal all openings

to the surface, and prevent acid or other toxic

drainage.

Enforcement of SMCRA’S performance

standards and reclamation plans will play a

critical role in determining the impact of the

Act on coal production and environmental

quality. As with administration of other

SMCRA provisions, enforcement can be delegated to States if their mining standards and

reclamation requirements are at least as stringent as the national standards. If this strategy

of delegating the primary enforcement role to

the States is successful, the Federal Office of

Surface Mining (OSM) would not require largescale enforcement resources. If the strategy

does not succeed, the ability of OSM to enforce the Act adequately is uncertain. During

interim enforcement of the Act by OSM, about

160 inspectors were responsible for ensuring

compliance at more than 3,900 surface mines

and approximately 2,550 underground mines

(or approximately 1 inspector per 35 surface

and per 56 underground mines).

An inadequate inspection force will result in

an inability to make the required number of in-
Ch. V1l—Present Federal Coal Policy ● 345

spections and therefore an emphasis on “problem mines” and flagrant violations. It is doubtful that all problem mines will be identified;

those mines that are not inspected as frequently as required could escape strict compliance

with the Act.

Other issues related to enforcement of

SMCRA include the availability and adequacy

of performance bonds, which are intended to

secure compliance with the Act. The amount

of a bond depends on the characteristics of the

site, but must be sufficient to cover completion of the reclamation plan if the work had to

be performed by the regulatory agency. Where

reclamation is difficult and therefore expensive, performance bonds may be difficult to

secure. The Small Business Administration,

which guarantees bonds from private sureties

in other industries, reportedly does not plan to

do so for coal mine reclamation. ” I n addition,

where the adverse impacts of mining may not

become apparent until long after mining has

ceased (for example, acid drainage from underground mining), the period of liability may

be insufficient.

The mining industry has been highly critical

of SMCRA. The principal complaints include

the complexity and detail of the regulations

and the resulting increased costs of mining and

reclamation. The industry argues that the Act

and OSM’s draft regulations are too detailed

and do not permit a mine operator to tailor the

engineering designs to site specific factors.

The result, according to industry, will be substantial increases in the cost of mining and reclamation, and therefore in the cost of coal.

Many of these requirements will be made more

flexible in OSM’s final regulations, issued

spring of 1979. However, much of the specificity is written into the Act itself and must be

changed legislatively. Once these changes

have been made, the cost increases attributable to SMCRA probably will not be substantial enough to limit either the supply of or demand for coal. For example, OSM’s cost analysis of the discretionary portions of the Act

(that is, excluding the requirements that were

“’’Excessive Regulation Drowns the Industry, ” Coal

Age, January 1979, pp. 11-13.

specified by Congress) indicates that their final

regulations would result in only a 0.25-percent

increase in the cost of electricity to the average residential customer in 1985.7

The Federal Mine Safety and

Health Act of 1977

The hazards in mining coal and other materials, and the need to provide for the health and

safety of the Nation’s miners, have long been

matters of Federal law. The Federal Mine Safety and Health Act of 1977’s is the most recent

expression of congressional intent to remedy

unsafe conditions and practices and to reduce

the number of mining fatalities and injuries.

The 1977 Act is based on the Federal Coal

Mine Health and Safety Act of 1969; it incorporates many of the provisions of the 1969 Act

but increases the level of protection for

miners.

The 1969 Act complemented the earlier

Metal Act, ’” which regulated the occupational

health and safety of all miners except coal

miners, and represented a direct response to

the number of deaths and serious injuries from

unsafe and unhealthy conditions and practices

in coal mines. To remedy these abuses, the Act

established interim mandatory health and safety standards and directed the Departments of

the Interior and of Health, Education, and

Welfare to develop permanent standards; to

ensure that mine operators comply with those

standards; to provide benefits for victims of

black lung; and to assist the States in developing and enforcing effective health and safety

programs.

Implementation and enforcement of the

mandatory standards established under the

1969 Act resulted in dramatic decreases in the
346 ● The Direct Use of Coal

number of coal mine fatalities and injuries.

However, a 1974 report on occupational safety

and health21 found that the incidence of workrelated injuries and illnesses for miners still exceeded the “all industry” rate by about 14 percent. Work-related deaths showed, even more

forcefully, the continuing inadequacy of mine

safety and health laws and their enforcement.

According to this report, about 1 of every 1,500

mine workers was killed on the job or died

from work-related injuries or illnesses in 1973.

This compared with 1 of every 2,800 railroad

workers, 1 of every 4,000 construction workers,

and only 1 of every 12,400 for al I workers covered by the Occupational Safety and Health

Administration.

In 1977 the Senate Committee on Human

Resources drew a number of conclusions from

its oversight of the Metal Act and the 1969

Coal Act:

First, the Metal Act does not provide effective protection for miners from health and

safety hazards and enforcement sanctions

under that Act are insufficient to encourage

compliance by operators.

Second, enforcement of safety and health

laws should be the responsibility of agencies

which are generally responsible for the needs

of workers.

Third, both the Coal and the Metal Acts do

not provide means to react quickly enough to

newly manifested health hazards.

Fourth, the procedures by which safety and

health standards are made under both the

Metal and the Coal Act are much too slow and

cumbersome for standards promulgated under

those Acts to keep pace with developments in

a dynamic and expanding industry.

Fifth, the assessment and collective civil

penalties under the Coal Act have resulted in

penalties which are much too low, and paid

much too long after the underlying violations

to effectively induce meaningful operator

compliance.

Sixth, enforcement sanctions under the current laws are insufficient to deal with chronic

violators. 22

“Annual Report on Occupational Safety and Health

(Washington, D. C.: U.S. Department of Labor, Occupational Health and Safety Administration, 1974).

‘

zSenate Report No. 95-181, 95th Cong., 1st sess., Federal Mine Safety and Health Act of 1977, p. 7.

By enacting the Federal Mine Safety and

Health Act of 1977, Congress combined protection of all miners under a single comprehensive law that adopts the best features of both

earlier statutes relative to health and safety.

Insofar as the 1977 Act’s objectives affect coal

mine productivity, the Act adopts the consensus of labor and industry witnesses that a safe

coal mine is also a productive mine. The resuiting extensions of regulatory power in coal mining are more the product of technical improvements in the standard-setting and enforcement

process than substantial departures from prior

law.

The 1977 Mine Safety and Health Act

adopted the provisions of the 1969 Act that

prescribed mandatory health and safety standards and provided black lung benefits. That

these parts of the Act were not appreciably

altered is consistent with the legislative intent

that standard-setting and enforcement procedures be made uniform throughout the mining

industry whiIe the standards themselves remain responsive to the characteristics of different segments of the industry.

Although much of the 1969 Coal Act remains as it was, several important changes are

expected to increase the level of safety and

health protection in the Nation’s coal mines:

standard-setting and enforcement provisions

were made more effective, admininstration

was transferred from the Department of the Interior to the Department of Labor, the Federal

Mine Safety and Health Review Commission

was established, mandatory health and safety

training of miners was instituted, and the exercise of safety and health rights by miners was

given added protection and support.

Past procedures for promulgating and revising standards in both the Metal and the Coal

Acts had resulted in long delays between the

perception of needed improvements and the

implementation of new or revised standards.

Each step in the process now requires compliance within a specified period. Enforcement

procedures now also must comply with a more

rigorous timetable.

A key element of the 1977 Act is the shift of

administration from the Department of the In- ‘
Ch. V1l—Present Federal Coal Policy ● 347

terior to the Department of Labor, Interior’s responsibility for maximizing energy resource

development was found to be incompatible

with concurrent responsibilities for enforcing

mine safety and health regulations; the Labor

Department was perceived as having but one

purpose: the welfare of the workers. The responsibilities of Interior’s Mining Enforcement

and Safety Admininstration also have been

transferred to the Department of Labor, where

an Assistant Secretary for Mine Safety and

Health will preside over the new Mine Safety

and Health Admininstration.

Under the 1969 Coal Act, review of contested matters was an internal function of the

Secretary of the Interior, who established a

Board of Mine Operations Appeals to separate

prosecutorial and investigative functions from

his adjudicatory functions. With the transfer of

administration to the Department of Labor, a

similar system was considered but ultimately

rejected. While recognizing organizational and

administrative drawbacks, Congress was persuaded to establish a completely independent

adjudicatory authority, the Mine Safety and

Health Review Commission. An independent

commission was considered essential to provide administrative adjudication that preserves due process and instills more confidence in the program. Affected miners or their

representatives have an opportunity to participate in the Commission’s proceedings, and

it is the intent of Congress that the Commission

develop procedures to facilitate the participation of parties appearing pro se or not represented by counsel. This attention to adjudicative detail and purpose is better suited to serving both the interests of the parties and the

underlying purposes of the Act.

One of the historic problems in the American coal industry has been the inadequate

training afforded coal miners. Many miners

stilI go underground with Iittle or no training

and, until very recently, the Federal requirements for training were weak. The 1977 Act

provides for at least 40 hours of training for

new underground miners, 24 hours for new surface miners, and 8 hours per year of refresher

training for all miners. Miners must be paid

their normal rate of pay and any costs incurred

while attending this training. If an inspector

determines that any miner has not received the

requisite training, then the miner must be withdrawn from the mine until his training is complete. Any miner so withdrawn may not be discriminated against by the operator and is entitled to fulI compensation during the training.

Congress expressed its displeasure with the

Interior Department’s repeated attempts to

restrict miners’ protection from retaliation for

engaging in safety activity by changing not

only the substantive aspects of the antidiscrimination provisions but also the procedural

aspects. Under the new provisions, once a

complaint is filed, the Secretary must conduct

an investigation. If as a result of the investigation the Secretary believes that a violation has

occurred, the Secretary must file to intervene

in the proceedings and attempt to prove to the

Commission that a violation has occurred. If

the Secretary concludes that no violation occurred, the miner can still prosecute a case

before the Commission. Even where the Secretary participates in the proceedings, the miner

has the right to offer evidence, cross-examine

the respondent’s witnesses, and generally participate as a party. In both the 1969 Act and

the 1977 Act, the miner is entitled to an award

of attorney’s fees if a violation of the antidiscrimination provision is proved. The 1977

Act, in clearly setting out the procedural steps

in an antidiscrimination proceeding and clearly delineating the role of the Secretary, has

greatly strengthened the antidiscrimination

provision.

One of the most valuable provisions in the

1977 Act is the possibility of temporary reinstatement. Under the 1969 Act, miners often

were severely disadvantaged if they chose to

prosecute complaints, including significant

economic hardship during the 1 or 2 years it

might take to litigate their claims. The 1977

Act solves this problem by requiring the Secretary to make an initial determination, after a

factual investigation of a discrimination complaint, as to whether the miner’s complaint is

frivolous. If the Secretary determines that the

complaint is not frivolous, the Secretary must
348 ● The Direct Use of Coal

petition the Commission for temporary reinstatement of the miner, and the Commission

must order reinstatement absent a showing of

bad faith on the part of the Secretary. This simple measure should go a long way in providing

practical protection for the miners who exercise their safety rights and are discharged as a

result.

Both the 1969 and the 1977 Acts provide for

reinstatement with back pay for discharged

miners who prevail on their discrimination

claims. The 1977 Act also provides for interest

on an award of back pay to compensate miners for the loss of wages during Iitigation.

The loss of income that occurs when a miner

is fired presents serious problems that back

pay and interest alone may fail to remedy.

Neither the 1969 Act nor its legislative history

explicitly provided for the award of special

damages to a miner who had been discriminated against for attempting to enforce safety

rules. Not surprisingly, the Interior Department

never exercised its discretionary authority to

award special damages, even where clear economic damages resulted from a discriminatory

act. The legislative history of the 1977 Act rejects the Interior Department position and specifically authorizes the award of special damages. In addition to compensatory relief, the

1977 Act anticipates the use of affirmative relief, such as a cease and desist order, where appropriate.

The Federal Mine Safety and Health Act of

1977 is not a major departure from prior law

governing the operators of the Nation’s coal

mines, Those most affected wilI be miners employed in other mining sectors and mine operators. The present law does represent an incremental improvement, however, in what is an

ongoing congressional effort to reduce mining

deaths and injuries to the lowest practicable

levels. In addition to the major changes already discussed, several smaller amendments

in the law can be expected to further these objectives.

For example, the definition of a mine “operator” is expanded to include any independent

contractor performing construction services at

a mine. Thus, employees of mine construction

contractors now are considered miners and the

Secretary should be able to issue citations,

notices, and orders, and the Commission

should be able to assess civil penalties, against

these contractors. Statistics on mine-related

deaths and injuries also will be more accurate

because these contractors previously were not

required to comply with recordkeeping and reporting obligations.

I n addition, some penalties have been made

more harsh, the collection of fines has been facilitated by an 8-percent interest charge, and

an additional enforcement mechanism, injunctive-type relief, has been adopted to provide a

flexible method of dealing with habitual or

chronic violators of the Act.

Because the 1977 Act is modeled on its predecessor, the Mine Health and Safety Act of

1969, no substantial adaptations by the coal industry appear necessary. While noncoal mining operations previously subject to the Metal

Act may face adjustment difficulties, coal industry and labor familiarity with the prior law

should permit a relatively smooth transition.

Increased operating costs may result from

mandatory safety and health training, but

whether the total additional costs directly

associated with the legislation represent a net

loss to the operators remains unclear,

Costs and benefits associated with safety

and health regulations have been difficult to

define accurately. If productivity can be improved as a result of vigorous Federal enforcement and operator compliance, all parties will

benefit. If productivity remains unchanged or

declines, however, coal consumers can be expected to share the burdens of improving the

safety and health of the Nation’s miners. Not

unmindful of these costs, Congress has nevertheless declared mine safety to be an overriding concern, and the several changes described

can be expected to lessen the annual rate of

mining deaths and injuries.
Ch. VII—Present Federal Coal Policy ● 349

The Clean Air Act

In drafting the Clean Air Act Amendments of

1977, 23 Congress was aware of the related but

often conflicting demands of environmental

and energy policies. However, the amendments do not always refIect a consistent unified approach to the fundamental problems involved, and the overaIl effect of the Act is difficult to assess. To the extent that coal-fired facilities have a greater potential for emitting air

pollutants than do facilities using other energy

sources, they may require greater expenditures

for pollution control equipment under the Act

or be subject to stricter siting and other preconstruction review procedures and thus may

be at a competitive disadvantage. On the other

hand, some provisions of the Act exempt coalburning sources from regulatory restrictions

applicable to other fuels. Still other provisions

limit the growth and development of all stationary sources in certain areas.

It is not possible to quantify the impact of

any of these provisions on increased coal use,

much less to assess their combined impact.

Such an analysis would require a major technical and economic inquiry. Rather, this section

identifies and briefly discusses the nature of

the Clean Air Act provisions that affect the use

of coal by new fossil-fuel-fired sources as well

as the conversion from oil or gas to coal by existing sources. Some of these provisions have

been in effect since 1970; others are included

in the 1977 amendments.

Background and History

Before 1970, air pollution control essentially

was left to the States, with the Federal Government providing technical and financial assistance for planning and for R&D. The Clean Air

Act Amendments of 197024 inaugurated direct

Federal regulation, mandated specific State

implementation plans (SIPs), and required Federal intervention in the absence of State action.

The 1970 amendments represented a balance between uniform national requirements

and the preservation of States rights. Those

factors that were deemed to require national

uniformity in order to prevent regional subversion of the Act’s goals or regional economic

advantages included numerical standards for

how clean the air must be and for emissions of

airborne polIutants from future sources as well

as guidelines for air quality control plans. The

States were required to devise and implement

plans in accordance with these guidelines for

achieving and maintaining the specified levels

of air quality. The Act also allowed the States

to set more stringent standards. This fundamental role division continues under the 1977

amendments, which were intended to remedy

problems that had developed under the 1970

Act and to strengthen some regulatory programs.

National Ambient Air Quality Standards

The central feature of the 1970 Clean Air Act

Amendments was the requirement that EPA

promulgate National Ambient Air Quality

Standards (NAAQS). NAAQS define air quality

in terms of ambient concentrations of pollutants. These standards represent target levels

for air quality; they do not regulate emissions

from individual sources. The amendments required two sets of standards that reflected the

latest scientific knowledge about the effects of

various air pollutants. Primary standards were

intended to protect public health; secondary

standards were designed to protect the public

welfare from polIution damage to soils, vegetation, animals, materials, and other environmental factors not related to human health.

Pursuant to the 1970 amendments, the EPA

Administrator listed six pollutants as having

potentially adverse effects on public health

and welfare and established primary and secondary NAAQS for each. Standards have been

established for sulfur oxides (SOX) (measured

as sulfur dioxide (S02

)), particulate matter, nitrogen dioxide (N02

), hydrocarbons, photochemical oxidants, and carbon monoxide (CO);

standards for lead were proposed in 1978.

Under the 1977 amendments, these standards

are to be reviewed and revised if necessary

every 5 years beginning in 1980. The standards

for SOX

, particulate matter, and NO2,, the pri-
350 The Direct Use of Coal

mary byproducts of coal combustion, are

listed in table 58.

Table 58.—Standards for Particulate Matter,

Sulfur Dioxide, and Nitrogen Dioxide

Averaging Primary Secondary

Pollutant time standard standard

These ambient air quality standards are implemented at the national level through standards of performance for new stationary

sources and guidelines for State control strategies for existing sources as well as through

guidelines for regulatory programs designed to

improve air quality in areas that have not attained the national standards, to prevent degradation of air quality in areas cleaner than the

national standards, and to protect visibility in

important scenic areas.

The State role centers on the preparation

and implementation of a plan, consistent with

EPA guidelines, that sets out control strategies

for meeting and maintaining NAAQS in various parts of the State (known as air quality

control regions (ACQRs)). States have considerable discretion in deciding what emission

limitations and other controls on individual

sources to use in cleaning up their air, as long

as their SIPs are shown to be capable of

achieving the national standards.

The 1970 Act required the States to attain

the primary standards as expeditiously as practicable but not later than 3 years after the date

the S1P became efective. The S1Ps also were re

quired to specify a reasonable time at which

the secondary standards would be achieved;

“reasonable time” was defined by EPA to depend on the degree of emission reduction

needed to attain the standards and on the

social, economic, and technological problems

involved in doing so. However, as of 1977, 116

of the 247 ACQRS reported violations of the

primary annual particulate standard while 108

reported violations of the 24-hour standard.

Similarly, 12 ACQRS reported violations of the

primary annual S02 standard while 37 reported

violations of the 24-hour standard. zs The 1977

amendments require the States to revise their

S1Ps by 1979 in order to provide for attainment

of the primary standards by 1982. However,

the amendments did not change the “reasonable time” requirement for achieving the secondary standards.

New Source Performance Standards

The Clean Air Act Amendments of 1970 required the EPA Administrator to establish

standards of performance for large new or

substantially modified stationary sources to

ensure that they would not exacerbate existing

air quality problems or contribute to new ones.

Under the 1970 Act, New Source Performance

Standards (NSPS) included federally determined allowable rates of emissions from 19

categories of sources. S1Ps were required to include a procedure for preconstruction review

of new sources to ensure that these standards

were met.

The 1977 amendments significantly tightened these requirements. In order to meet

NSPS, 28 categories of sources now must apply

the best technological system of continuous

emission reduction that has been demonstrated adequately. In addition, fossil-fuelfired sources are subject to an enforceable

percentage reduction in emissions that would

have resulted from the use of untreated fuels.

In determining which technological systems

of continuous emission reduction have been

demonstrated adequately, the EPA Administrator is required to consider the energy requirements of a technology as well as its cost and

any nonair quality health and environmental

impacts. I n calculating the percentage reduction requirements, the Administrator may give

2543 F,R, 8962 (Mar. 3, 1978).
Ch. VII—Present Federal Coal Policy ● 351

credit for mine-mouth and other precombustion fuel-cleaning processes. NSPS have been

promulgated for fossil-fuel-fired steam generators and for coal preparation plants. EPA

plans to announce new standards for industrial

boilers in 1980.

As discussed in chapter IV, the NSPS provisions in the 1977 amendments have become

controversial. If the final regulations require

continuously operating flue-gas desulfurization (FGD) systems, it probably will promote

the use of locally available high-sulfur coals,

especially in the Midwest, while removing the

advantage that accrued to low-sulfur coal

under the previous regulations. 1 n addition, a

continuous control requirement could delay

the construction of new coal-fired powerplants, causing a greater reliance on exisiting

plants than would have occurred under the

previous regulations. zb Regardless of whether

the final regulations require full, partial, or a

sliding-scale control, they will increase the pollution control costs of new coal-fired plants.

Nonattainment Areas

The 1970 Clean Air Act Amendments did not

specify the consequences of a State’s failure to

attain NAAQS by the deadline While EPA regulations promulgated in 197627 filled this gap

to some extent, it was clear that congressional

guidance was necessary. Consequently the

1977 amendments add new requirements that

must be incorporated into all SIPS by July

1979.

The 1977 amendments basically adopt EPA’s

1976 offset policy for nonattainment areas until July 1979. In general, this policy imposes the

following conditions for the issuance of construction permits for new or modified sources

in nonattainment areas: the source meets the

lowest achievable emission rate (LAER), the

permit applicant certifies that all its other

facilities are in compliance with all applicable

Clean Air Act control requirements, the permit

applicant has secured emissions reductions

from existing sources that more than offset the

emissions from the proposed source, and a

2643 F R. 42154 (Sept 19, 1978)

2741 F R 55524 (Dee 21, 1976).

positive net air quality benefit results. LAER

must reflect the most stringent emission rate

required by any State or the lowest rate

achieved in practice, if the latter is more stringent. In no event, however, may emissions

from a source subject to LAER be allowed to

exceed the applicable NSPS.

This offset policy applies to any source

capable of emitting 100 tons per year of a pollutant that would exacerbate an existing

NAAQS violation. EPA has announced that it

will implement the policy through the use of

significance levels patterned after the prevention of significant deterioration (PSD) increments (see below). A source will not be considered to exacerbate air quality problems if its

emissions are below the specified significance

level. ”

Whether a source is subject to the offset

policy is determined on a case-by-case basis

through air quality modeling. Thus a source

still could be located in an AQCR with localized violations so long as its emissions will not

exacerbate those local violations.

After June 30, 1979, construction of new or

modified stationary sources that would adversely affect air quality in nonattainment

areas must be prohibited unless the applicable

SIP meets the requirements of the 1977 amendments. SIP revisions must provide for attainment of the primary standards not later than

1982, and in the interim must require annual incremental emissions reductions from existing

sources through the implementation of reasonably available control measures.

As with the new NSPS requirements, EPA’s

offset policy is controversial. It places significant constraints on siting in many areas because the offsetting reductions are difficult to

obtain and LAER is expensive to meet; siting

constraints could become even more severe if

SIP revisions are not accomplished in a timely

manner. I n addition, most industries feel it is

inappropriate to place the burden of securing

emission reductions on the private sector

*44 F.R, 3274 Jan 16, 1979).
352 The Direct Use of Coal

rather than on Government. 29 Although many

States are expected to adopt E PA’s offset policy in their SIP revisions, they are being encouraged by EPA to experiment with alternative programs for cleaning up “dirty air” areas,

such as emission taxes, or banking of emission

reductions to allow for future growth. 30

Prevention of Significant Deterioration/

Visibility Protection

The 1970 Clean Air Act Amendments merely

required EPA and the States to achieve and

maintain NAAQS; they did not address the

question of air quality in areas already cleaner

than NAAQS require. In 1972 environmental

groups brought suit against EPA to prohibit the

Agency’s approval of S1Ps that failed to prevent significant deteriorate ion of air quality. Relying on the Act’s stated purpose of protecting

and enhancing the Nation’s air quality, the

court ordered EPA to develop a program to

prevent the degradation of air quality in clean

air areas. EPA’s PSD regulations were promulgated and incorporated into all SIPS in

1974, and were adopted with some changes in

the 1977 amendments.

In general, the PSD program divides clean

air areas into three classes and specifies the

maximum allowable increases in ambient concentrations of pollutants, or PSD increments,

for each class.

As discussed in chapter IV, construction of a

major emitting facility (defined to include

most large fossil-fuel-fired steam electric

plants and other coal-burning sources) that will

affect air quality in a clean air area is subject

to extensive preconstruction review and permit requirements. Review of a permit application must be preceded by an analysis of the

ambient air quality at the proposed site and in

areas within 50 km downwind that may be affected by emissions from the proposed facility.

The PSD regulations could constrain the

development of coal combustion facilities in

two main situations: where the difference between the baseline concentration and the maximum allowable increase already is lower than

the applicable increment, and where sources

that are exempt from PSD review (because of

their size or date of construction) will use up

available increments. However, a 1975 Federal

Energy Administration (FEA)/E PA study of the

effects of the then-pending PSD legislation on

the electric utility industry concluded that the

requirements would not significantly hamper

siting of even the largest sources of air pollution. J2 These conclusions are summarized in

appendix XVI of volume 11. In addition, the

study analyzed the economic impacts of PSD

requirements on the utiIity industry; it concluded that the industry’s total capital requirements and annual operating costs as well as

the costs to consumers would increase less

than 3 percent to the year 1990.

Siting considerations also could be affected

by regulations intended to protect visibility in

Class I areas (national parks and wilderness

areas subject to the lowest PSD increments)

primarily valuable for scenic factors. The 1977

amendments established a national goal of

preventing any future—as well as remedying

any existing— impairment of visibility in these

areas. By August 1979, EPA is required to promulgate regulations to assure reasonable progress toward meeting the national goal, taking

into account the economic, energy, and environmental costs of compliance. In addition,

States must revise their SIPs to require all existing major stationary sources constructed in the

last 15 years to install the best available retrofit technology for controlling emissions that

may impair visibility. A principal contributor

to reduced visibility is fine particulate matter;

these particles are not captured by the current

technology-of-choice, electrostatic precipitators. Their control may require the use of

baghouses, a costly alternative. However, the

Act does provide exemptions for sources that

‘

2An Analysis of the Impact on the Electric Utility Industry of Alternative Approaches to Significant Deterioration (Washington, D.C : Federal Energy Administration

and Environmental ProtectIon Agency, October 1975)
Ch. VII—Present Federal Coal Policy ● 353

can demonstrate that they will neither cause

nor contribute to a significant impairment of

visibility in mandatory Class I areas, or where

the costs of compliance would be too high (for

example, if the source is scheduled for retirement soon). Until the final regulations are published, it is not possible to estimate the extent

to which visibility protection requirements will

constrain increased coal consumption.

EPA Studies and Potential New Standards

I n adopting the 1977 amendments, Congress

directed EPA to undertake an extensive review

of existing standards and to study potential

new standards. To the extent that E PA’s efforts

result in tightening existing standards or in promulgating new standards, these provisions may

impose new and potentially costly constraints

on the use of coal. At this time, however, it is

possible only to identify the areas of potential

concern.

The amendments require EPA to review air

quality criteria and NAAQS by the end of 1980,

and every 5 years thereafter, and to revise the

criteria and standards as appropriate. Any revision of a NAAQS for a pollutant may result in

major changes in SIPs and control requirements applicable to sources of that pollutant.

I n addition, the amendments direct EPA to promulgate a 3-hour primary standard for NO2

,

unless EPA determines that there is no significant evidence that this standard is necessary.

A stringent short-term NO2 standard may require flue-gas denitrification, a technology

that is not expected to be available until after

1985.

Another provision of the amendments requires EPA, in conjunction with the National

Academy of Sciences, to complete a study of

the health effects of fine particulate; preliminary findings will be published by June 1979.

The amendments also require EPA to determine whether emissions of radioactive pollutants, cadmium, arsenic, and polycyclic organic

matter may endanger public health. If EPA

finds that these emissions do pose a hazard to

human health, then EPA must establish air

quality standards, NSPS, or hazardous pollutant standards for them. For radioactive pollutants, EPA must make this determination by

August 1979; background documents on the

sources, health effects, population exposures,

and risks associated with the other pollutants

were available for public comment in spring

1978. All of these pollutants are present in

trace amounts in the fly ash of coal emissions;

moreover they are concentrated preferentially

on the fine particulate matter that conventional control technologies do not remove effectively. Baghouses entailing large costs and

space requirements would be required to capture these materials if the standards mandated

highly efficient removal.

Finally, EPA currently is developing a standard for the control of sulfates, a transformation product of S0x. Sulfates also adhere to

fine particulate and contribute to visibility

impairment and acid precipitation, primarily

in the Northeast. A stringent sulfate standard

may impose severe constraints on new coalfired sources in the Eastern United States.

Interface With Energy Legislation

The Energy Supply and Environmental Coordination Act (ESECA) of 19743

’ (discussed below) amended the Clean Air Act to provide for

coordination between national energy and air

quality goals. E PA’s primary responsibilities

under ESECA were to determine the earliest

date that a source converting to coal could

meet applicable air polIution control requirements and, if necessary, to grant an order to

the source extending its date of compliance

with the Clean Air Act. The 1977 Clean Air Act

Amendments repealed this requirement under

ESECA and placed E PA’s coal conversion oversight within its general authority to grant delayed compliance orders.

In 1978, ESECA was replaced by the Powerplant and Industrial Fuel Use Act” (see below),

which prohibits the use of oil or natural gas as

a primary energy source in new fuel-burning installations and the use of natural gas in existing facilities after 1990. Temporary and permanent exemptions from these prohibitions are

“Public Law 93-319 (June 22, 1974), as amended by

Public Law 94-163 (Dee 22, 1975) and Public Law 95-70

(July 21, 1977)

“Public Law 95-620 (Nov 9, 1978)
354 ● The Direct Use of Coal

provided for facility operators who demonstrate that they cannot meet the prohibition

without violating environmental requirements

such as emissions limitations; the operator

must demonstrate that he has made a good

faith effort to comply with environmental requirements before he is entitled to use gas or

oil instead of coal. The Act specifically states

that it is not intended to permit any existing or

new facility to delay or avoid compliance with

applicable environmental requirements.

The 1977 Clean Air Act Amendments encourage increased coal use through measures

designed to prevent significant local or regional economic disruption or unemployment.

Where a source or class of sources intends to

use petroleum products, natural gas, or nonlocal coal in order to comply with the Clean

Air Act requirements, and it is determined that

the result would be local economic disruption

or unemployment, the President can prohibit

the source from using any fuel other than

locally or regionally available coal. A source

may be ordered to enter into long-term contracts of at least 10 years for supplies of local

coal as well as contracts to acquire additional

pollution controls. This provision does not exempt a source from the requirements of the

Act, but prevents it from relying on fuels with a

sulfur content lower than that of locally available fuels.

Implementation of the Amendments

This review of the 1977 amendments indicates that, if effectively implemented, the Act

may increase the costs of coal utilization and

may impose siting constraints in both dirty and

clean air regions, primarily in the vicinity of

Eastern and Western coal resources. However,

the extent to which the environmental and

health objectives of the amendments are

achieved and, conversely, the extent to which

substantial constraints on increased coal use

are created, depend on the implementation of

the Act. Major implementation factors to be

considered include monitoring requirements,

air quality modeling, and the level of enforcement.

The Act contains several provisions designed to ensure that major stationary sources

such as fossil-fuel-fired powerplants monitor

their emissions. A condition for EPA approval

of SIPs is that they include requirements for

the installation of monitoring equipment and

for the submission of periodic reports on the

nature and amount of emissions. In addition,

EPA has independent authority to require a

source to monitor and report its emissions

when EPA determines that this information is

required to assess compliance with the Act.

Monitoring data are used in conjunction

with dispersion modeling techniques in order

to determine a source’s impact on air quality

under a variety of Clean Air Act provisions.

Current regulations limit the applicability of

air quality models to a downwind distance of

not more than 50 km. 35 However, recent research suggests that under certain meteorological conditions, such as after prolonged

periods of stagnation or during extremely persistent winds, air pollutants and their transformation products may be transported over

distances greater than 50 km. To the extent

that this longer range transport of pollutants

occurs and is not regulated directly, it may interfere with enforcement of measures directed

at visibility protection and it may consume

PSD increments in clean air areas or contribute

to NAAQS violations in nonattainment areas

downwind. Thus the limits imposed on air

quality modeling may further constrain siting

downwind.

Finally, the 1977 amendments enhance

EPA’s enforcement authority in several important respects. First, EPA now has the authority

to seek civil penalties to a maximum of

$25,000 per day of violation. Second, criminal

actions now may be brought against any responsible corporate officer. Third, and most

important, the amendments provide for the imposition of noncompliance penalties that operate in addition to the other penalty provisions.

These noncompliance penalties essentially remove the economic advantages accruing to a

noncomplying source. The Act sets forth elab3543 F.R. 26380 (June 19, 1978). See also Guideline on

Air Quality Mode/s (Research Triangle Park, N. C.: U.S.

Environmental Protection Agency, April 1978), OAQPS

1.2-080.
Ch. VII—Present Federal Coal Policy 355

orate procedures and standards for this penalty provision, which, in general, requires a

source not in compliance as of July 1979 to

pay a quarterly penalty equal to the money

saved during that quarter as a result of noncompliance.

However, a variety of problems still exist in

enforcing the Clean Air Act and in air quality

management in general. Gaps may be created

in the ability to enforce the Act when new regulations are challenged in court (as they almost always are). New regulations supplant old

ones, yet the courts will grant a stay of enforcement of the new ones, leaving EPA with

nothing to enforce. In addition, enforcement

problems may occur from a lack of communication among the various agencies and governments involved. Thus action taken by the Department of justice, the EPA Office of General

Counsel, or the State may undercut enforcement actions in progress at the EPA regional

offices. Similarly, there is a general lack of integration within EPA for overall environmental

management strategies. Personnel responsible

for developing air programs may be unaware

of the implications of their actions for solid

waste disposal or water pollution and vice

versa.

General air quality management also is constrained by States rights in that administration

of the Clean Air Act must be turned over to the

States as soon as their SIPs meet the minimum

requirements, yet the States may not be ready

or able to administer and enforce the Act adequately. Conversely, whenever a State program falls below the minimum requirements,

administration and enforcement revert to the

EPA regional office regardless of whether that

off ice has sufficient funds or personnel.

In addition, most of the Clean Air Act requirements are dependent on the technological and economic availability of control technology, yet the Act places most of the burden

for developing that technology on Federal

R&D programs that are not funded adequately.

A shift in regulatory philosophy that would

force industry to take the initiative, such as an

emissions tax, could alleviate some of EPA’s

management problems. Finally, because EPA

must use its available R&D funding to attempt

to remedy existing pollution control problems

the Agency is unable to allocate funds to the

anticipation of future control problems.

Conclusions

The Clean Air Act of 1970 failed to achieve

the primary NAAQS nationwide by the target

date of 1975. In 1977 Congress responded with

thorough revisions of the Act in order to

achieve those standards in areas that had not

done so and to protect the quality of the air in

regions that already are cleaner than NAAQS.

Whether in light of continued industrial

growth the new amendments will achieve the

desired air quality is uncertain. In an effort to

do so, however, the amendments may impose

new constraints on stationary sources.

whether the 1977 amendments will impede

increased coal use is largely a question of economics. Within certain limits, increased costs

resulting from clean air requirements, such as

NSPS, will not significantly affect the amount

of coal used; fuel demand has been shown to

be rather unresponsive to moderate price increases. However, regulations that may delay

the siting of facilities, such as those for nonattainment areas and for PSD, or that may substantially increase the cost of new facilities,

could encourage greater reliance on existing

capacity in Iieu of new plants. I n addition, provisions of the Act that require stringent con -

trols regardless of the sulfur content of the fuel

may tend to favor production of locally available high-sulfur coals over higher priced low -

suIfur coal.

The Clean Water Act

Water pollution associated with the direct

use of coal stems from three major sources:

surface and deep mining operations, preparation plants (including ancillary storage areas

and washing facilities], and combustion facilities. Effluents from these sources are regulated under the Clean Water Act 36 (formerly

known as the Federal Water Pollution Control

Act) through ambient water quality standards,

effluent limitations for new and existing

sources, I imitations on thermal discharges, permit programs, and areawide planning.

3633 u S.C. 466 et seq.
356 ● The Direct Use of Coal

Water Quality Standards

Section 101 of the Clean Water Act establishes two national water quality goals. The

first, to be achieved by 1983, is an interim goal

that provides for the protection and propagation of fish, shellfish, and wildlife and for recreation in and on the water. The second national goal is the elimination of all pollutant discharges. The States have the primary responsibility for achieving these goals and for planning the development and use of land and

water resources consistent with them. In 1977,

Congress recognized that significant progress

toward these goals was not being made and

that the discharge elimination goal probably is

unrealistic. Accordingly, the Clean Water Act

Amendments of 1977 extended the deadline

for compliance with the stricter limitations

under the Act by 1 to 3 years.

Each State is required to develop and implement, subject to the approval of the Administrator of EPA, a comprehensive water quality

management plan that includes water quality

standards. These standards consist of the designated uses of the waters involved, including

their use and value for public water supplies;

propagation of fish and wildlife; recreational,

agricuItural, industrial, and other purposes;

and navigation. In addition, the standards include water quality criteria for the waters

based on these uses.

In general, the water quality standards are

to be achieved through effluent limitations on

discharges from point sources (see below).

However, for those waters for which the effluent limitations are not stringent enough to

implement the applicable water quality standard, the State must establish a total maximum

daily load for the relevant pollutants. This load

must be established at the level necessary to

implement the applicable water quality standards with seasonal variations and a margin of

safety that takes into account any lack of

knowledge concerning the relationship between effluent limitations and water quality.

In addition, the State must estimate the total

maximum daily thermal load required to assure protection and propagation of a balanced

indigenous population of shellfish, fish, and

wildlife. This estimate must take into account

the normal water temperatures, flow rates, seasonal variations, existing sources of heat input,

and the dissipative capacity of the waters, and

also must include a margin of safety that takes

into account any lack of knowledge about the

development of thermal water quality criteria.

Effluent Limitations

Effluent limitations are restrictions established by a State or the EPA Administrator on

quantities, rates, and concentrations of chemical, physical, biological, and other constituents that are discharged from point sources. Effluent limitations may be categorized by: 1)

the sources for which they have been established, 2) whether those sources discharge directly into receiving waters or into a publicly

owned treatment works, and 3) the degrees of

control required for each category of sources

or pollutants and the dates those controls become mandatory.

In general, the 1977 amendments require all

categories of point sources to apply the best

practicable control technology currently available (BPCTCA) not later than July 1, 1977.

Those point sources that discharge conventional pollutants (including, but not limited to,

pollutants classified as biological oxygen demanding, suspended sol ids, and hydrogen-ion

concentration (p H)) must apply the best conventional pollution control technology

(BCPCT) not later than July 1, 1984. Finally, all

categories of point sources must apply the best

avaiIable technology economically achievable

(BATEA) that will result in reasonable further

progress toward the stringent discharge elimination goal if the Administrator finds that the

goal is technologically and economically

achievable. BATEA is required not later than 3

years after the date the effluent limitations for

a pollutant have been established or by July 1,

1984, whichever is later, but in no case later

than July 1, 1987. In determining the control

measures and practices to be applicable to

point sources, the EPA Administrator must

take into account the age of equipment and facilities involved, the process employed, the

engineering aspects of the application of various types of control technologies, process

changes, and nonwater quality environmental
Ch. VII—Present Federal Coal Policy ● 357

impacts (including energy requirements) as

well as the total cost of achieving the limitation in relation to the effluent reduction benefits to be achieved.

Where pollutants are introduced into publicly owned treatment works they are subject

to pretreatment standards to ensure that the

effluent limitations applicable to the treatment works will not be violated. I n addition, as

mentioned above, where the general effluent

limitations are not strict enough to contribute

to the attainment or maintenance of the water

quality goals for a particular stream, the EPA

Administrator may establish stricter standards

for point sources located along that stream,

These stricter, water quality related effluent

limitations must take into account: 1) the

tradeoff between the economic and social

costs of achieving the limitation, including any

economic or social dislocation in the affected

communities, and the social, economic, and

water quality benefits to be obtained; and 2)

whether the limitation can be implemented

with available technology or alternative control strategies.

The principal coal-based activities for which

effluent I imitations have been established are

steam electric-power generation and coal mining; these are summarized in tables 59 and 60.

The steam electric-power generating point

source category applies to all units that produce electricity for distribution and sale. It is

broken down further by the size and age of the

unit. I n practice, however, neither the distinctions based on size and age of the facility nor

those based on degree of control required

Table 59.—Effluent Limitations: Steam Electric Power Generating Units

Technology

Source category requirement

Generating unitb and small BPCTCA

unitc subcategories: and BATEA

existing and newd sources;

old unite subcategory

Measurement

Type of discharge Pollutant Limitation time

All except once-through pH 6.0-9.0 – At all times –

cooling water;

all

PCBS No discharge At all times

low-volume waste sources; TSS 100 mg/1 Maximum/day
358 ● The Direct Use of Coal

Table 60.—Effluent Limitations: Coal Mining Point Source Category

(BPCTCA or BATEA) is meaningful. As can be

seen in table 59, except for pollutants from

corrosion-inhibiting materials, the effluent

limitations are the same across the board. The

coal mining point source category applies to

all active mining areas (surface and deep) including secondary recovery facilities and preparation plants but excluding surface mines in

which grading has been completed and reclamation work has begun. The limitations are

broken down into those applicable to acid

drainage and to alkaline drainage.

The EPA Administrator may modify any of

the limitations for a point source if the owner

of the source demonstrates that the modified

requirement will represent the maximum use

of technology within his economic capability

and will result in reasonable further progress

toward the discharge elimination goal. 37 T h e

1977 amendments provide that such a modification is mandatory if the owner also demonstrates-that it will not interfere with attainment

of a water quality standard or the 1983 water

quality goal, and it will not result in additional

requirements on any other point source. As

mentioned above, this provision reflects congressional doubt about the reasonableness and

practicability of the 1985 discharge elimination goal.

Thermal Discharges

Limits on thermal discharges from steam

electric-generating plants are included in the

effIuent I imitations for those sources. These include the BATEA requirements for existing

generating units and NSPS for generating units

and for small units.

Existing generating units are required to

eliminate the discharge of heat from the main

condensers by July 1, 1981, through the application of BAT EA. Exceptions to this general

limitation include:

●

●

●

●

●

Blowdown from recirculated cooling

water systems, provided the temperature

of the discharge does not exceed the lowest temperature of recirculating cooling

water prior to the addition of the makeup

water. (Systems technologically incapable

of meeting this exception are exempt provided they begin construction prior to July

1,1981 .);

Blowdown (overflow) from a cooling pond

under construction or in operation prior

to July 1, 1981, and used to cool water

before it is recirculated to the main condensers;

Where sufficient land for mechanical

draft evaporative cooling towers is not

available (on property owned before

March 4, 1974) and where no alternate recirculating cooling system is practicable;

Where the total dissolved solids concentration in blowdown exceeds 30,000 mg/1

and land not owned by the owner of the

source is located within 150 m in the pre

vailing downwind direction of every practicable location for mechanical draft

cooling towers and no alternate recirculating system is practicable; and

Where the cooling tower plume would, in

the opinion of the Federal Aviation Administration, cause a substantial hazard

to commercial aviation in the vicinity of a
Ch. VII—Present Federal Coal Policy 359

major commercial airport and no alternate recirculating cooling water system is

practicable. 38

In addition, the effective date of the retrofit requirement may be extended for from 1 to 2

years where reliability would be jeopardized

by timely compliance.

The New Source Performance Standards for

generating units and small units provide that

there shall be no discharge of heat from the

main condensers except in the case of blowdown from recirculated cooling water systems

or from cooling ponds where the temperature

of the blowdown does not exceed the lowest

temperature of recirculated cooling water

prior to the addition of the makeup water. In

addition, the Act requires that the location,

design, construction, and capacity of cooling

water intake structures reflect the best technology available for minimizing adverse environmental impacts (e. g., impingement and entrainment).

Where these limitations on thermal discharges are deemed to be more stringent than

necessary for the protection and propagation

of a balanced, indigenous population of shellfish, fish, and wildlife, the EPA Administrator

may modify the thermal discharge limits for a

source. In addition, sources upon which modifications are begun after 1972 and which, as

modified, meet all applicable effluent limitations, are exempt from more stringent limitations for a period of 10 years following completion of the modifications.

Permit Systems

Effluent limitations and water quality standards are implemented through State certification programs and through the National Pollutant Discharge EIimination System (NPDES).

An applicant for a Federal license or permit

to conduct any activity, including the construction or operation of facilities, that may

result in a discharge into navigable waters,

must obtain State certification that the discharge will not violate any effluent I imitations,

water quality standards, or NSPS. Where the

discharge will affect more than one State, the

38ld.

Federal licensing or permitting agency must

condition the permit to ensure that all water

quality requirements will be met. In addition,

when Federal regulations require only a construction permit, the certifying State must be

given an opportunity to review the manner in

which the facility will be operated in order to

ensure that water quality requirements will not

be violated. If the State finds that the operation of the facility will result in violations, the

Federal agency may suspend the license or permit.

NPDES is designed to ensure the orderly and

timely achievement of water quality goals

without sacrificing economic or energy

growth. Under NPDES, a facility may be issued

a permit for a discharge on the condition that

the discharge will meet all applicable water

quality requirements. NPDES permits are issued under State programs approved by EPA,

or, where a State program has not been approved, by the EPA Administrator. The permits

are for fixed terms not to exceed 5 years and

can be terminated or modified for violations.

Compliance with the conditions under which

an NPDES permit is issued is deemed compliance with the effluent limitations and water

quality standards promulgated

Clean Water Act.

Areawide Planning

Section 208 of the Clean Water

under the

Act encourages areawide land and water management

planning for regions with substantial water

quality problems because of urban-industrial

concentrations or other factors. The features

of section 208 plans that could affect coal development include programs:

1.

2.

3.

4.

to regulate the location, modification,

and construction of facilities that may

result in a discharge;

to control mine-related sources of pollution including new, current, and abandoned surface and deep mine runoff;

to control construction activity-related

sources of pollution; and

to control the disposal of residual waste

material and of pollutants on land or in

subsurface excavations.
360 ● The Direct Use of Coal

Section 208 programs were intended to provide the long-range planning basis for the implementation of other Clean Water Act programs. However, the other programs addressed

immediate pollution problems and received

funding priority over section 208. Consequently, implementation of areawide land and water

management planning has been slow; to date

only 9 of 216 plans have received final approval. For reasons primarily related to local

politics, when the section 208 plans are implemented they are not expected to affect the

siting of new coal combustion facilities significant y.

Resource Conservation and

Recovery Act of 1976

Prior to passage of the Resource Conservation and Recovery Act (RCRA) of 1976,3’ the

Federal Government faced a policy vacuum in

regard to the control of solid wastes from coalproducing and coal-consuming facilities. Because there were no major Federal programs

related to the land disposal of solid wastes,

disposal practices could not even be regulated

indirectly through the requirements of NE PA.

Yet scrubbers eventually will produce large

quantities of sludge, and coal mines are

notorious for their waste piles.

In general, RCRA seeks to control open

dumping under a system of State plans and

permits for solid waste disposal. All forms of

solid waste are covered, both hazardous and

nonhazardous, with more stringent regulations

for the former. In neither case, however, are

there prohibitions on waste disposal.

The implementation of this Act by EPA

could have far-reaching consequences for the

handling of solid wastes from coal production

and use. For example, section 1004(5) of the

Act defines “hazardous wastes” to include

those which, because of their quantity, concentration, or physical, chemical, or infectious

characteristics may pose a substantial present

or potential hazard to human health or to the

environment. Under section 3001, EPA is required to: 1) establish criteria for identifying

the characteristics of hazardous wastes, taking

into account toxicity, persistence, and degradability in nature, potential for accumulation

in tissue, and related factors such as flammability, corrosiveness, and other hazardous

characteristics; and 2) based on these characteristics, list particular hazardous wastes that

will be regulated.

The generator of a substance that is listed as

a hazardous waste is responsible for its disposal in accordance with the applicable State

plan. In addition, generators of hazardous

wastes are subject to extensive recordkeeping

provisions that require them to identify the

quantities of wastes generated, the constituents of the wastes that are significant in quantity or in potential harm to human health or

the environment, and the eventual disposition

of the wastes. Finally, the generator must furnish information on the general chemical composition of hazardous wastes to anyone transporting, storing, treating, or disposing the

wastes.

The Act also imposes Government-wide responsibilities that affect coal production and

use. It requires Federal agencies to conform to

EPA solid waste management guidelines if

their activities, such as leasing or permitting,

embrace production or disposal of solid

wastes, particularly hazardous solid wastes.

The impact of this provision is unclear until

the Act’s implementation by EPA is understood more fulIy within Federal agencies. However, it can be expected to involve operating

agencies such as the Tennessee Valley Authority and permitting agencies such as the Departments of the interior and Agriculture, which

grant mining leases and approve powerplants

on Federal land.

The overaIl effect of RCRA probably will be

to increase the cost of waste disposal; the Act

also could increase the amount of waste to be

disposed. If neither ash nor sludge is determined to be hazardous, the costs of waste disposal could increase as much as 45 percent

(see table 61). However, a preliminary analysis

by the utility industry of various waste streams

from coal-fired powerplants indicates that bottom ash, fly ash, and scrubber sludge all could
Ch. V/l—Present Federal Coal Policy ● 367

Table 61.— Potential Sludge and Ash Disposal Costs Under RCRA

Case 1: Ash: Nonhazardous

Sludge: Nonhazardous. . . . . . . . . . . . . . . . . . . . . . . 0.57-0.65 0.65-1.03 1.22-1.68

Case 2: Ash: Hazardous

Sludge: Nonhazardous. . . . . . . . . . . . . . . . . . . . . ., . . . 0.77-0.84 0.65-1.03 1.42-1,87

Case 3: Ash: Hazardous

Sludge: Hazardous . . . . . . . . . . . . . . . . . . . . . . 0.77-0.84 0.90-1.17 1.67-2.01

(Case 4, where ash is nonhazardous but sludge is hazardous, is considered extremely unlikely) — — SOURCE Energy Resources Co Inc

be classified as hazardous.’” All three wastes

yield substances (primarily toxic trace elements) in concentrations that exceed the allowable limits for drinking water. In addition,

ash contains concentrations of radionuclides

and corrosive substances that approach the

allowable Iimits. If either or both of these

wastes is Iisted as hazardous, disposal costs

could increase as much as 84 percent (see

table 61).

Listing ash and/or sludge as hazardous also

would change utility disposal practices significantly. Sludge ponds could be prohibited as

“open dumps” (an area in which there is a reasonable probability of adverse effects on

health or the environment) and utilities forced

to find alternative disposal methods. In addition, the sale or use of wastes probably would

be discouraged. The National Ash Association

estimates that more than 80 percent of the utilities that burn coal selI or use a portion of their

ash and sludge wastes, The provisions of RCRA

that govern transportation of these wastes

could make them noncompetitive. This could

increase disposable ash wastes by approximately 18 milIion tons annualIy at current

levels; no comparable estimates were available for sludge. This effect directly contradicts

RCRA’S stated objective of promoting the recovery and recycling of solid wastes.

Cost increases also could be expected in the

disposal of coal mine wastes, which contain

significant quantities of potentialIy toxic trace

metals, if they are listed as hazardous. Potential overlaps between RCRA and SMCRA could

add to these cost increases.

‘“Electric Power Research Institute, The Impact of

RCRA (Public Law 94-580] on Utility Solid Wastes (F P-878,

TPS 78-779, August 1978)

Percent

increase

over base —

—

45

65

84

Coal Conversion Authority

ESECA

4

’ was enacted following the 1973 oil

embargo in order to reduce imports of natural

gas and oil by increasing the use of coal in

their place. Under ESECA, the FEA Administrator was required to prohibit powerplants, and

possibly other major fuel-burning installations,

from burning natural gas or oil as their primary

energy source if certain conditions were met.

These conditions are:

●

●

●

that the facility has the capacity and necessary plant equipment to burn coal;

that the burning of coal by the facility is

practicable, that adequate coal supplies

and transportation facilities will be available, and that the order wouId not impair

a powerplant’s reliabiIity of service; and

that EPA either certifies that the facility

will be able to comply with applicable

portions of the Clean Air Act by the effective date of the FEA order or grants a compliance date extension.

In addition, ESECA authorized the FEA Administrator to require a powerplant or other

major fuel-burning installation in the early

planning process to be designed and constructed to use coal as its primary energy

source. As with the prohibitions, design or construction requirements were conditioned on an

adequate supply of coal and preservation of

reliability of service, as well as the ability of

the owner of the facility to meet existing contractual commitments and to recover capital

investments made as a result of the FEA order.

4’ Public Law 93-319 (June 22, 1974), as amended by

Public Law 94-163 (Dee 22, 1975) and Public Law 95-70

(July 21, 1977)
362 ● The Direct Use of Coal

Finally, the FEA Administrator was authorized

to allocate coal, while EPA was empowered to

issue temporary suspensions of some SIP provisions, in order to facilitate coal conversion.

FEA authority to issue conversion orders under

ESECA expired on December 31,1978.

For a variety of reasons, including ineffective management and inadequate funding and

personnel, ESECA did not result in many coal

conversions. On June 30, 1975, FEA issued prohibition orders to 74 generating units at 32

powerplants and construction orders on 143

units at 97 powerplants. By early 1977, EPA

had reviewed 65 of the 74 prohibitions, finding

that only 11 of the 65 could burn coal immediately and remain in compliance with the Clean

Air Act. Compliance date extensions were

given to 20 more, while 34 were found to require additional pollution control equipment.

42 Other stumbling blocks to the success

of ESECA included the lack of financial incentives (other than market price) to stimulate

coal conversions and the lack of statutory prohibitions for new sources.

The first National Energy Plan proposed by

the Carter administration anticipated that twothirds of the reduction in projected 1985 oil imports (3.3 million bbls/d out of 4.5 million

bbls/d) would be achieved by coal conversions.

The primary means by which these conversions

were to be accomplished was a tax on industry

use of oil and gas. (The utility sector was expected to switch to coal because of market incentives and was not considered the chief

target of the proposed legislation. ) However,

Congress failed to approve the industrial use

tax, and the final energy package is designed

to achieve coal conversions through a regulatory program with slightly more authority

than that granted under ESECA.

The primary purposes of the Powerplant and

Industrial Fuel Use Act of 197843 (part of the

National Energy Act) are: 1 ) to reduce petroleum imports and increase the capability to

use indigenous energy resources, 2) to con-

‘

z

Progress in the Prevention and Control of Air Pollution in 1976: Annua/ Report of the Administrator of the

Environmental Protection Agency to Congress, S. Dec.

No. 95-75, 95th Cong., 1st sess. (November 1977).

‘

] Public Law 95-620 (Nov. 9, 1978).

serve natural gas and petroleum for uses other

than electrical generation for which there are

no feasible substitutes, and 3) to encourage the

greater use of coal, synthetic gas derived from

coal, and other alternate fuels in lieu of natural gas and petroleum. Supporting purposes of

the Act include the rehabilitation and upgrading of railroad service and equipment necessary to transport coal, compliance with all applicable environmental requirements, and assurance of adequate supplies of natural gas for

agricultural uses.

The Powerplant and Industrial Fuel Use Act

(PIFUA) strengthens the regulatory program

under ESECA in two primary ways. First, PIFUA

prohibits, with certain exemptions, the use of

natural gas or petroleum as a primary energy

source in new electric powerplants and new

major fuel-burning installations” and provides

that no new electric powerplants may be constructed without the capability to use coal or

any other alternate fuel as a primary energy

source. In addition, PIFUA prohibits existing

powerplants from using natural gas as their

primary energy source after 1990 and, in the

meantime, from switching from any other fuel

to natural gas and from increasing the proportion of natural gas used as the primary energy

source. The Secretary of Energy is granted additional authority to prohibit the use of petroleum and natural gas where certain conditions

related to technical and economic feasibility

are met.

Second, these prohibitions are reinforced

with a shift in the burden of proof. That is,

under ESECA, the choice of fuel was left up to

the owner of a facility, and the Federal Government was required to prove that a particular facility could and should use coal. PIFUA,

however, begins with a blanket prohibition

against the use of oil and natural gas, and the

owner of a facility must make a good faith effort to comply with the prohibition and show

that despite these efforts he will be unable to

44 The provisions of the Powerplant and Industrial Fuel

Use Act are applicable to powerplants and other stationary units that have the design capability to consume

any fuel at a heat input rate of at least 100 million Btu

per hour or to a unit at a site that has an aggregate heat

input rate of at least 250 million Btu per hour.
Ch. VII—Present Federal Coal Policy 363

comply and that he is entitled to an exemption

from that prohibition.

The prohibitions also are reinforced with a

variety of financial assistance provisions.

PIFUA provides an additional 10-percent tax

credit for industrial investment in alternative

energy property such as boiIers, polIution control technology, and equipment for producing

synthetic fuels from coal. I n addition, investment tax credits and accelerated depreciation

were denied for new gas and oil burners.

PIFUA also provides loans for up to two-thirds

of the cost of pollution control equipment for

powerplants. Finally, funds were made available for the rehabilitation and maintenance of

railIines used to transport coal.

These statutory prohibitions are, however,

subject to numerous temporary and permanent exemptions. In addition, the Department

of Energy (DOE) is given great latitude in interpreting the Act. Therefore, PIFUA’S success in

achieving coal conversions will not be possible

to predict until DOE promulgates the final regulations under which exemptions will be

granted. For example, PIFUA permits an exemption if the cost of coal “substantially exceeds” the cost of oil or natural gas. The definition of “substantially exceeds, ” the costs to

be included in the determination and the methods for arriving at those costs wilI be set out in

the regulations and will determine the availabiIity of exemptions under this provision.

Despite these uncertainties, DOE estimated

in June 1977 that a regulatory program alone

(that is, without an industrial use tax) would increase industrial coal consumption by 66 million tons in 1985 (as compared to no further

legislation) and would yield 700,000 bbls/d in

oil savings. However, the impact of PI FUA may

be difficult to ascertain because most utilities

and major industries are not planning new oilor gas-burning facilities. Utilities have reported

plans to bring 250 new coal-fired units on line

by 1985; no new large industrial oil- or gasfired boilers have been ordered since March

1977 and industry projections indicate none

are expected. However, these projections

could be undercut by environmental regulations. EPA plans to announce New Source Performance Standards for industrial boilers

under the Clean Air Act soon after PIFUA takes

effect. If those standards are stringent, industrial coal use could be constrained severely in

the Eastern United States. Because large powerplants and industrial boilers are the chief

target of PIFUA, and because those facilities

already plan to use coal to the extent possible,

the main effect of PIFUA could be to provide

financial assistance to ensure those plans do

not change. Where PIFUA could have a major

impact — on smalIer industries — the amount of

coal involved is not as great and exemptions

are more easily obtained.

Other Federal Policy Actions

In addition to the protection from adverse

impacts of coal use afforded to health and the

environment by the above legislation, a variety

of other Federal policy actions may affect coal

production and use. These include the Endangered Species Act, the National Historic Preservation Act, the Fish and Wildlife Coordination Act, and a variety of measures related to

transportation and transmission.

To the extent that coal production and use

disrupt the ecology, it may be constrained by

the Endangered Species Act of 1973. 45 The Act

is designed to protect all forms of wildlife (including mammals, birds, reptiles, amphibians,

fish, shellfish, and other crustaceans, and insects) and pIants through conservation programs for endangered and threatened species

and for the ecosystems upon which these species depend. The provisions of the Act that are

most relevant to coal production and use are

the prohibitions against “taking” any species

that the Secretary of the Interior has determined to be endangered or threatened and

against violating any regulation promulgated

under the Act, and the requirement that all

Federal departments and agencies consult with

the Secretary to ensure that actions authorized, funded, or carried out by them do not

jeopardize the continued existence of these

species or result in the destruction or adverse

modification of their habitat.

Actions related to the production or consumption of coal, such as mining or facility

construction, that would result in the death of

4516 U.S C 1531 et seq
364 The Direct Use of Coal

endangered or threatened species, are constrained by the prohibition against taking. I n

addition, the regulations promulgated under

the Act designate habitats that are critical to

the survival of some species. Any action affecting a designated critical habitat is an offense

under the Act if it might be expected to result

in a reduction in the number or distribution of

the species of sufficient magnitude to place

the species in further jeopardy or to restrict the

potential expansion or recovery of the species.

Several of these designated critical habitats

are in major coal-producing counties.

The requirement that all Federal agencies

consult with the Secretary of the Interior to ensure that actions authorized, funded, or carried out by them will not result in ecological

displacement or otherwise adversely affect endangered species directly affects almost all

coal-related activities. For example, most surface mines require a permit under the Surface

Mining Control and Reclamation Act. Similarly, most coal facilities, such as preparation and

generating plants, require permits and authorizations under a variety of Federal laws such as

the Clean Air and Water Acts. In determining

whether actions will adversely affect an endangered or threatened species, agencies must

consider not only the particular action to be

authorized or funded, but also the probable

secondary effects, such as induced private development.

Once an agency has consulted with the Secretary of the Interior, the final decision on

whether or not to proceed with an action lies

with the agency itself. That is, the Secretary of

the Interior does not have veto power over actions of other agencies that might adversely affect critical ecosystems. However, the Act

makes liberal provision for citizen suits to enjoin actions that violate the Act or regulations

promulgated under it. In these suits the court

will give great weight to the Secretary of the

Interior’s opinion about the effect of an action, and will defer to the Secretary to determine what modifications are necessary to ensure that an action does not adversely affect

endangered or threatened species.

The National Historic Preservation Act of

19704

’ (NH PA) requires all Federal agencies to

4616 U S C. 470 et seq

obtain comments from the Advisory Council

on Historic Preservation whenever any action

may affect a site or structure listed, or found

eligible for listing, in the National Register. In

addition, reguIations promulgated under

NHPA require the agencies to determine

whether there are historic, archeological, architectural, or cultural resources that may be eligible for listing in the National Register. If

there are, the proposed project must be referred to the agency charged with protection

of those resources for review.

As with the Endangered Species Act, NHPA’s

requirements affect almost all coal-related activities. Significant historic and cultural

resources already have become the focus for

concern over the impacts of energy development in the Eastern United States, while the

preservation of archeological sites is a key issue

in the Indian lands of the West. However, in

very few instances may a proposed project be

blocked by NH PA. Rather, the Act requires

that an adequate opportunity to study the historic or other resource be provided before the

project proceeds. Therefore, the primary impact of NHPA would be to delay proposed

coal-related activities that might endanger

these resources.

The Fish and Wildlife Coordination Act of

1 9 70

47 offers some protection against the

modification of any water body as the result of

a Federal or federally permitted project. Under

the Act, Federal agencies must consult with

the Department of the Interior’s Fish and Wildlife Service and with the State agency having

jurisdiction over fish and wildlife, prior to taking any action on a proposed project. Serious

consideration must be given to mitigating

adverse impacts to fish and wildlife, and a

project may be enjoined until the mandated

coordination and consultation have occurred.

The principal coal-related activities that

may be affected by this legislation include the

construction of cooling water intake structures

and of barge and other transportation facilities. However, these activities also are subject

to the requirement that all projects affecting

navigable waters obtain a permit from the

4716 U. SC. 661 et seq.
Ch. VII—Present Federal Coal Policy ● 365

Army Corps of Engineers. I n practice, therefore, the consultation required under the Fish

and Wildlife Coordination Act usually occurs

at the time of application for the Corps permit.

If water resources will be taken by the project

and wildlife values destroyed, mitigating measures may be required to protect the water flow

or even to replace lands lost to construction.

Finally, the Transportation Act of 196648 forbids the taking of publicly owned wildlife

refuges and parks as well as public or private

historic sites for highway construction unless

there is no feasible and prudent alternative

and all steps are taken to minimize harm. This

provision probably will not pose significant

constraints to coal use because adequate

transportation facilities already exist in most

parts of the country. Its greatest potential impact would occur if greatly increased production of Western coal required new highway

construct ion.

Similarly, where transportation or transmission facilities are routed across public lands, or

where the site for a combustion facility is on

public land, the Federal agency having jurisdiction over the Iand must issue a permit for

use of the right-of-way. There usualIy are statutory limits on the width of the corridor or on

the size of the site, and other limitations may

be imposed by the agency in order to prevent

adverse environmental impacts. Again, these

requirements probably would have a greater

effect in the West where there is the largest

concentration of Federal land.

IMPLEMENTATON

How these major Federal policy actions are

implemented plays a central role in determining whether they contribute to or obstruct a

coherent national coal policy. The primary factors relevant to their effective implementation

include the number of agencies with responsibility for regulating coal production and use,

the extent to which those agencies’ mandates

may overlap and conflict, and the number of

gaps in regulatory programs created by unanticipated problems.

Institutional Factors

The responsibility for implementation of the

various laws that affect coal production and

use and their impacts on health and the environment is divided among a variety of administrative departments and agencies. The major

areas of responsibility for environmental and

social impacts are environmental impact assessment, air and water quality management,

resource extraction, occupational health and

safety, solid waste disposal, and siting and

land use. For the promotion of coal use, agency responsibility covers resource exploration

and acquisition, and resource use. Although

4

’49 U S.C 1650

the focus of this discussion is on Federal agencies and their responsibilities, it must be kept

in mind that State and local laws and their implementation also have a substantial impact

on the direct use of coal.

Environmental and Social Impacts

Since the passage of the National Environmental Policy Act (NE PA), all Federal agencies

must prepare a detailed E IS on all major actions significantly affecting the quality of the

human environment. Two Federal agencies

have EIS oversight responsibilities: CEQ and

EPA. CEQ was established by NEPA to advise

the President on environmental affairs, to provide the public with information about environmental issues, and to monitor other agencies’ compliance with NE PA. CEQ regulates

the preparation of EISS, serves as the Federal

repository for EISs, reviews and comments on

draft EISs, and develops comparative analyses

on the E I S process. However, CEQ’s role is primarily advisory; it can neither compel compliance with NEPA nor block actions it feels

wouId have unacceptable impacts.

EPA was established in 1970 to administer a

variety of environmental laws and to police

the environmental activities of other agencies
366 ● The Direct Use of Coal

by reviewing and publicly commenting on “environmentally impacting action s.” As with

CEQ, EPA’s role in E IS review is advisory; it can

make recommendations but cannot block

other agencies’ actions unless those actions

violate other environmental legislation.

A number of State and local governments

have enacted environmental policy acts loosely modeled on NE PA. Their requirements range

from detailed EISS to advisory planning

mechanisms.

The Federal agency primarily responsible for

air quality management is EPA. As discussed in

previous sections, EPA’s role under the Clean

Air Act includes publishing information about

the effects of airborne pollutants on human

health and the environment and about means

of monitoring and controlling those pollutants,

establishing numerical standards for ambient

air quality and for pollutant emissions from

various sources, promulgating guidelines for

State plans to implement those standards, and

implementing and enforcing the standards in

the absence of State action. HEW sponsors

some research into the health effects of airborne pollutants, and the Department of justice assists EPA in enforcing the Clean Air Act.

The States have the primary responsibility

for implementing and enforcing the Federal air

quality standards in accordance with EPA

guidelines. In addition, implementation and

enforcement authority may be delegated to

local government where State law permits and

where the locality is deemed to be capable of

handling this responsibility.

As is the case with air quality, EPA has the

primary Federal oversight responsibility for

water quality management. EPA publishes information about water pollutants and methods

of control, sets water quality standards and effluent limitations for sources in order to meet

those standards, establishes guidelines for

State regulatory and permit programs, and implements and enforces the Clean Water Act in

the case of State failure to do so. A variety of

Federal departments and agencies assist EPA

in fulfilling this responsibility including the

Department of Agriculture, which is responsible for watershed management and runoff erosion prevention; the Geological Survey, National Oceanic and Atmospheric Administration, National Aeronautic and Space Administration, and the Coast Guard, which assist

EPA in water quality surveillance; HEW, which

assists EPA in researching the harmful effects

of water pollutants; the Department of justice,

which aids EPA and the States in enforcing the

Clean Water Act; and the Department of the

Interior, which assists EPA in determining the

standards of water quality necessary for wildlife protection.

The State role under the Clean Water Act

centers on developing and implementing plans

and permit programs consistent with EPA

guidelines.

As mentioned above, there is no comprehensive Federal policy for water resource management. The allocation of water rights traditionally has been the responsibility of the

States, and means of allocation vary widely.

However, many Federal agencies have been assigned duties that affect State allocations.

First, the Water Resources Council” (WRC) assesses water supplies and, through its River

Basin Commissions, coordinates regional water resource planning. In addition, WRC evaluates water resource requirements and availability for nonnuclear energy technologies.

The Department of the Interior sells or leases

water supplies from its reclamation projects

and, in cooperation with the Army Corps of

Engineers, evaluates reservoir projects for the

development of domestic, municipal, or industrial water supplies. The Corps also is responsible for inland waterways in cooperation with

the Department of Commerce. The Department of Housing and Urban Development

assists in water supply and distribution planning. The Departments of the Interior and Agriculture cooperate on water conservation and

utilization projects. These and a variety of

other agencies have additional minor and advisory responsibilities for the management of

water resources as they relate to irrigation,

aquatic life, recreation, flood control, and

other purposes.

4942 U.S.C. 1962a et seq.
Ch. V/l—Present Federal Coal Policy . 367

The Department of the Interior has primary

Federal responsibility for the environmental

and social impacts of resource extraction.

Within the Department of the Interior, the Office of Surface Mining (OSM) implements the

Surface Mining Control and Reclamation Act

(SMCRA). Under SMCRA, OSM sets environmental performance standards for all aspects

of surface mining and for the surface operations of underground mines and establishes

guidelines for State permit programs designed

to implement and enforce those standards.

A variety of other offices within the Department of the Interior are responsible for environmental management of Federal coal leases.

The Geological Survey has overall regulatory

authority over extraction operations after leasing decisions have been made, including the

site-specific conditions to be incorporated in

leases as well as the resource conservation

regulations for Federal lands. The Bureau of

Land Management develops the reclamation

requirements to be included in mining plans,

while the Bureau of Indian Affairs regulates

mining activities on Indian lands.

Prior to the passage of SMCRA, State regulation of the environmental impacts of mining

varied widely. States that wish to retain regulatory authority over surface coal mining and

reclamation operations now must develop

comprehensive plans and permit systems in accordance with SMCRA. OSM will regulate the

mining activities in those States that fail to

develop or enforce a regulatory program.

Until the 1960’s, regulation of the occupational health and safety impacts of mining was

characterized by conflicts between State and

Federal jurisdiction. These conflicts were

resolved in 1969 with passage of the Coal Mine

Health and Safety Act, which gave the Department of the Interior primary regulatory responsibility for miner’s health and safety. Within

the Department of the Interior, the Mining Enforcement and Safety Administration (MESA)

set minimum standards, outlined penalties for

violations, and established mine closure criteria. However, the Department of the interior’s concurrent responsibility for maximizing

energy resource development was found to be

incompatible with its duty to enforce mine

health and safety regulations, and in 1977 the

Mine Safety and Health Act shifted the latter

duty to the Department of Labor. The Department of Labor’s Mine Safety and Health Administration (MS HA) will take over MESA’s responsibilities. Both HEW’s National Institute

for Occupational Safety and Health and the

Department of the Interior’s Bureau of Mines

conduct mine health and safety research.

Federal responsibility for solid waste disposal is divided among EPA, the Department

of the Interior, and the Army Corps of Engineers. Under the Resource Conservation and

Recovery Act (RCRA), EPA has general oversight authority for solid waste disposal. EPA is

required to promulgate guidelines for the

transportation and disposal of hazardous and

nonhazardous wastes of all types (except

radioactive wastes). The Department of the interior’s OSM sets minimum environmental performance standards for the disposal of spoil

and coal-processing wastes. If either of these

wastes is Iisted by EPA as hazardous or if E PA’s

environmental protection standards are more

stringent than OSM’S, the mine operator will

be required to meet the stricter standards.

Finally, the Army Corps of Engineers issues permits for the disposal of solid wastes or of

dredge and fill material in navigable waters.

Implementation and enforcement of EPA’s

requirements under RCRA and of OSM’S regulations under SMCRA may be turned over to

States that establish approved regulatory programs. To the extent allowed by these State

programs, local governments may control the

location of waste disposal through land use

planning and zoning.

As with water resource management, no

comprehensive Federal policy exists for land

use and facility siting. Although the Nation’s

energy goals call for increased reliance on

coal, the recent escalation in parties-at-interest

to energy development makes it difficult to

find acceptable sites for new coal combustion

facilities. In addition, most of the Federal regulatory programs discussed above indirectly

control facility siting to prevent unacceptable

site-specific environmental and social impacts,

but there is little coordination among these

programs.
368 ● The Direct Use of Coal

Only on Federal lands do Federal agencies

have any direct control over land use and energy facility siting. The Departments of the interior and Agriculture supervise most Federal

coal lands and have the authority to forbid

mining where it would be environmentally unacceptable. For all Federal lands, the agency

having jurisdiction over the land must issue a

permit for use of the land as the site for a coalrelated faciIity or for the right-of-way for transportation or transmission purposes.

Indirect controls—primarily constraints—

on facility siting may be exercised by CEQ and

EPA through their role in reviewing EISs. In addition, a variety of EPA regulations for air and

water quality management Iimits the number

of sites available to utilities and industry.

The States have the greatest amount of control over facility siting and land use, either

through their general police power to protect

the public health and welfare or through the

implementation of federally mandated programs. Under their police power, States can

control energy resource development through

land use planning and zoning, permit requirements, and regulation of public utilities. A few

States have enacted comprehensive statewide

land use planning legislation; some only provide statewide planning for energy facility

siting; in others all land use and siting remains

under piecemeal legislation, much of it implemented at the local level.

The Promotion of Coal Use

Federal responsibility for resource exploration and acquisition rests with the Department

of the Interior, which administers the Federal

coal-leasing program. Within the Department

of the Interior, the Geological Survey evaluates coal resource data while BLM records

lease applications and collects various fees,

rents, and royalties. I n addition, other agencies

with jurisdiction over the surface of public

lands, such as the Department of Defense, may

block coal leases on their lands.

The responsibility for coal extraction and

use is divided between the Departments of the

Interior and Energy. As discussed above, the

Department of the Interior oversees Federal

coal leases. But the 1977 Department of Energy Organization Act gives DOE control over

economic leasing terms and conditions. DOE’s

duties under the 1977 Act include establishing

long-term production goals for federally

owned energy resources, developing standards

for rates of production from Federal leases,

specifying economic terms and conditions of

individual leases (for example, eligibility of

joint ventures), and setting guidelines for postIease conditions (such as recommending forfeiture of a lease that does not meet production rates). To facilitate cooperation between

the Departments of the Interior and Energy in

administering the leasing program, the 1977

Act created a Leasing Liaison Committee

within DOE but composed of equal numbers

of members from both departments.

The use of coal is governed mainly by DOE

through conversion of existing facilities to

coal, the prohibition of new large facilities

from burning gas or oil, R&D on new technology, and regulatory price setting.

Evaluation

Many critics of present Federal coal policy

and of the agencies that implement it argue

that energy development is overregulated. Certainly the scope of Federal intervention has

grown dramatically in the last decade. The

number of permits, certifications, and authorizations required to operate a coal mine or a

coal combustion facility has increased substantially. Often several agencies share the

responsibility for regulating a particular activity, such as leasing federally owned coal.

Where those responsibilities overlap, conflicts

may occur between the goals of the agencies

involved. For example, limitations imposed on

Federal coal leases by the Department of the

Interior to prevent unacceptable environmental or social impacts may be incompatible with

the economic terms and conditions imposed

by DOE to achieve national energy goals.

Whether the present Federal coal policy is

perceived as counterproductive usually is a

function of the interests being represented. impartial analysis is rare and conventional costbenefit analysis often cannot adequately

weigh the tradeoffs between the dolIar costs of

regulation and the resulting unquantifiable environmental and health benefits.
Ch. VII—Present Federal Coal Policy 369

On the other hand, some commentator s

argue that more regulation of coal-related ac -

tivities is required, either because of the manner in which agencies have interpreted their

Federal mandates, or because gaps or incon -

sistencies in those mandates preclude the existence of either a coherent national coa l

policy or a coherent national environmental

policy. The most significant obstacles include

the lack of comprehensive Federal programs

for coal, water, and land resource management; the conflict between States rights and

the need for uniform Federal legislation; the

lack of workable mechanisms for solving interstate or interregional problems; and the lack of

mechanisms for long-range planning.

No comprehensive Federal policies currently exist for coal leasing, water resource management, or land use and facility siting. A Federal coal-leasing policy should be developed

and implemented by the early 1980’s, long before any significant coal supply constraints are

expected to arise. Water availability and land

use, however, may present obstacles to increased coal use.

As discussed above, water supplies traditionally have been allocated by the State with

some Federal oversight. For the most part,

State control of water resources is logical because of the wide variation in water availability. Thus a regulatory scheme that may be

workable in the East, where surface and

ground water resources are relatively abundant, would not be appropriate for the arid

and semiarid regions of the West. Yet as the

competition for water for agricultural, industrial, residential, and energy uses increases, a

national system of priorities may become necessary.

Similarly, while land traditionally has been

considered the Nation’s most abundant resource, past abuses and the increasing concerns of parties-at-interest have begun to limit

the land available for energy resource development. As with water, the concerns over land

use and siting have regional variations. In the

more industrialized East the concerns center

on facility siting patterns; concentrations of

coal-fired powerplants in particular areas may

lead to cumulative and interactive impacts

44-102 0 -79 25

that are not fully understood. In the Western

States, the primary concern is the preservation

of environmentally valuable scenic areas and

the prevention of the adverse social and economic impacts of rapid development. To date,

proposals for Federal land use legislation have

been designed to encourage statewide planning. But many of the existing siting problems,

such as air quality management and the longrange transport of pollutants, do not respect

State boundaries. Without comprehensive nationwide land use planning that directly addresses facility siting problems it may not be

possible to meet national energy goals.

Problems also have arisen in implementation of those regulatory schemes that mandate

comprehensive State programs in accordance

with Federal guidelines. Although nationwide

legislative uniformity in these areas is in the

public interest, States are under increasing

pressure to reduce spending and are reluctant

to accept the responsibility for major new regulatory programs. Yet if the States wish to preserve their rights to regulate energy development within their borders, they must accept

that responsibility. Similarly, where federally

mandated State regulatory programs are found

to be inadequate, responsibility for their implementation and enforcement reverts to Federal agencies that have neither adequate personnel nor funding to perform those duties.

As discussed in chapter V, a variety of environmental impacts of energy resource development have become regional problems that

do not lend themselves to management on a

State-by-State basis. Yet the mechanisms for

solving interstate pollution problems are cumbersome and ineffective, and the result will be

an increase in the number of suits between

States. For example, the State of Kentucky has

passed a law that requires powerplant operators to obtain a permit from Kentucky if they

take water from or discharge waste into the

Ohio River along the State’s border. This law

effectively gives Kentucky control over powerplant siting along the Ohio River in the States

of Ohio, Indiana, and Illinois. Kentucky has announced that those States must work together

to solve their common air and water pollution

and siting problems or face legal action by
370 ● The Direct Use of Coal

Kentucky. To some extent, the existing Federal

EPA regions could be used to manage interstate pollution problems, but the same issues

of coordination and cooperation exist at the

regional level; there has been very little interaction among the EPA regional offices even

though environmental management strategies

developed for one region may significantly affect another. For example, Kentucky’s programs are under the jurisdiction of EPA region

IV while Ohio, Indiana, and Illinois are in

region V. The neighboring States of Pennsylvania and West Virginia, which share the same

pollution problems, are under the jurisdiction

of region III. In September 1978, these three

EPA regions established an interregional task

force to coordinate pollution control in the

Ohio River Valley. Such interstate and interregional cooperation must become the rule

rather than the exception if environmental

problems are to be solved. Existing mechanisms for this cooperation, such as interstate

compacts, should be adequate if used effectively.

Finally, most of the Federal policy actions

discussed represent a legislative response to an

existing problem, such as lack of development

of Federal coal leases or the already polluted

condition of the Nation’s air and water. Consequently most of the programs and the R&D

funding is aimed at solving these problems and

little attention is given to long-range planning

or to researching potential future problems.

In summary, the piecemeal legislative approach to energy resource development and

environmental management has resulted in a

variety of implementation problems. Some of

these result in additional dollar costs to the developer. Others result from a lack of coordination within and among regulatory agencies,

such as the solid waste impacts of air pollution

control or interstate and interregional energy

development impacts. Still other problems,

such as the obstacles to energy facility siting,

may require additional regulation if the Nation’s energy goals are to be met. For the most

part, however, these problems could be solved

if existing legislation were implemented in an

effective, coordinated manner.
.

.
Chapter VllL-POLICY OPTIONS

Implementation . . . . . . . . . . . . . . . . .

Major Policy Problems. . . . . . . . . . . .

Community Impacts. . . . . . . . . . . . . . . .

Overload of Existing Community Servi

Economic Dislocation . . . . . . . . . . . .

Social Instability and Quality of Life .

General Policy Options . . . . . . . . . . .

Specific Policy Options . . . . . . . . . . .

Labor-Management Relations . . . . . . . .

. . . . . . . . . . . . . . . . . . 384

. . . . . . . . . . . . . . . . . . 385

. . . . . . . . . . . . . . . . . . 39-1

ces. . . . . . . . . . . . . . . 392

. . . . . . . . . . . . . . . . . . 392

. . . . . . . . . . . . . . . . . . 393

. . . . . . . . . . . . . . . . . . 393

. . . . . . . . . . . . . . . . . . 394

. . . . . . . . . . . . . . . . . . 396

62.

63.

TABLES

Page

Environmental Impacts (Land, Water Quality and Quantity,

Air Quality). . . . . . . . . . . . . . . . . # . . . . . . . . . . . . . . . . . . . . .. 385

Comparison of Policy Options Under Consideration by

the Department of the Interior. . . . . . . . . . . . . . . . . . . . . . . .
Chapter Vlll

POLICY OPTIONS

Each of the national energy supply and demand scenarios in this assessment involves a

very substantial increase in coal use over the next two decades. There is no doubt that the resource to sustain a high level of use over that period is physically present and accessible. It is

also clear that from an engineering standpoint coal can be extracted, processed, and burned

at an economic cost that will make it very competitive with alternative fuels. What is not so

clear is how the external costs, institutional and social constraints, and other nonmarket factors associated with coal use will affect the validity of the economic and technological analysis. At the extreme, increased coal use could pose such serious external costs to the environment and public health that would make it unacceptable. At a minimum, the process of

reducing external costs (e. g., by imposing pollution controls) and coping with internal constraints (e. g., labor-management problems) will moderately increase the economic costs of

coal utilization. Given the central place of coal in future U.S. energy planning, it makes a

great deal of difference where we ultimately come out on the continuum between minimum

and maximum constraints on coal use. In short, the stakes involved in formulating a national

coal policy are very high.

The tasks of policy analysis in this area are to identify the potential problems and constraints and to examine the range of governmental policies that offer some promise of ameliorating them. This study does not recommend specific policies, but it identifies policy options, the sorting criteria for choosing among them, and the implications of available

choices.

The sorting criteria are of three basic types: 1 ) national objectives concerning the level

of coal production and use, 2) political and normative values, and 3) pragmatic calculations

concerning the relative efficacy of policies and technologies in stimulating production and

use and/or minimizing adverse impacts. These are analyzed in sequence.

NATIONAL ENERGY OBJECTIVES

National objectives concerning the magnitude and timing of coal use set the context for

formulating coal policy. For example, acceptable policies for the leasing of Federal coal

reserves, workplace health and safety, and

clean air legislation may be different in kind or

degree depending on whether the Nation seeks

100, 125, or 150 quadrillion Btu (Quads) of

energy supply. Similarly, policies designed to

compel the conversion of existing industrial

boilers from gas and oil to coal mayor may not

be necessary depending on the Government’s

timetable for increased coal use.

In actual fact a sufficient supply of coal

should be available to meet the three coal use

scenarios cited above while satisfying existing

and pending environmental, health and safety,

leasing, and related legislative and regulatory

requirements. Nevertheless, there are actions

that will provide an additional margin of safety against the possibility that these supply projections are overly optimistic or that it becomes necessary to raise coal’s fraction of U.S.

total energy supply above the levels posited in

this report. Many of these measures have merit

independent of their potential effect on coal

supply. The list includes efforts to: 1 ) mitigate

the adverse community impacts that might

constrain coal development, 2) remedy the

sources of labor-management disputes and

promptly settle strikes that do occur, 3) anticipate and avert potential coal transportation bottlenecks by upgrading existing modes

(e.g., railroads) and facilitating the creation of

new ones (e. g., slurry pipelines), 4) expedite the

formation of a leasing policy and the designation of eligible tracts, 5) streamline the permit373
374 ● The Direct Use of Coal

ting process for new mines, and 6) develop procedures for anticipating and accommodating

potential objections to new coal facilities in

order to avoid extensive Iitigation and delay.

Demand is more likely to be a constraint on

coal development over the next two decades

than is supply. While demand will probably be

adequate to sustain all but very high energy

scenarios, this is far from certain. Several

broad policy options are available to strengthen the future market for coal. These include: 1 )

tax pressures and incentives to induce utility

and industrial conversion to coal; 2) R&D support for technologies, e.g., fluidized-bed combustion (FBC) and solvent-refined coal (SRC)

that can help make coal an acceptable fuel for

small users; 3) RD&D support for improved,

less expensive emission control technologies;

4) RD&D support for coal gasification and liquefaction technologies; and 5) higher prices for

natural gas and fuel oil.

In general, however, the different plausible

targets regarding coal production and use for

the remainder of the century do not emerge as

a critical basis for sorting among legislative

and regulatory policy options.

POLITICAL AND NORMATIVE VALUES

Values play a critical role in the policymaking process, yet policy analysis often proceeds under the assumption that policymaking

is or can be a clinically objective, value-free

process. In fact, the choice between conflicting courses of action will often and inescapably reflect subjective judgments concerning

what is desirable. With regard to coal policy,

the most important value conflict involves the

relative priority assigned to increasing production as opposed to reducing adverse impacts.

Taken together, existing legislation and regulations define a rough but discernible balance

between these two value sets. In broad terms

future policy must either accept that balance

or shift it in favor of production or impacts

amelioration. This tradeoff, perhaps more than

any other, lies at the heart of national coal

policy. In one sense, however, the dichotomy is

a false one. Adverse impacts lead to constraints on coal use, and a major reason for

controlling them is to facilitate coal development. The environmental goal conflicts with

the production goal only when protection

measures increase the cost of coal sufficiently

to dampen demand. Other potential value conflicts involve the proper allocation of decisionmaking authority between the public and private sectors and among Federal, State, local,

and tribal governments. Conflicts may also occur between various impacts-related values;

e.g., operating a new coal mine may help solve

a number of community problems, including

unemployment, but may have serious adverse

impacts on the physical environment.

What follows is a more detailed examination

of three conflicting value sets: 1 ) production

maximization or impacts amelioration, 2) the

allocation of decisionmaking responsibility

concerning coal development between Federal

or State and local authorities, and 3) the

allocation of decisionmaking between the

public or private sectors. The first choice between production and impacts values can be

analyzed in terms of specific tradeoffs.

The first tradeoff is between coal extraction

and environmental quality. Mining has a number of inevitable adverse environmental impacts. To some extent these are specific to

either surface or underground, but both forms

of mining have a range of effects. Although

complete control over these effects is impossible, all can be greatly reduced with existing

technologies and procedures. But these technologies have both costs and limitations. They

will certainly make coal more expensive.

Higher prices for coal can have secondary impacts on much of the economy, including inflation and unemployment levels. The limitations of reclamation and control technologies

mean that mining certain coal reserves (e. g.,

under prime farmland) may be precluded altogether.

On the other hand, failure to employ available controls has its own costs. These can in-
Ch. Vlll—Policy Options 375

elude scarred landscapes (often permanent),

subsidence (some of it continuing for a century

or more), polIution and siltation of surface

waters, pollution and disruption of aquifers,

and in some cases, flooding. Secondary costs

can include a reduction in tourism, damage to

agriculture, dim in i shed opportunities for recreation, esthetic impairment, and the need for

control and reclamation. Whereas costs of employing controls in the form of higher energy

prices are borne by the beneficiaries of coal

use, the costs of not using controls tend to fall

disproportionately on the coalfield communities and their inhabitants.

The second tradeoff is between coal combustion on the one hand and environmental quality and public health on the other. Burning coal

to produce energy will unavoidably generate

emissions with potential adverse impacts on

health and the environment. Some emissions

cannot be practicably controlled with known

technologies, while the others can be partly,

but not entirely, eliminated. Carbon dioxide

( C O2

) emissions belong in the first category

and sulfur oxides (SOX

) and nitrogen oxides

(NOX

) in the second. Nevertheless, most immediately threatening emissions can be minimized with present or pending technologies.

There are costs. Coal becomes more expensive

to burn; environmental problems are created

by the need for disposal of flue-gas desulfurization (FGD) sludge; and the process of coal

conversion by plants is made more expensive

and time consuming.

The costs of not controlling emissions include agricultural crop losses, damage to forests and freshwater fisheries, adverse impacts

on esthetic and property values, possible alteration of global climate over time, and possible

increased incidence of human iIIness and mortality due to lung and other diseases.

To the extent to which powerplants are located in urban areas, there is a basic symmetry

between the costs and benefits of emission

control. The urban consumer population bears

the primary burden of increased energy costs

and benefits from the reduction in pollution

from nearby plants. The increasing tendency,

however, is to site new plants in rural areas or

on the outer fringes of urban centers. Under

these circumstances the symmetry is overturned with potential implications for the

balance of political pressures concerning the

tradeoff between energy price and pollution

control.

Where the policy maker or analyst ultimately

draws the balance in the tradeoff between

energy availability and cost on one side and

environmental and health considerations on

the other depends on four considerations:

1,

2.

3.

4.

The severity of the specific impacts being

analyzed and the equity of their distribution.

Personal values, e.g., economic growth as

opposed to conservation.

Attitudes toward risk. The economic costs

of imposing various controls are reasonably predictable, but the environmental

and health costs of foregoing those controls are not, and the range of possible

consequences is very wide. Consequently,

policy choices often involve tradeoffs between the known and unknown or partially known.

Relative value assigned to present and

future costs and benefits. The economic

consequences of higher coal prices will be

felt in the short term, while many of the

most important and environmental effects (e.g., from carcinogens) will not be

felt for years or even decades.

The third tradeoff is between coal extraction

and community well-being. Mining can have

substantial community benefits relating to

economic growth and employment. The costs

can be high as well, including overloaded community services, economic dislocation, and

social disruption. Which effects will tend to

predominate depend on the circumstances of

the particular community. The costs of alleviating community distress related to coal development tend to take the form of transfers of

State and Federal resources to the locality–

e.g., through loans, grants, and bond guarantees. A bill submitted to the 95th Congress

would have allotted $1 billion over the next

decade for this purpose.

The costs of doing nothing are also real,

though not readily quantifiable. These costs in-
376 ● The Direct Use of Coal

elude worker dissatisfaction (with consequent

high turnover and unrest), alcoholism and related social ills, rapid inflation in the coalfields, disruption of the local economy, opportunity costs due to losses in potential income

from noncoal economic activities (e.g., declines in tourism), and congestion and disruption of settled community life. The decision of

where to place the burden of dealing with

these community problems hinges partly on

whether future coal development revenues are

seen as ultimately sufficient to cover the community costs or not. If so, the choice may be

sidestepped by providing loans to cover the

immediate “front-end” costs, which can be

repaid out of future revenues. If not, a choice

must be made where the burden will fall —on

the society as a whole, which presumably

benefits from the increased availability of

energy; on the individual coalfield communities; or on the utilities and mining companies

and, through them, on the direct consumers of

the energy.

The fourth tradeoff is between coal extraction and workplace health and safety. A certain number of casualties in the form of injuries, deaths, and occupational disease

among miners is an inevitable result of coal

production. Mining, particularly underground,

is an inherently dangerous occupation. Nevertheless, with current technologies and procedures (e. g., dust sampling and control, safety

training, inspections) the risks can be lowered,

The costs of doing so include higher priced

coal, and possibly a dampening of productivity

and output. The latter relationship has yet to

be clearly demonstrated. The costs of not acting to reduce the risks to miners are a higher incidence of accident and disease, which could

result in increased labor unrest. Once again

policy makers face a choice between allocating

the costs of ameliorating impacts to society as

a whole through increased energy prices or allowing the costs to fall upon a single group–

the miners.

The policy implications of these tradeoffs

are simply illustrated by positing two opposite

ideal types of policymaker — an “impacts minimizer” and an “energy maximizer. ” I n addressing the major issues involved in coal policy the

impacts minimizer wilI favor such measures as

stringent standards (requiring the best available control technology (BACT)) under the

Clean Air Act for removal of SOX and NOX

, application of Federal point source air emission

standards to existing as well as new facilities,

the imposition of stringent and detailed regulations implementing the Surface Mining Control

and Reclamation Act (SMCRA), the classification of sludge as a hazardous substance subject to rigorous disposal standards, and the enforcement of strict criteria (e.g., regarding the

impact on water availability in arid regions) in

selecting sites for coal faciIities.

With regard to community effects of coal

development, the impacts minimizer will favor

policies that cause the coal companies to internalize an increased portion of the public

costs (e. g., concerning roads and housing) consequent to their activity. He or she will tend to

favor the use of State eminent domain powers

to obtain coal company lands for housing in

Appalachia and in both the East and West will

support increased community participation

and control concerning the decisions of coal

companies that significantly affect the community. A go-slow, careful approach to further

leasing of Federal coal lands will be preferred.

In the tension between production/output objectives on the one hand and health/safety

goals on the other, the impacts minimizer will

give preference to the latter. Examples include

the application of more rigorous dust control

standards and procedures and the use of more

Federal safety inspectors in the mines. With regard to labor/management disputes over such

questions as mine safety and health care centers, the tendency will be to support the

miners.

The energy maximizer is defined as the mirror image of the above and, as such, would embrace an opposite set of policies. The above

list of policy issues is merely illustrative and is

far from complete. Moreover, not all policies

sort in terms of production and impacts values.

A second set of competing values relevant

to coal policy relates to Federal Government

regulation of the private sector—a classic

issue of political ideology. For the sake of convenience, the two competitive perspectives
Ch. Vlll—Policy Options ● 377
378 ● The Direct Use of Coa/

can be called “proregulatory” and “anti regula -

tory” — recognizing that these are oversimplified caricatures. In recent years the proregulatory perspective has been the predominant

influence on national policymaking concerning coal. Rooted in the liberal political tradition, proponents of this view tend to give less

priority to the production of coal than to the

mitigation of its adverse impacts. They see major tensions between the interests of the coal

companies and the public and are generally

skeptical of the wilI or ability of these corporations to avoid actions detrimental to the public

interest without strong Government pressure

to do so. They have a high regard for the value

of public, grassroots participation in decisions

affecting coal development. Regulations are

viewed positively as an indispensable means of

protecting the environment and public health

and safety. They provide a uniform, detailed,

obligatory code of conduct on the coal companies that is enforceable in the courts.

in contrast, adherents of the antiregulatory

perspective are associated with the conservative part of the political spectrum, tend to value energy production over impacts mitigation,

and see the public interest as being best served

by according maximum freedom of action to

the productive genius of the private sector.

Government attempts to regulate economic

activity are seen as a recipe for higher costs

and reduced productivity to the detriment of

all. Some regulation of coal development may

be unavoidable, but it should take the form of

general performance criteria that leave to the

private company freedom to determine how

best to achieve the standard. Wherever possible, broad guidelines and reliance on voluntary compliance should be the rule.

These two contrasting philosophies lead to

very different approaches to specific problems. Three illustrative examples are noise

abatement, air pollution control, and coal

facility siting. With regard to noise, advocates

of the first perspective tend to favor detailed

requirements concerning the devices and procedures that must be used to achieve a reduction in noise levels in a mine. Scorning this

“cookbook” approach, the antiregulators favor only performance standards, e.g., miners

must not be exposed to sounds above a certain

decibel level. How the company achieves this

objective is not the Government’s concern.

Similarly, with regard to air pollution, the proreguIators argue for BACT requirements

whereas their counterparts favor simple emission standards. As for siting, the first perspective sees merit in detailed uniform site selection criteria whereas the second viewpoint

tends to favor case-by-case negotiation of sites

by interested parties within very

lines.

A final value choice concerns

making authority over coal

should be allocated among the

generaI guidehow decisiondevelopment

various levels

of government: Federal, State, local, and

tribal. Considerations that argue for a growing

Federal role include: 1 ) there is a clear need for

a national policy concerning coal development and use, 2) a substantial portion of

known coal deposits underlie Federal lands, 3)

Federal money plays a key role in R&D concerning coal, and 4) scientific evidence increasingly documents the regional/interstate

nature of the pollution problem. Coal burned

in Ohio produces acid rain in New Hampshire.

Pesticides entering the Mississippi River in IlIinois eventually pollute the drinking water of

New Orleans, La. The failure to impose minimum national standards would permit one

State to attract industrial investment by lowering its environmental standards, thereby becoming a pollution haven to the economic and

perhaps environmental detriment of its neighbors. Moreover, it is argued that the scenic

quality of a State like Utah is a national

treasure and, as a consequence, the Federal

Government has a responsibility to protect it.

On the other hand, the potential costs of an

increased Federal role are: 1 ) reduced State

and local initiative, 2) a diminished ability to

fine-tune policy to fit local and regional conditions, 3) the possibility of a halfhearted State

and local commitment to the successful implementation of national coal policy, 4) a risk of

creating a precedent for increased Federal intervention in regional and local affairs generally, and 5) a belief that Federal requirements

concerning air quality, surface mining, water

quality, and potentially, land use unjustly in-
Ch. VIII—Policy Options . 379

terfere with the right of States to develop their

resources, attract economic investment, and

draw their own balance between energy and

environmental goals. For example, the prevention of significant deterioration (PSD) requirements under the Clean Air Act limit the scope

for industrial development in Utah and Montana. Provisions of SMCRA constrain the ability of Kentucky to exploit in-State coal reserves. Rising pressures on State budgets for

cause much Federal environmental legislation

sets standards and then mandates implementation by the States— at the Iatters’ expense.

Despite this difficulty the potential tradeoff

between national and subnational decisionmaking can be at least partly sidestepped by

setting broad Federal standards of performance to be elaborated and applied by the

States. This strategy has been followed in recent legislation concerning coal development.

fiscal austerity exacerbate the problem beEFFICACY CRITERIA

The remaining type of criteria for selecting

among available policies and associated technologies involves an assessment of their utility

in solving the specific production, utilization,

and impact problems associated with coal. Unlike the previous two sets of criteria, which are

to a significant degree discretionary, the third

class of criteria involves a determination of

fact, i.e., an assessment of the feasibility and

effectiveness of various policy options. The

unevenness of the data base means that the

gaps in relevant knowledge must be clearly

identified during the analysis.

Five major areas of policy concern have

been identified, each with a potential for significant influence on efforts to expand the production and combustion of coal. They include

environmental impacts, community and social

impacts, labor-management relations, workplace health and safety, and leasing of Federal

coal reserves. The policy options relevant to

these areas of concern are analyzed in terms of

the efficacy criteria cited above.

ENVIRONMENTAL IMPACTS

Environmental considerations are an important potential constraint on any substantial increase in coal production and combustion. A

number of special characteristics tend to distinguish environmental from other concerns.

One is the range and scale of potential impacts–from minor aggravations to global catastrophe. Perhaps the best known example in

the latter category is the possible climatic effects resulting from increased concentrations

of atmospheric COZ

. The potential time scale

of environmental damage covers a similarly

broad range from virtually instantaneous and

short-lived phenomena to impacts that are

slow in developing but that wit I endure for centuries. Environmental issues relate directly to

matters of great importance to people. What

for the environmentalist is a question of public

health and the quality of life is for the

developer a matter of personal livelihood.

Governmental concern for the environment

is evidenced by an imposing body of legislation and regulation administered by a substantial bureaucracy. To a remarkable degree the

legislation has kept pace with advances in

scientific knowledge. I n terms of control technology, legislation has more than kept pace,

i.e., it has in some instances assumed a technology-forcing function.

Achieving a policy consensus on environmental questions is always difficult. This

reflects, in part, the value conflicts noted

above. It also reflects important gaps and ambiguities in the scientific evidence, for example, with regard to the health effects of chronic

long-term exposure to relatively low levels of

certain pollutants. The sheer magnitude and

unprecedented nature of some of the potential

impacts tend to induce skepticism regarding

the available data. The combination of strong

emotional commitments and uncertain data is

a sure recipe for political conflict. This tendency is exacerbated in the case of coal by the
380 ● The Direct Use of Coal

time, effort, and cost involved in developing

and implementing environmental controls.

Many of the participants in the policy process approach environmental issues from quite

different perspectives. One viewpoint assumes

the worst regarding potential adverse impacts

on the environment from coal development

and use. The burden of proof concerning the

environmental acceptability of coal is placed

on the industry. Adherents to this perspective

would sharply limit coal development until

control technologies have proven their effectiveness. As such technologies become available their universal application would be a

condition of coal development. The alternative perspective is the mirror image: impacts

are assumed to be acceptable and manageable

pending clear evidence to the contrary, the

costs of environmental controls are emphasized, and control technologies must meet a

test of economic acceptability as well as effectiveness. The threshold tolerance of environmental disruption is predictably higher among

supporters of the second perspective.

A final factor complicating the task of environmental policy analysis is the sheer complexity and comprehensiveness of the field. Policy

options designed to minimize the adverse environmental impacts of increased coal use range

from very specific technological or managerial

actions (e. g., lining of ponds used to hold toxic

wastes) to regulatory modifications (e. g., regulation of stack plume opacity), to broad questions of strategy and philosophy (e. g., the use

of effluent charges and other market-oriented

mechanisms in Iieu of regulated controls).

The era of unregulated environmental impacts is clearly past for coal, as for other fuels.

There is in place an elaborate, though still incomplete, framework of legislation, regulation, and implementing institutions that constitute a national policy system for managing

the environmental impacts of increased coal

use. The relevant control technologies are at

various stages in their evolution from conception to maturity— but most have at least

reached the point where a first generation

technology can actually be applied in coal industry operations. Control technologies for

combustion emissions are particularly important and, while existing technologies may not

be optimal, they are workable and effective

and the outlook-for improvement is reasonably

promising. In short, after the investment of

substantial economic, technological, and

human resources over recent years, the foundation for a viable environmental policy for

coal now exists.

Under these circumstances the priority task

of policy analysis is to identify ways the existing policy system can be upgraded. Five major tasks appropriate to this effort are:

1.

2

3.

4.

5.

Identify gaps in present knowledge re

garding the nature and magnitude of the

risks to the environment associated with

coal utilization and the data required to

fill those gaps.

Indicate the prospects and priority needs

for the development of specific control

technologies as a guide to possible Federal support.

Examine the existing body of law and

regulation for omissions, inconsistencies,

and unproductive or counterproductive

requirements.

Analyze the prospects for effective implementation.

Identify those specific major issues that

warrant the priority attention of policymakers.

A discussion of preliminary findings relevant

to each of these tasks follows.

Data Gaps and Needs

Present scientific understanding of the environmental impacts associated with coal is

deficient in a number of areas. The relevant

policy response by the Federal Government

would be support for research designed to supply the required data. The following is a preliminary list of areas where such additional research is needed:

● rate of accumulation of atmospheric COZ

and its impact on climate;

● atmospheric transport of pollutants, the

chemical transformations they undergo,

and the paths they travel;
Ch. VIII—Policy OptIons ● 381

●

●

●

●

●

●

●

correlation between particular pollutants

or levels of pollutants and human health

(dose-response relationships);

relationship between coal combustion,

acid rain, and the productivity of cropIands, forests, and freshwater fisheries;

patterns and consequences of plume

touchdowns;

impacts of SOX and photochemical oxidants on human health and agricultural

productivity;

impacts of fine particulate on human

health;

role of coal combustion in the formation

of hydrocarbons and their impact on

human health; and

physical and chemical interaction of different pollutants, soils, and hydrological

configurations (i. e., the role of site characteristics in determining the impact of pollutants and pollutant disposal methods on

ground and surface waters).

Development Priorities for

Control Technologies

A variety of control technologies and techniques is presently or prospectively available

for dealing with the multiple assaults on the

environment from coal development. These

vary widely in effectiveness, stage of development, and future promise. The task from a policy standpoint is to identify those areas where

problems remain, where technological innovation and development are needed, and where

Federal actions should make a difference.

With regard to control of the combustion

products of coal the priority needs are for improved NOx control technologies, electrostatic

precipitator designs that are effective against

small particulate and low-sulfur coal, lower

cost baghouses, techniques for minimizing

hydrocarbon emissions from small boilers, and

the improvement of new technologies for combustion (FBC) and fuel cleaning (SRC). The

prospects in each case are sufficiently promising to warrant the commitment of substantial

R&D funds. There is also need for continued

upgrading of FCD scrubbers with regard to

their reliability, maintenance requirements,

and costs. One major emission from coal com44- 102 0 79 26

bustion, CO2, is not susceptible to practical

control by any known technology.

A similar agenda of priority needs can be

identified with regard to the control of adverse

environmental impacts of mining. They include ways of making constructive use of land

that is subject to uncontrolled subsidence,

materials and methods for backfilling and/or

sealing abandoned mines, improved techniques for the safe burial of mine wastes, new

methods for constructive use or recycle of

mine wastes, improved techniques for controlling acid mine drainage, and methods for reclaiming particularly sensitive land forms (e. g.,

steep slopes, prime farmland, etc. ) after surface mining.

Other control technologies that warrant attention and the commitment of resources are

regenerable scrubbers, impermeable land fills

for FGD sludge, and water-conserving designs ,

for energy facilities including dry and wet/dry

cooling systems.

Adequacy of Existing Law and Regulations

A substantial body of law and regulation

relevant to the control of environmental impacts from coal development is presently in

place. There remain, however, areas of omission, inconsistency, and weakness that warrant

congressional attention. I n part, the problems

transcend coal and relate to a lack of Federal

policy in such major related areas as water

resource management, conservation, land use,

and energy facility siting. Mechanisms for

long-range planning and for resolving interstate and interregional problems are generally

weak. There is, moreover, still no comprehensive, consistent national policy toward energy

generally and coal specifically. For example,

there is no Federal policy to have the prices of

all fuels reflect their true relative costs or to

provide a consistent regulatory framework for

all modes of transporting coal. Federal legislation and regulation on coal reflect an unresolved tension between the goals of environmental protection and energy development,

with the task of drawing the balance left to the

courts.

Agency mandates and jurisdictions overlap,

as with the Department of Energy (DOE) and
382 The Direct Use of Coal

the Department of the Interior responsibilities

for leasing and the Department of the Interior

and the Environmental Protection Agency

(EPA) jurisdictions over the implementation of

SMCRA. In some cases legislation has resulted

in environmental programs seemingly at cross

purposes. In the past, environmental legislation tended to focus on a specific media and

be blind to the effects of control efforts on

other media. More recent legislation has attempted to address this problem, e.g., in formulating New Source Performance Standards

(NSPS) regulations, their impact on nonair environmental quality must be taken into account. The problem is in a sense irresolvable

because it is an immutable physical law that

matter cannot be destroyed. Thus the Clean

Air Act amendments that in effect mandate

FGD scrubbers create a substantial land and

water pollution problem in the form of large

quantities of sludge.

Existing law deals creatively with another

tension—that between the need for uniform

national standards and States rights— by mandating State implementation of Federal environmental guidelines. This solution may be

threatened, however, by an increasing inability

or unwillingness of States to bear the costs of

such programs in a time of financial stringency.

There are some specific areas of omission in

environmental legislation and regulations concerning coal. Current regulations under the

Clean Air Act do not deal with the long-range

transport and transformation of combustion

products. Thus the regulations control sulfur

dioxide (S02 ) but not the more dangerous

transformation product—sulfates. They also

leave small (respirable) particulate and trace

hydrocarbons inadequately regulated. The

small boilers that would be the principal

source of hydrocarbons are not federally

regulated. Other areas where the present legalregulatory framework is incomplete include

leasing policy and whether sludge will require

disposal as a hazardous substance.

Table 62 presents a summary of key problems and possible new policy initiatives organized around specific pollutants in each medium.

Table 62.–Environmental Impacts (Land)

Problem Impacts Solutions/policies

Subisdence Disrupts surface use, damages structures, ●

lowers property values.

●

●

●

●

●

●

Prohibition of underground mining beneath

densely populated areas pending demonstrated ability to prevent subsidence.

Alter law to make mine owner directly responsible to surface owner.

Government-financed insurance to compensate surface owners for damage resulting

from subsidence.

Tax on underground mining to compensate

for future damages.

Research regarding controlled subsidence:

Planned subsidence for active mines; induced subsidence for inactive mines.

Increased research regarding preventing

subsidence by using FGD sludge, FBC sorbent, or other materials, to backfill abandoned mines.

Research regarding productive uses for land

subject to uncontrolled subsidence.

Disposal of mine wastes Surface disposal source of declining esthetic ● R&D regarding reuse of waste materials

(gob, preparation plant and property values, erosion, landslides, (e.g., in highway pavement, as a mineral

wastes, sludge from treat- and gob pile fires. source, and as backfill for underground

ment of acid mine drain- mines. Major objective is to find methods

age) and combustion prod- All disposal methods risk pollution of sur- to prevent leaching of toxic materials, to

ucts (ash, slag, FGD sludge, face, ground water by leaching. allow disposal under RCRA.

FBC sorbent)
Ch. Vlll—Policy Options ● 383

Table 62.— Environmental Impacts (Land) —Continued

Problem Impacts Solutions/policies

Reclamation of surface- Inadequately reclaimed land is less produc- ●

mined lands tive and may be subject to erosion, landslides, and acid mine runoff. ●

Have had enforcement problems with smaller

mines. ●

Monitor implementation of Surface Mine

Control and Reclamation Act (SMCRA).

RD&D regarding feasibility of fully reclaiming and arid Western forest lands, steep

slopes, prime farmland and alluvial valleys.

Limit surface mining to lands where reclamation to former higher use is virtually certain.

Develop criteria by which all coal lands can

be classified in terms of their eligibility for

surface mining. SMCRA would accomplish

this if State programs are strong.

Adopt measures that favor underground mining (e.g., requirement that FGD scrubbers be

placed on existing as well as new plants).

Acid mine drainage Pollution of surface and ground water to the

detriment of both flora, fauna, and commu- ●

nity drinking water.

Problem most acute regarding abandoned

underground mines in pyrite rich strata. ●

Have had enforcement problems with smaller ●

mines.

●

Active mines: Strengthen enforcement effort

to insure full coverage of small mines, detection of illegal mining.

Abandoned mines: Lengthen bonding period

to ensure permanent acid control.

Establish a fund to pay for control failure,

paid for by tax on mining.

RD&D regarding improved control methods

and technologies.

Land disposal of ash and Leaching of salts and toxic trace elements ● (See disposal of mine wastes and combusFGD sludge into ground water and salts, trace elements, tion products under land impacts above.)

and small particles into surface flows. ● Research regarding pollutants, soils, and

hydrology to obtain detailed understanding

of site factors that influence impacts.

● Incentives to use regenerable scrubbers or

to recycle waste from nonregenerable systems.

● Monitor employment of existing technologies to determine if present incentives are

adequate.

Water consumption require- Stress on limited water supplies in arid .

ments of plant cooling sys- regions (e.g., Upper Colorado River Basin).

terns

●

Require water conservation in the design

and operation of energy facilities (e.g., dry

and wet/dry cooling) in water-short areas.

Water conservation in arid lands agriculture

as a means of freeing additional water supplies. Methods include:

● More efficient irrigation.

● Switching to less water intensive crops.

● Adding irrigation efficiency and/or water

use requirements to rules governing Federal water projects.

● Reexamination of new impoundment and

irrigation projects designed to supply low

cost water to farmers.
384 ● The Direct Use of Coal

Table 62.—Environmental Impacts (Air Quality) —Continued

Pollutant Impacts SO Solution/Policies

Stunts agricultural crops. ●

Possible adverse health effects.

Acid rain. ●

Visibility degradation.

●

●

Particulates Adverse health effects of fine particulate. ● Institute particulate emission standards that

Visibility degradation. distinguishes by particle size.

. Require baghouses on new plants.

. R&D regarding new designs for electrostatic

precipitators.

Hydrocarbons Possible high levels of hydrocarbon . Increased research regarding chemistry of

emissions from small boilers with conse- formation and health impacts.

quent adverse impacts on health. ● Increased research regarding levels of

hydrocarbon emissions from small boilers.

. Establish design standards for small units.

● R&D regarding emission controls for small

units.

● Devise system for monitoring and inspecting

small units.

● Avoid promoting coal use in small boilers.

Implemental ion tention because implementation questions will

loom increasingly large as the basic framework

Data may be adequate and regulations ap- of environmental legislation and regulation is

propriate, but if the law is not implemented lit- put in place. In the simplest case implementable will be achieved. The process of implement- tion involves the installation of a particular

ing environmental rules will require careful at- piece of equipment–with Government i m -
Ch. Vlll—Policy Options ● 385

posed sanctions the price of failure or recalcitrance. Increasingly, however, implementation

rests on more complex and less tangible

actions–planning, management, and general

procedures. This is due to the site-specific

nature of activities related to coal development (e. g., reclamation) and the interaction of

environmental impacts with social, political,

and economic concerns. To the extent that implementation (e. g., of combustion controls)

can be based on technical hardware, it will be

easier than if it depends on procedures. Implementation questions will focus on the

various major items of recent legislation and

regulation, notably the SMCRA, the Clean Air

Act amendments, the revised requirements

and procedures for environmental impact

statements (E IS), and the Toxic Substances

Control Act. The stringency and vigor, including timetables, with which these are interpreted and enforced will have a major influence on the way the balance is drawn between

coal development and environmental protection. This in turn will depend in part on how effectively the responsible executive agencies

(EPA, DOE, the Department of the Interior,

and the Council on Environmental Quality

(CEQ)) can coordinate their activities. More

specific implementation questions relate to

the content of forthcoming regulatory decisions regarding leasing and whether sludge wilI

be classified as hazardous. Also, the thorny

issue of how to deal with a State that is out of

compliance with Federal clean air standards as

a consequence of pollution transported from

out of State will have to be addressed.

Major Policy Problems

Among the many policy issues relating to

the control of the environmental consequences of coal development, three stand out:

1, the utility of cost/benefit analysis,

2. the role of Government relative to the

private sector in the development of control technologies, and

3. whether national point source emission

standards should be imposed on existing

as well as new faciIities.

These are addressed in turn.

THE ROLE OF COST/BENEFIT ANALYSIS

All environmental decision making involves

at least an implicit weighing of costs and

benefits. Even a conscious decision not to

measure costs — as in the Clean Air Act’s requirements for establishing ambient air quality

standards to protect public health — can be interpreted as a decision that the benefits of

health are so high that they must outweigh any

costs incurred in its protection.

Much environmental legislation contains

language requiring a consideration of “costs”

in standard-setting. For example, the Clean Air

Act requires EPA to consider, in specifying a

NSPS for controlling air pollution, “the cost of

achieving emission reduction(s), any nonair

quality health and environmental impact, and

energy requirements. ” However, in virtually

every case the costs of control are described as

a constraint rather than as a factor to be balanced against benefits. In all ai and water

legislation spelling out the terms for selecting

emission limitations, EPA is asked to select the

“best technology available,” not the most

cost-effective.

In most public opinion surveys, Americans

have supported spending for environmental

improvement, even when such spending

causes some economic hardship. However, this

support is based on the public’s perception

that the benefits of environmental standards

outweigh their costs. I n the wake of a variety

of regulatory decisions (e. g., the Clean Air Act

amendments and the new proposed NSPS for

control of SOX

, the proposed mining regulations issued by the Office of Surface Mining)

designed to strengthen environmental controls, the industries subject to them have attempted to change public perception about

the balance of costs and benefits. In addition,

there have been many calls for requiring regulatory agencies to balance costs and benefits

and explicitly defend their selected regulatory

strategies in these terms.

Arguments raised in favor of requiring cost/

benefit analysis include the following:

1. While general quantitative understanding

of environmental impacts of coal development may not be well developed, many
386 ● The Direct Use of Coa/

2.

3

4.

individual areas of impact can be measured. (E. g., some of the costs of reclamation failure, pollution crop damages, costs

to municipalities of pollution of drinking

water sources. ) Thus, cost/benefit type

analyses may be appropriate for some

standards, if not for al 1.

The problems currently associated with

identifying and appropriately quantifying

benefits may never be resolved unless

regulatory agencies are forced to take

benefits into account in their decisionmaking. With a limited research budget,

the environmental agencies are not likely

to pursue vigorously research that is not

directly required for their regulatory functions. For example, EPA virtually abandoned its research program on environmental benefits and disbanded the responsible organization (the Washington

Environmental Research Center) in a 1975

reorganization. (Some funding has recently been restored to this research area.)

Analytical techniques for dealing with risk

and uncertainty can address many of the

problems associated with cost/benefit

analysis.

Public acceptance of expensive environmental controls may ‘be jeopardized

unless the benefits that these controls provide are clearly identified.

There are a number of arguments against requiring such a formal weighing of costs and

benefits in environmental standard-setting:

1. The cost/benefit calculations performed

2

in the past by public works agencies such

as the Bureau of Reclamation and the Army Corps of Engineers have produced a

widespread aversion to this form of analysis. Environmental benefits, being inherently difficult to quantify, have tended to

be neglected in quantitative evaluations

to the detriment of environmental values.

Knowledge about some of the most critical environmental effects of coal development is inadequate. Major controversies

rage as to the magnitude and even the existence of specific environmental and

health impacts. A prominent example is

the controversy surrounding the associa3.

4.

5

tion that has been claimed between community death rates and sulfate pollution

levels. Respectable scientific support can

be found for estimates of annual deaths

caused by today’s air pollution ranging

from zero to tens of thousands.

Even when environmental impacts can be

quantified in physical terms, it is difficult

to translate these impacts into a “language” that allows comparison with

monetary costs of control. The state of

the art of such translation is not well advanced.

The level of uncertainty involved in identifying and quantifying the benefits of

pollution control could considerably increase the incidence of judicial rejection

of environmental standards. For example,

EPA has had considerable difficulty in

promulgating enforceable effluent guidelines for water pollution control, which require mainly technical and economic

analysis. A requirement for a careful balancing of costs and benefits could make

matters far worse.

Any requirement to determine costs and

benefits and/or to balance them in arriving at regulatory decisions may substantially delay the standard-setting process.

Aside from the environmental damage

that may occur, delays could hamper

energy development by adding to the

uncertainty currently faced by entrepreneurs.

At least two options are available for dealing with these questions short of requiring explicit cost/benefit analysis for all standards.

Congress could:

Option A.

Require regulatory agencies to state the expected benefits of their proposals. This would

avoid the need for the agencies to conduct the

difficult analysis involved in balancing economic costs and poorly quantified benefits

(such as esthetic improvements, statistical

risks of health injuries, etc.), but would force

an explicit public discussion of benefits and

probably would provide incentives for benefits

research.
Ch. Vlll—Policy Options ● 387

Option B.

Establish an independent commission that

will decide which, if any, forthcoming environmental standards must be set by an explicit balancing of costs and benefits. The

basis for the commission’s decisions would be

the state of the art of impact assessment for

the pollutants in question. This would take into account the sharp variations in the state of

environmental research, although it may not

provide an incentive for more vigorous research (actually, it could provide a negative incentive if the agencies perceive cost/benefit

analysis as an undesirable requirement). The

commission couId be given the authority to review the environmental research programs of

the regulatory agencies to ensure that fruitful

areas of research are appropriately pursued.

WHO SHOULD DEVELOP

POLLUTION CONTROLS?

Interest in the control of SOX and NOX emissions has led to the development of flue-gas

S 0x and NOX scrubbers, new combustion technologies such as fluidized-bed combustion,

and new fuels such as SRC. Many of these technologies are in early stages of development,

and all will undergo continued refinement so

long as they are considered desirable. The continued rapid development of such control

technologies is critical to maintaining an effective environmental protection strategy, but the

most efficient means to achieve such development has been a subject of considerable

debate within the Government. The major

issue is the role Government should play in

either carrying out the required development

itself or supporting comparable efforts by industry. This debate is equally applicable to

water and land polIution control. Positions

range from advocacy of Government “in

house” development to the commercial stage,

to total reliance on industry. (For example, EPA

and the Office of Management and Budget

(OMB) have argued for years over E PA’s active

role in developing scrubbers. )

The major arguments in favor of active Government participation are:

● NSPS must be based on demonstrated

technologies; therefore, industry has an

●

●

●

●

incentive to avoid demonstrating new

controls or improvements in existing controls.

An equipment manufacturer cannot

“demonstrate” a control technology

unless he places it on a commercial-scale

plant. To do this he needs the cooperation

of the polluting industry, which might not

be forthcoming without Government intervention for the reason just indicated.

EPA has been generally quite successful in

its control development and demonstration program. Examples of successful controls developed or improved through this

program include combustion modification for NOX control and flue-gas scrubbers for SOX control.

An active R&D role by EPA and DOE is

necessary in order to maintain the inhouse expertise to allow competent, informed policymaking about control levels

and technologies required under the

Clean Air and Water Acts.

In those areas where the polluting industries are public utilities, the behavior of

their regulatory commissions can skew

their behavior away from searching for

the most efficient, least expensive controls. For instance, widespread allowance

of fuel transportation cost “passthroughs” and delays in granting rate increases for capital expenditures tend to

push utilities away from capital-intensive

control solutions even if these are the

least costly and most effective options in

the long run.

The major argument in favor of allowing industry to be the prime mover in developing

control technologies is that Government

should not attempt to do what private industry

can do as welI or better:

● The polluting industries have the largest

reserve of personnel who are intimately

familiar with the processes to be controlled and in an ideal position to develop

the most efficient technologies possible.

In addition, the industries have the strong

incentive to develop controls that are inexpensive and conserving of their resources; this incentive may be weak in

Government-research activities.
388 ● The Direct Use of Coal

●

●

●

●

A private pollution control industry exists

that will pursue control technology development even if the polluting industry does

not wish to. Also, there are cases of industries generating considerable profits

from marketing controls they have developed for their own plants; this phenomenon adds considerably to their incentive

for successful and efficient operation of

control innovations.

Private entities such as the EIectric Power

Research Institute (EPRI) are heavily involved in pollution control R&D, apparently at a high level of professional

competence.

The need to get facility siting approval in

difficult areas— with bad meteorology,

pre-existence of high levels of air and

water pollution, or proximity to sensitive

ecological areas — provides a continuing

incentive for industry to develop improved pollution controls.

The Clean Air Act allows exemptions to

NSPS and BACT requirements for firms installing promising experimental equipment, providing additional incentive for

private development.

The options available for dealing with this

question are:

Option A.

Maintain the status quo, i.e., continue

Government spending in control development

at its current level while continuing to cooperate with private development of controls (for

instance, EPA and EPRI have a cooperative

agreement for sharing research results). This

option recognizes the value of encouraging a

“dual track” of control development and accepts the existing incentives for industry

development of controls as requiring Government participation.

Option B.

Substantially increase Government spending in pollution control technologies, especially in areas where control development does

not appear to match the seriousness of pollution problems. Although spending for controls

on energy-producing industry is high, the environmental impacts of energy development

depend strongly on the extent of control of

nonenergy industry. Thus the environmental

hazard posed by SO2 emissions from a powerplant may be great or slight depending whether

there are other sources of sulfur emission (e. g.,

smelters) nearby. EPA’s control program for industrial processes has been at a low level of

support for several years; increased spending

in this area could conceivably have an eventual payoff in removing some constraints from

energy development (e. g., in present nonattainment areas). A corollary of this option could be

to restore E PA’s authority to pursue large-scale

demonstration of energy-related pollution controls; at the moment, DOE has this responsibility. Although DOE has recently indicated an interest in pursuing the development of improved controls for existing conversion technologies, its major emphasis in the past has

been on new technologies such as FBC, gasification, etc.

This option clearly dismisses the argument

that Government should not be heavily involved in activities that private industry is

capable of doing (however, it must be recognized that most of the actual work sponsored

by the Federal Government is contracted out

rather than being conducted in-house).

Option C.

Substantially decrease Government spending in pollution control development, while

taking steps to provide increased incentive for

industry to expand its efforts. These incentives

might include: 1 ) changing the language of the

Clean Air Act to make control requirements

more “technology forcing” (as has been done

with requirements for automobiles); 2) using

economic inducements such as accelerated

rates of depreciation for experimental technology, liberal Federal support for capital and

operating costs of industry demonstration

projects, Federal assistance in persuading local

rate commissions to allow utilities to imme

diately incorporate the expense of new technologies into their rate base, and tax credits for

testing of new technologies.

This option clearly is derived from the philosophy that private industry is the ideaI devel-
Ch. Vlll—Policy Options ● 389

oper of controls for its own technologies, whiIe

recognizing that the nature of the marketplace

requires special incentives to encourage this

development. This option accepts the risk that

industry could choose to avoid development

of new controls and presents the Federal Government with the choice of either taking harsh

measures (fines or plant closings) or delaying

or loosening control requirements.

NATIONAL CONTROL STANDARDS FOR

EXISTING FACILITIES

Under the present regulatory structure for

control of air polIution jurisdiction over new

sources is shared by the States and EPA but

control over existing sources is the exclusive

responsibility of the States. This has created

concern about control of long-range, interstate

transport of pollution and our ability to construct a rational, cost-effective strategy for

emissions reductions. The divided regulatory

structure may be adequate for protecting local

air quality from locally produced pollution,

but it contains no effective mechanism for protecting against air quality degradation caused

by the interstate transport of pollution from

existing sources. This happens because the

characteristics that tend to lead to longdistance transport —tail stacks and persistent

winds — also tend to minimize impacts on local

air quality. Pollution sources with these

characteristics usually would be loosely controlled by their SIPS. For example, large coalfired powerplants in the Ohio River Basin have

been associated with elevated sulfate levels

hundreds of miles downwind, while their SIPS

allow them to burn high-sulfur coal with no

controls.

Because of EPA’s lack of direct control of

existing sources; national strategy must concentrate mainly on restricting emissions from

new sources. The Clean Air Act’s requirement

for continuous technological controls leads to

a high cost of S02 emission reduction for new

sources; estimates of the cost of the EPA and

DOE proposals range up to $1 ,000/ton of emissions reduced, and total costs of the NSPS controls will be several tens of billions of dollars

by 1990. Although these controls will slow the

rise of SOX emissions in the face of expanding

coal use, the large quantity of emissions from

existing powerplants will remain unaffected by

NSPS and is not expected to decrease substantially in this time period. The questionable

wisdom, from a national perspective, of simultaneously requiring maximum controls on new

powerplants and lenient or no controls on a

number of large existing plants is highlighted

when the potential costs of controlIing some

of the existing plants are examined. For example, if a utility currently using 4 percent sulfur

coal could obtain 2 percent sulfur coal at a

$10/ton premium, it would achieve a 50-

percent reduction in S02 emissions at a cost of

$250/ton of emissions reduced.

Because long-term stabilization and reduction of SOX emissions depend on the gradual

movement to reduced operations and eventual

retirement of the older uncontrolled plants,

changes in their expected operational patterns

and retirement schedules can have severe effects on national emissions levels and air quality. The sharp differences between the operating costs of old and new plants due to

emission control requirements or the latter

may make the intensive operation of older

plants more attractive to the utilities. NSPS requirements could have a perverse effect of increasing the emissions in some areas by encouraging a shift of baseload operations to the

older, poorly controlled plants and by discouraging their retirement. Computer modeling has tended to confirm the potential for this

effect.

Individual States are unlikely to change

voluntarily their SIPs to eliminate these potential problems. An increase in control requirements would trade an economic cost to a

State’s constituents for a benefit to the

residents of other States. I n some cases, increased control of SOX could require a shift to

out-of-State sources of coal, hurting in-State

producers and miners. Finally, there is substantial controversy surrounding the impacts of

long-range transport (acid rain, sulfate, health

effects, etc. ) so that the known benefits of

emission reductions are less tangible than the

costs. The options available to Congress for

dealing with the issue of further controls on existing faciIities are:
390 ● The Direct Use of Coal

Option A.

Maintain the present divided regulatory

structure and forego additional reductions in

emissions from existing sources untiI either further research results are obtained or less expensive or disruptive control alternatives are

developed. This option can be combined with

increased funding for research on the impacts

and mechanisms of long-range pollutant transport and for development of controls. Control

development would focus on low-cost alternatives suitable for retrofit. Examples are competitive low-sulfur/low-ash fuels Iike SRC, lowN OX burners, and modifications to electrostatic precipitators to provide better fineparticle control. This option avoids additional

regulatory costs unless they are absolutely

necessary or unless new controls can sharply

reduce costs. The option is essentially a delaying tactic until more information is obtained

and more options are available. It can be supported by recognizing that emissions are not

expected to rise rapidly in the next decade or

so. However, it involves the implicit acceptance of the risk that present emission levels are

causing significant levels of health and environmental damage. These risks are discussed

in detaiI in chapter V.

Option B.

Amend the Clean Air Act to provide for

Federal control of existing pollution sources.

Require existing facilities to satisfy the same

emissions standards as new facilities. Exempt

plants that are close to retirement from full

compliance, but require fuel switching to

clean or cleaned coals when this alternative is

available. Successful implementation of this

option would drastically cut emissions of SOX

and particulate. But because retrofit of controls is more expensive than incorporating the

controls in the plant design, and the existing

coal-fired capacity will represent the majority

of total coal-fired capacity for several decades, the cost of this option should be in excess of that predicted for the proposed NSPS

for steam electric utility boilers through 1990,

or several tens of billions of dollars. For some

plants, electricity production costs would increase by 20 percent or more. This option embodies the idea that risks of the type associated with coal pollutants are unacceptable.

However, implementation would be difficult.

Besides the cost, the option would present

substantial resource problems: the need to

quickly construct large numbers of scrubber

installations, the requirement to safely dispose

of large quantities of scrubber sludge, and the

need to train large numbers of operating personnel for new control systems. Given the difficulties that American utilities have had in

operating scrubbers, this resource problem

could substantialIy delay implementation.

Option C.

Amend the Clean Air Act to provide for

Federal control of existing pollution sources.

Selectively increase controls on large facilities

where the SIPs have been determined to be lenient or when the facilities have been determined to be a major source of problems associated with long-range transport of pollutants.

Also, increase pressure to enforce SIP deadlines with tight enforcement resources and/or

economic incentives. The SOX controls envisioned in this option would be primarily lowsulfur coals, cleaned coals, and eventually,

SRC. Selective use of scrubbers might be justified for newer plants. Also, the R&D program

described in Option A would be adopted. As in

Option B, this course of action places a high

premium on risk avoidance. It considers the

potential dangers attributed to acid rain, fine

particulate, and sulfates as significant enough

to warrant considerable expenditure of control

funds, but attempts to keep expenditures significantly below the costs of total control. It

recognizes the variations among SIP regulations and the role that location plays in determining the seriousness of impacts. Nevertheless, it remains (like scenario B) an expenditure

of considerable funds to combat impacts that

for the most part have yet to be definitely

proved; it can be expected to produce considerable opposition from utilities and industry

on these grounds. Also, it can be expected to

be opposed by Midwestern States whose

powerplants, now burning local coal, might be

asked to shift to low-sulfur coals from out-ofState sources. This latter problem can be overcome by speeding up the demonstration of ad-
Ch. Vlll—Policy Options ● 391

vanced coal-cleaning processes and allowing

the States to require their use in favor of outof-State coals.

COMMUNITY IMPACTS

The impacts of coal development on local

communities and the response of those communities will be a significant factor influencing the future of coal as a national energy

source. Some of the impacts— notably the generation of investment and employment in economicalIy depressed areas — are almost universally viewed as positive. The adverse impacts,

however, are of greatest concern to policymakers because they may jeopardize the projected conversion to coal and require ameliorative action by Government. The dislocations and social ills associated with boomtowns may lead to high worker turnover and

low productivity in western mining areas. The

utter inadequacy of such basic social infrastructure as housing, roads, and sewers may

severely inhibit efforts to rapidly expand Appalachian coal production. Community resistance to siting of coal-fired powerplants may induce further slippage in already lagging construction timetables. Consequently, a viable

national energy program would logically include policies designed to alleviate the

negative community impacts associated with

coal development.

Such policies, if they are to be effective,

must recognize two basic characteristics of the

present situation. First, there is considerable

uncertainty regarding the nature of coal

development impacts and the balance of benefits and costs that will accompany them.

Policy perspectives vary accordingly. Proponents of community aid programs contend

that future tax revenues and other economic

benefits of coal development will never cover

all the costs to the locality, thus necessitating

a real net transfer of Government funds. An

alternative view sees energy growth as similar

in its impacts to other sources of growth and

more likely than most to pay its own way in

terms of community costs and benefits. From

this perspective, the Federal Government role

should be limited, except in special circumstances, to supplementing existing policy

mechanisms. Second, value disagreements

concerning what are positive and what are

negative impacts result even where the nature

of these impacts is understood. Whether economic growth should be viewed as a positive

or negative phenomenon is itself the subject of

dispute. Value conflicts extend to other areas.

For example, should community impact costs

be borne by energy consumers through forcing

the coal companies to internalize such costs

and pass them along in the form of higher

prices? Or should such costs be paid out of

general tax revenue in the form of Government

loans and grants to impacted communities?

What is the extent, if any, of Government obligation to assist communities that will ultimately benefit economically from Federal policies to stimulate coal use but are unable to

adequately cover the “front-end” costs of infrastructure and community service development in the short term?

Clearly, policies designed to ameliorate

adverse impacts must recognize these uncertainties and value disagreements. This can be

done with a policy approach that is basically

accommodational, that seeks to anticipate the

concerns of interested parties and deal with

them in a way that encourages compromise.

Such an approach has two principal characteristics.

First, all parties affected by increased coal

use are able to participate in decisions concerning the location, timing, and scale of coal

developments that directly concern them. Second, Federal policies are designed to distribute

the risks, costs, and benefits equitably among

all parties affected by increased coal development. The process of participation and consultation has two drawbacks; it can be expensive

and time consuming. However, to the extent

that adverse impacts can be anticipated and

forestalled through consultation with the affected communities, the economic costs of

ameliorating those impacts will be lessened.

Moreover, the result can be a general upgrading of community capabilities.

Adverse community impacts associated with

coal development take three major forms: 1)

community services and infrastructure are
392 ● The Direct Use of Coal

overloaded, 2) local economies become overheated and distorted, and 3) social instability

accompanies a decline in some aspects of the

quality of life. These are briefly summarized as

a prelude to the analysis of possible policy

responses.

Overload of Existing Community Services

In many parts of the Eastern coalfields existing services are incapable of coping with the

effects of a rapid expansion in coal development. The weakness has multiple dimensions.

Local government services and infrastructure

(utilities, police, roads, flood control, etc.) are

often woefully inadequate. Public utilities are

frequently incapable of meeting any significant additional demands without an overhaul

of the entire system. Consequently the marginal costs of increased utility services are

often very high. The commercial services and

the supporting infrastructure in the private sector are also weak. Professional and skilled personnel are difficult to attract, given the living

conditions in the coal towns. Private investment is discouraged by the risks associated

with the historic boom and bust cycle of the

coal industry. Local financial institutions have

very Iimited resources. The tax system, particularly as it relates to the coal industry, is inadequate, reflecting a general weakness in local

political institutions. Coal lands and enterprises are characteristically taxed at low,

sometimes spectacularly low, rates. In many

locales housing is in desperately short supply

due to rugged topography, large landholdings

by coal companies, a shortage of mortgage

money, high utility costs, a low volume capacity of local builders, the absence of public

housing programs, and other causes. Thus, in

coping with the impacts of increased coal production the Eastern coalfield communities

begin in a serious deficit situation with already

inadequate services and supporting infrastructure. This situation rests, in turn on basic economic, social, and political underdevelopment

rooted in a lack of economic diversification

and absentee ownership of coal-related resources.

The Western coalfields present a different,

although still troubled, picture. Community

services and infrastructure are often extremely

limited because of the characteristically small

size and isolated location of Western coal

towns. The explosive increase in demand for

community services associated with largescale coal development will occur before coal

revenues become available. This front-end financing problem is exacerbated by the present

small tax base and lack of bonding history or

authority of the communities in question and

the long Ieadtimes required to initiate coal

production. The problem is in some instances

aggravated by jurisdictional mismatches

where the productive enterprise (and consequently the tax revenue) is located in a different political jurisdiction from the locality

that must bear the brunt of the social costs. As

in the East, supplying sufficient housing is a

serious problem. The principal causes are inadequate sources of financing and the limited

volume capacities of local builders. In sum,

western efforts to provide community support

to coal development must start largely from

scratch. Compared to the East there is virtually

no capability in place, but often there is also

no service deficit to make up and no antiquated infrastructure that must be dismantled.

Further, there is nothing comparable to the

pervasive constraint in the East imposed by the

high and virtually irreducible ratio of population to habitable land.

Economic Dislocation

For the coal towns the benefits of a rapidly

expanding coal industry are principally economic, but there are economic costs to the

community as well. In the East as coal-related

incomes and demand for goods and services

rise, the commercial sector is often unable to

keep pace, with rapid inflation the result. For

those in the community on fixed incomes or

otherwise not positioned to benefit from the

income effect of an expanded coal industry,

the consequences can be devastating. Other

costs of coal growth can include a reinforcement of the existing single primary product

economy, with its associated vulnerabilities.

There are opportunity costs as coal development inhibits or forecloses other beneficial

economic activities, notably recreation and

tourism.
Ch. Vlll—Policy Options ● 393

In the coal boomtowns of the West severe

inflation is also a problem. Opportunity costs

are present here as well, particularly disruption

of the rural ranching economy because of coal

development.

Social Instability and Quality of Life

For many citizens of the community the

social and psychological costs of rapid coal

development may be the most difficult to

bear. Heavy coal truck traffic on eastern rural

roads not designed for such use can pose a

growing threat to public safety and convenience. Overloading of local services plus sheer

congestion can mean increasing emotional

stress and even mark a perceived decline in the

quality of life of established eastern communities. The boom and bust history of the industry can induce a basic mood of uncertainty

about the future that contributes to the social

and psychological malaise. In the West, boomtown conditions can lead to crowding, emotional stress, family problems, juvenile delinquency, crime{ alcoholism, and other social ills

rooted in a pervasive sense of rootlessness and

impermanence. The situation is exacerbated

by the tendency of coal development to erode

the settled ranching culture of the area. Here

too, uncertainties about the future of the industry can reinforce other problems.

These factors can adversely influence coal

output in a number of ways, but particularly in

terms of their impact on the work force. Miner

dissatisfaction with community living conditions can translate into high worker turnover,

absenteeism, low productivity, and strikes.

The policy options available for dealing with

these problems fall into two categories: generic measures designed to improve the process

of coping with coal development impacts nationally and specific initiatives designed to

solve particular problems, some of which are

peculiar to one geographical area. These two

categories are discussed in turn.

General Policy Options

Five major policy initiatives of this type can

be identified:

First, improve the access of communities to

information concerning coal development impacts. One way would be to establish a single

national energy facility siting schedule, perhaps as part of a national energy information

service. The objective would be to provide advance information about energy development

plans to potentially affected communities. In

this regard, DOE might be empowered to gather and disseminate energy-impact-related data

available within the Federal Government, including OCS and BLM leasing plans and industry projects submitted for Federal licensing or

approval. (Some regional efforts of this nature

exist, For instance, E PA’s Region 8 office in

Denver publishes a continually updated list of

planned facilities). On request the Federal

Government might provide any locality scheduled to be impacted by a major new energy

facility with an assessment of the effect of that

development on the community. Such an

assessment might be conducted as a joint Federal-State-local effort. This could be accomplished through existing E IS procedures if

they were modified to give added weight to

community impacts along with the existing attention to impacts on flora and fauna.

Second, increase opportunities for local authorities and citizens to participate in decisions concerning the siting, construction, or expansion of coal facilities. This might involve

support, in the form of financial assistance and

access to information, of citizen interest

groups acting as interveners in Government

proceedings concerning facility siting, and

related decisions. Similarly, mechanisms might

be established for giving State, local, and tribal

authorities earlier access to relevant Government deliberations than is now commonly

available. Consideration might also be given to

supplementing the modified E I S procedures

suggested above with a requirement that companies planning to construct energy facilities

propose actions they will take to alleviate

those adverse community impacts that have

been identified.

Third, improve the capability of localities to

manage coal development impacts. This might

take the form of Federal technical assistance

for development, planning, and impact assess-
394 ● The Direct Use of Coal

ment. The Government could also ease the financial burden on localities seeking to cope

with adverse impacts. This might involve grant

and loan programs to finance public sector

personnel, construction, and other costs. The

eligibility requirements of existing Federal

community assistance programs might be

modified to give priority to coal-impacted

communities. The Federal tax code could be

amended to encourage prepayment of State

and local taxes by industries planning coal facilities. Also Federal programs can be used to

encourage State initiatives to deal with community impacts, e.g., by according priority to

States that have established mechanisms for

State assistance to coal communities. Finally,

Federal assistance could facilitate direct communication between responsible officials from

different coal communities, thereby enabling

community governments to share experiences

in dealing with energy development impacts.

Fourth, improve coordination of Federal assistance programs. A variety of steps might be

taken in this regard. DOE, for example, could

be designated as the lead Federal agency with

responsibility for coordinating Federal impact

assistance programs through an interagency

board at the regional level. An office within

DOE could be established to coordinate community impact assistance planning with other

energy-related planning. The Federal Regional

Commissions could be asked to sponsor regular assessments of coal-related community

impacts on a regional basis. The Commissions

might also be accorded a substantive voice in

the allocation of Federal impact assistance.

Federal-State coordination might be improved

by a requirement that Federal decisions affecting the siting or expansion of energy facilities

be compatible with federally approved State

impact mitigation strategies.

Fifth, modify the point criteria by which the

eligibility of communities for Federal assistance is determined. These criteria are presently designed to permit assistance to communities in economic decline by basing eligibility

on such measures as unemployment and the

percentage of substandard housing. Programs

under the Department of Housing and Urban

Development and the Economic Development

Administration of the Department of Commerce are prominent examples. A community

suffering the dislocations of a coal boom cannot qua! if y under these criteria.

Specific Policy Options

Listed below are specific Federal actions

that might alleviate some of the potential

adverse impacts associated with coal development. These are in addition to the broader

generic actions outlined above.

COMMUNITY SERVICES AND INFRASTRUCTURE

●

●

●

●

●

Target Federal highway funds toward road

construction (including overpasses), improvements, and repairs necessitated by

coal development.

Increase Federal funds available through

the Farmers Home Administration for

water and sewage systems in coal-impacted localities and broaden eligibility

for such assistance to include communities with over 10,000 population. Larger

communities do not presently qualify for

FmHA funding.

Establish a new Federal loan program to

finance the construction of public works

needed to meet demands resulting from

coal development. An alternative would

be to provide a Federal guarantee of local

bonds to finance such construction.

Compel coal development companies to

internalize some of the risk associated

with front-end financing by prepayment

of taxes, provision of certain community

services, or guarantees of municipal

bonds as a condition for obtaining needed

Government licenses and approvals. Alternatively, an attempt could be made to

induce such actions by coal companies in

return for tax breaks or other inducements.

Expand Federal subsidy programs for lowand moderate-income housing such as the

FmHA homeownership program, Other

possible Government initiatives to alleviate the shortage of housing include the

use of Federal and State eminent domain

authority to obtain land, encouragement

of community nonprofit housing corporations with subsidies, modifications of the
Ch. VIII—Policy Options ● 395

●

●

●

●

●

●

●

●

tax laws to encourage coal development

companies to provide employee housing,

and Federal subsidies or guarantees designed to make mortgage loans with low

downpayments available to young couples.

Impose a Federal severance tax on coal

with revenues going to States or localities

to provide needed community infrastructure and services. Use funds generated by

leases of Federal coal lands for the same

purpose.

ECONOMIC DISLOCATION

Create a stable and predictable demand

for coal by means of a national energy

policy clearly committed to substantially

increased coal use through the end of the

century.

Encourage non-coal-related private investment in the coal field communities by

use of tax incentives, preference in awards

of Federal contracts, etc.

Give preference to coal-producing areas

in siting of Federal installations.

Levy a national severance tax or royalty

on coal production and use the revenues

to establish development banks or trusts

for investment in coalfield communities.

Provide compensatory payments to communities that bear the social costs of mining federally owned coal or of coal development in adjacent Federal lands.

Upgrade the capabilities of the Appalachia Regional Commission and its western

counterparts to support a broad range of

development programs.

Help coalfield communities identify and

develop alternative sources of economic

growth (e. g., reconstruction of a historic

narrow gauge railway as a tourist attraction).

SOCIAL INSTABILITY AND QUALITY OF LIFE

● Provide loans, grants, bond guarantees,

etc., to assist coal communities in establishing recreational and social service programs (e. g., family counseling, day care

centers, adult education, parks).

●

●

●

Assist community self-help projects (e.g.,

civic beautification).

Fund study by Federal Regional Commissions concerning possible regional approaches to preserving existing farms and

ranches.

Fund joint study by Federal and State governments and Indian tribal governments

regarding ways of Iimiting the corrosive

impact of energy development on Indian

culture and social systems.

Any comprehensive program to deal with

the community consequences of coal development will have at least two objectives: the mitigation of specific adverse impacts and the diversification of the local economy. Clearly,

such an effort will strain the resources of local

jurisdictions and may require supplemental

Federal funding– ing the form of loans, grants,

or both.

If it is assumed that revenues generated by

coal development ultimately will prove adequate to cover the costs of impacts amelioration, the money can be raised by local taxes on

the activities of the coal companies supplemented, if necessary, by Federal loans to cover

front-end costs of public works and other in

frastructure. The coal companies will presumably pass along the cost of taxes to consumers

in the form of higher coal (i. e., higher energy)

prices. This, in effect, puts coal development

on a pay-as-you-go basis with the ultimate beneficiaries of coal production, the energy consumer, paying most of the bill. The feasibility

of the pay-as-you-go option wiII depend on:

1.

2.

3.

If

how heavily coal development activities

can be taxed without pushing the price of

coal to uncompetitive levels,

whether coal communities are willing and

able to impose those levies that will capture the potential revenue, and

the availability of Federal loans.

it is assumed instead that coal develoDment revenues will not cover the external costs

involved, the choice is between turning to the

Federal or State governments for some sort of

net transfer of funds or continuing the past

practice of allowing the costs to fall on the
396 ● The Direct Use of Coal

local communities in the form of environmental and social deterioration. The limiting factors will be the availability of Federal or State

funding and the absorptive capacity, in terms

of environmental and social pressures, of individual coal communities.

Policy makers will also have to consider how

the needed funds will be acquired and distributed. In practical terms, the communities have

two methods of raising revenue from coal development, a property tax on company-owned

coal lands and facilities within the local jurisdiction, and a severance tax on the value or

quantity of coal actually mined. The difficulty

with any local tax is that it may place the community at a competitive disadvantage compared to other localities in attracting coal investment.

The Federal Government has a much wider

choice of sources for funds, including general

Federal revenues based primarily on the income tax and a variety of levies specifically on

coal production and use— including fees,

rents, and royalties for leases on Federal land,

and a national coal severance tax. Federal net

transfers can be made available to coal communities in the form of direct payments (e. g.,

revenue sharing, grants, trust funds) according

to some established formula (e. g., amount of

Btu equivalents mined) or through a development bank that would provide assistance on a

project-by- project basis.

LABOR-MANAGEMENT RELATIONS

The history of labor-management relations

in the coal industry has been a tumultuous

one. Any analysis of the contribution of coal to

U.S. energy requirements must take into account the possibility of supply disruptions due

to work stoppages. This was dramatically demonstrated in 1977-78 when the United Mine

Workers of America (UMWA) and the Bituminous Coal Operators of America (BCOA)

locked horns in a prolonged 109-day strike that

effectively shut down about half of U.S. coal

output. The reasons for this troubled history

are multiple and complex. They include characteristics of the coal market, the ownership

structure of the industry, the nature of the

workplace and work process, the social and

political environment of the coalfields, and

the accumulated ill-will and mistrust built up

over decades of conflict between the operators and miners.

Policy makers face two basic tasks: first, how

to ameliorate the sources of destructive labormanagement relations and lay the groundwork

for a more constructive long-term relationship;

and second, how to deal with another lengthy

strike should it occur.

Under the present legislation, the Federal

Government can do little to directly alter the

terms or context of labor-management relations. The principal exceptions are measures

designed to ensure a growing or stable market

for coal by mandating or inducing the use of

coal instead of gas or oil. The recently passed

National Energy Act contains a number of

such provisions, including a prohibition

against the use of oil and gas in new utility or

industrial boilers, DOE authority to require

capable facilities to use coal, and restrictions

on the use of gas in existing utility powerplants. A stable market should ease the

historic insecurity of both operators and

miners that has been such a large factor in the

industry’s labor problems. Other measures are

more indirect and relate to the basic social, environmental, and other ills of the coalfields

that contribute to the miners’ discontent.

These options are outlined in earlier portions

of this chapter.

In the event of another major coal strike the

Federal Government will have an interest in

achieving a settlement that is prompt, noninflationary, and that establishes the basis for

long-term labor-management stability. If the

latter condition is to be met, the settlement

must be supported by a substantial majority of

rank-and-file miners and must address some of

the underlying problems noted previously.

In pursuit of these objectives, five major

strategies or approaches will be available, as

they were during the 1978 strike:

1. reliance on collective bargaining with limited Government intervention,

2. collective bargaining with strong Government involvement,
Ch. Vlll—Policy Options ● 397

3. use of Taft-Hartley with limited efforts at

enforcement,

4. Taft-Hartley with vigorous enforcement,

and

5. Government seizure of the mines.

Each has its own set of opportunities and liabilities. Of the five, only the last will require

legislation. It should be emphasized that these

options are purely instrumental; they are independent of any judgment on the substantive

merit of the labor/management issues in dispute.

Collective Bargaining With Limited

Government Intervention

Under this approach resolution of the strike

would be essentially left to bargaining between negotiators for UMWA and BCOA. The

Federal Government would limit itself to encouraging the negotiators by “jawboning,”

meditation, and public appeals to the industry

rank-and-file miners.

The major argument in favor of this policy is

that it enables the Government to avoid a

direct confrontation with either the operators

or the miners. If strike-related damage to the

economy can be kept to manageable levels

(due perhaps to mild weather and increasing

production from nonunion mines), this strategy

promises to leave BCOA and UMWA increasingly isolated as their mutual leverage over the

rest of society declines. Under these conditions the strike may be seen by both labor and

management as increasingly self-defeating,

thereby hastening a negotiated settlement.

The principal arguments against this approach are that it offers no assurance of a

quick end to the strike or that a settlement,

when achieved, will be anything more than a

temporary truce borne of mutual exhaustion

that leaves the underlying causes of labor

unrest in the coalfields intact. Moreover, if a

prompt settlement is not achieved, the credibility of the Government’s energy policy may

be seriously undermined with consequent

long-term damage to the economy and the effort to reduce reliance on imported fuels.

Finally, a hands-off policy may contribute to

an image of Government ineffectiveness in

dealing with the problems of an industry that

has been identified as the key to America’s

energy future.

Collective Bargaining With Strong

Government Intervention

This approach would involve preserving the

framework of collective bargaining while

bringing substantial Government pressure to

bear on one or both parties to modify their

negotiating positions. The instrumentalities of

pressure will differ depending on whether the

operators or the union is the target. Means of

influencing the operators could include:

1,

2.

3.

4.

5.

6.

7.

8.

manipulation of Government contracts,

threat of Government seizure of the

mines,

vigorous implementation of antitrust laws

regarding horizontal and vertical divestiture,

proposed changes in the tax laws (e.g., the

coal depletion alIowance, the write off for

black lung benefits, rapidity of amortization, investment credits),

modifications in leasing reguIations,

a tightening or loosening of regulations

concerning coal imports and exports,

changes in the frequency of Federal

health and safety inspections of mines,

and

a general increasing or lessening of the

Government regulatory and permitting

burden on the industry.

Pressure on the union could take the form of:

1.

2.

3.

4.

5.

6

withholding food stamps from strikers,

threats to investigate union finances,

modifications in National Labor Relations

Board regulations to make it either easier

or harder to organize new mines,

threats of preferential Government purchasing from nonunion mines,

greater or lesser Government willingness

to make coal miners exceptions to national wage guidelines, and

an offer to explore means of using public

money to strengthen union health care

programs.

44.102 () - ‘i 1 - 27
398 The Direct Use of Coal

In addition, statements by Government

spokesmen can be used in an effort to pressure

or persuade both miners and operators.

Taft-Hartley With Limited Enforcement

This strategy is similar to that apparently

adopted by the administration following the

second rejection of a tentative contract by the

rank and file in early 1978. It involves the use

of Taft-Hartley to obtain police protection for

those miners who want to return to work. The

principal focus would be nonunion mines shut

down due to threats of violence by strikers at

nearby union mines. No effort would be made

to coerce unwilling miners back into the

mines. As an inducement, miners who went

back to work under a Taft-Hartley injunction

could be paid at a new higher wage scale

(within Government wage-price guidelines)

pending a final settlement. The basic advantage of this approach is that it permits the Government to facilitate a return to production of

nonunion mines without a major confrontation

with striking miners. To the extent that production is increased, the pressure on UMWA and

BCOA will mount. Warmer weather, the growing economic strain on miners and coalfield

communities, and an increase in coal prices

caused by supply shortages can all contribute

to that pressure.

There are several arguments against this

strategy. First, it does not assure a quick end to

the strike and thus leaves open the possibility

of all the negative economic effects identified

in the limited intervention option. Second, by

tacitly accepting defiance of Taft-Hartley by

UMWA miners this policy tolerates disregard

for the law and may contribute to a general impression of Government ineffectiveness in

energy matters. Third, this approach will probably be widely perceived as favoring the operators at the expense of the miners. Fourth, the

underlying assumption is that there is significant nonunion coal production that is not

forthcoming because of a union strike. This

may be a false premise. Finally, as with the first

policy option, there is little reason to think

that a settlement reached under this strategy

will successfully address the root causes of

labor unrest.

Taft-Hartley With Vigorous

Enforcement

With this strategy, every effort would be

made to use Taft-Hartley to persuade and, if

necessary, force miners to return to work.

Tools available to the Government include all

those listed under the second option plus fines

levied on recalcitrant union locals and arrests

of pickets. If necessary, separate agreements

between UMWA locals and individual coal

companies would be encouraged. Other aspects of the strategy might include the offer of

a provisional wage increase to miners returning under Taft-Hartley and creation of a White

House Commission to recommend terms of a

new contract. The basic effect of this policy is

to increase pressure on the union by making a

strike illegal for 80 days. Any efforts toward

encouraging local settlements and thereby

fragmenting the industry are a threat to both

the union and the operators. The result may induce renewed and productive BCOA-UMWA

negotiations under threat of such fragmentation.

The principal argument in favor of this option is that it is designed to achieve an immediate restoration of coal production. At

present both UMWA and BCOA are seriously

divided internally and consequently vulnerable to the threat of fragmentation. Given that

vulnerability, a possible outcome of this

strategy would be to induce the miners and

operators to resume serious negotiation in

order to forestall the mutual danger posed by

Government intervention. Also, an activist

posture by the administration should have

some political benefit in terms of providing an

image of decisive national leadership. There

may even be an important benefit if it becomes necessary to resort to individual agree

ments between specific union locals and coal

companies because fragmentation may create

the possibility of breaking the historic pattern

of labor relations in the industry. It could

create the opportunity for new leadership, new

ideas, and a new structure for union-industry

bargaining. This in turn may make it possible

to address some of the root causes of labor

unrest in the Eastern coal fields.
Ch. Vlll—Policy Options ● 399

Arguments against the invocation and vigorous enforcement of Taft-Hartley center on the

danger that the whole effort could be counterproductive. Previous attempts by the Government to use Taft-Hartley to force coal miners

back to work have been uniformly unsuccessful. Even a successful attempt could be politically damaging by antagonizing other unions

and blue-colIar workers generalIy. On close examination, some of the tools available to

Government are of dubious utility. Because

many union locals may already be bankrupt,

fines could be ineffective, A cutoff of welfare

benefits and food stamps may be successfully

challenged in the courts with the result that

new legislation will be required. Reliance on

Taft-Hartley will clearly antagonize UMWA,

and to the extent fragmentation is threatened,

BCOA as well. Fragmentation might well result

in anarchy rather than a new industry structure, with competitive inflationary wage increases and labor instability the result. Localized settlements or an industrywide settlement

reached under the threat of fragmentation are

unlikely to systematicalIy address the underlying causes of labor instability. Also, a strong

and cohesive union wilI be required if the pervasive community and environmental problems of Appalachia are ever to be solved. It

will not be easy to reconstitute an industrywide union; dismemberment of UMWA might

prove to be effectively permanent. Moreover,

a basic tenet of national labor policy is to

facilitate, not undermine, collective bargaining.

Government Seizure of the Mines

If invocation of the Taft-Hartley Act fails to

bring settlement of a strike, the remaining option of last resort is seizure of the mines by the

Federal Government. Such action would require the passage of enabling legislation by

Congress. The case for legislation would presumably be made in terms of the strike’s shortterm impact on the economy and the longterm injury done to the Government’s effort to

meet the Nation’s energy requirements

through increased use of coal. It should be

noted, however, that retrospective analysis of

the 1978 strike indicates that the economic impacts, with localized exceptions, were quite

manageable. Because of a projected increase

in nonunion western production, a future

strike would have even less damaging consequences for the national economy.

History suggests that if seizure is to be effective, the authorizing legislation must provide

the President with the power to control the

conditions under which seizure is carried out.

This means authority to change the terms and

conditions of employment, to decide when the

property should be returned to private ownership, and to seek injunctions in Federal court if

there is resistance to this control. The President also has at his command a number of

sanctions — moral, economic, military, judicial, and legislative —the use of which Congress must be prepared to support if they are

to be effective.

On taking control of the mines, the Government might try to resolve the impasse that led

to the strike by mediating between the parties.

More severe Government actions would include removal of the existing management personnel, alteration of the conditions and terms

of employment, and wage increases (or decreases). Strikes would be forbidden. A decision concerning the conditions of takeover

might follow an inquiry by a White House

Commission and consultations with miners

and operators. The Government could choose

to negotiate a new contract with the union and

make its acceptance by management a condition for returning the mines to their former

ownership. By directly negotiating a new labor

contract the Government might be in a position to break the historic cycle of mistrust and

hostility in coal labor relations. For example, a

Government-negotiated contract might go far

to meet the miners’ demands concerning such

key noneconomic issues as medical care and

safety. At the same time a systematic effort to

improve the quality of life in the coalfield

communities could alter the environment that

nourished the miners’ discontent. To the extent

these objectives are achieved, the climate for a

successful implementation of a national energy policy will be markedly improved.

Arguments for this approach center on the

contention that it is a way of acheiving both a
400 ● The Direct Use of Coal

quick and durable settlement. It is seen as an

extreme remedy necessitated by the severity

and intractability of the problem, This strategy

is also attractive on the grounds that it will

probably be welcomed by UMWA and organized labor generally and should convey an

image of governmental decisiveness and vigor

to the public as a whole.

Arguments against this option begin with the

observation that the historical record of the

use of seizure in labor disputes has not been

altogether happy. Of the 71 instances in which

it has been used since the Civil War, only 40

resulted in agreements between labor and

management before the property was returned

to its owners. In the 31 remaining instances

negotiations took place after the seizure was

terminated and in 20 cases strikes occurred.

Moreover, in 38 of the seizure cases either

labor or management obstructed production in

some way while the Government was running

the business. President Truman’s seizure of the

steel mills in 1952 was welcomed by the unions

but eventually resulted in a 53 day strike. The

fact that the seizure of the coal mines would

require congressional legislation raises the

possibility of congressional delay or veto.

Significant congressional reservations. seem

likely given the predictable opposition of the

coal companies and a generalized uneasiness

with seizure as socialistic. To the extent that

seizure undermines business confidence in the

administration, the political costs could be

high. Finally, the seizure or an attempted

seizure of the mines wilI preoccupy congressional and executive energies and attention at

the expense of other high priority concerns.

WORKPLACE HEALTH AND SAFETY

Underground mining is a hazardous occupation as measured by the incidence of work-related accidents and disease. Health and safety

issues have been a major factor behind labor

unrest in the coal industry— including the 109-

day UMWA strike of 1977-78. Any substantial

increase in coal production will inevitably be

purchased at the price of thousands of ill and

injured miners.

Health

A number of measures designed to upgrade

the existing dust control system can be identified. They include:

● Assignment of higher priority to efforts to

control nonrespirable dust.

● Development of new methods of mitigating the health impacts of dust from longwall mining, including improved respirator designs, fans, and special ventilation

systems.

● Development of area sampler technologies (with appropriate standards) that

would supplement personal samplers. Unlike the latter, these area devices should

be capable of providing an immediate, on

the spot reading of dust levels.

● Reorganization of the respirable dustsampling program around the new sampler technology and around the concept

of miner control or joint control of the

program. Shared management should

minimize the opportunities for falsification of results that exist in the present program.

● Monitoring of the incidence of trace elements in coal dust.

● Support for research to resolve some of

the present uncertainty concerning the

adequacy of the 2-mg standard.

The Mine Safety and Health Administration

(MSHA) is now considering alternative sampling systems to improve measuring and reporting reliability. Two promising approaches

are in-mine dust measurement (allowing immediate correction of excessive dust) and continuous, machine-mounted monitoring that

would automatically cut power to operating

machinery when dust levels are too high. Both

of these approaches would require new capital

investment and could impede production dur-
Ch. Vlll—Policy Options . 401

ing the year or two they were installed. These

costs would probably be offset over time by a

lower prevalence of coal workers’ pneumoconiosis (CWP) among workers and lower operator-financed compensation expenses. The

present public costs of black lung compensation are substantial.

Other hazards – “nonrespirable ” dust, trace

elements, emissions from machinery fires and

diesel engines, and the like– contribute to respiratory illness to one degree or another. These

pollutants may work synergistically with coal

dust, thereby increasing the hazard to the

worker. Since the individual miner experiences

these hazards cumulatively, research and prevention programs should be structured in holistic, multifactor fashion rather than in terms of

single-factor hazards. Federal regulation may

be necessary to cover the respiratory hazards

the 1969 Act did not address specifically (e. g.,

trace elements). Improved monitoring and control technologies for these pollutants may be

needed.

Noise and stress are other significant minehealth concerns. The National Institute of Oc- .

cupational Safety and Health (NIOSH) has

recommended a tightening of the current noise

standards, but neither MSHA nor the Occupational Safety and Health Administration

IOSHA) has proposed implementing regulations. Miners experience significantly more

hearing loss than nonminers, and some studies

have linked noise to accidents. A more stringent noise standard would undoubtedly require additional investment by mine operators.

After this initial expense, however, production

costs should not be increased and productivity

may be enhanced by lowering workplace noise

levels. Medical costs and compensation are

likely to be reduced if a tougher standard is

adopted.

Job stress to which noise contributes, has

been implicated as an important causal agent

in coronary heart disease, gastrointestinal

malfunctions, severe nervous conditions, and

other disorders.

Recent studies have found more anxiety, depression, irritation, and somatic complaints

among miners than other blue-colIar workers.

Underground coal miners reported a high level

of emotional strain in a recent survey. Stress

and strain are probably associated with absenteeism, workplace hostility, and lower productivity. Shift rotation may be an important

source of job stress and disruption of family

life. It may also be related to adverse health

and safety effects. A Federal policy response

to this situation could include banning or

modifying certain work practices that research

identifies as key sources of job-stress, and establishing a program for monitoring workers

for signs of stress.

Safety

As coal production increases, more workers

are likely to be hired. If accident rates do not

improve, the number of fatalities and disabling

injuries will double and triple as production

and employment doubles and triples. It is

unlikely that any major labor-saving technology will be commercialized over the next 15 to

20 years that would sharply raise productivity

and reduce the number of workers exposed to

safety hazards. Therefore, it is necessary to

assess accident prevention strategies in the

context of existing mining systems.

The 1969 Coal Act sought to prevent coal

mine disasters. [t has succeeded. The number

and severity of disasters have been cut substantially in the last 8 years. Other legislated

safety measures — involving roof support, electrical hazards, blasting— have probably reduced fatalities and injuries, but the effects

are often difficult to separate and measure.

The principal need in the area of safety is to

develop a program to reduce the frequency of

disabling injuries (there were 15,000 such injuries last year, each of which cost more than 2

months of lost time).

Several measures designed to mitigate the

problem can be identified:

● Comprehensive, mandatory safety standards and design features for machinery.

● More safety conscious work procedures in

the mine such as preventing the accumulation of debris along haulage ways. A related measure would be to package supplies (e. g., cement) in small enough units
402 The Direct Use of Coal

●

●

●

●

to be handled easily in confined quarters

thereby avoiding back and other muscle

injuries.

Specially designed prevention programs

for high-accident mines devised jointly by

labor, management, and Federal officials.

Improved safety education and job training of workers and supervisors. This

should have measurable safety benefits

since so much of the work force is young

and inexperienced.

Greater frequency of visits by Federal

safety inspectors. Studies have shown an

inverse correlation between the incidence

of inspections and accidents.

Research into the relationship among the

pace of work, production quotas, and accidents.

● A greater voice for miners in safety decisions.

Safety does not come easily or cheaply,

Management and workers must practice it continually. Prevention-consciousness must be incorporated into the work attitudes of both

management and labor. The costs of inadequate attention to safety are measured in

lower productivity, compensation payments,

lost production time, lower morale, absenteeism, and medical bills. Upgrading safety

often involves capital investment, and may

lower productivity and output. On the other

hand, a conscientious approach to safety can

help production and productivity, and often

brings dollar benefits in terms of lower insurance premiums and medical bills,

LEASING

The most basic policy question concerns

whether additional leasing of Federal coal

lands will be required to meet projected increases in coal demand. Western coal comprises roughly half of the Nation’s coal

reserves and the Federal Government owns 60

percent and indirectly controls another 20 percent of Western coal. The extent to which

Western coal will be used to meet national

energy demand is presently unclear due to the

1977 amendments to the Clean Air Act, which

may have reduced the attractiveness of Western coal to utilities. Even if it turns out that

substantial quantities of Western coal are required, it is not clear how much (if any) new

Federal coal reserves would have to be leased.

There are already 18 billion tons of Federal

coal under lease and another 9 billion tons on

land for which preference right lease applications (PRLAs) are pending. However, the status

of PRLAs is very much uncertain as a consequence of the “commercialization quantities”

test to be applied to all applications. Coal

from PRLAs could meet national demand for a

decade or, alternatively, many PRLAs could be

found illegal or unable to pass the commercial

quantities test. Given the uncertainties it is impossible to predict when any new Federal lands

will have to be made available for leasing. In

any case, available sources of Western coal

will be adequate for the next several years,

regardless of the disposition of PRLAs. Moreover, recent court cases mean that no new

leasing will be possible until the early 1980’s at

the earliest.

By that time it is possible that a tight coal

market could create the conditions for a coal

land rush in the West. The clearest way for the

Federal Government to defuse such an event is

to prepare contingency plans for the orderly

resumption of coal leasing at that time, This

will require the Government to select among

various options for an overall long-term approach. Recently a high-level review committee within the Department of the Interior addressed this problem and produced an option

paper.

The stated goal of the paper is to suggest

alternative approaches for managing coal resources that emphasize environmental and

land use planning and enable the Department

of the Interior to adjust the amount of coal

leased to production goals set by DOE.

For each suggested option, land use planning and environmental standards are employed to assess which “coal resource areas”
Ch. Vlll—Policy Options ● 403

are suitable for mining. Within those areas specific tracts would be identified for leasing. Production goals set by DOE would determine

how many mines would be opened. The options differ as to whether industry or Government identifies the areas and tracts for leasing

and designates the areas to be subject to environmental and land use assessment.

Option 1:

Industry Nominates Areas and Tracts

for Leasing

Under the first option proposed by the Review Committee, industry would nominate

those areas it desired to mine. The Department

of the Interior would then perform various

land use and environmental studies to determine which of the nominated resource areas

was suitable for mining. Interior would estimate the production potential of the suitable

areas relation to the production goals set by

DOE. A decision on which areas actually to

lease would be made taking into account “by

trading off the projected resource needs and

environmental consequences of developmerit. ” If the areas nominated by industry and

found suitable for development failed to provide sufficient coal to meet production needs,

then the Department of the Interior would

designate additional areas on its own initiative. Finally, industry would nominate specific

tracts that it desired to lease within each

selected leasing area. The frequency and size

of leases wouId be adjusted to meet DOE production goals.

Option II:

Government Identifies Areas for

Leasing and Industry Nominates

Specific Tracts

Under the proposed second option the selection of potential coal leasing areas would first

be made by the Department of the Interior.

Coal areas appearing to have “significant national potential” would be identified and subjected to environmental and land use analysis.

Those areas found suitable for leasing would

be “selected and prioritized by comparing

resource, socioeconomic, and environmental

values. ” Using DOE production targets as a

goal, leasing targets would be set for those

areas found to have the highest priority. Industry would then be asked to nominate tracts

within the selected areas that it wished to

lease. The frequency and size of leases would

be timed to meet the leasing targets for each

area.

Option Ill:

Government Selects Areas and Tracts

for Leasing

Under the third option suggested by the Review Committee, the Government would follow the procedure specified under Option II

for selecting areas for mining and setting leasing targets for each area. I n addition, however,

the Government would select those specific

tracts to be offered for lease without requesting nominations from industry. As with Option

II the frequency and size of leases would be

keyed to the area leasing targets.

Comparison of the Options

Table 63 summarizes the Department of the

Interior’s comparison of these three options.

As can be seen, in the Department’s opinion,

the more involved the Government becomes in

the planning process the higher the cost to the

Government and the greater the chance of production shortages produced by reason of

Government errors in selecting areas that are

not economically suitable for mining. On the

other hand, the greater the Government role

the more assurance there will be that adverse

social, economic, and environmental impacts

can be minimized.

Whichever approach is ultimately selected,

a number of specific issues will have to be

clarified. They include logical mining units,

preference right lease applications, the requirements of diligent development and continued operation, estimated recoverable reserves, advance royalty payments, and the exchange of environmentally sensitive leased

lands for other unleased Federal land. These

topics are examined in chapter V1. There are

also some important institutional issues con-
404 The Direct Use of Coal

cerning the division of responsibility between of the leasing process, considerable effort will

the Department of the Interior and DOE re- be required to prevent it from becoming hopegarding leasing. Given the inherent complexity Iessly lengthy and cumbersome.

Table 63.—Comparison of Policy Options Under Consideration by the Department of the Interior

—

Option I Option II Option Ill

1. Determination of production goals. . . . . . . . . . Government Government Government

2. Identifies areas for leasing. . . . . . . . . . . . . . . . . Industry Government Government

3. Identifies tracts for leasing . . . . . . . . . . . . . . . . Industry Industry Government

4. Defines areas for environmental planning . . . . Industry Government Government

5. Cost of planning and administration. . . . . . . . . — Increasing *

6. Chances for environmental mistakes. . . . . . . . — Decreasing -

7. Chances for production shortages . . . . . . . . . . — Increasing -

8. Likelihood of litigation . . . . . . . . . . . . . . . . . . . . — Decreasing *

9. Consideration of socioeconomic concerns. . . — Increasing

SOURCE: US Department of the Interior

CONCLUSION

With the possible exception of carbon dioxide pollution, all the significant problems

associated with substantially increased coal

use appear to be solvable. That is, policy remedies exist to make coal a viable fuel option for

the United States through 2000. But the fact

that effective policies can be identified does

not mean they will be adopted and implemented. If coal use is to be facilitated and the

potential adverse impacts of such use controlled, a complex network of law and regulation will be required to deal with environmental, community, health, safety, and other

impacts and to a lesser extent, coal supply and

demand. Most of that framework already exists but some does not. Under the best of circumstances there will be difficult problems of

coordination, administration, enforcement,

technological improvement, and cost. In short,

the ingredients for an effective national coal

policy exist, but that achievement will not

come easiIy or inexpensively.
Glossary
ACRONYMS

407
408 ● The Direct Use of Coal

DEFINITIONS

Acre-foot: A measure of water 1 foot deep

by an acre in area, or 43,560 ftj.

Ambient Air Quality Standards: According to

the Clean Air Act of 1970, the air quality

level which must be met to protect the

public health (primary) and welfare

(secondary). Secondary standards are

more stringent than Primary Ambient Air

Quality Standards.

Anthracite Coal: A hard, high rank coal with

high fixed carbon.

Aquifer: A subsurface zone that yields economicalIy important amounts of water to

wells; a water-bearing stratum or permeable rock, sand, or gravel.

Ash [fly ash): Light-weight solid particles

that are carried into the atmosphere

stack gases.

Base Load: The minimum load of a util

electric or gas, over a given period

time.

Best Available Control Technology (BAC

by

ty,

of

T]:

A technology or technique that represents

the most effective pollution control that

has been demonstrated, used to establish

emission or effluent control requirements

for a polluting industry.

Bituminous Coal: The coal ranked below anthracite. It generally has a high heat content and is soft enough to be readily

ground for easy combustion. It accounts

for the bulk of all coal mined in this country.

Black Lung Disease: A group of pulmonary

diseases that are common among coal

miners.

BTU: British thermal unit, a measure of the

energy required to raise one pound of

water one degree Fahrenheit.

Coal Gasification: The process that produces

synthetic gas from coal.

Coal Liquefaction: Conversion of coal to a

liquid for use as synthetic petroleum.

Commercial Sector: A subsector of service

industries that includes wholesale and

retail trade, schools and other government nonmanufacturing facilities, hospitals and nursing homes, and hotels. As defined, this sector does not include transportation and household services.

Criteria Pollutants: Six pollutants identified

prior to passage of the Clean Air Act

Amendments which now have established

Ambient Air Quality Standards, i.e., sulfur

dioxide, particulate matter, carbon monoxide, photochemical oxidants, nonmethane hydrocarbons, and nitrogen oxides.

Effluent: Any water flowing out of an

enclosure or source to a surface water or

groundwater flow network.

Elasticity: The fractional change in a

variable that is caused by a unit change in

a second variable. Income elasticities are

important in energy estimates, since these

estimate the changes in quantities of

energy demanded as incomes change.

Electrostatic Recipitator (ESPJ A device for

cleaning stack gas of particulate. The

device first charges particles in the gas

stream and then collects them on an oppositely charged surface.

Enhanced Oil Recovery (EOR): A variety of

techniques (other than conventional

pumping) for extracting additional quantities of oil from a well.

Fertility Rate: Average number of lifetime

births per woman.

Flue-Gas Desulfurization: The use of a stack

scrubber to reduce emissions of Sulfur oxides. See stack scrubber.

Fuidized Bed: A fluidized bed results when

gas is blown upward through finely

crushed particles. The gas separates the

particles so that the mixture behaves like

a turbulent liquid. Being developed for

coal burning for greater efficiency and environmental control.

Greenhouse Effect: The potential rise in

global atmospheric temperatures due to

an increasing concentration of C02 in the

atmosphere. CO, absorbs some of the

heat radiation given off by the Earth,

some of which is then reradiated back to

the Earth.

Cross Energy Demand: The total amount of

energy consumed by direct burning and
Glossary ● 409

indirect burning by utilities to generate

electricity. Net energy demand includes

direct burning of fuels and the energy content of consumed electricity. The difference between gross and net energy demand is a measure of the energy losses by

utility conversion to electricity. The difference between gross and net energy demand is a measure of the energy losses by

utility convers to electricity. About twothirds of the energy input at the utility is

lost in generation and transmission.

Gross National Product (GNP): The value of

all goods and services produced in a given

year. GNP is a “value added” concept. It

is stated in either current or constant (real)

dollars.

Groundwater: Subsurface water occupying

the saturation zone from which wells and

springs are fed; in a strict sense, this term

applies only to water below the water

table.

Heat Purmp: A device that moves heat from

one environment to another. I n the winter

it moves heat from the outside of a building to the inside, and in the summer it

moves heat from the inside to the outside.

Hydroelectric: Electricity generated by

water power.

Industry: Industry is an aggregate of three

sectors — manufacturing, mining, and construct ion.

In Situ Processing: In-place processing of

fuel by combustion without mining applies to oil shale and coal.

joule: A unit of energy which is equivalent to

1 watt for 1 second. 1 Btu = 1,055 Joules.

Labor force: The number of persons 16 years

of age or older who are either employed

or actively looking for work.

Lignite: The lowest rank coal from a heat

content and fixed carbon standpoint.

Metallurgical Coal: Coal used in the

steel making process. Its special properties

and difficulty of extraction make it more

expensive than steam coal.

Methane: CH,, carburated hydrogen or

marsh gas formed by the decomposition

of organic matter. It is the most common

gas found in coal mines.

NEP: National Energy Plan, the plan

presented to Congress by President Carter

in April 1977.

New Source Performance Standards: Standards set for new facilities to ensure that

ambient standards are met and to limit

the amount of a given pollutant a stationary source may emit over a given

time.

Oil Shale: A finely grained sedimentary rock

that contains an organic material, kerogen, which can be extracted and converted to the equivalent of petroleum.

Participation Rate: The percentage of persons 16 years of age or older who are

either employed or actively looking for

work. I n 1976, the participation rate was

62.1 percent.

Particulate Matter: Solid airborne particles,

such as ash.

Peak Power: The maximum amount of electrical energy consumed in any consecutive number of minutes, say 15 or 30

minutes, during a month.

Petrochernical Feedstocks: Petroleum used

as an industrial raw material to manufacture goods, such as chemicals, rather than

as a source of energy.

Prevention of Significant Deterioration

(PSD): Pollution standards that have been

set to protect air quality in regions that

are already cleaner than the Ambient Air

Quality Standards. Areas are divided into

three categories determining the degree to

which deterioration in the area will be

allowed.

Prime Farmlands: Land defined by the

Agriculture Department’s Soil Conservation Service based on soil quality, growing

season, and moisture supply needed to

produce sustained high crop yields using

modern farm methods.

Primitive Areas: Scenic and wild areas in the

national forests that were set aside and

preserved from timber cutting, mineral

operations, etc., from 1930-39 by act of

Congress; these areas can be added to the

National Wilderness Preservation System

established in 1964.

Process Steam and Heat: Steam and heat

produced for industrial process uses, such
410 ● The Direct Use of Coal

as the activation of drive mechanisms and

product processing.

Productivity; The value of goods or services

produced by a worker in a given period of

time, such as 1 hour. For the United States

in 1975, this averaged $7.39. Increas

e

s in

output over time are used to measure

gains in productivity. A variety of timeperiods are used, including output per

worker per year. Also, productivity statements often refer to gains in private sector

output per worker rather than output in

the total economy.

Quad: One quadrillion (10’5

) British thermal

units (Btu).

Reclamation: Restoring mined land to productive use; includes replacement of topsoil, restoration of surface topography,

waste disposal, and fertilization and

revegetation.

Reserves: Resources of known location,

quantity, and quality which ar e

economically recoverable using currently

available technologies.

Residential/ Sector: Includes all primary livi ng units–houses, apartments, a n d

mobile homes. Households are classified

as follows: a) family households, which incorporate persons who are either married

or blood related; b) primary individual

households, which are made up either of

single persons or incorporate two or more

persons who are neither married or bloodrelated.

Resources: Mineral or ore estimates that include reserves, identified deposits that

cannot presently be extracted due to economical or technological reasons, and

other deposits that have not been discovered but whose existence is inferred.

Retrofit: A modification of an existing structure, such as a house or its equipment to

reduce energy requirements for heating or

cooling. There are basic types of retrofit:

equipment, such as a heat pump replacing

less efficient equipment; and insulation,

storm doors, calking, etc., designed to

lower energy requirements.

Seam: A bed of coal or other valuable

mineral of any thickness.

Slurry Pipeline: A pipeline that conveys a

mixture of liquid and solid. The primary

application proposed is to move coal long

distances (over 300 miles) in a water mixture.

Stack Scrubber: An air pollution control

device that usually uses a liquid spray to

remove pollutants, such as sulfur dioxide

or particulate, from a gas stream by absorption or chemical reaction. Scrubbers

are also used to reduce the temperature

of the emissions.

Steam Coal: Coal suitable for combustion in

boilers. It is generally soft enough for easy

grinding and less expensive than

metallurgical coal or anthracite.

Strip Mining: A surface mining method that

removes the overburden that covers the

coal seam in a series of parallel strips.

Subbituminous Coal: A low rank coal with

low fixed carbon and high percentages of

volatile matter and moisture.

Subsidence: The sinking, descending, or

lowering of the land surface; the surface

depression over an underground mine that

has been created by subsurface caving.

Sulfates: A class of secondary pollutants

that includes acid-sulfates and neutral

metalIic sulfates.

Sulfur: An element that appears in many

fossil fuels. In combustion of the fuel the

sulfur combines with oxygen to form

sulfur dioxide.

Sulfur Dioxide: one of several forms of

sulfur in the air; an air pollutant generated

principally from combustion of fuels that

contain sulfur.

Supply: The functional connection between

the price of a good and the quantity of

that good that some agent is willing to sell

at that price. The supply function is

generally positive, or (geometrically

speaking) up-sloping, meaning that as

price goes up, the quantity supplied also

goes up.

Swing Fuel: A fuel that plays a key role during the transition from exhaustible to inexhaustible fuels. Coal is viewed by many as

the swing fuel during the transition.

Synthetic Fuel: A fuel produced by

biologically, chemically, or thermally

transforming other fuels or materials.
Glossary . 411

Traportation Sector; Includes five sub - Western Coal: Can refer to all coal reserves

sectors: 1 ) automobiles; 2) service trucks; west of the Mississippi. By Bureau of

3) truck/bus/rail freight; 4) air transport; Mines definition, includes only those coaland 5) ship/barge/pipel inc. fields west of straight line disecting MinUnit Train: “A system “for delivering coal in nesota and running to the Western

which a string of cars, with distinctive Texas. Wyoming and Montana

markings and loaded to full visible capaci- bituminous) and North Dakota (1

ty, is operated without service frills or have the largest reserves.

stops along the way for cars to be cut in

and out.

tip of

(subgnite)

0