An Assessment of Development and

Production Potential of Federal Coal

Leases

December 1981

NTIS order #PB82-149378
Library of Congress Catalog Card Number 81-600178

For sale by the Superintendent of Documents,

U.S. Government Printing Office, Washington, D.C. 20402
Foreword

This report is submitted in fulfillment of OTA’s mandate under the Federal

Coal Leasing Amendments Act of 1976 (Public Law 94-377) “to conduct a complete study of coal leases entered into by the United States under section 2 of the

act of February 25, 1920 (commonly known as the Mineral Lands Leasing Act). ”

The act directed that the study “shall include an analysis of all mining activities, present and potential value of said coal leases, receipts of the Federal

Government from said leases, and recommendations as to the feasibility of the use

of deep mining technology in said leased area. “ “Present and potential value”

have been defined as the amount of potential coal production from Federal leases

in the next decade.

This study differs from the typical OTA assessment in that the report

“assesses” resources instead of technology. The main focus of the study is an

estimation of the likely production from the existing 548 Federal coal leases in the

seven major Western coal States. Although technical factors, mostly of a geological and mining engineering nature, were important in arriving at these estimates,

the evaluation of technology was not central to the work.

OTA’s analysis was greatly aided by the five State task forces held by OTA in

Colorado, New Mexico, Oklahoma, Utah, and Wyoming. The task forces, composed of participants from State governments, local and Federal agencies, industry, citizens groups, and local universities were of inestimable help to OTA in

evaluating the development potential of undeveloped leases and in providing insights on the factors affecting coal development in these regions,

The estimates of potential production from Federal leases made in this report

are not forecasts of the coal that would be produced at a given price or a given demand. They are estimates of the total amount of coal that could be produced from

existing and planned Federal mines and from those undeveloped Federal leases

that have mining costs competitive with costs at currently operating mines in the

same area. If the demand for Federal coal does not increase to these levels of potential production, then not all the Federal leases that could technically and economically be developed will be mined.

We hope that this report will provide Congress with helpful insights for the

impending debates on Federal coal leasing and coal use goals for the United

States.

‘Director

iii
Federal Coal Leasing Advisory Panel

Lynton K. Caldwell, Chairman

Department of Political Science, Indiana University

Jack Simon, Co-chairrnan

Director, Illinois State Geological Survey

James Boyd

private Consultant

C. Wayne Cook

Department of Range Science

Colorado State University

Lloyd Ernst

Manager of Operations

Western Fuels Association, Inc.

Thomas France

Private Consultant

Gerrie Greene

Legislative Representative

National Association of Counties

James R. Jones

Director of Environmental Quality

Peabody Coal Co.

Carla Kish

Western Organization of Resource Councils

Robert Lang*

Plant Sciences Division

University of Wyoming

Jonathan Lash

Senior Project Attorney

Natural Resources Defense Council, Inc.

Alfred Petrick, Jr.

Petrick Associates

Daniel J. Snyder

President

Colorado-Westmoreland, Inc.

Gary Tabak* *

Western Fuels Association, Inc.

Joseph Yancik

Vice President, Research and Technical Services

National Coal Association

iv
Federal Coal Leasing Project Staff

Lionel S. Johns, Assistant Director, OTA

Energy, Materials, and International Security Division

Audrey Buyrn, Materials Program Manager and Acting Project Director

Karen L. Larsen Michael J, Gargas McGrath*

Associate Project Director Senior Project Associate

J. Russell Boulding James S. Cannon Jack C. Schmidt** Lawrence E. Welborn*

Research Staff

Iris A. Goodman Nancy Greenebaum James K. Hayes

Deborah L. Pederson J. Stephen Schindler Sara E. Wright Aleka Unkovskoy

Administrative Staff

Carol A. Drohan Patricia A. Canavan Margaret Connors Holmberg

OTA Publishing Staff

John C. Holmes, Publishing Officer

John Bergling Kathie S. Boss Debra M. Datcher Joe Henson
Contractors and Consultants

This report was prepared by the Office of Technology Assessment Materials Program. The Materials

Program wishes to acknowledge the assistance and cooperation of the following contractors and consultants in the collection and analysis of data.

Hope M. Babcock

Christopher J. Bise

Lynda L. Brothers

Douglas W. Canete

Cartography, Inc.

Colorado Energy Research Institute

Colorado School of Mines Research Institute

Dames & Moore

Earth Satellite Corp.

Energy and Environmental Analysis, Inc.

Hoffman-Muntner Corp.

Mel Horwitch

Vladumir J. Hucka

Thomas W. Hunter

Joan E. Martin

Sanna Porte

Powder River Basin Resource Council

Resource Consulting Group, Inc.

James J. Sebesta

Curtis Seltzer

Arnold J. Silverman

Cheryl A. Stevenson

The Tosco Foundation

U.S. Fish and Wildlife Service (WELUT)

University of Utah

Utah Geological and Mineralogical Survey

John D. Wiener

Martin E. Zeller

Contributors

OTA wishes to acknowledge the assistance of the following individuals:

Ralph J. Blumer, U.S. Geological Survey* Stanley P. Schweinfurth, U.S. Geological Survey*

William E. Davis, Materials Program Frank J. Wobber, U.S. Department of Energy***

E. Alan Phillips

Albert E. Paladino, National Bureau of

Standards* *

*On detail to OTA from U.S. Geological Survey.

* * Materials Program Manager through December 1978. * * * Formerly OTA Staff

Acknowledgments

OTA also wishes to acknowledge the contributions and cooperation of the following agencies and

organizations:

American Mining Congress

Association of American Railroads

Colorado Department of Natural Resources

Montana Bureau of Mines and Geology

Montana Department of State Lands

National Coal Association

New Mexico Energy and Minerals Department

North Dakota Geological Survey

North Dakota Public Services Commission

North Dakota State Department of Health

Oklahoma Department of Mines

Oklahoma Geological Survey

Pittsburgh Mining Technology Center

U.S. Department of Energy

U.S. Department of the Interior

Bureau of Land Management

Bureau of Mines

Geological Survey

Office of Surface Mining

Utah Geological and Mineralogical Survey

Western Organization of Resource Councils

Wyoming Department of Environmental Quality

Wyoming Game and Fish Department

Wyoming Geological Survey

Wyoming Natural Heritage Program,

The Nature Conservancy

In addition, OTA wishes to express its appreciation to the many individuals, organizations and companies who acted as reviewers for this report, and to the many Federal coal lessees without whose

cooperation this report would not have been possible.

vi
Participants in the State Task Forces

Colorado

William Bosworth

Sheridan Enterprises, Inc.

Archie Carver

U.S. Geological Survey

C. Wayne Cook

Colorado State University

Henry E. Davis

Peabody Coal Co.

Doran Gillette

Bureau of Land Management

Scott Grace

U.S. Environmental Protection Agency

Dewitt John

Department of Natura Resources

Dan Kimball

Office of Surface Mining

Carla Kish

Western Organization of Resource

Councils

Lewis Ladwig

Colorado Geological Survey

Dan Martin

Bureau of Land Management

D. Keith Murray

Colorado School of Mines Research

Institute

Chris Seglem

Colorado-Westmoreland Inc.

Greg Spanski

U.S. Geological Survey

Robert Turner

National Audubon Society

New Mexico

William G. Bradley

Chaco Energy Co.

Robert Calkins

Bureau of Land Management

Cubia L. Clayton

Environmental Improvements Division

New Mexico Health and Environment

Department

William Darmitzel

New Mexico Mining Association

James Edwards, Jr.

U.S. Geological Survey

Lucy Fox

New Mexico Energy and Minerals

Department

Steven J. Frost

New Mexico Bureau of Mines and

Mineral Resources

D. Eugene Gray

State Engineer’s Office

Louis Martinez

New Mexico Energy and Minerals

Department

Mat Millenbach

Bureau of Land Management

Joseph A. Pierce

New Mexico Health and Environment

Department

Charles Roybal

New Mexico Energy and Minerals

Department

Jon Samuelson

New Mexican State Planning Office

Wyoming

Walter C. Ackerman

Department of Environmental Quality

Stephen Berg-Hansen

Rocky Mountain Energy Co.

Jerry Boggs

Office of Surface Mining

C. Wayne Cook

Colorado State University

Norman Dalstead

Colorado State University

Fred Eiserman

Energy Transportation Systems, Inc.

John Eichenauer

NERC0, Inc.

Joseph Evans

Department of Economic Planning and

Development

Chris Farrand

Peabody Coal Co.

Thomas M. France

Northern Rockies Action Group

Gary B. Glass

Wyoming Geological Survey

Joseph M. Hamner

Carter Coal Co.

Harry J. Harju

Wyoming Game and Fish Department

Bernice Heilbrunn

Exxon Coal USA, Inc.

Carla Kish

Western Organization of Resource

Councils

Ron Kisicki

Wyoming Highway Department

John Lane Wyoming Highway Department

Marion Loomis

Wyoming Mining Association

Arnie Mattila

Rock Springs District Mining Office

J. Stan McKee

Bureau of Land Management

Richard Moore

industrial Siting Administration

Kenneth Nation

U.S. Geological Survey

James J. Sebesta

Colorado State University

Frederick Scheerer

Arco Coal Co.

Mark R. Stromberg

Wyoming Nature Conservacy

Richard Tupper

Black Hills Power & Light Co.

James Vandel

Wyoming Highway Department

Warren White

Office of the Governor

John Wiener

Environmental Consultant/Attorney

Reed Zars

Powder River Basin Resource Council

Oklahoma

Ernest Achterberg

U.S. Geological Survey

Robert Brown

Bureau of Land Management

Ray Brubaker

U.S. Department of the Interior

Michael E. Cyr

Bureau of Land Management

William Dahlgrcn

Dahlgren Contracting Co.

Samuel A. Friedman

Oklahomo Geological Survey

James Gegen

Bureau of Land Management

Homer G. Meyer

Bureau of Land Management

Jeff Porter, III

Garland Coal Mining Co.

Blaney Qualls

Oklahoma Department of Mines

Nick M. Spanos

Armco Materials Resources

Utah

Gordon Anderson

Friends of the Earth

C. Wayne Cook

Colorado State University

Ron Daniels

Utah Department of Natural Resources

Hellmut Doelling

Utah Geoligical and

Mineralogical Survey

John Garr

Coastal States Energy Corp.

Frank Hachman

University of Utah

Dan Kimball

Office of Surface Mining Region V

Jack Moffitt

U.S. Geological Survey

Lyman Moore

Bureau of Land Management

Robert Moore

Utah Coal Operators Association

Max Nielson

Bureau of Land Management

Ken Riddle

Utah Department of Transportation

Carol Senden

Bureau of Land Management

Vll
Contents

Chapter Page

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Background and Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Federal Coal Leases and Preference Right Lease Applications:

An Overview. , , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Federal Coal Resources, ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Markets and Projected Demand for Federal Coal. . . . . . . . . . . . . . . . . . . 79

Development Potential and Production Prospects of

Federal Coal Leases. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .113

The Powder River Basin: A Case Study. . .........................169

Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........201

Federal Coal Lease Management. . . . . . . . . . . . . . . . . . . . . . . .........227

Implications of Environmental and Reclamation Issues for

the Development of Federal Coal.... . ...........................273

Mining Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........323

Revenues and Socioeconomic Impacts. . . . . . . . . . . . . . . . . . . . . . . . ...347

Patterns and Trends in Ownership of Federal Coal Leases and

PRLAs 1950-80 . . . . . . . . . . . . . . . . . . . . . . . . .......................371

Appendixes

A. Development and Production of Federal Coal Leases in

the Southern Rocky Mountain States. . . . . . . . . . . . . . . . . . . . . . .......389

B. OTA Working Lease List and Lessee Index . . . . . . . . . . . ..............408

C. Acronyms, Abbreviations, and Glossary . . . . . . . . . . . . . . . ............466

D. Some Key References. .. . . . . . . . . . . . . . . . . . . . . . . . ..............470

E. Availability of OTA Working Papers . . . . . . . . . . . . . . . ...............473

ix
CHAPTER 1

Executive Summary
Page

Overview ● .... ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ 3

Status of Federal Coal Leases . . . . . . . . . . . . . 6

Federal Coal Resources and Production . . . . . 7

Ownership of Federal Coal Leases.. . . . . . . . . 10

Lease Development Status. . . . . . . . . . . . . . . . 11

Potential Production From Federal Coal

Leases in 1986 and 1991. . . . . . . . . . . . . . . . . 16

Development Prospects of Undeveloped

Federal Coal Leases. . . . . . . . . . . . . . . . . . . . 16

Production and Capacity Estimates for 1986

and 1991: Developed and

Undeveloped Leases. . . . . . . . . . . . . . . . . . . . 17

Diligent Development . . . . . . . . . . . . . . . . . . . . 21

The Powder River Basin. . . . . . . . . . . . . . . . . . 22

Factors Affecting Federal Lease Development

and Federal Coal Production . . . . . . . . . . . . . 25

Market Factors. . . . . . . . . . . . . . . . . . . . . . . . . 25

Environmental Factors. . . . . . . . . . . . . . . . . . . 26

Laws and Regulations on Management of

Existing Federal Leases. . . . . . . . . . . . . . . . . 29

Transportation Considerations . . . . . . . . . . . . 31

Revenues and Socioeconomic

Considerations. . . . . . . . . . . . . . . . . . . . . . . . 32

List of Tables

Table No. Page

l. Federal Leaseholdings and Production by

Business Category . . . . . . . . . . . . . . . . . . . . 13

2. 1979 and 1980 Coal Production From the

Seven Federal Coal States Studied in

This Report ..... ● ,.... .. ,..,. ● . 15

3. Development Potential of

Undeveloped Leases. . . . . . . . . . . . . . . . . . . 16

4. Summary of Impacts to Federal

Recoverable Reserves From Environmental

and Reclamation Considerations . . . . . . . . . 27

5. Federal Royalties and State Distributions

From Potential Coal Production on

Federal Leases 1980, 1986, and 1991 . . . . . 32

List of Figures

Figure No. Page

I. Potential Production From and Planned

Capacity of Federal Mines Summed Over

the Six Major Federal Coal States . . . . . . . 4

2. Generalized Coal Provinces of the

United States. . . . . . . . . . . . . . . . . . . . . . . . 7

3. Sketch Map Showing Major Coal Regions

With Leased Federal Coal, and

Generalized Location of Strippable and

Metallurgical Coal Deposits. . . . . . . . . . . . 8

4. Distribution of Production, Reserves,

Acres, and Number of Leases by State . . . 8

5. Distribution of Federal Production.

6

Federal Mine Production and Total State

Production in 1979, by State, for the

Seven Federal Coal States Considered

in This Report . . . . . . . . . . . . . . . . . . . . . . . 9

Number of Leases, Acreage Under Lease,

and Federal Coal Production From

1950 to 1980....... . . . . . . . . . . . . . . 10

7. Annual Coal Production From the Six

Major Federal Coal-Producing States in

the West, 1957-79. . . . . . . . . . . . . . . . . . . . 11

8. Number of Federal Coal Acres Under

9

10

Lease by Business Activity Category,

1950-80 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

The Development Status of Federal

Coal Leases . . . . . . . . . . . . . . . . . . . . . . . . . 14

Planned Capacity and Potential

Production of All Mines With Federal

Leases in the Powder River Basin,

Southern Wyoming,and

Fort Union Region. . . . . . . . . . . . . . . . . . . . 19

11. Potential Production Capacity of All Mines ,

With Federal Leases in Colorado,

New Mexico, and Utah, . . . . . . . . . . . . . . . 20

12, Dilligent Development Summary for the

Powder River Basin . . . . . . . . . . . . . . . . . . 22

13. Dilligent Development Summary for the

Southern Rocky Mountain Region . . . . . . . 22

14. Comparisons of Powder River Basin -

Demand Projections With Planned

Capacity and Production Levels for

1990 . . . . . , . .. . . . . . . . . . ...... 24
CHAPTER 1

Executive Summary

Overview

As of late 1980, there were 565 Federal

coal leases* in existence in 14 States covering 812,000 acres and containing 16.5 billion

tons of recoverable reserves. This study examines the development potential and production prospects for the 548 Federal coal

leases in the seven States of Wyoming, Montana, Colorado, Utah, New Mexico, North

Dakota, and Oklahoma, with principal emphasis on the 502 leases in the first six States

listed above: the six major Western Federal

coal States. These six States contain over 98

percent of leased Federal reserves and account for over 99 percent of Federal coal production. The 17 small leases in Alabama,

Alaska, California, Kentucky, Oregon, Pennsylvania, and Washington, with 0.5 percent

of leased Federal coal reserves and 0.2 percent of Federal coal production, were not examined in this study. Furthermore, the development potential and production prospects of

currently unleased Federal coal were not examined in this study. Therefore, the findings

of this study on potential Federal coal production and its relation to likely markets for

Federal coal refer only to currently leased

Federal coal in the seven States of Colorado,

Montana, New Mexico, North Dakota, Oklahoma, Utah, and Wyoming.

A Federal coal lease may be conveniently

classified by its mine plan status: in an approved mine plan, or in a mine plan submitted

to and pending approval by the U.S. Department of the Interior (DOI), or with no mine

plan. The 565 Federal coal leases are

grouped as follows:

1. There are 198 leases in approved mine

plans covering nearly 280,000 acres,

and containing 7.4 billion tons of recoverable reserves.

*The leases sold in early 1981 under the new Federal coal

management program are not included in this total and were

not considered in this study.

2.

3.

Of these 198 leases, 182 are located in

the six major Western Federal coal

States listed above. The 182 leases are

included in 69 approved mine plans. Of

these 69 Federal mines, 64 produced

coal in 1979; the remaining 5 are scheduled to begin production within a few

years.

Total coal production from these 64

Federal mines in 1979 was 138 million

tons. The Federal portion of this production was 60 million tons, up from 7.3 million tons in 1970.** In 1979, Federal production in the six States of Wyoming,

Montana, Colorado, Utah, New Mexico,

and North Dakota accounted for 7.7 percent of the total U.S. coal production of

776 million tons, In 1980, Federal coal

production in these six States grew to 69

million tons, or 8.4 percent of the total

U.S. coal production of 820 million tons.

There are 118 leases in 32 pending mine

plans covering nearly 195,000 acres and

containing 2,5 billion tons of recoverable

reserves.

There are 249 leases not in mine plans A

covering nearly 338,000 acres and containing 6.6 billion tons of recoverable reserves. (These leases are called undeveloped leases in this report. ) However,

many of these leases are in the process

of being developed and could be in production within the decade.

**Coal from Federal coal leases is referred to as Federal

coal. A mine that includes a Federal lease is called a Federal

mine. Sometimes, for the sake of efficiency of recovery or

economy of operations, intervening State or private coal is

mined with Federal lease(s) in the same mine. This practice is

the rule in southern Wyoming and North Dakota, for example.

Thus, many Federal mines produce both Federal and non-Federal coal. A mine that contains no Federal coal is called a nonFederal mine. Total coal production in a State or region is thus

the sum of: 1 ) Federal coal production from Federal mines plus

2] non-Federal coal production from Federal mines plus 3) nonFederal coal product ion from non-Federal mines.

3
4 ● An Assessment of Development and Production Potential of Federal Coal Leases

Approximately 5 percent of currently

leased Federal reserves appear undevelopable because of poor property characteristics, remote location, or environmental prohibition. Considerable uncertainty surrounds

the likelihood of the development of another

15 to 20 percent of leased Federal reserves

(some of them in the pending mine plan category) because of factors such as construction of transportation systems, synfuels development, pace of associated powerplant

construction, availability of additional Federal reserves, and lessee development priorities. Delays in development and production

caused by these factors and by market uncertainties might result in leases containing over

7 billion tons of reserves, or 43 percent of all

currently leased reserves, to fail to meet diligent development requirements by 1991;

leases containing over 3.5 billion tons of recoverable coal are unlikely to meet diligence

by 1991; leases containing approximately 3.4

billion tons of recoverable reserves have

uncertainties surrounding attainment of diligence by 1991.

The following estimates of potential production from Federal leases are not forecasts

of the coal that will be produced at a given

price or a given demand. They are estimates

of the total amount of coal that could be produced from operating Federal mines and

from those Federal leases that have characteristics comparable to operating mines in the

same region. Coal from these leases would

thus be likely to have mining costs competitive with costs at currently operating mines in

the same area. If the demand for Federal coal

does not increase to these levels of potential

production, then not all the Federal leases

that could technically and economically be

developed will go into production.

Production from existing Federal coal

leases is likely to increase substantially over

the next 10 years. Planned production capacity for 1986 for Federal mines is 400 million

tons per year; for 1991, over 535 million tons

per year (see fig. 1). OTA estimates that production from Federal mines could range between 410 million and 500 million tons per

Figure 1.— Potential Production From and Planned

‘Capacity of Federal Mines Summed Over the

Six Major Federal Coal Statesa

600.

Likely 1990 demand range for all coal from the

six major Western Federal coal States 1

1979

A:

B:

c:

1966 1991

Year

Potential annual production, b

Lessees’ planned annual production from

Federal mines in currently approved mine plans

only

Lessees’ planned annual production from

Federal mines in currently approved and pending

mine plans

The sum of B, above, plus estimates of potential

production from presently undeveloped Federal

leases

a Wyoming, Montana. Colorado, Utah. New Mexico and North Dakota

b Planned capacity for a given year IS the upper Iimit to potential production in

that year (although an even higher total capacity might be attainable in a very

strong market for coal) In many cases (e.g., currently approved mines m the

Powder River Basin in 1991), the lessees’ production plans call for them to produce at or near capacity. In other cases, even optimistic production plans fall

short of using planned capacity to the full. Some mines, particularly newer

mines in the Southern Rockies wiII not attain their planned maximum capacity

until the 1990’s. In all cases, however, the capacities planned for 1986 or 1991

were used in deriving fig. 1, above, not the higher numbers for planned maximum capacities in the post 1991 period For most Federal mines in the

Southern Rockies, the planned productions for 1986 and 1991 are close to the

planned capacities for those years

Explanation of ranges

C: 92 million tons per year range in 1991

65 mty = Dominant uncertainty IS the development of markets for the coal

22 mty = Dominant uncertainty IS the construction of two railroads, one to the

Kaiparowits Plateau in Utah (14 mty) and one to the Star Lake. Bisti

area of New Mexico (8 mty)

5 mty = Dominant uncertainty IS the schedule of synfuels development

D 22 million ton per year range in 1991

Dominant uncertainty IS the construction of the two railroads mentioned

above, under C

SOURCE Office of Technology Assessment

year in 1991 depending on markets, synfuels

development, and rail construction. Actual

production in 1991 could fall below this

range, however, because of competition with

non-Federal mines and new Federal coal

leases in the West and from other coal-pro-
Ch. l—Executive Summary ● 5

ducing regions of the country and because

overall demand for coal may not grow sufficiently during the next decade to support this

level of production from Federal mines.

During the 1990’s, demand for coal in general and Western and Federal coal in particular may grow rapidly, particularly if coalbased synfuels and exports of Western coal

to foreign countries become important.

The Powder River basin of Wyoming and

Montana was the source of about 50 percent

of coal produced from Federal mines in 1979

(71.7 million tons) and contains 56 percent of

recoverable Federal coal reserves under

lease (9.2 billion tons). In 1979, there was

more than 75 million tons of overcapacity in

Federal mines in the Powder River basin. The

Powder River basin can increase production

substantially by 1990. For 1990, 186 million

tons of Powder River basin coal have already

been contracted: 159 million tons from currently operating Federal mines, 17 million

tons from undeveloped Federal leases, and 10

million tons from currently operating nonFederal mines. Planned capacity for 1990 for

all coal properties in the Powder River basin

likely to be in production by that year is

approximately 350 million tons per year. The

likely demand range for Powder River basin

coal for 1990 falls substantially below this

planned mine capacity.

The States of Colorado, New Mexico, and

Utah contain 360 Federal coal leases, about a

third of which (113 leases) are in active

mines, The five major coal-producing regions

in these three States have a wide range of

coal quality and mining conditions, The area

contains both large and small active surface

and underground mines.

In 1979, mines with Federal leases in Colorado, New Mexico, and Utah produced 35

million tons of coal, Little overcapacity in coal

production existed in these three States in

1979, New mine plan proposals have been

submitted for another 108 Federal leases and

96 out of the 139 leases that are not in mine

plans might be developed over the next decade. By 1991, Federal mines in these three

States could sustain 110 million to 146 million

tons per year of production, 65 million tons

per year from currently operating Federal

mines, 28 million to 49 million tons per year

from new Federal mines with plans are pending approval and 17 million to 32 million tons

per year from presently undeveloped leases.

These estimates are subject to two principal

uncertainties: 1) whether demand for coal

from this region will increase as generally expected; and 2) whether proposed coal transportation systems will be constructed to connect currently inactive coal mining areas in

southwestern Utah and the San Juan basin of

New Mexico with potential markets. At present, only the proposed Star Lake Railroad in

the San Juan basin is nearing approval. However, the above numbers suggest that there

will be little overcapacity in coal production

in this three-State region over the next

decade.

The potential for continued overcapacity in

the Powder River basin over the next 10

years has caused questions to be raised about

the timing, extent, and location of large-scale

leasing under the new Federal coal management program. The debate focuses on the role

of competition and the free market in resource supply, the potential costs to the social

and physical environments of the coal-producing areas of “overleaping,” the length of

time needed to bring a new lease into full

scale production, the margin of supply safety

needed for prudent planning on a national

and a corporate level, questions of equity

raised by restricted opportunities for new entrants to Federal leaseholding, a fair return

to the public for the use of its resources, and

the levels of demand likely in the early to mid1990’s. Many proponents of large-scale new

leasing in the Powder River basin in the near

future cite the long moratorium on such leasing and its effect of restricting entry possibilities to leaseholding as one reason for prompt

resumption. They also contend that postponing leasing will unduly interfere with the

workings of the free market and will restrict

competitition. They anticipate high demand

for coal by 1995 and fear that the present

leased reserve base in the Powder River
6 . An Assessment of Development and Production Potential of Federal Coal Leases

basin will not provide enough certainty or

flexibility to meet that demand efficiently.

Opponents of large-scale new leasing in the

Powder River basin as scheduled in 1982 cite

the potential for overcapacity through the

early 1990’s as proof that such leasing is not

necessary at this time. They contend that

leasing can be safely deferred until its necessity is clearly indicated by realistic demand

forecasts. They hold that large-scale leasing

substantially beyond that necessary to meet

likely demand in 1990 will place an unnecessary strain on orderly planning in the communities of the region, shift demand to the

Powder River basin that could have been met

by Midwestern supply, depress the value of

leases so that the public will not receive a fair

return for its resources, and, moreover, be

unlikely to increase competition significantly.

Minability of Federal coal reserves in the

West is affected by administrative and regulatory decisions in several aspects of environmental concern. These areas of concern include air quality, water resources, alluvial

valley floors, return to approximate original

contour, and wildlife resources. The effect of

environmental regulations on the production

of Federal coal has been to remove small

amounts of minable coal from the recoverable

reserve base, to delay development of other

recoverable reserves, to increase the complexity of the mine permit process, and to increase the overall cost of mining.

The percentage of recoverable Federal reserves currently under lease on which mining

could be prohibited or delayed over the next

10 years because of environmental regulations is between 5 percent and 10 percent of

the total currently leased reserves, Less than

1 percent of currently leased Federal reserves appear likely to be subject to complete

prohibition from mining; the remainder of

currently leased Federal reserves that may

be affected may be subject to delay in mining

because of unresolved environmental questions, but the available evidence indicates

that most of these reserves will be mined.

There are additional leased reserves (mainly

in the Kaiparowits Plateau in southern Utah)

over which there are potential environmental

conflicts, but impediments to development of

these reserves are primarily related to nonenvironmental factors such as transportation

availability y.

Status of Federal Coal Leases

In terms of tonnage, a little over one-half of

the U.S. recoverable coal reserves lies west

of the Mississippi River; in terms of heat content, a little less than one-half lies west of the

Mississippi River. According to the best available data, the Federal Government owns between 50 and 60 percent of the coal reserves

in the six major Federal coal States;* the

percentage varies considerably among coal

regions.

Since 1920, DOI has leased rights to mine

Federal coal to the private sector. During the

past 60 years, over 16 billion tons of coal on

812,000 acres have been leased and remain

in currently existing leases. Less than 20

*The six major Federal coal States are Colorado, Montana,

New Mexico, North Dakota, Utah, and Wyoming.

percent of the total coal reserves owned by

the Federal Government are presently under

lease.

A lease is necessary to mine Federal coal.

The lease grants the lessee exclusive rights to

mine coal subject to stipulations in the lease

established by DOI and subject to Federal

and State laws. Historically, most leases have

been issued in two ways: 1) competitively

through bidding at lease sales, and 2) noncompetitively through an application process

called preference right leasing. **About half

of all existing leases have been issued by ——

**About 6 percent of existing leases have been created in a

third way, segregation or partial assignment, whereby a lease

tract is split into two or more units. A new lease(s) is issued for

the new unit(s) and the acreage of the original lease is correspondingly reduced.
Ch. l—Executive Summary ● 7

each method, but the Federal Coal Leasing

Amendments Act of 1976 abolished the preference right system and required competitive

leasing of all Federal coal. As of January 1,

1980, 176 preference right lease applications

(PRLAs) covering nearly 404,000 acres and

containing 5.8 billion tons of recoverable reserves were in existence, All these applications are scheduled to be processed by DOI by

1984,

DOI began issuing leases under the new

coal management program in January 1981,

after a lo-year moratorium on all but leasing

for special purposes. * Given the 5- to 12-year

leadtime required to develop a coal mine, production from presently unleased land will be

relatively small during most of the 1980’s.

*Those leases issued under the new Federal coal managemen t program are not included in this report.

Federal Coal Resources and Production

The Federal Government owns coal resources in all the major coal regions of the

United States. However, the vast majority of

Federal coal is located in two coal regions in

the Northern Great Plains coal province and

seven regions in the Rocky Mountain coal

province. Federal leases in these two provinces include over 98 percent of the 16.5

billion tons of recoverable coal currently

under lease. Three-quarters of the Federal

coal reserves on leases outside of the Northern Great Plains and Rocky Mountain coal

provinces are contained in 46 leases in

Oklahoma, which is geologically part of the

Interior coal province, The remaining reserves (0.5 percent of the total under lease)

are in 17 leases in the States of Alaska, Alabama, California, Kentucky, Oregon, Pennsylvania, and Washington (see figs. 2 and 3).

Figure 2.—Generalized Coal Provinces of the United States

Dominion of Canada .-. /..

. New I

/ “ .

Legend

Bitumlnous

coal

Subbituminous

coal

.

. Lignite

Mexico

Atlantic Ocean

SOURCE U S Bureau of Mines, adapted from USGS Coal Map of the United States, 1960

84-1410-81-2:0L 3
8 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 3.—Sketch Map Showing Major Coal

Regions With Leased Federal Coal, and

Generalized Location of Strippable and

Metallurgical Coal Deposits

Powder River Region

I

Utah region

Raton Mesa region

SOURCE Base Map National Academy of Sciences, Rehabilitation Potential of

Western Coal Lands, Cambridge, Mass, Ballinger Press, 1974)

Figure 4 summarizes 1980 Federal coal

production and the distribution of leases,

leased acreage, and leased recoverable reserves among the Federal coal States. Figure

5 summarizes 1979 Federal production, FedFigure 4.— Distribution of Production, Reserves.

Acres, and Number of Leases by State ‘

Montana

Utah

New

Mexico

1 1 1 1 I 1 i

o 10 20 30 40 50 60

Percent of totals

69.2

16.5

812,001

565

Totals

million tons (ret) of Federal coal

production in 1980

billion tons (bt) of recoverable coal

reserves under Federal coal lease

acres under Federal coal lease

Federal coal leases

a mt million tons

b

bt billion tons

CO 14 million tons in 1979

SOURCE Off Ice of Technology Assessment

eral mine production, and total production by

State for those seven States. The States of

Wyoming and Montana together contain 61

percent of leased reserves and accounted for

63 percent of Federal production in 1980.
Ch. 1—Executive Summary ● 9

Figure 5.— Distribution of Federal Production, Federal Mine Production and Total State Production in 1979,

by State, for the Seven Federal Coal States Considered in This Reporta

30.1mtb‘ 1 Wyoming

67.5 mt

71.8 mt

8.6 mt

27.4 mt

32.5 mt

7,7 mt

16.0 mt

18.1 mt

6.9 mt

10.4 mt

11.8 mt

5.4 mt

8.4 mt

15.1 mt

1.1 mt

14.1 mt

15.0 ml

0.3 mt

0.3 mt

4.8 mt

““ !.

Montana

Colorado

Utah

I New Mexico

Sums for

the seven

States:

North Dakota Federal production: 60.1 mt

Federal mine production: 144 mt

Total State production: 169 mt

Total Federal coal production

in the U.S. in 1979: 60.2 mtC

Oklahoma Total U.S. coal production

in 1979: 776 mt

I I I I 1 I I

10 20 30 40 50 60 70

Key Millions of tons

Federal production

Federal mine production

Total State production

aSee the footnote on page 8 for definitons of Federal production, Federal mine production, and total production

bmt = milion tons

cThe other States contributed 0.14 mt of Federal production in 1979

SOURCE Office of Technology Assessment

Most of this came from the large surface

mines in the Powder River basin. Colorado

and Utah, which have 59 percent of leases,

contain 33 percent of recoverable reserves

and produced 26 percent of Federal coal in

1980. Mines are smaller on the average in

these two States than in the Powder River

basin and underground mining currently accounts for about 40 percent of production.

New Mexico and North Dakota contain predominantly large surface mines; coal properties in North Dakota have relatively small

amounts of Federal reserves in conjunction

with large amounts of private coal.

Heat content of Colorado and Utah coal is

generally higher than that of the Powder

River basin; leased New Mexico coal is generally of higher heat content than Powder

River basin coal, but lower than Colorado and

Utah coals. Utah, Colorado, New Mexico, and

Oklahoma all contain metallurgical grade

coal under lease, North Dakota coal is all

lignite of low heat content and in general is

suitable only for onsite use.
10 . An Assessment of Development and Production Potential of Federal Coal Leases

The quality of coal reserves presently under lease and PRLA does not appear to impose any serious limitations for meeting the

demand that is likely for Western coal over

the next 10 to 15 years. Most leased reserves

have low-sulfur and ash content and are suitable for use by utilities, which constitute the

single largest user of Western coal.

Because of low heat content, the coal on all

Federal leases in the Fort Union region of

North Dakota and Montana and about 50 million tons of potential annual production capacity from Federal reserves under lease and

PRLA in the Wyoming Powder River basin*

are probably suitable only for onsite development for electric power or synfuel plants.

(The large majority of leased Federal reserves are, however, of sufficiently high quality to be exported out of the producing State.)

Deposits of metallurgical-grade coal are relatively limited in the West, but demand for

Western metallurgical coal is also limited;

the availability of Federal and non-Federal

Western metallurgical coal is probably sufficient to meet the limited demand for this coal

anticipated in the foreseeable future.

Federal coal production has risen steadily

over the past 10 years. Figure 6 shows the

change since 1950 in the number of leases,

the acreage under lease, and Federal coal

production. Whereas the sharp rise in leasing

occurred in the 1960’s, the sharp rise in production from leased land started 10 years

later, in the 1970’s. Figure 7 compares Federal coal production and total coal production

in the six major Federal coal producing

States. Production from leased land started

its sharp rise approximately 5 years later

than overall Western production and has

risen faster in most years since then. During

the next decade, coal production from Federal leases will probably increase at a faster

rate than non-Federal coal production in the

West because of the large increases in Federal production expected in the Powder River

basin.

*Forty-five million tons out of the 50 million tons are unlikely

to be in production by 1991 but could come into production in

the 1990'5.

1950 1960 1970 1980

Year

SOURCE Acreage and number of leases data from Office of Technology

Assessment review of U S Department of Interior case files Federal

coal production from the U S Department of the Interior, Federal

Coal Management Report, F/sea/ Year 1978, March 1979 and from the

ACLDS.

Ownership of Federal Coal Leases

The ownership of Federal coal leases has

undergone marked changes over the last 30

years. Figure 8 shows how the leaseholdings

of 11 groups of lessees and two major leaseholding companies have changed since 1950.

Independent coal companies and unincorporated individuals dominated coal leasing in

the 1950’s and 1960’s, but their relative importance has steadily declined since 1950. In

contrast, the electric utilities, major energy

companies, and natural gas pipeline companies have increased their Federal coal hold-
Ch. 1—Executive Summary ● 11

Figure 7. —Annual Coal Production From the Six

Major Federal Coal-Producing States in the West,

1957-79a

1955 1960 1965 1970 1975 1980

Year

a

The six states are Colorado, Montana, New Mexico, North Dakota, Utah. and

Wyoming

SOURCES Data for 1957-77 from table 27 U S Department of Interior Final Environmental States Federal Coal Management Program

(Washington, D.C.; U.S. Government Printing Office 1979) 1978

data from table A 2, U S Department of Interior Federal Coal

Management Report Fiscal Year 1979 (Washington D C U S

Government Prlntlng Office. 1980), 1979 data from table 16, ch. 3 of

this report

ings significantly since 1965 both in absolute

and relative terms. Steel companies and

metals and mining companies were early

leasing participants, but steel industry influence has declined steadily in relative terms

since 1950, although the acreage held by the

steel industry has steadily increased since

1950. Metals and mining company leaseholdings have varied widely, due in part to the

1977 sale of Peabody Coal Co. by Kennecott

Copper Corp. Independent land companies

played a significant role in leasing in the

1950’s and 1960’s, but they have largely liquidated their holdings over the past decade.

Table 1 shows the acres held under lease

by the principal categories of leaseholders

and the amount of Federal coal they produced in the early and late 1970’s. There is a

fairly close correspondence between the

share of Federal leased acreage and the

share of coal production in 1979. A striking

exception is the case of the metals and mining

companies, which accounted for 16 percent

of Federal coal production in 1979 while

holding only 2 percent of leased acreage.

The ownership data reveal little evidence

of concentration of leaseholdings between

1950 and 1980. The number of leaseholders

approximately doubled in that period, from

84 to over 160 while the number of leases increased sixfold from 88 to 565 and the leased

acreage increased by nearly a factor of 20,

from about 41,000 acres to 812,000 acres,

The four largest leaseholders in 1950 controlled 32 percent of all land under lease

while the largest eight controlled 34 percent

in 1980. Leaseholders in 1980 came from nine

business categories, up from four categories

in 1950. On the average, a leaseholder held

three times as many leases and 10 times the

acreage in 1980 as in 1950.

Three trends in the nature of leaseholders

are noteworthy: 1) There is a growing involvement in the leasing program by horizontally

integrated companies, The energy companies,

natural gas pipeline companies, and the

smaller oil and gas companies together hold

31 percent of leased acreage and produced

29 percent of Federal coal in fiscal year 1979.

2) There is a growing involvement of companies for which coal production represents a

vertical integration of business activities.

Steel companies and electric utilities are the

principal examples of vertical integration

among leaseholders, Together, the two

groups hold 29 percent of coal land under

lease. 3) There is a growing involvement of

large, already diversified companies in coal

leasing, including metals and mining companies and chemical and high technology

companies.

Lease Development Status

A principal objective of this study is to

assess the development potential of existing
12 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 8.— Number of Federal Coal Acres Under Lease by

Business Activity Category, 1950-80

Acres

800,00

700,00

600,00

500,00(

400,00

3oo,oo~

200,00(

100!00(

1950 1955 1960 1965 1970 1975 19 )

Year

SOURCE: Off Ice of Technology Assessment
Ch. 1—Executive Summary ● 13

Table 1 .—Federal Leaseholdings and Production by

Business Category

Fiscal year

1972 1979

coal coal

production production

1970 from 1980 from

Business activity leased Federal leased Federal

category acres leases acres leases

18% 47% 21 % 3 0 %

Electric utilities . . 132,038 4.8 163,259 17.8

18% 5% 20% 1 6 %

Energy companies. . 132,274 0.51 155,024 9.9

Metals and mining 12% 12% 2 % 1 6 %

companies 107,504 1.2 17,620 9.3

Oil and gas com- 4%0 2 % 6 % 9 %

panics (minor) . . . . 26,911 0.23 45,926 5.3

6 % 4 % 10% 9 %

“Other” companies . . 41,153 0.46 77,861 5.2

Independent 11 % 20% 7% 7%

coal companies . . . 78,297 2.0 55,410 4.4

Natural gas pipe- 0% 0% 5% 4%

line companies ., . . 0 0 36,317 2.4

Peabody Coal 8% a0% a

8 % 4 %

Co. . . . . . . . . . . . a a 62,009 2.2

6 % 7 % 8 % 2 %

Steel companies . . . 46,114 0.77 60,015 1.3

Non resource 1% 0% 5 % 2 %

diversified companies 10,015 0 35,675 1.0

Unincorporated 11 % 3 % 6 % 1 %

individuals . . 78,995 0.27 43,215 0.72

Kemmerer Coal 5 % 0 % 4 % below 1%

Cob . . . . . . . . . 33,793 0 32,191 0.06

94% 100% 9 9 % 100%

Total . . . . . . . . . 687,094 10,3 784,522 59.5

NOTE. Percentage sums might not equal totals because of rounding All land

holdings listed as acres. All production Iisted in million tons of coal.

a Peabody 1970 land holdings and 1972 productions totaled In metals and mining category

b

ln March 1981, Kemmerer Coal Co was purchased by Gulf Oil Corp.

SOURCE Office of Technology Assessment

leases, For this analysis, OTA combined the

existing leases into units or blocks, A lease

block, as defined in this report, consists of

one or more leases owned by the same lessee(s) that are contiguous or sufficiently close

together to form a compact minable unit,

Using this approach, OTA divided the 565

existing coal leases into 256 blocks. The

smallest blocks contain one lease covering 40

acres, The largest, located in southern Utah,

includes 21 leases and 47,000 acres.

OTA conducted a comprehensive study of

mining and development activities and production prospects for the 548 Federal leases

in 244 lease blocks located in the seven States

of Colorado, Montana, New Mexico, North

Dakota, Oklahoma, Utah, and Wyoming. To

facilitate this analysis, OTA grouped the

lease units in three categories based on the

status of the mine plan.

Before a coal mine can produce coal from

Federal land, a mine plan must be approved

by DOI. Hence, determining mine plan status

is a useful first step in assessing lease

development potential, Accordingly, the lease

blocks in this report are grouped in the

following three development categories based

on a review of all mine plans on file at the

Office of Surface Mining (OSM) on September 30, 1980:*

. producing or have approved mine plans,

● have mine plans submitted and pending

approval, and

• have no submitted mine plan (“undeveloped”),

Figure 9 summarizes the mine plan status

of leases, leased acreage, and recoverable

reserves by State for the seven principal Federal coal States.

Approximately one-third of all Federal

leases are either producing or have approved

mine plans. This category also includes

leases issued in 1979 and 1980 to permit the

continued operation of existing mines (regardless of whether or not they have formally

been included in approved mine plans) and

leases which have been included in amendments to approved mine plans.

The highest percentage of leases in the approved mine plan category is in Montana: 67

percent of leases covering 69 percent of the

leased reserves in the State. Utah and

Oklahoma have the smallest percentages of

leases and the lowest percentage of leased

reserves in the approved categroy.

Although not every lease falling into the approved mine plan category is producing coal,

all Federal coal production was mined from

leases in this category. In 1979, 60 million

tons of coal were mined from 83 Federal

*Both surface and underground mine plans are on file at the

U.S. Office of Surface Mining.
14 ● An A.s.sessrnent of Development and Production Potential of Federal Coal Leases

. .

. - m
Ch. 1—Executive Summary ● 15

leases, over 40 percent of the leases in the approved category. * In 1979, Federal coal contributed 36 percent of all production from the

seven Federal coal States shown in figure 9.

Federal coal provided 58 percent of Utah’s

coal production, 42 percent of Wyoming’s

coal production, 7 percent of the coal mined

in North Dakota, and 6 percent of the coal

mined in Oklahoma (see fig. 5). The pattern is

similar for 1980 (table 2).

Approximately 20 percent of all leases and

15 percent of leased reserves are included in

mine plans which are pending approval at

OSM. This category does not distinguish

among lease units according to the quality of

submitted mine plans, their date of submission, or the present position of the mine plan

in the regulatory review process.

Utah and New Mexico have the highest

percentage of leases in the pending mine plan

category, 38 and 31 percent, respectively. On

*Because only a portion of the approved permit area is

mined in any given year, it is unlikely that all Federal coal

leases in approved mine plans will be producing at one time.

the other hand, no pending mine plans for

Montana leases have been submitted to DOI

and only one of Oklahoma’s 46 leases is included in a pending mine plan.

Forty-four percent of all leases, 42 percent

of all leased acreage, and 40 percent of

leased reserves have not been developed to

the point of a mine plan submission to OSM.

Preliminary development activity varies

widely on these undeveloped units, from extensive exploration drilling and mine plan

preparation on some units to no activity at all

on others.

Oklahoma has the highest percentage of

leases and leased acres and reserves in

the undeveloped category; five of the seven

Western States have over 30 percent of their

leased Federal reserves in this category.

Thirty-eight percent of New Mexico’s leases

and 40 percent of North Dakota’s leases have

no mine plans but they cover just 22 percent

and 19 percent, respectively, of leased reserves. These are lowest percentages of reserves in the undeveloped lease category

among the seven Western States.

Table 2.—1979 and 1980 Coal Production From the Seven Federal Coal

States Studied in This Reporta (all production in millions of tons per year)

1979 1980

Production

from Total Total

Federal Federal State Federal State

State production minesb

production production production

Colorado . . . . . . . . 7.7 16.0 18.1 9.4 19.5

Montana . . . . . . . . 8.6 27.4 32.5 10.4 36.1

New Mexico. . . . . . 5.4 8.4 15.1 6.3 16.5

North Dakota . . . . 1.1 14.1C15.0 0.6 17.2

Oklahoma . . . . . . . 0.3 0.3 4.8 0.3 4.9

Utah . . . . . . . . . . . . 6.9 10.4 11.8 8.7 13.1

Wyoming . . . . . . . . 30.1 67.5 71.8 33.4 94.0

Totals. . . . . . . . . 60.1 144.1 169.1 69.1 201.4

aTOTAL U S COAL PRODUCTION IN 1979 776 MILLION TONS.

TOTAL U S COAL PRODUCTION IN 1960 820 MILLION TONS.

bCoal from Federal coal leases IS referred to as Federal coal A mine which Includes a Federal lease IS called a Federal mine.

Sometimes, for the sake of efficiency of recovery or economy of operations, intervening State or private coal IS mined with

Federal lease(s) in the same mine This practice iS the rule in Southern Wyoming and North Dakota, for example Thus, many

Federal mines produce both Federal and nonfederal coal A mine which contains no Federal coal IS called a non-Federal

mine Total coal production in a State or region IS thus the sum of 1) Federal coal production from Federal mines plus 2) Non.

Federal coal production from Federal mines p/us 3) Nonfederal coal production from nonfederal mines

cThis figure includes 56 million tons of production from operating mines with Federal leases in pending mine plans Al I of

this 56 million tons iS from non-Federal reserves

SOURCES 1979 Federal productlion from U S Geological Survey accounting office

1979 State production from the U S Energy Information Agency, Weekly Coal Production Report, Aug.

16, 1980

1980 Federal production from U S Geological Survey, Federal and Indian Lands, Coal, Phoshpate, POtash, Sodiurn and Other Mineral Production, Royalty Income and Related Statistics (Washington, D C

U S Government Printing Office, June 1981).

1980 State production from the U S Energy Information Agency, personal communication to OTA,

July 27, 1981
16 ● An Assessment of Development and Production Potential of Federal Coal Leases

Potential Production From Federal Coal Leases

in 1986 and 1991

The development and production estimates

presented in this report are based on information in mine plans, the deliberations of the

OTA State task forces* and communications

with the lessees. Although OTA based its

evaluations of likelihood of development and

levels of potential production on the best data

available for each lease at the time, as additional information based on further exploration and development becomes available, the

prospects for any given lease could change.

These estimates of potential production

from Federal leases are not forecasts of the

coal that will be produced at a given price or

given demand. They are estimates of the total

amount of coal that could be produced from

currently operating Federal mines and from

those Federal leases that have characteristics comparable to operating mines in the

same region. Coal from these leases would

thus be likely to have mining costs competitive with costs at currently operating

mines in the same area. If the overall demand

for Federal coal does not increase to the

production levels that are possible, then not

all of the Federal leases that could technical-

*OTA task forces were held in Colorado, New Mexico. Oklahoma. Utah, and Wyoming. For a complete listing of task force

participants, see p. vii of this report.

ly and economically be developed will go into

production.

Development Prospects of

Undeveloped Federal Coal Leases

Of the 502 leases in the six major Western

coal States of Colorado, Montana, New Mexico, North Dakota, Utah, and Wyoming, 203

are not in mining plans. These leases cover

nearly 265,000 acres, contain 6.4 billion tons

of recoverable reserves, and have the potential to contribute substantial coal production

within the next 10 years. Along with five

leases in three pending mine plans in Wyoming, OTA called these leases “undeveloped”

and has evaluated the likelihood that they

will be developed within the next 10 years

(see table 3), Geological, technical, ownership, environmental, transportation, and

community factors were considered in the

evaluation process,

Of the 208 leases analyzed as undeveloped,

80 leases containing 4.1 billion tons of recoverable reserves have favorable prospects for

development by 1991. The majority of these

reserves are concentrated in the Wyoming

portion of the Powder River basin (3,2 billion

tons of surface-minable reserves) and in the

Table 3.— Development Potential of Undeveloped Leasesa

Amount of Undeveloped leases Undeveloped leases Undeveloped leases

undeveloped with favorable with uncertain with unfavorable

Number of reserves development potential development potential development potential

undeveloped (Billions No. of Amount of No. of Amount of No. of Amount of

State leases of tons) leases reserves leases reserves leases reserves

Wyoming, . . . . . . . 54 4.2 35 3.5 7 0.67 12 0.03

Montana . . . . . . . . 7 0.37 2 <0.1 1 <0.1 4 <0.3

Colorado. . . . . . . . 52 1.06 10 0.08 21 0.82 21 0.16

Utah. . . . . . . . . . . . 76 1.19 30 0.42 28 0.70 18 0.06

New Mexico . . . . . 11 0.10 2 0,09 5 0.001 4 <0.001 b

North Dakota . . . . 8 0.05 1 <0.01 3 0.05 4 0.006

Total . . . . . . . . . 208 6.9 80 4.1 65 2.3 63 0.5

a

lncludes five leases in Wyoming in three pending mine plans.

bOne-half million tons.

SOURCE Office of Technology Assessment
Ch. 1—Executive Summary ● 17

Uinta region of Utah (0.4 billion tons of underground reserves). In almost all cases, the

lessees are actively developing these leases.

Another 65 leases containing 2.3 billion

tons of recoverable reserves have uncertain

prospects for development by 1991. The large

majority of these reserves (about 90 percent)

are about evenly divided among the Kaiparowits Plateau coalfield of southwestern Utah,

the Green River region of Colorado and the

Wyoming portion of the Powder River basin,

Development depends on factors such as

pace and scale of construction of associated

powerplants or synfuels projects, development of in situ gasification, availability of

additional Federal reserves from pending

PRLAs or from new lease sales, construction

of transportation systems, and lessee development priorities.

Considerable uncertainty faces the three

lease blocks (with a total of 0.6 billion tons of

recoverable reserves) in the Powder River

basin whose development is dependent on

in-situ gasification, a technology in the experimental stage which is not likely to be

ready for commercial application before the

1990’s. Considerable uncertainty also faces

the 25 undeveloped leases with 0.7 billion

tons of reserves located on the Kaiparowits

Plateau coalfield of southwestern Utah. The

leases in this large, isolated, rugged area face

uncertainty in potential development over the

next decade because construction of the rail

or slurry transportation systems to connect

the area with potential markets depends on a

minimum production in the area of over 30

million tons per year—a scale that is unlikely

to be reached in the next decade.

Finally, 63 leases with approximately 0.5

billion tons of recoverable reserves are unlikely to be developed. Most of these leases

lack sufficient minable reserves of marketable quality to be developed as new mines.

Many also have difficult mining conditions

that would make them expensive to develop.

Some of the leases are located outside active

mining areas and lack adequate transportation. For example, a seven-lease block in Colorado that meets the minimum requirements

for an average new mine in its region is

located in a remote area without rail service.

It is unlikely that it will be developed in the

next decade, given the availability of other

coal sources with adequate transportation

and which are closer to potential markets.

Production and Capacity Estimates for

1986 and 1991: Developed and

Undeveloped Leases

Production estimates for 1986 and 1991

were made on a lease-by-lease basis and

summed by region and State. The 63 undeveloped leases in the above six States with unfavorable development prospects were assumed to have zero production. A range of

production was usually estimated for the 145

undeveloped leases with favorable or uncertain prospects for development. With a few

exceptions, the lessee’s estimates for production were used for leases in mine plans.

North Dakota, Montana, and Wyoming

In 1979, mines with Federal leases in these

three States produced 109 million tons of

coal, over 90 percent of the total amount of

coal produced in this area. The lessees plan

to increase production from currently operating Federal mines substantially, to 280

million tons in 1991. Currently undeveloped

leases could add another 20 to 80 million tons

per year of production in 1991, for a total production from Federal mines in that year of

300 million to 360 million tons.

In the Powder River basin of Wyoming and

Montana, Federal mines accounted for 88

percent of total coal mine capacity in 1980.

This percentage is projected to remain relatively constant throughout the decade, However, production from Federal leases themselves is projected to increase from less than

40 percent of total coal production in the

basin in 1979 to approximately 80 percent in

1991. In southern Wyoming, essentially all

coal production is from Federal mines, with

about one-third of the production from the

Federal reserves. This pattern is expected to

continue, with the contribution from Federal
18 . An Assessment of Development and Production Potential of Federal Coal Leases

reserves rising to perhaps 40 percent by

1991. In 1979, Federal mines in the North

Dakota portion of the Fort Union region accounted for over 90 percent of the State’s

coal production; the amount produced from

Federal reserves was less than 7 percent.

This situation is expected to continue, with

however, production from Federal reserves

rising to perhaps 20 percent in 1991.

Figure 10 summarizes potential production

and planned mine capacity for Federal mines

over the next decade for the Fort Union region of North Dakota and Montana, for the

Powder River basin of Montana and Wyoming, and for southern Wyoming. The upper

capacity lines (lines D) in this figure represent OTA’s estimate of the maximum coal

production from Federal mines that could be

achieved in these three regions under strong

market conditions. Several features of figure

10 should be noted:

1.

2.

3.

The Powder River basin will continue to

increase in importance as a coal-producing region. By 1991, Federal mine production in the Powder River basin could

account for about 80 percent of Federal

mine production in these three States.

All estimated Federal mine production

for 1991 for the Powder River basin

comes from currently approved mines

and from undeveloped leases with favorable development potential. (Undeveloped leases with uncertain development

potential contribute no production

through 1991. ) The large range in estimated production from undeveloped

leases arises from demand uncertainty.

However, several undeveloped leases in

the Powder River basin have contracts

for delivery of coal before 1990.

By 1991, the capacity of Federal mines

in the Powder River basin could be as

high as 310 million tons per year. According to the lessee’s plans, the overcapacity in presently operating Federal

mines in the Powder River basin, which

was greater than 75 million tons per

year in 1979 will diminish to nearly zero

by 199l.

4.

5.

The maintenance of total capacity of

Federal mines in southern Wyoming depends on the development of new mines.

Although capacity of presently operating mines is projected to decrease over

the next 10 years, their production will

probably not decline. Most of the range

in production arises from uncertainty in

the pace of a synfuels project.

The potential increase in production and

capacity of Federal mines in the Fort

Union region will occur largely from

mines in North Dakota with leases in

currently pending mine plans. Undeveloped leases are not likely to contribute

more than 1 million tons per year by

1991. Federal mine production in the

Montana portion of the region is likely to

remain constant at 0.3 million ton per

year.

Colorado, New Mexico, and Utah

In 1979, mines with Federal leases in these

three States produced a total of 35 million

tons of coal, about 77 percent of the total

amount of coal produced in this area. Many

of the Federal mines in the area are relatively

new and have not yet reached full production

levels; consequently, the lessees plan to increase production from currently operating

mines substantially, to 65 million tons per

year by 1991. Over the next decade, several

operating mines are expected to be at, or

near, depletion of their current mine plan

reserves. Part of this reduction in capacity

will be offset by replacement capacity from

new mines on Federal leases. About 5 million

to 10 million tons are potentially involved.

If all currently operating and proposed

mines that include Federal leases are developed and produced as planned, production

from these mines could reach 75 million tons

by 1986, and between 110 million and 146

million tons by 1991. The production increase

would be greatest in Utah, where production

from Federal mines might rise from about 10

million tons in 1979 to as much as 74 million

tons by 1991.
Ch. 1—Executive Summary ● 19

Figure I0.— Planned Capacity and Potential Production of All Mines With Federal Leases in the

Powder River Basin, Southern Wyoming, and Fort Union Region

Millions of tons

per year

. “

40

30

20

10

1979 1986 1991

Year

Millions of tons

per year

300

250

200

150

100

50

I

Powder River Basin

I I I I I

1979 1980 1986 1991

Year

A: Lessee’s planned annual production from Federal mines in currently approved mine plans only

B: Lessee’s planned annual capacity for Federal mines in currently approved mine plans only

C: The sum of A, above, plus estimates of potential production from Federal mines in pending mine plans and from presently

undeveloped Federal leases

D: Planned annual capacity for all Federal mines, including Federal mines in pending mine plans and presently undeveloped Federal

leases

SOURCE Office of Technology Assessment

Over the next decade, the percentage of Federal production from existing leases in

total State production coming from existing New Mexico is expected to remain relatively

Federal coal leases is expected to increase in stable, although, output from PRLAs could inUtah and Colorado as new, large Federal crease the total share of annual State producmines reach full operation, The percentage of tion from Federal reserves.
20 . An Assessment 0f Development and Production Potential of Federal Coal Leases

Figure 11 summarizes potential production

for Federal mines over the next decade for

the States of Colorado, New Mexico, and

Utah. Several features of figure 11 should be

noted.

1. Most of the projected increases in production will come from new mines on

Figure 1 1.— Potential Production Capacity of

All Mines With Federal Leases in Colorado,

New Mexico, and Utah

Millions of tons

per year Colorado

40

30

20

10

1979 1986 1991

Millions of tons

per year New Mexico

1979 1966 1991

Millions of tons

per year Utah

A: Lessees’ planned annual production capacity for Federal mines

in currently approved mine plans only.

B: The sum of A, above, plus estimates of production capacity for

Federal mines in pending mine plans and for presently

undeveloped Federal leases.

SOURCE. Office of Technology Assessment

2.

3.

4.

leases in pending mine plans and on currently undeveloped leases that will not

achieve full design capacity until after

1991. The projected 1991 production

range of 110 million to 146 million tons is

less than the total capacity of about zoo

million tons per year that could be supported by mines on existing Federal

leases in these States by the mid-1990’s.

In the late 1990’s, however, the capacity

supported by existing leases will begin to

decline as many of the mines that are

now operating exhaust their reserves.

For Colorado, the increased production

comes from new mines with pending

mine plans and from undeveloped

leases. The new mines could add from 25

million to 30 million tons of new annual

capacity split almost evenly between

surface and underground operations.

About 1.9 million tons of projected 1991

production is tied to synthetic fuel projects but could be sold to other customers

if the proposed projects were delayed.

The major uncertainty facing increased

production in Colorado is whether expanded markets will materialize as expected.

The range of potential production from

new mines in New Mexico in 1991 reflects the uncertainties in the rate of

mine development because of possible

delays in the construction of the Star

Lake Railroad and in the availability of

reserves in pending PRLAs associated

with two new mines. Production levels

and mine capacity for the Black Lake

Mine will also be influenced by the requirements of a proposed coal gasification project. Two other new mines are

unaffected by PRLA availability or railroad construction, but are tied to the

coal needs of new powerplants.

The range of 27 million tons per year in

1991 production in Utah arises from uncertainties in development in the Alton

and Kaiparowits coalfields of southwestern Utah. Coal development in

southwestern Utah depends on expansion of potential markets only the Alton
Ch. 1—Executive Summary ● 21

mine currently has a purchaser for its

coal) and, more importantly, on the construction of a rail or slurry transportation system to serve potential consumers, A minimum of 30 million tons

annual production is required to offset

the costs of constructing a rail line onto

the Kaiparowits Plateau,

Oklahoma

In 1979, approximately 0.3 million tons of

Federal coal was produced in Oklahoma.

Four mines with Federal leases are currently

producing coal in this State; however, the

Federal reserves on three of these mines are

expected to be depleted before 1986. No undeveloped leases in Oklahoma are expected

to produce coal in commercial quantities

before 1991, Three main reasons account

for the unfavorable production prospects of

these leases: 1) difficult and costly underground mining conditions, 2) a depressed

metallurgical coal market, and 3) a high Federal royalty relative to royalties charged for

fee coal in the State.

Diligent Development

Federal coal leases issued before August 4,

1976 (527 out of the 565 leases in this study)*

are required to produce 21⁄2 percent of logical

mining unit** (LMU) recoverable reserves by

June 1, 1986, or be subject to cancellation

proceedings. Under certain specific circumstances, the Secretary of the Interior may

grant an extension to mid-1991, (See ch. 9 for

more detail. )

Most leases with potential for production

by 1991 could qualify for extensions under

existing guidelines. The exceptions are mines

that do not fit clearly into any of the current

guidelines, specifically several proposed

small- to medium-sized mines that are in-

* Thc 38 leases issued after August 4, 1976. are subject to a

Slightly different requirement. N( )ne of these leases are :~n -

ti{’ip;i ted to have cfifficul IV in meeting that requirement t.

**The Bureau of Land hlanagemenl has defined everv lease

as an LNIU. ‘[’ills definition may be. but is not ne(x?ssarll},

superseded when :~ mine plan is nppr[wed. In [) mine plan. :) n

LN![J mav consist of more thi)n one Fmicrnl lease t~ncf m:]~ include non-Federal coal 1.

tended to serve spot markets and several underground mines with difficult mining conditions requiring longer construction periods.

OTA has examined estimated production

schedules to assess the likelihood that a lease

block will achieve diligence by 1986 or 1991.

By 1991, over 70 percent of the 502 leases

in the six major Western Federal coal States

might meet the existing diligence requirements.

•

●

●

216 leases with 7.4 billion tons of reserves are likely to meet diligence by

1986 (45 percent of total leased reserves).

29 additional leases with 2.1 billion tons

of reserves are likely to meet diligence

by 1991 with extensions (13 percent of

total leased reserves).

112 leases with 3.4 billion tons of reserves (20 percent of total leased reserves) are uncertain to meet diligence

by 1991. Major uncertainties are tied to

delays in powerplant, synfuels and

transportation system construction, fluctuations in captive coal needs, development of markets for the coal, and difficulties in defining the logical mining unit

for leases with very large reserves in

multiple seams. Development of markets

for the coal constitutes a particularly important uncertainty in the Powder River

basin where market demand will be an

important factor in determining whether

1.2 billion tons of recoverable reserves

under lease will meet diligence by 1991.

Thirty percent of the leases in the six major

Western Federal coal States containing 20

percent of total leased reserves are unlikely

to meet diligence by 1991 even were they to

be granted extensions:

● Production for 61 leases in the Kaiparowits Plateau with 1.4 billion tons of

reserves is dependent on construction of

a coal transportation system that is unlikely to be in place by 1991. Moreover,

even if the Kaiparowits Plateau leases

begin producing at the earliest feasible

date, 1987, it is unlikely that they would
22 ● An Assessment of Development and Production Potential of Federal Coal Leases

●

●

produce enough to meet diligence requirements because of the large amount

of underground reserves involved.

Development of 10 leases in the Powder

River basin with 1.4 billion tons of reserves depend on onsite synfuels development; 0.6 billion tons of these are suitable only for in situ gasification, assuming that technology is developed.

The remaining 74 leases are primarily

small, scattered leases with poor quality

reserves that are unlikely to be developed.

Figure 12.— Dilligent Development Summary for the

Powder River Basin

The Powder River Basin Montana portion of the

73 Leases Powder River Basin

38 Lease blocks ! 15 Leases

9.2 Billion tons of recoverable I 8 Leaseblocks

reserves under Federal lease I 0.9 Billion tons

I /

I /

Wyoming portion of

Powder River Basin

58 Leases

30 Leaseblocks

8.3 Billion tons

the

Percent

Key Reservesa

of reserves

_ Likely to achieve diligence by 1986: 4.8 52%

_ Likely to achieve diligence by 1991: 1.7 18%

– Uncertain whether will achieve

diligence by 1991: 1.2 13%

– Unlikely to achieve diligence by 1991: 1.5 16%

aBillions of tons.

SOURCE: Office of Technology Assessment.

The

Figures 12 and 13 graphically summarize

the results of OTA’s diligent development analysis for the Southern Rocky Mountain region (Colorado, Utah, and New Mexico) and

for the Powder River basin.

Figure 13.— Diligent Development Summary for the

Southern Rocky Mountain Region

(Colorado, New Mexico, and Utah)

Number Percent Percent

of of of

Key leases leases Reservesa

reserves

■ Likely to meet

diligence by 1986 136 28 2.0 34

■ Likely to meet

diligence by 1991 15 4 0.3 5

a Billions of tons.

SOURCE Office of Technology Assessment

Powder River Basin

The Powder River basin is particularly important to Federal coal development because

it contains over one-half the recoverable reserves under lease, accounts for about onehalf the coal produced from Federal mines,

contains the largest pool of Undeveloped

leased Federal coal reserves in the United

States, and has the largest market area of

any Western coal-producing region. Federal

mines accounted for 88 percent of mine capacity in the Powder River basin in 1980. This

Percentage is projected to remain relatively — ,
Ch 1—Executive Summary ● 23

constant throughout the decade. However,

production from the leases themselves is projected to increase from less than 40 percent

of total coal production in the basin in 1979 to

approximately 80 percent in 1991. *

A number of projections for this region suggest that the most likely range of demand for

Powder River basin coal in 1990 will be 200

million to 225 million tons per year (see fig.

14), The Department of Energy (DOE) interim

midrange production goal of 275 million tons

per year is probably high.**

Contracts already exist for delivery of 186

million tons per year of Powder River basin

coal in 1990. Of this amount of contracted

coal production, 159 million tons is from currently producing mines with Federal leases,

10 million tons is from non-Federal mines,

and 17 million tons is from presently undeveloped Federal leases,

For 1990, lessees and non-Federal mine operators have plans to produce a total of

nearly 100 million tons per year more than

the presently contracted level for that year.

Production plans for 1990 total 280 million

tons per year; of this amount, 215 million tons

is from currently producing mines with Federal leases, 10 million tons is from non-Federal mines, and 55 million tons is from presently undeveloped leases which have favorable production prospects for 1990 under

strong market conditions. Only 6 million tons

of this production is contingent on synfuels

development.

Mine design capacity planned by lessees

and non-Federal mine operators for 1990 is

considerably higher: 348 million tons per

year. Mine design capacity is an upper limit

to long-term production levels that can be

reached with a leadtime of a year or so. Currently operating Federal mines are scheduled

to reach 97 percent of mine design capacity

*’I’hc pcrmntt~gc of F’cdcrt]l UI;II pr(du(lion will lx: ICSS Ih;ln

th(! perrentagc of F’ecferal mine r:]p:]ritf. t)wause l-’e(ier:~l

m i ncs (;om m( )n I \ pr( I(IU (c som (3 III JII- F’e(lc r:] I (I( );) I. S0(; fool” n( ) t (:

011 [1 :1 (111(1 tclt)ll’ 50

* “’1’tl(’ (1(’nl:ll)[l ~)rol(’( I 10[1> (11’(’ (1 is{ (i\>(’(l Ill (l[’t(Ill 011 l)])

169-173 and I ig. 34. S[w also [jp 100-102 for a (1 is(llssion of the

I) OF: find [)ro(iu(:tion goal+

by 1991. Therefore, given sufficient market

demand, production levels of close to 350

million tons per year are attainable in the

early 1990's from currently operating mines

plus good quality properties currently being

actively developed.

These levels of capacity and production depend on all plans being realized for both

Federal and non-Federal properties, If only

11 out of the 17 undeveloped properties contributing to this projection are developed,

total design capacity could be reduced by up

to 60 million tons per year; total design capacity would then be 290 million tons per year.

Nevertheless, planned capacity in the Powder River basin seems likely to be adequate to

meet demand into the early 1990's.

Potential capacity in the post-1990 period

is considerably more difficult to estimate, as

is potential demand. An additional 155 million tons per year of capacity could perhaps

become available in the post-1990 period

from undeveloped Federal leases, PRLAs and

new non-Federal mines. About 70 million tons

per year of this capacity would be suitable

only for onsite development because of low

coal quality, This amount ( 155 million tons

per year) should be considered an upper limit

rather than a likely value of additional

post-l990 capacity without additional leasing

of Federal coal. For the post-1990 period, demand projections become very uncertain, The

DOE preliminary midlevel production goals,

the ICF CEUM* midlevel production forecast

and the DOE midlevel final production goals

for 1995 for the Powder River basin are 382,

306, and 491 million tons per year, respectively. The DOE final production goal. 491

million tons per year. reflects several policies

about increased coal use (e. g., coal for synfuels), that cause the number to be higher

than other forecasts. Although all demand

projections past 1990 should be regarded as

very uncertain, the lower numbers above are,

as of now, more likely to be realized.

The potential for continued high overcapacity in the Powder River basin has caused

* See footnote on fig. 14 for citation.
24 . An Assessment of Development and Production Potential of Federal Coal Leases

Figure 14.—Comparisons of Powder River Basin Demand Projections With

Planned Capacity and Production Levels for 1990

(Prelim.)

High

(Final)

\

Base

P

Prelim.)

~

(Final)

- L o w

(Prelim.)

CEUM

High

Demand projections and goals

1990

a Calculated by adding Sebesta’s figure for the Montana portion of the Powder River Basin (68 mmt) to Glass' figure for the Wyoming portion (133 mmt).

References

ICF: CEUM: Coal Electric Utility Model Forecasts and Sensitivity Analyses of Glass: Wyoming Coal Production and Summary of Coal Contracts (Laramie

Western Coal Production, Prepared for Rocky Mountain Energy Company, (ICF Incorporated; Washington, D. C.: November 1980), DOE:

Sebesta: Demand for Wyoming Coal 1980-1991 Based Upon Protected Utility

Coal Market and Demand for Montana Coal 1980-1991 Based Upon

Prptected Utility Market (Washington, D. C.; Office of Technology

Assessment: October 1980).

Wyoming Task Force; Result of deliberations of the Off Ice of Technology

Assessment Wyoming Task Force; Cheyenne, DOE:

Wyoming. October 1980.

Silverman: Preliminary results from A. Silverman, University of Montana,

Missoula. Private Communication to Office of Technology

Assessment.

Wyoming: Wyoming Geological Survey, 1980).

Preliminary National and Regional Coal Production Goals for 1985,

1990, and 1995. (Washington, D C.. DOE, August 7, 1980). See also:

Analysis and Critique of the Department of Energy’s August 7, 1980

Report Entitied: “Preliminary National and Regional Coal Production

Goals for 1985, 1990, and 1995, prepared for the Rocky Mountain

Energy Company, (ICF Incorporated; Washington, DC.: October 1980)

The 1980 Biennial Update of National and Regional Coal Production

Goals for 1985, 1990 and 1995. U.S. Department of Energy (Washington

D.C., January 1981).
Ch. 1—Executive Summary ● 25

questions to be raised about the timing, extent and location of renewed large-scale leasing under the Federal Coal Management Program. The debate focuses on the role of competition and the free market in resource supply, the potential costs to the social and

physical environments of the coal producing

areas of “overleasing,” the length of time

needed to bring a new lease into full-scale

production, the margin of supply safety

needed for prudent planning on a national

and corporate level, questions of equity

raised by restricted opportunities for new entrants to Federal leaseholding, a fair return

to the public for use of its resources, and the

levels of likely demand in the early to mid1990’s,

Many proponents of large-scale new leasing in the Powder River basin in the near

future cite the long moratorium on such leasing and its effect of restricting entry possibilities to leaseholding as one reason for

prompt resumption. They also contend that

postponing leasing will unduly interfere with

Factors Affecting Federal

Federal Coal

There are a number of market, environmental, legal and regulatory, transportation,

and socioeconomic factors that

Federal lease development and

tion.

Market Factors

could affect

coal producMost energy forecasts predict that the major Federal coal States in the West will attract larger shares of the total coal market

over the next 10 years. Several studies project that Western coal, which supplied 28

percent of the 1979 U.S. demand, will supply

as much as 49 percent of the market by

1990. *

the workings of the free market and will restrict competition. They anticipate high demand for coal by 1995 and fear that the present leased reserve base in the Powder River

basin will not provide enough certainty or

flexibility to meet that demand efficiently.

Opponents of large-scale new leasing in the

Powder River basin as scheduled in 1982 cite

the potential for overcapacity through the

early 1990's as proof that such leasing is not

necessary at this time. They contend that

leasing can be safely deferred until its necessity is clearly indicated by realistic demand

forecasts. They hold that large-scale leasing

substantially beyond that necessary to meet

likely demand in 1990 will place an unnecessary strain on orderly planning in the communities of the region, shift demand to the

Powder River basin that could have been met

by Midwestern supply, depress the value of

leases so that the public will not receive a fair

return for its resources, and, moreover, be

unlikely to increase competition significantly.

Lease Development and

Production

Many factors will influence the demand for

Western coal and the competition between

Western coal States for markets, but three

are particularly significant: demand by domestic electric utilities, growth of new nonutility markets, and transportation availability y and cost.

The principal markets for Western coal

are utilities in the Western coal-producing

States, the Midwest, and the Southcentral

States. The electrical growth rates in these

regions will probably be the single most important factor affecting demand for Western

coal. Also, growth rates and fuel preferences

of utilities for new plants in regions such as

California, which currently do not burn coal,

and the extent of conversion of existing oil- or

gas-fired powerplants to coal will shape

Western coal demand. The present new
26 ● An Assessment of Development and Production Potential of Federal Coal Leases

source performance sulfur dioxide (S02)

emission standards, which require sulfur

reduction of all coals (thus, reducing the cost

advantage to utilities of burning low-sulfur

coal), and the decline in electrical growth

rates in recent years suggest that the growth

in Western coal demand might not be as high

as some earlier forecasts had predicted.

New nonutility markets could increase the

demand for Western coal, These include foreign coal users, particularly Japan, and the

incipient domestic synfuels industry, although neither is likely to substantially affect

Western coal demand before 1990. Moderate

increases in industrial coal use could increase demand for Western coal somewhat.

Access to reliable, efficient, and low-cost

transportation is critical to the success of

Western coal producers in selling to out-ofState coal markets. In all Western coal

regions, coal transportation costs are increasing, Because these costs can account for

over 70 percent of the delivered price of coal

in out-of-State markets, the competititive

position of Western coal in these markets is

not likely to be as favorable in the next 10

years as it was in the previous 10 years.

Environmental Factors

Because almost all Federal coal reserves

are located in the Western United States, the

environmental and reclamation concerns

about Federal coal development are largely

those characteristic of Western coal mining.

The dominant issues include concern about

fugitive dust and its impact on the good to

very good air quality of the West, the effect of

mining on the sparse water resources of the

region, the ability to revegetate mined areas

with semiarid and arid climates, the effect of

various spoil handling and recontouring requirements on the ability to mine coal, the effect of mining and associated population

growth on the region’s wildlife populations,

and the effect of mining on the region’s archeologic resources.

Several important laws and regulations

have been adopted to deal with these concerns, The effect of these regulations on

Federal coal production has been to remove

small amounts of minable coal from the recoverable reserve base, to delay development

of other recoverable reserves, to increase the

complexity of the mine permit process, and to

increase the overall cost of mining, The percentage of recoverable Federal reserves currently under lease that may be prohibited, or

subject to delay from mining over the next 10

years because of environmental regulations

is between 5 percent and 10 percent of the

total currently leased reserves.

Less than 1 percent of currently leased

Federal reserves appear likely to be subject

to complete prohibition from mining. The remainder of currently leased Federal reserves

that may be affected may be subject to delays

in mining because of unresolved environmental questions, but the available evidence indicates that most of these reserves will be

mined. There are additional leased reserves

(mainly in the Kaiparowits Plateau in southern Utah) over which there are potential environmental conflicts, but impediments to development of these reserves are primarily

related to nonenvironmental factors such as

transportation availability. These estimates

of Federal leased reserves adversely affected

by environmental requirements are considerably lower than earlier estimates by DOI

which indicated that as much as 10 percent

of leased reserves might not be developed because of environmental considerations.

The Surface Mining Control and Reclamation Act of 1977 (SMCRA) addresses most of

the concerns about the environmental effects

of Western coal mining. The act establishes

performance standards for mining and reclamation and criteria that must be met before

mining permits can be approved. The act is

administered in the West largely by the

States, with oversight responsibility remaining with OSM. Various other statutes, such as

the Clean Water Act, the Clean Air Act, and

legislation to protect wildlife also affect coal

mining operations. Also, the Federal Land

Management Policy Act included environ-
Ch. 1—Executive Summary ● 27

mental provisions in the Federal coal leasing

program,

The coal mining industry has severly criticized the regulatory programs generated by

these statutes. Criticism has centered on

overlapping and inconsistent regulations,

problems with enforcement, excessive paperwork requirements, and increases in the

costs of mining and in the time needed to

develop mines,

This report does not evaluate the issues of

cost or the lengthened development process

caused by regulations nor does it evaluate the

extent to which recoverable Federal reserves

will be affected by environmental concerns

under the renewed Federal coal leasing program. However, this report does examine the

amount of currently leased Federal coal that

has been or that may be prohibited from development or subjected to extra delay from

recovery. Table 4 summarizes the results of

this analysis.

Air-quality concerns. North Dakota coal is

lignite, which is uneconomical to transport

over any distance and which must therefore

Table 4.—Summary of Impacts to Federal Recoverable Reserves From

Environmental and Reclamation Considerations

Federal

reserves

affected’

Location of (millions

Issue area Specific issue affected area of tons) Effect 2

Air resources Expansion of mine production rate in a Rosebud Mine, 1.5 ret/y

non-attainment area Colstrip, Montana after 1985

or about

30 mt of

reserve

U

3

, effect would be

to limit production

rate, not prohibit

any mining areas

Permitting of additional power plants West Central <1oo

near class 1 area where SO2 levels for ex- North Dakota

isting and permitted but not constructed

facilities are currently predicted to be at

maximum PSD level. The additional

power plants would be fueled by lignite

mines in the vicinity.

Lands unsuitable Impacts of coal mining will damage Alton Coalfield, 24

for mining important aesthetic values of Bryce Southern Utah

Canyon National Park

Water resources Subsidence of mine will divert surface

and ground water and adversely affect

other uses

Mt. Gunnison Mine

West Central Colorado

Alluvial Valley floor (AVF) in areas

significant to farming

Developed mines with stream valleys

under study as potential AVF where

mine plan development has been

delayed

Designated AVF in developed mines.

Valleys not significant to farming. Mine

plan development affected

CX Ranch leases Montana portion of the

Powder River basin

Powder River basin,

Buckskin, and Spring

Creek mines

Powder River basin,

Eagle Butte, Rawhide,

Coal Creek mines

U

4

, improved air

quality modelling

techniques being

developed

A p

5

-on portion of

proposed mine area

designated as

unsuitable; rest

of leasehold

unaffected.

23 U, approval likely if

mine will buy or

replace senior

water rights

affected. 6

<100 Ap uncertain7

95 D, mining of valleys

expected 8

61 U, mining of valley

expected 9
28 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 4.—Summary of Impacts to Federal Recoverable Reserves From Environmental and

Reclamation Considerations—Continued

Federal

reserves

affected 1

Location of (millions

Issue area Specific issue affected area of tons) Effect2

—

Potential alluvial valley floors which ex- Powder River basin, 240 U, mining of valleys

isted in developed mines prior to Big Sky, East Decker, expected*

passage of SMCRA. Reclamation plans Eagle Butte, Wyodak,

must still be approved Belle Ayr, Jacobs

Ranch, and Black

Thunder mines

Potential AVFS in undeveloped coal Powder River basin 219 U, mining of most

lease areas valleys expected8

Spoil handling Limitation on out-of-pit spoil area Black Butte Mine 5 Ap1O

and protection Green River-Hams Fork

of raptor habitat region

Limitation on out-of-pit spoil area Green River-Hams Fork 50 Possible problem;

region resolution

uncertain 6,9

Mining in environmentally sensitive Glen Harold Mine West 29 D

11

woody draws Central North Dakota

1

Total Federal reserves under lease are 16,500 million tons.

2Ap-absolute prohibition; D-delay in approval, U-unresolved.

3

Jurisdiction lies with the Montana Department of Health and Environmental Sciences

4

Jurisdiction lies with the North Dakota State Department of Health.

5Decision made by the Department of the Interior, 1980. Decision under appeal to Federal courts

6

Jurlsdtction Iies with Colorado Department of Natural Resources and U.S. Office of Surface Mining

7Under Section 510(b)(5) of SMCRA. Jurisdiction lies with the Montana Department of State Lands The department has ruled that the alluvial valley floor IS significant

to farming. The lessee has asked the department to reconsider its decision.

8

Jurisdiction lies with Montana Department of State Lands (Spring Creek) and Wyoming Department of Environmental Quality (Buckskin)

9

Jurisdiction lies with Wyoming Department of Environmental Quality

10Lead decision made by OSM

11Permit application denied by North Dakota Public Service Commission on grounds that plans for reclamation of wooded draws were inadequate

be sold to onsite or nearby powerplants or

synfuels facilities. Permitting of additional

coal conversion facilities in west-central

North Dakota is currently being delayed,

pending further information on the effect of

existing and permitted plants on the air quality of nearby Theodore Roosevelt National

Park.

Additional Federal coal development could

be affected by possible fugitive dust problems. At Colstrip, Mont., where fugitive dust

levels presently exceed ambient air standards, future mine expansion will have to address and minimize air impacts.

Lands unsuitable for mining. In Utah, 24

million tons of Federal coal have been removed from mining because of adverse impacts on nearby Bryce Canyon National Park.

The remainder of the leased surface minable

reserves in the area, about 270 million tons,

are unaffected by the decision. The decision

has been challenged in Federal court.

Water resource concerns could affect over

700 million tons of Federal recoverable reserves. However, less than 100 million tons

may be prohibited from mining. These reserves are located beneath an alluvial valley

floor significant to farming and thus can be

absolutely prohibited from mining under

SMCRA. * Alluvial valley floor concerns may

affect another 600 million tons; however mining of these reserves is likely, with especially

stringent reclamation standards applied. Development of over 20 million tons may hinge

on purchase or replacement of senior water

rights that could be affected by mine subsidence.

*The Montana Department of State Lands has ruled that the

alluvial valley floor in question is significant to farming. The

lessee has asked the Department to reconsider its decision.
Ch. 1—Executive Summary ● 29

Spoil handling and protection of raptor

habitat* have removed 5 million tons of Federal recoverable reserves from mining in

southern Wyoming. Spoil handling concerns

could affect perhaps as much as another 50

million tons in southern Wyoming and northern Colorado. Development of 29 million tons

has been delayed in west-central North

Dakota because of concerns about reclamation of wooded draws.

In summary, approximately 1 billion tons of

leased Federal recoverable reserves out of

16.5 billion tons of leased Federal recoverable reserves have been or could possibly be

affected in the following ways by environmental laws and regulations:

29 million tons have been absolutely prohibited from mining;

up to another 100 million tons may be absolutely prohibited from mining;

124 million tons have been delayed in the

approval process;

573 million tons could be affected or delayed but approval is likely; and

up to another 150 million tons could be

affected or delayed and approval is

uncertain.

Several reclamation issues where further

data are needed or where regulatory decisions have yet to develop a clear pattern,

such as the long-term success of revegetation,

the hydrologic effects of mining, and the ability to achieve approximate original contour,

have not yet resulted in any prohibitions to

mining but could become important issues in

the future. The long-term success of reclamation in the West is still unproven, but regulatory authorities have approved continued

mine expansion based on the short-term success achieved to date.

Laws and Regulations on Management

of Existing Federal Leases

The development of existing Federal coal

leases may be affected to varying degrees by

the resolution of the following legal issues:

*Especially eagle habitat.

●

●

●

●

application and enforcement of diligent

development requirements;

exchange of lease and PRLA reserves

for unleased Federal coal;

processing of pending PRLAs; and

designation of areas unsuitable for surface mining under SMCRA.

Diligent Development

Under current regulations, leases issued

before passage of the Federal Coal Leasing

Amendments Act of 1976 (FCLAA) (preFCLAA leases) that do not produce 2 l/z percent of the lease’s logical mining unit reserves by June 1, 1986, can be canceled, Extensions to this diligence deadline may be

granted by the Secretary of the Interior

under certain circumstances; however, lack

of markets is not solely a basis for extensions.

Leases issued after August 4, 1976 (postFCLAA leases) will be terminated automatically if they do not produce coal in commercial quantities within 10 years after the

lease is issued. Section 3 of FCLAA (30 U.S.C.

201(a)(2)(A)) also provides that, with a few exceptions, after August 4, 1986, no new leases

can be issued to any lessee who is still holding

a coal lease from which he has not produced

coal for 10 or more years.

The current regulations defining diligence as actual production of coal were

first promulgated in May 1976 in response

to concerns over the large amounts of Federal coal that had been leased in the 1960’s

during a period of declining Federal coal

production.

Since May 1976, the diligence regulations have been modified slightly to include provisions required by FCLAA and

minor editorial clarifications, but th e

production requirements for pre-FCLAA

leases have remained virtually un -

changed. *

According to OTA’s analysis, under existing regulations, many pre-FCLAA leases

*In 1977, the Department of Energy organization” Act transferred the Secretary of the Interior’s authority to establish diligence requirements and minimum production rates for Federal leases to the Secretary of Energy.
30 ● An Assessment of Development and Product/on Potent/al of Federal Coal Leases

will meet diligence by the 1986 deadline or,

with extensions, by 1991; a number of

others will not and prospects for some remain uncertain. (See Diligent Development

section on p. 21, ) Since the current diligence

standard could change within the broad limits set by statute as a result of policy redirection or court decisions, it is difficult to predict the precise impact of diligence requirements on pre-FCLAA leases.

DOI’s diligence standard requiring production of coal on existing leases within 10 years

was opposed by mining industry trade groups

and many lessees. Legal challenges by lessees

to the reasonableness of the regulations and

their applicability to pre-FCLAA leases are

likely.

The impact of diligence requirements on

pre-FCLAA leases will depend on the interact ion of many factors besides the legal precedents that may be established on the applicability of the regulations. These factors include: 1) the extent of voluntary compliance

by lessees; 2) how many extensions to the

1986 deadline are granted; 3) how many existing leases are combined with other leases

or non-Federal coal reserves to meet diligence by forming an approved LMU; 4) how

LMU reserves are defined for each lease: 5)

the extent to which leases are readjusted on

schedule; 6) the extent of effective enforcement of the 1976 regulations by DOI and the

Department of Justice; and 7) how many nonproducing leases are relinquished,

Exchanges

Because of requirements in FCLAA that all

new leases must be offered by competitive

bid, the possibilities for trading new Federal

leases for Federal leases where mining poses

problems is limited to exchanges specifically

authorized by Congress and to leases in alluvial valley floors where mining is prohibited

by SMCRA. The congressionally authorized

exchanges would offer unleased Federal coal

for relinquishment of certain existing leases

in Wyoming and New Mexico and PRLAs in

Utah, and for contested leases on Indian

lands in Montana, Exchanges of non-Federal

coal lands in alluvial valley floors that cannot

be mined for available Federal coal reserves

is also authorized under SMCRA. Generally,

to be approved by DOI, the tracts exchanged

must be approximately equal in value and the

exchange must serve the public interest. Exchanges can thus offset possible losses in coal

production from areas that cannot be mined.

Preference Right Lease Applications

Processing of the 176 PRLAs over the next

3 years will confront several legal, administrative, and procedural issues before the potential for coal production from pending applications will be known. Among the questions to be resolved are: 1) how many PRLAs

will be affected by conflicting mining claims,

2) how many rejected prospecting permits

and PRLAs will be reinstated on appeal, and

3) how many PRLAs will fail to meet the more

stringent commercial quantities test for discovery of a valuable deposit. The production

potential from PRLAs could range from 35

million to 60 million tons per year in the

1990’s, depending on the extent that legal,

planning, and environmental considerations

affect the issuance of preference right

leases. * This is considerably less than earlier

estimates made by DOI on production potential from PRLAs but still represents a significant contribution from Western coal in the

1990’s.

Areas Unsuitable for Mining

Section 522 of SMCRA allows DOI to designate areas on Federal lands as unsuitable

for mining. Two petitions affecting Federal

coal have been filed. One petition involving

existing leases in southwestern Utah has

been decided, In December 1980, the Secretary of the Interior declared 8 percent of

the leased surface minable reserves in the

Alton area (about 24 million out of 290 million

tons) as unsuitable for mining because of ad-

*This range includes about 10 million tons of PRLA production rapacitv ass(mia ted with new mines on exislln~ E’wicral

le[ises. Addili(m:il PRI,A prlxiurlit)n is p(wsihle from PR1,As In

WI St e rn 0)1( )ra(io o nd \4’\oming i f :] vt?rv s [ rt mg (iomo n(i ii rises

for (>(lal 111:1[ is suil:)ble for stnlh[;li( fuels (i(?v[;lopmcnt in Ihf?

1 990’s.
Ch 1—Executive Summary ● 31

verse impacts on nearby Bryce Canyon National Park. The Secretary found that mining

activities would significantly reduce visibility

and scenic vistas from park overlooks and increase noise levels in the park, damaging the

values for which the park was established

and the experience of the park’s visitors. The

decision has been challenged in Federal court

in Utah by both the environmental groups

who brought the petition and by the Alton

lessees.

The second petition submitted jointly to

OSM and the State of Montana involves intermingled Federal, State and private lands in

the Tongue River area of Montana, The petition area does not cover any existing Federal

leases but does include the non-Federal

Montco Mine with a proposed capacity of 12

million tons per year as well as areas under

consideration for the 1982 Powder River

region coal lease sale.

Transportation Considerations

The two most important modes of transporting Western coal in 1979 were by rail

and wire. Railroads originated more than 60

percent of all Western coal production in

1979. Most Federal coal was hauled by rail to

utilities. Mine-mouth and other nearby generating plants use locally mined coal and distribute it as electricity through high-voltage

transmission lines.

Other transport modes are currently less

important to Western coal production. Only

one coal slurry pipeline presently operates,

It has a 4.8-million-ton-per-year capacity.

Trucks handle about 15 percent of Western

coal tonnage, mainly for local markets in

Utah and Colorado. About 2 percent of Western coal is moved by rail to port terminals on

the Great Lakes, and another 4 percent to

river connections, About 23 percent was

moved by tramway, conveyor, or private

railroad.

The Western rail transportation network

has the ability to increase its capacity to

move coal from mine to market during the

1980’s and 1990’s. Most Federal coal leases

are and will be served by rail. The mine-tomarket transportation cost of Western coal

ranges from about 10 percent to over 70 percent of delivered fuel costs and constitutes an

important factor in determining future demand. The existing rail transportation network in the West was generally adequate to

move coal production from Federal leases

and private tracts in 1980, although a number of specific bottlenecks have been identified. The principal constraint that might

materialize in moving leased coal to its

markets is the willingness of the railroads to

invest sufficient capital in time to satisfy demand for increased rail service from all shippers, including Federal coal,

Increasing amounts of Federal coal are

likely to be burned at nearby powerplants

and the electricity transmitted by wire. However, plans for construction of powerplants in

the West to export electricity must consider

air quality standards, competition for water,

and possible opposition to granting of rightsof-way for high-voltage transmission lines.

These plants are attractive to utilities which

own both the generating plant and distribution system and, thereby, become independent of other carriers. Various studies have

reached different conclusions regarding the

relative cost efficiency of rail v. wire transportation.

Although coal slurry pipelines have not

played a significant role in coal transportation

to date, a number of slurry pipelines are

planned or proposed. Nearest to construction

is the Energy Transportation Systems Inc.

line that is planned to ship 25 million tons per

year of Powder River basin coal to Oklahoma,

Louisiana, and Arkansas. OTA found in an

earlier study* that:

. . . [coal slurry pipelines] . . . do represent

under some specific circumstanecs the least

costly available means for transporting coal

measured in economic terms.

*Office off Technology Assessment, U.S. Congress. Coal

Slurry Pipelines, Summary, Washington, D.C., U.S. Government Printing Office, September 1980) p. 8 I’ll IS SLInInl{I r\ II IJ-

(1:) I(:s :In [?() rl i(’r rt;p{ )rl. ,] ‘I’(I( III] ( Il{JgJ ,liif~~sr]lf~rl( ~il ( ‘I)(JI

Sl~irr\ Pi/){Jlir]f~\ {L1’iishingtt)rl. 1). ( ;.. 1‘ S ( jt}~t’rrlrnt~l] I 1]1’11) I lr]~

[) ffi((?, il;lr(h 1 ‘1781.
32 ● An Assessment of Development and Production Potential of Federal Coal Leases

This report also stated that:

. . . the introduction of coal slurry pipelines is

not likely to affect materially the rate of coal

resource development and use on a national

scale. It may, however, affect the regional

pattern of coal mining and distribution in

such a way as to expand the use of Western

coal to greater distances from its area of

origin,

Revenues and Socioeconomic

Considerations

Energy development, including recent

large-scale coal mining, has frequently

brought rapid growth to Western rural

towns. Many communities have been hard

pressed to deal with the sudden influx of people. Typically, they have found themselves

short of housing, municipal services, health

care facilities, and other elements of an

extensive community infrastructure. Some

towns have shown symptoms of social disruption, such as increased crime, alcoholism and

suicide, and of economic dislocation, such as

local business failures and labor shortages.

The communities have had varied degrees

of success in coping with these boomtown

problems. Mitigation is complicated because

it is hard to anticipate which towns are apt to

have severe difficulties. Both public and private sectors are engaged in preventive efforts; industry actively participates because

successful mitigation helps stabilize its work

force.

The ability to solve the problems is hampered by a lack of timely revenues; expanded

facilities and services are needed before new

local taxes are available, Planning and construction must start in the early stages of

rapid growth, but this is before mines or

other industries come on the local tax rolls.

Several ways have been used to meet the

early costs. These include State revenue

mechanisms, such as severance taxes, and

private contributions, such as the prepayment of taxes. The States’ share of Federal

mineral leasing revenues can be used, but

these payments do not increase substantially

until coal is produced. Consequently, State

and local governments have looked to other

Federal programs for assistance.

Each Western State (except Alaska) receives 50 percent of the revenues from mineral leases of public lands in the State. These

funds are distributed according to priorities

set by each State legislature. Section 10 of

FCLAA directed OTA to provide an estimate

of future rentals and royalties from existing

Federal coal leases. Based on potential production and expected coal prices for each region, OTA has derived estimates for 1986 and

1991. Table 5 shows the current allocation

and estimates by State. The estimates indicate a substantial increase over the amount

Table 5.— Federal Royalties and State Distributions From Potential Coal Production on Federal Leases

1980 (actual), 1986, and 1991 (estimated)

198 0

a –

—

1986b1991 b —

Federal lease

production

(millions of

State tons)

Colorado . . . . . . . . . . . . . . 9.4

Montana . . . . . . . 10.4

New Mexico. . . . . . . . . 6.3

North Dakota. . . . . . . . 0.6

Utah . . . . . . . . . . . . . . . . . . . . 8.7

Wyoming . . . . . . . . 33.4

Royalty State

total share

(millions of dollars)

8.9 4.5

2.7 1.3

3.5

(0.3) 0

4.5 4.4

Federal lease

production

(millions of

tons)

27

23-31

9-11

about 6

26

113-150

Royalty State

total share

(millions of dollars)-

49 24

21-27 10-14

15-16 7-8

about 4 2

48 24

57-71 28-36

Federal lease

production

(millions of

tons)

33-40 25-40

12-16 C

6

34-66

133-238

Royalty State

total share

(millions of dollars)

78-94 39-47

23-37 12-19

21-28C 11-14C

5 2

64-122 32-66

145-258 73-129

Total (West). . . . 68.8 31.5 16 204-250 193-215 95-108 245-405 336-544 168-277

Details may not add to totals because of independent rounding.

a U.S. Department of the Interior, Geological Survey, Conservation Division Federal and Indian Lands, Coal, Phosphate, Potash, Sodium, and Other Mineral Production,

Royalty Income, and Related Statistics, Calendar Year 1980 (June 1981).

bRoyalty estimates assume timely readjustment of leases to a minimum royalty of 125 percent for surface coal and 8 Percent for underground coal

cExcludes about 8 million tons of Federal PRLA production and about $15 million in PRLA royalties.

SOURCE: Off Ice of Technology Assessment.
Ch. 1—Executive Summary ● 33

of revenues distributed in 1980, These revenue increases come primarily from expanded Federal production and readjustments to the higher royalty rates required by

FCLAA,

There is, however, considerable debate

over whether existing private and governmental programs will be adequate to meet the

financing and other needs arising from the

management of energy development growth.

Federal coal development in the 1980’s,

especially in areas where other kinds of rural

industrialization (such as synfuels and powerplant development) are occurring, could

strain the capacities of communities in the

Powder River basin, the western slope of Colorado, central and southern Utah, and the

San Juan basin of New Mexico.
CHAPTER 2

Background and Introduction
Contents

Page

Scope of the Assessment and Methodology ● ............ ✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎✎

Information Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Analysis of Leases in Mine Plans . ● ●✎ . . . . . . . . . . ............... .

Analysis of Undeveloped Leases ● . . ............ .

Analysis of Diligent Development. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ,.

Uncertainties in the Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Focus of Subsequent Chapters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

38

38

40

40

41

43

44
CHAPTER 2

Background and Introduction

The Federal Government owns between 50

and 60 percent of the coal reserves west of

the Mississippi River. Over 16 billion tons of

these Federal reserves are currently under

lease, * In 1979, coal production from leased

Federal land was about 60 million tons. As

Western coal production expands to meet

new demand, the development of Federal

leases will become increasingly important.

Since 1920, the Department of the Interior

(DOI) has administered a leasing program

that allows the private sector to mine coal on

Federal lands, A lease grants to the lessee the

exclusive right to mine coal subject to the

terms of the lease and to State and Federal

laws. Historically, leases have been issued by

two methods; 1) competitively, to the highest

bidder at a lease sale and 2) noncompetitively, through an application process called

“preference right leasing, ” to prospectors

who discovered commercial coal reserves on

Federal land, About half of all existing leases

have been issued by each method. The Federal Coal Leasing Amendments Act of 1976

(FCLAA), which abolished the preference

right system, requires competitive leasing of

Federal coal.

In 1970, a Bureau of Land Management

(BLM) study of the Federal coal leasing program found that from 1955 to 1970 the

amount of coal under lease had increased

sharply while the amount of production from

Federal leases had declined. (See fig, 15 in

ch. 3,) In response to this study, BLM imposed

an informal moratorium in 1971 on the issuance of new leases. The purpose of this moratorium, which was made formal in February

1973, was to provide time to reassess Federal

coal leasing policies. Over the next several

years a number of issues were examined during BLM’s reassessment of the size, timing,

and location of new leasing.

*See ch. 4 anti table 7 for a discussion of the amount of Federal coal reserves in the West.

Public concern and debates about these

issues and about the structure and management of the leasing program led to congressional hearings and to passage of FCLAA

(Public Law 94-377). Section 10 of this act

directs the Office of Technology Assessment

to conduct an independent review of existing

Federal coal leases. Specifically, the act

directs OTA to:

● analyze all mining activities on Federal

coal leases;

• determine the present and potential value (production) of Federal coal leases;

● estimate the Federal receipts from lease

rentals and royalties: and

• assess the feasibility of using deepmining technology in leased areas.

To meet these requirements, OTA completed a comprehensive inventory of Federal

coal leases, which identifies the location of

each lease, its major geotechnical characteristics (e.g., amount and quality of coal, depth

and thickness of the coal seams), and the

business experience and capability of the

lessee. After completing this inventory, OTA

analyzed the development potential and production prospects of the 565 Federal coal

leases in existence on September 30, 1980. *

OTA estimated the mine design capacity and

annual production that these leases could

sustain from 1980 to 1991, considering the

mining and reclamation conditions anticipated on the leases and the market conditions, environmental, transportation, legal,

and institutional factors affecting their development. In addition, OTA analyzed the prospects for increasing coal recovery by underground methods on Federal leases and

estimated the revenues from present and

potential production.
38 . An Assessment of Development and Production Potential of Federal Coal Leases

Scope of the Assessment and Methodology

There are currently 565 Federal coal

leases and over 170 pending preference right

lease applications (PRLAs) in 14 States. This

report focuses on the leases in Colorado,

Montana, New Mexico, North Dakota, Oklahoma, Utah, and Wyoming. These seven

States account for 97 percent of the existing

leases and over 99 percent of the leased recoverable reserves (16.5 billion tons). OTA

did not examine the development potential

and production prospects of unleased Federal coal reserves, proposed new leasing tracts,

or the small quantity of reserves under lease

in Alabama, Alaska, California, Kentucky,

Oregon, Pennsylvania, and Washington.

Coal leases in this report are classified according to their mine plan status on September 30, 1980. Submittal of a mine plan is

an important milestone in lease development.

DOI must approve a mine plan before a lessee

can mine coal from Federal land. Each mine

plan details the development plans of the

lessee, includes technical information on the

resource characteristics of the lease(s), and

describes the proposed mining operation. Accordingly, OTA grouped the leases in three

categories of development: 1) leases with approved mine plans; 2) leases with mine plans

submitted and pending approval; and 3)

leases with no submitted mine plan. Leases

without mine plans are called “undeveloped”

leases in this report.

Evaluation of the development potential

and production prospects of existing Federal

coal leases and PRLAs involved extensive

data collection and analysis. Development

and production of Federal coal will depend on

a variety of property characteristics, including: 1) the quantity and quality of reserves, 2)

the geological features of the coal deposits, 3)

the size and configuration of the leases (coal

leases vary from 40 acres to more than

20,000 acres and are often interspersed with

non-Federal coal), and 4) environmental, mining, and reclamation conditions. The mining

experience and capital resources of the lessee are also important to consider in estimating the development potential and production prospects of a lease. The production

prospects of many Federal leases will also depend on other factors including the level of

demand and location of markets for Western

coal, the impacts of State and Federal policies and regulations, and the availability of

transportation.

Information Sources

OTA obtained information from a variety

of sources, including: 1) Federal and State

government agencies; 2) special studies; and

3) interviews and special State task forces.

Federal and State Government Agencies

In addition to the mine plans submitted by

the lessees and the lease records, two important sources of technical data used in this

study, especially for the analysis of undeveloped leases, are the Automated Coal Lease

Data System (ACLDS) and the information

submitted by lessees under General Mining

Order No. 1 (GMO No. 1).

ACLDS is a computer-based inventory of

Federal coal leases and lease applications.

The system is managed by BLM and is updated every 6 months. The purpose of ACLDS

is to store in a readily accessible format a

range of technical and administrative information on every existing lease. The system is

still being developed and both the quality and

amount of information vary among leases.

The U.S. Geological Survey (USGS) is currently revising the reserve information for

each lease in ACLDS, integrating the information on mining methods and conditions acquired by USGS officials and geophysical

data from its files with data prepared under

contract and with each lessee’s submittal

under GMO No. 1.

GMO No. 1 establishes a standard procedure for estimating in-place, minable, and recoverable reserves. The order also requires

the lessee to submit other information on a
Ch. 2—Background and Information ● 3 9

lease such as overburden thickness, stripping

ratio, and seam thickness according to uniform reporting criteria. GMO data are reviewed and processed in regional offices of

USGS. Because there are differences in the

interpretation of this data among USGS offices, the process of developing a uniform,

comprehensive data base for Federal coal

leases is still continuing. When GMO data

were not available, OTA was often able to obtain information on coal reserves from the

lessees themselves or from regional environmental impact statements (EISS), other published sources, or independent calculations.

Special Studies

In addition to reviewing numerous published and unpublished reports on Western

coal development and Federal coal leasing,

OTA conducted several special studies to

support the assessment, These include:

● Ownership study, Analysis of ownership

trends of Federal coal leases that identifies and classifies the types of business

organizations that have acquired Federal coal reserves from 1950 to 1980.1

● PRLA study. Review of the history of

preference right leasing, the location of

existing PRLAs, and the ownership patterns and business organizations of the

holders of PRLAs.

● Mine development study. Review of the

major geotechnical and economic features of coal mining in the seven Western States covered in this assessment.

“Mine profiles” are developed for each

region.

1 This study has been published as an OTA Technical Memorandum, Patterns and Trends in Federal Coal Lease Ownership, 1950-80, OTA-TM-M-7, March 1981.

●

●

Market studies, Analysis of the likely

markets for coal produced in Wyoming,

Montana, Colorado, and Utah, and of the

factors that are expected to affect demand for this coal in the 1980’s.

Synthetic fuels study. Analysis of the

coal quality requirements an-d technical

issues affecting potential development of

coal-based synthetic fuels projects in the

Western United States.

Interviews and Task Forces

OTA conducted personal and telephone interviews with representatives of coal companies, industry associations, Government

agencies, and technical and policy specialists. OTA also convened five State task forces

to assess the development potential of undeveloped Federal leases in Colorado, New

Mexico, Oklahoma, Utah, and Wyoming and

to review the factors affecting coal development in these States. These task forces

brought together participants from Federal

and State government agencies, industry, environmental groups, and the general technical community. * The results of task force

deliberations contributed to the six OTA

State reports, which assessed the development and production prospects of undeveloped leases and analyzed the factors affecting Federal coal development in each of the

seven States.**

*A complete listing of the task force participants is at the

front of this report.

**Six State reports were prepared. Reports on the undeveloped leases were prepared for: 1) Wyoming and Montana; 2)

Colorado; and 3) Utah. Reports for North Dakota, Oklahoma,

and New Mexico were also prepared, covering both developed

and undeveloped leases. These reports will be available

through the National Technical Information Service.

4 - : 1, ‘ — ,. - 1.
49 . An Assessment of Development and Production Potential of Federal Coal Leases

Analysis of Leases in Mine Plans

The primary source of information used to

estimate potential production for leases in approved or pending mine plans was the mine

plan itself.

Some of the important mine plan data reviewed by OTA include:

●

●

●

quantity and quality of the reserves,

total permitted and total disturbed acreage, seam thickness, and depth of overburden;

mining and reclamation methods, permit

requirements, and pending regulatory

actions;

mine design, anticipated resource recovery rates, peak capacity of the mine,

and the lessee’s estimated annual production from 1981 to 1990.

After reviewing this information, OTA prepared a summary of each mine plan that identifies the location, size, and type of the mining

operation; the Federal leases, and the State

and private lands in the mine plan or contiguous with or close to the mining area; surface

ownership; and the quality and quantity of

the coal reserves.

The summary also identifies the geological,

environmental, and mining conditions that

could potentially increase or decrease the recoverability of the coal reserves at the mine.

The summary also considers the completeness of the mining plan, the status of geological exploration and monitoring activities

completed at the site, and access to transportation networks.

The quality and amount of the information

contained in the mine plans, and the range of

issues they covered, vary considerably. Some

of the mine plans exceed 20 volumes. Many

provide a great deal of information on the environmental factors discussed in this report,

especially those pertaining to reclamation.

Comprehensive technical and environmental

assessments prepared by the Office of Surface Mining (OSM), and technical and policy

memoranda prepared by OSM and USGS during the mine plan review are also included in

the official Government files on many of the

larger mine plans, along with contractor

reports and correspondence between lessees

and Government officials. *

*A few leases in mine plans that were incomplete or inactive

or submitted after August 1980 were included in the assessment of undeveloped leases.

Analysis of Undeveloped Leases

Nearly 45 percent of the existing Federal

coal leases (249 leases) are not covered by approved or pending mine plans. For these undeveloped leases, detailed descriptions of the

lessee’s development plans are not readily

available. State task forces were convened to

assist in assessing the development potential

and production prospects of these undeveloped leases. Task forces were held in Colorado, New Mexico, Oklahoma, Utah, and

Wyoming.

Before each task force, OTA conducted a

preliminary evaluation of the development

potential of the undeveloped leases in the

State. All adjoining undeveloped leases held

by the same lessee and forming a compact

and contiguous geographic unit were combined into a single lease block for purposes of

analysis. The property characteristics of the

lease blocks were then compared with a profile of economically viable mines in the State.

(Mine profiles for average new mines were

developed for each Western coal basin with

Federal leases.) The following questions were

asked in the comparison:

● Mining unit. Is the lease block compact,

contiguous, and under single ownership
Ch. 2—Background and Inforrnation • 41

to allow for orderly development as a

mining unit?

● Coal reserves. Are there enough recoverable coal reserves within the lease

block to support a competitive new mining operation?

● Coal quality. Do the coal reserves meet

minimum Btu, sulfur, and ash quality

standards for the expected end use (e.g.,

electric power generation, industrial

use, synthetic fuels)?

● Geological characteristics. Do the geological and topographical conditions of

the coal reserves—such as depth of

overburden, seam thickness, and dip—

permit economic coal recovery?

● Ownership. Does the lessee have the financial capability and mining expertise

to develop the lease block?

The task force members drew on their extensive experience and knowledge of local

conditions to assess the influence of other

factors on the development potential of the

leases, including potential markets, geographic location, status of adjacent properties, surface resource values, transportation availability, community infrastructure,

and environmental impacts. Following this

review, OTA, with the assistance of the State

task forces, classified the lease blocks as

having:

●

●

•

Favorable development potential.—The

lease or lease block has favorable development characteristics overall; the

lease(s) meet the threshold criteria for a

viable mining property; there are no

identified major technical or permitting

problems or uncertainties associated

with the lease development.

Uncertain development potential.-The

lease or lease block has uncertain development potential because development

is contingent on factors such as transportation or synfuels development or because of lack of information about the

lessee’s development intentions. Property characteristics can be good or

marginal.

Unfavorable development potential.—

The lease or lease block has unfavorable

development potential, generally because it has one or more of the following property characteristics: small reserves, difficult mining or reclamation

conditions, poor quality coal, or isolated

location.

Finally, each State task force estimated the

production prospects for all undeveloped

leases with either uncertain or favorable

development potential. The results of each

task force were reviewed by OTA and supplemented with additional information where

needed.

Analysis of Diligent Development

The 1920 Mineral Leasing Act originally

provided that a Federal lease be issued for an

indeterminant period of time, subject to the

requirement that the lease be diligently developed. The act also included a clause requiring continuous operation after the lease was

brought into production. Failure to abide by

these conditions was grounds for cancellation

of the lease. Between 1920 and 1970, however, the diligence requirements for Federal

coal leases were not specifically defined. No

lease was ever canceled because it failed to

meet diligence. In 1976, FCLAA removed the

indeterminate term for Federal leases and required that new leases be canceled if they do

not produce coal in commercial quantities

within 10 years of issuance. Also in 1976, DOI

issued regulations specifying that 21⁄2 percent of the recoverable reserves on leases

issued before the passage of FCLAA (preFCLAA leases) must be mined by June 1,

1986, to fulfill the terms of diligent development and that 1 percent of the recoverable

reserves on leases issued after August 4,
42 . An Assessment of Development and Production Potential of Federal Coal Leases

1976 (post-FCLAA leases) must be mined 10

years after the date of issuance. Continuous

operations requirements were also specified.

Under the 1976 regulations, the Secretary

of the Interior can grant up to a 5-year extension of the 1986 deadline for pre-FCLAA

leases. (Post-FCLAA leases are not eligible

for this 5-year extension.) The grounds for

granting an extension are: 1) time needed to

complete the development of an advanced

technology such as synthetic fuels, 2) time

needed because of the magnitude of the project such as a large mine, or 3) a contract for

sale of the first 21⁄2 percent of the lease

reserves after 1986. In addition to the above

reasons, lease terms can be suspended because of delays in meeting the diligence requirements that are beyond the control of the

lessee (e.g., accidents, strikes, or administrative delays). Poor market conditions do not

constitute grounds for suspending the lease

terms or extending the deadline for diligence.

In light of the diligence requirements promulgated in the 1976 regulations, 2 years are

particularly important in OTA’s analysis of

Federal coal development: 1986 when leases

issued prior to August 4, 1976, must meet the

diligent production requirement of 21⁄2 percent of the recoverable reserves, and 1991

when those pre-FCLAA leases that have been

granted a 5-year extension must produce 21⁄2

percent of the recoverable reserves. OTA

analyzed its estimates of future production

from Federal coal leases to determine how

many leases are likely to meet diligence by

1986 or by 1991. *

Patterns of coal ownership in the West are

not always consistent with the most efficient

and economical mine design. Often a mine

*Of the 565 Federal coal leases in existence as of Sept. 30,

1980, less than 40 are post-FCLAA leases. Almost all of these

post-FCLAA leases are associated with active mines and will

meet diligence by or before their due date as part of the larger

mining operation.

will include coal that is owned by the Federal

Government, by a State Government, or by a

private party. In recognition of this possibility

and to promote the economical and efficient

development of Federal coal leases, the concept of logical mining unit (LMU) was included in FCLAA and the 1976 regulations.

An LMU is defined in the FCLAA as “an area

of coal land that can be developed and mined

in an efficient, economical and orderly manner with due regard for the conservation of

coal reserves and other resources.” According to the regulations, no LMU may be

larger than 25,000 acres. All areas within an

LMU must be contiguous and under the control of a single operator.

LMU is an important concept in this report

because it defines the physical boundaries

within which recoverable reserves are identified for diligence requirements. By regulation, BLM has defined every lease as an

LMU whether or not it meets the statutory

LMU description. Therefore, unless a lessee

requests that a lease be included in an LMU

with other Federal leases or non-Federal

coal, the recoverable reserves on a lease will

establish the reserve base on which diligent

production requirements will be calculated.

In cases where a lease is included in an

LMU with other Federal leases or non-Federal coal, compliance with diligent development and continued operations requirements

will be calculated on the total recoverable

reserves in the LMU, not just the Federal

reserves. Consequently, a Federal lease in an

LMU with non-Federal coal could meet diligence requirements before any Federal coal

is mined, and in any year could fulfill continuous operations requirements even if no coal

were mined from the lease itself. Under certain circumstances a lessee may petition to

relinquish certain areas of the lease or certain seams or beds, in order to lower the recoverable reserves so that diligent development can be achieved.
Ch. 2—Background and Information ● 43

Uncertainties in the Analysis

OTA’s analysis draws on extensive geological, technical, and market data, and informed judgments about the development potential and production prospects of Federal

coal leases made by OTA and the OTA task

forces on the basis of these data. Many of

these judgments were reviewed by the lessees and by technical specialists. Nevertheless, uncertainties remain in the analysis

both of leases in mine plans and of undeveloped leases.

Many undeveloped leases with good property characteristics, with owners actively

developing the property, and with markets

identified and, in some cases, with signed

contracts are likely to be producing coal in

the next 10 years. There is little uncertainty

in ranking many of these leases as having

favorable development potential and production prospects.

Many of the undeveloped leases classified

as having unfavorable development potential

have poor property characteristics compared

to mines currently operating in the area and

would be expensive to bring into production.

Small reserves, poor coal quality, difficult

mining and reclamation conditions, or combinations of several of these factors mean

that there is little uncertainty in classifying

these leases as having unfavorable development potential. However, even for some of the

undeveloped leases with poor property characteristics, the lessee might be able to integrate the lease into an operating or planned

mine or develop the lease for synthetic fuels

production. Consequently, several undeveloped leases with poor property characteristics have favorable or uncertain development

potential.

The development potential of many other

undeveloped leases was clouded by uncertainties, In several cases, lease development

was dependent on factors such as a favorable

climate for synfuels or the construction of a

new transportation facility.

Markets and the demand for Western coal

over the next 10 years were particularly important considerations for those undeveloped

leases with favorable or uncertain development potential. Coal production in the West

during this period will likely be demand

driven. OTA assessed the potential demand

for coal from States with major Federal coal

reserves. However, demand projections for

Western coal are subject to numerous uncertainties, ranging from the rate of increase of

electricity demand to the amount of coal to be

exported to foreign countries. Moreover,

even if demand for Western coal could be accurately and precisely forecast, predicting

the success of a given lessee in capturing a

share of this demand would still be subject to

uncertainty. In the buyer’s market that is

likely for Western coal in the next 10 years,

there will be strong competition for new

sales, including competition from non-Federal

coal mines in the West, from new Federal

leases, and from coal produced in other regions. A number of factors, but especially the

marketing success of the lessee, will ultimately decide whether or not a given undeveloped lease is brought into production and at

what level. Even for those leases in approved

mine plans with definite production goals and

in many cases with contracts, the amount of

coal that will be mined annually over the next

10 years is subject to uncertainty.

Thus, the estimates of potential production

from Federal leases made in this report are

not forecasts of the coal that would be produced at a given price or a given demand.

They are estimates of the total amount of coal

that could be produced from operating and

proposed Federal mines and from those undeveloped Federal leases that have characteristics comparable to operating mines in the

same region. Coal from these leases would

thus be likely to have mining costs competitive with costs at currently operating mines in

the same area. If the demand for Federal coal

does not increase to these levels of potential
44 . An Assessment of Development and Production Potential of Federal Coal Leases

production, then not all the Federal leases

that could technically and economically be

developed will be brought into production.

Moreover, although OTA based its evaluations of likelihood of development and levels

of potential production on the best data available for each lease or mine at the time, as additional information based on further exploration and development becomes available,

the prospects for any given lease or mine

could change.

Estimating production from Federal leases

was complicated by the fact that many coal

operations in the West include Federal, State,

or private (fee] coal. This pattern is most pro

nounced in southern Wyoming, the Colstrip

area of the Montana portion of the Powder

River basin, and in North Dakota. For North

Dakota, Wyoming, and Montana, OTA has estimated what fraction of the annual production of mines with Federal leases is likely to

be from Federal reserves. In many cases, the

geological characteristics of the mine and the

direction of mining operations are such that

little variation occurs from year to year in the

ratio of Federal to non-Federal production; in

other cases, however, large changes in this

ratio will occur over several years. Wherever

possible, OTA followed the judgments of the

lessee’s mine plan.

In any work that evaluates a large number of units, random statistical errors and

changes tend to cancel one another. While

events could prove OTA’s estimates of lease

development wrong in a number of individual

cases, taken in the aggregate by region or

State, the estimates presented in this report

should constitute a reasonably accurate picture of Federal coal development over the

next decade.

Focus of Subsequent Chapters

Chapters 5, 6, and 7 present OTA’s findings concerning the development potential

and production prospects of Federal coal

leases. Chapter 5 identifies the factors that

are likely to affect the markets for Western

coal over the next 10 years and reviews the

demand projections for Western coal that

have been developed and considered by industry and Government. Chapter 6 presents

the findings of the assessment on the amount

of Federal coal that is likely to be produced

over the next 10 years and the number of

leases likely to fulfill diligence requirements.

Chapter 7 is a case study of Federal coal development and production in the Powder

River Basin of Wyoming and Montana.

Chapters 3, 4, and 13 review the status,

distribution, geotechnical characteristics,

and ownership of existing Federal coal

leases, Federal coal reserves, and PRLAs.

Chapters 8, 10, and 12 examine the impacts

on Federal coal development and production

resulting from transportation availability and

costs, environmental statutes and regulations, and socioeconomic factors. Chapter 12

also presents OTA’s estimate of revenues

from rentals and royalties from Federal coal

production over the next decade. Chapter 9

provides an overview of Federal coal lease

management issues, and chapter 11 presents

OTA’s analysis of the feasibility of increasing

Federal coal recovery through underground

mining methods.
CHAPTER 3

Federal Coal Leases and

Preference Right Lease

Applications: An Overview
Contents

Page

History of Leasing **** **. .*. **e. .*** *.**   .** * **** .*9. **** *e** **** *. *m *

Lease Issuance Methods. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Pending PRLAs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .*.,...* .,*..... . . . .

Lease or PRLA Acquisition Methods. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Ownership of Leases and PRLAs ● .*..*** ● *.*,**** ● ..**...* .*..*..*. .*.*****

Lease Development Status .. ● 0....04 ..00..00 ..0...0. ....0.0$ ● .00..0. .

Leases With Approved Mine Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Leases With Pending Mine Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Leases Without Mine Plans. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

List of Tables

Table No.

6. Extent of Leasing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7. Leased, Federal, and Total Recoverable Coal Reserves in the Principal Western

Coal-Producing States. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

8. History of Leasing 1950-80 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

9. Lease Issuance Method for Existing Leases. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

10. Extent and Location of PRLAs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

11. Lease and PRLA Acquisition Method Used by Present Owner . . . . . . . . . . . . . . . . .

12. Major Business Activity Categories Holding Federal Coal Leases and PRLAs

in 1980. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . .

13. Number and Location of Leases and Lease Units. ,... . . . . . . . . . . . . . . . . . . . . . . .

14. Summary Table - The Development Status of Federal Coal Leases . . . . . . . . . . . . .

15. Leases in Production and With Approved Mine Plans. . . . . . . . . . . . . . . . . . . . . . . .

16. 1979 and 1980 Coal Production From Federal Leases and From

Western States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

17. Leases With PendingMine Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18. Leases for Which No Mine Plans Have Been Submitted . . . . . . . . . . . . . . . . . . . . . .

List of Figures

48

49

50

51

51

52

53

54

55

Page

47

48

49

49

50

51

52

53

54

54

55

56

56

Figure No. Page

15. Number of Leases, Acreage Under Lease, and Federal Coal Production From

1950 to 1980. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
CHAPTER 3

Federal Coal Leases and Preference

Right Lease Applications: An Overview

As of September 30, 1980, there were 565

Federal coal leases in 14 States (see table 6].

Ninety-seven percent of the total, or 548

leases, are located in seven Western States:

Colorado, Montana, New Mexico, North Dakota, Oklahoma, Utah, and Wyoming. These

548 leases were examined by OTA in some

detail. * Utah has 204 or 36 percent of all

leases, more than any other State, Colorado

and Wyoming have the next largest number

of leases, 127 (22 percent) and 101 (18 percent) respectively, With 20 leases, North

Dakota has the fewest leases among the

seven States studied by OTA.

*OTA did not examine coal leases that have been relinquished or canceled and made only a limited review of leases

outside this seven State region because of the small reserves involved. OTA did not study unleased Federal coal.

Table 6.—Extent of Leasing

(includes all leases in existence as of Sept. 30, 1980)

Recoverable coal

Number of Acreage reserves

leases under lease (billions of tons)

127 126.893 2.2

Colorado . . . . . . . (22%) a

(16%) (13%)

aAll percentages are percent of total Ieasing, sums may not add to 100 Percent

because of rounding.

b

The “other” leases include leases in Alabama (2), Alaska (4), California (1),

Kentucky (3), Oregon (3), Pennsylvania (2), and Washington (2)

SOURCE Off Ice of Technology Assessment,

The 565 coal leases cover 812,000 acres of

Federal land, 7 percent of the 11.5 million

acres of Federal coal land classified as

known recoverable coal resource areas

(KRCRA) as defined by the Department of the

Interior (DOI) in March 1978. Utah, Wyoming, and Colorado have a major proportion

of leased acreage with 34, 27, and 16 percent

respectively. North Dakota has the fewest

leased acres among the seven principal

States studied.

OTA estimates that 16.5 billion tons of recoverable coal reserves are now under lease

in the seven States with 97 percent of the

leases. Production from these reserves totaled 60 million tons in 1979 and 69 million

tons in 1980; in the same years, total U.S. coal

production was 776 million tons and 820 million tons, respectively.

Currently leased Federal reserves are less

than 20 percent of the estimated total of over

80 billion tons of Federal recoverable coal

reserves (see table 7). The percentage of total

Federal coal reserves under lease in each

State varies from a high of 50 percent in Utah

to a low of 5 percent in Montana and about 3

percent in North Dakota. The percentages of

federally owned coal to the total known recoverable coal reserves in each State vary

from under 10 percent in Oklahoma to 85 percent in Utah with an average of about 60 percent for the seven States. *

Leases range from 40 acres to 20,701

acres. Approximately 60 leases are under

100 acres and 4 leases are over 10,000 acres

in size. In terms of recoverable coal reserves,

some small leases contain negligible amounts

of coal (i. e., under 10,000 tons) while several

large leases contain over one-half billion tons

of recoverable coal.

*These percentages represent best available data on coal

reserves and ownership, but these data are incomplete. See

footnotes to table 7.

47
48 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 7.—Leased, Federal, and Total Recoverable Coal Reserves in the Principal Western

Coal-Producing States (all reserves shown in billion tons)

Estimates of Estimates of

Recoverable total Federal Estimates of Recoverable total Federal Estimates of

coal under recoverable total recoverable coal under recoverable total recoverable

IeaseareservesbcoalcIeasea

reservesbcoalc

Colorado. . . . . 2.2 10 17 Oklahoma. . . . 0.2 0.2 2

Montana . . . . . 1.2 26 40 Utah . . . . . . . . 3.2 6.4 7.5

New Mexico . . 0.45 4 9 Wyoming . . . . 8.9 26 36

North Dakota . 0.3 - 1 0 25 to 35 Total . . . . . . 16.5 - 8 3 -140

a

Leased reserve figures from Automated Coal Lease Data System as modified

by Office of Technology Assessment.

b

The numbers in this column are estimates of the total Federal recoverable

coal reserves in each State. The figure for New Mexico was supplied to Office

of Technology Assessment by the New Mexico Bureau of Mines and Mineral

Resources and the figure for Utah by the Utah Geological and Mineral Survey.

See footnote c, below. The figures for the other states were estimated by

multiplying the estimate of total recoverable coal in the State by the percentage of Federal coal acreage in Known Recoverable Coal Resource Areas in

each State These percentages were taken from table 21 in ch. 4 and are: Colorado (580/0), Montana (640/0), North Dakota (327.), and Wyoming (730/0). In

Montana, the Federal percentage may be high because the KRCRAs do not include Indian reservations with significant reserves of coal. The Colorado

percentage may also be high because the KRCRAs do not include the DenverRaton Mesa coal region which has a high percentage of non-Federal coal

ownership.

c

Total State recoverable reserves from the following sources:

Colorado. Keith Murray, Colorado School of Mines Research Institute. Personal communication to Office of Technology Assessment, February 1981. The figure of 17 billion tons IS based on his earlier work

at the Colorado Geological Survey.

Montana: Montana Bureau of Mines and Geology as reported in the 1979

SOURCE:

Keystone Coal Industry Manual. The figure of 40 billion tons was

derived from the reported figure of 50 billion tons of strippable

reserves and a recovery rate of 80 percent. This figure does not include 71 billion tons of underground demonstrated reserve base

also listed in the 1979 Keystone Coal Industry Manual from data

supplied by the U.S.B.M.

Office of Technology Assessment.

New Mexico: New Mexico Bureau of Mines and Mineral Resources, Personal

communication to Office of Technology Assessment, August 1981.

The figure does not include an additional 59 billion tons of

recoverable underground reserves between 250 ft depth and 3,000

ft depth because insufficient information was available for the

New Mexico Bureau to determine the portion of these reserves in

seams that are likely to be mined In the next decade.

North Dakota: North Dakota Geological Survey, Personal communication to

Office of Technology Assessment, August 1981. A recovery rate of

90 percent has been assumed by the North Dakota Survey.

Oklahoma: Friedman, S.A. Investigation of the Coal Reserves in the Ozarks

Section of Oklahoma and their Potential Uses (Norman, Okla.:

Oklahoma Geological Survey, 1975).

Utah: Utah Geological and Mineral Survey, Personal communication to Off Ice

of Technology Assessment, August 1981. The Utah Survey cautions that this figure is low, because it is based on stringent standards for identification and correlation of economically

recoverable reserves.

Wyoming: Gary Glass, Wyoming Geological Survey, Personal communication

to Office of Technology Assessment, August 1981. The above

figure is derived from a surface reserve base of 26.3 billion tons

with a recovery rate of 80 percent and an underground reserve base

of 29.5 billion tons with a recovery rate of 50 percent. Glass cautions that the underground recovery rate of 50 percent may be too

high for Wyoming.

General caution: The total recoverable coal reserve figures were obtained

from seven different sources and are not based on uniform

standards.

History of Leasing

Federal coal has been leased since enactment of the Mineral Leasing Act on February

25, 1920. The oldest lease still in effect,

issued on January 17, 1921, originally covered 2,080 acres in Utah. Of the currently existing leases, 88 were issued before 1950 (see

table 8). These include 16 percent of all existing leases, but only 5 percent of all land

under lease as of September 30, 1980. Eightysix percent of all leases covering 90 percent

of all land under lease are at least 10 years

old. *

*A total of 526 of the 565 existing leases were issued before

Aug. 4, 1976, the date of enactment of the Federal Coal Leasing

Amendments Act of 1976 (Public Law 94-377]. Technically

these are the “existing” leases subject to OTA scrutiny under

sec. 10 of that law.

The number of leases and leased acreage

increased slowly in the 1950’s but accelerated sharply in the 1960’s (see fig. 15). The

solid line (number of leases) and the dashed

line (acres under lease) in figure 15 cross

around 1965 because of a trend during the

1960’s to include larger acreages in single

leases. The moratorium on most new leasing

by DOI from 1971 through 1980 slowed leasing to the levels of the 1950’s.

Historically, trends in Federal coal production did not coincide with trends in leasing.

Production declined from 7.1 million to 5.4

million tons from 1950 to 1960 and remained

at this relatively low level during the 1960’s.

Production during the 1970’s has, however,

soared from 7.3 million tons in 1970 to 69 million tons in 1980.
Ch. 3—Federal Coal Leases and Preference Right Lease Applications: An Overview Ž 49

Table 8.— History of Leasing 1950-80a

Number of leases Acres under lease

1950 . . . . . . . . 88 (16%) b

41,492 (5%)

1955 . . . . . . . . 119 (21 %) 75,949 (9%)

1960 . . . . . . . . 166 (29%) 143,746 (18%)

1965 . . . . . . . . 286 (51%) 308,354 (38%)

1970 . . . . . . . . 485 (86%) 733,318 (90%)

1975 . . . . . . . . 523 (93%) 764,994 (94%)

1980 . . . . . . . . 565 812,001

a

Table includes only leases in existence on Jan 2 of each year Iisted 1950-75

and which were still valid on Sept. 30, 1980 The 1980 figures report alI leases

in existence on Sept. 30, 1980

b

percentages are percent of 1980 totals.

SOURCE Office of Technology Assessment

Figure 15.— Number of Leases, Acreage Under

Lease, and Federal Coal Production From

1950 to 1980

. . Acres under lease

.

— Number of leases /

produced per year

1950 1960 1970 1980

SOURCE Acreage and number of leases data from OTA review of DOI case

files Federal coal production from the U S Department of Interior,

Federal Coal Management Report Fiscal Year 1978, March 1979 and

from the ACLDS

Lease Issuance Methods

Existing leases were issued by one of three

methods: 1 ) competitive bidding at a lease

sale, 2) noncompetitive preference right leasing, or 3) segregation of an existing lease (also

called partial assignment).

The Mineral Leasing Act of 1920 requires

DOI to lease competitively public land known

to contain commercial quantities of coal, Several bidding procedures have been used in

the past, including sealed written bids and

open verbal auctions. Leases have been

awarded to the party offering the highest onetime cash bonus payment. Other bidding

methods besides the cash bonus procedure

may be used for future leasing. Although

these lease sales were open to all bidders,

more than half of all lease sales held before

1979 attracted only one bidder. In total, 52

percent of all existing leases have been

issued under the lease sale method (see

table 9).

Preference right leasing under the 1920

leasing act was limited to land without known

commercial quantities of coal for which additional prospecting work was needed to determine the existence of economically minable

coal deposits. In these cases, applicants could

receive a prospecting permit from DOI to perform exploration and drilling. If coal was

found in commercial quantities within the 2-

year permit period (extendable once), the

prospector was entitled to a preference right

lease. As an incentive to promote exploration

of public lands, no bonus was required on

preference right leases. Of all existing leases,

42 percent were issued under the preference

right method.

In 1971, DOI suspended issuance of new

prospecting permits and delayed processing

Table 9.—Lease Issuance Method for

Existing Leases

Issuance method Number of leases 0/0 of leases

Lease sales . . . . . . . . . . . 294 520/o

Preference right , . . . . . . 237 420/o

Segregation . . . . . . . . . . . 34 60/0

SOURCE Off Ice of Technology Assessment
50 ● An Assessment of Development and production Potential of Federal Coal Leases

of pending preference right lease applications (PRLAs). In 1976, in the Federal Coal

Leasing Amendments Act, Congress repealed

provisions for preference right leasing, subject to valid existing rights. The preference

right program no longer exists except for the

applications for leases based on the prospecting permits issued prior to the 1971 leasing

moratorium (nearly all dating from 1967 to

1971). Applications for leases were not completely processed by DOI when the moratorium began; processing largely ceased during the moratorium and resumed in late 1979.

(About 176 applications remain.) These

PRLAs are discussed in more detail in the

next section.

Another leasing procedure is called segregation or partial assignment. Here, an existing lease is divided into two or more parcels at the request of the lessee(s). Such

actions require the approval of DOI. A new

lease(s) is then issued for the new tract(s) and

the terms of the surviving lease are modified

to reflect a reduced acreage. Only 6 percent

of outstanding Federal leases have been created by segregation.

Pending PRLAs

As of January 1, 1980, there were 176

pending applications for preference right

leases. They stem from prospecting permits

issued between 1955 and 1971—with 172 (98

percent) originating after January 1, 1965.

These permits expired just before or shortly

after the initiation of the leasing moratorium

in 1971 and the resulting lease applications

were neither approved nor denied. They have

remained unprocessed for a decade, although

they have been the subject of lawsuits, Government studies, and congressional actions.

Nearly 98 percent of the PRLAs are located

in the seven Western State region studied by

OTA (see table 10). The remaining four are in

Alaska. In total, 403,800 acres of Federal

coal land are included in PRLAs and involve

an estimated 5.8 billion tons of recoverable

coal reserves. Wyoming, with 74 PRLAs, has

the largest number of applications. They inTable 10.—Extent and Location of PRLAs

Recoverable coal

Number of reserves

PRLAs Acreage (billions of tons)

Total . . . . . . . . . . . 176 403,800 5.8

aAll percentages equal percent of total for all PRLAs.

b

Figures for Montana and Oklahoma combined.

SOURCE” Number of PRLAs and acreage from OTA review of DOI case files.

Reserves from Automated Coal Lease Data System, Sept. 30, 1979

and reported in U S. Department of the Interior, Federal Coal Management Report, March 1980.

elude 43 percent of the reserves and 34 percent of the acreage in all PRLAs. Colorado

ranks second with 37 PRLAs including 18 percent of total reserves and New Mexico is

third with 28 PRLAs including 26 percent of

the reserves.

Acreages and reserves under the PRLAs

are substantial. If all the applications are approved and converted to leases, total land

under lease will increase by 50 percent and

leased recoverable coal reserves will be

raised by 35 percent.

Most of the legal and administrative problems preventing the processing of the PRLAs

have been resolved in recent years. The current Federal coal lease management program

adopted by DOI in July 1979 calls for the processing of the applications to be completed by

1984. Environmental, legal, and technical

considerations could lead to the rejection of

some of the PRLAs or result in acreage modifications or the addition of lease stipulations

which restrict subsequent coal mining. These

issues are discussed in more detail in

chapter 9.
Ch. 3—Federal Coal Leases and Preference Right Lease Applications: An Overview ● 51

Lease or PRLA Acquisition Methods

Although each lease or prospecting permit

was originally issued by DOI, there are several other methods by which the present

owners have obtained leases or PRLAs.

The issuance of a lease or prospecting permit by the Federal Government is termed in

this study de novo leasing or permitting. OTA

found in a study of the 538 leases and 176

PRLAs outstanding as of September 30, 1979,

that only 117 leases (22 percent of the lease

total) and 19 PRLAs (11 percent of the total

PRLAs) are still held by the original owner

(see table 11). The remaining 78 percent of all

leases and 89 percent of all PRLAs have been

obtained by their present owners from previous owners through one of two methods:

1) assignment and 2) segregation.

Owners of leases or PRLAs may sell or

transfer their contracts to other parties with

approval of DOI. This process is called assignment. Assignments are essentially private transactions and any cash, property,

service agreements, or overriding royalties

are, with few limitations, between the buyer

and seller.

Table 11.— Lease and PRLA Acquisition Method

Used by Present Owner

Number and percent Number and percent

Acquisition method of leases of PRLAs

De novo . . . . . . . . . . . . 117 (22%) 19 (11%)

Assignment ., . . . . . . . 403 (75%) 133 (76%)

First . . . . . . . . . . – 146 –76

Second. . . . . . . . . . . – 124 - 2 7

Third or more . . . . . – 133 –30

Segregation. . . . . . . . . 1 8

a (3% ) 24 (14%)

aThe "Segregatlon" total in this table differs from the number (34) Iisted in table

9 because eight segregated leases were subsequently assigned to their present owners Also, table 9 includes 27 leases issued in late 1979 and in 1980

These leases were not Included in the above analysis

SOURCE: Office of Technology Assessment.

Approximately 75 percent of the outstanding leases and PRLAs were obtained by their

current owner through assignment. Multiple

assignments have been made on many leases

and PRLAs; 124 leases have been assigned

twice and 133 have changed hands three or

more times. The 176 PRLAs have been assigned a total of 227 times.

Segregation, already discussed in this

chapter (see table 9), has been used by the

present owners of 18 leases and 24 PRLAs.

Like assignments, segregations are largely

transactions among private parties that are

then recorded by the Federal Government.

Control of a coal lease or PRLA can be

obtained without actually acquiring title

through the de novo, assignment, or segregation procedures, This involves the purchase

of a controlling interest in a firm which

already owns leases or PRLAs. The acquired

firm can then become a subsidiary of the purchaser and the purchaser is able to make decisions affecting the leases or PRLAs. Although transfers of title by assignment from

the acquired company to the purchasing company often occur, they are not obligatory.

Corporate mergers and acquisitions have

frequently involved leases and PRLAs. For

example, at least 10 of the 36 leaseholding

companies now operating as wholly owned

subsidiaries once held leases as independent

corporations. As another example, in 1980

three firms holding leases were purchased by

major energy companies. Because lease title

transfers do not always accompany corporate acquisitions, it is difficult to precisely determine the role of mergers in the leasing program; however it is clearly significant.

Ownership of Leases and PRLAs

Ownership of leases and PRLAs is shared ventures involving some of the largest corpoby a number of unincorporated individuals rations in the world. *

and by a variety of diverse companies.

Owners range from sole proprietors to joint

*Lease and PRLA ownership patterns and trends from 1950

to 1980 are discussed in greater detail in ch. 13. Lease owner-
52 . An Assessment of Development and Production Potentia/ of Federal Coal Leases

About 115 corporations own coal leases or

indirectly control them through subsidiaries

or joint ventures. In addition, as of January 1,

1980, 59 individuals held leases in their own

name. As of January 1, 1980, 29 companies

and 18 individuals owned PRLAs.

Electric utilities hold 21 percent of all outstanding acreage under coal lease as of September 30, 1979, more than any other single

business category defined by OTA. Seventeen

utilities now own leases. Eleven of the 18 largest oil companies (i.e., the oil majors) control

20 percent of leased acreage. Seven other

business activity categories own leases covering at least 5 percent of all land under lease,

ranging from 8 percent owned by Peabody

Coal Co. (the largest single lessee) to 5 percent owned by nonresource-related diversified companies such as General Electric or

Monsanto (see table 12 and ch. 13).

Unincorporated individuals hold 20 percent of all land included in PRLAs, more than

any of the eight business categories identified

by OTA as major PRLA holders. The major

energy companies rank second, with 16 percent. Other principal holders of PRLAs include natural gas pipeline, metals, oil or gas,

and electric utility companies.

OTA found that lease and PRLA holders

represent one of four types of business organizations. Most of the acreage under lease

(43 percent) and under PRLA (44 percent) is

held by subsidiaries of larger parent companies. Only 26 percent of all leased land and

12 percent of land under PRLAs is controlled

by independent firms. Multicorporate entiContinued from p. 51.

ship is discussed in considerable detail in the OTA Technical

Memorandum Patterns and Trends in Federal Coal Lease Ownership: 1950-80, OTA-TM-M-7, March 1981.

Table 12.—Major Business Activity Categories

Holding Federal Coal Leases and PRLAs in 1980a

Percent of Percent of land

leased land included in PRLAs

Electric utilities . . . . . . . . . . . . .

Energy companies . . . . . . . . . .

Peabody Coal Co. . . . . . . . . . . .

Steel companies . . . . . . . . . . . .

Independent coal companies.

Oil and gas (minor) companies

Unincorporated individuals . . .

Natural gas pipeline

companies . . . . . . . . . . . . . . . .

Nonresource-related

diversified companies . . . . . .

Kemmerer Coal Cob . . . . . . . . .

Metals and mining companies.

Landholding companies . . . . . .

“Other” companies. . . . . . . . . .

21%

20

8

8

7

6

5

5

5

4

2

<1

10

12

(In “other”)

(less than 5%)

10

9

1

14

a

The office of Technology Assessment analyzed separately any business

activity category (including Individual companies with unique business structures) holding at least 5 percent of all land under lease or PRLA at at least 1 of

7 analysis dates between 1950 and 1980. (See ch. 13). The analysis includes

the 538 leases and 176 PRLAs in existence as of Sept. 30, 1979,

b

ln March 1981, Kemmerer Coal Co. was purchased by Gulf Oil Corp.

SOURCE: Office of Technology Assessment

ties, such as joint ventures, are the newest

business organizations to control significant

public coal land; they hold 25 percent of

leased land and 22 percent of land under

PRLAs. Finally, unincorporated individuals

control 5 percent of land under lease and 20

percent of land under PRLAs.

Over the past 30 years, there has been a

general decline in the percentage of leases

and PRLAs held by small independent companies and unincorporated individuals. The

proportion of leases held by large diversified

firms and companies operating on leased

land through subsidiary and multicorporate

arrangements has risen. There has also been

an increase in the number of different industries holding major shares in Federal leasing.

The number of business categories holding at

least 5 percent of all land under lease grew

from four to nine between 1950 and 1980.

Lease Development Status

A principal objective of this study is to ex- isting leases and PRLAs. During this analysis

amine mining activity on Federal leases and OTA divided the existing leases into units or

to assess the development potential of ex- blocks. A lease unit, as used by OTA, consists
Ch. 3—Federal Coal Leases and Preference Right Lease Applications: An Overview ● 53

of either all leases included in the same active or proposed mine as defined by the mine

plan, or one or more undeveloped leases that

are owned by the same lessee and that are

contiguous or sufficiently close together to

form a compact minable unit. *

OTA divided the 565 existing coal leases

into 256 units (see table 13). The smallest

units contain one lease covering 40 acres.

The largest, located in southern Utah, includes 21 leases and 40,277 acres. Colorado,

Utah, and Wyoming together account for 176

lease units, 69 percent of the total.

OTA evaluated mining activity and mine

development prospects for the 244 lease units

located in the seven principal Western coalproducing States listed in table 13. The lease

units were grouped in three categories according to stages of development. Each of the

categories required a different type of data

collection and analysis. The three development categories are:

• leases with approved mine plans;

. leases with mine plans submitted and

pending approval; and

• leases without submitted mine plans.

Leases and lease units were placed in

these categories based on OTA’s review of all

mine plans on file with the Office of Surface

‘See ch. 2 for more information on the OTA methodology.

Table 13.—Number and Location of Leases

and Lease Units

State Number of leases Number of lease units

Colorado. . . . . 127

Montana . . . . . 21

New Mexico . . 29

North Dakota . 20

Oklahoma . . . . 46

Utah. . . . . . . . . 204

Wyoming . . . . 101

Other States . . 17

66

13

15

14

26

56

54

12

Total . . . . . . 565 256

SOURCE Off Ice of Technology Assessment

Mining (OSM) on September 30, 1980. * The

number of leases and lease units, acreage,

and recoverable coal reserves in each of the

three categories is shown in table 14 (see also

fig. 9 in ch. 1). Information in this table is

summarized below.

Leases With Approved Mine Plans

Approximately one-third of all leases and

all lease units have approved mine plans.

Many of the mines in this category are actively producing; however, some mines only

recently received permit approval and have

not yet begun commercial operations, The approved category also includes a small number

of new leases issued in 1979 and 1980 to ensure the continued operation of existing

mines (even if the approved mine plan has not

yet been formally modified to add the new

leases) and several leases included in pending amendments to approved mine plans.

In Montana, 54 percent of the lease units,

containing 69 percent of the leased reserves

are in approved mine plans (see table 15).

New Mexico and Oklahoma have the smallest

percentage of lease units in the approved category and Oklahoma and Utah the lowest percentage of leased reserves in the approved

category.

Before a lessee can mine coal from a

Federal lease, DOI must approve the proposed mining operation. Because only a por-

*Before coal can be produced from Federal land, a mine plan

must be submitted to and approved by DOI. Hence, mine plan

status provides a convenient yardstick by which to measure

lease development. There are two separate requirements for

mine plans for Federal leases. First, a mine plan must be submitted to comply with the general provisions and regulations

under the Mineral Leasing Act of 1920 (MLA), as amended, and

secondly, a mining and reclamation plan must be submitted for

all surface and underground mines to comply with the Surface

Mining Control and Reclamation Act of 1977 (SMCRA) whether

or not Federal lands are involved. Under DOI directives, a

single mining plan is submitted to OSM to meet both MLA and

SMCRA requirements, however, OSM and the Geological Survey each retain their separate responsibilities for enforcement

and permit approval.
54 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 14.—Summary Table—The Development Status of Federal Coal Leasesa

Approved mining plans

(including leases in production) Pending mine plans No mine plans

Recover- Recover- Recoverable able able

Number Number Number reserves Number Number Number reserves Number Number Number reserves

of of of billions of of of billions of of of billions

leases units acres of tons leases units acres of tons leases units acres of tons

aSee also table 6 in this chapter and fig. 9 in ch. 1.

bPercentages are percent of totals within the State, for each State.

cPercentages are percent of totals for all States

SOURCE: Office of Technology Assessment.

Table 15.—Leases in Production and

With Approved Mine Plans

Number Number Recoverable

of of lease reserves

leases units Acres (billions of tons)

tion of the approved permit area is mined in

any given year, it is unlikely that all Federal

coal leases in approved mine plans will be

producing at one time. In 1980, coal was

mined from about 100 Federal leases, which

is about half of the leases in the approved

category. Sixty-nine million tons of coal were

mined from the producing leases in the seven

Western State OTA study region (see table

16). Federal coal contributed 34 percent of all

production from these States. In 1980, Federal coal provided 66 percent of Utah’s entire

output, 36 percent of Wyoming’s production,

but only 3.5 percent of the coal mined in

North Dakota and only 5 percent of the coal

mined in Oklahoma.

Leases With Pending Mine Plans

Approximately 21 percent of all leases and

15 percent of leased reserves are included in
Ch. 3—Federal Coal Leases and Preference Right Lease Applications: An Overview ● 55

Table 16.—1979 and 1980 Coal Production From Federal Leases and From Western States

a

lncludes Federal production from Kentucky, Alabama, and Washington.

b

Total does not include contribution from “’other” States.

SOURCE: 1979 Federal production from U.S. Geological Survey accounting office. 1979 State production from the U.S. Energy Information Agency, Week/y Coal Production Report, Aug. 16, 1960.

1960 Federal production from U.S. Geological Survey, Federal and Indian Lands Coal, Phosphate, Potash, Sodium and Other Mineral Production, Royalty lncome, and Related Statistics, June 1981. 1960 State production from the U.S. Energy Information Agency, Personal Communication to the Office of

Technology Assessment, July 27, 1961.

the 13 percent of all lease units for which

mine plans have been submitted to OSM and

for which Federal approval is pending. This

classification does not distinguish among

lease units on the basis of quality of submitted mine plans, their date of submission,

or the current stage of the review of the mine

plan.

New Mexico, Utah, and North Dakota each

have 20 percent of their lease units falling in

the pending mine plan category. On the other

hand, no pending mine plans affecting Montana leases are being studied by DOI and only

1 of Oklahoma’s 26 lease units is included in a

pending mine plan (see table 17).

Leases Without Mine Plans

Over half of all existing lease units, 44 percent of all leases, 42 percent of all leased

Table 17.—Leases With Pending Mine Plans

Number Number Recoverable

of of lease reserves

leases units Acres (billions of tons)

0 0 0 0

Montana. . . . . . . — — — —

aPercentags are percent of total for each State except percent of total which

is percent of seven State total.

SOURCE: Office of Technology Assessment

84-141 0 - 81 - 5 : O L 3
56 ● An Assessment of Development and production Potential of Federal Coal Leases

acreage, and 40 percent of leased reserves

have not been developed to the point of a mine

plan submission to OSM.

Preliminary development activity varies

widely on these undeveloped units, from extensive exploration drilling and mine plan

preparation on some units to no activity at all

on others (see ch. 6).

Oklahoma has the largest proportion of

Federal coal leases without mine plans, and

five of the seven Western States have over 30

percent of their leased Federal reserves in

this category (see table 18). Sixty-seven percent of New Mexico’s lease units have no

mine plans, but they cover just 22 percent of

leased reserves.

Table 18.—Leases for Which No Mine Plans

Have Been Submitted

Number Number Recoverable

of of lease reserves

leases units Acres (billions of tons)

241 138 329,522 6.6

Total . . . . . . . . (44%) (57%) (41 %) (40%)

aPercentages are percent of total for each State except percent of total which

is percent of seven State total.

SOURCE: Office of Technology Assessment.
CHAPTER 4

Federal Coal Resources
Contents

Page

Location of Leased Federal Coal Reserves... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Federal Coal Production .... ● .... ● ..... ●✎☛☛✎✎✎ ●✎ ....... . .

Coal Ownership Patterns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Coal Use and Market Areas ..,.,, . . . . . . . . . ...,., ● .... ,,.,.,.,, . . .

Quailty of Federal Coal Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Heat Content ● . .... ● ... ● .. .. ● ... ●

Sulfur and Ash Content ● . . . . . . ● ,. ● ...... ● ...,.*.**, . . . . . . . ● .

Variations in Coal Quality by Region ● .**,*, ● ,..*.., ● *.*.,,. ,0..0.0. ● ****,,, .

Geologic Conditions and Mining Methods ● .,. ● .., .,. ●☛✎✎✎✎☛☛☛ ●

Summary ● ***.**. ..., .******** .*.*.***. ● ***.**** ● *.****.* ...***** *

List of Tables

59

63

65

68

70

70

71

71

73

76

Table No. Page

19.

20.

21.

22.

23.

24.

25.

Distribution of Recoverable Coal Reserves Under Federal Lease and Preference

Right Lease Application by Major Coal Production Region. . . . . . . . . . . . . . . . . . . .

Distribution of Recoverable Coal Reserves Under Federal Lease and Preference

Right Lease Application by State ● **.*, ..,,,,. ,,,...., ● *,***,* ,.,...,, ●

Federal Coal Ownership in Coal Regions and Known Recoverable Coal Resource

Areas in the Six Major Federal Coal States ● ******* ● ***.**** ● *..***** .,.*.,

Uses and Market Areas of Coal From States With Significant Amounts of Leased

Federal Coal .**. ***, o*, .*** ***, **, ,. ,, ,. , ,.,,.,...*,*.,

Classification of Coals by Rank ● .*** ***, *..**,..,.*,,, *

Coal Quality Characteristics of Federal Leases and Major Coalfields With

Federal Leases *,. **** o,. **. ,**, .,e**, ,,. ..** ***. .*0. **ao**. #.*e e,., *

Geologic and Mining Characteristics of Major Federal Coal States . . . . . . . . . . . .

List of Figures

Figure No.

16.

17.

18.

19.

Generalized Coal Provinces of the United States ● .******..********.*.,*.****

Sketch Map Showing Major Coal Regions With Leased Federal Coal, and

Generalized Location of Strippable and Metallurgical Coal Deposits . . . . . . . . . . . .

Coal Production Regions in the United States: Nov. 9,1979.., . . . . . . . . . . . . . . . . .

Annual Coal Production From the Six Major Federal Coal-Producing States in the

west, 1957-70 .. . . ... . **** * * . . * * * * * * * * . . * . * * * ....*..**

Page

63

64

67

69

70

72

74

60

61

62

65
CHAPTER 4

Federal Coal Resources

Coal quality, geologic conditions, mining ●

methods, and end uses of Federal coal are important factors that affect the development of

individual Federal coal leases, and also the ●

general development of coal resources in the

Western United States. The following topics ●

are discussed in this chapter:

● geographic location of Federal surface •

and underground coal reserves under

lease and preference right lease applications (PRLAs) in the major Western coal

regions;

trends in Federal surface and underground coal production in the different

regions;

uses and market areas of coal from the

major Federal coal States;

quality of coal in the Western coal

regions, and characteristics of major

leased coal reserves and coalfields; and

geologic conditions and mining methods —

in the major coal regions that are important in the development of Federal coal

reserves.

Location of Leased Federal Coal Reserves

Leased Federal coal reserves are located

in 14 States and in 5 of the 6 major coal

regions of the United States (fig. 16). However, most Federal coal is located in two coal

regions in the Northern Great Plains coal

province and seven coal regions in the Rocky

Mountain coal province (see fig. 17). * Federal

leases in these two provinces include over 98

percent of the approximately 16.5 billion tons

of recoverable coal presently under lease.

Three-quarters of the leased Federal coal

reserves outside of the Northern Great Plains

and Rocky Mountain coal provinces are contained in 46 leases in Oklahoma, which is geologically part of the Interior coal province.

The remaining reserves (0.4 percent of the

total under lease) are found in 17 leases in

the States of Alaska, Alabama, California,

*A number of different terms are used to describe areas in

which coal deposits are located. Coal provinces cover a large

geographic area where coal deposits have a relatively similar

geologic and physiographic setting. The continental United

States has six major coal provinces (see fig. 16). Coal provinces

are usually divided into geologically distinct coal regions (or

basins, where the geologic structure of the region is in the form

of a basin) which also cover relatively large areas (generally

hundreds of thousands to millions of acres) of coal-bearing

rocks. Coal regions may be further divided into coal fields

which generally cover areas of thousands or tens of thousands

of acres, and identify specific deposits of minable coal, or a

number of coal deposits with a similar geologic setting. Fig. 17

also shows the location and names of the major coal regions

and fields in which Federal coal is leased.

Kentucky, Oregon, Pennsylvania, and Washington. Leases in these seven States were not

analyzed by OTA. Leases in Oklahoma were

evaluated by OTA and some data on this

State is included in this chapter, but Oklahoma is discussed in less detail than the

major Federal coal States of Colorado, Montana, New Mexico, North Dakota, Utah, and

Wyoming.

The United States has several hundred billion tons of recoverable coal reserves, which

are approximately evenly distributed between the Eastern and Western halves of the

country.* These reserves are very large com-

*Various terms are used to describe quantity of coal. Inplace resources (also called the resource or reserve base) include all coal deposits, regardless of depth, thickness, or

economic recoverability. Minable resources represent the portion of the in-place resource that can be mined under present

technology and economic conditions. Recoverable reserves

refer to the amount of coal that can actually be recovered; this

is always less than minable resources because some coal is lost

during mining, and in some cases, some coal may be unavailable because of environmental and regulatory factors. Use of

the term reserves in this chapter is synonymous with recoverable reserves. The demonstrated reserve base in the United

States is estimated to be 475 billion tons (Demonstrated

Reserve Base of Coal in the U.S. on Jan. 1, 1979, EIA, May 1981].

An earlier OTA report has estimated recoverable reserves in

the United States to total 283 billion tons (The Direct Use of

Coal p. 63, OTA-E-86, April 1979). Experts differ in specific

estimates of total recoverable reserves in the United States, but

generally agree that it is on the order of several hundreds of

billion tons or more.

59
60 • An Assessment of Development and Production Potential of Federal Coal Leases

Figure 16.—Generalized Coal Provinces of the United States

\.

“,-.

New \

Vermont \

. . . . - —

, Georgia ‘..

hama -+ . + Atlantic Ocean

.\.\..

Mexico !

SOURCE U S. Bureau of Mines, adapted from USGS Coal Map of the United States, 1960

pared with the 820 million tons of coal produced in the United States in 1980. Slightly

more than half of the recoverable reserves in

terms of tonnage and slightly less than half in

terms of heat content are found in the

West. *

Federal coal leases are located primarily

in six coal production regions in the West:

Fort Union, Powder River, Green River-Hams

Fork, Uinta-Southwest Utah, Denver-Raton

*Coals in the West have generally a lower heat content

than coals in the East (i.e., more coal must be burned to provide

the same amount of energy). About 60 billion tons of underground subbituminous coal in the Powder River Basin of Wyoming and Montana cannot be economically mined now. (F. X.

Murray (cd.), Where We Agree: Report of the National Coal

Policy Project V.2 (Boulder, Colo.: Westview Press, 1978).) If

this coal is subtracted from the reserve totals, the West’s share

of recoverable reserves according to heat content drops to approximately 40 percent of total U.S. reserves (National Research Council, Surface Mining: Soil, Coed and Society,

Washington, D. C.: National Academy Press, 1981).

Mesa, and San Juan River (see fig. 18). These

coal production regions have been delineated

along administrative boundaries of the Bureau of Land Management (BLM) for the purpose of implementing the new Federal coal

management program and do not exactly coincide with geologic coal region boundaries.

For example, the Danforth Hills coal field,

which is geologically part of the Uinta coal region, is located within the Green River-Hams

Fork production region. Also, some areas of

the Uinta-Southwest Utah coal production

region are geologically part of the San Juan

River coal region. Unless coal production

regions are specifically referred to (as in

table 19), discussion in this chapter refers to

geologic coal regions. *

*There are a few Federal leases that are located in coal regions that are not included in the Federal coal production regions. These include two small leases in the Bighorn basin in
Ch. 4—Federal Coal Resources ● 61

Figure 17.—Sketch Map Showing Major Coal

Regions With Leased Federal Coal, and

Generalized Location of Strippable and

Metallurgical Coal Deposits

Coal reserves under Federal lease and

PRLAs are unevenly distributed among the

seven major Federal coal States (see table

20). Wyoming alone contains more than half

(56 percent) of the reserves under lease, and

Utah, the State with the next largest leased

reserves has 20 percent of the total. Wyoming

and Utah together contain more than threequarters of the reserves under Federal lease.

Wyoming also has the largest percentage of

reserves under PRLA (43 percent), followed

by New Mexico (26 percent) and Colorado (18

percent). These three States account for

Hams Fork region nearly 90 percent of the reserves under

PRLA. Most Federal leased reserves are surface minable (1 1.3 billion tons, or 69 percent)

as are most of the reserves under PRLA (3.6

billion tons, or 63 percent). The majority of

leased reserves in Montana, New Mexico,

Utah reglon -

~ Area of coal - Generalized O Major areas of

reserves location of metallurgical

strippable coal

reserves

Numbers show locations of major coal fields

with leased Federal coal:

1. Colstrip 13. Danforth Hils

2. Decker 14. Somerset

3. Buffalo 15. Book Cliffs (CO)

4. Powder River 16. Book Cliffs (UT)

5. Gillette 17. Wasatch Plateau

6. Glenrook 18. Emery

7. Hanna 19. Alton

8. Little Snake River 20. Kapalrowits Plateau

9. Rook Springs 21. Fruitland

10. Kemmerer 22. Bisti

11. Yampa 23. Star Lake

12. North Park 24. Carbondale Coal Basin

SOURCE Base Map National Academy of Sciences, Rehabilitation Potential of

Western Coal Lands (Cambridge, Mass Ballinger Press, 1974)

Continued from p. 60.

north-central Wyoming and one small lease in the Yellowstone

region in southwestern Montana. Very small reserves are involved with these leases so these regions are not discussed in

this chapter.

North Dakota, and Wyoming are surface minable; most of the leased reserves in Colorado,

Utah, and Oklahoma will have to be mined by

underground methods.

Table 19 shows the distribution of Federal

coal reserves under lease and PRLA by coal

production region. The Powder River region

in Montana and Wyoming, contains 59 percent of the leased reserves and the UintaSouthwest Utah production region in Utah

and Colorado contains 25 percent of the

leased Federal reserves. The two regions

combined contain 84 percent of the coal

under lease.

The large amount of leased Federal coal reserves in the Powder River basin reflects the

region’s large reserves in thick flat-lying coal

seams that can be easily surface mined and

the high percentage of Federal coal ownership in the area. The thick seams in the

Powder River basin can be mined at a substantially lower cost than other U.S. coal

deposits. Federal coal leases are concentrated in the Uinta-Southwest Utah region because of its diversity of high-quality coals including metallurgical coal. The region is one

of the oldest active mining areas in the West.

The majority of reserves under lease in the

Uinta-Southwest Utah region must be mined

underground. The Green River-Hams Fork
62 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 18.–Coal Production Regions in the United States: Nov. 9,1979

I Region

m

Note: The boldface print indicates regions or subregions that have been officially designated as Federal Coal ProductIon Regions.

SOURCE: U.S. Department of the Interior, Federal Coal Management Report, Fiseal Year 1979 (Washington, D.C.: U.S. Government Printing Office, 1980).

region of northwestern Colorado and southwestern Wyoming has a fairly even division

between surface and underground minable

reserves.

Of the total Federal reserves covered by

PRLAs, 45 percent are located in the Powder

River basin. The 2.4 billion tons of PRLA

reserves in the Powder River basin include

some 760 million tons that are recoverable

only by underground or in situ methods. Consequently these underground reserves are

unlikely to be developed commercially within

the next 10 years. 1

If these underground

1

J. R. Boulding and D. Pederson Development and Production

Potential of Undeveloped Federal Coal Leases and Preference

PRLA reserves are excluded from the total

reserves under PRLA, the Powder River basin

still contains 35 percent of the total. The San

Juan River region with 28 percent (32 percent

if Powder River underground reserves are

subtracted) and Denver-Raton Mesa region

with 14 percent (or 16 percent) also have

substantial amounts of reserves under PRLA.

Right Lease Applications in the Powder River Basin and Other

Wyoming Coal Basins, final report (Washington, D. C.: Office of

Technology Assessment, 1981). PRLAs must have commercial

quantities of coal to qualify for a lease. It is possible that in situ

gasification may allow development of underground coal in the

Powder River basin, but this technology is still experimental in

nature, and is likely to be so until after 1984, which is the

deadline for processing all PRLAs, Consequently, it is possible

that areas under PRLA that include only underground reserves

may not have leases granted.
Ch. 4—Federal Coal Resources . 63

Table 19.—Distribution of Recoverable Coal Reserves Under Federal Lease and Preference Right Lease

Application by Major Coal Production Region

Recoverable reserves (billions of tons)b

FY79

Coal Preference right Federal coal production

productio n Number of Under lease lease applications (millions of tons)f

. — .

region State Ieases a

Surface Undergroun d

—

Total Surface Undergroun d Total Surface Undergroun d

Fort Union ND 17 0.25 0 0 0 0

M T 3 —.

0.28 0 e o – e 0.7 0

20 0.53 0 0.53 (100%)

(loo%)* (3%)* *

aAS OF SEPT 30, 1979, TOTALS DIFFER FROM TABLE 20 BECAUSE A FEW LEASES IN MONTANA AND WYOMING ARE LOCATED OUTSIDE OF THE

PRODUCTION REGION BOUNDARIES AND BECAUSE A NUMBER OF LEASES WERE LET BETWEEN MID-1979 AND SEPTEMBER 1980.

bSOURCE. Automated Coal Lease Data System, Sept, 30, 1979, pages A-8 and A-14, U.S. Department of the Interior, Federal Coal Managemenf Report, Fiscal Year 1979

(Washington, D.C.: U.S. Government Printing Office, 1980). TOTALS FOR REGIONS ARE SLIGHTLY LESS THAN STATE TOTALS IN TABLE 20 BECAUSE A

FEW LEASES IN MONTANA AND WYOMING ARE LOCATED OUTSIDE OF THE PRODUCTION REGION BOUNDARIES.

cSmall reserves in New Mexico included in Colorado total to protect confidentiality of information.

dSmall reserves in Colorado Included in New Mexico total to protect confidentiality of information.

eSmall reserves in Montana not listed to protect confidentiality of information

f

For fiscal year 1979, from page A-11 in USDI report cited in footnote b. Total is slightly less than in table 16 in ch. 3 because data is for fiscal year rather than calendar

year.

Federal Coal Production

In 1979, 60,1 million tons of Federal coal Montana, North Dakota, New Mexico, Utah,

were mined (and in 1980, 69 million tons), of and Wyoming. Figure 19 shows the trends in

which nearly 99.5 percent was produced in Federal coal production and total coal prothe six major Federal coal States of Colorado, duction from 1957 to 1979 in these six States.
64 . An Assessment of Development and Production Potential of Federal Coal Leases

Table 20.—Distribution of Recoverable Coal Reserves Under Federal Lease and Preference Right Lease

Application by State

New Mexico . . . . . 29 28 0.27 0.06 0.33 0.83 0.67 1.5

(82%) (18%) (2%) (55%) (45%) (26%)

North Dakota . . . . 20 0 0.25 0 0.25 0 0 0

(100% ) (2%)

Oklahoma. . . . . . . 46 4 0.01 0.19 0.2 — —

(6%) (94%) (1%) c c c

Utah. . . . . . . . . . . . 204 25 0.27 3.0 3.3 0.09 0,27 0.36

(8%) (92%) (20%) (26%) (74%) (6%)

● Numbers in parentheses represent percent of total leased reserves in the State.

● ● Numbers in parentheses represent percent of total reserves in all States.

a

lncludes all leases outstanding as of September 30, 1980, Seventeen leases with small reserves in Alaska, Alabama, California, Kentucky, Oregon, Pennsylvania, and

Washington are not included in this table.

bSOURCE: Automated Coal Lease Data System, Sept. 30, 1979, pages A-7 and A-12, U.S. Department of the Interior, Federal Coal Management Report, Fiscal Year

1979 (Washington D.C.: U.S. Government Printing Office, 1960). NOTE THAT TOTALS HERE DIFFER SLIGHTLY FROM RESERVE FIGURES DISCUSSED IN

CH. 3 AND CH. 6. FOR THE PURPOSE OF DISCUSSION IN THIS CHAPTER. THESE DIFFERENCES ARE NOT SIGNIFICANT.

cReserves not shown due to confidentiality requirements.

d

lncludes 315.2 million tons of surface and 15.8 million tong of underground reserves in eight PRLAs in Montana and Oklahoma.

e

There are also four PRLAs in Alaska with 0.1 billion tons of recoverable reserves. See table 10. Extent and Location of PRLAs in ch. 3.

Between 1957 and 1967 total production from

these States ranged between 3.2 and 3.8 percent of total U.S. production, but production

increased dramatically during the 1970’s to

21 percent in 1979 and 24 percent in 1980.

Federal coal production from these States

during this same period ranged between 0.9

and 1.3 percent of total U.S. production and

increased to about 8 percent in 1979 and

1980.

Figure 19 also shows the changes in percentage contribution of Federal coal to total

coal production for these six States. Between

1960 and and 1972 the share of Federal coal

production in the six States declined from

about 40 percent to 20 percent. Since 1973

the percentage of Federal coal production

has shown a general increase, although in

1979, even though total Federal production

was more than eight times higher than in

1970, its percentage share of all production

(36 percent) was less than in 1960. During the

next decade, Federal coal production will

probably increase at a higher rate than nonFederal coal production because of the large

increases from the Powder River region,

where most coal reserves are owned by the

Federal Government.

The current trend in production of Western Federal coal is toward large surface or

underground mines producing more than 1

million tons per year. In Utah and Colorado

where underground mines are common,

small- and medium-sized mines ranging from

200,000 to 1 million tons per year in capacity

still represent a significant and vital share of

active and planned mines. Several mines on

Federal leases in the Powder River basin

have planned capacities exceeding 20 million

tons per year. Annual production from one of

these mines will exceed the individual 1979

total production from Colorado, New Mexico,
Ch. 4—Federal Coal Resources ● 65

Figure 19. —Annual Coal Production From the

Six Major Federal Coal-Producing States

100

80

60

40

20

1955 1960 1965 1970 1975 1980

Year

a

The six States are Colorado, Montana, New Mexico, North Dakota, Utah, and

Wyoming

SOURCE Data for 1957.77 from table 2-7, U.S. Department of Interior, Final

Environmental States Federal Coal Management Progra m

(Washington, D C U S Government Printing Office, 1979) 1978 data

from table A-2, U S Department of In tenor Federal Coal Management

Report Fiscal Year 1979 (Washington, D C U S. Government Printing

Off Ice, 1980) 1979 data from table 16 ch. 3 of this report

North Dakota, or Utah (18.1 million, 15.1 million, 15.0 million and 11.8 million tons, respectively).

The trend toward large mines contrasts

sharply with coal production from the period

1920 to 1960. Most of the leases issued during

this period were to individuals or small mining companies that produced relatively small

amounts of coal for domestic or local industrial consumption. For example, about half

(65 out of 138) of the leases issued before

1960 produced coal at one time, but are no

longer producing coal. Most of the production

from these leases was from small underground mines, and sum total cumulative production from 59 of these leases was less than

a million tons.2 This is less than the annual

production of typical new mines on Federal

leases.

The last two columns in table 19 show the

breakdown between Federal surface and underground coal producton from the different

coal regions. Surface mines accounted for

48.8 million tons, or 83 percent of Federal

production in 1979. Since only 70 percent of

reserves under lease, and 61 percent of reserves under PRLA* are surface minable,

present production is concentrated more

heavily on leases with surface reserves than

underground reserves. Many leases with

large surface reserves in the Powder River

basin were not producing coal in 1979, so the

emphasis on development of surface reserves

will probably continue over the next 10 years

or so. However, full development of existing

reserves will have to rely increasingly on

more costly underground mining methods.

2Data from Automated Coal Lease Data System, Summary of

Federal Leases—Oct. 1, 1979 prepared by the Bureau of Land

Management for OTA, including cumulative production from

each lease, and production in fiscal year 1979. Of the other

leases issued between 1920 and 1960, 38 (27 percent of total)

produced coal in 1979, and 35 (25 percent of total) never produced coal.

*Table 19 shows that only 61 percent of the reserves under

PRLA are surface minable, but if the subbituminous underground reserves in the Powder River basin are subtracted. as

discussed earlier, the percentage changes to 71 percent.

Coal Ownership Patterns

Production from Federal coal leases must passed into non-Federal ownership under a

also be understood in the context of the coal variety of laws and procedures. Under the

ownership patterns that exist in the West. homestead laws passed in the early 1900’s,

From the time of the early settlement of the the Federal Government retained ownership

West until the late 19th century, Federal coal of the coal and other mineral rights in lands
66 ● An Assessment of Development and Production Potential of Federal Coal Leases

patented to settlers. Passage of the Mineral

Leasing Act of 1920 ended the era of disposal

of Federal coal lands and established a leasing system for coal and other fuel and fertilizer minerals on Federal lands. The pattern

of coal ownership in the West has been generally stable since then. * The major categories of non-Federal coal ownership are: Indian, railroad, State, and private (often

called fee coal because the owner holds fee

simple title to the coal).

Sixty percent is a figure that is commonly

cited as the amount of coal resources controlled by the Federal Government in the

West. This figure originates from estimates

made by State BLM offices of Federal coal

ownership in coal-bearing lands (i.e., geologic

formations known to contain coal deposits) in

the major Federal coal States (see table 21)

and probably does not accurately reflect the

percentage of Federal ownership of recoverable coal reserves. This is because: 1) coal

deposits are not evenly distributed throughout areas of coal-bearing rocks, and 2) the

percentage of Federal coal landownership

varies between coal regions.

A closer approximation (but still not entirely accurate, as discussed later) of Federal

ownership of coal resources can be obtained

by looking at the percentage of Federal coal

land ownership in known recoverable coal resource areas (KRCRAs). A KRCRA is an administrative and technical classification established by the U.S. Geological Survey to

designate areas where the location and

amount of minable coal deposits have been

reasonably well-defined by geologic mapping

and coal exploration. KRCRAs must be formally designated by publication in the

Federal Register. Minable coal reserves are

found outside KRCRAs, but generally there is

less information available about the extent of

the reserves and little or no commercial coal

mining in these areas. Table 21 shows that

*Further changes in coal ownership patterns are possible

through exchanges of Federal and non-Federal coal, but the

amounts of coal involved are relatively small compared to total

leased reserves and the overall relationships among categories

of coal ownership are likely to remain much the same. Exchanges are discussed in more detail in ch. 9.

the six major Federal coal States contain

116.7 million acres of coal-bearing lands, but

that only 17.5 million acres (15 percent) had

been included in KRCRAs as of March 1978.

Table 21 also shows that the percentage of

Federal coal acreage varies considerably between States and coal regions. The percentage of Federal coal ownership in KRCRAs

range from a low of 32 percent in North

Dakota to a high of 90 percent in the Colorado

portion of the Uinta region. Other KRCRAs

with a high percentage of Federal coal

ownership are the Wyoming portion of the

Powder River basin (82 percent), the New

Mexico portion of the San Juan region (82 percent) and Utah (85 percent).

Overall, the percentage of Federal coal

ownership in KRCRAs in the six major Federal coal States is higher than the percentage

of Federal ownership in coal-bearing areas

(65 percent v. 52 percent). Furthermore, the

DOI estimates that the Federal Government

owns about 72 percent of the recoverable

coal reserves in KRCRAs because of the high

percentage of Federal coal ownership in the

Powder River basin where coal seams are exceptionally thick. 3 However, Federal ownership of total recoverable coal reserves in the

West is probably lower than this percentage

for several reasons: 1) a number of Indian

tribes control substantial amounts of coal reserves that are not included in KRCRAs* and

2) identification of KRCRAs has tended to

focus on areas of high Federal coal ownership and active coal exploration or leasing interest. Identification of new KRCRAs may

tend to be located in areas where the percentage of Federal coal ownership is lower

(such as the Raton Mesa region). When all

3U.S. Department of Interior, Final Environmental Statement

Federal Coal Management Program (Washington, D. C.: U.S.

Government Printing Office, 1979), p. 2-5.

*Twenty Indian reservations in the West contain coal-bearing rocks and Indians control an estimated 15 percent of the

strippable coal reserves in the United States (Council of Energy

Resource Tribes, The Control and Reclamation of Surface Mining on Indian Lands, Washington, D.C.: CERT, Sept. 30, 1979).

Indian reservations with significant amounts of minable coal

reserves are: Craw and Northern Cheyenne in southeastern

Montana, Fort Berthold in North Dakota, and the Hopi and

Navajo in Arizona and New Mexico.
Ch. 4—Federal Coal Resources ● 67

Table 21 .—Federal Coal Ownership in Coal Regions and Known Recoverable

Coal Resource Areas in the Six Major Federal Coal States

Known recoverable coal

Federal coal Total coal resource areasd

State/coal acreage aacreage Federal coal Total coal

production region (million acres) (million acres) (million acres) (million acres)

North Dakota 5.6(25)b

22.4 0.8(32)e

2.5(11)f

Montana/Fort Union 0.5(44) 1.2

Powder River 1 .7(75) 2.3

Total 24.6(75) 32.8 2.2(64) 3.5(1 1)

Wyoming/Powder River 3.3(82) 4.0

Green River-Hams Fork 1.2(55) 2.2

Total 11 .8(39) 30.5 4.5(73) 6.2(19)

Colorado/Green RiverHams Fork 0.3(68) 0.5

Uinta 0.5(90) 0.6

San Juan 0.2(59) 0.3

Denver-Raton Mesag0.1(20) 0.5

Total 8.7(53) 16.6 1.1(58) 1 .9(11)

Utah/Uinta-Southwest Utah 4.1(82) 5.0 0.9(85) 1 .1(22)

New Mexico/San Juan 1.8(82) 2,3

Raton Mesago 0

Total 5.5(59) 9.4 1.8(82) 2,3(24)

Total (6 States) 60.3(52) 116.7 11.3(65) 17.5(15)

Total all States 92.1 (61)c150.2 — —

a

From table 1-31 US. Department of the Interior, Final Environmental Impact Statement, Proposed Federal coal Leasing program (Washington, DC.: U.S. Government Printing Office, 1975). Figures are based on BLM State Office estimates.

bNumbers in parentheses indicate percent of total coal acreage in the State.

c

This total includes 23.4 million acres (97 percent of total Coal acreage) of Federal coal in Alaska and 0.4 million acres (4 percent of total coal acreage of Federal coal in Oklahoma).

dKnown Recoverable coal Resource Areas defined as of March 1978, A few of these KRCRAs include small amounts Of Indian

coal, but Indian coal within reservation boundaries (which include the majority of Indian coal reserves) IS not included in

KRCRAs.

e

From table 2-5, U.s. Department of the Interior, Final Environmental Statement Federal Coal Management Program

(Washington, D. C.: U.S. Government Printing Office, 1979), Totals may not add because of rounding. Numbers in parentheses Indicate percent of total KRCRA acreage in the State or region. Percentages may not match numbers in table

because of rounding.

fNumbers in parentheses indicate percentage of total coal acreage in the State or region (the second column in table).

gRaton Mesa region did not include any areas designated as a KRCRA as of March 1978,

SOURCE: Office of Technology Assessment.

these factors are taken into consideration,

Federal ownership of total recoverable reserves in the six major Federal coal States is

probably somewhere between 50 percent and

60 percent.

Overall, the landownership patterns in the

West are probably no more complex than

those found in the East and Midwest, however, because Federal, State, and Indian

lands generally cannot be sold, a coal operator cannot gain ownership or control of a

potential mine area through purchase of the

title to surface and mineral rights as he might

in other regions. Consequently, a single mining unit in Western States will often include

coal reserves of several different ownership

categories to allow maximum recovery of the

reserves and Federal and non-Federal coal

reserves are frequently mined as part of the

same operation. * For example in Campbell

County, Wyoming, which has a high percentage of Federal coal, 16 out of 20 lease units

involving Federal leases have non-Federal

coal associated with them, Federal coal is in-

*Mining of coal held by a single owner is often possible and

has been done in areas of mixed ownership, but in some cases

recovery rates are reduced because mining operations cannot

be designed for maximum efficiency.
68 • An Assessment of Development and Production Potential of Federal Coal Leases

terspersed with alternate sections (a section

is a square mile and covers 640 acres) of railroad coal over hundreds of thousands of

acres in the Fort Union region, the Montana

portion of the Powder River region and the

Wyoming portion of the Green River-Hams

Fork region. This situation also exists in

limited areas of the San Juan Basin in New

Mexico. Mining in these areas usually involves both Federal and non-Federal coal. In

parts of North Dakota, on the other hand, current development of lignite reserves is concentrated in areas where relatively small

amounts of Federal coal are interspersed

with State and private coal. The Crow and

Northern Cheyenne tribes in southeastern

Montana own large blocks of surface minable

coal (estimated to exceed 5 billion tons) most

of which can be mined without involving Federal, State, or private coal. About one-third of

the 168 million tons of potential production

capacity from the Montana Powder River

basin involves only Indian coal.4 All the major

coal deposits in Arizona are located on the

Navaho and Hopi Reservations, and all coal

production in the State comes from those

lands. The Navaho tribe also has important

coal reserves in New Mexico. Current production of coal in New Mexico comes from Indian, Federal, State, and private land. Only

one currently operating mine involves mixed

ownership of Indian, Federal, and private

coal.

4

See table 65 of this report. See also tables 6.8, vol. 1 and

A.4.3, vol. 2 of J. R. Boulding and D. Pederson, Development and

Production Potential of Undeveloped Federal Coal Leases and

Preference Right Lease Applications in the Powder River Basin

and Other Wyoming Coal Basins, Final Report (Washington,

D. C.: Office of Technology Assessment, 1981). Note that the

168 million tons per year production capacity cited here is

higher than planned capacity for 1990; the 168 million tons

figure is potential capacity in the post-1990 period. It does not

depend on new leasing of Federal coal, but does depend on a

number of factors including, for example, the building of the

proposed Tongue River Railroad.

Coal Use and Market Areas

Table 22 summarizes current uses and

market areas for coal produced in States with

significant amounts of leased Federal coal.

Possible new markets for Federal coal are

discussed in chapter 5. By far the largest end

use of coal for all States is steam electric generation. In Wyoming, North Dakota, and New

Mexico, over 90 percent of all the coal mined

is used by electric utilities. There is considerable flexibility in the quality of coal that

can be used for new powerplants because a

boiler can be designed to accommodate

almost any coal. Existing powerplants have

less flexibility because use of coal with heat

content and sulfur and ash content significantly different from coal for which the boiler

was designed often reduces its efficiency.

In contrast to the electric utility industry,

the steel industry has much stricter specifications for its coal. Coke, which is made from

metallurgical-grade coal, is used in the production of steel from iron ore. Metallurgicalgrade coal generally requires a low sulfur

and ash content and medium to low content of

volatile matter, as well as other specific physical characteristics. Although low-sulfur and

low-ash coal is found throughout the West,

relatively few coal deposits have the other

characteristics necessary for the production

of coke. Colorado, Utah, New Mexico, and

Oklahoma are the only Western States with

significant commercial deposits of metallurgical-grade coal. Major deposits of highgrade metallurgical coals are found in portions of the Uinta region in Colorado and Utah

and in the Raton Mesa region of Colorado and

New Mexico. Smaller occurrences of metallurgical coal have been found in other areas

of New Mexico and Montana (see fig. 17).

Other major industrial uses of coal in the

West include cement and lime processing,

sugar processing, other metals processing,

and, in Wyoming, processing of the mineral
Ch. 4—Federal Coal Resources ● 69

Table 22.—Uses and Market Areas of Coal From States With Significant Amounts of Leased Federal Coal

Percent use in 1979a Out-of-State market areac

Industrial/ lnState

out-ofUtility commercial Residential State State Non-utility usesb Utility Industrial

Colorado . . . .

Montan a

New Mexico. . .

North Dakota.

Oklahom a

Utah .

Wyoming .

71.5 26.6

96.0 4.0

94.0 6.0

93.4 6 6

79.0 21.0

73.3 24.9

96.3 3.7

1.9 55

11

6 0

d

75

16

1.8 47

22

45

89

40

25

84

53

78

, ., , ,, ., , A CoKe for steel, cememt, sugar

processing, metals processing,

railroad.

Cement, sugar processing.

Cement, metals processing

(copper), drilling mud, coke for

steel (Raton Mesa),

Sugar processing, Ieonardite,

charcoal briquets.

Lime and cement (16% total)

coke for steel (3% total)

Coke for steel (about half nonutility use), cement, metals

processing.

Trona processing, synthetic

coke, cement, sugar

processing.

MW (IL, IN, 1A, MU,

NB), SC (TX, MS),

W (AZ, NM, NV),

MW (IL, IN, 1A, Ml,

MN, Wl), SC (TX).

MW (MO), SC (TX).

MW (SD, MN)

MW. SC

MW (IN, IL, MO, NB),

SC (MS), W (NV,

WA).

MW (IL, IN, 1A, KS,

MO, NB, OH, SD,

Wl), SC (AK, LA, OK,

TX), W (CO).

MW (IN, 1A, Ml, MN, NB, TN,

SD), SC (OK, TX)( W (CA, MT,

NM, NV, OR, UT, WA)

MW (IL, 1A, MN, Wl).

W (AZ, CA, TX)

MW (MN)

MW, SC

NW (IL, 1A), W (AZ, CA, CO,

ID, MT, NV, OR, WA, WY).

MW (IL, 1A, MN, NB, SD,)

SC (OK), W (CO, ID, MT, OR,

UT, WA).

a

percentage breakdown in use categories taken from Office of Technology Assessment State assessment and market survey reports. In-State/out-of-State Percentages calculated from U.S. Department of Energy, Bituminous and Subbituminous Coal and Lignite Distribution, Calendar Year 7979 (Washington, D.C.: U.S.

Government Printing Office, April 1980).

bNon-utility uses compiled from Office of Technology Assessment State assessment and market survey reports, information from the Utah and Wyoming Geological

Surveys and Keystone Coal Industry Manual. cConpiled from DOE report cited In footnote a.

dHalf of coal used in-State is used to generate electricity (about 30 percent of total coal production) that IS exported Out-Of .State

SOURCE: Office of Technology Assessment.

trona. * Like utilities, most industrial users

(other than steel manufacturing) use coal for

heat rather than its physical and chemical

properties. However, industrial users generally do not require large amounts of coal

compared to utilities, so economies in transportation costs through the use of unit-trains

cannot be realized. Because of this, high heat

content is a premium for industrial and commercial users, and it is the coal regions that

produce coal with the highest heat content

(Green River-Hams Fork, Uinta and Oklahoma) that have the widest market areas for

industrial uses of coal.**

*Trona is a mineral that is refined to soda ash, which in turn

is used in the production of glass, woodpulp and paper processing, and manufacture of other chemicals. Southwestern Wyoming contains the only known commercial deposits of trona in

the world (Department of Economic Planning and Development

1975 Wyoming Mineral Yearbook, Cheyenne, Wyo.: DEPAD,

1976).

* *One notable exception to the premium on heat content is

the mining of leonardite in North Dakota, Leonardite is a soft,

earthy coal-like substance that results from the oxidation of lignite. It is a poor fuel (about 4,000 Btu/lb) but is useful as a soil

conditioner, and for various industrial uses such as manufacture of oil well-drilling muds, water treatment and stains for

wood-finishing.

All of the States that produce Federal coal

have either a nearly even division between

coal that is used in-State and out-of-State

(Colorado and Utah) or export most of the

coal that is produced in the State, either as

coal (Montana, Oklahoma, and Wyoming] or

as coal and electricity generated at minemouth plants (New Mexico and North Dakota). Table 22 also shows the current market

areas for coal that is exported out-of-State.

Wyoming has by far the largest market area

of any Western State, with 1979 coal production for utility use going to 14 States and

nonutility use to 13 States. In contrast, North

Dakota has the most limited market area,

because of the low heat content of the coal.

Colorado and Utah are the Western States

that produce significant amounts of coal for

industrial uses (26.6 and 24.9 percent respectively) and the importance of this market is

shown by the fact that coal from Colorado

and Utah was shipped to more States for industrial uses than for utility uses (16 v. 10

States for Colorado, and 11 v. 7 States for

Utah). Chapter 5 discusses the reasons for

the differences in market areas between the

States in more detail.
70 . An Assessment of Development and Production Potential of Federal Coal Leases

Quality of Federal Coal Reserves

User needs related to coal quality have

been discussed briefly in the previous section. Except for metallurgical-grade coal

(where several additional physical and chemical characteristics are important), the primary parameters of coal quality that are of

concern to coal users are: 1) heat content, 2)

sulfur content, and 3) ash content.

Heat Content

The large majority of coal is used for its

energy value, which is usually expressed as

the number of British thermal units (Btu) per

pound of coal. * Coals vary considerably in

heat content, ranging from less than 5,000

Btu/lb for low rank lignites to more than

14,000 Btu/lb for bituminous and anthracite

*A Btu is the quantity of heat required to raise the temperature of 1 lb of water 10 at, or near, its point of maximum density (39.1 0 F).

coals.* (See table 23.) This possible range in

heat content of coal can make a substantial

difference in the amount of coal that is used.

*Coal deposits are classified into 13 different ranks based

primarily on criteria involving heat content, volatile matter

(coal constituents that are easily vaporized), and fixed carbon

(what is left after all volatile constituents have been driven off

when coal is heated in the absence of oxygen). Table 23 shows

the standards for classification of coal by rank that have been

established by the American Society for Testing and Materials

(ASTM). Lignite and subbituminous coal are classified according to heat content calculated on a moist mineral-matter-free

basis. Bituminous coals are classified based on both heat content and percent volatile matter in the coal. High-volatile bituminous coal (greater than 31 percent volatiles) are classified

into three ranks based on heat content. Coal with less than 31

percent volatile matter are classified as low or medium-volatile

coal irrespective of heat content, Anthracites have very low

content of volatile matter (less than 8 percent), Heat contents

reported in this chapter are on an as-received basis, which differ from the heat contents which would be used to rank the coal

using ASTM procedures, because corrections have not been

made to account for ash content (for lower rank coals) or ash

and moisture content (for higher rank coals). The as-received

heat content of a coal sample is lower than the heat content

that is used to classify the sample according to rank.

Table 23.—Classification of Coals by Rank

Fixed carbon

limits, in percent (dry,

mineral-matterfree basis)

Equal or

greater Less

Class Group than than

Volatile matter

limits, in percent (dry,

mineral-matterfree basis)

Equal or

greater Less

than than

Calorific value

limits, in Btu per

pound (moist,

mineral-matterfree basis)a

Equal or

greater Less Agglomerating

than than character

1. Anthracitic . . . . . . . 1.

2.

3.

Il. Bituminous . . . . . . 1.

2.

3.

4.

5.

Ill. Subbituminous , . . 1.

2.

3.

IV. Lignitic . . . . . . . . . 1.

2.

Subbituminous A coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,500 11,500 Nonagglomerating.

Subbituminous B coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,500 10,500 Subbituminous C coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,300 9,500

Lignite A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,300 8,300

Lignite B, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,300

aMoist refers to coal containing Its natural inherent moisture but not including visible water on the surface of the coal.

b

lf agglomerating, classify in low-volatile group of the bituminous class.

cCoals having 69 percent or more fixed carbon on the dry, mineral-matter-free basis shall be classified according to fixed carbon, regardless of calorific value.

d

lt is recognized that there may be nonagglomerating varieties in these groups of the bituminous class, and there are notable exceptions in the high-volatile C

bituminous group.

NOTE: This classification does not include a few coals, principally nonbanded varieties, which have unusual physical and chemical properties and which come within

the limits of fixed carbon or calorific value of the high-volatile bituminous and subbituminous ranks. All these coals either contain less than 48 percent dry,

mineral-matter-free fixed carbon, or have more than 15,500 British thermal units per pound, calculated on the moist, mineral-matter-free basis. Modified from

American Society for Testing and Materials (1974).

SOURCE: P. Averitt Coal Resources of the United States, January 1, 1974 U.S. Geological Survey Bulletin 1412 (Washington, D C.. U.S. Government Printing Off Ice 1975)
Ch. 4—Federal Coal Resources ● 71

For example, a powerplant using lignite may

burn more than twice as much coal as a powerplant using bituminous coal to produce the

same amount of electricity. However, the

most important concern of the user in relation

to heat content is the cost per unit of energy

in the coal (usually expressed as cents or

dollars per million Btu) rather than the heat

content itself. Thus, a low rank coal that has

a lower delivered price per Btu in general

compares favorably with a higher rank coal

at a higher delivered price.

Sulfur and Ash Content

Sulfur content has become an important

aspect of coal quality since passage of the

Clean Air Act of 1970, which established limitations on sulfur dioxide emission from coalfired powerplants. The effect of sulfur emission standards on the demand for Western

coal is discussed in more detail in the following chapter on markets. Ash content may be a

concern to users if its percentage reaches a

level (generally greater than 15 percent)

where ash begins to build up in boilers and

reduce their efficiency. High ash content also

increases the cost of ash disposal after the

coal is burned. Boiler design must also take

into account the physical and chemical properties of the sulfur and ash in the coal that is

used. To some extent, sulfur and ash can be

removed from coal before it is burned, however this process adds to the cost.

Variations in Coal Quality by Region

Coal ranks in the Northern Great Plains

province fall within a fairly narrow range of

lignite and subbituminous coals. In the Rocky

Mountain coal province, on the other hand,

the different coal regions have a considerable

range of coal ranks. The Uinta-Southwest

Utah region has the widest range of coal

ranks, ranging from lignite to anthracite, although current production is entirely bituminous coal. The diversity of coal ranks in the

Rocky Mountain province resulted from the

fact that the processes promoting the formation of coal—heat and pressure—have operated with varying degrees of intensity over

the geologic history of different deposits. The

Northern Great Plains province, on the other

hand, has had a relatively simple geologic history in which coal forming processes have

generally not been very intense.

Table 24 summarizes some of the important coal quality characteristics of leased

Federal coal and major coal fields with Federal leases. The location of these fields is

shown in figure 17. The data shown for the

Fort Union and Powder River regions shows

the range of values for existing leases,

whereas data for other coal regions is for the

whole coal field, which is generally wider

than the range for actual Federal leases in

the field.

All coals in the Fort Union region are lignites, whereas Federal coal reserves under

lease in the Powder River basin are primarily

subbituminous coal. The leased coal in the

Decker and Colstrip areas in Montana have

higher heat contents than leased reserves in

the Wyoming portion of the Powder River

basin, but the Colstrip area also has higher

sulfur contents. Leased reserves in the Wyoming portion of Green River-Hams Fork region are generally higher quality subbituminous coals [greater than 9,000 Btu/lb) and

bituminous coals. Maximum sulfur content is

higher than in the Powder River basin, but

often coal from higher sulfur seams can be

blended with low-sulfur coal to produce coal

with acceptable levels of sulfur.

Major fields with leased Federal coal in

Colorado and Utah contain mostly bituminous

coals, except for the Alton field in southwest

Utah which contains leased reserves of subbituminous coal. Leased reserves in the San

Juan River region in New Mexico are mostly

subbituminous coals with generally higher

heat content than in the Powder River basin.

There are leased Federal reserves of metallurgical-grade coal in the Uinta region in Colorado and Utah and the Raton Mesa region in

Colorado and New Mexico. There are some

reserves of lignite under Federal lease in the

Denver region of Colorado, but total reserves

leased in this area are small and not likely to

be developed in the next 10 years.

84-141 0 - 81 - 6 : 21 ‘?
72 . An Assessment of Development and Production Potential of Federal Coal Leases

Table 24.—Coal Quality Characteristics of Federal Leases and Major Coaifieids With Federai Leases

No. fields Quality characteristics of field/Federal leasesb

No. coal w/leased Coal fields with significant Ash Sulfur Heat content

State Coal region fieldsa

Fed. coal concentrations of Federal leases percent percent (Btu/lb) c

North Dakota Fort Union — — — 5.3-10.0 0.2-1.1 5,460-7,345

Montana Fort Union 26 2 —d 5.7-6.7 0.3-0.5 6,660-6,740

Powder River 36 4 Decker 3.7-22.1 0.3-0.5 9,100-9,650

Colstrip 8.0-10.4 0.75-1.0 8,700-9,000

Wyoming Powder River 12 8 Gillette

{

{4.8-12.6 0.3-0.5 7,500-8,600}

Powder River }

Buffalo 12-30 — 6,500-7,500

Glenrock 8-12 0.4-0.5 7,300-8,000

Green River 8 4 Hanna 4.8-18.3 0.4-1.4 9,400-11,460

Rock Springs 2.8-17.5 0.6-1.2 9,000-13,670

Little Snake River 14.6 1.7 8,000

Hams Fork 4 2 Kemmerer 5.3-7.0 0.4-0.6 8,500-9,600

Colorado Green River 1 1 Yampa

North Park 2 1 —d

Uinta 8 8 Book Cliffs

Danforth Hills

Somerset

San Juan River 4 2 —d

Denver 2 1 — d

Raton Mesa 2 1 —d

3-20

2-19

5-23

2-1o

3-11

3-27

4-45

5-22

0.3-1.8

0.2-1.6

0.4-1.7

0.3-1.4

0.5-0.8

0.5-1.3

0.2-1.1

0.4-1.3

9,800-12,600

6,500-11,300

9,800-13,600

10,100-12,000

10,000-13,500

9,400-14,700

3,600-10,800

10,200-13,900

Utah Uinta 15 3 Book Cliffs 6-7 0.4-1.0 12,500-13,000

Wasatch Plateau 6-7 0.6 12,200-12,700

Emery 9-20 0.5-2.5 11,400-12,300

Southwest Utah 4 2 Alton 9 1.1 9,600

Kaiparowits Plateau 8-14 0.8-1.3 11,200-12,400

New Mexico San Juan River 31 7 Fruitland 12.6-17,4 0.7-1.0 9,800-10,600

Bisti 18.5 0.4-0.9 7,500-10,000

Star Lake 15-20 0.4-0.7 9,400-10,200

Raton Mesa 1 1 Raton 9-14 0.6 14,300

aNumber of coalfields in each region identified from maps in Criteria for Detetmining viable Mining Properties of Exitsing Federal Coal Leases in the Unitedd States,

Final Report prepared by Colorado School of Mines for the Office of Technology Assessment, March 1980, except for Montana which was taken from Montana Energy

Advisory Council, Coal Development Information Packet (Helena, Mont.: Office of the Lieutenant Governor, 1974). bCoal qualirty data for North Dakota, Montana and Wyoming represents range of characteristics of existing developed and undeveloped leases in each region; data for

other States represents range for the whole coalfield. Data Sources: North Dakota, Montana, and Wyoming — Office of Technology Assessment State assessment

reports; Colorado and Utah — Colorado School of Mines Report cited in footnote a; New Mexico — J. W. Shomaker, E. C. Beaumont and F. E. Kottiowski, Strippable

Low-Sulfur Coal Resources of the San Juan Basin in New Mexico and Colorado (Socorro, N. Mex.: New Mexico Bureau of Mines and Mineral Resources, 1971).

cAs-received values.

dOnly small amounts of Federal reserves are under lease in these regions

SOURCE: Office of Technology Assessment.

A notable characteristic of all the Western

coal fields with leased Federal reserves is

their generally low-sulfur content. Only the

Emery field in Utah has a maximum sulfur

content greater than 2 percent. In contrast

sulfur contents exceeding 2 percent are typical in the Midwest and Appalachia, except

for West Virginia, which produces a significant amount of low-sulfur coal. Although

many Western coal fields have coal seams

that exceed 1 percent sulfur, mining is generally concentrated in seams that average

less than this percentage. For example, a recent survey of mine expansions and proposed

new mines by ICF, Inc., found that only 1 mine

will produce coal with more than 1 percent

sulfur5 of 55 mines responding in the Powder

River basin and southern Wyoming. All mines

responding in the Rocky Mountain coal province will produce coal with less than 1 percent sulfur. In contrast, only 6 percent of the

mines surveyed in the Midwest and 25 percent in northern Appalachia will produce

coal with less than 1 percent sulfur. *

‘Percentages calculated from table 11, ICF, Final Report,

Survey of United States Coal Mine Expansion Plans prepared

for the Department of Energy (Washington, D. C,: ICF, Inc.

August 1980). The percentage is calculated for only those

mines for which coal quality information was reported, which

ranged from 71 to 87 percent of all mines included in the survey

for the different regions mentioned in the text,

*It should be noted that differences in sulfur content are

slightly less when they are compared on a uniform Btu basis.
Ch. 4—Federal Coal Resources ● 73

The same ICF mines survey shows that, except for the San Juan River region, ash content is also generally lower in the West than

in the Midwest and Appalachia, although the

differences are less than with sulfur. According to the ICF survey, all new mines and mine

expansions in the Northern Great Plains and

88 percent of the mines in Utah and Colorado

will produce coal with less than 10 percent

ash. In the Midwest 68 percent and in northern Appalachia 65 percent of mine expansions and new mines involve less than 10 percent ash. The San Juan River region in New

Mexico is the only area with leased Federal

coal where ash content seems to be a significant coal quality factor. Eighty-five percent

of the mines in the ICF survey from this area

will produce coal with greater than 10 percent ash and most of these mines will produce

coal that exceeds 14 percent ash. At mines in

the San Juan River region of New Mexico, the

coal is frequently cleaned to reduce ash

before it is burned.

Continued from p. 72.

Because Western coal has generally lower heat content than

coal from Appalachia and the Midwest, its effective sulfur content is higher than a comparison based on percentages would

indicate. Table 12 of the ICF survey cited above compares

mines according to pounds of sulfur per million Btu. In the

Northern Plain, for example, 67 percent of the mines will produce coal with less than 0.83 lb sulfur per million Btu (coal less

than this can comply with the 1970 new source performance

standards with small amounts of sulfur reduction) compared to

30 percent of the mines in northern Appalachia. Western coal

still has a lower sulfur content on the whole than Eastern coal,

but the difference is not as great as sulfur percentage comparisons suggest.

In general, the quality characteristics of

leased Federal coal reserves would not prevent development of the coal, based on user

needs, provided the coal can be sold at a

price that is competitive with coal produced

from other mines or regions. There are a few

exceptions to this generalization. All Federal

leases in the Fort Union region and about 50

million tons per year potential production capacity from Federal reserves under lease and

preference right lease application in the

Wyoming Powder River basin are suitable

only for onsite development because of low

heat content. * Similar constraints for lease

development exist for NERCO’s Cherokee

lease block in the Little Snake River field in

southern Wyoming and several leases in the

Denver region of Colorado.

The demand for metallurgical coal in the

West is expected to remain relatively stable

during the next decade because most coal

currently produced is used at steel plants in

the region. Production of metallurgical coal

could increase slightly to meet expanded

foreign exports. The availability of Federal

and non-Federal coal from the metallurgical

coal areas in the West is expected to meet demand in the foreseeable future.

*Forty-five million tons out of the 50 million tons are unlikely

to be in production by 1991, but could come into production in

the 1990’s.

Geologic Conditions and Mining Methods

The diversity of geologic and topographic

conditions in which coal is found in the West

requires a variety of mining methods. This

section describes the different geologic conditions in the West that affect the choice of mining methods and the ease or difficulty of mining coal. Chapter 11 describes in more detail

the surface and underground mining methods

that are currently used in the West and analyzes the potential for use of more advanced

mining technologies.

Table 25 summarizes data on seam thickness and dip (the inclination of a coal seam

expressed as degrees from the horizontal) in

the major coal regions in which Federal coal

is leased and the dominant mining methods

and common mining problems encountered.

The thickness and dip of a coal seam affect

the ease and cost of mining. In most of these

regions coal seams can be very thick. Two regions, the Powder River and Hams Fork, have

single coal seams that exceed 100 ft. All other
74 . An Assessment of Development and Production Potential of Federal Coal Leases

Table 25.—Geologica and Mining Characteristics of Major Federal Coal States

Coal production Coal

—

Typical

region thickness (ft) seam dip Mining methods Mining problemsb

Fort Union 2-37 (ND) Less than 30 Surface onlyc Highwall stability

(ND, MT) 10-50 (MT)

Powder River 4-80 (MT) Less than 40 Surface onlyc Highwall stability.

(MT, WY) 10-220 (WY) Burned coal.

Green River- 2-40 (CO) 1-15° (CO) Surface and underground in Steep dips create difficulties in Hams Fork

Hams Fork 5-110 (WY) 10-50”, some areas less Green River region; surface only and Hanna areas in Wyoming and subsi-

(WY, CO) than 6° (WY) in Hams Fork region at dence from previous underground mining

present.c

has been a problem in the Rock Springs

area, Wyoming. No serious problems in

Colorado because dips are generally less

steep than in Wyoming.

Uinta-southwest 1-30 (CO) Less than 10” (Uinta) Mostly underground in Uinta Uinta area: some methane, floor and roof

Utah (CO, UT) 3-25 (UT) generally less than 70 but region at present. No present stability, faulting, steep dips (CO), sandUP to 15” (SW Utah). production in southwest Utah, stone dikes (CO), thick overburden (UT and

but both surface and under- CO), variable dips (UT), water (UT, CO),

ground possible. rugged terrain (UT, CO). Southwest Utah:

discontinuous beds, burned coal, undulating roof, water, difficult terrain, splits and

partings in coal.

Raton Mesa 3-10 (CO) Less than 3“ Surface and underground. Colorado: roof stability, igneous sills and

(CO, NM) 6-13 (NM) dikes, some methane. New Mexico: no

serious problems.

San Juan River 1-40 (CO) Generally 2-6” up to 20° Surface and underground in Colorado: rugged topography. New Mex-

(CO, NM) 3-50 (NM) Colorado. Surface only in New ice: steep dips, faulting.

Mexico at present, but underground possible in future.

Oklahoma 1-7 Generally less than 3“ but Surface and underground. Steep dips, methane, abandoned workings,

up to 80° thin seams, undulating beds, faulting.

aData drawn primarily from tabular summary of conventional coal mine development models, western U.S. in Criteria for Determining viable Mining Properties On Existing Federal Coal Leases in the Western United States, Final Report prepared by the Colorado School of Mines for the Office of Technology Assessment, March

1980. Some additional data on coal rank and seam dips comes from Summary Geologic Description of the United States Coal Provinces and Coal Regions, Prepared

from Existing Data, prepared for Office of Technology Assessment by Earth Satellite Corporation, February 1980.

bGeologic and topographic conditions that make the process of mining difficult, as distinct from environmental regulations that may affect the mining process.

Problems listed here do not occur at all mines in a region; individual mines will rarely have more than a few of the problems listed here, and many have none. Mining

problems listed here were identified in Criteria for Determining Viable Mining Properties on Existing Federal Coal Leases m the Western United States, Final Report,

prepared by the Colorado School of Mines for the Office of Technology Assessment, with some supplemental information obtained from the Office of Technology

Assessment State assessment reports.

c

There has been underground mining in the Fort Union, powder River and Hams Fork regions in the past, but such production is not expected In the near future. In the

longer term, in situ gasification may result in the development of underground reserves in the Powder River Basin. Coal in the Hams Fork region has a higher heat content than the Powder River Basin, but steep dips make underground mining difficult, Hydraulic mining, which uses a jet of high-pressure water for cutting coal has

been proposed for this region on an experimental basis. Hydraulic mining has been successfully used In Canada on coal seams with dips 25 to 50” (R. L Raines,

“Underground Mining of Coal” Mining Congress Journal, February 1976, pp. 24-27,

SOURCE: Office of Technology Assessment.

regions have coal seams that range up to 30

to 50 ft, except Oklahoma and the Raton

Mesa.

Thick coal seams are advantageous for surface mining because less overburden must be

removed per ton of coal compared to the thinner coal seams (generally less than 6 ft) that

are mined in the Midwest and Appalachia.

On the other hand, in underground mines recovery of coal reserves is considerably decreased where coal seams exceed 10 or 12 ft

in thickness, although full seam extraction of

coal seams 20 to 30 ft thick is currently

achieved in mines in France and Poland.

However, the high costs of the methods used

to achieve high recovery rates in thick coal

seams has prevented use of these methods in

the United States where underground coal

mines must compete with inexpensive surface mined coal.

Coal seams in the West range from horizontal to vertical, but there are considerable regional differences in the typical dips of coal

seams (see table 25). The Fort Union, Powder

River, Raton Mesa, and San Juan River coal

regions have generally flatlying beds which

are easily surface mined. Difficulties may be

encountered in the Colorado portion of the

Raton Mesa region because of factors other
Ch. 4—Federal Coal Resources ● 75

than dip (see table 25). The Green River and

Southwest Utah regions and the Oklahoma

portion of the Western Interior coal region

are generally characterized by coal seams

that dip less than 70, but some coal leases in

the Rock Springs field in the Green River

region and in Oklahoma have more steeply

dipping beds that can create difficulties for

mining. The Hanna field and the Hams Fork

coal region in Wyoming typically dip more

than 100, The dipping seams in the Hanna

field, located in the northeast part of the

Green River region (see fig. 17) present some

of the most difficult surface mining conditions

in the United States, and special methods of

using draglines to handle overburden have

been developed.

At this time, only surface mining methods

are used to produce coal in the Powder River

and Fort Union regions because thick seams

and low heat content make underground mining economically unfeasible, In-situ gasification in the Powder River region may permit

development of deeper coal beds (more than

500 ft of overburden) in the future. All production at present from the Hams Fork region

in Wyoming and the San Juan River region in

New Mexico is from surface mines, but several operators are planning or considering

underground mining in these areas because

the higher heat content of these coals makes

it economically feasible to do so. Coal in the

Uinta and Raton Mesa regions and the Colorado portion of the San Juan River region is

currently mined by both surface and underground methods, Mining in the Utah portion

of the Uinta region is almost entirely underground, and there is no mining in the Southwest Utah region at this time, although both

surface and underground mining is possible.

Geologic conditions that make mining difficult are also very site specific, but there are

definite regional differences in the extent to

which problems can be expected to occur.

The Fort Union, Powder River, and San Juan

River regions generally have few, or minor

mining problems, although highwall stability

may be a problem locally in the Northern

Great Plains. Steep dips in the Hams Fork Region and the Rock Springs and Hanna fields in

the Green River regions of Wyoming create

difficulties for both surface and underground

mining as mentioned previously. In underground mines a variety of difficulties can be

encountered in the Uinta, Southwest Utah,

Raton Mesa regions and in Oklahoma. The

number and relative importance of underground mining problems varies between

these regions (see table 25) but include: methane hazards, roof and floor instability, dikes

and intrusions in the coal, faulting, steep

dips, thick overburden, variable dips, thin

seams, undulating or discontinuous beds,

splits and partings in coal, water, and burned

coal.

Mining conditions found on Federal leases

include almost the whole range of possible

combinations that make mining easy or difficult. The Gillette field in northeastern Wyoming presents some of the most ideal mining

conditions found anywhere, with thick, flatlying coal seams under shallow overburden.

Underground mining conditions on Federal

leases in western Colorado and central Utah

range from very favorable to very difficult,

Among the most difficult underground mining

problems that are sometimes encountered

are: overburden that exceeds 3,000 ft, seam

dips that approach 350, extreme fracturing

and faulting in both the coal seams and the

confining rock strata, and unstable floor and

roof conditions. Chapter 11 examines in more

detail geologic conditions as they affect

underground mining methods.
76 . An Assessment of Development and Production Potential of Federal Coal Leases

Summary

Leased Federal coal reserves encompass a

wide range of coal types, qualities, and geologic conditions for mining. This section summarizes some of the important points made in

this chapter.

1. Federal coal leases are located in 1 4

States, but the vast majority of leased Federal coal reserves (98 percent) are located

in six Western States: Colorado, Montana,

North Dakota, New Mexico, Utah, and

Wyoming. Coal reserves under lease and

PRLA are very unevenly divided between

these six States. Wyoming has by far the

greatest reserves under lease and PRLA

(56 and 43 percent respectively of total reserves under lease and PRLA in the six

States). Wyoming and Utah together contain more than three-quarters of the reserves under Federal lease, and Wyoming,

New Mexico, and Colorado contain nearly

90 percent of the reserves under PRLA.

Most of the reserves under lease and PRLA

(about 70 percent for both)* can be mined

by surface methods, but a majority of the

leased reserves in Colorado and Utah must

be mined by underground methods.

2. Although the Federal Government owns

approximately 60 percent of the coal reserves in the six major Federal coal States,

production from Federal coal leases between 1957 and 1979 fluctuated between

only 20 and 45 percent of total production.

Since 1973 the quantity and percentage

share of Federal coal production in these

‘Table 19 shows that only 61 percent of the reserves under

PRLA are surface minable, but if the subbituminous underground reserves in the Powder River basin are subtracted, as

discussed earlier, the percentage changes to 71 percent.

3.

States has shown a general increase. However in 1979, even though total Federal

production was more than eight times

higher than in 1970, its percentage share

of all production in the six States was less

than in 1960. During the next decade,

Federal coal production will probably increase at a higher rate than non-Federal

coal production because of the large increases from the Powder River region

where the Federal Government owns a

large percentage of coal reserves.

The quality of coal reserves presently

under lease and PRLA does not appear to

impose any serious limitations for meeting

the demand that is likely for Western coal

over the next 10 to 15 years. Most leased

reserves have low sulfur and ash content

and are suitable for use by utilities, which

constitute the single greatest user of Western coal. All Federal leases in the Fort

Union region and about 50 million tons per

year potential production capacity from

Federal reserves under lease and PRLA in

the Wyoming portion of the Powder River

basin are probably suitable only for onsite

development for power or synfuels plants

because of their low heat content. (However, the majority of Federal reserves

under lease are of sufficiently high quality

to be exported out of the producing State. )

The demand for metallurgical coal in the

West is expected to remain relatively stable during the next decade and even when

possible increases in demand for foreign

export are considered, the availability of

Federal and non-Federal metallurgical coal

in the West appears to be adequate for the

foreseeable future.
CHAPTER 5

Markets and Projected Demand

for Federal Coal
Contents

Page

Factors Affecting the Demand for Coal. . . . . 79

User Needs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

Cost Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

Institutional Constraints. . . . . . . . . . . . . . . . . . 82

Trends in Factors Affecting the Demand for

Western Coal: 1980-90 . . . . . . . . . . . . . . . . . 82

Electrical Growth Rate. . . . . . . . . . . . . . . . . . . . 83

Sulfur Reduction Standards. . . . . . . . . . . . . . . . 85

Mine Costs.... . . . . . . . . . . . . . . . . . . . . . . . . . . 86

Transportation Costs . . . . . . . . . . . . . . . . . . . . . 87

Reclamation Costs . . . . . . . . . . . . . . . . . . . . . . . 88

Royalty Rates and Severance Taxes . . . . . . . . . 88

Industrial Demand . . . . . . . . . . . . . . . . . . . . . . . 89

Synthetic Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . 90

Foreign Export . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Institutional Constraints . . . . . . . . . . . . . . . . . . 93

Factors Affecting Competition Between

Western Coal States. . . . . . . . . . . . . . . . . . . 93

North Dakota... . . . . . . . . . . . . . . . . . . . . . . . . . 93

Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

The Market Area of Western Coal States. . . . 97

Projections of Demand for Western Coal:

1980-90 and 1990-2000. . . . . . . . . . . . . . . . . 99

Production and Demand Forecasts and

Production Goals. . . . . . . . . . . . . . . . . . . . . . . 99

Fort Union Region . . . . . . . . . . .............105

Powder River Basin . . . . . . . . . . . ... ... ... ..105

Southern Wyoming.. . . . . . . . . . . . . . . . . ... ..105

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105

Utah. . . . . . . . . . . . .......................106

New Mexico . . . . . . . . . . ..................107

Comparisons of Forecasts . . . . . . . . .........107

Demand for Western Coal: 1990-2000........108

Summary ● .. ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ 110

List of Tables

Table No, Page

26. Factors Affecting Market Demand for

Western Coal... . . . . . . . . . . . . . . . . . . . . . . 81

27. Comparison of Historical Forecasts of

Annual Growth Rate of Total Electric

Generation. . . . . . . . . . . . . . . . . . . . . . . . . . . 83

28. Representative Mine-Mouth Prices and

Transportation Costs for Western Coal. . . 87

29. Major Market Advantages and

Disadvantages of the Major Federal

Coal-Producing States. . . . . . . . . . . . . . . . . 94

SO. Market Relationships Between the Six

Major Federal Coal-Producing States . . . . . 99

31. Comparison of Demand Projections for

32

33

Major Western Federal Coal Regions

and States With OTA Task Force

Demand Estimates . . . . . . . .. ... ... .., ..103

Demand and Production Forecasts for

Coal for the United States: 1985-2000...,.104

Forecasted Changes in Contribution of

Western Coal to Total U.S. Production, ,..ll0

List of Figures

Figure No. Page

20, Market Areas of the Six Major Federal

Coal-Producing States. ,, ...,... . . . . . . . 98

21. Demand Projections for the Fort Union

and Powder River Coal Regions and

Southern Wyoming, Compared to

OTA Task Force Estimates . . . . . . . .. ....106

22. Demand Projections for Colorado, Utah,

and New Mexico, Compared to OTA

Task Force Estimates. . . . . . . . . . . . . . . . ..107

23. Demand and Production Forecasts for

the United States: 1985-2000 and the

Six Major Federal Coal States: 1985-90....108
CHAPTER 5

Markets and Projected Demand

for Federal Coal

The concentration of Federal coal resources in the West means that the demand

for Federal coal is closely tied to the demand

for Western coal. The demand for Western

coal is determined by the dynamic interaction

of various economic and institutional factors

that affect: I) coal use in the far West, 2) the

competitive position of Western coal in energy demand centers in the Midwest, NorthCentral and South-Central United States with

respect to other coal provinces (the Gulf

Coast and Interior provinces primarily), and

3) the competitive position of Western coal

with respect to competing fuels such as oil,

gas, and uranium.

This chapter first examines in a general

way the factors that affect the overall demand for coal, and then looks a little more

closely at the effect these factors have on the

market situation for Western coal as of 1980.

The impact that likely or possible trends

could have on Western markets through to

1990 are then examined in some detail. Next,

the major market advantages and disadvantages of coal produced from the six major

Federal coal-producing States (North Dakota,

Montana, Wyoming, Colorado, Utah, and

New Mexico)* are summarized with an analysis of the relative competitive position of

coal production from these States in different

regions of the country. Finally, the results of

recent market studies and forecasts of the demand for Western coal in the period 1980 to

1990 are analyzed in relation to demand estimates that were developed by OTA to evaluate potential production from existing Federal coal leases. The chapter concludes with

a general look at the range of possibilities for

demand for Western coal in the context of

total U. S. coal demand between 1980 and

2000.

*Arizona produced almost as much coal in 1979 as New

Mexico, and thus ranks as a major Western coal-producing

State. However, all production in Arizona is from Indian land

and is thus not considered in this chapter.

Factors Affecting the Demand for Coal

The demand for coal is primarily the result

of individual consumers- or users making

choices based on suitable quality and the

price of coal from different regions and,

when other fuels can be substituted for coal,

the price of alternative noncoal energy resources. Although these relative prices may

be significantly affected by “nonmarket” factors, such as Government policy, in this

chapter the term “market demand” refers to

least-cost energy purchasing decisions made

by users, ** “Nonmarket” factors in the form

* * It should be noted that coal quality factors affect purchasing decisions and may result in the purchase of higher cost

coal. For example, higher delivered cost of Western low-sulfur

coal East of the Mississippi compared to local high-sulfur coal

has been accepted by some utilities because retrofitting old

of Government policy can have a significant

impact on the demand for coal, but a distinction can be made between Government policies that: 1) change the institutional context

of the market system and 2) directly stimulate

the demand for coal. Policies in the first

category include most environmental regulations that change the relative cost of using

coal from different regions. The market system itself makes the necessary adjustments to

the new institutional context. Thus, the marplants with stack gas scrubbers was considered too costly and

risky due to uncertainties surrounding the reliability of available scrubbers. However, even in this case the decision to purchase more expensive coal is based on the belief that in the

long run the cost of generating electricity would be cheaper

than the use of less expensive high-sulfur coal.

79
80 . An Assessment 0f Development and Production Potential of Federal Coal Leases

ket demand for coal changes, but shifts in the

level of demand and regional shifts in coal

production are based on least-cost energy

purchasing decisions. Government policies

that directly stimulate demand for coal include Government subsidies for a commercial

coal-based synthetic fuels industry and the

off-gas requirements of the Powerplant and

Industrial Fuel Use Act. * At the present time

Government intervention in the market system to directly increase demand for coal

forms a small percentage of coal use in the

United States. However, if Government subsidies are seen as necessary to develop a

large-scale coal-based synthetic fuels industry, this situation could change.

Table 26 lists some of the major factors

that affect demand for coal. These factors

fall into three broad categories: 1) user

needs, 2) costs (mine mouth, delivered, and

costs of converting into useful energy), and

3) institutional constraints on production.

User Needs

User needs are the primary determinant in

the demand for coal. High levels in the electrical growth rate, high steel production, and

extensive conversion of industrial and electric utility boilers to coal from oil and gas will

all mean an increase in coal demand. High

levels of coal-based synthetic fuels development and high overseas demand for coal will

also increase coal markets. The important

role that coal is expected to play in the U.S.

energy picture is largely the result of the high

cost and less certain availability of oil. Coal’s

main competitors as substitutes for oil and

gas are nuclear power and energy conservation. ** Low levels of energy conservation and

*The off-gas requirements in this act actually have elements

of both kinds of policies: the law requires conversion from gas

to coal even if it is cheaper for the utility to continue with gas

(i.e., least cost energy purchasing decisions are not allowed),

but on the other hand, once the shift is made to coal, the open

market will determine where the utility buys its coal based on a

narrower set of least cost considerations. These requirements

have now been repealed by Congress (see third footnote, next

column),

**If conservation reduces the total level of energy consump

tion which is served by oil and gas, there is less need to substitute other energy sources. Without conservation the demand

for coal as a substitute to oil and gas would be higher, and it is

in this specific sense that conservation is a competitor to coal.

nuclear power growth would contribute to increased demand for coal.

Coal markets are also affected by the extent of substitutability of alternative sources

to meet user needs. Electric utility needs can

be met by oil, gas, uranium, conservation*

and a wide range of coal qualities. For a new

powerplant the primary determinant in utility

choice of fuels is the relative cost of producing electricity. Once a choice has been made

and a powerplant built to meet the specifications of the chosen fuel some substitutions

become impossible (i.e., nuclear to coal) and

most become costly (i.e., oil or gas to coal and

shifts from one coal type to another). On the

other hand, there is little substitutability in

the demand for metallurgical-grade coal.**

Cost Factors

For a coal producer to sell his coal, he must

usually produce it at a price such that delivered cost per Btu to the consumers (mine

plus transportation cost) is lower than the

delivered cost per Btu of coal offered by competing coal producers. If the offered price is

higher, then the coal must be more attractive

to the prospective buyer, either because the

coal quality characteristics are more suitable

for his need, or for some other reason such as

lower costs to produce electricity or greater

assurance of reliable delivery.*** Basic mine

*Conservation in this context refers to utility investments in

activities that reduce total demand or reduce peak demand

(such as time-of-day pricing, load management, insulation loan

programs) because they are cheaper than investments that increase generating capacity. This kind of conservation is different from conservation by electricity users that is purely in

response to increased cost of electricity. The latter form of conservation reduces the amount of electricy a utility needs to produce, but does not fulfill the needs of the utility as a business. **To a limited extent low-sulfur, low-ash coals that do not

have normal coking properties can be blended with metallurgical-grade coal to produce coke, Newly developing technology

for production of “form coke” can take a wide range in rank of

coal, although sulfur and ash content are still important.

***The Powerplant and Industrial Fuel Use Act which mandated conversions to coal from gas in utility and large industrial boilers may result in the choice of coal as a fuel where

cost comparisons would indicate staying with gas. However,

the impact of this law has been reduced by the Omnibus Budget

Reconciliation Act passed by Congress in August 1981 which

repealed the ban on use of natural gas in 1990 in section 301 of

PIFUA, Instead, utilities that use natural gas as a primary fuel

are required to develop conservation plans to reduce current

annual power production attributable to natural gas by 10 percent within 5 years.
Ch. 5—Markets and Projected Demand for Federal Coal ● 81

Table 26.—Factors Affecting Market Demand for Western Coal

Markets increase Markets decrease Current market Current or probable trends

Factor when factor is: when factor is: situation in West (1980-90)

User needs

Utilities

Electrical growth rate

SO, emissions standards

Competing energy sources

Cost of oil & gas

Nuclear power growth

Industrial

Steel production

Industrial boiler conversions

Synthetic fuels development

Foreign export

High (>5%)

1970 NSPS, limits

on total emissions

High

Low

High

High

High

High

Low (<3%)

1979 NSPS or no

emissions limits

Low

High

Low

Low

Low

Low

Low

Current standards

reduce demand compared to 1970 NSPS.

High

Low (in West)

Low

Low

Low

Low

Low - moderate

Amendments to Clean Air Act

could change situation either way.

Higher

Low (in Western coal’s market area)

Low

Low - moderate

Low - moderate

Possible increase

Costsa

Mine (FOB) cost per million Btu

Equipment cost, operation &

maintenance

Labor

Reclamation

Health & safety

Royalty rates

Severance taxes

Overall: b low (Northern

Plains) moderate

(Rockies)

Low High Moderate

Low High Low - moderate

Low High Low

Low High Low - surface mines

High - underground mines

Low Hig h Low - existing leases

High - new leases

Low High Low - high

Delivered cost

Transportation Low High Low (mine-mouth plants)

High (export)

Technologies for clean burning HighdLow Moderate - high

of coal (cost)

Little change

Little change

Little change

Little changec

Little change

Little change

Increases as existing leases come

up for adjustment

Some increase or decrease at State

level is possible

Additional increases likely with rail

deregulation and increased fuel

costs. Possible decreases in some

localities with slurry pipelines

Decreases possible through increased experience and

technological improvements

Institutional constraints at mine Low High Institutional constraints are highly site specific. See chs. 8 and

10 for specific examples.

a

For utilities and industrial boiler users the essential cost factors are delivered price and the cost of technologies for clean burning of coal. For the steel industry cost

comparisons are restricted to coals that have characteristics that are suitable for making coke.

bRelative to the cost of Midwestern coal.

C

Little change in reclamation costs is likely in the West, but proposed amendments to the Surface Mining Control and Reclamation Act that would give States more

flexibility in setting reclamation standards could decrease markets for Western coal because the relatively high reclamation costs in the Midwest resulting from enforcement of the act might be reduced,

dHigh costs for technologies promoting clean burning of coal (coal cleaning, flue gas desulfurization and fluidized bed combustion) favor Western coal because of its

generally low sulfur and ash content. Decreases in costs favor increased use of high sulfur Midwestern coal. Reliability of these technologies IS also an important factor, with low reliability favoring Western coal and high reliability favoring Midwestern coal.

SOURCE: Office of Technology Assessment

costs include the cost of equipment purchase,

operation and maintenance, labor, and the

cost of reclamation and improving health and

safety conditions for miners. Additional costs

may be added as a result of royalties that

must be paid to the owner of the coal and

severance taxes imposed by States in which

the coal is mined. Low costs in all these factors relative to other coal producers improves

the competitive position of a coal deposit.

Heat content can make an important difference in the unit-energy cost of coal. At any

given price, all other things being equal, coal

with a higher heat content is cheaper to use

for a given job than coal with a low heat

content.
82 ● An Assessment of Development and Production Potential of Federal Coal Leases

Coal is a commodity with a low specific

value compared to other commodities, often

costing less than a cent per pound at the mine

and sometimes considerably less. Consequently transportation costs represent a substantial portion of the delivered cost of coal if

the user is a significant distance from the

mine. Low transportation costs relative to

other coal producers increase marketing potential. Transportation costs can bean important limiting factor where coalfields are distant from existing networks that transport

coal. For example, the high cost of building a

coal transportation infrastructure to connect

the coalfields in southwest Utah with existing

networks is an impediment to developing this

area.

Institutional Constraints

In some situations a coal reserve may be

available for development at a cost that is

competitive with coal from other sources, but

the coal cannot be mined because of environmental reasons, labor or equipment shortages, or possibly limited or nonexistent transportation capacity. An example of an environmental threshold that might eventually

delay or possibly limit expansion of coal development appears to exist in North Dakota.

All currently proposed mines in North Dakota

are associated with proposed nearby power

and synthetic fuel plants. Operation of all

currently permitted plants may exceed the

“prevention of significant deterioration” air

quality increments for sulfur dioxide (S02

). If

this is the case, the level of mine development

may be limited as well. (Additional discussion

of this situation can be found in ch. 10. ) Labor

shortages and limits to transportation capacity are usually relatively short-term conditions that can be corrected in the presence of

strong demand for coal from a region. Specific transportation and environmental issues

affecting Western coal development are discussed in more detail in chapters 8 and 10,

respectively.

Institutional constraints are more significant in their impact on production at a specific locality than on the demand for coal in

general, Unless institutional constraints limit

production in a large number of coal-producing regions, demand is met by increased production from regions that do not experience

constraints. Such shifts in production may

result in some cost increases, but unless production is constrained in a number of regions,

causing rapid increases in production of marginal coal reserves that cost more to mine

than existing mines, such cost increases are

not likely to be large. ’ If reasonable environmental and socioeconomic thresholds set

limits on coal production in an area, cost increases resulting in shifts in coal production

to other areas can be considered part of internalizing the environmental and social

costs of mining coal. *

1

The cost impact of such regional shifts in production

depends on both changes in mine mouth cost and transportation cost. ICF has noted that moderate shortfalls in some regions can be compensated for by increased production from

nearby regions which are less constrained and which have adequate reserves of comparable coals available, but that if constraints are widespread, the net costs to society can be high

(ICF, Inc., Analysis and Critique of the Department of Energy’s

August 7, 1980 Report Entitled “Preliminary Nationcd and Regional Coal Production Goals for 1985, 1990 and 1995,

Washington, D. C.: ICF, Inc., October 1980).

*However, it must be recognized that there may be considerable disagreement as to what constitutes a “reasonable” environmental or socioeconomic threshold at a specific location.

Trends in Factors Affecting the Demand for

Western Coal: 1980-90

The last two columns in table 26 give a gen- sible trends in these factors in the period

eral view of the current market situation in from 1980 to 1990. The following text disthe West with respect to the factors affecting cusses only the most salient factors listed on

the demand for coal and identify likely or pos- this table with respect to Western coal.
Ch. 5—Markets and Projected Demand for Federal Coal - 83

Electrical Growth Rate

Electric utilities are by far the most significant user that will be affecting the demand

for Western coal. In 1979 utilities purchased

70 to 96 percent of the coal produced in the

major Western Federal coal-producing States

(see table 22, ch. 4). The electrical growth

rate will probably be the single most important factor affecting demand for coal from

Western States during the next 10 years. The

electrical growth rate in the last few years

has declined significantly compared to rates

following World War II. The average growth

rate of total net generation of electricity from

1945 to 1973 was 7 percent. Average annual

growth since 1973 has slowed substantially

and has averaged less than 2 percent during

the last few years (total U.S. consumption of

electricity in 1979 was 1.9 percent higher

than in 1978 and in 1980 the increase was 1.4

percent).

The decrease in the electrical growth rate

has been largely the result of conservation in

response to increasing costs of electricity,

although the economic situation of the past

few years has been an important factor in recent very low growth rates. This decline in

the electrical growth rate is a major reason

for the decreases in projections for demand

for Western coal over the last few years. For

example, the Department of Energy’s (DOE)

1990 production goals for the western Northern Great Plains (which also includes southern Wyoming) dropped from 529 million tons

in the 1978 forecast to 336 million tons in the

1980 preliminary forecast. Most of this drop

can be attributed to a reduction in the electrical growth rate used in the forecast.

Efforts to project longer-term electricity

growth rates have historically not been very

accurate, but table 27, which compares projected growth rates over the last decade,

show there has been a consistent downward

trend in projected growth for similar time

periods in the future. Table 27 shows that recent electrical growth projections for the

period from 1979 to 1985 range from 2,5 to

4.1 percent. The low projections are higher

than growth rates in the past few years, reflecting a belief that an economic upturn will

Table 27.—Comparison of Historical Forecasts of

Annual Growth Rate of Total Electric Generation

Projected

growt h

Scurce and year of study rate Time period

U.S. Energy Outlook–1971 . . . . . . . . .

Department of the interior—1972 . . . . .

Oak Ridge National Laboratory–1973

Lawrence Livermore Laboratory— 1974

Technical Advisory Committee—1974.

Oak Ridge National Laboratory—1975

Westinghouse—1975. . . . . . . . . . . .

Electrical World—1975 . . . . . . . . . . . .

Exxon Co.—1977 . . . . . . . . . . . . . . . . . .

ElA’s Annual Report to Congress—

1978 ......, . . . . . . . . . . . . . . . . . . . .

CONAES–1978 . . . . . . . ,

National Electric Reliability Council —

July 1980, . .

National Electric Reliability Council —

July 1981 . . . . . . . . . . . . . . . . ...

Department of Energy—August 1980. .

ICF, Inc.—November 1980, .,

ICF, Inc.—November 1980, . . . . . . .

Economic Regulatory Administration

and Energy Information

Administration—December 1980 . . .

1980 actuala 

. . . . . . . . . . ., . . . . . . .

aRate of increase experienced for the first 47 weeks of 1980 over corresponding

period of 1979.

SOURCES:

(percent)

7.2

6.1

4.4

5.6

6.0

5.1

5.0

5.8

4.8

4.7

0.7-3.2

4.1

3.7

3.0

3.5

3.0

2,5

1,4

1971-85

1971-2000

1974-85

1974-85

1974-85

1974-85

1974-85

1975-85

1977-90

1977-85

1975-2010

1979-89

1981-90

1978-85

1979-85

1985-90

1979-85

1980

Forecasts from 1971 to 1978 from table 39, U S Department of Energy, Short Term Energy Outlook, DOE/EIA-0202/2 (Washington,

DC U.S. Government Printing Office, February 1980) Projections

of the Demand and Conservation Panel of the Committee on Nuclear and Alternative Energy Systems as scenario B cited in Science,

Apr. 14, 1978, p. 151

National Electric Reliablilty Council, 1980 Summary of Protected

Peak Demand, Generating Capability and Fossil Fuel Require.

ments for the Regional Reliability Councils of NERC (Princeton,

N. J.: NERC, July 1980), Calculated from table 9 It should be noted

that this is a drop from the 4 4-percent rate projected by the Regional Councils in their April 1980 reports to the U S. Economic

Regulatory Administration,

National Electric Reliability Council, Electric Power Supply and

Demand 1981-1990 (Princeton, N.J.: NERC, July 1981)

Department of Energy, Preliminary National and Regional Coal

Production Goals for 1985, 1990 and 1995 (Washington, D C DOE}

Aug 7, 1980), From table 19

ICF, Inc., Forecasts and Sensitivity Analyses of Western Coal

Product/on, prepared for Rocky Mountain Energy Co (Washington,

D.C.: ICF, Inc., November 1980). From table 3-2, app A

ERA and EIA growth rate taken from table 1, Department of Energy, Proposed Changes to Generating Capacity 1980.89 for the Contiguous United States, DOE/RG-0047 (Washington, D C DOE, December 1980,) The 25 percent was derived by combining the esti.

mates by the Economic Regulatory Administratlon of 21 percent

from 1979 to 1983, and latest estimates by the Energy Information

Administration of 32 percent from 1978 to 1995

increase demand for electricity. The upper

range of 4. I percent projected by the National Electric Reliability Council (NERC) in

July 1980 is considered by a number of observers to be somewhat high. The National

Coal Association (NCA), for example, uses the

NERC electrical growth rate for their high

projection and an electrical growth rate of

3.5 percent for their most likely projection of

U.S. coal production.’ Also the electrical

‘National Coal Association, NCA Long-Term Forecast (Washington, D. C.: NCA, March 198 1).
84 . An Assessment of Development and Production Potential of Federal Coal Leases

growth rate projected by NERC in July 1981

was reduced by 10 percent from their earlier

projection, to 3.7 percent.

There are analysts who expect the electrical growth rate to continue to decline in the

future. For example, the Solar Energy Research Institute (SERI) projects an electrical

growth rate of 0.4 percent annually between

1978 and 2000 if cost-effective efficiency investments are made (excluding investments

in solar).3 According to this study, construction programs already underway could support such an increase in demand over the

next 20 years even if: 1) no plants are brought

on line after 1985, 2) all fossil plants built

before 1961 are retired, and 3) 80 percent of

all oil- and gas-burning generating plants are

retired. The SERI study also concluded that

vigorous onsite solar investments (active and

passive solar space and water heating) combined with extensive development of cogeneration and onsite wind and photovoltaic systems could result in a negative growth rate in

the demand for electricity between now and

the turn of the century.

More important than the overall electrical

growth rate in the United States are the

regional growth rates in the potential market

areas for Western coal. Recent projections by

NERC, NCA, and ICF all assume electrical

growth rates (EGR) in the far West that are

lower than, or near average compared to the

United States as a whole. For the period 1980

to 1990 NERC projects an EGR of 3.8 percent

in the West compared to a national average

of 3.7 percent. ICF projects a slightly lower

rate for the West (2.8 v. 3.0 percent from

1979 to 1990) and NCA projects a significantly lower rate in the West than the national average (2.9 v. 3.5 percent) for the

same time period.4 On the other hand, all

3House Committee on Energy and Commerce, Report on Building a Sustainable Future, prepared by the Solar Energy Research Institute (Washington, D. C.: U.S. Government Printing

Office, April 1981), p, 152,

4

The geographic areas for these projections do not entirely

coincide. The NERC projection is for the Western Systems Coordination Council (calculated from table 19, Electric Power

Supply and Demand 1981-1990 (Princeton, N.].: National Electric Reliability Council, July 1981). The ICF projections cover

approximately the same area as the WSCC but include parts of

Montana and New Mexico that are in other regional reliability

councils (calculated from table 3-2, app. A, Forecasts and Senthree of these sources project higher than

average electrical growth rates in the Midwest and South-Central United States, both

important market areas for Western coal. In

much of this area coal from the Gulf Coast

lignite province and the Midwest compete

with coal from the major Federal coal States.

Another important factor affecting the utility demand for Western coal is the regional

growth rate in coal-fired generation. In some

areas in the United States, such as in the

Midwest, where coal is already meeting most

generation requirements, increases in coal

demand are fairly directly tied to the growth

in demand for electricity. However, in areas

like the South-Central United States where

coal-fired capacity is being added in a system

primarily dependent on more expensive fuel

(i.e., oil or natural gas), demand for coal may

increase through replacement of oil and/or

gas base load generation even if there is no

total generation growth. Regional growth

rates in coal-fired generation between 1980

and 1990 are projected by NERC to be 3.1

percent in the West (WSCC and MARCA regional reliability councils) and 10.0 percent

for the South-Central United States (ERCOT

and SPP reliability councils).* NCA projects

higher growth rates for essentially the same

time period (1979-90) of 5.0 percent in the

West and 13.1 percent in the South-Central

United States.

It is apparent that the electrical growth

rate and conversions from gas to coal in the

South-Central United States will be a major

determinant in the rate of increase in the demand for Western coal. In 1979 the SouthCentral United States consumed 26 percent of

total Western coal production used by utilities. ** NCA projects that 40 percent of the

sitivity Analysis of Western Coal Production, Washington, D, C.:

ICF, Inc., November 1980). The NCA projections include both

the WSCC and the Mid-Continent Area Reliability y Coordination

Agreement (MARCA) which covers the upper Midwest (see

footnote 2 for source).

*ERCOT covers most of Texas and SPP includes north Texas,

eastern New Mexico, Oklahoma, Kansas, Arkansas, Louisiana,

and the western parts of Missouri and Mississippi, See footnote

4 for sources of projections cited in this paragraph.

**Total Western coal production includes production from

the Northern Plains, Rocky Mountain, and Gulf Coast coal

provinces, the western part of the Interior coal province,

Washington State, and Alaska.
Ch. 5—Markets and Projected Demand for Federal Coal ● 85

coal produced in the West in 1990 will be

used in the South-Central region, and NERC

projects that 47 percent of Western coal production for utilities will be used in this area.

The reasons for this projected large increase

are: 1) replacement of gas with coal-fired generation, as originally required by the Powerplant and Industrial Fuel Use Act (PIFUA];

and 2) higher gas prices. Increases in the

availability of natural gas since passage of

PIFUA has decreased some of the pressures

to switch from gas to coal, and there remains

some uncertainty as to how much of a shift

from gas to coal will actually occur in this

region by 1990,

Sulfur Reduction Standards

Before passage of the 1970 Clean Air Act,

sulfur content of coal was not a significant

factor affecting utility coal purchase decisions. The 1970 new source performance

standards (NSPS) for S02 that set a maximum

emission rate of 1.2-lb/million Btu, created a

large market for “compliance” coal (i.e., coal

that could be burned without stack gas scrubbing and meet the 1.2-lb standard). * A significant amount of the increased demand for

Western coal between 1970 and 1979 can be

attributed to the fact that Western coalfields

could produce compliance coal that had a delivered price in the Midwest that was lower

than the delivered price of high-sulfur Midwestern coal when the added cost of scrubbing the high-sulfur coal was factored in.

The 1977 Clean Air Act Amendments,

which required sulfur reduction for all coals

burned by utilities, significantly reduced the

market advantage enjoyed by low-sulfur

Western coal under the 1970 NSPS for SO2

.

The 1979 NSPS for SO2 which apply to new

powerplants, establish a dual standard for

sulfur reduction based on both sulfur content

and maximum allowable emissions of SO2

. **

If 70-percent sulfur reduction will result in an

*This translates into a coal sulfur content of 0.6 lb/million

Btu since that amount of sulfur would convert to 1.2 lb of SO2.

**The final 1979 NSPS were published on June 11, 1979 (44

Federal Register 33613-33624) but apply to all electric utility

steam generating units for which construction commenced

after Sept. 18, 1978.

emission rate of less than 0.6 lb SO2/million

Btu, a higher sulfur reduction is not necessary. All higher sulfur coals must have 90-

percent reduction in sulfur, but emission of

S O2 cannot exceed the 1970 NSPS of 1.2

lb/million Btu.5 For “high” sulfur coal, this

translates into a maximum of 6.0 lb sulfur/million Btu (90-percent reduction of this

amount equals 1.2 lb SO2/million Btu). For low

sulfur coal this translates into a maximum of

1.0 lb sulfur/million Btu (70-percent reduction

of this amount equals 0.6 lb SO2

/million Btu).

Most current production in the West would

qualify for a 70-percent sulfur reduction rate.

The cost of stack gas scrubbing for Western low-sulfur coal is generally lower than for

high-sulfur coal because scrubbing processes

for low-sulfur coal (mostly dry) are cheaper

than wet processes needed for high sulfur

coal. However, this advantage is largely offset by allowances in the present regulations

that give credit for sulfur reduction by precombustion cleaning (i.e., sulfur reduction by

cleaning can reduce the percentage of sulfur

reduction required by stack gas scrubbing).

According to studies by the Bureau of Mines,

mechanical cleaning of coal from northern

Appalachia and the Midwest can result in

average reductions in sulfur of 33 and 23 percent respectively.’ This means that sulfur

reduction by stack gas scrubbing would typically need to range from 57 to 67 percent

5

The 1979 NSPS have been challenged in court on the

grounds that there was irregular ex parte communication during their formulation. The regulations have been upheld in district court and the decision has been appealed by industry, It is

possible that the regulations will be revised as a result of this

litigation. Legislative modifications to sulfur reduction standards are also in early stages of consideration by Congress.

Revisions that would allow a more flexible sliding scale for

sulfur reduction would lessen the adverse impact of the 1979

NSPS on the competitive position of Western coal in Midwestern markets, but not eliminate it. For example, the Mining Task

Force of the National Coal Policy Project concluded before the

1979 NSPS were promulgated that the Clean Air Act Amendments of 1977 (which require utilities to install the best

available control technology on all new plants) would mean

that coal production in the Northern Great Plains was not likely

to increase as much as would happen under the 1970 NSPS.

F. X. Murray (cd.), Where We Agree: Report of the National

Coal Policy Project V.2 (Boulder, Colo,: Westview Press, 1978).

6A. W. Deurbrouck, Sulfur Reduction Potential of Coals in the

United States, Bureau of Mines RI 7633 (Washington, D. C.: U.S.

Government Printing Office, 1972).
86 . An Assessment of Developmenf and Production Potential of Federal Coal Leases

(rather than 90 percent) for Eastern coal compared to 70 percent for low-sulfur Western

coal. Coal cleaning is not generally practiced

on Western coal primarily because of the generally low heat content of these coals that are

used by utilities, and because Western coals

tend to be high in organic sulfur, which is not

amenable to reduction by conventional mechanical cleaning processes.

The 1979 NSPS for S02 have not been in effect long enough to allow full evaluation of

their effect on coal markets, but it appears

that stack gas scrubbing costs for high-sulfur

coal (with credits for sulfur reduction by

cleaning before combustion) and for low-sulfur Western coal will not differ greatly. If this

proves to be the case, it would largely eliminate sulfur content in coal as a key factor in

coal purchasing decisions for new powerplants by electric utilities, although there are

some situations where Western coal may retain a competitive advantage based on sulfur

content. For example, in nonattainment areas

where further development hinges on reducing total emission of S02

, low-sulfur coal may

have an advantage because full (i.e., 90 percent) stack gas scrubbing of low-sulfur coal

emits less total S02 than the same amount of

scrubbing of high-sulfur coal.

In summary, the competitive position of

Western coal varies according to the kind of

limitations that are set on the emission of SO2

.

At one extreme, the absence of restrictions

on S02 emissions would make the delivered

price, rather than the sulfur content of the

coal, the key factor in purchasing decisions.

The 1979 NSPS will probably achieve a similar result. In contrast, the 1970 NSPS gave

low-sulfur Western coal a significant competitive edge, and strict limitations on the

total level of emissions also favor Western

coal.

The full effect of the 1979 NSPS (if they are

not modified) will not be felt until the late

1980’s because a large percentage of new

coal-fired capacity that will come online between 1980 and 1985 was ordered before the

NSPS went into effect.7 The major impacts of

the 1979 NSPS in the next decade will be in

the effect it has on determining which coal

regions will supply those new coal-fired

plants that will be built in the late 1980’s and

that have not signed long-term contracts for

coal.8

Mine Costs

Now that sulfur content will probably be a

less significant factor in the marketing of

Western coal, the single most important competitive advantage retained by Western coal

is its low cost at the mine mouth. Table 28

summarizes recent representative steam coal

contract prices in January and June 1981 for

the major Federal coal-producing States and

ranges of prices within the Midwestern and

Appalachian coal regions. In January 1981,

typical price per ton from the Powder River

basin in Wyoming and Montana ranged from

$6.75 to $12.00/ton, and in the other Western

coal States, for higher Btu coal, from $16.00

to $20.75/ton. In contrast, prices for Midwestern coal range from a low of $17.00 to

$27.501 ton and for Appalachian coal from

$23.00 to $34.50/ton. The actual cost spread

is a little less when these prices are translated into cost per million Btu. For example

the low price for coal in the Midwest of

‘Eighty-three percent (49,200 of the projected 59,400 gigawatts total net capacity) of new coal plants that are planned to

come on line between 1979 and 1985 will be constructed to

meet the 1970 NSPS rather than the 1979 NSPS, and an additional 5,800 gigawatts planned to come on line between 1985

and 1990 will be under the old standards because orders for

boilers were made before the new standards took effect (numbers calculated from tables 3-7 and 3-9, app. A, Forecusts and

Sensitivity Analysis of Western Coal Production, Washington,

D. C.: ICF, Inc., November 1980).

8

It should be noted that the present administration has proposed that the mandatory scrubbing requirements in the 1977

Clean Air Act Amendments be eliminated. However, if the

1979 NSPS are repealed, it is not certain that low-sulfur Western coal would be as attractive to Midwestern utilities as it was

in the 1970’s. For example, a study by Data Resources Inc.

(DRI) has concluded that eastern and Midwestern electric

utilities would continue to favor local high-sulfur coal, even if

the mandatory scrubbing requirements were dropped (Coal

Week, May 18, 1981). The reason for this is that DRI’s projections of rail rate increases for Western coal offset the cost savings from not having to control the SO2 emissions.
Ch. 5—Markets and Projected Demand for federal Coal - 87

Table 28.—Representative Mine-Mouth Prices and Transportation Costs for Western Coal

(January and June 1981)

Contract steam coal price (FOB) Representative rail rates ($/ton)

Kansas

State Btu/lb $/ton $/mm Btu From To: Minneapolis Omaha City Chicago Hammond, IN

Montana . . . . 8,600

9,300

8,100’

1 0,500*

10,700

11,600

11,500

10,000

9,500

to

12,000

11,200

to

13,000

9.75 0.57 Colstrip MT 11 .46a

21.44b

(22.31)

Decker MT —

—

18.69a

(18.26)

—

18.94a

(18.00)

—

12.00 0.65 —

Wyoming. . . . 6.75

(7.00)

16.50

— —

14.24a

(16.29)

Hanna WY — 8.0118.97a

(9.1 1/10.13)

12.43a

(14.30)

Colorado . . . . 17.50 .

(19.00)

0.82

(0.89)

Routt CO — —

20.75

(22.00)

20.50

— — — — —

Utah 30.25b

(31.76)

Utah. . . . . . . .

New Mexico .

Midwest . . . .

—

Appalachia. .

aUnit train rate

bSingle car rate

cPowder River Basin

‘Southern Wyoming

NOTE Number in parentheses Indicates price change from January to June 1981 No parentheses Indicates no change

SOURCE Coal Week. Jan 5, 1981, and June 8, 1981

$17.00/ton is 2.5 times higher than the low

price for Western coal, but on a Btu basis the

spread is reduced to a factor of 1.7. The low

cost of mining Western coal can be attributed

primarily to low production, labor and reclamation costs for both surface and underground mines with coal seams that are thicker than those in the Midwest and Appalachia.

shown here, except from Hanna, Wyo., the

rail transport costs exceed the mine-mouth

cost. The cost advantage of unit train rates is

also clearly shown in this table. From Colstrip, Mont., to Minneapolis, Minn., single car

rates are almost twice unit train rates. The

difference works to the disadvantage of Colorado and Utah where single mines often cannot produce enough to justify commitment of

unit trains. Table 28 also shows that rail

rates are changing at a faster rate than mine

costs in the West. During the first 6 months of

1981 all except one rail rate changed, and

most of the changes involved increases of

$1.00/ton or more. In contrast, most coal

prices in the West remained unchanged during this same period.

There is a general consensus that rail

transportation costs over the next 10 years

are likely to increase at a faster rate than inTransportation Costs

Western coalfields are located far from

the main centers of coal demand in the Midwest and South-Central United States. Consequently, transportation costs are one of the

major market disadvantages experienced by

Western coal and are probably the single

largest overall factor in market decisions concerning Western coal. Table 28 shows some

representative rail rates from points in the

West to the Midwest, In all the examples
88 . An Assessment o/ Development and Production Potentia/ of Federal Coal Leases

flation. 9 Coal slurry pipelines may reduce

transportation costs between certain points,

but there is no consensus as to how significant these cost savings may be, nor is there

much certainty as to the magnitude of real increases that can be expected in rail transport

costs (see ch. 8).10 However, the net effect of

real increases in transportation costs will adversely affect the competitive position of

Western coal with respect to Midwestern

coal because longer distances are involved.

The alternative to shipping coal to centers

of demand is to generate electricity at the

mine mouth and ship the energy by wire.

North Dakota, which is relatively close to

centers of electricity demand in ‘the upper

Midwest, and New Mexico, which is relatively close to centers of demand for electricity in southern California both export significant amounts of electricity by wire. However,

several factors tend to limit the level of minemouth generation to primarily what is needed

within the Western Federal coal-producing

States and adjacent States: 1) long-distance

transmission of electricity is generally expensive because of high capital costs, 2) the

availability of water is less (although use of

dry-cooling towers can reduce some of the

9 Participants in a conference held in Cctober 1980, shortly

after the Staggers Rail Act of 1980 was signed into law

reached the general conclusion that there would be an almost

immediate impact in terms of increased rates for shipping coal

(Coal Week, Oct. 20, 1980). The Department of Energy assumed

a 15-percent real increase in rail transportation costs between

1978 and 1985 in setting its preliminary regional coal production goals. However, ICF has found that between 1978 and

1980 alone real increases (i. e., adjusted to account for inflation) were 10.5 percent, almost as much as DOE’s projected increase over the 7-year period. This underestimation of likely

rail increases resulted in a considerable overestimation of demand for coal from the Powder River basin (ICF, Inc., Analysis

and Critique of the Department of Energy’s August 7, 1980

Report Entitled “Preliminary Notional and RegionalCoal Production coals for 1985, 1990 and 1995” (Washington, D. C.: ICF,

Inc., October 1980). ] In the final production goals, DOE increased assumed escalation of transportation costs to 25 percent. Rocky Mountain Energy Co. projects a 40-percent real increase in rail transportation costs in southern Wyoming between 1980 and 1990 (personal communication, Stephen BergHansen, Wyoming Task Force, Oct. 16, 1980).

‘Wee also Office of Technology Assessment, U.S. Congress,

Coal Slurry Pipelines, Summ(]ry (Washington, D. C,: U.S.

Government Printing Office, September 1980), p. 8, This summary updates an earlier report, A Technolo~y Assessment of

Cool Siurry Pipelines (Washington, D. C.: U.S. Government

Printing Office, March 1978),

problems related to water availability), and

3) the relative environmental and social impacts of large-scale powerplants are greater

in the arid and semiarid West compared to

the Midwest and South-Central United

States. 11 Transportation by wire is discussed

in more detail in chapter 8.

Reclamation Costs

Reclamation requirements under the Surface Mining Control and Reclamation Act of

1977 give Western coal a decided competitive

advantage compared to Eastern coal because

the relative cost increases attributable to the

Act are small in the West compared to the

Midwest and Appalachia. Typical incremental costs with Public Law 95-87 have recently

been estimated to be $5.24/ton in Appalachia,

$1.80/ton in the Midwest and $0.57 ton in the

West. [z The incremental cost differential because of reclamation requirements between

Western and Midwestern coal (a factor of 3)

is more significant than the cost differential

between Appalachian and Western coal (a

factor of 10) because Western and Appalachian coal serve different market areas,

whereas the market areas for Midwestern

and Western coal overlap. Less stringent

reclamation requirements for mining would

probably have the effect of improving the

competitive position of Midwestern coal with

respect to Western coal because cost reductions from less stringent reclamation standards would generally be greater in the

Midwest.

Royalty Rates and Severance Taxes

Royalty rates on coal produced in Western

States were generally very low before the

1970’s reflecting the relatively low value attributed to Western coal reserves. The increased demand for coal in the West in the

1970’s resulted in increases in royalty rates

11See for example discussion on pp. 199-201 in F. X. hlurray

(cd.), Where We Agree: Report of the Natianai Coal Policy Project V,2 (Boulder, Co]o.: Westview Press, 1978).

“National Research Council, Surface Mining Soij, CO(I1 and

Society (Washington, D. C,: Academy Press. 1981). This study’s

analysis of reclamation costs is discussed in more detail in ch.

10.
Ch. 5—Markets and Projected Demand for Federal Coal ● 89

as coal was perceived by both the owners and

potential lessees as having a higher value. Indian tribes and private leaseholders led the

way in exacting higher royalty rates in the

early 1970’s. The 1976 Federal Coal Leasing

Amendments Act (FCLAA) set minimum production royalty rates on surface coal at 121⁄2

percent; a lower royalty rate (currently 8 percent) is permitted for underground coal. Several States followed suit in raising royalty

rates, and new leasing transactions of nonFederal coal generally follow minimum levels

set by the Federal Government.

The overall effect of changing royalty rates

has been to create considerable differentials

in royalties between “old” ‘and “new” leased

coal. Federal leases before 1976 contained

nominal royalties by today’s standards. The

average royalty rate on Federal coal mined in

1977 was 18.8 centslton. Royalty rates at current contract prices at rates set in FCLAA

may be more than 10 times that. The Department of the Interior (DOI) is required to raise

royalty rates when leases come up for adjustment, consequently over the next 10 to 15

years as leases are adjusted, there will exist

a dual royalty standard that could affect the

competitive position of individual Federal

leases with respect to other Federal leases

and non-Federal coal. Without a systematic

analysis of the intraregional and interregional effects of differential royalty rates, it

is difficult to draw conclusions concerning

the impact of these differentials on coal

markets.

Severance taxes* imposed by States also

add to the mine-mouth cost of coal. In the

Western States severance taxes range from

zero in Utah to 30 percent in Montana. A comparison of severance taxes on surface mined

coal in the West shows that cost per million

Btu is roughly the same in Colorado, New

Mexico, North Dakota, and Wyoming (generally 3 to 5 cents/million Btu).13 Severance tax

costs in Montana run three to four times

*See ch. 12 of this report for a description of State coal

severance taxes.

‘ ‘Colorado Energy Research Institute, Mineral Severance

Tuxes in the Western Stutes: A Comparison (Golden, CO1O.:”

CERI, 1979].

higher. Severance taxes and royalty rates

add to the cost of coal, but increases attributable to these sources are relatively

small compared to the cost of mining and

transporting the coal. Consequently, such difference may cause shifts in the location of the

coal production between Western States (as

could be the case in Montana,)* or from

Western coalfields to other coalfields, but do

not have a significant impact on the availability or overall demand for coal.

Industrial Demand

Utah, Colorado, and New Mexico are the

only Western States with significant reserves

of metallurgical coal. In 1979 these three

States supplied only 3 percent of the metallurgical coal that was used by the steel industry although they supplied nearly all of

the metallurgical coal used in the West. The

rest was produced and mostly consumed in

the Midwest and Appalachia. Federal leases

in Oklahoma also contain metallurgical coal,

and demand for Federal coal from this State

hinges strongly on the needs of the steel industry. Even a dramatic increase in the demand for metallurgical coal would not have

much effect on the total demand for Western

coal, given its small share of that market.

Industrial coal burning in California presents a significant source of potential increased demand for coal from Utah, southern

Wyoming, New Mexico, and Colorado, but little realization of this potential is expected

within the next 10 years because of the economic costs of converting boilers from natural gas or oil to coal, combined with the

costs of emission controls. The same is probably generally true of industrial boiler conversion in the Midwest and South-Central

United States where Western coal also experiences competition from Gulf Coast

lignites and Midwestern coal production. Significant increases in demand for coal be-

*The impact of the Montana severance lax is discussed in

more detail in the section on market advantages and disadvantages of Montana coal later in this chapter.
90 . An Assessment of Development and production Potential of Federal Coal Leases

cause of industrial boiler conversions are not

likely to be experienced until after 1990.

1

’

In 1979, 6 percent of total coal production

in the far Western States (including Arizona

and Washington) was for nonmetallurgical

industrial uses, most of which was used for

lime and cement kilns, metals processing, and

sugar processing (table 22, ch. 4). Some increase in demand for coal for such industrial

uses may occur, but dramatic increases are

not likely, thus the major potential source of

increased industrial demand for coal will be

industrial boiler conversions.

Synthetic Fuels

A major disadvantage of coal is that it is

not as convenient to use and transport as oil

and gas, and is not directly substitutable for

use in the transportation sector, which accounted for 25 percent of the total energy use

in the United States in 1979. Synthetic gas

and liquids can be produced from coal, but at

a high cost. Relative costs of oil and gas and

coal-based synthetic fuels are still such that

synthetic fuels cannot currently compete in

the market place, although some large energy

companies may be willing to commit funds to

commercialization of coal-based synthetic

fuels in anticipation of future oil and gas

price rises. Nevertheless, demand for coal to

produce synthetic fuels during the next

decade is likely to depend to a large extent on

Government incentives. Coal-derived liquids

must also compete with oil shale, which produces a synthetic crude oil that can be processed in conventional refineries. At present

the uncertainties in the cost estimates for the

various synthetic liquid fuels are larger than

the estimated difference in the cost of coal

and oil shale derived synthetic liquids.

NCA’s long-term forecast for coal production concludes that coal synfuels production

will fall short of production goals set by the

Federal Government when it created the Synthetic Fuels Corp. NCA estimates that coal

synfuels production is not likely to exceed

14 F. Hachman, Market Factors Associated With the Assessment of the Development Potential of Federal Coal Leases in

Utah, prepared for OTA, 1980.

200,000 barrels per day (bbl/d) of oil equivalent by 1990 in contrast to the goals of

500,000 bbl/d in 1987 and 2 million bbl/d in

1992 established by the Government (of

which two-thirds was to have come from

coal). 15 NCA stated that the goals were unrealistic considering the economic, technical,

environmental, and other regulatory conditions in which synfuels plants must be built.

The current status of coal-based synfuels

projects indicates that most of the demand

for coal for this purpose during the next

decade is likely to be in the Midwest and East

rather than the West. A survey by NCA of existing and proposed coal-based synfuel facilities found that the largest coal synfuel facilities operating in the United States are pilot

plants in Kentucky and Texas, and that the

only large commercial synfuel plant under

construction in 1980 was located in Tennessee.

l6 According to this survey, of the four

large-scale synfuels demonstration plants

that were expected to start construction in

1981, only one, the Great Plains Gasification Associates’ project in North Dakota, was

located in the West. The other three are

located in Kentucky, West Virginia, and

Illinois.

On the other hand, DOE assumed in its

final 1980 coal production goals that 60 percent of the 1990 demand for coal feedstock

for synfuels will be west of the Mississippi,

most of which (45 percent of total demand)

would be from the six major Western Federal

coal States.17 This assumption was based on

two major considerations: 1) the technical superiority of low caking Western coal when

used with first-generation conversion technology and 2) the relative abundance of lowcost strippable Western coal resources. However, the assumed l-million-bbl/d total U.S.

production of coal-based synfuels (20 plants

with a capacity of 50,000 bbl/d oil equivalent

15NCA, NCA Long-Term Forecast, op. cit.

16National Coal Association. Survey of Existing and Proposed

Synthetic Fuel Facilities (Washington, D. C.: NCA, September

1980).

17 U.S. Department of Energy, The Biennial Updute of National

und Regiona~ Coal Production Cmds for 1985, 1990 and 1995

(Washington, DC.: DOE, January 1981).
Ch. 5—Markets and Projected Demand for Federal Coal ● 91

nationwide) exceed other estimates of likely

levels of synfuel production by 1990.

Evaluation of this potential for coal-based

synfuel development in the West by OTA in

the different State assessments generally

agrees with the data in the NCA survey, indicating limited development of Western coal

to support synfuels plants before 1990, The

OTA Wyoming task force judged only one of

the three Federal lease blocks in Wyoming

that are associated with synthetic fuels projects to have favorable production prospects

by 1991 and recent developments have increased the uncertainty that this project will

be online by then.18 The market analyses prepared for the Utah and Colorado task forces

concluded that the use of coal for synfuels in

those States would be minimal by 1991.19 The

New Mexico task force projections assumed

that no commercial-scale synthetic fuel

plants using New Mexico coal would be in

operation by 1990.20

All of the barriers to beginning full-scale

construction of the most advanced commer18J. R. Boulding and D. L. Pederson, Development and Production Potential of Undevelopcd Federal Coal Leases and Preference Right Lease Applications in the Powder River Basin and

other Wyoming Coal Basins, final report (Washington, D. C.:

OTA, 1981). The one block with favorable prospects is the

Rochhelle lease held by Peabody Coat Co., which is committed ta

Panhandle Eastern’s proposed gasification plant near Douglas.

Wyo. This gasification project received a major setback in

August 1981 when Pacific Gas & Electric and Ruhrgas Aktiengesellschaft of West German~’ announced they were withdrawing from their preliminary partnership agreement for the

project. Consequently, it is uncertain whether any synfuel

plants will be producing in the Powder River basin by 1991.

The other two blocks associated with synfuel proposals are

Texaco’s Lake DeSmet block in the western Powder River

basin and Nerco’sCherakee block in southern Wyoming. These

were judged by the Wyoming task force to have uncertain production praspects by 1991, Subsequent analysis by OTA

changed 1991 production prospects for the DeSmet block from

uncertain to unfavorable. Two other proposed synfuel projects

in Wyoming are still in the early stages of development. The

Hampshire project proposed for the eastern Powder River

basin is not associated with a specific source of coal, and a coal

to gasoline plant proposed by Mobil would involve entirely nonFederal coal in the western Powder River basin.

‘<’See Hachman, op. cit.: and J. E. Martin, Market Factors and

Production Contingencies Determining the Present nnd Future

Demand far Colorado COul (Lakewood, Colo.: Colorado Energy

Research Institute, December 1980).

-“The Development Praspects for Federal CoaJ Leases in New

Mexico 1980-1990 (Washington, D. C.: OTA, November 1980].

cial-scale Western synfuel project in the NCA

survey have been overcome. Preconstruction

activities began on the Great Plains Gasification Associates’ coal gasification facility in

Mercer County, N. Dak,, in August 1980. The

first unit of the plant, which would use 4.7

million tons per year of lignite, is scheduled to

be in operation in late 1984. The project had

considerable difficulty in developing a financing plan that was acceptable to the Federal

Energy Regulatory Commission and consumers who would purchase the gas. The original

financing plan was revised in January 1981,

and received approval in May. Citing possible

cost overruns and the need for a separate

pipeline, the project sponsors increased their

loan guarantee request to DOE from $1.8 billion to $2.0 billion. This request was approved by President Reagan in early August

1981.

A study prepared for OTA by the Colorado

School of Mines Research Institute on the

synfuels potential of Western coal concluded

that significant commercial production of

high-Btu gas from coal is unlikely for at least

10 years even with Federal incentives.21

Development activities related to mediumand low-Btu gasification facilities are strongly dependent on the availability of natural

gas. The Institute’s study concluded that the

relative abundance of natural gas, and the

prospects for acquiring additional supplies

from new foreign and domestic sources have

dampened the development of small-scale industrial gasifiers.

This study also concluded that significant

commercial production of coal liquids is unlikely over the next 10 years. Even if substantial Government incentives are offered, commercial production levels are expected to be

less than 100,000 to 200,000 bbl/d of synthetic liquid, primarily because of the leadtimes for construction and the risks associated with first generation plants. Because

of these risks, industry is likely to wait until

processes have been demonstrated on a com21 Colorado School of Mines Research Institute. Synfuels Potential of Western Coal, Draft Report, prepared for OTA, Oct.

31.1980.
92 ● An Assessment of Development and Production Potential of Federal Coal Leases

mercial scale before committing to build a

large synfuels industry. Because commercial

demonstration is not possible until the late

1980’s, 1990 production levels are likely to be

limited to the capacity of the first generation

pioneer plants.

Foreign Export

Japan, Korea, and Taiwan are expecting to

significantly increase their imports of coal

during the next 10 years, and have purchased

coal from several Western States for test

burns. Initial shipments of coal have been

made to Japan from Utah and to Korea from

Colorado. Current capacity of port facilities

to handle coal for foreign export on the west

coast is about 3 million tons, and significant

export of Western coal will require considerable expansion of existing facilities and construction of new facilities to handle coal.

NCA estimates that countries in the Far East

will import from 153 million to 180 million

tons in 1990.22

Potential competitors to the United States

for the coal demand in the Far East are Australia, Canada, China, the Soviet Union, and

South Africa. The NCA range of projected

coal exports for these countries in 1990 is 195

million to 240 million tons, which is well

above the range of import demand in the Far

East (although all export from these countries

is unlikely to go to the Far East). Consequently, the Western coal States will be entering a

competitive market; it is thus difficult to

predict what share of this market the United

States is likely to obtain. Australia has a considerable competitive advantage over coal

produced in the Western United States, but

the Japanese in particular appear to be placing limited coal commitments elsewhere as a

hedge to limit the strength of the Australian

position.23

The Japanese have expressed the greatest

interest in high-Btu bituminous coal with low

ash, moisture, and sulfur content, which

gives the Rocky Mountain coal region a prob-

‘lNCA, NCA Long-Term Forecast, op. cit.

“Hachman, op. cit., pp. 24-25.

able advantage over the Northern Great

Plains. The recent expressions of interest by

the Japanese in Powder River basin coal have

resulted in plans to construct a coal export

facility at Kalama, Wash., that could have an

export capacity of 15 million tons by 1983.

Export of subbituminous coals from the

Powder River basin will probably depend on

the development of slurry pipelines and technology for drying the coal to upgrade its heat

content. A recent analysis of the economics of

export from the west coast did not consider

Powder River coal to have significant export

potential in the near future, primarily because of its lower heat content. 24 The potential for export of Alaskan coal to the Pacific

Rim countries was not examined in this study.

If the Japanese would make firm commitments to purchase significant amounts of

Western coal, port facilities could probably

be constructed to meet the demand for export. However, such firm commitments have

not yet been made, and existing ports that

handle coal on the west coast are reluctant to

expand or construct new facilities until

higher volumes of coal are assured. In the

absence of firm commitment by Asian countries to purchase Western coal, it is very difficult to predict the level of foreign exports of

Western coal by 1990, ICF projects exports

from the west coast to be 2 million tons in

1985 and 14 million tons in 1990.25 The Interagency Coal Export Task Force projects an

upper limit of 15 million tons in 1990 for west

coast export. 26 DOE final production goals

assume that 12 million to 35 million tons of

coal in 1990 will be exported from west coast

ports. 27

NOTE: See also, Office of Technology Assessment, U.S.

Congress, Coal Export and Port Development (Washington,

D. C,: U.S. Government Printing Office, April 1981),

“G. B. McMeans, Jr., The Economic Viability of Proposed

West Coast Coo] Port Sites (Oakland, Calif.: Kaiser Engineers,

Inc., 1981 ). This paper presented at Coal Outlook”s Conference,

Charting the Cuurse of Western Cou], June 8-9, 1981 says “’we

are not optimistic about the export potential of Powder River

Basin subbituminous coals. ”

~~Tab]e 4-2, app. A, ]CF report cited in footnote 4.

“’Interagency Coal Export Task Force, Interim Report,

DOEIFE-0012 (Washington, DC.: U.S. Department of Energy,

January 1981).

‘“Tables 35, 36, and 37 in DOE report cited in footnote 17.
Institutional Constraints

Later chapters on transportation, environmental, and socioeconomic issues examine in

more detail the impacts of various institutional constraints on coal production in the

West. There are some specific instances

where Federal coal reserves under existing

lease cannot be mined because of environmental restrictions, but the total reserves involved in such restrictions are relatively

small. * It does not appear that implementation of environmental policies are likely to

*See ch. 10, espercially table 93 on p. 317.

Ch. 5—Markets and Projected Demand for Federal Coal . 93

pose a significant constraint on the ability of

Western States to produce coal. Infrastructure constraints, such as the ability of communities to expand services to accommodate

population increase because of coal development and the ability of transportation systems to deliver coal to the areas of demand

may cause constraints on a site-specific

basis. However, such constraints do not appear likely to prevent Western coal States

from meeting the possible ranges of demands

that are likely during the next 10 years. (See

ch. 6 for estimates of production from the

Western Federal coal States.)

Factors Affecting Competition Between

Western Coal States

The net result of the various factors and

trends discussed in the previous section is

that conditions favoring rapid increases in

demand for coal from the major Federal coal

States are not as favorable for the 1980’s as

they were in the 1970’s, This does not mean

that there will not be substantial increases in

Western coal production—the low cost of

mining Western coal will ensure that—but it

does mean that the West’s share of coal markets will probably not be as great as has been

commonly anticipated. The major reasons for

this are: 1) reduction in the low sulfur advantage, 2) lower electrical growth rates. and

3) higher transportation costs. Offsetting

these trends somewhat is the likelihood that

the South-Central United States, which is a

major consumer of Western coal, will have a

high growth rate in coal-fired powerplants to

replace gas-fired plants. Nearly 60 percent

(174 million of 301 million tons) of NERC’S

projected new annual demand for utility coal

and lignite from the West between 1979 and

1989 will be consumed in the South-Central

region (ERCOT and SPP regions). Consequently, the overall demand for Western coal will

be highly sensitive to both electrical growth

rates and gas to coal conversions in this region. It is more difficult to evaluate the factors affecting demand for coal in the 1990-

2000 time period, but some discussion of this

can be found later in the Demand for Western

Coal; 1990-2000 section.

This section looks in more detail at the

relative market advantages and disadvantages that coal producers in each of the major

Federal coal-producing States experience

with respect to demand for coal in the West

and in other parts of the United States. These

relative advantages and disadvantages are

summarized in table 29. The next section examines the net effect of these advantages and

disadvantages in the share of total production and geographic market areas of the different States.

North Dakota

In 1979 North Dakota produced 15.0 million tons of lignite, ranking fifth out of the six

major Federal coal States. The key market

disadvantage of North Dakota lignite is its

low heat content and poor handling characteristics for long-distance transport. Lignite

tends to combust spontaneously when exposed to air, and is difficult to unload from

rail cars in winter because moisture in the
94 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 29.—Major Market Advantages and Disadvantages of the Major Federal Coal-Producing States

.

Major market advantages

—

Major market disadvantages —

North Dakota

—Large amounts of surface reserves with easy mining conditions.

—Low mine-mouth cost.

—Availability of water for onsite development.

—Low heat content and tendency of lignite to spontaneously combust when exposed to air restricts markets almost entirely to

mine-mouth development.

—PSD air quality limitations may restrict the level of mine-mouth

development that is possible.

Montanta

—Large amounts of surface minable reserves allow high-volume

long-term contracts.

—Low mine-mouth cost.

—Relatively low sulfur content.

—Higher heat content compared to the Wyoming

Powder River basin,

—Long distance from major coal demand centers in Midwest and

South-Central United States means transportation costs are a

high percentage of delivered cost.

—High severance tax (30%).

—Low heat content compared to Rocky Mountain coal States,

Wyomin g

Powder River basin

—Large amounts of surface minable reserves allow high-volume,

I long-term contracts.

—Very thick coal seams, low strip ratios mean low mine.

mouth costs.

—Low sulfur content.

Southern Wyoming

—Relatively high heat content.

—Moderately extensive reserves of thick multiple seams that can be

surface mined.

—Central geographic location facilities competition in all Western

States except the Southwest.

—Reserves well located with respect to existing rail lines.

Colorado

—Most reserves are high Btu and low sulfur.

—Significant reserves of metallurgical grade coal.

—Central geographic position allows marketing in all

Western States.

—Low heat content compared to Montana and Rocky

Mountain States.

—Long distance to major coal demand centers in the Midwest and

South-Central United States means transportation costs are a

high percentage of delivered cost.

—Availability of water for onsite development IS Iimited.

—Some current and potential future problems with rail capacity for

out-of-State markets.

–Difficult mining conditions (commonly caused by dipping coal

beds) increase cost of both surface and underground mines.

—Long distance from major coal demand centers in the Midwest

and South-Central United States means transportation costs are

a high percentage of delivered cost.

—Majority of reserves must be underground mined, resulting in relatively high mine-mouth costs.

—More distant from demand centers in the west coast than Utah

and New Mexico.

–Transportation costs to demand centers in the Midwest and

South-Central United States are higher compared to Montana and

Wyoming because most production must cross high mountains

and rail routes are not as direct and require more carriers.

Utah

—High-quality reserves (high Btu and low sulfur),

—Significant reserves of metallurgical coal.

—No severance tax.

—Relatively close to coal demand centers on west coast,

–Most production is from underground mines resulting in high

mine-mouth costs.

—Southern Utah fields distant from transportation networks.

—Very far from major demand centers in the Midwest and SouthCentral United States.

—Some reserves in southern Utah are near National Parks.

New Mexico

—Large reserves of medium-Btu (9,500-10,500 Btu/lb) low-sulfur coal

allows high-volume, long-term contracts with utilities.

—High-Btu metallurgical grade coal in Raton Mesa region.

—Closer to coal demand centers in Texas than other Northern

Plains or Rocky Mountain States.

——-— ———

SOURCE Off Ice of Technology Assessment

—Some reserves are not generally well served by transportation

networks.

—Some coal in Raton Mesa region must be underground mined with

higher mining costs.

—High ash content of some coals sometimes requires coal cleaning, thus increasing cost.

-— —
Ch. 5—Markets and Projected Demand for Federal Coal ● 95

lignite freezes. The low heat content limits

coal sales almost entirely to nearby powerplants (or synfuel facilities) in the State with

some export to the adjacent States of South

Dakota and Minnesota. Air quality thresholds, as mentioned previously, are becoming a

factor to consider in the use of North Dakota

lignite reserves in mine-mouth power and

synfuel plants.

The key market advantages of North Dakota lignite are that water is readily available

for onsite development and there are large

reserves of surface minable lignite that can

be mined at a relatively low cost, North

Dakota is also located closer to the electricity

demand centers in the upper Midwest than

other Western States, and reserves are well-

-suited for commercially available gasification

technologies.

Montana

In 1979 Montana produced 32.5 million

tons of coal, ranking second among the six

major Federal coal States. The major market

advantages in Montana are large reserves of

surface minable coal, with generally higher

heat content compared to other Northern

Plains States (but relatively low compared to

the Rocky Mountain States). Four counties in

the Montana portion of the Powder River

basin contain an estimated 32 billion tons of

strippable reserves,28 Mine-mouth costs are

generally half that in the Midwest (see table

28) but transportation costs are high, comprising about one-half to two-thirds the delivered cost in the Midwest. The Crow and

Northern Cheyenne Tribes have large reserves of coal that do not depend on Federal,

State, or private coal to form minable blocks,

Montana has the highest severance tax in

the United States, Between 1970 and 1975

(the year Montana’s severance tax was instituted) growth rates in coal production in

Montana and Wyoming were approximately

the same. Between 1976 and 1979 the growth

28 13R, E. ~~iltsorl an[j J. m’. B]umer, Quofit} ond Heserkrf:s f)~

Stripp{lhlc C(NJI Selmtefi Deposits, Southmlstern Monttln(l, bullelin 91 (Butte, Nlont.: hl(~ntana Bureau of \lines and Cet)l(jgv.

December 1973).

rate in coal production in Wyoming was

almost three times that of Montana (19.3 percent compared to 6.5 ). Several published reports have concluded that Montana’s severance tax has depressed the growth rate of

coal production in the State and point to the

difference in growth rate between Montana

and Wyoming as evidence. 29 However the difference in growth rates between the two

States can also be attributed to other factors

than the severance tax, such as limits on the

availability of rail lines to areas for proposed

new development, and slightly higher production costs before severance taxes are applied

in either State. It is possible that Montana’s

higher severance tax may increase Wyoming’s share of production from the Powder

River basin compared to what it would have

been without differentials in severance

taxes, but no analysis of Montana’s severance tax to date has established a clear relationship between the tax and changes in Montana coal production,30 Whatever its relative

impact in Montana and Wyoming, the severance tax remains a small percentage of the

delivered price of electricity generated from

Powder River basin coal, and despite the high

severance tax planned production capacity in

Montana during the next 10 years is high (see

chs. 6 and 7).

Wyoming

In 1979 Wyoming produced 71,8 million

tons of coal, which was 44 percent of total

coal production from the six major Federal

coal States and more than twice the production from Montana, which was the second

ranked State of the six. This high level of production is the result of favorable conditions in

the State’s coalfields in both the Powder

River basin and southern Wyoming. Wyoming

has very large (23 billion tons) reserves of

surface minable coal in thick coal seams with

low stripping ratios in the Powder River

-“See for example Coal Age, April 1979, p. 39, and House

Committee on Interstate and Foreign Commerce, Coal Sever[lnce Tf].xes, hearing report 96-173 (Washington. D. C.: U.S.

Government Printing Office, 198o).

1“Personal communication, Arnold Silverman, professor (If

Economic Geology a t the Universi tv of Montana, Nlissoula

(phone conversation, Feb. 10, 1981].
96 . An Assessment of Development and Production Potential of Federal Coal Leases

basin, and also moderate reserves (3.2 billion

tons) of medium-Btu coal (9,500 to 10,500

Btu/lb) in southern Wyoming that can be surface mined.31

Coal in the Powder River basin of Wyoming

is cheaper to mine than anywhere else in the

United States. The best coal deposits in the

Powder River basin are also well located with

respect to rail lines, and are likely to be

served by at least one coal slurry pipeline by

the mid or late 1980's. The major disadvantage of coal from the Powder River basin is

that it has a low heat content, and there are

some potential bottlenecks outside of Wyoming in transporting coal by rail to markets to

the East and South. Reserves are sufficient to

support many mine-mouth conversion facilities, but the availability of water for onsite

development, plus other siting problems limits

the likelihood of extensive onsite development

during the next 10 years.

The central geographic position of coalfields in southern Wyoming, combined with

their close location to the Union Pacific

Railroad’s main line, facilitates competition

in States to the East and West. Mining conditions are generally more difficult in southern

Wyoming compared to the northern Great

Plains both because dipping coal seams are

more difficult to mine and also because the

more arid climate creates more difficult conditions for reclaiming mined land. As a consequence, mine-mouth prices are higher, even

when the higher heat content is taken into

account.

Colorado

In 1979 Colorado produced 18.1 million

tons of coal, ranking third among the six

major Federal coal States. The main advantage of Colorado coal is high heat content

and low-sulfur content, reserves of surface

and underground coal that are served by existing transporatation networks, significant

reserves of metallurgical coal, and a central

geographic position that allows marketing in

“Reserve data from table 9, G. B. Glass, Wyoming COu]

Fields, 1978, inf. cir. No. 9 (Laramie, Wyo.: Geological Survev of

WVoming, 1978).

the Southwest as well as the Midwest and

west coast.

One of the major market disadvantages is

that the majority of reserves in the State must

be underground mined, resulting in relatively

high mine-mouth costs. However, surface

mine production will continue to provide at

least half of Colorado’s coal output through

the 1980’s. Transportation costs place Colorado somewhat at a disadvantage in both

Western and Midwestern market areas compared to the other States. Utah is closer to

west coast demand centers, and New Mexico

is closer to both major demand centers in

southern California and in the South-Central

United States. Even though Colorado is closer

to the demand centers in the South-Central

United States than Montana and Wyoming,

transportation costs are relatively higher

because most production must cross high

mountain passes and rail routes are not as

direct. The mountain passes increase transportation costs because steep grades necessitate more engines and fewer cars than typical unit trains. Also, lines owned by two or

three railroads must be traversed to reach

most destinations in the Midwest and SouthCentral United States. Because of these

transportation costs, a significant fraction of

the coal used by utilities in eastern Colorado

comes from Wyoming.

Utah

In 1979 Utah’s coal production was 11.8

million tons. The main advantage of Utah coal

is high heat content of steam coal, reserves of

metallurgical coal, and close location to demand centers on the west coast, The major

disadvantages are that virtually all present

production is from underground mines, and

consequently mine-mouth costs on the average are the highest of any Western State.

Fields in southern Utah have significant surface minable reserves, but are distant from

existing transportation networks. Twentyfour million tons of the Alton field reserves in

southern Utah nearest to Bryce Canyon National Park have been designated by DOI as

unsuitable for mining, Utah is also very far

from coal demand centers in the Midwest and
Ch. 5—Markets and Projected Demand for Federal Coal ● 97

South-Central United States with consequen t

high transportation costs, Nevertheless, Utah

coal, because of its high heat content and low

sulfur content has penetrated these markets

(see fig. 20).

New Mexico

In 1979 New Mexico produced 15.1 million

tons of coal, slightly more than fifth-ranked

North Dakota. The major market advantages

of coal in New Mexico are the presence of

moderate reserves of medium-Btu (9,500 to

10,500 Btu/lb) surface minable coal in the San

Juan River region, sufficient to supply highvolume, long-term contracts with utilities.

The Raton Mesa coal region has high-Btu

coal, but a substantial fraction must be underground mined and thus has a relatively

high mine-mouth cost per ton. New Mexico is

closer to coal demand centers in Texas than

other Western coal-producing States and this

represents a significant potential market that

has as yet been unrealized because some of

the existing coal leases are not well served by

transportation networks. Extensive development of coalfields in the San Juan basin

depends on construction of the Star LakeBisti Railroad. A significant disadvantage of

some New Mexico coal is that some of the

major coal deposits in the San Juan River

region are quite uniformly high in ash content

(generally greater than 14 percent) and

cleaning to reduce ash adds to the cost of

using the coal.

The Market Area of Western Coal States

The share that each Western coal State

has in fulfilling the demand for coal depends

on the extent to which the advantages in the

State outweigh the disadvantages relative to

the other Western States and other coal regions. Figure 20 shows all the States to which

the six major Federal coal-producing States

shipped coal in 1979, The percentage shown

in each State on the map indicates how much

each Federal coal State contributed to tota l

State use of coal. Coal went to every State

west of the Mississippi River and to seven

States east of the Mississippi River. In none of

the States east of the Mississippi River did the

combined contribution of Western coal exceed 37 percent of total coal use, which indicates that Western coal has made substantial inroads into the central market areas of

the Midwest coalfields, but has not achieved

market dominance* over local coal in these

areas. On the other hand, west of the Mississippi River, Western coal contributed more

than half of coal use within all but two States,

showing a clear market dominance over Mid-

*Note that the term “’market dominance”” is used here to

refer to mm] that has a strong cornpeti t ive edge in a certain

market area. The specific meaning of market dominance ;is

used in railroad ra Iemaking is not rneanl.

western coal in these markets. The exceptions are in Texas, where local lignite has the

dominant share of the coal market and in

Missouri.

The relative competitive position of the six

Western coal States can be measured by several indicators: total coal production, the geographic area where coal is sold, and the percentage contribution to total State coal use.

This information is summarized in table 30.

Wyoming’s market dominance compared to

the other five Western States is evident from

the data shown on this table. Wyoming has

the largest level of coal production of any

Western State producing Federal coal. In addition coal from Wyoming was shipped to the

largest market area (22 States) and in 11 of

those States Wyoming contributed the largest

percentage of in-State coal use compared to

the other five States. Furthermore, Wyoming

contributed more than half of total in-State

coal use in eight States, whereas no other

Western State contributed more than this

percentage in more than one State. Wyoming

also shipped coal to all the Western coalproducing States except Arizona and New

Mexico. Wyoming coal’s cost competitiveness
98 . An Assessment of Development and Production Potential of Federal Coal Leases
Ch. 5—Markets and Projected Demand for Federal Coal ● 99

Table 30.—Market Relationships Between the Six Major

Federal Coal-Producing States

1979 Market area Contribution to No. major

production (Excludes the out-of-State usea

synfuels

State (mmt) supplying State) <10% 10-50% >50% proposals

aNumbers in column indicate the number of States coal was shipped to in 1979 in each Category. Data derived from figure 20.

bOnly projects that would produce more than I0,000 bbl/d oil equivalent of synthetic natural gas or Iiquids from coal are included As of January 1981 none of the proposals listed here was at a stage where production of synthetic fuels was certain

Compiled from Colorado School of Mines Research Institute, Synfuels Potential of Western Coals, Draft, Oct 31, 1980,

prepared for Off Ice of Technology Assessment, and a listing of DOE synfuel project awards In Coal Week, Dec. 22, 1980. The

number for Wyoming Includes a feasibility study being conducted by Rocky Mountain Energy Co. for a synfuel plant to

develop a Federal lease in southern Wyoming and a Utah facility, neither of which is listed in either of the previously cited

sources

cNumber in parentheses indicates the number of States where there is market dominance compared to the other five States

(I e., the State supplies the Iargest percentage of in-State coal used comdared to the other five States. but IS not necessarily

the dominant supplier in the State). -

SOURCE Office of Technology Assessment

compared to Colorado coal along the Front

Range urban corridor in Colorado, arising

from transportation factors, is shown by the

fact that Wyoming contributed almost onequarter of Colorado’s total coal use in 1979.

Montana is the State with the next greatest

competitive advantage, as measured by total

coal production. In 1979 Montana produced

almost twice as much coal as Colorado, the

next largest coal producer. However, it is apparent that market dominance in terms of

magnitude of coal production is not necessarily accompanied by dominance in terms of

geographic market area, as can be seen in the

cases of Colorado and Utah. Both States

ranked below Montana based on coal production, but both Colorado and Utah have very

large geographic market areas compared to

Montana, North Dakota, and New Mexico. In

fact, Colorado shipped coal to as many States

as Wyoming. However in only a few States

did Colorado or Utah contribute the highest

percentage of total State coal use, and in a

large majority coal shipments represented

less than 10 percent of total coal use.

The main reason magnitude of coal production and the size of market area do not always

coincide is that utilities use much larger

volumes of coal than industrial users. The low

cost of surface mined coal in the Powder

River basin, along with large blocks of reserves that can sustain high production rates

for long-term utility contracts have been the

key factors in the market dominance (in terms

of magnitude of coal production) enjoyed by

Wyoming and Montana. The high quality of

coal in Colorado and Utah (high heat content

and availability of metallurgical coal) allows

a large geographic market area through sale

to industrial users, spot market utility sales,

and sale for blending with high-sulfur Midwestern coal. However, the high cost of producing and transporting this coal has significantly limited total production compared to

Montana and Wyoming. New Mexico is perhaps the only Western State in which the

relationships described here may change significantly during the next 10 years. At the

present time New Mexico does not export significant amounts of coal out-of-State. However, Texas represents a significant potential

market that could possibly use 20 million tons

of New Mexico coal by 1990. *

Table 30 also lists the number of largescale synthetic fuel plants that are in active

planning stages in each State. All of these

projects, except one in North Dakota, are still

in early planning stages, and there is no cer-

*The OTA New Mexico Task Force estimated that 20 million

tons or more of coal would he shipped to Texas markets in

199o. This seems to be optimistic (see discussion of forecasts of

demand for New Mexico coal later in this chapter).
100 . An Assessment of Developrnent and Production Potential of Federal Coal Leases

tainty whether, or when, they will be constructed. North Dakota has a large number of

possible plants because the reserves are well-

-suited for conversion to synthetic gas, and

water needed for cooling and conversion

processes is more readily available than in

other Western coal States. Wyoming has a

large number of proposed projects due primarily to the availability of reserves in both

the Powder River basin and southern Wyoming to support such facilities, but availability of water is more of a problem than in

North Dakota. Projects in the active planning

stage in the remaining four States range from

one each in Colorado, New Mexico, and Utah

to two in Montana.

The discussion of synthetic fuels earlier in

this chapter indicated that significant levels

of coal production for synthetic fuels were

unlikely before 1990. The capacity in 1990 of

the only two projects that were judged by

OTA to have a good chance of being in operation before 1990 (the Great Plains Gasification Project in North Dakota and Panhandle

Eastern’s proposed gasification project in

northeastern Wyoming) is 12 million tons, but

it is uncertain whether either would be producing at full capacity by 1990.32 Levels of

coal production for synthetic fuels could

become significant after 1990. Coal consumption of currently proposed commercial-scale

synthetic fuel plants that would use coal from

the major Federal coal States would be 95

million tons per year at full capacity. Attainment of full capacity might be reached in the

mid to late 1990’s.

‘- Boulding and Pederson, op. cil.

“Calculated from tables VI-2 and VI-3, NCA. NCA L(mg-Term

F(jrecust, op. cit.

Projections of Demand for Western Coal:

1980-90 and 1990=2000

There is no way to predict with certainty

the demand for coal from the major Federal

coal States over the next 10 years, but it is

possible to estimate demand. Numerous estimates (usually called forecasts or projections) concerning demand for coal from the

West have been made for the 1985-90 period

that was the focus of OTA’s analysis of existing Federal leases.

Production and Demand Forecasts and

Production Goals

Coal forecasts fall into two major categories: 1) production projections that are based

on production commitments under existing

contracts and potential production based on

industry plans to open new mines and expand

production at existing mines, and 2) demand

projections based on computer models that

assume certain conditions in coal markets

and allocate coal production to different coal

regions based on varying assumptions about

factors such as mining and transportation

costs and electrical growth rates. Production

forecasts are most useful for evaluating

changes in coal production over the short

term (up to 5 years or so in the future)

whereas demand forecasts are most useful

for evaluating intermediate and long time

periods (greater than 5 years). Each approach has its own advantages and limitations.

Production Forecasts

These forecasts are more directly related

to the “real” world because they are based

on contractual commitments and specific industry plans. Production forecasts based on

industry plans for new mine openings and

mine expansions are frequently high because

such plans are based on individual company

expectations of the share of market demand

they will be able to capture. Some of the expected market share may be captured by

other competitors and consequently actual

production may be less than production

based on industry plans. Also, coal contracts

usually specify a range of possible delivery
Ch. 5—Markets and Projected Demand for Federal Coal - 101

rates. If electric utilities need less than the

maximum amount contracted for, then forecasts based on contracts will overstate production. For example, in the Powder River

basin of Wyoming, deliveries to utilities in

1979 and 1980 averaged about 5 percent

lower than would be expected based on contractual commitments. ” Production forecasts

can change quite rapidly in response to

changed perceptions by the coal industry of

likely demand. For example the projected

capacity for coal mines in Carbon, Sevier,

Wayne, and Emery counties in Utah for the

year 1985 dropped from 45.2 million tons in a

1977 survey to 26.5 million tons in a 1979

survey .3’ One value of production forecasts is

that they can serve as an indicator of the

capacity of the coal industry to respond to

changes in demand.

Demand Forecasts

Based on computer models, these forecasts

are not very reliable for making point forecasts for a single year because small errors

in assumptions used in making the forecast

can result in large differences in projected

amounts. On the other hand, computer models are very useful in evaluating the sensitivity of demand for coal to changes in conditions such as the electrical growth rate and in

identifying possible ranges in demand in

response to different conditions. The range of

possible demands generated by computer

models using different assumptions can be so

great that ultimately identification of a “most

likely” range of demands must be based on

human judgments by individuals knowledgeable about current coal market conditions

and an understanding of the impact that existing trends and possible changes in these

trends will have on future demand. Evaluation of forecasts from a number of different

sources allows the development of a range of

“most likely” demands in which a higher

degree of confidence can be placed than the

“Personal communication with Gary Glass, Geological Survey of Wyoming, September 1981.

“The 1977 and 1979 Keystone Coal Surveys reported in Coal

Age, February 1978; and Coal Age, February 1980, respectively.

range of possible demands that may be generated by a single computer model.

An important element in OTA’s evaluation

of the production potential from existing

Federal coal leases was to identify a most

likely range of demands for coal from the

major Western coal regions and States with

Federal leases. This identification of probable ranges in demand generally involved a

four step process: 1) review of existing projections from different sources, 2) development of independent projections by OTA

based on evaluation of market conditions in

the specific regions or States of interest, 3)

development of estimates by OTA State task

forces based on review of projections identified in steps 1 and 2 and/or the development

of new estimates representing the collective

judgment of task force members, and 4) further evaluation and modification of task force

estimates by OTA to identify a range of demands which could be compared to other estimates of production potential from existing

Federal leases. *

Production Goals

OTA also paid particular attention to two

sets of forecasts that became available after

most of OTA’s task force meetings had been

completed: 1) the August 1980 preliminary

coal production goals and the January 1981

final production goals developed from DOE’s

National Coal Model36 and 2) refinements to

the National Coal Model forecasts developed

by ICF, Inc., using its Coal Electric Utility

Model. 37 DOE’s final production goals were

...——

*Special market analyses were prepared for OTAA on the

Powder River basin and southern \\’yoming, Utah, and Colorado. The Utah, Wyoming. Colorado, and New Mexico task

forces each discussed various ranges of likely demand in the

years 1985 and 1990 ([he bases for these pr[)j(:(t]ons ,] re surlma rized in footnotes in table 31 ]. In most instances () I’A mt Nil.

fied Ihe ranges discussed by the task forces to in(lude ;I wider

range for purposes of a na] yzing pro(iuc! ion pllten I i,]] from exist in~ Federal leases,

‘ll+-eJirnin(~ry Nfjtionrd and ~e~ion[li CCJ(I/ F’r(j{iu((i{)n (;~MIls

for 198s, I!)!)(), (ln(i IWS (Washington, 1).(; .: 1)OE, Aug. 7, 19w)]:

and The 1980 Bienniuf Updo te t)f N(1 tion(ll Region(]l C(MII Pr(Niuc

lion Go(lIs for 198,5. 1990, (]nd 1995 IWashington, 1). (~.: I) OF,

January 1981.)

‘“The ICF forecasts are reported in An[l~\’sJ+ (in(~ (;rit)(~ue of

the I)epnrtment {)f Enprgv’s Augu\t 7, I !]80 Heport en li(lf~[i ‘‘Pre-
102 - An Assessment of Development and Production Potential of Federal Coal Leases

increased substantially over the preliminary

goals (see tables 31 and 32). The final national goals average 16.6, 15.7, and 26.0 percent higher than the preliminary goals for the

years 1985, 1990, and 1995 respectively. The

final

very

(see

final

tons

than

DOE goal for 1985 (1.118 million tons) is

close to both the ICF and NCA forecasts

table 32), but the 1990 and 1995 DOE

goals (1,620 million and 2,214 million

respectively) are considerably higher

recent Projections from other sources

for the same time periods. The 1990 DOE

final goal is almost 300 million tons higher

than the highest recent forecast shown in

table 32 and the 1995 DOE final goal is almost

as high as the high “likely” projection for

2000 shown on table 32.

The reason for the increases from the preliminary to the final DOE production goals appear to be primarily a clearer conceptual

definition of the relationship between coal

production goals and other coal production

forecasts. As the report on the DOE final

goals says:

The goals developed here are based on national energy needs, existing and emerging

national and international policies and laws

Continued from p. 101

liminuryAIotionul ond Ilegion(d f.lxJl Production Gools for 1985.

1990 ond 1995 (Washington D. C.: ICF, Inc., October 1980). ICF

originally developed the National Coal Model that is used by

DOE 10 develop production goals., and has since refined this

model into the Coal Electric Utility Llodel (CEUM). ICF’S critique of the DOE preliminary goals identified a number of

structural deficiencies in the model, and deficiencies in data

and assumptions used in the mode]. Examples of structural

deficiencies include such things as coal production and demand regions not coinciding with DOI coal production regions

necessitating often arbilrary allocation of model outputs between regions, and distortion of transportation cost due to

using average distances between large regions (e. g., transportation costs for southern Wyoming are calculated using an

average distance from the Powder River basin. ) Examples of

deficiencies in data and assumptions include out-of-date coal

reserve data in several regions, and unrealistically low

assumptions about increases in transportation costs (see footnote 9). The ICF forecasts correct many of these problems,

although ICF emphasizes in its analysis that no modeling

forecast can be considered definitive, and that the results of

forecasts must be interpreted and used with judgment. Some of

the deficiencies pointed out by ICF were corrected in preparing

the final goals (i.e., analysis was based on DOI supply region

and higher transportation costs were used) but other changes

in assumptions were made that makes comparisons between

the ICF base case and DOE final production goals more difficult.

that affect coal demand and supply, and

market conditions, By comparison, energy

forecasts are generally based on expected

market conditions and energy laws and regulations. Since many of the assumptions underlying the production goals are based on

policy initiatives to expand domestic coal

production, the goals are likely to exceed

coal production forecasts ., , Such a relationship is entirely appropriate.

The assumptions that were used in setting the

preliminary production goals appeared consistent with a forecasting approach rather

than a production goal approach to modeling.

Thus, the difference between the final and

preliminary goals can be attributed mostly to

assumptions concerning implementation of

Government policies that will increase demand for coal. * For example, the final production goals assume 1 million bbl/d oil equivalent of coal-based synfuels production in

1990 (in accordance with goals set when the

Synthetic Fuels Corp. was established) and

strict enforcement of the 1990 deadline in

PIFUA for utility and industrial boiler conversions from gas to coal. It does not appear likely that these goals will be met by 1990. The

synfuels assumptions in the final production

goals substantially exceed those in recent

coal production forecasts (see Synthetic Fuels

section), and section 301(a) (the off gas requirement) of PIFUA has been repealed by

Congress, although rising prices for natural

gas will serve as as incentive for conversion

from gas to coal.

The final production goals are listed in

most tables and figures in this chapter to

show their relationship to other production

forecasts, but are not considered in detail in

the evaluation of the likely range of coal demand in the major Federal coal States because the assumptions on which the final

goals were developed probably overstate the

impact of Government policies on increasing

overall demand for coal in the United

States.** However, the preliminary produc- ——. —

‘See p. 79 for additional discussion of the conceptual distinction between Government policies that change the framework

of the market system and policies that influence the market

system directly to increase demand for coal.

**it should be noted that in some instances (Colorado in particular) the final production goals are lower than the pre-
Ch. 5—Markets and Projected Demand for Federal Coal ● 103

Table 31 .—Comparison of Demand Projections for Major Western Federal Coal Regions and States

With OTA Task Force Demand Estimates

Forecast (million tons per year)

DOE NCM ICF CEUM

Region/State Year Low Medium High Low Base High OTA task force estimates

Fort Union (North Dakota 1985 23 (29) 23 (29) 28 (29) 23 26 26 —

and Montana). . . . . . . . . . . . . . 1990 31 (35) 48 (51) 73 (60) 27 27 32 —

Powder River (Montana 1985 129(187) 159(193) 223(222) 138 169 194 169 to 177

and Wyoming). . . . . . . . . . . . . . 1990 186(206) 275(295) 438(412) 163 226 382 199 to 212

Rocky Mountain coal province

Wyoming (excluding 1985 43 (55) 50 (58) 52 (67) 29 38 43 38

Powder River). . . . . . . . . . . . 1990 55 (60) 58 (71) 63 (82) 29 36 52 42 to 51

Colorado . . . . . . . . . . . . . . . . 1985 33 (34) 36 (34) 39 (38) 26 35 51 at least 25-26

1990 38 (28) 42 (35) 45 (43) 35 52 95 at least 32-38

Utah . . . . . . . . . . . . . . . . . . . . 1985 25 (25) 29 (30) 31 (35) 14 16 20 15 to 18

1990 41 (36) 43 (49) 52 (63) 15 27 59 1 8

a to 30a to 40a

New Mexico. . . . . . . . . . . . . . 1985 32 (33) 34 (38) 40 (44) 28 30 32 about 30

1990 43 (56) 57 (64) 61 (67) 46 58 115 up to 72

aEstimates made for central Utah only.

NOTE: First number IS DOE preliminary production goal which was analyzed by ICF The number in parenthesis IS the final DOE coal production goal

SOURCES. DOE Preliminary National Coal Model and ICF Coal Electric Utility Model forecasts taken from tables 3-5A, 3-5B, 3-7A and 3-7B in ICF, Inc., Analysis and

Crltique of the Departmenf of Energy’s Aug 7, 1980 Report Entitled, “Preliminary National and Regional Coal Product/on Goals for 1985, 1990 and 1995”,

prepared for Rocky Mountain Energy Co, (Washington, D C.. ICF, Inc. October 1980),

DOE Final Production Goals taken from The 1980 Biennial Update of Nafional and Regional Coal Production Goals for 1985, 1990 and 1995 U S. Department

of Energy, Leasing Policy Development Off Ice, January 1981.

Off Ice of Technology Assessment Task Force projections from following sources:

Powder River Basin and southern Wyoming. Wyoming Task Force, Oct 14-18, 1980. Most Iikely demand in Wyoming taken from G B. Glass, Wyoming Coal

Production and Summary of Coal Contracts (Laramie, Wyo. Wyoming Geological Survey, 1960), and likely high demand taken from J J. Sebesta, Demand

for Wyoming Coal 1980-1991 Based Upon Protected Utility Coal Market (Washington, DC.. Office of Technology Assessment, October 1980) with slight

modifications by the Wyoming Task Force as reported in J. R. Boulding and D. L. Pederson, Development and Production Potential of Undeveloped Federal

Coal Leases and Preference Right Lease Applications in the Powder River Basin and Other Wyoming Coal Basins (Washington, D.C. Off Ice of Technology

Assessment, 1981), Likely high demand for Montana Powder River Basin taken from J. J, Sebesta, Demand for Montana Coal 1980-1991 Based Upon Proyected Utility Market (Washington, D C.. Off Ice of Technology Assessment, October 1980). Most likely projections for the whole Powder River Basin derived

by adding Sebesta’s Montana projections to Glass’ Wyoming projections, and likely high demand derived by adding Sebesta’s Wyoming and Montana projectlons Note that the Glass and Sebesta projections for southern Wyomlng in 1985 are the same, so there IS no range shown

Colorado Estimates by Colorado Task Force, Sept 22-24, 1980, represent minimum production expected from existing contracts, mine plans, and undeveloped leases, as reported in J E Martin, Market Factors and Production Contingencies Determining the Present and future Demands for Colorado Coal

(Lakewood, Colo.: Colorado Energy Research Institute. December 1980),

Utah Off Ice of Technology Assessment Task Force, Feb. 2529, 1980 Low to high range was developed by the task force Most likely production IS from F

Hachman, Market Factors Associated With the Assessment of Development Potential of Federal Coal Leases in Utah, prepared for the Office of Technology Assessment, 1980 Total excludes production from Alton Mine or for the Allen-Warner Valley Complex

New Mexico OTA New Mexico Task Force, Aug. 26-27, 1980 Estimates developed by task force as reported in The Development Prospects for Federal Coal

Leases in New Mexico 1980-7990 (Washington, D C : Office of Technology Assessment, November 1980) The 1990 projection was based on a number of op.

timistic assumptions including that a major new market for New Mexico steam coal (about 20 million tons per year) wiII develop in Texas and the gulf coast,

and that demand for electricity in New Mexico and the Western region wiII grow at 4 percent during this period

tion goals are more comparable with other

coal production forecasts and are analyzed in

this chapter as such.

Table 31 summarizes the DOE, ICF, and

OTA task force projections for the Fort Union

and Powder River coal regions, southern

Wyoming, Colorado, Utah, and New Mexico. * Figure 21 compares these projections

schematically for the Fort Union and Powder

Iim)n:l rv R(xIIs. This is i]pp;i renllv due I() the f<)ft th:] t refinements in the rn(dei (such i)s in(’reiising [ransport:l (ion costs)

offset I h[; other [~ssumpt ions t h[] I increased the twer:~ll n:) t ion:] I

(():] 1 pr{du(’t i t )n g(HI 1s.

*Since most coal production from the major Federal coal

Slates will come from the Powder River region (50 percent or

River regions and southern Wyoming, and figure 22 illustrates these projections for Colorado, Utah, and New Mexico.

It should be kept in mind when comparing

the DOE, ICF, and OTA task force forecasts

that they were derived by very different

methods, The model forecasts are based on

varying assumptions concerning factors affecting the overall demand for coal in the

United States: this demand is then allocated

m ( )rc), dcma nd pro j e(’ t i( )ns f[ )r this iirea k~erc tlllilIpzcd in

~re;l ter det:~il hv ()’I’A, Pr[~je(:tions discusse(i in t his t:haplcr in-

(lu(ie (Jnlv the DOE, 1(; F’. and ()’I’A t[~sk ft)rce projections tc)

{]IIOW general (:t)mparis{)n with projections” for the other F’e(l-

[?r[]l c[){~l re~ ions :~nd St;] tes. Analysis of other pr[~jecl ions for

the P{)w(ier Ri\(:r Ix]sin ([in ho foun(i in (’h. 7.

4 . - ‘+ 1 XI - 6 : ,,[ ‘
104 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 32.–Demand and Production Forecasts for Coai for the United States: 1985-2000

(millions of tons)

1985 1990 1995

Low Medium High Low Medium High Low Medium High 2000

EIA production forecasts (1979). . . . 1,129 1,130 1,129 1,305

Council on Environmental Quality

(1979) . . . . . . . . . . . . . . . . . . . . . . . – – – –

Exxon (1979). . . . . . . . . . . . . . . . . . . . – – – –

DOE preliminary production goals

(1980) . . . . . . . . . . . . . . . . . . . . . . 880 963 1,080 1,089

ICF CEUM forecasts (1980) . . . . . . . 915 1,016 1,082 1,122

Data Resources, Inc. (1980) . . . . . . . – 987 – –

National Coal Association (1981) . . 878 1,015 1,131 1,092

DOE final production goals (1981)b . 1,040 1,118 1,245 1,270

1,343 1,353 1,592 1,715 1,718

— — — — —

1,285 – — – —

1,375 1,762 1,238 1,718 2,322

1,300 1,791 1,380 1,756 2,976

1,290 – — 1,617 —

1,345 1,540 — — —

1,620 1,986 1,519 2,214 2,766

—

899-1850a

2,219

—

—

1,931

—

aRange is for low and high energy growth scenarios analyzed by CEQ. Numbers are recalculated from table 6 using an average of 20 million Btu/ton rather than the 23

million Btu/ton used by CEQ in order to account for declines in average coal heat content as Western coal production increases. The 20 million Btu/ton is taken from

the national average projected in 1990 by Congressional Research Service project Interdependence: U.S. and World Energy Outlook Through 1990, Senate Committee

on Energy and Natural Resources, Pub. No. 95-31 (Washington, D. C.: U.S. Government Printing Office, 1977). b

lncluded for comparison to forecasts. See discussion in text for difference between the DOE production goals and production forecasts.

I SOURCES (in order listed in table):

Table 4.26, V.III Energy Information Administration, Annual Report to Congress, 1979 (Washington, DC.: U.S. Government Printing Office, 1980).

Council on Environmental Quality, The Good News About Energy (Washington, DC.: U.S. Government Printing Office, 1979).

Exxon Co., U.S. Energy Outlook 1980-2000 (Houston, Tex. Exxon USA, December 1979), p. 12.

U.S. Department of Energy, Preliminary National and Regional Coal Production Goals for 1985, 1990 and 1995 (Washington, DC.: DOE, Aug. 7, 1980).

ICF, Inc. Analysis and Critque of the Department of Energy’s August 7, 1980 Report Ent/tied “Preliminary National and Regional Coal Production Goals for

1985, 1990 and 1995” prepared for Rocky Mountain Energy Co. (Washington, D, C.: ICF, inc. October 1980),

Data Resources, Inc., production forecast as reported in Coal Week, Sept. 22, 1980.

National Coal Association NCA Long-Term Forecast (Washington, D. C.: NCA, March 1981).

U.S. Department of Energy, The 1980 Biennial Update of National and Regional Coal Product/on Goals for 1985, 1990, and 1995 (Washington, D.C., DOE,

January 1981).

to different regions or States. A fundamental

weakness of all computer models is that they

are least accurate when results are disaggregate to small geographic regions. The

reason for this is that when modeling complex

systems, simplifying assumptions must be

made. At the aggregate level, simplifying

assumptions that may distort results one way

or another tend to cancel each other out. At

the specific geographic level, small changes

in assumptions may create large shifts in projected demand between regions.38 It must also

be realized that models reflect the assumptions, perceptions and biases of the model

manager. In addition, models tend to seek optimal (least cost) solutions to fuel procurement and the entire system tends to approach

a general equilibrium solution. Rarely, if

ever, are these conditions totally achieved in

reality.

The OTA task force estimates, on the other

hand, were developed based on analysis and

judgments by a group of people familiar with

the effect that specific conditions in the

38 Additional discussion of this problem can be found in the

ICF report cited previously and also in Energy and Environmental Analysis, Inc., Feasibility of Using Coal Market Projections

To Appraise Potential Production of Federal Coal Leaseholds,

draft report prepared for OTA, 1980.

region or State could have for the demand for

coal from that area. The advantage of this approach is that it reflects a sensitivity to local

conditions that a computer model cannot

have. The disadvantage of this approach is

that events or conditions outside of the State

or region might affect demand for coal from

that region in ways not anticipated by the

task force. There is also a possibility that individuals closely associated with development in a region or State may underestimate

the effects of competition from another region

or State.

The value of looking at both kinds of forecasts is that the two can be used as a check

against each other. If several different forecasts are in close agreement, then it can be

expected with a reasonably high level of confidence that actual production will be close to

the levels forecasted. On the other hand, if

different forecasts of the “most likely” level

of production differ substantially, then a

closer look at the forecasts is merited to try to

understand the reasons for the differences.

Given the inherent uncertainty in forecasts, it is necessary to identify a range* to

* I t should be noted that this range is distinctly different from

the kinds of ranges developed by computer models such as the
Ch. 5—Markets and Projected Demand for Federal Coal . 105

account for contingencies and factors that

cannot be predicted, The rest of this section

examines more closely the different forecasts

in the regions and states shown in figures 21

and 22, identifying, where possible, the reasons for divergence between the forecasts.

Fort Union Region

Virtually all production from this region

comes from North Dakota; only 0.5 million

tons were produced in the Montana portion of

the Fort Union region in 1979, compared to

15.0 million tons in North Dakota. The DOE

and ICF forecasts are in close agreement in

1985 (see fig. 21) but diverge widely in 1990

with the ICF high forecast nearly the same as

the DOE low forecast. OTA did not convene a

task force for this region, so no projections

are available for comparison, but OTA’s

evaluation of existing leases found that 30

million tons would be needed to meet the requirements of existing and new coal conversion facilities currently planned or under construction. Given the leadtime necessary to

construct these large facilities, it appears

that demand for Fort Union coal in 1990 is

likely to be closer to the ICF forecast than the

higher DOE forecasts.

Powder River Basin

All three forecasts show quite good agreement for 1985 (see fig. 21) with the ICF base

case of 169 million tons exactly the same as

the OTA task force most likely production

estimate, and DOE’s medium forecast 10 million tons lower. However, OTA’s likely high

demand in 1985 is considerably lower than

the DOE and ICF high forecasts. In 1990 there

is considerable divergence between the three

DOE and ICF forecasts shown in table 31, Tbese ranges are indicative of the sensitivity of demand to changes in assump(i(ms

(ha I are plugged into the model. but are not necessarily inciicative of what is likely to happen in the real world. Even though

(he low to high ranges identified bV OTA for analysis of exis[ing

h’ederal leases are narrower than the model ranges, it is Iikel}

that (iemand for 1985 and 1990 w1lI be within the ran~e. After

1990 unrerta inlies and ran~es in forecasts increase r(Jnsiderablv (see final section of this chapter]; OTA did not allempt to

develop m[)s t likdv ranges of dema n(i for the post- I {)90 period,

forecasts, with OTA’s likely high estimate of

212 million tons being 14 million tons lower

than the ICF base case, and 63 million tons

lower than DOE’s medium forecast. The main

reason the DOE forecast is so much higher

than the ICF forecast is that the DOE forecasts included unrealistically low increases

in transportation costs that were modified in

the ICF forecast. OTA used the DOE medium

forecast as its high-demand scenario for

analysis of production potential of leases,

even though it is probably beyond the range

of “likely” high production levels. (See ch. 7

for further discussion of demand for Powder

River basin coal,)

Southern Wyoming

The OTA task force and ICF projections of

38 million tons for southern Wyoming are exactly the same in 1985 (see fig. 21 ) and are

considerably lower than DOE’s midrange

forecast of 50 million tons, In fact, DOE’s midrange forecast for 1985 is almost the same as

the OTA likely high estimate of 51 million tons

for 1990. The primary reason for the high

DOE numbers is that the DOE model considerably understates transportation costs from

southern Wyoming because distances in the

model are calculated using a centroid located

in the Powder River basin, In 1990, DOE’s low

forecast is still higher than ICF’s high forecast (for the reason just mentioned) and the

OTA range of likely to likely high production

falls within the midrange to upper range of

the ICF forecast. For reasons that are not

clear, the ICF base forecast drops below its

1985 forecast (from 38 million to 36 million

tons) and is thus lower than the OTA task

force projection.

Colorado

The DOE and ICF forecasts for 1985 are

very close (36 million and 35 million tons

respectively); the OTA task force estimate in

this case is an estimate of minimum demand.

For 1990, the OTA task force estimate of 32

million to 38 million tons is comparable to the

ICF and DOE low forecasts, The ICF base

forecast is considerably higher than the DOE
106 ● An Assessment of Development and Production Potential of Federal Coal Leases

400

300

200

100

Figure 21 .—Demand Projections for the Fort Union and Powder River Coal Regions

and Southern Wyoming, Compared to OTA Task Force Estimates

1985 1990 1985 1990 1985 1990

Fort Union region a Powder River basin Southern Wyoming

aNo OTA protection

SOURCE Table 30

medium forecast (52 million v. 42 million

tons). The OTA task force estimate was conservative; and although the DOE and ICF

models may not be sensitive to the especially

disadvantageous situation in Colorado with

respect to transportation costs, as discussed

earlier in this chapter, demand in 1990 may

be closer to the DOE range than the OTA

range.

Utah

The forecasted ranges by DOE and ICF do

not overlap at all in 1985. The OTA task force

estimated that 1985 production in Utah would

come from mines currently in operation or

construction. In 1980, the State geological

survey estimated planned 1985 production

would be between 15 million to 18 million

tons. Probably the ICF base of 16 million tons

and the DOE medium forecast of 29 million

tons is a reasonable low to high range. In

1990 the ICF base projection and OTA misestimate are close (27 million and 30 million

tons respectively) but are considerably lower

than the DOE midrange forecast of 43 million

tons. The DOE medium forecast is quite close

to the OTA high estimate of 40 million tons.
Ch. 5—Markets and Projected Demand for Federal Coal ● 107

Figure 22.—Demand Projections for Colorado, Utah, and New Mexico,

Compared to OTA Task Force Estimates

—

I 51

95

67

52

42

Key:

DOE final production goals

ICF Coal Electric Utility Model

14 15 l a

40

34 32 30

‘-J9

1 -

44

115

i 1 I I I I I

1985

Colorado

a

Figures shown are low ranges.

bOTA demand estimates for-central Utah only

c

Figure represents maximum likely demand.

SOURCE Table 30

New Mexico

The ICF base forecast and the OTA estimate in 1985 are exactly the same (30 million

tons) and 4 million tons lower than the DOE

forecast, which indicates good agreement

among all three forecasts. In 1990 the DOE

and ICF forecasts are very close (57 million

and 58 million tons respectively) but are considerably lower than the OTA task force estimate of 72 million tons. The OTA task force

estimate was admittedly an optimistic estimate, and assumed that in the 1990’s New

Mexico would be shipping 20 or more million

tons of coal to Texas markets. A substantial

portion of Texas exports would come from

captive mines. The OTA task force estimate

has been categorized in table 31 as a potenUtahb New Mexico

tial high production level rather than a “most

likely” level of production. If it is assumed

that New Mexico exports a more modest level

of 10 million tons per year to the South-Central States in 1990, the OTA estimate would

drop to 62 million tons, which is close to the

DOE and ICF projections.

Comparisons of Forecasts

The comparisons between the three sets of

forecasts for the major Federal coal regions

and States allow a few generalizations. First,

compared to the DOE and ICF forecasts, the

OTA task force estimates are quite consistently lower than, or near the lower of the midrange forecasts of the two models. Although

the specific reasons for this vary, this is prob-
108 . An Assessment of Development and Production Potential of Federal Coal Leases

ably generally because the OTA task force estimates are more sensitive to some of the factors discussed earlier in this chapter that

have weakened the competitive position of

Western coal. Another reason is that the

OTA task forces quite uniformly did not consider synthetic fuels or foreign exports to be

significant sources of demand before 1990.

Should demand from these sources materialize to a greater extent than expected by the

task forces, demand might be higher than the

“most likely” levels estimated. However, inclusion of the higher midlevel forecasts from

other sources increases the upper range of

the “most likely” estimates sufficiently that

possible demand from these sources is likely

to be adequately accounted for. A second

generalization is that the 1990 forecasts from

all sources tend to have wider ranges than

the 1985 forecasts. This can be attributed to

the higher levels of uncertainty in the factors

affecting demand 10 years from now compared to 5 years from now.

Demand for Western Coal: 1990=2000

Forecasts for the demand for Western coal

after 1990 have a much higher level of uncertainty than the period from 1980 to 1990, and

OTA has not tried to conduct any quantitative

analysis for the 1990’s. However, a number

of demand forecasts are available for the

United States through 2000, and these can be

used to get a general idea of possible trends

and development through to the end of this

century.

Table 32 shows eight forecasts made in the

last few years for total U.S. coal production

in 1985, 1990, 1995, and 2000. Elements of

these forecasts are compared schematically

in figure 23. Also shown in figure 23 for 1985

aColorado

Figure 23.– Demand and Production Forecasts for the United States: 1985-2000 and

the Six Major Federal Coal States:a 1985-90

3,000

2,500

2,000

1,500

1,000

1985 1990 1995 2000

Key: Year

Range of “most likely” forecasts ❑ Range of low and high forecasts

CEQ Council on Environmental Quality EIA Energy Information Administration

DRI Data Resources, Inc. ICF ICF Coal Electric Utility Model

DOE Dept. of Energy National Coal Modelc NCA National Coal Association

, Montana. New Mexico, North Dakota, Utah, and Wyoming b

lntermediate high and Iow forecasts from the various sources not shown.

cDOE’s 19S0 preliminary production goals are shown here rather than the final goals because they are more comparable with other production forecasts See discussion

p 100

SOURCE Table 32.
Ch. 5—Markets and Projected Demand for Federal Coal ● 109

and 1990 are the DOE and ICF forecasts for

the six major Federal coal States combined.

From 1990 to 2000 both the range of “most

likely” forecasts in figure 23 (shaded) and the

range of low to high increase greatly, reflecting the greater uncertainties inherent in forecasting over longer periods of time. In fact the

low forecast in 2000 (899 million tons) made

by the Council on Environmental Quality

(CEQ), is lower than the lowest medium projection in 1985 (963 million tons by DOE) (see

table 32). The CEQ forecast is based on a lowenergy growth scenario in which conservation is the main focus of national energy

policy.

Electrical growth rates after 1990 are generally projected to be similar to or lower than

growth projected for the 1980-90 decade. For

example, Exxon’s projection of 5.3 percent

from 1978 to 1990 drops to 2,9 percent from

1990 to 2000. ICF projects electrical growth

rate continuing at 3.0 percent from 1990 to

1995. Consequently, according to these projections of electrical growth rate, rates of increase in coal demand for utility use can be

expected to be somewhat lower or about the

same in the last decade of this century, although conversion of oil and gas to coal may

offset lower overall electrical growth rates.

Significant areas of potential new demand

for western coal after 1990 include: 1) synthetic fuels, 2) industrial boilers, and 3) foreign export. Possible (but not necessarily

probable) levels of demand for Western coal

for these uses after 1990 could total on the

order of 250 million tons, which is more than

the total of 231 million tons produced in the

West in 1979. Coal consumption for synthetic

fuels plants could be around 100 million tons

(see p. 100), Incremental demand for industrial boilers from 1990 to 2000 in the whole

United States could be on the order of 100

million tons (assuming the 7-percent growth

in demand projected by NCA from 1979 to

1990 continues) of which perhaps half might

be supplied by the West, Foreign exports

could possibly range from 50 million to 100

million tons,

Most of the projections shown in table 32

are not disaggregated to a level that allows a

close look at trends in forecasted production

from the six major Federal coal States, but

most forecasts make a breakdown between

production from the West and East. Some

trends are evident when Western coal production is translated into percentage of total

U.S. coal production (see table 33). All the

forecasts show a steady increase in the

West’s share of total U.S. coal production between 1985 and 2000. A significant part of

this increase is due to the fact that more

Western coal must be mined to make a n

equivalent contribution to U.S. energy needs

compared to Eastern coal. For example, the

CEQ forecast did not take this into account,

and adjusting their forecast to correct for the

lower heat content of Western coal increased

CEQ’s low coal demand scenario in 2000 from

782 million to 899 million tons (see footnote,

table 32).

A comparison of the different forecasts for

any given year in table 33 shows that there is

a considerable range in the percentage that is

projected to come from the West. In 1985 the

West’s share of total U.S. production is projected to range from 33 to 43 percent and in

1990 from 38 to 49 percent. The Energy Information Administration production fore -

casts, which are the lowest for these 2 years

agree with the most recent forecast in tabl e

33 made by NCA and it seems likely that the

growth rate of Western coal production will

increase at a lower rate than the variou s

model forecasts (DOE, ICF, and DRI) indicate.

In 1995 the forecasted percentage of Western coal production begins to converge (from

47 to 52 percent) with a mid point of 49.5 percent and in 2000 Western coal production is

projected to exceed so percent of U.S. pro -

duction .

In table 33 the numbers in parentheses indicate the percentage of total U.S. coal pro -

duction that would come from the six majo r

Federal coal States. It is clear from thes e

percentages that these States account for

most of the production from the West, but the

DOE and ICF forecasts show production from
110 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 33.—Forecasted Changes in Contribution of

Western Coal to Total U.S. Production

SOURCE. See table 32

the major Federal coal States growing at a

somewhat slower rate than total Wester n

coal production between 1985 and 1995. The

DRI forecast shows production from th e

major Federal coal States growing at a

slightly faster rate than total Western coa l

production between 1985 and 1995. It is in -

teresting to note that the final DOE produc -

tion goals indicate a relatively smaller pro -

portion of production from the major Federal

coal States compared to the preliminary goals

(i.e., 32 v. 38 percent in 1990). The final goals

are considerably higher than the preliminar y

goals, but the assumed higher cost increase s

in transportation appear to have restricte d

the share that the Federal coal States obtai n

of the higher goals.

Summary

The analysis of the various factors affecting demand for coal from the major Federa l

coal States in this chapter allows a few general conclusions:

1. The demand for coal from the major Federal coal States will continue to grow at

a faster rate than the total growth in the

demand for coal in the United States due

3.

primarily to the low cost of mining this

coal compared to the Midwest and A p -

palachia, and to the fact that more coal

must be mined to meet equivalent energy

needs because of the lower heat content

of the coal.

2. However, because of several factors (increasing transportation costs and present S O2 emission standards being amon g

the most important) the competitive position of Western coal in the Midwest and

South-Central United States (which ar e

the major centers of demand for Western coal) will not be as favorable during

the next 10 years. as compared to th e

previous 10 years. The net effect of

these factors, combined with downward

revisions in projected growth rates fo r

electricity means that the growth in de -

mand for Western coal will probably not

be as great as some earlier forecasts

had predicted .

After 1990 Western coal is expected t o

continue increasing its share of tota l

U.S. coal production, but total Wester n

coal production may increase at a

slightly faster rate than coal productio n

from the major Federal coal States. Offsetting slowed growth in demand be -

cause of possible reduced electrica l

growth are a number of possible ne w

markets for Western coal for which precise demands are difficult to predict, but

which could potentially be large consumers of coal. These potential major new

markets for Western coal after 1990 ar e

synthetic fuels, industrial boiler conversions, and exports to Asia.
CHAPTER 6

Development Potential and

Production Prospects of

Federal Coal Leases

Contents

Page

Introduction and Summary of Findings.. . . 113

Summary of Findings. . . . . . . . . . . . ........ 114

Development Potential and Production

Prospects of Federal Coal Leases in

Colorado, New Mexico, and Utah . . . . . . . . 116

Overview. . . . . . . . . . . . . . . . . . . . . . .........116

Summary of Production Potential and

Planned Capacity. . . . . . . . . . . . . . . . . . . . . ..118

Development Status of Federal Coal Leases

in the Southern Rocky Mountain Region . . . 123

Leases With Approved Mine Plans. . ........124

Leases in Pending Mine Plans. . . ............127

Undeveloped Leases. . . . . . . . . . . . . . . . . . . . .l30

Development Potential and Production . .

Prospects of Federal Coal Leases in

North Dakota, Montana, and Wyoming.. .138

Summary of Production Potential and

Planned Capacity. . . . . . . . . . . . . . . . . . . . . . . 138

Quality of Coal Under Lease . . . . . . . . . . . . . . . 142

Production and Consumption of Coal:

Powder River Basin, Southern Wyoming,

and the Fort Union Region. . .............142

Page

Development Status of Federal Coal Leases

in North Dakota, Montana, and Wyoming. .146

Leases With Approved Mine Plans and

Leases in Pending Mine Plans. . ..........147

Undeveloped Leases. . . ..................151

Diligence ● *************************** 156

Diligent Development Analysis. . ...........156

Comparison of Production From Federal

Leases and Diligent Development

Requirements. . . . . . . . . . . . . . . . . . . . . . . . . ● 157

Diligent Development in Colorado,

New Mexico, and Utah . . . . . . . . . . . . ......157

Diligent Development in North Dakota,

Montana, and Wyoming . . . . . . . ..........161

in Oklahoma   ** ** ** ************* 164

Status and Production Prospects of Leases in

Approved Mine Plans in Oklahoma. . ......164

Status and Development Potential of

Undeveloped Leases and Leases in

Pending Mine Plans in Oklahoma. . .......164
List of Tables

TabIe No. Page

34. Federal Coal Leases in Colorado, New

Mexico, and Utah. . . . . . . . . . . . . . . . . . . . . 117

35. Rank ofCoal Under Lease in the

Southern Rocky Mountain Region. ... ...1l9

36. Total and Federal Production in

Colorado, New Mexico, and Utah

Selected Years, 1972-80................120

37. Potential Production From Federal

Coal Leases . . . . . . . . . ..... ....... 121

38. Acreage and Reserves Under Lease

by Development Status. . ...............124

39. Summary of Mine Plan and Federal

40

41

Lease Acreage and Recoverable

Reserves: Approved Mine Plans,

Sept 30, 1980. . . . .....................125

Mine Capacity and Projected

Production: Leases in Approved Mine

plans: Colorado, New Mexico, and

Utah, Sept 30, 1980...................126

Summary of Mine Plan, Federal Lease

Acreage-and Recoverable Reserves

Pending Mine Plans — Colorado, New

Mexico, and Utah, Sept. 30, 1980. . . . ....128

42. Mine Capacity and Projected

Production: Leases in Pending Mine

Plans, Colorado, New Mexico, and Utah. .l29

43.Undeveloped Leases in Colorado,

44

45

46

New Mexico, and Utah: Acreage and

Recoverable Reserves. . ................131

Resource Characteristics of

Undeveloped Leases: Colorado,

New Mexico, and Utah. . ...............133

Summary of Development Potential of

Undeveloped Leases in Colorado, New

Mexico, and Utah. . ...................134

Summary of Potential Production and

Mine Capacity for Undeveloped Leases

With Favorable or Uncertain

Development Prospects in Colorado,

New Mexico, and Utah. . ...............135

47. Potential Production From Mines

Containing Federal Coal Leases:

North Dakota, Montana, and Wyoming. ..l39

48. Acreage and Reserves Under Lease by

Development Status . . . . . . . . . . . ........146

49. Summary of Mine Plan and Federal

Lease Acreage and Recoverable

Reserves: Approved and Pending Mine

Plans in North Dakota, Montana,

and Wyoming . . . . . . . .................149

50. Federal Mine Capacity and Federal Mine

Production Prospects: Approved and

Table No,

Pending Mine Plans in North Dakota:

Approved Mine Plans in Montana

and Wyoming . . . . . . . .................150

51. Acreage and Reserves of Undeveloped

Leases: North Dakota, Montana,

and Wyoming ,, ..., . .................151

52. Summary of Development Potential of

Undeveloped Leases: North Dakota,

Montana, and Wyoming. . . . . . . . . . . . .

53. Summary of Production Prospects for

Undeveloped Leases With Favorable

or Uncertain Development Potential:

North Dakota, Montana, and Wyoming

54. Analysis of Prospects for Meeting

Diligent Development Requirements by

1986 or 1991: Federal Leases, Mining

Units, and Recoverable Reserves in

..15 4

..15 5

Colorado, New Mexico, and Utah. . ......158

55. Diligent Development Summary. . .......162

56. Status and Development Potential of

Undeveloped Leases in Oklahoma. ... ... l65

List of Figures

Figure No. Page

24. Potential Production From and Planned

Capacity of Federal Mines Summed Over

the Six Major Federal Coal States. ... .... ll5

25. Coal Regions in the Southern Rocky

Mountain States . . . . . . . . . . . ...........116

26. Potential Production Capacity of All

Mines With Federal Leases in

Colorado, New Mexico, and Utah. . ......117

27. Planned Capacity and Potential

Production of All Mines With Federal

Leases in the Powder River Basin,

Southern Wyoming, and Fort Union

Region, . . . . . . . . . . . . . . . . . ... ,... . . . 140

28. Federal Leases in the Hanna Basin,

Southern Wyoming. . ..................143

29. Federal Leases in the Powder River

Basin, North of Gillette, Wyo. ...........144

30. Lessee Projections of Capacity, Total

Production, and Federal Production

From Mines With Federal Leases:

Fort Union Region, Powder River Basin,

and Southern Wyoming . . . . . . . .........148

31. Diligent Development Summary for the

Southern Rocky Mountain Region. ... ... l59

32. Diligent Development Summary for

Federal Lease Reserves in Colorado,

New Mexico, and Utah. . . .. ............160

33. Diligent Development Summary for the

Powder River Basin. . .................163
CHAPTER 6

Development Potential and Production

Prospects of Federal Coal Leases

This chapter presents the results of OTA’s the Federal Coal Leasing Amendments Act of

assessment of the development potential an d l976 (FCLAA): an analysis of all mining acproduction prospects of Federal coal leases. tivities on Federal leases and of the presen t

These results constitute OTA’s response t o and potential value of existing Federal coa l

the first and second of its four charges i n leases.

Introduction and Summary of Findings

This chapter presents OTA’s estimate of

the amount of coal that could be produce d

from mines with Federal leases in the next 10

years. The estimates of the potential production from Federal leases made in this report

are not forecasts of the coal that would b e

produced at a given price or a given demand.

They are estimates of the total amount of coal

that could be produced from currently operating and proposed Federal mines and from

those undeveloped Federal leases that hav e

characteristic s comparabl e to operatin g

mines in the same region. Coal from thes e

leases would thus be likely to be produced at

a price that is competitive with other mines in

the same area, (Most analyses of coal market

trends in the 1980’s, including those used in

OTA’s State task forces, have projected tha t

demand for Western coal will expand significantly while the price of coal will remai n

stable during the next decade with primar y

increases because of inflation. ) If the pro -

jected increases in demand fail to materialize

or if holders of existing leases do not capture

a proportionate share of any expanded market, then not all the leases that could tech -

nically and economically be developed will be

brought into production, Under those circumstances, OTA’s production estimates will b e

higher than actual production from existin g

leases.

The years 1986 and 1991 are key years in

Federal coal development. All Federal coa l

leases issued before the passage of FCLAA

must meet the diligent production require -

ment of 21⁄2 percent of recoverable reserve s

by June 1, 1986, under Department of interior

(DOI) regulations. Failure to meet this re -

quirement could result in cancellation of th e

lease. However, the diligence period may b e

extended for up to 5 years to June 1, 1991, if

certain conditions are met (see ch. 9).

The production estimates for these two key

years are based on resource potential an d

other factors that will affect output, e.g. ,

1) the lessees’ plans, financial capability, and

mining experience; 2) geological conditions on

the lease: 3) mining and reclamation conditions on the lease; 4) possible environmental

permit restrictions; 5) availability of transportation; 6) socioeconomic impacts and limitations; and 7) potential markets and demand

for Western coal.

Mining plans are an excellent source of detailed information for analyzing potential production and assessing specific problems con -

cerning the development of Federal coa l

leases, The submission of a mining and reclamation plan to the U.S. Office of Surface Mining (OSM) and the U.S. Geological Surve y

(USGS)* is a necessary step in the process of

mine development and coal production, A s

the first step in its analysis, OTA has grouped

leases in three categories: 1) those wit h

approved mine plans; 2) those with min e

plans submitted and pending approval; a n d

*Both surface and underground mines must submit mine

plans to thc Office of Surface Mining,

113
114 - An Assessment of Development and Production Potential of Federal Coal Leases

3) those with no submitted mine plan, which

are referred to as “undeveloped leases” i n

this report.

OTA examined each mine plan to determine: 1) major geological, mining, and reclamation conditions associated with the opera -

tion; 2) the lessee’s mine design capacity and

projected annual production over the next 10

years; and 3) likelihood of the mine’s production meeting diligence requirements, Min e

design capacity is the maximum annual pro -

duction of coal that all facilities located at a

mine can support.

OTA analyzed undeveloped leases, (thos e

without mine plans) differently. These lease s

were grouped in blocks of adjoining lease s

held by the same lessee, Based on geological

and technical characteristics of the blocks,

each lease block was assigned favorable, un -

certain, or unfavorable development poten -

tial. These assignments were made in part by

comparing the reserves, coal quality, and the

mining and reclamation conditions of unde -

veloped leases with similar mines in the area,

Leases that had questionable developmen t

potential based on the criteria were furthe r

evaluated for their potential to be integrate d

into an adjoining mine or to be combined with

other undeveloped reserves.

Those leases with favorable or uncertai n

development potential were analyzed bloc k

by block to assess the factors that could affect

their rate and level of development. Factors

examined included coal markets and demand .

Production estimates were then developed for

each lease block.

A more detailed description of the methodology for evaluating development potentia l

and estimating production is given in chapter

2.

Summary of Findings

As of late 1980, there were 502 Federal

coal leases in the six Western States of Colorado, Montana, New Mexico, North Dakota ,

Utah, and Wyoming. * These 502 leases, 89

percent of the 565 existing Federal coal

leases, contain 16.3 billion tons of recoverable reserves, over 98 percent of the total of

16.5 billion tons of Federal coal currentl y

under lease; they account for over 99) percent

of Federal coal production.**

The 502 Federal coal leases in these si x

States are grouped as follows:***

1.

2 .

3 .

182 leases with 7.3 billion tons of recoverable reserves (# percent of the total

leased reserves) are in approved min e

plans.

117 leases with 2.5 billion tons of recoverable reserves (15 percent) are in pend -

ing mine plans. ****

203 leases with 6.4 billion tons of recoverable reserves (39 percent) are not in

mine plans. (These leases, plus fiv e

leases in pending mine plans in Wyoming

are called undeveloped leases. )

Of these 208 undeveloped leases (20 3

leases with no mine plans and the five Wyoming leases in pending mine plans), 80 leases

containing 4.1 billion tons of recoverable reserves have favorable prospects for develop-

*The leases issued in f;t~rlv 1981 under the new Federal coal

ma nagemen I program are not included in I }1 is I 01 a I and were

not considered in this study. See also p. 164 of this chapter, for

a discussion of the 46 Federa ] leases i n Oklahoma.

* *C(ml from h’df;ral coiil leases is referred 10 [Is Feder;]l

coal. A mine that includes a F’edera 1 lease is G) ]led a Federal

mine. Sornel imes, for the sake of efficiency of recoverv or economy of opera t ions, in Iervening Sla [e or private coal is mined

with Federal lease(s) in [he same m inc. This practice is I he rule

in southern Wyoming and North [)ak{)ta, for example. “1’hus,

many Federal mines produce Ix)lh F’edera I and non-h’ederal

coal. A mine which (:[)n la ins no Federal C(NII is called a nonFederal mine, Totai C(M1 production” in a State or regi(m is thus

the sum of: 1 ) Federal C(MI production from Federal mines plus

2) non-Federal coal production from Federal mines, plus 3) nonFederal coal production from n(m-Federal mines.

** *Five small leases, isolated from principal c(ml-producing

regions, t h ree in Montana and I w() in VVy{)m i ng, were not a na -

Iy’zed in this chapter, hut are in(:luded in these totals. F’our are

undeveloped leases with lit tle likelihood of heing devel(~ped.

one is a pr(xiuring lease. ‘1’hese leases do not appear in the

tables in this chapter,

****Five leases in pending mine plans in Wyoming are inrluded in this total. Because of the preliminary nature of the

mine plans a t the time the a na IVS is was done, these leases are.

however, analyzed as undeveloped leases later in this chapter.
Ch. 6—Development Potential and ProductIon Prospects of Federal Coal Leases ● 115

ment by 1991. The majority of these reserves

are concentrated in the Wyoming portion o f

the Powder River basin (3.2 billion tons of surface-minable reserves) and in the Uinta re -

gion of Utah (0.4 billion tons of underground

reserves). In almost all cases, the lessees are

actively developing these leases.

Another 65 leases containing 2.3 billio n

tons of recoverable reserves have uncertai n

prospects for development by 1991. The large

majority of these reserves (about 90 percent]

are about evenly divided among the Kaiparowits Plateau coalfield of southwestern Utah ,

the Green River region of Colorado and th e

Wyoming portion of the Powder River basin.

Development depends on factors such a s

pace and scale of construction of associate d

powerplants or synfuel projects, developmen t

of in situ gasification, availability of additional Federal reserves from pending preference right leasing applications (PRLAs] o r

from new lease sales, construction of transportation systems and lessee developmen t

priorities.

Finally, 63 leases with approximately 0. 5

billion tons of recoverable reserves are u n -

likely to be developed. Most of these leases

lack sufficient minable reserves of marketable quality to be developed as new mines.

Many also have difficult mining condition s

that would make them expensive to develop ,

and some are located outside active minin g

areas and lack adequate transportation. Be -

cause they are unlikely to be developed, any

production is unlikely from these leases.

Production from existing Federal coa l

leases is likely to increase substantially over

the next 10 years, Planned production capacity for 1986 for Federal mines is 400 million

tons per year; for 1991, over 535 million tons

per year (see fig, 24). OTA estimates that production from Federal mines could range be -

tween 410 million and 500 million tons pe r

year in 1991 depending on markets, synfuels

development, and rail construction. Accord -

ing to the plans of lessees, about 65 percent of

1991 upper limit projected production (32 5

million tons) is expected to be mined from

Federal mines with currently approved min e

Figure 24.— Potential Production From and Planned

Capacity of Federal Mines Summed Over the

Six Major Federal Coal Statesa

600

Likely 1990 demand range for all coal from the

six major Western Federal coal States I

100

1 I I 1 I I I 1 1 1 I I I

1979 1986 1991

Year

A Lessees’ planned annual production from

Federal mines in currently approved mine plans

only

B Lessees’ planned annual production from

Federal mines in currently approved and pending

mine plans

C The sum of E?, above, plus estimates of potential

production from presently undeveloped Federal leases

aWyoming, Montana, Colorado, Utah, New Mexico, and North Dakota

bPlanned capacity for a given year IS the upper Iimit to potential production in

that year (although an even higher total capacity might be attainable in a very

strong market for coal) In many cases (e g currently approved mines In the

Powder River basin in 1991), the lessees’ production plans call for them to pro.

duce at or near capacity In other cases, even optimistic production plans fall

short of using planned capacity to the full Some mines, particularly newer

mines in the Southern Rockies wiII not attain thelr planned maximum capacity

untiI the 1990's. In alI cases, however the capacities planned for 1986 or 1991

were used in deriving fig. 24, above, not the higher numbers for planned maximum capacities in the post 1991 period For most Federal mines in the

Southern Rockies the planned productions for 1986 and 1991 are close to the

planned capacities for those years

Explanation of ranges

C. 92 million ton per year range in 1991

65 mty = Dominant uncertainty iS the development of markets for the coal

22 mty Dominant uncertainty IS the construction of two railroads one to the

Kaiparowits Plateau in Utah (14 mty) and one to the Star Lake Bisti

area of New Mexico (8 mty)

5 mty Dominant uncertainty IS the schedule of synfuels development

D: 22 million ton per year range in 1991

Dominant uncertainty IS the construction of the two railroads mentioned

above under C

SOURCE Off Ice of Technology Assessment

plans. About 14 percent would come from

Federal mines with currently pending mine

plans (69 million tons). The remaining 22 percent (109 million tons) is projected to come

from presently undeveloped leases. Actua l
116 ● An Assessment of Development and Production Potential of Federal Coal Leases

production in 1991 could fall below this During the 1990's, demand for coal in genrange, however, because of competition wit h eral and Western and Federal coal in partic -

non-Federal mines and new Federal leases i n ular might grow rapidly, particularly if coalthe West and from other coal-producing re - based synfuels and exports to foreign coun -

gions of the country and because overall de- tries become important.

mand for coal may not grow sufficiently during the next decade to support this level o f

production from Federal mines.

Development Potential and Production Prospects of

Federal Coal Leases in Colorado, New Mexico, and Utah

Overview

Colorado, New Mexico, and Utah comprise

what is referred to in this report as the Southern Rocky Mountain region. * This three-State

area embraces five major Western coal-pro -

ducing regions—the Uinta region, the Sa n

Juan River region, the Denver-Raton Mesa region, Southwestern Utah, and the Colorad o

portion of the Green River-Hams Fork region

(see fig, 25). The 360 Federal coal leases in

these States cover over 451,000 acres an d

contain over 5.9 billion tons of recoverabl e

coal reserves (see table 34), These State s

have 64 percent of the total Federal leases,

over 55 percent of the acreage under lease ,

and over 35 percent of the reserves unde r

lease. Roughly one-third of the leases in the

Southern Rockies are in approved mine plans,

another third are in proposed mine plans, and

the remaining third are undeveloped. Tota l

production from Federal coal reserves in Colorado, New Mexico, and Utah was 20 million

tons in 1979 or about 45 percent of the total

—

*’I’he Southern Rockv Mounltiin and the Northern Great

Plains regions-as used in this report-should not be confused

with I he Northern Grca t Plains and Rocky Mountain coal provin(x;s. The Rocky hlountain coal province is H geologic and

physit)graphic designiition that includes rxmlfields west of the

m)nt inental (iivide and the Denver basin and Ra ton hfesa coal

regions of (;olorado and New Mexico. The Rocky hlountain coal

province runs from the Big Horn basin of northwestern Wy[)-

m ing to coalficlds in southern New Mex ice. The Great Plains

coal province includes the Powder River basin and Fort Union

region of Wyoming, hlontana, and North Dakota. Geologic province designi+ tions are made on the basis of the geologic cha racteristi(’s and age of the real deposits. (Arizona, which is also

part of the R(mky N!ounti+in C(MI provinre, hi)s little Federal

(’l)al Ii)ll(l illl(l no ~EXICri]l (X)al leases. )

Figure 25.–Coal Regions in the Southern Rocky

Mountain States

Green River

gion

s

u

region

SOURCE Office of Technology Assessment

production of 45 million tons in the three

States. In 1980, production from Federa l

reserves was 24.4 million tons out of tota l

production in the Southern Rocky Mountai n

area of over 49 million tons. These thre e

States contributed about 33 percent of th e

total production from all Federal leases i n

1979 and 35 percent of the 1980 production.

Summary of Production Potential and

Planned Capacity

Production from mines with existin g

Federal leases in the Southern Rocky Moun -
Ch. 6—Development Potential and ProductIon Prospects of Federal Coal Leases ● 117

Table 34.— Federal Coal Leases in Colorado,

New Mexico, and Utah

Total Total

number of recoverable

Total plans or Total reserves

number of lease Federal (millions

State/region leases blocks acres of tons)

Colorado

— .

Green River 57 34 53,254 1,363

Uinta 63 27 69,793 803

San Juan ., 1 1 160 1,6

Denver-Raton Mesa 6 4 3,686 66

Tota l 127 6 6 - 126,893 2,234

New Mexico

San Juan . . 26 12 44,560 447

Denver-Raton Mesa 3 3 200 0.5

Total . . . . . 29 15 44,760 447

Utah

Uinta, . . . . . . 108 42 128,930 1,503

Southwestern Utah 96 14 150,566 1,750

Total . . 204 56 279,496 3,253

Regional total ., 360 137 451,149 5,934

NOTE Sums of acreage and reserves may not add to totals because of Independent rounding

SOURCE Off Ice of Technology Assessment

tain area is expected to rise substantially i n

the next decade as existing and planned

mines reach full operation and new mines are

opened on undeveloped leases. By 1986, according to current mine plan schedules, production from Federal mines could reach over

76 million tons- more than double 1979 production. By 1991, depending on the rate at

which Federal leases are developed, production from Federal mines could total between

110 million and 146 million tons—potentially

doubling the 1986 output and at least tripling

the 1979 level. Figure 26 shows projected increases in production from Federal leases in

Colorado, New Mexico, and Utah. The percentage of total regional production coming

from Federal leases will also increase significantly from about 44 percent in 1980 to over

60 percent by 1991.

Most of the projected increases in production will come from new mines that will not

achieve their full design capacity until the

mid-l990’s. The estimated 1991 production

range of 110 million to 146 million tons is less

than the total maximum annual capacity of

over 200 million tons per year that could be

supported by mines on existing Federal

leases in the mid-l990”s, In the late 1990’s

Figure 26.— Potential Production Capacity of

All Mines With Federal Leases in Colorado,

New Mexico, and Utah

Million tons

per year Colorado

40 —

30 “

A

20 —

I 1 1 I i 1 1 1 1 1 1 I 1

1979 1986 1991

Million tons

per year New Mexico

I

30 —

B

20 —

A

I 1 I I I I I I 1 1 I

1979 1986 1991

Million tons

per year Utah

B

A

I I 1 1 1 I i I I 1 1 1 1

1979 1986 1991

A. Lessees’ planned annual production capacity for Federal mines

in currently approved mine plans only

B. The sum of A, above, plus estimates of production capacity for

Federal mines in pending mine plans and for presently

undeveloped Federal leases

SOURCE Office of Technology Assessment

however, as many of the mines that are now

operating exhaust their reserves, the total

capacity supported by existing leases will

begin to decline slowly.

The maximum annual capacity of the 35

mines with 113 Federal leases that currently

have approved mine plans is about 74 million

tons per year at full operation, Proposed mine
118 . An Assessment of Development and Production Potential of Federal Coal Leases

plans have been submitted for 25 new mines

with 108 Federal leases that would add over

71 million tons of annual capacity. (When the

capacity of existing mines is referred to, it

means capacity at full-scale operation, not

current installed capacity. ) Nearly half of the

existing and planned capacity (about 64

million tons per year) is in underground mines

in the Uinta region of Utah and Colorado.

About 40 percent of the capacity (nearly 30

million tons) in pending mine plans is from

proposed mines in Southwestern Utah.

Production in the Southern Rockies will

generally be less than capacity until the mid1990’s, however, overcapacity is not expected to be as significant in this region as in

the Northern Great Plains. Many of the larger

mines in the Southern Rockies have opened in

the past 4 years and are still under construction. These new mines will not reach full commercial operation for several more years.

Other existing and proposed mines have

scheduled production to fuel new electric

powerplants when they begin operations.

Several of the mines with pending mine plans

will not begin producing until after 1986 and

will reach full-scale production by the early

1990’s.

Many of the 139 currently undeveloped

leases could, according to OTA’s analysis,

support new mines and at least 13 undeveloped lease blocks with 27 leases are already

in mine plan preparation stages. By 1986, few

undeveloped leases will be producing. By

1991, they could contribute between 17 million and 32 million tons of production. If all of

the undeveloped leases with favorable or uncertain development potential go into production, they could add 34 million to 57 million

tons of new annual capacity. Most of this new

capacity (between 23 million and 45 million

tons per year) would come from mines in Utah

and in the Green River region of Colorado.

Besides market uncertainties, the major difficulty affecting production from undeveloped leases is construction of coal transportation systems in Utah and New Mexico.

Quality of Coal Under Lease

The Southern Rocky Mountain States have

a wide variety of coal resources and mining

conditions. The coal quality ranges from

lignite deposits in the Denver basin to highgrade metallurgical bituminous coals in the

Uinta region of Colorado and Utah and in the

Raton Mesa fields of New Mexico and Colorado. The three-State region has supported

an active coal mining industry for over a century. Mines currently in operation in the

region range from small underground mines

producing several thousand tons per year to

large surface mines producing over 5 million

tons per year. Several of the underground

mining operations will reach production

levels of 4 million to 6 million tons per year by

the early 1990’s, and several new surface

and underground mines are planned that will

achieve annual production levels in excess of

10 million tons per year.

Generally the active mining areas have

good quality minable coal reserves, however,

they do not have the extensive shallow, very

thick seams that give a cost advantage to surface mines in areas of the Powder River

basin. The higher heat content of Southern

Rocky Mountain coals, however, partially offsets the lower mining costs in the Northern

Great Plains, especially, when coals are

shipped great distances. In some fields in the

Southern Rockies, the location and quality of

the coals make them strong competitors for

coal from other areas. In northwest Colorado,

for example, minable surface reserves can

reach an aggregate seam thickness of 60 ft

with overburden depths between zero and

400 ft.

Underground mining conditions in the coalfields vary, but generally, these regions are

characterized by thick minable seams of 5 to

12 ft. Some underground seams are 25 ft

thick or more, however, current mining methods have limited recovery to only 12 to 14 ft of

coal. Newer techniques, such as multiple-lift

longwall, promise improvements in recovery

rates; but even with recovery rates of only 40
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 119

percent in some underground mines, the mining conditions and seam thicknesses are often

more favorable than those encountered in

some Eastern and Midwestern coalfields.

Most of the reserves under lease in the

Southern Rocky Mountain region are subbituminous to bituminous in rank. They include

high-quality coal reserves with heat contents

ranging from 9,000 to over 14,000 Btu/lb.

Most have relatively low sulfur contents of

1.5 percent or less, making them suitable for

compliance quality coal. * The ash content

also averages less than 15 percent. Some

coals in the San Juan basin of New Mexico

and the Denver basin of Colorado are an exception with relatively lower Btu values, (as

*As discussed in chs. 4 and 5, one strategy of complying with

Clean Air Act requirements before the 1977 amendments and

implementing regulations was to blend low-sulfur “compliance” coals with higher sulfur local coals so that average sulfur content would be low enough so that pollution control equipment costs were minimized while meeting Clean Air Act requirements. The 1977 changes requiring sulfur reduction for

all coals removed what had been an advantage for Western

coals.

low as 7,800 Btu/lb in the San Juan basin) and

relatively higher average ash contents of up

to 29 percent at the mine. These coals are

nevertheless considered marketable for their

area because the coal can be washed to reduce ash contents to between 16 to 17 percent.

Table 35 shows the rank of coal under

lease in each of the major coal production regions in the three States and the amount of recoverable reserves of each type by mine plan

status. Federal lease reserves in approved

mine plans contain about 1.2 billion tons of bituminous coal and 0.3 billion tons of subbituminous coal. There are about 1.4 billion

tons of bituminous reserves and about 0.5 billion tons of subbituminous reserves on leases

in pending mine plans. Undeveloped Federal

lease reserves include over 2 billion tons of

bituminous coal and nearly 0.3 billion tons of

subbituminous coal. Only about 49 million

tons of leased reserves in the three States are

classified as lignite.

Table 35.—Rank of Coal Under Lease in the Southern Rocky Mountain Region

Reserves and Mine Plan Status (all reserves in millions of tons)

Approved mine plans - Pending mine plans Leases without mine plans

— —

Sub- Sub. - SubBituminous bituminous Bituminous bituminous Bituminous bituminous Lignite

State/region

Lignite

HvAb HvBb HvCb SbA Sbc HvAb HvBb HvCb SbA SbC HvAb HvBb HvCb SbA SbB SbC A

Colorado

Green River 146 160 29 185 487 43 88 18

Uinta 63 164 8 92 165 110

San Jua n

1 31 7 130

2

Denver-Raton Mesa 17 01 49

Tota l 63 166 154 -

160 92 165 139 18 217 494 43 218 18 49

New Mexico

San Juan 34 135 38 56 89 94 1

Denver-Raton Mesa 0.1 04

Tota l 34 1

-

35 38 – 56 89 01 94 04 1

Utah

Uinta 2 676 114 16 141 108

Southwestern Uta h

83 359 0.3

671 335 43 02 698 3 0 3

Total 2 676 114 16 ‘-

141 778 335 125 359 698 3 0 3 —

Total reserves by rank may vary slightly from total lease reserves in other tables because of differences in the sources of coal quality data

Column totals may not add due to Independent rounding

NOTE Calorific values by rank in Btu per pound based on a moist, mineral matter. free basis, are as follows

(HvAb) high volatile A bituminous > 14,000 Btu/lb (SbA) sub.bituminous A 10,500-11,500 Btu/lb Lignite A 6,300.8,300 Btu/lb

(HvBb) high volatile B bituminous 13,000-14,000 Btu/lb (SbB) sub-bituminous B 9,500-10,500 Btu/lb

(HvCb) high volatile C bituminous 11,500-13,000 Btu/lb (Sbc) sub.bituminous C 8,300-9,500 Btu/lb

See ch. 4 for di!scussion of coal rank.

SOURCE Off Ice of Technology Assessment, Mine Plan Data and Department of Interior Automated Coal Lease Data System

134-11+1 O - 81 - 9 : QL 3
120 ● An Assessment of Development and Production Potential of Federal Coal Leases

Production and Consumption of Coal From

Colorado, New Mexico, and Utah

The Rocky Mountain region coals serve

many markets. Most of the coal produced in

the three States is consumed in the region or

in the west coast markets (see fig. 20, ch. 5.)

Under existing long-term contracts, however,

a significant amount is shipped to the South

and Midwest. Coal from Utah is shipped to

Mississippi utilities, and coal from Colorado

is burned by Indiana utilities. Coals from Colorado and Utah have been sold under contract for export to consumers in Korea and

Japan.

Colorado, New Mexico, and Utah also have

deposits of metallurgical coal. Although some

of this coal is not of as premium a quality as

some metallurgical coals in the East, these

Western reserves have supplied the Western

steel industry for decades and also show

some promise for expanding export markets.

Over the next decade, production of metallurgical coal in the Rocky Mountain States is

expected to continue at current annual levels

of about 3 million tons a year because of conditions in the domestic steel industry.

In the past decade, Colorado, Utah, and

New Mexico have seen an increase in coal

production and planned mining activities,

Many Federal leases have recently gone into

production and new mine plans have been

proposed for others. Table 36 shows the increases in total and Federal production in

these States for selected years since 1972,

Federal coal production in these States has

risen from 4.6 million tons in 1972 to over 24

million tons in 1980, while total annual production for the region has risen from 19.4

million tons in 1972 to approximately 49 million tons in 1980. Federal leases thus have

contributed an even larger share of total production, growing from about 25 percent in

1972 to approximately 50 percent in 1980.

The Federal share of total regional production is expected to increase substantially over

the next decade. Coal producers in these

three States have shared in the generally increased level of coal development activities in

the West and hold the optimistic expectation

that the coal production from these States

will be competitive and capture its share of

the expanding market.

In 1979, Federal mines in the Southern

Rockies produced 34.7 million tons of coal,

with about 20 million tons mined from Federal reserves. If all existing and proposed

mines on Federal leases are developed and

produce at their expected rates, the 1986 production from mines with Federal leases could

more than double the 1979 levels (see table

37). By 1991, production from Federal mines

could be more than three times the 1979 level.

The increases in production would be most

dramatic in Utah, rising from 10 million tons

in 1979 to as much as 74 million tons in 1991.

In general, the OTA potential production

from Federal mines compares favorably with

the State task force production estimates and

with the Department of Energy’s (DOE) final

1985 and 1990 production goals, previously

Table 36.—Total and Federal Production in Colorado, New Mexico, and Utah: Selected Years, 1972-80

(millions of tons)

1972 1976 1977 1978 1979 1980

Total Federal Tota l Federal Tota l Federal Tota l Federal Tota l Federal Tota l Federal

Colorado . . . . . . . . . . . . 5.5 2.4 9.4 1.6 12.0 4.0 13.8 5.7 18,1 7.7 19,5 9.4

New Mexico . . . . . . . . 8.2 0.2 10.0 1.2 11.1 2.3 12,6 4,3 15.1 5.4 16,5 6.3

Utah . 5.7 2.0 799 4.4 8.6 5.8 9.1 5.3 11.8 6.9 13,1 8.7

SOURCES U.S Department of the Interior, Annual Federal Coal Management Reports, Fiscal Years 1979 and 1980

U S Geological Survey, Federal and Indian Lands Coal, Phosphate, Potash, Sodiurn, and Other Minerals Production, Royalty Income and Related Statistics

Calendar year 1960, June 1981

Bureau of Land Management, PubIic Land Statistics 1976.

U.S. Department of the Interior, Final Environmenal Statement Proposed Federal Coal Leasing Program (1975)

McGraw HiII, Keystone Coal Indusfry Manual 1977.

U.S. Department of Energy, Energy Information Administration, Coal Production 1980 (preliminary), June 1981
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 121

Table 37.—Potential Production From Federal Coal Leases

(all production in million tons per year)

Potential production from mines with Federal leases

1986 1991

From leases From leases From leases From leases From leases From leases

Production in approved in pending without in approved

State/reglon

in pending without

in 1979 mine plansa mine plansa mine plansb

Total mine plansa mine plansa mine plansb Total

Colorado

Green River ...

Uinta . . . . . .

San Juan ... ...

Denver-Raton

Mesa . . . . . . . . .

Total ., ., ... . .

New Mexico

San Jua n

Denver-Raton

Mesa ., . .

11.2

4.7

0.08

19.0

5.6

0.07

1.3

2.8

0

0.6

0

0

20.9 20.0

8.4 5.8

0.07 0

1.8 6.4 28.1

7.4 1.3 14.5

0 0 0

0 0.5 0.5

9.3 8.2 43.1

0 0 0 0 0

16,0 24.7 4.1 0.6 29.4 25.8

8.4 10.0 6.6 0.2 16.8 10,5 7.5-10.5 1.7-8.0 19.7 -29.0

0 0 0 0 0 0 0 0 0

Total . . . . . ., 8.4 10.0 6.6 0.2 16.8 10.5 7.5-10.5 1.7-8.0 19.7 -29.0

Utah

Uinta . . . . . . . . . 10.4 24 5.6 0 29.6 29.0 11.3 7.0-8.6 47.3-48.9

Southwestern

Utah . . . . . . . . . 0 0 0.6 0 0.6 0 0-18.0 0-7.4 0-25.4

Total ., . . . . . . 10.4 24 6.2 0 30.2 29.0 11.3-29.3 7.0-? 6.0 47.3-74.3

Grand total . . . . . 34.7 58.7 16,9 0.8 76.4 65.3 28.1 -49.1 16.8 -32.1 110.1 -146.4

a For leases in mine plans, with few exceptions, the lessees’ planned production is used.

b For leases with no mine plans and favorable or uncertain development potential, OTA estimates are used, Ranges in production reflect uncertainties In construction

schedules and final mine capacity

Columns may not add to totals due to independent rounding

SOURCE Office of Technology Assessment

described in chapter 5 of this report (see

table 31).

In 1986, production from all mines on Federal leases, including currently undeveloped

leases, could reach 76.4 million tons with

about 29 million tons coming from Colorado

mines, 17 million tons from New Mexico, and

over 29 million tons from Utah. Estimated production from mines on Federal leases in the

Colorado portion of the Green River-Hams

Fork region is 20.9 million tons in 1986 with

about 15.7 million tons from surface mines.

Total production from Federal mines in the

Uinta region in 1986 is expected to be about

36 million tons (8.4 million tons in Colorado

and 29.6 million tons in Utah). Almost all of

this production will come from underground

mines. Production from mines with Federal

leases in the San Juan region is estimated to

reach 16.8 million tons in 1986 with most of it

coming from large surface mines in New

Mexico,

For both Colorado and New Mexico, the

DOE 1985 production goals are higher than

the potential production from Federal leases,

however, the difference is in large part offset

by production from existing and planned nonFederal mines and from new mines on Federal PRLAs. In Utah, OTA’s potential production from Federal mines of 30 million tons

matches the DOE medium production goal,

but both estimates are higher than the estimate of 15 million to 18 million tons used by

the OTA Utah task force.

For 1991, production from mines with Federal leases is projected to increase to between 110 million and 146 million tons depending on the rate of mine construction. Federal mines in Colorado would account for 43

million tons, New Mexico mines for up to 30

million tons and production from Utah mines

would add between 47 million to 74 million

tons. About 28 million tons could come from

Federal mines in the Green River region. Between 59 million and 61 million tons could be

produced from Federal mines in the Uinta region (14.5 million tons in Colorado and 44.8

million to 46.4 million tons in Utah). Between

19.7 million and 29 million tons is expected to

be produced from Federal mines in the San
122 . An Assessment of Development and Production Potential of Federal Coal Leases

Juan region in New Mexico. Production from

Federal leases in Southwestern Utah is uncertain and ranges from no production at all

to as high as 25 million tons by 1991.

The 1990 DOE production goals for Colorado range from a low of 28 million tons to a

high of 43 million tons; 35 million tons is the

midlevel goal. (These goals were reduced

slightly from the preliminary DOE goals published in August 1980. ) Potential production

of 37 million to 43 million tons from Federal

mines and undeveloped leases could meet or

exceed the DOE goals and the State task force

1991 minimum production estimate of 32 million to 38 million tons. Even though non-Federal mines are expected to contribute a

smaller relative share of State production by

the late 1980’s, the large production capacity

of existing Federal leases is apparent. However, at least a portion of this capacity could

be used to replace existing mines that will

shut down in the mid-1990’s. Potential Federal mine production of 47 million to 74

million tons in Utah in 1991 could also exceed

the DOE high production goal of 63 million

tons and the State task force estimate of 30

million tons. However, when the likelihood of

little, if any, production from Southwestern

Utah is considered, the lower estimate of 47

million tons in 1991 is comparable to the DOE

medium goal of 49 million tons. Both the DOE

1990 New Mexico production goals (56 million to 67 million tons) and the OTA task force

1991 maximum production estimate of 72 million tons are substantially higher than Federal mine production of 20 million to 29 million tons. When planned production from

Indian and non-Federal mines is added to

Federal mine production, the total is around

67 million tons, the DOE goal, but still less

than the OTA task force estimate. Thus,

while there is a substantial variety in estimates of coal demand and production for the

Southern Rocky Mountain States, in most

cases, OTA’s estimated potential production

from Federal mines falls within the ranges of

production that would be absorbed under the

various forecasts.

By the early 1990’s, several currently operating mines on Federal leases will deplete

their existing lease reserves. Replacement

capacity for at least three of these mines will

come from new mines on other existing Federal leases. Replacement capacity amounts to

between 5 million and 10 million tons of total

new annual production capacity.

OTA’s production estimates include some

uncertainties that are reflected as ranges of

potential production and capacity. If all

leases meet current mine plan schedules and

demand for coal from these States increases

as expected, production from Federal mines

could reach 110 million tons in 1991. Production of an additional 36 million tons of coal in

1991 is possible, but subject to large uncertainties as a result of factors that could delay

or prevent development. About 10 million

tons of estimated 1991 output comes from existing or proposed captive mines that may not

reach planned full production levels because

of changes in internal coal requirements or

production schedules. Between 4 million and

8 million tons of 1991 production could be

used in proposed synthetic fuel projects.

However, according to the lessees, delays in

these projects are not expected to affect

planned production in 1991 since the coal

produced could be used to meet existing

contracts.

The greatest uncertainty involves the estimated 25 million tons of production, and 36

million to 45 million tons of annual capacity

from mines in Southwestern Utah. Except for

the Alton Mine, none of the existing leases

there have even tentative commitments for

potential production. Furthermore, the Alton

and Kaiparowits Plateau fields are not connected to existing transportation networks. A

slurry system and rail line have been proposed to link these fields to potential markets,

primarily in Nevada and California. However, according to most estimates, at least 30

million tons of annual coal production would

be needed to support construction of the

needed transportation system. OTA’s anal-
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases “ 123

ysis indicates that Federal leases on the Kaiparowits Plateau could support that level of

production, however, it is unlikely that the

lessees would begin producing without assurances that the transportation system would

be built. Mine-mouth powerplants that were

once proposed for Southern Utah, have been

abandoned because of high capital costs and

water availability and air pollution problems.

The Alton Mine and slurry project is opposed

by environmental groups because of potential

impacts on Bryce Canyon and Zion National

Parks and on regional water supplies and air

quality.

The rate of development for about 10 million tons of capacity in the central San Juan

basin of New Mexico is also in question because of delays in the original construction

schedule and final right-of-way approvals for

the proposed Star Lake Railroad. In addition,

two proposed mines there are linked to pending PRLAs and sustaining full production capacity depends on the availability of PRLA

reserves. Several of the lessees could, however, begin small-scale production on existing

leases before 1986 in order to meet diligence

requirements and could delay expansion until

the rail line is completed. Thus, delays are not

expected to affect lease development except

in the rate of construction and production.

The factors affecting development and production from Federal leases in Colorado, New

Mexico, and Utah are discussed in more detail in the State appendixes to this report and

in the OTA task force reports.

Development Status of Federal Coal

Leases in the Southern Rocky

Mountain Region

Over 60 percent of the 360 coal leases in

the Southern Rocky Mountain region were

covered by approved or pending mine plans

as of September 30, 1980. About 30 percent,

113 leases, are part of 35 operating mines

with approved mining plans. During fiscal

year 1980, coal was actually produced from

57 of these leases in approved mine plans.

(The number of leases in approved mine plans

that are actively being mined varies according to the lessees’ production schedules

and mine configurations. ) Another 108 leases

are included in 25 proposed new mines for

which mine plans have been submitted to

DOI. The remaining 139 leases, 38 percent of

the leases in the region, have not yet reached

the mine plan stage of development. The 139

undeveloped leases are divided into 77 different blocks of contiguous leases in common

ownership. (Table 38 summarizes the acreage and reserves under lease by mine plan

status. )

While many existing leases are in historically active mining areas, some are located

in areas that have not been mined extensively. Two such areas—the southern San Juan

basin and Southwestern Utah—are largely

rural and have supported little past coal mining activity. Proposed large-scale coal development in these two fields with substantially

untapped coal resources raises potentially

difficult conflicts with other resource values

and land uses. Several of the active mining

areas face major expansions of coal mining at

the same time that they are already being

affected by development of other energy

sources—oil shale, oil and gas, uranium, and

tar sands. If all these development activities

proceed, they could change the predominantly rural character and economic base of these

regions which primarily have depended on

mining, agricultural, recreational, and nonindustrial activities.

Federal coal production in the Southern

Rocky Mountain region has more than quadrupled in the past decade and it will continue

to grow during the 1980’s as new mines open

and existing mines expand capacity. By 1991

according to OTA’s analysis, total production

from mines operating on existing Federal

leases in the region could reach as much as

146 million tons. Total mine capacity could

eventually reach more than 216 million tons

per year in the mid-1990’s if all planned

mines and leases with favorable and uncertain development prospects go into production.
124 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 38.—Acreage and Reserves Under Lease by Development Status

Approved mine plans Pending mine plans No mine plans

Recover- Recover- – Recover~

able able

Number Number

able

reserves Number Number reserves Number Number reserves

of of (millions of of (millions of of (millions

leases plans Acres of tons) leases plans Acres of tons) leases blocks Acres of tons)

State/BLM coal region

Colorado

Green River . . . . . . . . . . 31 10 25,687 519 3a 3 3,150a 28 a 23 21 24,417 816

Uinta . . . . . . . . . . . . . 22b8 16,23 9

b 2 0 3b

18c

8 34,704c427 C 23 11 18,850

San Juan . . . . . . . . . . . . 1

173

1 160 1.6 — —

Denver-Raton Mesa . . . — —

— — — — — —

— — — — — — 6 4 3,686 66

Total . . . . . . . . . . . . . . . 54 19 42,086 724 21 11 37,855 455 52 36 46,953- 1,055

New Mexico

San Juan . . . . . . . . . . . 9

d

2 18,828 169d9 3 21,098 183 8 7 4,634 95

Denver-Raton Mesa . . . 0 0 0 0 0 0 0 0 3 3 200 0.5

Total . . . . . . . . . . . . . . . 9 2 18,828 169 9 3 21,098 183 – 11 – 10- 4,834 95 -

Utah

Uinta . . . . . . . . . . . . . . . 50 14 55,540 792 14e

8 25,711e264 e 44 20 47,679 447

Southwestern Utah. . . . 0 — — — 64 3 93,029 1,006 32 11 57,537 744

Total . . . . . . . . . . . . . . . 50 14 55,540 792 78 11 118,740 -

1,270 76 31 105,215 1,191—

NOTE: Sums of acreage and reserves columns may not add to totals because of Independent rounding

a

Lease total does not include one lease in pending Trout Creek underground mine plan, which IS also part of approved Edna surface mine, acreage and reserves totals

have been adjusted 10 avoid double counting

bApproved mine plan lease and acreage totals exclude one lease in the approved Bear Mine, which iS included in the larger, proposed Mt. Gunnison Mine to avoid double counting.

cPending mine plan lease, acreage and reserve totals exclude one lease in proposed Blue Ribbon Mine located on a portion of U.S. Steel’s Somerset Mine leases that

have an approved plan, totals have been adjusted to avoid double counting.

dApproved mine plan lease, acreage and reserve totals also include one lease issued in 1980 for the San Juan Underground Mine Extension and one small lease Included in a minor modification to the San Juan surface mine.

e

Total does not include three leases that are part of the pending O’Connor mine plan and which are also covered in part by the approved Belina and skyline mine plans,

totals have been adjusted to avoid double counting

SOURCE: Off Ice of Technology Assessment

Leases With Approved Mine Plans

There are 113 leases in 35 active mines

with approved mine plans in the Southern

Rocky Mountain region. They cover a total of

over 116,000 acres of Federal land and contain more than 1.6 billion tons of recoverable

Federal coal reserves. Nine mines are surface operations (seven in Colorado, two in

New Mexico) and 26 are underground mines

(12 in Colorado, 14 in Utah). Over the next

decade, two of the active surface mine operations are planning to shift to underground

operations to recover deeper reserves (one in

Colorado, one in New Mexico). Table 39 summarizes the acreage and reserves for mines

with Federal leases in Colorado, New Mexico,

and Utah. Table 40 shows the total capacity

and estimated 1979, 1986 and 1991 production for mines with approved mine plans on

Federal leases.

The 26 underground mines range in size

from two small mines producing less than

100,000 tons per year (one in Colorado, one in

Utah) to large mine complexes producing over

1 million tons annually. Three of the existing

underground mines propose to expand annual production capacity to 5 million tons per

year or more by 1986. The nine active surface

mines on Federal leases range in size from

one small operation producing just over

100,000 tons annually to several large surface mines producing over 5 million tons per

year. Most of the surface mines produce between 1 million and 3 million tons annually.

Surface mining activity on existing leases is

currently limited to the Green River region of
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 125

Table 39.—Summary of Mine Plan and Federal Lease Acreage and Recoverable Reserves:

Approved Mine Plans, Sept. 30, 1980 (all reserves shown in millions of tons)

Total

Total Federal Total Total mine plan Total Federal lease

Number Number mine mine Federal reserves reserves

of of mine plan plan lease Under- Sur- Under- SurState/region leases plans acres acres acres ground face Total ground face Total

Colorado

Green River . . . . . . . . 31 10 40,300 25,687 25,687 113 303 416 199 320 519

Uinta 22 8 24,104a 16,239a 16,239a 208 0 208 203 0 203

San Juan 1 1 1 160 160 160 0.7 0 0.7 1.6 0 1.6

Denver-Raton Mesa — — — — — — — — — — —

Total . . . . . . . . . . . . 54 19 64,564 42,086 42,086 322 303 625 404 320 724

New Mexico

San Juan . . . . . . . . . . 9 2 13,622b

14,972b18,828 0 194 194 0 169 169

Denver-Raton Mesa . — — — — — — — — — — —

Total. . . . . . . . . . . . 9 2 13,622 14,972 18,828 0 194 194 0 169 169

Utah

Uinta . . . . . . . . . . . 50 14 85,260C

54,523C

55,540C630 0 630 792C O 792c

Southwestern Utah. . — — — — — — — — — — —

Total . . . . . . . . 50 14 85,260 54,523 55,540 630 0 630 792 0 792

aTotal excludes acreage in approved Bear Mine that is also included in pending Mt. Gunnison mine Plan.

bTotal mine plan acreage and Federal mine plan acreage exclude 3,856 acres in San Juan Underground Mine expansion not approved as of Sept. 30,

c 1960 All totals have been adjusted to avoid double Counting of lease acres and reserves Included in the Belina and Skyline approved mine plans and the

pending O’Connor mine plan

SOURCE Off Ice of Technology Assessment, mine plan review

northwest Colorado and to the San Juan basin

of New Mexico, although two surface mine

operations are proposed for Federal leases in

Utah.

Total capacity of the active mines with

Federal leases is 74.3 million tons per year at

full production. The surface mines in Colorado and New Mexico account for about 26

million tons of annual capacity. The remaining 48 million tons of capacity is in underground mines. Many of the active mines have

been opened within the last 5 years and will

not produce at full capacity until about 1986.

Most of the approved mining operations

include both Federal and non-Federal coal reserves. Total estimated production from

these mines in 1979 was 34.7 million tons.

About 20 million tons of this production came

from the more than 55 Federal leases in approved mine plans that were actually mined.

About 20 million tons of the total 1979 Federal mine production came from surface

mines and 14 million tons was from underground mines.

By 1986, production from mines with approved mine plans could total 58.7 million

tons. About 26 million tons of this will come

from surface mines. By 1991 production from

currently active mines is projected to be 65.3

million tons. Over the next decade at least

two of the mines with approved plans are expected to exhaust their reserves and the operators will shift to proposed new mines on

other Federal leases.

Colorado.—There are 19 mines with approved mine plans operating on Federal

leases in Colorado. The 54 leases in these

mines cover over 42,000 acres and contain an

estimated 724 million tons of recoverable

reserves. Seven of the approved operations

are surface mines located in the Green River

region of northwest Colorado. The remaining

12 mines are underground mines. Three of

the underground mines are in the Green River

region, eight are found in the Uinta region

and one in the San Juan River region. There

are no active mines on Federal leases in the

Denver-Raton Mesa region of Colorado.
126 . An Assessment of Development and Production Potential of Federal Coal Leases

Table 40.—Mine Capacity and Projected Production: Leases in Approved Mine Plans:

Colorado, New Mexico, and Utah, Sept. 30, 1980 (capacity and production in millions of tons)

1979

Number Number Maximum Actual

of mine of annual production

plans Federal capacity from mines

with leases in of all with

Federal these proposed Federal

State/basin leases plans mines leases

1986

Maximum Projected

mine production

capacity from mines

of with

producing Federal

mines leases

1991

Maximum Projected

mine production

capacity from mines

of with

producing Federal

mines leases

Total . . . . . . . . . . . 19 54 31.6 16.0 28.4 24.7 27.0 25.8

Total . . . . . . . . . . . 2 9 10.5 8.4 10.5 10.0 10.5 10.5

Utah

Uinta . . . . . . . . . . . . . 14 50 32.2 10.4 32.2 24.0 32.1g

29.0

Southwestern Utah . 0 0 0 0 0 0 0 0

Total . . . . . . . . . . . 14 50 32.2 10.4 32.2 24.0 32.1 29.0

Regional total. . . . . . . 35 113 74.3 35.4 71.1 58.7 69.6 65.3

aEmpire Energy Eagle #5 and #9 Mines exhaust existing lease reserves; possibility Of extending mine life with new lease reserves not known.

b

canadian Strip mine exhausts existing lease reserves; additional new lease reserves have been requested.

CBear Mine shuts down in early 1980's, production from lease continues as part of proposed Mt Gunnison Mine.

dRoadside Mine exhausts existing lease reserves according to mine plan.

eKng Coal Mine shuts down because existing lease reserves exhausted.

f Capacity excludes 2 million tons of replacement capacity from the San Juan underground mine, which will open in early 1980’s, to maintain production at San Juan

Mine complex at 5.5 million tons annually.

g

Trail Mountain Mine exhausts existing lease reserves according to mine plan; additional new lease reserves have been requested.

Maximum capacity means the highest annual production from a mine operating at its full designed capacity level and not the installed capacity in place in 1988 to 1991.

Actual installed capacity for most mines in the Southern Rocky Mountains will be at or near the projected production levels,

Production estimates based on lessees’ mine plan schedules,

SOURCE: Office of Technology Assessment.

At full operation, the total production capacity of the active mines on Federal leases is

31.6 million tons per year. These mines include large surface mines producing over 3.4

million tons annually, medium to large underground mines yielding from 200,000 to over 1

million tons annually, and several small operations serving local or spot markets. Several

of the underground mines are expanding

their capacity by constructing new portals

that will allow mining of several overlying

seams at the same time. These enlarged underground mines will be capable of producing

over 4 million tons annually—thus matching

the capacity of large surface mines in the

same area. By the early 1990’s, several large

surface mines in the Green River area are expected to exhaust their current mine plan

reserves and will have to either shut down or

shift to underground recovery if additional

strip reserves are not available. At least one

underground mine will require additional

unleased Federal reserves to maintain the

planned level of production.

Total 1979 production from the 19 mines

with Federal leases in Colorado was more

than 16 million tons; 7.7 million tons was

mined from 39 of the Federal leases. According to current mine plan projections, production from currently active mines on Federal

leases is expected to reach 24.7 million tons

by 1986 and by 1991 their total output will

rise slightly to about 25.8 million tons. The
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases . 127

Federal leases in approved mine plans are

discussed more fully in the Colorado

appendix.

New Mexico. —The two currently operating

mines on Federal lands in New Mexico include nine Federal leases with over 18,000

acres and 169 million tons of Federal reserves. Both mines are located in the San

Juan basin in northwestern New Mexico. The

McKinley Mine, near Gallup operates on Federal, Navajo and private lands; the San Juan

Mine near Farmington operates mostly on

Federal land. The total annual production

capacity of these two surface mines is currently 10.5 million tons. The San Juan Mine

will replace about 2 million tons of surface

capacity with underground capacity as it

moves to deeper seams.

In 1979, the two mines produced a total of

8.4 million tons with 5.4 million tons coming

from Federal reserves. According to current

mine plans and information from lessees,

total production will increase to 10 million

tons by 1986. Capacity and production from

the two mines are projected to remain at

around 10 million tons per year through 1991.

Production from both mines is used primarily

at powerplants in the Southwest. See the

New Mexico appendix for additional information on these mines.

Utah.—There are currently 14 active underground mines with Federal coal leases in

the Uinta coal region in central Utah. These

14 approved mine plans include 50 leases

covering a total of more than 55,000 leased

acres and containing about 792 million tons

of recoverable coal reserves. At full operation, the total capacity for these mines will be

32.2 million tons per year, or roughly three

times greater than the 1979 production

levels.

Total coal production in Utah in 1979 was

11.8 million tons. About 10.4 million tons of

this was produced by the mines with Federal

leases, with 6.9 million tons mined from Federal reserves. The Utah State Geological Survey estimates that up to 2 million tons of coal

were stockpiled by several Utah mines in

1979 because of low demand. This overcapacity is expected to be short-lived. With the

opening of the new Emery and Intermountain

Power Project electric generating stations, inState use will expand significantly. Spot market sales and long-term contracts for exports

to Japan and Korea are being negotiated. According to several coal operators in the region, all current excess capacity in Utah was

under contract by early 1981.

By 1986, production from mines with approved plans on Federal leases in Utah is expected to rise to about 24 million tons. Two of

the currently producing mines are scheduled

to be depleted in the early 1990’s. However,

this loss in capacity will be offset as newer

operations reach full production levels in the

late 1980’s. By 1991, total production from

the currently approved mining operations is

projected to increase to about 29 million tons.

A significant portion of this total is captive

production for steel and utility companies.

See the Utah appendix for additional information on active mines on Federal leases in

Utah.

Leases in Pending Mine Plans

As of September 30, 1980, 25 mine plans

with 108 Federal leases were under review

by DOI. These new mines include a total of

108 Federal leases with over 177,000 acres

and 1.9 billion tons of recoverable reserves.

Most of the proposed mines include both Federal and non-Federal coal reserves. The mine

plans cover more than 221,000 acres with

Federal leased acreage making up about 75

percent of the total. The 25 pending mine

plans vary widely in completeness and sophistication, ranging from multivolume, technically complete proposals in the final stages

of permit review, to more general “conceptual” descriptions of the lessee’s 1ongrange plans. Many of the conceptual mine

plans were submitted in 1976-78 in response

to DOI requests for information on diligent

development or for inclusion in regional coal

statements and have not been updated to include information for permit approval under
128 ● An Assessment of Development and Production Potential of Federal Coal Leases

the Surface Mining Control and Reclamation

Act of 1977 (SMCRA). Table 41 summarizes

the acreage and reserves for these proposed

mines, and table 42 shows the estimated capacity and production.

The 25 pending mine plans include 4 new

surface mines (2 in New Mexico, 2 in Utah)

and 21 new underground mines (11 in Colorado, 9 in Utah, and 1 in New Mexico). The

two Utah surface mines also include some

underground operations. The total annual

production capacity of these proposed mines

at full operation is 71.6 million tons. About 25

million tons is surface mine capacity and 47

million tons is underground mine capacity.

Most of these mines will not reach full capacity until the 1990’s. The proposed underground mines range in size from some with

annual capacity between 100,000 and

500,000 tons per year to several new, large

mines capable of producing over 1 million

tons per year. Several of the largest proposed

underground mines would produce over 10

million tons annually. The proposed new surface mines range in size from 1.6 million to

more than 11 million tons of annual production capacity. Two of the proposed surface

mines are in areas where there is currently

no large-scale surface coal mining activity—

the Alton Field of Southwestern Utah and the

central San Juan basin of New Mexico.

All of the proposed mines are scheduled to

begin production over the next decade. The

more technically complete and active mine

plan proposals will probably receive the necessary permits and begin construction in the

next few years. Some of these will be producing by 1986. Initiation of production from

several mines with inactive mine plans is less

certain. According to mine plan estimates,

about 16.9 million tons will be produced from

proposed mines with Federal leases in the

Southern Rocky Mountain States in 1986. By

1991, production from proposed mines with

Federal leases is expected to be between 28.1

million tons and 49.1 million tons. The range

Table 41.—Summary of Mine Plan, Federal Lease Acreage and Recoverable Reserves Pending

Mine Plans—Colorado, New Mexico, and Utah, Sept. 30,1980 (all reserves shown in millions of tons)

State/region

Colorado

Green River . . . . . . . .

Uinta . . . . . . . . . . . . .

San Juan . . . . . . . . . .

Denver-Raton Mesa

Total. . . . . . . . . . . .

Total

Total Federal Total Total mine plan Total Federal lease

Number Number mine mine Federal reserves reserves

of of mine plan plan lease Under- Sur- Under- Surleases plans acres acres acres ground face Total ground face Total

3

a

3 3,150a3,150a3,150a 3 1

b 0 3 1b

2 8

b 0 2 8b

18 8 39,144 34,704 34,704 423 0 423 427 0 427

— — — — — — — — — — — — — — — — — — — — — —

21 11 42,293 37,854 37,854 454 0 454 455 0 455

New Mexico

San Juan . . . . . . . . . . 9 3 29,580 14,979 21,098 42 352 394 56 127 183

Denver-Raton Mesa — — — — — — — — — — —

Total. . . . . . . . . . . . 9 3 29,580 14,979 21,098 42 352 394 56 127 183

Utah

Uinta . . . . . . . . . . . . . 14d8 33,020 19,902 25,711 300 15 315 247 17 264

Southwestern Utah. . 64 3 116,949 93,029 93,029 100 823 923 776 230 1,006

Total. . . . . . . . . . . . 78 11 149,969 112,931 118,740 400 838 1,236 1,023 247 1,270

aExcludes one lease in Trout Creek underground mine that iS also part of approved Edna surface mine: acreage figures have been adjusted to

avoid double counting.

bReserves totals Include Trout Creek Mine underground reserves

cAcreage totals include leased area in approved Bear Mine that is also Part Of proposed Mt Gunnison Mine

dExcludes three leases in the proposed O’Connor Mine that are also partly covered by the approved Skyline and Belina mines Acreage and reserves figures include actual lease portions in the O’Connor mine plan

Acreage and reserves may not add to totals because of Independent rounding

SOURCE: Office of Technology Assessment; mine plan review.
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 129

Table 42.—Mine Capacity and Projected Production: Leases in Pending Mine Plans,

Colorado, New Mexico, and Utah (all capacity and production in millions of tons)

1986 1991

Number of Number of Total Maximum* Projected Maximum Projected

mine plans Federal maximum capacity production capacity production

with leases in capacity of mines from mines of mines from mines

Federal these in pending producing with Federal producing with Federal

State/basin leases plans mine plans in 1986 leases in 1991 leases

Colorado

Green River . . . . . . . . . . . . . . 3 4

a

2.3 2.3 1.3 2.3 1.8

Uinta . . . . . . . . . . . . . . . . . . . 8 18 11.1 8.7 2.8 11.1 7.4

San Juan . . . . . . . . . . . . . . . . 0 0 0 0 0 0 0

Denver-Raton Mesa . . . . . . . 0 0 0 0 0 0 0

Total . . . . . . . . . . . . . . . . . . 11 22 13.4 11.0 4.1 13.4 9.3

New Mexico

San Juan . . . . . . . . . . . . . . . . 3 9 15.3 15.3 6.6 15.3 7.5-10.5

Denver-Raton Mesa . . . . . . . 0 0 0 0 0 0 0

Total . . . . . . . . . . . . . . . . . . 3 9 15.3 15.3 6.6 15.3 7.5-10.5

Utah

Uinta . . . . . . . . . . . . . . . . . . . 8 17b

13.1 11.9 5.6 13.1 11.3

Southwestern Utah . . . . . . . 3 68 29.8 11 0-0.6 29.8 0-18.0

Total. . . . . . . . . . . . . . . . . . 11 85 42.9 22.9 5.6-6.2 42.9 11.3 -29.3

Regional total . . . . . . . . 25 116 71.6 49.2 16.3 -16.9 71.6 28.1 -49.1

a

Includes one lease also in an approved plan

b

Includes three leases also in approved plans.

* Maximum capacity means highest annual production from mine operating at full design capacity level and not the Installed capacity in place in 1986 or 1991 Actual

Installed capacity for most mines in Southern Rocky Mountains wiII be at or near the projected production levels

Product Ion and capacity columns may not add to totals because of Independent rounding

SOURCE’ Off Ice of Technology Assessment

in production reflects uncertainties about the

pace and scale of planned mine construction.

At least seven of the new mines with pending plans will not begin production until after

1986. There are several reasons for this:

1) some new mines are replacement capacity

for existing operations and will not open until

the active mines shut down or reduce production; 2) other mines are being developed

under difficult mining conditions, and thus require longer periods for construction, and

3) several mines are intended to supply new

powerplants that have been delayed or deferred. The planned production dates show

that some operators clearly intend to open

mines according to their own schedules and

market situations rather than to accelerate

development or project early starts to meet

1986 diligence requirements. All of the operators expect to qualify for extensions or modification of the diligence requirements under

current guidelines,

Despite the optimism reflected in pending

mine plans, OTA’s analysis indicates that

production from some of these mines is uncertain. In several instances, the mine plans appear to be inactive and the lessee has not proceeded with development according to the

original plan schedule. Moreover, because of

the substantial difficulties facing developers

in Southwestern Utah, it is likely that the proposed mines there will not open in the late

1980’s as originally announced, if at all.

Colorado.—Proposed mine plans for 11

new mines on Federal leases in Colorado

have been filed for review by DOI. The plans

include 21 leases with a total acreage of over

37,000 acres and with estimated recoverable

reserves in excess of 450 million tons. All of

the proposed new mines are underground operations, All but three of the pending mine

plans are in the Uinta region. The production

capacity of the pending mine plans at full operation is over 13 million tons per year.
130 ● An Assessment of Development and Production Potential of Federal Coal Leases

For 1986, these mines are projected to produce about 4 million tons. By 1991, production is estimated to increase to around 9.3

million tons. Several of the mines are expansions or replacements of existing capacity.

Many of the pending Colorado mine plans

were recently submitted or updated. Although markets for some mines are still unknown, at least two of the new mines have

contracts or letters of intent to supply existing or planned powerplants. See the Colorado

appendix for additional information on pending mine plans in Colorado.

New Mexico.—Mine plans were recently

submitted for three new mines on Federal

leases in the San Juan basin of New Mexico.

The plans include nine Federal leases covering over 21,000 acres and 183 million tons of

recoverable reserves. The proposals include

two new large surface mines in the Star LakeBisti area and one underground mine that

will produce coal for industrial use. Total

production capacity for these mines is 15.3

million tons per year. By 1986, OTA estimates

that production could approach 6.6 million

tons, or about 43 percent of full capacity. The

production estimates for 1991 are more variable, and range between 7.5 million and 10.5

million tons depending on the rate of mine

construction of the proposed surface mines.

Portions of two Federal leases in the proposed Bisti Mine are under review for exchange for unleased Federal coal. The exchange is not expected to delay mine construction. Production from the Bisti Mine will

supply the San Juan Power Plant and the asyet-unsited New Mexico Generating Station.

The Star Lake Mine is associated with pending PRLAs; the attainment of full commercial

production at Star Lake Mine is contingent on

the availability of PRLA reserves and on construction of the Star Lake Railroad for access

to out-of-State markets. See the New Mexico

appendix for additional information on these

mines.

Utah.—Eleven new mines on Federal leases

in Utah have been proposed. The mines contain 78 Federal leases and over 118,000 acres

of Federal land with nearly 1.3 billion tons of

recoverable coal reserves. The mine plans

cover almost 150,000 acres, and the total

mine plan reserves, which include both Federal and non-Federal coal, are over 1.2 billion

tons. (Total mine plan reserves are less than

the total lease reserves because plans currently do not cover all of the leased land.)

Eight of the mines are located in central Utah

and three are in Southwestern Utah. The proposed mine plans include nine new underground mines and two new surface mines—

the first strip mines on Federal leases in

Utah.

The total annual capacity of these proposed mines at full production is 42.9 million tons. The smallest of the mines will

produce 220,000 tons per year at full capacity; the largest mine will have an annual capacity of 12 million tons. The three mines

in Southwestern Utah have a total proposed capacity of 29.8 million tons per

year. Several mines will not reach full production levels on current schedules until

the late 1980’s or early 1990’s. Markets for

several of the new mines in Utah are as yet

unknown, although at least 4,2 million tons

of capacity can be considered captive production.

According to the pending mine plans,

total production could reach 6.2 million

tons by 1986. As the new mines near fullscale operations in 1991, total production

is expected to be between 11.3 million and

29.3 million tons, depending on whether

the three mines in Southwestern Utah open

as planned. The rate of production from

several mines in central Utah could be less

than currently projected because of

changes in construction plans for associated projects. See the Utah appendix for

additional information on the uncertainties

in the potential production from pending

mine plans.

Undeveloped Leases

In the three Southern Rocky Mountain

States there are 139 Federal coal leases
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 131

classified as undeveloped (without mine

plans). Table 43 shows the acreage and reserves for undeveloped leases in Colorado,

New Mexico, and Utah. These 139 leases are

divided into 77 lease blocks and contain over

2.3 billion tons of reserves. OTA’s review of

the reserves and mining conditions on the

leases found that 96 leases in 37 minable

blocks with 95 percent of the undeveloped

lease reserves could support new mining operations. OTA’s analysis further showed that

most, but not all of these 96 leases, could be

developed over the next decade. In addition,

there are a small number of leases that could

be mined as part of adjoining operations o n

existing or new base tracts.

OTA identified 42 leases with 599 million

tons of reserves that actually have favorabl e

prospects for development by 1991. An additional 54 leases with over 1.5 billion tons of

reserves have uncertain prospects for development. Forty-three leases with 219 millio n

tons of reserves were found to have unfavorable development potential. Over 70 percen t

of the lease reserves with favorable development potential are found in the Uinta regio n

of central Utah. Almost all of the reserve s

with uncertain development potential are lo -

Table 43.—Undeveloped Leases in Colorado,

New Mexico, and Utah: Acreage and

Recoverable Reserves

Total

Total recoverable

Total number of Total reserves

number of lease Federal (millions

State/region leases blocks acres of tons)

Colorado

Green River . . . . . 23

Uinta. . . . . . . . . . . . 23

San Juan . . . . . . . . 0

Denver-Raton Mesa 6

Total . . . . . . . . . . . 52

New Mexico

San Juan . . . . . . . . 8

Denver-Raton Mesa 3

21 24,417 816

11 18,850 173

0 0 0

4 3,686 66

36 46,953 1,055

7 4,634 95

3 200 0.5

Total . . . . . . . . . 11 10 4,834 95

Utah

Uinta. . . . . . . . . . 44 20 47,679 447

Southwestern Utah 32 11 57,537 744

Total . . . . . . . . . . . 76 31 105,215 1,191

Regional total ., 139 77 157,002 2,341

Acreage and reserves may not add 10 totals because of Independent rounding

SOURCE. Office of Technology Assessment.

cated in the Green River region of Colorado

and in Southwestern Utah. The major uncertainties associated with lease developmen t

are: 1) markets; 2) construction of propose d

transportation systems; and 3) availability o f

additional reserves. Most of the leases tha t

were found to have unfavorable potential for

development are small isolated lease tracts

with limited reserves.

Potential production from undevelope d

leases that were rated as favorable or uncertain development prospects is estimated to be

only about 800,000 tons by 1986, however by

1991, potential production from these lease s

could range between 16.8 million and 32. 2

million tons depending on the rate of min e

construction and resolution of various uncertainties. The undeveloped leases could con -

tribute between 32 million and 55 million tons

of new annual capacity and 2.6 million tons of

replacement capacity ,

Summary of Undeveloped Lease Statistics

Of the 360 Federal leases in the region, 39

percent are classified as undeveloped. The y

cover more than 157,000 acres, or about 3 5

percent of land under lease in the thre e

States, and include over 2.3 billion tons of recoverable reserves, or over 39 percent of the

leased reserves in these States. Of all lease s

identified as undeveloped by OTA, 56 percent

are located in this region.

Utah, with 76 undeveloped leases, ha s

more than half of the region’s undevelope d

leases; there are 52 undeveloped leases i n

Colorado and 11 in New Mexico. Utah an d

Colorado each have slightly over 1 billion tons

of undeveloped lease reserves. Nearly all o f

New Mexico’s undeveloped reserves are surface minable; in contrast, most of the unde -

veloped lease reserves in Utah must be dee p

mined. Slightly more than half of Colorado’s

undeveloped lease reserves are accessible b y

underground methods; the rest can be surface mined.

The undeveloped leases in the Souther n

Rocky Mountain region vary widely in character. At least 13 lease blocks are part of pro-
132 . An Assessment of Development and Production Potential 01 Federal Coal Leases

posed mining projects for which mine plans

are nearly completed. Another 13 blocks with

17 leases are small tracts of less than 100

acres that formerly sustained small underground mines serving local markets. These

mines closed for various reasons: 1) inability

to meet increased health and safety re -

quirements; 2) difficult mining conditions;

3) depleted reserves; or 4) a decline in local

markets. Many of these smaller leases are located in the isolated mountainous areas. Several large multilease blocks in remote area s

are also isolated from potential markets

because of lack of rail service. Two of these

lease areas—Southwestern Utah and th e

Star Lake-Bisti area of the San Juan basin in

New Mexico—also present possible environ -

mental conflicts for large-scale coal developers because of potential impacts on nearby

national parks, monuments and other sceni c

and archeological resources.

OTA has grouped the 139 undeveloped

leases in the Southern Rocky Mountain region

into 77 blocks of contiguous leases that are

owned by the same lessee(s). Each block will

probably be mined as one operation if developed. The blocks range from single leases

of 40 acres to multilease blocks with as many

as 10 leases and a total of more than 25,000

acres.

Colorado has the largest number of lease

blocks, 36, of which 31 are single lease blocks

and 5 are multilease blocks. New Mexico’s 11

undeveloped leases are divided into 1 0

blocks. Seven of these are single lease blocks

of less than 160 acres, one is a two lease

block of 160 acres, and two are large leases,

each with enough reserves to sustain a new

large mine.

Utah’s 76 leases are divided into 31 lease

blocks—20 blocks in central Utah and 11

blocks in Southwestern Utah. These blocks include 12 multilease blocks and 19 single lease

blocks. The single lease blocks in Utah range

in size from 40 acres to 1,908 acres.

The Colorado, New Mexico, and Utah sections of the appendix to this report describe

the lease blocks in more detail.

Assessing the Development Potential of

Undeveloped Leases (in Colorado,

New Mexico, and Utah)

OTA’s analysis of undeveloped leases included an assessment of each lease block to

determine which blocks could potentially support a new mine. OTA compared the resource

characteristics of each block with those of active or proposed mines in the same region.

Both large and small mines were included in

the regional mine profiles. * The following

criteria were used:

1. Approximate mining unit. Is the lease block

compact, contiguous, and under single

ownership to allow for orderly development as a mining unit?

2. Coal reserves. Are the recoverable coal reserves within the lease block sufficient to

support a competitively sized new mine,

i.e., large mines producing 0.5 million to 1.0

million tons per year; small mines producing 50,000 tons per year?

3. Coal quality. Do the coal reserves meet

minimum Btu, sulfur, and ash quality

standards for the expected end use, e.g.,

steam coal, industrial use, synthetic fuels?

4. Geological characteristics. Do the geological conditions of the coal reserve such

as depth of overburden, seam thickness

and dip, and surface topography permit efficient mine design and economic coal recovery comparable to other operating

mines in the area?

When the quality and quantity of the reserves and the potential mining conditions on

the lease blocks are considered, 37 blocks

with a total of 96 leases were found to have

sufficient minable reserves to sustain a new

mine without additional Federal or non-Federal reserves. Of these 37 blocks, 10 lease

blocks could support new small mines. It is

from these 96 Federal leases with sufficient

amounts of good quality minable reserves

that most, if not all, of the new production

*These profiles and the results of OTA’s evaluation of property characteristics are discussed in detail in the State task

force reports.
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases - 133

from existing Federal leases will come. See

table 44 for the results of OTA’s review of the

resource characteristics of undeveloped

leases.

In addition to the resource characteristics,

OTA’s analysis of the development potential

of leases without mine plans also included an

evaluation of other factors, such as market

conditions, transportation availability, and

environmental requirements, that will influence whether a lease will go into production,

For the Southern Rocky Mountain region,

OTA found that the undeveloped leases divide almost evenly among three categories:

favorable, uncertain, and unfavorable development prospects. The leases, acreage and

reserves in these categories are summarized

in table 45. Forty-two leases (13 blocks) were

rated as favorable prospects for development

by 1991; 54 leases (28 blocks) were rated as

uncertain; and 43 leases (36 blocks] were

rated as unfavorable. Only 9 percent of the

undeveloped lease reserves are included in

blocks with unfavorable development potential. Roughly 65 percent of the undeveloped

reserves, 1.5 billion tons, fell into the uncertain category and 599 million tons, or 25 percent of the undeveloped reserves in the region

received a favorable rating. As a result of the

analysis of the prospects for development of

existing leases, several lease blocks with minable reserves that could support new mines

were found to have little chance of actually

going into production in the next decade. A

small number of leases that could not independently support viable mining operations

were found to have some potential for development in association with adjacent Federal

or non-Federal reserves.

At least 17 leases (5 blocks) with favorable

ratings are part of proposed mining projects

with mine plans in preparation and potential

customers for future production. The lease

blocks with favorable prospects for development also include several large tracts of excellent reserves for which current development plans are unknown. The undeveloped

leases with unfavorable development potential include many single lease tracts with

small reserves as well as several larger

tracts in areas that are not likely to be linked

to an adequate coal transportation system

within the next 10 years. Some of the leases

receiving uncertain development prospect

ratings face resolvable development problems such as potentially adverse environmental impacts, uncertainties about construction of proposed transportation systems,

Table 44.—Resource Characteristics of Undeveloped Leases: Colorado, New Mexico, and Utah

(all reserves in millions of tons)

Leases in blocks with sufficient good Leases in blocks that do not have

quality minable reserves to support a new enough good quality minable reserves to

mine support a new mine

Number Number Number Number

of of Recoverable o f of Recoverable

State/region leases blocks Acres reserves leases blocks Acres reserves

Colorado. . . . . . . . . . . . . . . . . . . 39 23 44,274 1,017 13 13 2,679 38

Green River . . . . . . . . . . . . . . 16 14 22,970 792 7 7 1,447 24

Uinta . . . . . . . . . . . . . . . . . . . . 18 6 17,658 159 5 5 1,192 14

Denver-Raton Mesa. . . . . . . . 5 3 3,646 66 1 1 40 0.1

New Mexico . . . . . . . . . . . . . . . . 2 2 3,954 94 9 8 880 1.5

San Juan . . . . . . . . . . . . . . . . 2 2 3,954 94 6 5 680 1.0

Denver-Raton Mesa. . . . . . . . 0 0 0 0 3 3 200 0.5

Utah . . . . . . . . . . . . . . . . . . . . . . 55 12 99,274 1,119 21 19 5,942 67

Uinta . . . . . . . . . . . . . . . . . . . . 30 8 44,658 417 14 12 3,021 25

Southwestern Utah . . . . . . . . 25 4 54,616 702 7 7 2,921 42

Regional total . . . . . . . . . . 96 37 147,502 2,230 43 40 9,501 106

NOTE Columns may not add to totals because of independent rounding

SOURCE: Off Ice of Technology Assessment
134 ● An Assessment of Development and Production Potential Of Federal Coal Leases

Table 45.—Summary of Development Potential of Undeveloped Leases in Colorado, New Mexico, and Utah

Favorable development potential Uncertain development potential Unfavorable development potential

Recover- Recover- Recoverable able

Number Number

able

reserves Number Number reserves Number Number reserves

of of (millions of of (millions of

State/region

of (millions

leases blocks Acres of tons) leases blocks Acres of tons) leases blocks Acres of tons)

Acreage and reserves may not add to totals because of independent rounding

SOURCE: Office of Technology Assessment.

or difficulties in marketing coal competitively

in the current era of overcapacity.

OTA’s analysis identified 96 leases in the

Southern Rocky Mountain region that have

favorable or uncertain prospects for development in the next decade. These leases contain

over 2. I billion tons of reserves—over 90 percent of the undeveloped Federal lease reserves in the three States. While a classification of favorable or uncertain does not

mean that OTA has found that the lease will

definitely go into production by 1991, it is

probable that many of these leases will in

fact be mined because they include very good

reserves and the market situations for those

states show at least limited opportunities for

expanded coal production.

Production Prospects for

Undeveloped Leases

The potential production and mine capacity for Federal leases with favorable or

uncertain development prospects are summarized in table 46. OTA’s production and

capacity projections represent a rough estimate of the production and capacity that

could be supported by each block based on

consideration of the amount and type of reserves and expected mining conditions for

each block.

OTA identified only two undeveloped

leases, one in the Green River region of Colorado, and one in the San Juan basin of New

Mexico, which are expected to be in production by 1986. Together they could yield 0.8

million tons in 1986. One of the leases is

already committed to supply an existing powerplant; the other is associated with a proposed mine on adjacent non-Federal land

serving a local powerplant.

By 1991, 23 blocks including 77 leases (55

percent of the total undeveloped leases in the

Southern Rockies) could be in production. If

all 22 mines on these leases were developed,

they could produce between 16.8 million and

32.2 million tons of coal in 1991. If a very

strong coal market develops, however, production could approach the total maximum

capacity of 57.7 million tons that these leases

could support. Twelve of the 23 lease blocks

which might be in production in 1991 have favorable development prospects. The remaining 11 blocks have uncertain prospects for a

variety of reasons including lack of transportation, uncertain markets, and the need

for additional reserves. Despite these current
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 135

Table 46.—Summary of Potential Production and Mine Capacity for Undeveloped Leases With Favorable or

Uncertain Development Prospects in Colorado, New Mexico, and Utah

(all production and capacity in million of tons)

Estimated production in 1986a Estimated production in 1991a

State/region Number of Maximum Number of Maximum

development Total number of producing mine Estimated producing mine Estimated

potential Leases Blocks Leases Blocks capacity b production ‘Leases Blocks capacityb

production

Colorado ... 31 20 1 1 0.6 0.6 22 10 12.2 -17.7 8.1

New Mexico. ., 7 6 1 1 2.0 0.2 2 2 4.0-12.0 1.7-8.0

San Juan

Favorable. . . . 2 2 1 1 2.0 0.2 2 2 4.0-12.0 1.7-8.0

Uncertain . . . . 3 2 0 0 0 0 0 0 0 0

Denver-Raton-Mesa

Favorable. . . 0 0 0 0 0 0 0 0 0 0

Uncertain . . . . 2 2 0 0 0 0 0 0 0 0

Utah ... . . . . . 58 15 0 0 0 0 53 11 18.5 -28.0 7.0-16.0

Uinta

Favorable. . . . 30 8 0 0 0 0 28 7 12.0 7.0-8,6

Uncertain . . . . 3 3 0 0 0 0 0 0 0 0

Southwestern Utah

Favorable, . . 0 0 0 0 0 0 0 0 0 0

Uncertain . . . . 25 4 0 0 0 0 25 4 6.5-16.0 0-7.4

Total . . . . . . 96 41 2 2 2.6 0.8 77 23 34.7 -57.7 16.8 -32.2

Capacity and production columns may not add to totals because of Independent rounding.

aSome leases have favorable or uncertain development potential because they could be mined as part of adjacent operations. In almost all of these case, the

estimated Federal production would be very small and thus, neither those leases nor the possible production are shown in the production and capacity estimates

above.

bMaximum capacity means the actual amount of coal that could be produced by the mine operating at full production levels and not the actual installed capacity in

place by 1986 or 1991 Actual Installed capacity for new mines with Federal leases in those years wiII be at or near the estimated production level

SOURCE Office of Technology Assessment

problems, the lessees of 13 blocks are planning for development and the outlook for resolving their problems is good enough to support a forecast of some coal production from

their leases by 1991.

According to OTA’s analysis, a total of 77

of the 96 undeveloped leases with favorable

or uncertain development potential are likely

to be in production within the next decade.

The remaining leases, 17 of which received

uncertain development prospect ratings and

two of which received favorable development

prospect ratings, either are not as likely to

overcome the probable obstacles to development by 1991 or will contribute only very

small production.

Colorado.—Colorado has 52 undeveloped

leases with a total of over 1 billion tons of recoverable reserves. The Green River region

has 23 undeveloped leases and 77 percent of

the undeveloped lease reserves in the State.

Ten Colorado leases in three lease blocks

with a total of 78 million tons of recoverable

reserves were classified as favorable development prospects. All of the leases are located in western Colorado and all are part of

new mine projects that have not yet sub84-141 0 - 81 - 10 : 2! 3
136 ● An Assessment of Development and Production Potential of Federal Coal Leases

mitted mine plans. One of the leases is expected to be producing at it’s planned capacity of 600,000 tons per year by 1986; the other

two blocks could produce 1.8 million tons in

1991 out of a total planned capacity of 2 million tons (see table 45).

Twenty-one leases were classified as uncertain prospects for development. Over 90

percent of the 817 million tons of lease

reserves rated as uncertain are found in the

Green River region of northwest Colorado.

Several very large tracts of underground and

surface recoverable reserves are included in

this category. The uncertain rankings were

based on a variety of considerations that

were different for each lease block, including

coal quality, the availability of additional

reserves from PRLAs or new Federal leases,

transportation problems, and uncertain coal

demand due to the slow pace of construction

of planned powerplants and coal-based synthetic fuel projects. Almost all of these

lessees are proceeding with mine plan development. By 1991, these leases with uncertain

development prospects could produce up to

5.8 million tons with an eventual capacity of

between 9.6 million and 15.1 million tons per

year depending on the mine design.

Colorado has more leases and reserves

rated as unfavorable development prospects

than New Mexico and Utah combined. Even

so, only 15 percent of the undeveloped lease

reserves in Colorado were found to be unlikely to be developed. Twenty-one leases in 16

blocks with 154 million tons of reserves were

classified as unfavorable development prospects. Most of the unfavorable lease blocks

were single lease tracts with small amounts

of reserves. Two blocks in the Tongue Mesa

Field with a significant amount of good quality minable reserves were rated as unfavorable because the area is not served by adequate coal transportation. These two blocks

were the only large blocks in the three-State

region that were found to have little potential

for development in the next 10 years. See the

Colorado appendix for additional information

on potential production from undeveloped

leases in the State.

New Mexico.—There are 11 undeveloped

leases with 95 million tons of recoverable

reserves in New Mexico; 8 of these leases and

over 99 percent of the reserves are located in

the San Juan basin of northwest New Mexico.

The Raton Mesa region in the northeast has

three scattered Federal leases that once supported small mines.

Two large leases in the San Juan basin

were found to have favorable potential for development. These two leases cover 82 percent

of the acreage of undeveloped leases and contain nearly all of the undeveloped reserves.

These leases could produce 200,000 tons in

1986 and from 1.7 million to 8 million tons in

1991 depending on the rate of mine expansion.

One block is located in the northern part of

the basin near Farmington and is associated

with the proposed La Plata Mine on adjacent

non-Federal land. Production from this lease

will probably be sold to the San Juan powerplant. The other lease is located at Black

Lake in the Star Lake-Bisti area of the southcentral part of the basin, and is associated

with several pending PRLAs At least a portion of the production will reportedly be used

in the proposed Texas Eastern Synfuels coal

gasification project. Coal from the mine

would be shipped on the Star Lake Railroad.

Both leases would be surface mined. Mine

plans were submitted to the State surface

mine agency after OTA’s analysis was completed.

Five leases were rated as having uncertain

development prospects including three leases

in the San Juan basin and two leases in the

Raton Mesa region. All of the leases are less

than 160 acres and contain a total of about 1

million tons of reserves. These leases could

be developed only in association with adjacent properties. It is unknown whether operating agreements or assignments for such development have been negotiated. The amount

of production from these leases would be very

small. The four remaining leases were found

to have unfavorable development prospects.

See the New Mexico appendix for additional

information on these leases,
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 137

Utah.—There are 76 leases without mine

plans in Utah. These leases are divided into

31 lease blocks containing about 1.2 billion

tons of recoverable reserves, nearly all of

which are accessible by underground mining.

Thirty-two leases with over 63 percent of the

undeveloped lease reserves are found in

southwestern Utah, which currently has no

active coal mining operations. Several hundred million tons of reserves are contained in

large multilease blocks on the rugged and isolated Kaiparowits Plateau.

OTA identified 301 eases in 8 1ease blocks

in central Utah that have favorable prospects

for development in the next decade. These

leases cover some of the best quality undeveloped coal reserves currently under lease.

Several of the blocks contain metallurgical

coal reserves. Most of the reserves would be

deep mined, but portions of one block could

probably be strip mined. These 30 leases include over 70 percent of the undeveloped

lease reserves with favorable development

potential in the entire Southern Rocky Mountain region. These leases could produce up to

8.6 million tons in 1991 with maximum mine

capacity reaching 9 million to 12 million tons

per year in the mid-1990’s.

Twenty-eight leases in seven lease blocks

were found to have uncertain prospects for

development. Three small leases in central

Utah have uncertain development prospects

because the lessees reportedly intend to mine

the leases in conjunction with adjacent or

nearby operations. The amount of reserves

and annual production are small. Over 702

million of the 705 million tons of reserves

rated as uncertain for development are contained in 25 leases located in four blocks on

the Kaiparowits Plateau in southwestern

Utah. Production from these leases is highly

uncertain because of their distance from rail

service, lack of established communities, difficult underground mining conditions, and

potential environmental conflicts resulting

from development. These lease reserves

could support mines with an eventual annual

capacity of between 6.5 million and 16 million

tons per year depending on the mine size.

OTA estimates that these mines could produce between zero and 7,4 million tons in

1991.

Utah’s undeveloped leases with favorable

and uncertain development potential could

add as many as 11 new Federal mines by

1991 with a total capacity of 18.5 million to

28 million tons. The production capability of

the individual mines ranges from less than

I00,000 tons to more than 6.0 million tons per

year.

The remaining 18 leases in Utah were

found to have unfavorable prospects for development. These 16 blocks with 64 million

tons of reserves consist of small, scattered

lease tracts, many of which once supported

small mines. None of the lease tracts have

enough good quality reserves remaining to

support even a new small mine. Several undeveloped leases in central Utah are adjacent to

Utah Power & Light’s Deer Creek-Wilberg

Mine complex and to several proposed new

lease tracts. These unfavorable leases could

conceivably be combined with adjacent operations. However, as of May 1980, when OTA

completed its review of these leases, no such

action had been taken. Only 29 percent of the

undeveloped reserves in the region with unfavorable development ratings are located in

Utah. The Utah appendix discusses the location, production potential, and development

uncertainties of leases without mine plans in

central and southwestern Utah.
138 ● An Assessment of Development and Production Potential of Federal Coal Leases

Development Potential and Production Prospects

of Federal Coal Leases in North Dakota,

Montana, and Wyoming

The areas

coal province

of the Northern Great Plains

and the northern portion of the

Rocky Mountain coal province which contain

leased Federal coal are located in Montana,

North Dakota, and Wyoming (see fig. 2 in

ch. I). The Fort Union lignite region of

western North Dakota and east-central Montana, and the Powder River basin of southeastern Montana and northeastern Wyoming

are located in the Northern Great Plains coal

province. In southern Wyoming, which is

located in the northern portion of the Rocky

Mountain province, the Hanna Field, the Rock

Springs Field, and the Kemmerer Field contain significant amounts of leased Federal

coal (see fig. 3 in ch. 1). *

There are 137 existing Federal coal leases

in these three regions covering nearly

273,000 acres and containing 10.3 billion tons

of recoverable reserves.** These regions have

24 percent of the total Federal leases, 34 percent of the acreage under lease, and 62 percent of the reserves under lease. Sixty-eight

of the leases in this three-state area are in approved mine plans; only nine are in pending

mine plans; the remaining 60 leases are not in

mine plans, and are referred to as undeveloped leases in this report. Coal production

from mines with Federal leases in North

Dakota, Montana, and Wyoming was 109 million tons in 1979 or over 90 percent of the

total production of 119 million tons in these

three States and over 75 percent of the total

*PPL’s Cherokee lease block is technically part of the Little

Snake River Field in southern Wyoming, but is included in the

Rock Springs Field in the numerical analysis in this chapter.

**By confining the discussion in this section to the Fort

Union region, the Powder River basin and the Hanna, Rock

Springs, and Kemmerer fields of southern Wyoming, three

small leases in Montana in the Yellowstone and Bull Mountain

region, and two small leases in Wyoming in the Big Horn basin

are omitted. Four of these leases have unfavorable development potential. The fifth, in Montana, is currently producing.

production of all mines with Federal leases in

the West. *

Summary of Production Potential and

Planned Capacity

Table 47 summarizes the production potential of all mines with Federal coal leases in

North Dakota, Montana, and Wyoming. Operating mines with Federal leases in these three

States produced 109 million tons of coal in

1979. According to the lessees’ plans, Federal

mines in currently approved mine plans are

scheduled to produce 232 million tons in 1986

and 260 million tons in 1991. OTA estimates

that under favorable market conditions mines

with Federal leases in pending mine plans

and undeveloped Federal leases located in

this three-State area will contribute an additional 32 million tons of coal production in

1986 and 97 million tons in 1991, If these

OTA estimates and the lessees’ plans are

realized, total production from mines with

Federal coal leases in North Dakota, Montana, and Wyoming will be 264 million tons in

1986 and 357 million tons in 1991.

In the Powder River basin of Wyoming and

Montana, Federal mines accounted for 88

percent of total coal mine capacity in 1980.

This percentage is projected to remain relatively constant throughout the decade. However, production from Federal leases them-

*Coal from Federal coal leases is referred to as Federal

coal. A mine that includes a Federal lease is called a Federal

mine. Sometimes, for the sake of efficiency of recovery or economy of operations, intervening state or private coal is mined

with Federal lease(s) in the same mine. This practice is the rule

in Southern Wyoming and North Dakota. for example. Thus,

many Federal mines produce both Federal and non-Federal

coal. A mine that contains no Federal coal is called a nonFederal mine. Total coal production in a State or region is thus

the sum of: 1 ) Federal coal product from from Federal mines plus

2) non-Federal coal production from Federal mines plus 3) nonFederal coal production from non-Federal mines.
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 139

Table 47.—Potential Production From Mines Containing Federal Coal Leases:

North Dakota, Montana, and Wyoming (all production in million tons per year)

Potential production in 1986 Potential production in 1991

Federal mines Federal mines

Federal in pending Federal in pending

mines in mine plans mines in mine plans

approved and leases approved and leases

Production mine not in mine not in

State/region in 1979 plans a mine plansb Total plans a mine plansb

Total

North Dakota

Fort Union . . . . . . . . . . . 14.1 C

12 15 27 12 20 32

Subtotals. . . . . . . . . . 14.1 12 15 27 12 20 32

Montana

Fort Union . . . . . . . . . . . 0.3 0.3 0.0 0.3 0.3 0.0 0.3

Powder River basin . . . 27.1 46 0 to 1.6 46 to 48 49 0 to 8.8 49 to 58

Subtotals. . . . . . . . . . 27.4 47 0 to 1.6 47 to 48 49 0 to 8.8 49 to 58

Wyoming

Powder River basin . . . 44.5 144 5.6 to 9.5 150 to 154 170 17 to 56 186 to 225

Hanna Field . . . . . . . . . 10.7 10 0.4 to 0.6 10 to 11 8 0.3 to 0.6 8 to 9

Rock Springs Field . . . . 7.2 13 1.3 to 2.0 14 to 15 15 1.1 to 7.0 16 to 22

Kemmerer Field . . . . . . 5.1 6 2.2 to 3.5 9 to 10 6 2.6 to 4.5 9 to 11

Subtotals. . . . . . . . . . 67.5 173 10 to 16 183 to 189 199 21 to 68 219 to 266

Totals. . . . . . . . . . . . . 109 232 25 to 32 257 to 264 260 41 to 97 301 to 357

aWith few exceptions, the leSSee's planned production iS used for approved mine plans (and for pending mine plans in North Dakota)

bOffice of Technology Assessment estimates are used for pending mine plans (Wyoming) and for leases with no mine plans

c

lncludes 56 million tons of production from mines with Federal leases in currently pending mine plans.

SOURCE Office of Technology Assessment

selves is projected to increase from less than

40 percent of total coal production in the

basin in 1979 to approximately 80 percent in

1991. In southern Wyoming, essentially all

coal production is from Federal mines with

about one-third of the production from the

Federal leases, This pattern is expected to

continue with the contribution from Federal

reserves rising to perhaps 40 percent by

1991. In 1979, Federal mines in the North

Dakota portion of the Fort Union region accounted for over 90 percent of the State’s

coal production; the amount produced from

Federal reserves was less than 7 percent.

This situation is expected to continue, with

however, production from Federal reserves

rising to perhaps 20 percent by 1991.

Figure 27 summarizes the potential production and planned capacity of all mines

with Federal leases (including undeveloped

leases) in the Fort Union region of North

Dakota and Montana, the Powder River basin

of Montana and Wyoming, and the coalfields

of southern Wyoming. The upper capacity

lines (lines D) in this figure

estimate of the maximum

represent OTA’s

coal production

from Federal mines that could be achieved in

these three regions under strong market conditions.

Several features of figure 27 should be

noted:

1.

2 .

The Powder River basin will continue to

increase in importance as a coal-producing region, By 1991, Federal mine production in the Powder River basin could

account for about 80 percent of Federal

mine production in these three States. *

All estimated Federal mine production

for 1991 for the Powder River basin

comes from currently approved mines

and from undeveloped leases with favorable development potential. (Undeveloped leases with uncertain develop-

*Because of the importance of the Powder River basin in

Federal coal production, the development potential and production prospects of all Federal Coal leases in this region are

examined in more detail in ch. 7.
140 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 27.-Planned Capacity and Potential Production of All Mines With Federal Leases in the

Powder River Basin, Southern Wyoming, and Fort Union Region

Million tons

per year

40

Fort Union D

region c

30 -

20 -

● & I 1

1979 1966 1991

Year

Million tons

per year

50

40

30

20

10

Southern Wyoming

.

.

I 9 1 I I I 1 1 I t t I I

1979 1966 1991

. . Million tons

per year

350

Powder River basin

300

250

200

150

100

50

t

1 I t t I I 1 1 1 1

1979 1960 1986 1991

Year

Year

A: Lessee’s planned annual production from Federal mines in currently approved mine plans only

B: Lessee’s planned annual capacity for Federal mines in currently approved mine plans only

C: The sum of A, above, Plus estimates of potential production from Federal mines in pending mine plans and from presently

undeveloped Federal leases

D: Planned annual capacity for all Federal mines, including Federal mines in pending mine plans and presently undeveloped Federal

leases

SOURCE. Office of Technology Assessment.

ment potential contribute no production 3. By 1991, the capacity of Federal mines

through 1991. ) The large range in esti- in the Powder River basin could be as

mated production from undeveloped high as 310 million tons per year. Acleases arises from demand uncertainty. cording to the lessees’ plans, the overcaHowever, several undeveloped leases in pacity in presently operating Federal

the basin have contracts for delivery of mines in the Powder River basin, which

coal before 1990. was greater than 75 million tons per
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 141

4.

5,

year in 1979, will diminish to nearly zero

by 1991,

The maintenance of total capacity of

Federal mines in southern Wyoming depends on the development of new mines,

Although capacity of presently operating mines is projected to decrease over

the next 10 years, their production will

probably not decline, Most of the range

in production arises from uncertainty in

the pace of a synfuels project.

The potential increase in production and

capacity of Federal mines in the Fort

Union region will occur largely from

mines in North Dakota with leases in

currently pending mine plans. Undeveloped leases are not likely to contribute

more than 1 million tons per year by

1991. Federal mine production in the

Montana portion of the region is likely to

remain constant at 0.3 million tons per

year.

The following subsections summarize the

data presented in table 47 by State.

North Dakota.—Production from Federal

mines with approved mine plans in the Fort

Union region of North Dakota was 8,5 million tons in 1979. In 1986, these mines are

projected to produce 12 million tons, a level

of production that should remain constant

through 1991. Production from Federal mines

with mine plans pending was almost 6 million

tons in 1979 and is expected to increase to 15

million tons in 1986 and to 20 million tons in

1991. Production of perhaps 1 million tons

can be expected from undeveloped leases in

North Dakota by 1991. Total production from

Federal mines in North Dakota could reach

32 million tons by 1991,

Montana.—Production from mines with

Federal leases in Montana in 1979 was 27.4

million tons, Virtually all of this production

(27.1 million tons) came from the Powder

River basin; production from a small Federal

mine in the Fort Union region of Montana accounted for the balance. According to the lessees’ plans, 47 million tons of coal will be produced in 1986 from mines with Federal leases

already developed in the Montana Powder

River basin. Production from the Montana

leases in the Fort Union region is scheduled to

remain at 0.3 million tons through 1991.

OTA estimates that 1.6 million tons of coal

could be produced in 1986 and close to 9

million tons in 1991 from undeveloped Federal coal leases in the Montana portion of the

Powder River basin. Lessee plans call for production of 49 million tons in 1991 from Federal mines in approved mine plans. If these

estimates and plans are realized, production

from Federal mines in Montana would reach

58 million tons per year in 1991. There are no

leases with pending mine plans in Montana.

Wyoming.—Coal production from mines

with Federal leases in the four regions of

Wyoming— the Powder River basin, Hanna

Field, Rock Springs Field, and Kemmerer

Field—totaled 67.5 million tons of coal in

1979. Two-thirds of this production (44.5 million tons) came from the Wyoming portion of

the Powder River basin. By 1986, according

to the lessees’ plans, production in this basin

from Federal mines that now have approved

mine plans will increase to 144 million tons.

OTA estimates that an additional 10 million

tons could be produced from undeveloped

leases in the basin in 1986, giving planned

and estimated production of 154 million tons

in 1986. By 1991, production could increase

to 225 million tons with 170 million tons coming from Federal mines that now have approved mine plans and 56 million tons from

undeveloped leases.

Twenty-three million tons of coal was produced from mines with Federal leases in

southern Wyoming in 1979. The lessees plan

that production from currently operating

mines will increase to 29 million tons in 1986

and remain constant through 1991. OTA estimates that production from currently undeveloped leases and leases in pending mine

plans in this region could reach 6 million tons

by 1986 and 12 million tons by 1991, for total

southern Wyoming Federal mine production

of 35 million tons in 1986 and 41 million tons

in 1991.
142 ● An Assessment of Development and Production Potential of Federal Coal Leases

Quality of Coal Under Lease

Of the 9 billion tons of recoverable coal reserves under lease in the Powder River basin,

7 million tons are subbituminous C, and 1.3

billion tons are subbituminous B.* There are

small reserves of subbituminous A in the

Montana portion of the Powder River basin.

There are also Federal lignite reserves under

lease in the Powder River basin. Several Federal mines and leases in southern Wyoming

have reserves of bituminous coal, however

most of the Federal reserves in southern

Wyoming, including most of the reserves on

undeveloped leases, are subbituminous. All

Federal reserves in the Fort Union region are

lignite.

Most of the Federal coal in the Powder

River basin and the coalfields of southern

Wyoming is low sulfur (i.e., less than 0.5 percent sulfur). Only one Federal mine in the

Powder River basin produces coal with a sulfur content of over 1 percent.

Production and Consumption of Coal:

Powder River Basin, Southern

Wyoming, and the Fort Union Region

Coal seams in the Powder River basin typically range from 25 to 120 ft in thickness.

Because of the thick seams which lie fairly

close to the surface, all mines in the Powder

River basin are surface mines. Large quantities of coal can be extracted at low cost

from these mines. On a Btu basis, Powder

River basin coal mine-mouth prices are the

lowest of all coals, ranging from $0.42 to

$0.65 per million Btu (see table 28). In addition, the mines in the Powder River basin are

large. The Belle Ayr Mine in Wyoming is presently the largest coal mine in the United

States; it produced 15 million tons in 1980.

Four other mines in the basin are scheduled

to reach a design capacity of 20 million tons

per year or more by the end of the decade.

*The following Btu ranges are associated with different coal

quality: 1 - Bituminous-high volatile A (greater than 14,000

Btu), B (14,000 to 13,000 Btu), C (13,000 to 12,000 Btu): 2- Sub

bituminous—A (12,000 to 11,000 Btu), B (1 1,000 to 9,500 Btu),

C (9,500 to 8,300 Btu); and 3- Lignite (8,300 to 5,500 Btu).

Steeply pitching, multiple coal seams are

common in southern Wyoming where the recoverable reserves are usually much smaller

and the stripping ratios higher than in the

Powder River basin. Also, unlike the Powder

River basin, underground mining has a long

continuous history in southern Wyoming. Two

underground mining operations in southern

Wyoming, the Vanguard No. 2 and Carbon

No. 1 mines, currently include Federal coal

deposits. ** Longwall mining techniques are

being used or will be used to increase coal

recovery at both of these mines to about 75

percent of minable reserves.

Surface mining in southern Wyoming is

more complex and more costly than in the

Powder River basin because of the steeply

pitching and multiple coal seams. At some

mines, such as the Elkol-Sorensen Mine which

includes Federal reserves, combinations of

draglines, truck/shovel operations, and dozer/scraper teams are used to develop large

multiple open pits with depths that may reach

1500 ft. Up to 12 seams are mined at ElkolSorenson with an aggregate coal thickness of

300 ft and dips of 170 to 220. Another Federal

mine in southern Wyoming, the Black Butte

Mine, contains 13 coal seams ranging in

thickness from 3 to 35 ft. Eleven pits will

eventually be developed at Black Butte.

In the Wyoming portion of the Powder

River basin, most Federal mines are compact

units with little, if any non-Federal coal interspersed with the Federal reserves. Consequently, mining operations in this area involve predominantly Federal reserves. The

occasional sections of State and fee coal are

developed with the Federal reserves. By

1986, the Federal portion of coal production

from these mines is expected to increase to

well over 90 percent from the 1979 level of 49

percent. In southern Wyoming and in the

area around Colstrip, Mont., on the other

hand, most leased areas of Federal coal are

checker-boarded with non-Federal coal and

all LMUs include both Federal and non-Fed-

**Another underground Federal coal mine in this area, the

Stansbury Mine, closed in early 1981 but is expected to reopen

later in the decade.
Ch. 6—Development Potential and Product/on Prospects of Federal Coal Leases . 143

eral reserves. Orderly and efficient mining

can be difficult where only part of the Federal coal reserves within the extended mine

plan area are leased. These two patterns of

reserve development are shown in figure 28,

which illustrates patterns of Federal leaseholdings in southern Wyoming, and in figure

29, which illustrates patterns of Federal

leaseholdings in the Wyoming portion of the

Powder River basin.

Approximately 25 billion to 35 billion tons,

about two-thirds of the Nation’s lignite

reserves, are found in the Fort Union region

of North Dakota. The coal seams in this

region seldom dip more than a few degrees.

Typically, the North Dakota lignite operations

are surface mines designed to produce 2 million or more tons of lignite per year. Although

a few specialized or older smaller mines remain in operation, the trend recently has

been toward large-scale operations.

Reclamation and environmental issues are

expected to affect Federal coal development

in the Powder River basin, southern Wyoming, and the Fort Union region, For example,

at Colstrip, Mont., fugitive dust levels

presently exceed ambient air standards and

future mine expansion will have to address

and minimize air quality impacts. In southern

Wyoming, where the climate is more arid,

fugitive dust problems may have to be addressed at some mines, However, air quality

concerns are not likely to deter Federal coal

production significantly over the next 10

years in either the Powder River basin or

southern Wyoming. Air quality is an important issue in the Fort Union region of North

Dakota where the possible lack of sulfur dioxide (S02

) increments may delay development

of some leased Federal coal. These issues are

discussed in more detail in chapter 10,

The availability of water and the impact of

mining operations on water quality have not

Figure 28.— Federal Leases in the Hanna Basin, Southern Wyoming

SOURCE Off Ice of Technology Assessment.
144 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 29.—Federal Leases in the Powder River Basin, North of Gillette, Wyo.

SOURCE: Office of Technology Assessment.

generally been a major factor affecting coal

mine development in the Powder River basin.

However, such considerations could become

important if onsite powerplants or synthetic

fuels projects are extensively developed.

Scarcity of water in the Gillette area of the

Powder River basin, for example, justified the

expense of constructing the first dry cooling

tower in the United States at the Wyodak

Power Plant. Competition for limited water

supplies may ultimately affect the extent of

coal mining in portions of southern Wyoming.

In this area, mines need water for dust control and use in mining facilities and also for

the irrigation of reclaimed lands.

Substantial quantities of topsoil, adequate

rainfall, and a relatively flat terrain enhance

the potential for successful reclamation in

North Dakota. Nevertheless, reclamation efforts have not been uniformly successful in

North Dakota. Mining in environmentally sensitive woody draws in the west-central region

of the State has been delayed pending development of satisfactory reclamation plans,

Reclamation efforts in North Dakota must

also take into account sodic soil problems.

At present, Federal coal development in

southern Wyoming and the Fort Union region

affects no alluvial valley floors. In the Powder

River basin, however, Federal coal production or expansion of Federal mine capacity

could be affected in some cases if it is determined that adequate reclamation plans cannot be developed for alluvial valley floors, Of

the 9.2 billion tons of Federal recoverable

reserves under lease in the Powder River

basin, approximately 700 million tons could

be affected to some extent by alluvial valley
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 145

floor considerations; less than 100 million

tons of these may be prohibited from mining,

however.

Although alluvial valley floors are not an

important constraint on mine development in

North Dakota, they are given careful consideration in mine permitting. Mining can be

complicated in the Fort Union region because

of large amounts of water that can seep into

the mine pit. In cases where this seepage occurs through the highwall, there have been

problems of instability and spoil pile slumping

which cause inefficient and potentially dangerous mining conditions.

Concern about the protection of wildlife

habitat has resulted in minimal prohibition to

mining and production of Federal coal. In

southern Wyoming, protection of raptor

habitat has resulted in some changes in mining plans and has contributed to the loss of 5

million tons of reserves at one mine. Unless

endangered species are found to reside on a

proposed mine site, it is unlikely that significant amounts of recoverable reserves will be

lost because of wildlife concerns.

Because most mines in the Powder River

basin have large surface reserves, thick coal

seams, and a low stripping ratio, Powder

River basin coal is the cheapest coal to mine

in the country. The capacity of a typical mine

in the Powder River basin is larger than the

capacity of most other surface mines located

in the West and in other regions of the country, This high volume production and low production costs are well suited to long-term

utility contracts. However, the heat content

of Powder River basin coal is relatively low

compared to coal produced in the Rocky

Mountain coal province.

Electricity generation is the largest market

for coal mined in Wyoming and Montana,

with the main areas of demand in the SouthCentral and Midwest regions of the country.

Demand for coal produced in Wyoming and

Montana is expected to increase as demand

for electricity increases in these regions. Conversions to coal-fired utility burners, particularly in the South-Central region, may further increase the demand for coal produced

in the Powder River basin. Industrial demand

for coal mined in the Powder River basin is

expected to be relatively small over the next

10 years.

The availability, cost, and reliability of rail

transportation to the Midwest and South-Central regions of the country are important factors in coal mine development in Wyoming

and Montana. Transportation costs are already an important component of the delivered price of Wyoming and Montana coal,

running as high as 70 percent in the Midwest

(see table 28). Transportation costs are expected to rise still further over the next

decade.

In general, leases in southern Wyoming

and the Wyoming portion of the Powder River

basin are closer to rail lines than leases in the

Montana portion of the Powder River basin.

Rail costs to the Midwest are lower for southern Wyoming coal than for Powder River

basin coal; total delivered price on a per-Btu

basis for southern Wyoming coal is competitive with Powder River basin coal in some

areas, despite the higher mine-mouth cost of

the southern Wyoming coal (see table 28).

Coal slurry pipelines could become an option for transporting coal from the Powder

River basin over the next 10 years but development of slurry pipelines may be constrained by restrictions on water export. One

slurry pipeline company, the Energy Transportation Systems, Inc. (ETSI) has obtained

permission from Wyoming to export water.

This pipeline is planned to have a capacity of

25 million tons per year. However, the State

of Montana has decided that use of water for

slurry pipelines is specifically not a beneficial use of water.

Lignite, which is mined in the Fort Union

region, has a low-Btu value, high moisture

content, and large concentrations of impurities. Consequently, the Federal coal mined in

this region will generally be used close to the

mine site. The characteristics of the lignite

render its transportation both difficult and

costly, requiring special hopper cars and spe-
146 ● An Assessment of Development and Production Potential of Federal Coal Leases

cial facilities for loading and unloading.

Despite its poor quality, however, lignite has

proved to be an acceptable fuel when used in

properly designed, coal fired units. All powerplants currently planned or under construction in North Dakota will use lignite

onsite.

Development Status of Federal Coal

Leases in North Dakota, Montana,

and Wyoming

There are 68 leases in 33 approved mine

plans in the Federal coal regions of North

Dakota, Montana, and Wyoming (table 48).

These leases cover about 149,000 acres and

contain 5.7 billion tons of recoverable

reserves. Nearly 70 percent of the leases in

currently approved mine plans in this threeState area (47 leases in 23 mine plans) are

located in Wyoming. These Wyoming leases

cover about 110,000 acres and include 4.7

billion tons of recoverable reserves. The

Powder River basin of Wyoming contains 24

of these 47 leases in 12 mine plans on about

56,000 acres with 4.4 billion tons of recoverable reserves. Twelve leases in five approved

mine plans are located in the Montana portion of the Powder River basin. These 12

leases cover over 29,000 acres and contain

0.8 billion tons of recoverable reserves.

Nine Leases are included in six pending

mine plans in North Dakota and Wyoming. No

leases are in pending mine plans in Montana.

The five Wyoming leases in three pending

mine plans will be analyzed with undeveloped

leases.

Sixty leases not in mine plans are located

in North Dakota, Montana, and Wyoming.

The large majority of these undeveloped

leases (47 leases, 26 blocks) are located in

Wyoming. These Wyoming leases cover nearly 96,000 acres and contain 3.6 billion tons of

Table 48.—Acreage and Reserves Under Lease by Development Status

Approved mine plans Pending mine plans No mine plans

Number Number Recover- Number Number Recover- Number Number RecoverOf of able of of able of of

leases

able

plans Acres reserves a leases plans Acres reserves a leases blocks Acres reserves a

North Dakota

Fort Union . . . . . . . . . . . 8 4 8,655 0.12 4 3 5,283 0.10 8 7 4,754 0.05

Total . . . . . . . . . . . . . . . 8 4 8,655 0.12 4 3 5,283 0.10 8 7 4,754 0.05

Total. . . . . . . . . . . . . . . 13 6 30,212 0.83 – – – – 5 4 6,835 0.37

Total . . . . . . . . . . . . . . . 47 23 110,193 4.7 5 3 11,007 0.53 47 26 95,873 3.6

Totals. . . . . . . . . . . . 68 33 149,060 5.7 9 6 16,290 0.62 60 37 107,461 4.0

S = small reserves (zero to 30 million tons)

LM = low to medium reserves (30 million to 100 million tons)

HM = high to medium reserves (100 million to 180 million tons)

H = high reserves (over 180 million tons)

*Powder River basin reserves combined with Kemmerer Field reserves to preserve confidentiality.

**Hanna Field reserves combined with Rock Spring Field reserves to preserve confidentiality. Reserves for the Hanna Field lease are small

a

ln billions of tons.

b

THREE SMALL LEASES IN THE BULL MOUNTAIN/YELLOWSTONE AREA ARE NOT LISTED IN THIS TABLE. THE LEASES COVER 240 ACRES AND HAVE VERY

SMALL RESERVES. ONE LEASE IS IN A PRODUCING MINE. THE OTHER TWO ARE UNDEVELOPED LEASES.

C

TWO SMALL LEASES IN THE BIGHORN BASIN ARE NOT LISTED IN THIS TABLE. THE LEASES COVER 200 ACRES, AND HAVE VERY SMALL RESERVES. BOTH ARE

UNDEVELOPED.

SOURCE: Office of Technology Assessment.
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 147

recoverable reserves. Two-thirds of these

leases (30 leases, 16 blocks) with 3.4 billion

tons of recoverable reserves are located in

the Powder River basin.

Leases With Approved Mine Plans and

Leases in Pending Mine Plans*

Figure 30 shows the lessees’ plans for capacity, total production, and production of

Federal reserves from mines with Federal

leases in North Dakota, Montana, and Wyoming. The dominance of the Powder River

basin is apparent. Although coal production

from Federal mines in each of these regions is

expected to increase in the coming decade,

the greatest increase is expected in the

Powder River basin where, in 1986 total capacity and production of mines with Federal

leases may be six times the total capacity and

production of mines with Federal leases in

southern Wyoming. Production of Federal reserves from these mines in the Powder River

basin could be over 14 times that from Federal reserves in southern Wyoming in 1986.

In 1991, the Powder River basin will continue

to account for the largest capacity and production of coal from Federal mines in these

three States and in all the Federal coal

States.

Table 49 shows the acreage and recoverable reserves of Federal coal leases in approved mine plans in North Dakota, Montana,

and Wyoming and pending mine plans in

North Dakota. (The five leases in pending

mine plans in Wyoming are not included in

this table, because they are analyzed with

undeveloped leases, below. ) Total mine plan

acres in this table refer to the total area permitted for mining as of early 1981. These data

include Federal, State, and private surface

areas used for mining activities and

associated disturbances such as stockpiles,

plant facilities, and buffer zones. Total mine

plan acreage will change as mining operations expand to realize future production

*Five leases in three pending mine plans in Wyoming are

omitted from this section and are discussed in the section

Undeveloped Leases, below.

goals. The total mine plan acreage figures in

table 49 do not include proposed amendments. However, amendments have already

been submitted to the Office of Surface Mining for the expansion of mining activities at

approximately 20 percent of the mines with

Federal leases in Wyoming.

Federal lease acres refers to the surface

acreage under which Federal coal is located.

However, the Federal Government does not

necessarily own all (or any) of the surface

under which Federal coal lies. Thus, it is possible (and is indeed the case at the Caballo

Mine in the Powder River basin) that the Federal Government could own no surface acreage in a mine plan even though most of the

coal produced at the mine is extracted from

Federal reserves. Moreover, not all the acreage of a Federal lease will necessarily be included in a mine plan.

Table 50 identifies the current and projected capacity and production, as reported

by the lessees, for mines with Federal leases

in North Dakota, Montana, and Wyoming.

The portion of production that is expected

from Federal reserves at these mines in the

next 10 years is also included in table 50.

As tables 49 and 50 illustrate, the Powder

River basin has the most Federal coal production, the greatest potential capacity, the most

leased and permitted mine plan acreage, and

the largest reserves of any of the major Federal coal regions studied in this report.

Powder River Basin

Twenty-four of the 36 leases in 12 of 17 approved mine plans in the Powder River basin

are located in Wyoming; the remaining 12

leases in five approved mine plans are located in Montana. The large majority of reserves (over 80 percent) are located in the

Wyoming portion of the Powder River basin

as is the largest amount of recent and potential production. Production of coal from mines

with Federal leases in the Wyoming section of

the basin is expected to become more important during the next 10 years. The total capacity of mines with Federal leases in the
148 ● An Assessment of Development and production potential of Federal Coal Leases

Figure 30.—Lessee Projections of Capacity, Total Production, and Federal Production From Mines With

Federal Leases: Fort Union Region, Powder River Basin, and Southern Wyoming

(leases in approved and pending mine plans only)a

1979 80 86 91

A

B

c

1

a

Five leases in three pending mine plans in Wyoming are not included In this figure They are considered with the undeveloped leases later in this chapter

SOURCE: Office of Technology Assessment.

Powder River basin is currently 3.7 times that

of Federal mines in southern Wyoming and 8

times that of Federal mines in the Fort Union

region.

The capacity of mines with Federal leases

in the Powder River basin has not been fully

used in recent years. In 1979, these mines

could have produced 76 million tons more

coal; in 1980, 60 million tons more coal. Mine

capacity is expected to increase by nearly 50

percent between 1980 and 1986 (i.e., from

148 million to 220 million tons) and then remain relatively constant through 1991. This is

because of the opening of several new large

mines (e.g., Buckskin, Coal Creek, Rojo

Caballos) and to the expansion scheduled for

existing mines (e.g., Black Thunder, Eagle

Butte, Rawhide). However, according to the

production estimates of the lessees, the overcapacity of currently operating and permitted Federal mines in the Powder River

basin will diminish to 15 percent in 1986 and

to 3 percent in 1991.

Annual production from Federal reserves

in the Powder River basin is becoming increasingly important, particularly in Wyoming. Federal reserves accounted for only 42

percent of total production from mines with
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 149

Table 49.—Summary of Mine Plan and Federal Lease Acreage and Recoverable Reserves:

Approved and Pending Mine Plans in North Dakota, Montana, and Wyominga

Num- Total mine Federal mine Total Federal

Num- ber Total Total plan reservesb

plan reservesb

lease reservesb

ber of mine Federal – -- — – .—

of mine plan lease Under- Under- UnderState/region leases plans acres acres groundc Surface Total groundc Surface Total ground c Surface Total

Approved

North Dakota

Fort Union . . . . . . 8 4 — 8,655 0 0.14 0.14 0 0.06 0.06 0 0.12 0.12

Montana

Fort Union . . . . . . . 1 1 — 960 0 s s 0 s s o s s

Fort Union totals. . . 9 5 – 9,615 0 – — 0 – – 0 <0.15 <0.15

Montana

Powder River

basin ., . . . . . . . . 12 5 19,080 29,252 0 0.48 0.48 0 0.40 0.40 0 0.8 0.8

Wyoming

Powder River

basin . . . . . . . . . . 24 12 83,141 55,681 0 4.5 4.5 0 4.2 4.2 0 4.4 4.4

Powder River

basin totals. . . . . . 36 17 102,221 84,933 0 5.0 5.0 0 4.6 4.6 0 5.3 5.3

Southern Wyoming

Hanna Field . . . . . 15 6 57,037 23,927 LM <0.2 -0.2 LM LM 0.07 LM LM 0.07

Rock Springs

Field. ... ... , . . 5 3 66,227 24,983 LM <0.4 0.4 Small <0.18 0.18 Small <0.18 0.18

Kemmerer Field . . 3 2 5,901 5,602 0 0.13 0.13 0 s s o s s

Southern Wyoming

totals . . . . . . . . . . . 23 11 129,165 54,512 LM <0.7 0.7 LM <0.3 0.3 LM <0.3 0.3

Pending

North Dakota

Fort Union . . . . . . . 4 3 – 5,283 Small 0.07 0.07 Small 0.02 0.02 Small 0.10 0.10

a

THERE ARE TWO MINE PLANS WITH FEDERAL LEASES IN PRELIMINARY PERMIT REVIEW IN THE WYOMING POWDER RIVER BASIN, I.E. SOUTH RAWHIDE (1

LEASE) AND ANTELOPE (3 LEASES) AND ONE IN THE ROCK SPRINGS FIELD OF SOUTHERN WYOMING, I.E. , SOUTH HAYSTACK (1 LEASE) NO DECISION IS EXPECTED ON THESE PRELIMINARY REVIEWS UNTIL 1982 BECAUSE OF THE EARLY STAGES OF DEVELOPMENT OF THESE THREE MINE PLANS, DATA FOR THIS

TABLE WERE UNAVAILABLE THESE LEASES ARE CONSIDERED IN THE FOLLOWING SECTION ON UNDEVELOPED LEASES

b

ln billions of tons.

CUnderground mining occurs at the Vanguard #2 Mine in the Hanna Field. When strlppable reserves are depleted at this mine In 1984, underground operations wiII

meet all contractual commitments even though underground reserves are small Underground mining also occurs at the Carbon #1 Mine in the Hanna Field The

Stansbury Mine in the Rock Springs Field, closed early in 1981, was also an underground operation Stansbury may be reopened later in the decade

Key to reserve ratings:

S = small reserves (zero to 30 million tons)

LM = low to medium reserves (30 million to 100 million tons)

HM = high to medium reserves (100 million to 160 million tons)

H = high reserves (over 180 million tons)

NSR = no surface reserves

SOURCE Off Ice of Technology Assessment.

Federal leases in the basin in

Federal reserves will account

1979. By 1991,

for 92 percent

of production from Federal mines averaged

over the Powder River basin and almost 100

percent of production from Federal mines in

the Wyoming section of the basin.

Southern Wyoming

Twenty-three Federal leases in eleven approved mine plans are located in southern

Wyoming. These mine plans include over

129,000 permitted acres and contain 0.7 billion tons of recoverable reserves, of which

only 0.3 billion are Federal. Recoverable

reserves at three mines, Vanguard No. Z, Carbon No. 1 and Stansbury,* are suitable for

underground mining. The capacity of mines

with Federal leases in southern Wyoming is

expected to decrease 12 percent by the end of

the decade, although production is expected

to increase by 26 percent during this period.

Utilization of capacity is expected to increase

from 58 percent in 1979 to 83 percent in

1991. Federal reserves are expected to ac-

*Slansbury closed early in 1981 but is expected 10 reopen

later this decade.
150 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 50.—Federal Mine Capacity and Federal Mine Production Prospects: Approved and Pending Mine Plans

in North Dakota; Approved Mine Plans in Montana and Wyominga

1979b 1980b1986b1991b

Number Number

of mine of Actual Actual Projected Projected e

plans Federal Federal Federal Estimate Projected Federal ProjectedeProjected Federal Projectede

with leases in Federal mine Federal Federal mine of Federal mine Federal Federal mine Federal

Federal these mine produc- production mine produc- Federal mine produc- produc- mine produc- producIeases plans capacity tion only capacity tion production capacity tion tion capacity tion tion

North Dakota

Fort Union(A) c 4 8 10 8.5 1.0 10 8.9 0.6 13 12 3 13 12 3

Fort

Union(P) d

3 4 7 5.6 0 7 7.0 0 17 15 2 23 20 3

Montana

Fort Union 1 1 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3

Fort Union

totals 8 13 18 14 1.3 18 16 0.9 30 27 ~ 6 35 32 ~ 6

Montana

Powder River

Basin 5 12 36 27 8 36 25 10

Wyoming

52 46 29 52 49 31

Powder River

Basin 12 24 112 45 22 112 63 —f 169 144 142 175 170 170

Powder River

Basin totals 17 36 148 72 30 148 8 8 – 220 191 171 226 219 201

Hanna Field 6 15 14 10.7 4 14 9.0 – 11 10 4 9 8

Rock Springs

3

Field 3 5 19 7.2 4 19 10.4 — 18 13 7

Kemmerer

19 15 7

Field 2 3 7 5.1 0.1 7 5.7 – 7 6 1 7 6 2

Southern

Wyoming totals 11 23 40 23 8 40 25 —f 36 29 12 35 29 12

aFIVE LEASES IN THREE PENDING MINE PLANs IN WYOMING ARE NOT INCLUDED IN THIS TABLE. THEY ARE CONSIDERED WlTH THE UNDEVELOPED LEASES IN

TABLE 53. THERE ARE NO PENDING MINE PLANS IN MONTANA. ONE SMALL MINE IN THE BULL MOUNTAIN/YELLOWSTONE REGION OF MONTANA IS NOT INCLUDED IN THIS TABLE.

bALL PRODUCTION AND CAPACITY ESTlMATES IN MILLIONS OF TONS PER YEAR; TOTALS MAY NOT ADD BECAUSE OF ROUNDING. SEE SECOND FOOTNOTE ON

P. 114 FOR DISTINCTION BETWEEN FEDERAL MINE AND FEDERAL PRODUCTION. FEDERAL MINE PRODUCTION INCLUDES FEDERAL PRODUCTION.

cApproved mine plans.

d

pending mine plans.

eWith few exceptions. these production pprotections are derived from lessees’ mine plans, fTotal Federal coal production in Wyoming in 1980 was 33 million tons.

SOURCE: Office of Technology Assessment.

count for about 40 percent of production

through 1991 in the Hanna Field; approximately 50 percent in the Rock Springs Field;

and about 15 to 30 percent in the Kemmerer

Field.

Fort Union Region

Nine leases in five approved mine plans

are located in the Fort Union region of North

Dakota and Montana. Eight of these leases in

four approved mine plans located in North

Dakota contain 0.12 billion tons of recoverable reserves. The one lease in an approved

mine plan in Montana has small recoverable

reserves.

In 1979, mine capacity for the North

Dakota leases in approved and pending mine

plans was 17 million tons per year; for the

one Montana lease, only 300,000 tons per

year. Annual production from these mines in

1979 was 14 million tons per year, of which

about 1.3 million tons was from Federal

reserves.

The contribution of Federal reserves to

total production from mines with Federal

leases in North Dakota is small because usually the Federal coal was leased in order to

“fill out” a logical mining unit containing

large amounts of non-Federal coal. Only 25

percent of the coal reserves in North Dakota

are owned by the Federal Government—the

lowest percentage of federally owned coal in

the six major Federal coal States. Moreover,

several Federal leases in North Dakota have
Ch. 6—Development Potential and Product/on Prospects of Federal Coal Leases ● 151

either been mined out or are close to being

mined out,

Most of the increase in total production

and Federal production from Federal mines

in North Dakota over the next decade is expected from mines currently in pending

plans. By 1991 the capacity of mines with

Federal leases in the Fort Union region is estimated at about 35 million tons per year. Total

production could increase to 32 million tons

per year, but production of Federal reserves

will be a comparatively small proportion of

this total (about 6 million tons).

Undeveloped Leases

Table 51 presents acreage and reserves information for the undeveloped leases in North

Dakota, Montana, and Wyoming. The Wyoming portion of the Powder River basin contains 65 percent (nearly 77,000 acres) of the

total acreage and contains over 85 percent

(3,9 billion tons) of the recoverable reserves

for the undeveloped leases located in these

States. There are only about 80 million tons of

underground recoverable reserves on undeveloped leases in these three States; all are

located in southern Wyoming.

Assessing the Development Potential of

Undeveloped Leases in North Dakota,

Montana and Wyoming: Review of

Property Characteristics

Environmental, transportation, and market

factors were reviewed to assess the development potential of undeveloped leases in

North Dakota, Montana, and Wyoming. However, before considering these factors, OTA

reviewed information on the reserves, coal

quality, and geologic features of these leases.

This section summarizes the property characteristics of undeveloped leases in this threeState area. The review of the property characteristics of undeveloped leases emphasized

the following four questions: 1) does the tract

form a viable mining unit (i.e., is it compact

and contiguous)? 2) does the tract have sufficient reserves to support an economical

mine? 3) is the coal of suitable quality for current or potential markets (i. e., heat content

Table 51 .—Acreage and Reserves of Undeveloped Leases:a

North Dakota, Montana, and Wyoming

Tota l

b

Total Total recoverable Tota l

b

Tota l

b

number of Total number Federal underground recoverable recoverable

State/region leases of lease blocks acres reserves surface reserves reserves

North Dakota. . . . . . . . . . . . . . . 8 7 4,754 0 0.05 0.05

Fort Union . . . . . . . . . . . . . . . 8 7 4,754 0 0.05 0.05

Montana 5 4 6,834 0 0.37 0.37

S = small reserves (zero to 30 million tons)

LM = low to medium reserves (30 million to 100 million tons)

HM = high to medium reserves (100 million to 180 million tons)

H = high reserves (over 180 million tons)

a

lNCLUDES FIVE LEASES IN THREE PENDING MINE PLANS IN WYOMING. SEE TABLE 48 FOR THE ACREAGE AND RESERVES OF THESE FIVE LEASES EXCLUDES

FOUR SMALL LEASES, TWO IN WYOMING AND TWO IN MONTANA. SEE FOOTNOTES b AND C, TABLE 48.

b

ln billions of tons.

SOURCE: Office of Technology Assessment.

84-141 0 - 81 - 11 : Qt. 3
152 ● An Assessment of Development and Production Potential of Federal Coal Leases

not too low, sulfur and ash not too high)? and

4) are the coal seams sufficiently thick and,

where surface mines are involved, is the ratio

of overburden to seam thickness sufficiently

low to be economically minable?

Powder River Basin and Southern Wyoming.

—The following technical criteria were used

in OTA’s examination of the property characteristics of undeveloped leases in the Powder

River basin and the coalfields of southern

Wyoming.

There are three major uses for Western

coal—offsite electric power generation, onsite electric power generation, and, potentially, synfuels production. For export steam coal

in the Powder River basin and southern Wyoming, a mine needs to produce at least 1

million tons a year for a 30-year period. Thus,

the minimum reserve requirement for a mine

developed for export steam coal in these

areas was set at 30 million tons.

Four million tons of annual production are

generally required for 30 years (120 million

tons of recoverable reserves) to supply an onsite electric generation plant (l,000 MW).

Production of at least 6 million tons per year

for 30 years (180 million tons of recoverable

reserves) was set as the minimum requirement for the development of a mine for onsite

synfuels production.

Because of high transportation costs, coal

produced in these two regions for export outof-State should have an average heat content

of 8,000 Btu/lb for surface mines and 10,000

Btu/lb for underground mines. Coal with a

lower heat content could be mined for onsite

power generation or synthetic fuels production, but would be uneconomical to transport

over any distance.

The 1970 and 1979 New Source Performance Standards (NSPS) for S02 were used as

a basis for evaluating the sulfur content of

coal in the Powder River basin and southern

Wyoming. Generally, coal with less than 0.63

lb sulfur/million Btu will meet the NSPS without scrubbing, assuming 95 percent conversion of sulfur to SO2

. Sulfur content of less

than 1.0 lb sulfur/million Btu will meet the

1979 NSPS requirement with partial scrubbing. Coal used onsite may have a higher

sulfur level, but it should not exceed 2.0

lbs/million Btu in order to meet Wyoming’s

emission standard of 0.2 lb of S02 p e r

million/Btu.

Ash is less critical than sulfur in the

assessment of coal quality in Montana and

Wyoming, but a high ash content can raise

the cost per Btu of transporting coal to other

States to an uneconomical level. Coal for export in the Powder River basin should have a

maximum ash content of 10 percent; in southern Wyoming maximum ash content can be

12 percent since this coal usually has a

higher heat content. Ash levels greater than

12 percent were considered acceptable for

onsite conversion.

The seam thickness in existing mines in the

Powder River basin ranges from 35 to 110 ft.

Twenty ft was considered the minimum seam

thickness for a developable property in the

Powder River basin. The minimum seam

thickness in southern Wyoming was set at 15

ft for surface mines and at 5 ft for underground mines.

Seam dip is not especially important in the

Powder River basin since seams in this region

are relatively flat. However, seam dip is an

important factor in mine development in

southern Wyoming where coal seams dip as

much as 900. While surface mines can be developed with a seam dip up to 250, 13°, to 15°

is considered the maximum seam dip for efficient coal recovery in underground mines.

Maximum average overburden thickness

for coal mined in the Powder River basin is

usually less than 130 ft. The maximum stripping ratio for this coal is usually 2.5. A maximum average overburden of 175 ft and a

maximum average stripping ratio of 3.5 was

considered acceptable for mines that will use

coal onsite.

Fort Union Region.— Federal coal leases in

the Fort Union region are rarely contiguous

units or contiguous with one another. A single
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 153

lease in the Fort Union region is often divided

into several different tracts interspersed

with fee coal. For this reason a company

rarely acquires a Federal lease in North

Dakota when it does not control the mining

rights of the intervening coal property or

lease sections. In addition, the minimum

reserves required for mine development are

rarely found in any one Federal coal lease.

While this can and does occur in other States,

in North Dakota it is the rule. Furthermore,

variations in coal quality characteristics

such as heat content are relatively unimportant in North Dakota because all the coal is of

such quality that, in general, only development for use onsite or at a nearby facility is

practical.

Limitations of Property Characteristics as a

Measure of Development Potential.—Undeveloped leases with unfavorable property characteristics usually were found to have unfavorable development potential; similarly,

leases with favorable property characteristics usually were found to have either favorable or uncertain development potential.

However, in some cases other factors caused

a different classification. Several illustrative

examples are discussed below.

Lessee plans to incorporate the lease

into an approved mine plan or existing mining operation.—In the Powder River basin,

the Phillips Creek (1) lease block in Converse

County, Wyo., has coal of low heat content

and high ash content in thin seams. Nevertheless, it is adjacent to the Dave Johnston

Mine which is scheduled to deplete its reserves in the late 1990’s. The lease block was

recently acquired by the Pacific Power &

Light Co. (PPL) from SunEDCo and is likely to

be integrated into the Dave Johnston logical

mining unit. However, the Phillips (2) lease,

recently acquired by the same lessee, and

with similar poor property characteristics, is

unlikely to be developed by itself and is

unlikely to be integrated into an established

mining operation.

Lessee plans to develop a synthetic fuels

facility or onsite power generation.—Because of low heat content and high sulfur and

ash, the Cherokee lease in southern Wyoming

will probably not be developed to export coal

to other States. However, the lease has sufficient reserves to support either an onsite synfuels project or electric generation plant. The

site may eventually support both operations,

since a synfuels project and a powerplant

have been proposed by the lessee. The Cherokee lease, therefore, has favorable development potential contingent on the construction

of a facility onsite to use the coal.

Lessee integrates the lease with non-Federal coal.—The two CX Ranch leases in the

Montana portion of the Powder River basin

both have small Federal reserves; without additional coal, neither of these leases would be

likely to be developed. However, the lease

held by Consolidation Coal Co. has been integrated with State and private fee coal

already held by the company, and Consolidation is proposing an exchange of Indian coal

for unleased Federal coal adjacent to the

area. The transfer may be completed by the

end of 1984. Because of these additional reserves, the lease has favorable development

potential.

The other lease, held by Peter Kiewit Sons,

Inc., also has been integrated with good quality fee coal and also has favorable development potential.

Other considerations.— Some undeveloped

leases have unfavorable development potential even though they have excellent quality

coal. For example, the Deadman lease includes some of the highest quality coal in the

State of Wyoming; it has high heat content,

low sulfur and ash, and adequate seam thickness. However, the Deadman lease lacks the

reserve base needed to develop an economical new mining operation and is located

in an area isolated from adequate transportation. Furthermore, underground mining

operations required to develop this lease

would be difficult because the seams on the

lease dip as much as 250. For these reasons,

the development potential of this lease is unfavorable despite high coal quality.
154 ● An Assessment of Development and Production Potential of Federal Coal Leases

Results of Analysis of Development

Potential

Table 52 summarizes the development potential of the 65 undeveloped leases (40

blocks) in North Dakota, Montana, and Wyoming. This total includes the 5 leases in pending mine plans in Wyoming which were analyzed as undeveloped leases. Thirty-eight

leases (18 blocks) in this three-State area

have favorable development potential. These

leases contain 3.5 billion tons of recoverable

reserves and cover over 69,000 acres. Eleven

leases (eight blocks) in these States have uncertain development potential. These leases

account for over 760 million tons of recoverable reserves and cover over 37,000 acres.

Finally, 16 leases (14 blocks) in these States,

covering over 11,000 acres have unfavorable

development potential. However, the 310 million tons of recoverable reserves associated

with these leases are less than 10 percent of

the recoverable reserves contained on the 38

leases with favorable development prospects.

The Wyoming portion of the Powder River

basin has the most reserves on undeveloped

Table 52.—Summary of Development

Federal coal leases in this area. The 3.9

billion tons of undeveloped recoverable Federal reserves in the Wyoming portion of the

basin is nearly seven times larger than the

combined undeveloped Federal reserves of

southern Wyoming and the Fort Union region

and about 40 times larger than the undeveloped Federal reserves in the Montana portion

of the basin. Furthermore, less than 1 percent

of the undeveloped reserves in the Wyoming

portion of the Powder River basin have unfavorable development potential and over 80

percent have favorable development potential. The leases with unfavorable development potential in the Wyoming portion of the

Powder River basin have poor property characteristics and little chance of being integrated with another coal property. The owners of the leases have given no indication that

they will be developed. Two of the leases are

authorized for trade under provisions of Public Law 95-554. * The undeveloped reserves in

the Wyoming portion of the Powder River

*See ch. 9 for a discussion of exchanges.

Potential of Undeveloped Leases: .

North Dakota, Montana, and Wyominga

Favorable development potential Uncertain development potential

Number Number

Number of Recover- Number o f RecoverOf lease able of lease able

State/region leases blocks Acres reserves c leases blocks Acres reserves c

North Dakota. . . . . . . 1 1 320 s 3 2 3,912 LM

Fort Union . . . . . . . 1 1 320 s 3 2 3,912 LM

Unfavorable development potential a

Number

Number of RecoverOf lease able

leases blocks Acres reservesc

4 4 522 s

4 4 522 s

Totals. . . . . . . . . . . . . 38 18 69,145 3.5 11 8 37,878 0.76 16 14 11,446 0.31

aTWO SMALL UNDEVELOPED LEASES IN THE BIGHORN BASIN OF WYOMING AND Two SMALL UNDEVELOPED LEASES IN THE YELLOWSTONE/BULL MOUNTAIN

AREA OF MONTANA HAVE BEEN OMITTED FROM THIS TABLE AND THE FOLLOWING DISCUSSION. THE LEASES HAVE VERY SMALL RESERVES AND UNFAVORABLE DEVELOPMENT POTENTIAL.

S = small reserves (zero to 30 million tons)

1 M = low to medium reserves (30 million to 100 million tons)

HM = high to medium reservs (100 million to 180 million tons)

H = high reserves (over 180 million tons)

b

FIVE LEASES IN THREE PENDING MINE PLANS IN WYOMING (FOUR LEASES IN Two PENDING PLANS IN THE POWDER RIVER BASIN AND ONE LEASE IN THE

KEMMERER FIELD) ARE INCLUDED IN THIS TABLE. ALL HAVE FAVORABLE DEVELOPMENT POTENTIAL. SEE TABLE 48 FOR THE ACREAGE AND RESERVES OF

THESE LEASES.

C

ln bllions of tons

SOURCE: Office of Technology Assessment
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 155

basin represent a substantial pool of new

coal production for the 1980’s.

The three coalfields with Federal coal

leases in southern Wyoming have 18 undeveloped leases (11 blocks), covering 30,000

acres and containing nearly 300 million tons

of recoverable reserves. Less than 10 percent

of these reserves, in six small leases with

poor property characteristics, have unfavorable development potential.

Ten undeveloped leases are located in the

Fort Union region. These leases cover 9,850

acres and contain over 0.3 billion tons of recoverable reserves. Two leases with unfavorable development potential in the Montana

portion of the Fort Union region contain most

of these reserves. Of the four leases with unfavorable development prospects in the North

Dakota portion of the region, two were mined

out before passage of the Surface Mining

Control and Reclamation Act of 1977. Since

no mine plan was submitted to the Office of

Surface Mining they were classified as undeveloped. The lease with favorable development potential (located in the North Dakota

portion of the Fort Union region) has very

small reserves of leonardite, an oxidized form

of lignite. Development of two of the three

leases with uncertain development potential

hinges on the availability of adequate transportation (see ch. 8).

Production Prospects for Undeveloped

Leases With Favorable and Uncertain

Development Potential

Table 53 summarizes the production prospects of undeveloped leases with favorable or

uncertain development potential in North

Dakota, Montana and Wyoming. Production

from leases with unfavorable development

potential is assumed to be zero through 1991.

Under favorable* market conditions, currently undeveloped leases in Wyoming, Montana, and North Dakota could produce nearly

78 million tons of coal in 1991. Nearly 65 million tons of this production, or over 80 per-

*See ch. 5 for a discussion of these conditions.
156 . An Assessment of Development and production Potential of Federal Coal Leases

cent, could come from the Powder River

basin. Under weak market conditions, production from currently undeveloped leases in

the three-State area is likely to be only about

21 million tons in 1991, with about 17 million

tons (81 percent) coming from the Powder

River basin.

The wide range of 17 million to 65 million

tons in estimated production from Powder

River basin undeveloped leases in 1991 is

caused by demand uncertainty. Delivery of 17

million tons of coal in 1991 from presently

undeveloped leases in the Powder River basin

has been contracted for; markets would have

to be developed for the rest. All leases with

uncertain development potential in the Powder River basin have unfavorable production

prospects for 1986 and 1991 (see ch. 7).

In southern Wyoming, production from 12

presently undeveloped leases is estimated to

range between 4 million and 12 million tons

by 1991. The lower production could be

achieved by 1986; much of the remainder depends on the pace of development of a

planned synfuels facility. Presently undeveloped leases will be the only source of new

Federal mine capacity in southern Wyoming.

A Federal mine containing a small leonardite lease in North Dakota may be producing

50,000 tons per year by 1991, and one lease

block in North Dakota with uncertain development potential because of transportation

uncertainties may be producing up to 1 million tons per year by 1991.

Diligence

Diligent Development Analysis

The Mineral Leasing Act of 1920 provides

that each Federal coal lease is held subject to

the conditions of diligent development and

continuous operation. In 1976, DOI issued

regulations defining diligent development for

Federal coal leases as actual production of

coal in commercial quantities from the lease

or from the logical mining unit (LMU) of which

the lease is a part by June 1, 1986 or within

ten years after the lease is issued, whichever

is later. Leases that do not meet this minimum

production requirement can be canceled.

Under certain conditions, the period for producing the minimum amount for achievement

of diligence can be extended for up to 5 years

to June 1, 1991, for leases issued before

passage of FCLAA.

Enforcement of DOI's diligent development

requirements for pre-FCLAA leases is an important issue in the management of existing

leases, not only because of the controversy involving the applicability of the regulations,

but also because of the potential administrative requirements on DOI in handling requests for extensions or approvals of enlarged LMUS, and cancellations. Moreover,

after 1986, new Federal leases cannot be

issued to any lessee, including a pre-FCLAA

lessee, who is holding a lease from which he

has not produced coal in commercial quantities during the previous 10 years,

OTA made a rough comparison of its estimates of future production from Federal

leases with DOI’s diligent production requirements to determine: 1) how many leases are

likely to meet diligence by 1986, and 2) assuming that extensions were granted in many

cases under the existing guidelines, the likelihood for other leases meeting diligence by

1991. The following sections summarize

briefly the results of OTA’s diligence analysis. See chapter 9 for a description of the

issues related to current diligent development

regulations.
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 157

Comparison of Production From

Federal Leases and Diligent

Development Requirements

OTA compared the planned and estimated

production from existing Federal leases with

the minimum production requirements set by

the 1976 DOI regulations defining diligent development for pre-FCLAA leases. The analysis covered the 502 leases in the Southern

Rocky Mountain and Northern Great Plains

regions including about 30 post-FCLAA

leases issued as production maintenance,

hardship, or bypass leases associated with

active mines. * Almost all of these postFCLAA leases will meet diligence as part of

the larger mining operations,

OTA used mine plan data and information

from mine operators and Government agencies. Each approved or pending mine plan or

each undeveloped lease block was considered

to be an approximate logical mining operation. (The term approximate logical mining

operation was used so as not to confuse mine

plan and lease block units with designated or

approved LMUS as defined by DOI regulations.) In assessing a lessee’s prospects for

meeting diligence, OTA used the Federal

mine production estimates presented earlier,

In deriving these production estimates, OTA

considered many variables that could, in

turn, affect the lessee’s ability to meet diligence, such as the amount and quality of reserves, mine type, transportation availability,

and present and projected coal demand (see

ch. 2 of this report for further discussion of

the methodology used in reaching production

estimates).

In conducting this analysis, OTA made the

following assumptions:

1. The mining operations will meet the

mine plan production schedules or, if no

mine plan is available, the mining operations will meet OTA’s estimated production schedule. OTA estimated the earliest feasible year for commercial production for leases without plans.

*See the Oklahoma section at the end of this chapter for a

discussion of diligence prospects for Oklahoma leases.

2.

3.

The reserves and production from the

approximate logical mining operations

(either the total mine plan area or the

Federal lease block) were used in assessing prospects for meeting diligence.

Mines were presumed to meet diligence

for all Federal leases in the unit if they

produced at least 21⁄2 percent of the

total mine plan reserves by 1986 or

1991. (Without detailed information on

the mining sequence and geometry for

each mine, OTA was not able to calculate compliance on a lease by lease

basis).

All leases with planned production and

those undeveloped leases with favorable

or uncertain development prospects that

are likely to start producing in 10 years

were assumed to receive extensions of

the diligence period to 1991 if they did

not produce enough to meet diligence by

1986. Under current diligence guidelines, some mines, particularly smalland medium-sized underground operations producing under 2 million tons

per year, might have difficulty qualifying

for extensions. Nevertheless, it was

assumed for purposes of this analysis

that they would be able to negotiate an

extension. OTA estimates that the number of new mines and leases that are

likely to be producing by 1991 and that

could not qualify for an extension under

a broad interpretation of the diligence

guidelines is very small,

The results of OTA’s analysis for leases in

the six major Western Federal coal States

are described in the following sections.

Diligent Development in Colorado,

New Mexico, and Utah

Southern Rocky Mountain region States

(Colorado, New Mexico, and Utah) have 360

Federal coal leases. Over 60 percent (221

leases) of the leases in this region are included in currently approved or pending mine

plans. Of the remaining 139 leases without

mine plans, OTA’s analysis identified 96

leases that potentially could be producing by
158 . An Assessment of Development and Production Potential of Federal Coal Leases

1991. The results of OTA’s diligence analysis

are summarized in table 54 and figure 31.

The analysis shows that by 1986, all 113 of

the leases in approved mine plans, 22 leases

in pending mine plans and one undeveloped

lease will probably have satisfied the production requirements for diligence. By 1991

another 110 leases could possibly meet diligence, assuming that the lessees receive extensions to the diligence period. A total of 246

leases, (68 percent of the leases) with 73 percent of the Federal lease reserves in the

Southern Rocky Mountain region could meet,

or surpass, the production requirements for

diligence by 1991.

The percentages of leases and reserves in

each diligence category are relatively evenly

distributed for the region as a whole (see fig.

31), however, there is much less correspondence between reserves and leases meeting

diligence when these percentages are calculated on a State basis, as shown in figure 32.

In Colorado, about 80 percent of the leases

and 93 percent of the lease reserves could

possibly meet diligence; however, half of the

reserves contained in only 26 percent of the

leases are uncertain to meet diligence because of uncertainties in the pace and scale

of proposed development. The 19 percent of

the leases in Colorado that are unlikely to

meet diligence contain only 7 percent of the

Federal lease reserves.

In New Mexico, nine leases, 31 percent of

the leases in the State, are unlikely to meet

diligence. These leases, however, contain less

than 1 percent of the Federal lease reserves.

Thus, in New Mexico, 69 percent of the leases

with over 99 percent of Federal reserves

under lease are expected to meet diligence.

In Utah, about 40 percent of the leases in

the State and 44 percent of the lease reserves

are unlikely to meet diligence by 1991. Most

of the lease reserves (1.4 billion tons) in Utah

that will not meet diligence are contained in

61 leases on the Kaiparowits Plateau that

could be producing by 1991 but which are unlikely to do so and, in any event, will not have

produced enough to meet diligence by 1991.

Most of the leases and reserves in active, proposed, or potential new mines in central Utah

(95 leases—roughly 46 percent of leases and

reserves in the State) will probably achieve

diligence by 1991.

Table 54.—Analysis of Prospects for Meeting Diligent Development Requirements by 1986 or 1991:

Federal Leases, Mining Units, and Recoverable Reserves in Colorado, New Mexico, and Utah

(all reserves in millions of tons)

Likely to achieve Likely to achieve Uncertain to achieve Unlikely to achieve

diligence by 1986 diligence by 1991 diligence by 1991 diligence by 1991

Number Number Number Number Number

Number of Recov- Number of Recov- Number of Recov- Number of Recov- Number of RecovOf mining erable o f mining erable o f mining erable o f mining erable o f mining erable

State leases units reserves leases units reserves units reserves leases units reserves leases units reserves
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 159

Figure 31 .— Diligent Development Summary for

the Southern Rocky Mountain Region

(percent of reserves)

Number

of

leases

136

15

95

114

Percent

of

leases

36

4

26

32

Reserves a

2.0

0.3

2.0

1.6

Percent

of

reserves

34

5

34

27

SOURCE: Office of Technology Assessment

Leases That Are Likely To Meet

Diligence by 1986

In the Southern Rocky Mountain States,

136 leases with a total of 2 billion tons of Federal reserves—about 34 percent of the Federal reserves under lease in the region— are

likely to have met diligence by 1986. All of the

mines are expected to meet continuous operations requirements and to be mined out within

40 years at planned production rates.

According to projected production schedules contained in the mine plans, all of the

113 leases included or associated with the 35

mines with approved mining plans will have

met diligence for the total mine plan reserves

by June 1, 1986. Many, if not most, of these

mines have already produced this amount

and many of the individual leases have, in

fact, already produced enough to meet diligence. In those cases where leases have not

produced the minimum amounts by 1986, the

lessees could either request extensions or approval of enlarged LMUs combining both currently producing and nonproducing mine

areas so that aggregate production can be

used to meet the diligence requirement.

Another 22 leases in 10 pending mine plans

are also likely to achieve diligence by 1986

according to mine plan production schedules.

One currently undeveloped lease in Colorado

is expected to begin production before 1986

and thus, will meet diligence. It is possible

that other undeveloped leases could achieve

diligence by 1986 by inclusion with DOI approval in adjacent active mining units owned

by other lessees through assignment or operating agreements. This would involve fewer

than 10 leases in the Southern Rocky Mountain region because of the requirement that

all areas in an approved LMU must be

contiguous.

Leases That Are Likely To Meet

Diligence by 1991

By 1991, 15 more leases in eight mines with

a total of 315 million tons of Federal lease

reserves are expected to meet diligence requirements. These eight mines, including six

leases in Colorado, one in New Mexico, and

eight in Utah, represent 4 percent of the

leases and 5 percent of Federal coal reserves

in the region. All of these leases are in proposed mine plans currently under review. At

least three mines are not scheduled to begin

commercial production until 1986 or later.

The eight mines include two small mines that

are being reopened on previously mined

leases, one new, large surface mine, and one

mine that would combine surface and underground recovery methods. Another mine is a

captive operation that would supply a new

powerplant that has been delayed, and still

one other has been suggested by proponents

as one of the suppliers for a proposed coal

gasification plant in Utah. The remaining two
160 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 32.- DiIigent Development Summary for Federal Lease Reserves in Colorado, New Mexico, and Utaha

(Uinta region)

Key

aSee table 54 for amount of reserves.

SOURCE: Office of Technology Assessment.

mines are underground operations that will

sell to utilities and industrial users.

Leases That Are Uncertain To Meet

Diligence by 1991

OTA found that 95 leases in 35 approximate logical mining operations with about 2

billion tons of recoverable Federal reserves

may not meet diligence requirements by 1991.

Roughly 26 percent of the leases and 34 percent of the leased reserves in the Southern

Rocky Mountain region could possibly

achieve diligence by 1991; however, OTA

found that these leases face some uncertainties regarding the pace or scale of proposed

mining activities or in defining the LMU

reserves. There are several reasons why

some of these leases might not meet diligence:

The date of initial production for some mines

is uncertain because of delays in construction

of associated electric powerplants or transportation systems. For several lease tracts

with very large underground reserves in

multiple seams, it is difficult to predict how

many seams will eventually be included in the

LMU reserves, since that determination will,

in part, depend on the sequence of mining.

Perhaps the greatest uncertainty is that the

development plans of several lessees with

large tracts of good quality minable reserves

have not yet been announced. Production

from captive mines that are planned as replacement capacity for existing operations is

dependent on exhaustion of the economically

recoverable reserves in existing mines. In

some cases, the new captive mines are not

contiguous with the existing operations, so

they could not be combined with producing

mines to meet diligence under current law.

Utah has 60 leases that are uncertain to

meet diligence by 1991 including 28 leases in

the proposed Alton surface mine with over

200 million tons of recoverable Federal reserves. The Alton Mine alone contains one
Ch. 6—Development Potential and Product/on Prospects of Federal Coal Leases . 161

quarter of all the leases and 30 percent of the

reserves that are uncertain to meet diligence

in the three-State area. The difficulties in

Alton’s proposed development plans are discussed earlier in the chapter and in the Utah

appendix.

Colorado has 33 leases in 18 units that

might not meet diligence, including two pending mine plans. One of these, Arco’s Mt. Gunnison Mine, has a large amount of recoverable reserves in multiple seams, It is possible

that the logical mining unit reserves could be

defined by the U.S. Geological Survey as less

than the total reserves by including only the

seams commonly mined in the region. If so,

the mine could meet diligence by 1991, and

perhaps, even by 1986, since at least one

lease in the mine has already produced coal,

Leases That Are Unlikely To Meet

Diligence by 1991

Nearly one-third of the leases in the

Southern Rocky Mountain States, 114 leases,

with 1.6 billion tons of Federal reserves in 60

mining units, are unlikely to achieve diligent

development. These include 37 leases that

are in three proposed new mine plans—one

small mine in Colorado and two mine complexes on the Kaiparowits Plateau in Southwestern Utah. Sixty-eight leases that are

unlikely to meet diligence by 1991 are located

in southwestern Utah. A total of 61 Kaiparowits leases in six blocks with 1.4 billion

tons of reserves have some potential for development according to OTA’s analysis, But

even if the lessees began production by 1987

(probably the earliest feasible date), it is

unlikely that they would be able to produce

enough to meet diligence by 1991 because of

the large amount of reserves involved. Moreover, it is unlikely that a new coal transportation system connecting Southwestern Utah

with potential markets will be operational by

1991. The remaining 53 leases in the threeState region are unlikely to meet diligence

because they are unlikely to be mined in the

next decade. These nonproducing leases include many abandoned small mines and other

leases that do not have enough good quality

minable reserves to sustain viable independent mining operations and are not located adjacent to other active mines.

Diligent Development in North Dakota,

Montana, and Wyoming

The results of the analysis on diligent

development are summarized in table 55 for

the coal regions of Wyoming, Montana, and

North Dakota. Figure 33 summarizes the results for the Powder River basin, The first

diligence requirement (production of 21/z percent of LMU recoverable reserves by 1986/

1991) is the only one summarized in the table;

with few exceptions, LMUs which are likely

to meet this requirement appear likely to

meet the additional requirement of continuous operation and appear likely to be mined

out in 40 years.

The diligent development analysis for

Wyoming, Montana, and North Dakota has

reached the following conclusions:

1, Over 60 percent of the leases containing

nearly 70 percent of the reserves under

Federal lease in these three States are

likely to either meet diligence in 1986 or

in 1991,

2. For the Powder River basin, demand for

coal is the dominant factor in whether

leases containing about 1.2 billion tons

of recoverable reserves will meet diligence by 1991.

3. Over 90 percent of the 1.5 billion tons of

4

recoverable reserves contained in leases

unlikely to achieve diligence by 1991 in

the Powder River basin are suitable only

for onsite synfuels development; and

nearly 40 percent (0.6 billion tons) are

suitable only for in situ gasification, assuming that technology is developed.

For southern Wyoming, leases containing most of the reserves should meet diligence by 1986 under expected market

conditions, The principal uncertainty in

whether leases containing essentially all

of the reserves will meet diligence by

1991 is the pace of development of a synfuels project.
162 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 55.—Diligent Development Summary

Unlikely to achieve diligence by

Uncertain 1991

Total Total Federal Likely to Likely to whether will Favorable or

number of lease recover- achieve achieve achieve uncertain Unfavorable

Ieases/ able reserves diligence diligence diligence development development

State/region lease blocks (billions of tons) by 1986 by 1991 by 1991 potential potential

Powder River basin (27/13) (8/4) (8/4) (1 1/5) (4/4)

a

These leases generally have poor development potential because of small reserves, low coal(quality and difficult mining conditions,

bReserves in the Montana and North Dakota portions of the Fort Union region have been combined to preserve confidentiality.

C

ln addition, two leases were mined out before the passage of SMCRA. Because no mine plans were filed for these leases they were classed as undeveloped. Because

no further production will occur from the leases, they have unfavorable development potential. However, because their reserves have been mined out, they have met

diligence already.

S = small reserves (zero to 30 million tons)

LM = IOW to medium reserves (30 million to 100 million tons)

HM = high to medium reserves (100 million to 180 million tons)

H = high reserves (over 160 million tons)

SOURCE: Office of Technology Assessment.

5. In the Fort Union region, all leases in approved and pending mine plans (with

about 40 percent of the Federal reserves

under lease in the region) are likely to

meet diligence by 1986. However, only

one very small undeveloped lease is likely to meet diligence even by 1991. Adequate transportation constitutes an uncertainty in whether two other leases

will meet diligence by 1991.

Powder River Basin

As table 55 and figure 33 indicate, there

are 73 leases in 38 lease blocks in the Powder

River basin of Wyoming and Montana. Federal reserves under lease total 9.2 billion tons

in the Powder River basin, of which 10 percent, or 900 million tons, are in the Montana

portion. Seventy percent of the recoverable

reserves under lease in the Powder River

basin, or 6.5 billion tons, are likely to meet
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases ● 163

Figure 33.— Diligent Development Summary for the

Powder River Basin

The Powder River basin Montana portion of the

73 Leases Powder River basin

38 Lease blocks I 15 Leases

9.2 Billion tons of recoverable I 8 Lease blocks

reserves under Federal lease ! 0.9 Billion tons

I /

I /

Wyoming portion of the

Powder River basin

58 Leases

30 Lease blocks

8.3 Billion tons

Key

Percent

Reserves a

of reserves

5 2 %

1.7 18%

diligence by 1991: 1.2 1 3 %

1 6 %

aBillions of tons.

SOURCE: Office of Technology Assessment.

diligence by 1986 or 1991. Thirteen percent,

or 1.2 billion tons, are uncertain to achieve

diligence by 1991 and 16 percent, or 1.5 billion tons, are unlikely to achieve diligence by

1991,

With two exceptions, the 18 lease blocks in

the Powder River basin likely to achieve diligence by 1986 are associated with producing

mines or are in approved mine plans. With

one exception, all these lease blocks presently have contracts to deliver coal by 1986

or earlier. * Of the four lease blocks** likely

*PPL is conductng a feasibility study to determine whether

or not its Philllps Creek ( 1 ) leases should be integrated with the

Dave Johnston Mine. According to a company spokesman, the

leases are likely to be added to the mine, in which case, even

though the leases themselves are unlikely to be mined until

1991 or later, they would meet diligence as part of the logical

mining unit. North Antelope Coal Co, ’s North Antelope lease

does not yet have an approved mine plan but has a contract for

1984 delivery of coal.

* *South Rawhide, Rochelle, Antelope, Rojo Caballos. In the

case of South Rawhide. the lessee may blend its coal with the

to achieve diligence by 1991 but not by 1986,

only South Rawhide does not presently have

contracts for coal delivery before 1991. (Contracts are one of the criteria for granting diligence extensions).

The six lease blocks*** which are uncertain to achieve diligence by 1991 are all undeveloped; none of them presently has contracts

for 1991. However, all the lease blocks have

favorable development potential, and the

lessees are working to develop their properties. Applications for extensions to diligence

are expected to be filed for all of these blocks.

Five of the six lease blocks are being planned

as large surface mines, with capacities of 5

million tons per year or more, and would thus

probably qualify for a diligence extension

under the second (large mine) extension criterion. The sixth has a planned capacity of 4

million tons per year. However, the level of

demand for Powder River basin coal is an important factor in their achieving diligence. If

demand in 1991 is at the OTA high demand

scenario level of 275 million tons per year, all

of these lease blocks would likely meet diligence by 1991. However, if demand in 1991 is

at the OTA low demand scenario level of 163

million tons per year, it is possible that none

of these lease blocks will even go into production by 1991. (See ch. 7 for a description

of the OTA high and low demand scenarios

for Powder River basin coal.)

Six undeveloped lease blocks are unlikely

to achieve diligence by 1991 even though they

do not have unfavorable development potential. Production on four of these (Lake

deSmet, Bass Trust, Belco, Gulf [l&z)) is contingent on synfuels development; for three of

the four, production is contingent on in situ

gasification development. Although little development activity has occurred on the fifth

output from the existing Rawhide and Caballo Mines, reducing

production at these two mines, if contracts cannot be obtained

for South Rawhide itself. Diligence could then be achieved for

all three mines: for Rawhide and Caballo by 1986: for South

Rawhide by 1991.

***Dry Fork, East Gillette Federal, N. Rochelle, CX Ranch

(Consol), CX Ranch (PKS), Wildcat.
164 ● An Assessment of Development and Production Potential of Federal Coal Leases

(East Wyodak), the lessee (Peabody) has

strongly stated its intent to develop the property. The sixth lease, Pearl, is in Montana.

The lessee, Shell, spent considerable sums on

development, including the preparation of an

environmental impact statement, before suspending activity. Shell declares it will resume

development once markets strengthen. All six

are expected to file for diligence extensions.

Finally, four undeveloped lease blocks with

unfavorable development

likely to meet diligence.

Development

potential are unPotential and

Southern Wyoming

As table 55 states, there are a total of 41

leases in 22 lease blocks in the three coalfields of southern Wyoming. These leases

contain over 500 million tons of recoverable

reserves. Leases containing over 300 million

tons of reserves are likely to achieve diligence

by 1986 and several mines are likely to meet

diligence by 1991. The lease block whose

achievement of diligence is uncertain for

1991 is being planned for synfuels.

Production Prospects of

Federal Coal Leases in Oklahoma

There are 46 Federal coal leases located in

the Oklahoma portion of the Western Interior

coal region; the region also includes the

States of Arkansas, Kansas, Missouri, and

Iowa. There are no Federal coal leases in the

latter four States. Total coal production in

Oklahoma in 1979 was 5 million tons, or 40

percent of total Western Interior production

and over three times the total production of

the State a decade ago. However, Federal reserves accounted for only 0.3 million tons of

Oklahoma production in 1979.

Approximately 80 percent of the leased

Federal coal in Oklahoma is of high metallurgical quality that is used primarily to produce coke for domestic steel production. Virtually all of the increase in Oklahoma coal

production over the last 10 years has been

noncoking coal. Although metallurgical grade

coal can be blended with steam coal to generate electricity, it is unlikely that any new

mines with Federal leases in Oklahoma will

be developed to sell metallurgical quality coal

primarily for blending for steam-electric generation. Weak demand is expected for metallurgical quality coal over the next 10 years.

Captive mining operations, where the parent

company produces steel or cement, and sales

to foreign buyers appear to be the main

source for Federal coal development in Oklahoma throughout the 1980’s.

Status and Production Prospects of

Leases in Approved Mine Plans

in Oklahoma

There are seven leases in five approved

mine plans in Oklahoma (see table 56). One of

the seven leases was relinquished in 1980 because of the increase in royalty at the time of

readjustment. Production on another lease

has been interrupted because of labor disputes. The reserves remaining on this lease

can support less than 5 years of commercial

production. The remaining five leases in approved mine plans or associated with operating mines are currently producing coal or

are scheduled to produce coal in the near

future. However, only two of these leases in

one mine plan are expected to produce coal

continuously over the next 10 years. These

two leases are likely to meet diligence by

1986 or 1991. Of the remaining three leases

in approved mine plans, the reserves on one

are expected to be depleted by 1984, and the

reserves on the other two by 1986.

Status and Development Potential of

Undeveloped Leases and Leases in

Pending Mine Plans in Oklahoma

Thirty-eight leases (20 blocks) of the 46

leases in Oklahoma are not included in mine
Ch. 6—Development Potential and Production Prospects of Federal Coal Leases . 165

Table 56.—Status and Development Potential of

Undeveloped Leases in Oklahoma

Status of leases

Approved mine plans:

7 leases

5 mine plans

8,668 acres

6 million tons recoverable reserves

Underground: 5.4 million tons

Surface: 0.6 million tons

Pending mine plans:

1 lease

1 mine plan

680 acres

Small underground recoverable reserves

No mine plans:

38 leases

20 lease blocks

64,698 acres

179 million tons recoverable reserves

Underground: 169 million tons

Surface: 10 million tons

Development prospects: undeveloped leases

Uncertain development prospects:

23 leases

7 lease blocks

38,334 acres

104 million tons recoverable reserves

Unfavorable development prospects:

15 leases

13 lease blocks

26,360 acres

75 million tons recoverable reserves —

SOURCE. Office of Technology Assessment,

plans (table 56). None of these leases are expected to be brought into commercial production by 1991. The production prospects for

the one lease included in a pending mine plan

are also unfavorable during this period,

although the owner of Federal and fee coal

now being mined near this property has expressed interest in acquiring this lease.

Over 90 percent of the recoverable reserves on undeveloped leases are underground reserves. Twenty-five of these leases

(8 blocks) have uncertain development potential for 1991; the remaining undeveloped

leases have unfavorable development potential for 1991. There are three main reasons

for the unfavorable production prospects of

these leases: 1) a depressed metallurgical

coal market, 2) difficult and costly underground mining conditions, and 3) a high Federal royalty relative to royalties charged for

fee coal in the State.
Chapter 7

The Powder River Basin

“A Case Study”
●
CHAPTER 7

The Powder River Basin: A Case Study

As the preceding chapter has shown, the

Powder River basin of Wyoming and Montana contains the largest pool of undeveloped

leased Federal coal reserves with favorable

development potential in the United States.

Furthermore, the production of Federal

reserves from the Powder River basin now

accounts for about half of all Federal coal

production in the country. Because of the important role of this region in Federal coal production, this chapter examines the Powder

River basin in more detail, The chapter includes a mine-by-mine examination of the

Federal reserves scheduled to be produced

over the next 10 years from currently operating or permitted mines, an analysis of the

production prospects of each undeveloped

lease and preference right lease application

(PRLA) in this region, a discussion of the role

of non-Federal mines in Powder River basin

coal production, a consideration of demand

for Powder River basin coal in the post-1990

period, and an examination of the different

points of view on the large-scale new leasing

of Federal coal scheduled for the Powder

River basin in 1982.

Two Demand Scenarios for the Powder River Basin

In order to evaluate the production prospects of Federal leases in the Powder River

basin, it is necessary to identify the likely demand for Powder River basin coal over the

next 10 years. In this analysis, OTA used a

high demand scenario and a low demand scenario developed for the Powder River basin

case study. This section considers a range of

demand forecasts for Powder River basin

coal, arrives at a “most likely range” of demand for 1985 and 1990, and examines the

assumptions about high and low demand used

in the analysis of Federal coal production

prospects in this chapter.

Figure 34 summarizes several recent demand forecasts for Powder River basin coal

for 1985 and 1990. 1 The Department of Energy (DOE) and ICF, Inc.’s CEUM (Coal Elec-

‘These demand farecasts are:

1. DOE: Preliminary National and Regional Coal Production

Goals for 1985, 1990, and 1995 [Washington. D. C.: DOE,

Aug. 7, 1980. ) See also: Analysis and Critique of the Deportment of Energy’s August 7, 1980 Report EntitIed: “Preliminary National and Regional Coal Production Goals for

1985, 1990, and 1995. prepared for the Rocky Mountain

Energy Co. (Washington. D. C.: ICF Inc., October 1980).

2. DOE: The 1980 Biennia] Update of National and Regional

coal Production Goals for 1985, 1990, and 1995 (Washington D. C.: DOE, ]anuarv 1981.)

tric Utility Model) use basically the same computer model but vary a number of input assumptions (e.g., the overall growth rate of

electricity demand in the United States) to arrive at three projections each for 1985 and

1990: low, midlevel (or base), and high. The

Silverman forecasts (made for 1990 but not

for 1985) are computer projections based on

a series of different assumptions about electric demand in the market area for Northern

Great Plains coal, the share of that demand to

be met by coal, and the fraction of that share

to be met by Northern Great Plains coal. The

Sebesta and Glass projections are each based

on a detailed examination of utility plans and

3. ICF CEUM: Forecasts and Sensitivity Analyses of Western

Coal Production, prepared for Rocky Mountain Energy Co.

(Washington, D. C.: ICF, Inc., November 1980).

4. Sebesta: Demand for Wyoming Coal 1980-1991 Based Upon

Projected Utility Coal Market and Demand for Montana

Coall 1980-1991 Based Upon Projected Utility Market

(Washington, D. C.: OTA, October 1980).

5. Wyoming task force: Result of deliberations of the OTA

Wyoming task force: Cheyenne, Wyo., October 1980).

6. Glass: Wyoming Coal Production and Summary of Coal

Contracts (Laramie, Wyo.: Wyoming Geological Survey,

1980).

7. Silverman: Preliminary Results from A. Silverman. University of Montana, Missoula. Private communication to

OTA. Work is funded by OSM.

169
170 . An Assessment of Development and Production Potential of Federal Coal Leases

Figure 34.—Powder River Basin Demand Projectionsa

500

400

300

200

100

a

see

bCalc

cCalc

‘For

synf

0

footnote on

ulated by

ulated by

1965 all pro

uels and 

.

Final Preliminaryiminsty

~22 3

193

159

129

iCF

CEUM

194

169

136

Other

.

Demand projections d

1985

(173)

(169

(OTA)

Wyoming

force (OT

Glassc

of

 p. 169 for citations.

adding Sebesta’s figure

adding Sebeata’s figure

jections assume zero d

foreign export demand.

for the

for the

emand

Montana portion of the Powder River basin (66 mmt/yr) to Glass’ figure for the Wyoming portion (133 mmtlyr).

Montana portion of the Powder River basin (49 mmt/yr) to Glass’ figure for the Wyoming portion (120 mmt/yr).

for synfuels and for export to foreign countries from the Powder River basin. For 1990, see the text for a discussion

contracts in the Powder River basin market

area. The Wyoming task force estimate was

reached after a review of the DOE, Sebesta,

and Glass projections. Figure 34 also shows

the DOE final production goals. The DOE final

production goals and their relation to the

preliminary DOE projections and to other demand forecasts are discussed in chapter 5.
Ch. 7—The Powder River Basin: A Case Study ● 171

Demand Projections for 1985

For 1985, demand projections range from

129 million tons per year (the DOE low) to 223

million tons per year (the DOE high). ICF projections range from 138 million tons per year

to 194 million tons per year; these figures

assume that there will be zero demand for

Powder River basin coal for synfuels or for

export to foreign countries.

Although the demand projections for 1985

span a wide range, they cluster in a much

narrower range. The range of 138 million

tons per year to 177 million tons per year includes the ICF low, the DOE preliminary and

ICF mid, and the Glass, Sebesta, and Wyoming task force projections. This range excludes only the ICF and DOE preliminary low

and high projections and the DOE final production goals.

Two other projections, not shown on figure

34, were also examined: the National Electric

Reliability Council (NERC) 2 projections for

total U.S. utility* coal requirements and the

long-term forecast of the National Coal Association (NCA).3 NERC arrives at an electrical

demand growth rate of 3.7 percent annually

and a total domestic steam coal requirement

of 684 million tons in 1985. NCA assumes an

electrical demand growth rate of 3.5 percent

annually and projects total domestic steam

coal demand in 1985 of 727 million tons in its

midlevel projection. By comparison, ICF

assumes an electrical demand growth rate of

3.5 percent annually; its midlevel projection

is for 717 million tons of total domestic steam

coal demand in 1985.

‘Electric Power Supply and Demand, 1981-1990 for the Regional Rehubiiity Councils of NERC: National Electric Reliability y

Council: July 1981. The NERC figures do not explicitly project

demand for Powder River basin coal and must be interpreted

using assumptions about the extent of the Powder River basin

market area and the market share of Powder River basin coal

within the assumed market area. Therefore, NERC projections

are not shown in figure 34.

‘Because 95 percent of Powder River basin coal is purchased by utilities, total utility demand is a good measure of demand for Powder River basin coal in 1985.

‘National Coal Association, NCA Long Term Forecast

(Washington, D. C.: NCA, March 1981].

In the NERC projections, the anticipated

demand in 1985 for Western steam coal (excluding lignite) in the market area for Powder

River basin coal is about 205 million tons.

However, other coal competes in this market

area (see fig. 20). Assuming that the Powder

River basin share of this market in 1985 is the

same as in 1979, i.e., 65 percent, and that 95

percent of the Powder River basin coal will

continue to go to the utility market, the NERC

figures lead to a demand estimate of 140 million tons in 1985 for Powder River basin coal,

However, Powder River basin coal could capture a larger share of Western steam coal demand in its market area in 1985 than in 1979,

OTA High and Low Demand

Scenarios: 1985

OTA selected the Sebesta projection of 177

million tons per year for its high demand scenario for 1985. The Sebesta projection exceeds both the DOE preliminary and ICF midlevel projections, the NERC projections as interpreted above, and the projections of the

Wyoming State Geological Survey (Glass,

1980). The Wyoming task force estimated

1985 demand to be between the Glass and

Sebesta estimates.

OTA selected the ICF low projection of 138

million tons per year for its low demand scenario for 1985, This figure is lower than presently contracted Powder River basin production for 1985 (about 160 million tons per year)

and allows analysis of the implications of a

“worst case” scenario on development and

diligence.

Demand Projections for 1990

For 1990, the projections shown in figure

34 vary widely, and the clustering of projections, although marked, offers less reliable

guidance than for 1985. Projections range

from 163 million tons per year (the ICF low) to

438 million tons per year (the DOE preliminary high), but the range of 163 million tons

per year to 275 million tons per year includes
172 ● An Assessment of Development and Production Potential of Federal Coal Leases

all but the DOE preliminary and ICF high projections and the DOE mid and high final production goals.

For 1990, the projections of Sebesta and

Silverman in figure 34 include only demand

for steam coal. However, the ICF, DOE, and

Wyoming task force projections include demand for coal for synfuel, for export to

foreign countries, and for industrial use.

The ICF midlevel projection includes an estimate of about 10 million tons for synfuels

from Montana and Wyoming and a total demand of 8 million tons of subbituminous low

sulfur coal for foreign export; it is unclear

from the ICF report, however, how much of

this 8 million tons is projected to come from

the Powder River basin. The DOE midlevel

preliminary forecast assumes about 30 million tons of coal from Montana and Wyoming

for synfuels in 1990, and the DOE final production goals assume about 45 million tons of

coal from these two States for synfuels. For

comparison, the ICF base (midlevel) projection estimates a total demand throughout the

country of less than 50 million tons of coal for

synfuels in 1990; the NCA “most likely” projection is 38 million tons. The DOE midlevel

preliminary forecast estimates that about

100 million tons of coal will be used for synfuels production in the United States in 1990;

the DOE final production goals assume about

200 million tons.

The Wyoming task force rated one synfuels

property in the Powder River basin as having

favorable production prospects for 1991—

the Rochelle leaseblock with production projected at 6 million tons per year for 1991. *

Other synfuels properties in the Powder

River basin were judged by the task force as

unlikely to be producing by 1991. This projection is in agreement with the ICF projection of

10 million tons per year from all of Wyoming

and Montana, as another property, Cherokee,

may come into production for synfuels in

southern Wyoming.

*The 1991 production prospects of the Rochelle lease block

have become less favorable since the Wyoming task force meeting in October 1980, because of the withdrawal of two of the

partners in the Panhandle Eastern Wycoal Gas Project, to

which Rochelle’s coal is contracted.

NERC projections, which include only estimates of electric utility demand for coal, are

not shown in figure 34 for reasons explained

in footnote 2 on p. 171. The NERC figure of

881 million tons for total U.S. utility coal demand in 1990 is comparable to the ICF midlevel number of 862 million tons, but is lower

than the DOE preliminary midlevel number of

906 million tons, NCA’s most likely projection

of 935 million tons, and the DOE final midlevel production goal of 994 million tons. If

the Powder River basin captures the same

share of the market for Western steam coal

in 1990 as in 1979, (i. e., 65 percent, ) NERC

figures translate to a demand of approximately 180 million tons for steam coal. Using

the NERC estimated demand for all coal in the

Powder River basin market area as the base,

not just demand for Western coal, demand

for Powder River basin steam coal in 1990

(assuming a 37 percent market share) would

be about 170 million tons. Adding demand for

industrial coal, synfuels, and foreign export,

NERC projections translate to demand for

Powder River basin coal in 1990 of about ZO O

million tons, assuming the Powder River

basin market share of Western coal and of all

coal remains the same in 1990 as in 1979.

The Powder River basin share of the steam

coal market may expand over the next decade. Assuming all new Western steam coal

demand is for Powder River basin coal in the

Powder River basin market area, but that the

old demand for Western steam coal retains

its 1979 split between Powder River basin

and non-Powder River basin coal, NERC projections translate to a demand estimate for

Powder River basin coal in 1990 of approximately 255 million tons for all uses. * * NERC

projections, interpreted as described above,

give a range of demand for Powder River

basin coal in 1990 of about 200 million to

about 255 million tons; these calculations suggest that the DOE preliminary midlevel goals

are high. * * *

* *Including demand for industrial uses (5 percent addition

to utility demand), synfuels and foreign export (about 10 million tons per year).

* * *The same calculations using NERC’s projections for utility Western coal demand published 1 year earlier, in July 1980,

lead to a demand range of 235 million to 305 million Ions for
Ch. 7—The Powder River Basin: A Case Study ● 173

OTA High and Low Demand

Scenarios: 1990

For 1990, OTA selected the DOE preliminary midlevel forecast of 275 million tons per

year for its high demand scenario, and the

ICF projection of 163 million tons per year for

its low demand scenario. The Wyoming task

force projection of 206 million tons per year,

representing the estimate of informed regional opinion, falls slightly below the average of these two demand levels. The high scenario level of 275 million tons per year is 33

percent above the Wyoming task force estimate, and the low scenario level of 163 million tons per year is 79 percent of the Wyoming task force estimate. OTA’s selected low

projection is lower than present contracts for

1990 delivery of Powder River basin coal (186

million tons per year) and thus allows analysis of a “worst case” for development and

diligence,

Production Under OTA's Two

Demand Scenarios

The next two sections examine the production prospects of all Federal coal leases in the

Powder River basin for 1986 and 1991. The

first of these sections focuses on the leases included in producing mines or approved mine

plans; the second on undeveloped leases. This

section describes the approach used by OTA

to allocate production under the high and low

demand scenarios.

In its two demand scenarios, OTA allocated potential production among:

1. operating and permitted Federal mines;

2. leases with no mine plans* (undeveloped

leases) but with favorable development

potential; and

3. non-Federal mines.

— .. —-

Powder River basin coal in 1990. The difference between the

demands derived from NERC 1980 and 1981 projections is

caused by the fact that in 1981 NERC projected 50 million Ions

less 1990 demand for Western coal than it did in 1980.

*There are two mines in preliminary permit review in the

Powder River basin (South Rawhide and Antelope). Because of

the early stages of development of these mine plans, these

leases were analyzed with the undeveloped leases.

Under the high demand scenario, demand for

Powder River basin coal in 1985 and 1990 is

above present contracts for those years.

Thus, for all three categories of coal production, present contracts for 1985 and 1990 are

assumed to be met in full under the high demand scenario. Under the low demand scenario, demand for Powder River basin coal in

1985 is about 85 percent of present contracts

for 1985, and about 90 percent of present

contracts for 1990. Thus, under the high demand scenario, all Federal and non-Federal

mines and all undeveloped leases with contracts are assumed to be producing at or

above the current contract level for those

years; under the low demand scenario, they

are assumed to be producing at about 85 to 90

percent of the current contract level for those

years.

For both 1985 and 1990, OTA selected the

ICF low demand projections for its low demand scenarios. For each of these years,

under the low demand scenario, no undeveloped leases without current contracts go into

production. With the exception of three lease

blocks (Antelope, North Antelope, and Rochelle), the undeveloped leases in the Powder

River basin do not yet have contracts. Under

the high demand scenario, many undeveloped

leases would likely go into production by 1990

because demand under this scenario requires

considerably more production than the sum

of current contracts for future delivery of

coal. The difference between demand and

contracts is allocated among currently

operating and permitted Federal mines, nonFederal mines, and undeveloped leases with

favorable production prospects. No production is allocated to leases that, for technical

or economic reasons, are unlikely to be

brought into production by 1990.

A share of the demand increase is assigned

by formula to each Federal mine or undeveloped lease block likely to be producing in

1985 or 1990, with only its projected capacity

and its contracts (if any) entering the calculation, Allocation by formula is arbitrary. Some

lessees will be more successful than others in

competing for new coal contracts. Production

will be higher from some mines than OTA es-
174 ● An Assessment of Development and Production Potential of Federal Coal Leases

timates indicate, and lower from others. In al mines plans under the high and low dethe following section, OTA’s estimates of pro- mand scenarios are compared with the lesduction from operating and permitted Feder- sees’ own estimates.

Federal Leases in Approved Mine Plans and

Operating Mines in the Powder River Basin

This section assesses the production prospects for Federal coal leases in approved

mine plans and operating mines in the Powder River basin. Tables 57 and 58 summarize

technical and production data for each operating or permitted mine with Federal coal

reserves in the Powder River basin. Together,

these tables provide an overview of recent

Federal mine capacity and production in the

basin and expected developments in the coming decade.

Table 57 presents the following information for each mine in the Powder River basin

with Federal reserves:

● lessee;

• number of Federal leases in the mine

plan;

● range of recoverable reserves;

ž permitted mine plan and Federal lease

acreage;

● date of first coal shipments;

Table 57.—Powder River Basin Federal Mine Statistics

Acreage

Total

permitted

Number of Federal a mine Federal Cumulative

Federal lease plan lease First coal production Production Remaining

Mine name Lesseec

leases reserves acreage acreage shipped 1976-1979 1979 mine life

(Montana)

Rosebud Western Energy Co.

Big Sky Peabody Coal Co.

Spring Creek Spring Creek Coal Co.

West Decker Decker Coal Co.

East Decker Decker Coal Co.

Montana totals

(Wyoming)

Buckskin Shell Oil Co.

Rawhide Carter Mining Co.

Eagle Butte AMAX Coal Co.

Wyodak Wyodak Resources

Cabal lo Carter Mining Co.

Belle Ayr AMAX Coal Co.

Rojo Caballos Mobil Oil Corp.

Cordero Sunoco Energy Dev. Co.

Coal Creek Atlantic Richfield Co.

Jacobs Ranch Kerr-McGee Coal Co.

Black Thunder Thunder Basin Coal Co.

5

1

1

4

1

(billion tons)

HM

LM

L

HM

L

6,198

2,351

3,016

3,137

4,378

8,227

4,307

2,347

4,961

9,410

(million tons) (million tons)

1920’s 41.3 11.7 40 years

1969 9.3 2.5 38 years

1980 0.0 0.0 25 years

1972 55.7 7.1 21 years

1978 5.9 5.9 27 plus years

12 0.8 19,080

1,467

7,393

4,304

3,240

10,040

6,280

5,815

8,232

9,545

4,959

7,560

29,252

600

5,697

3,520

1,880

5,360

2,401

3,959

6,560

5,806

4,352

5,864

1981

1977

1978

1922

1979

1973

1983

1976

1981

1978

1977

112

0.0

7.2

4.0

6.3

1.4

53.8

0.0

9.8

0.0

6.5

10.3

27.2

0.0 16 years

3.6 26 years

3.7 37 years

2.4 43 years

1.3 44 years

15.0 19 years

0.0 27 years

3.8 26 years

0.0 35 years

4.7 22 years

6.2 38 years

Dave Johnston Pacific Power & Light Co 6 LM 14,305 9,662 1958 13.1 3.8 16 years

Wyoming totals 24 4.4 83,140 55,680 112 44.5

Powder River basin totals: 36 5.3 102,220 84,932 225 71.7

aNon-Federal reserves in logical mining units with these Federal lease reserves will add approximately 0.3 billion tons of recoverable reserves in both Montana and in

Wyoming to the above totals (approximately 0.6 billion tons in all would be added to the above Powder River basin lease total).

bAs reported by the lessees in their mine plans.

CSee the OTA Working Lease List, app. B, for a listing of both parent Companies and subsidiaries.

Key to reserve ratings:

s = small reserves (zero to 30 million tons)

LM = low to medium reserves (30 million to 100 million tons)

HM = high to medium reserves (100 million to 180 million tons)

H = high reserves (over 180 million tons)

SOURCE: Office of Technology Assessment,
Ch. 7—The Powder River Basin: A Case Study ● 175

Table 58.—Powder River Basin Federal Mine Production, Capacity, and Contracts

(millions of tons per year)

1980 1986 OTA estimated 1991 OTA estimated

mine mine production-1986 Contracts Lessees’

design

mine production-1991 Contracts Lessees’

Production design demand scenario for estimates of design demand scenario for

Mine name

estimates of

capacity 1980 capacity H L 1986 production-1986 capacity H L 1991 production-1991

Montana

Rosebu d 14.2 10.4 19.6 19.5 16.3 19.4 19.4 19.8 19.8 17.5

Big Sky . 4.6 3.0 4.6 4.6 3.9 4,6 4.6 4.6 4.6 4.1

Spring Cree k 0.2 01 10.0 7.6 5.9 7.0 7.6 10 9.2 6,2

West Decke r 10,4 5.6 10,4 7.5 5.6 6.7 8.0 10.4 9 4 5 9

East Decker. 67 5.6 6.7 6.8 5.6 6.7 6.6 6.7 6.9 5.9

Montana totals 36 24.7 52 46 37 44 46 52 50 40

Wyoming

Buckskin ., 0 0 6.2 6.2 5.2 6.2 6,2 6.2 6.2 5.5

Rawhide and

Caballo . . . 12+4 6.4 24+ 12 20.4 13.5 16.0 31.0 24+ 12 30.7 14.2

Eagle Butte and

Belle Ayr 14+21 24.5 25+ 11 33.7 27.8 33.0 33.0 25+ 1 la

35.2 29.2

Wyodak . . . 3 2.6 5 3 4 2.5 3.0 3.0 5 4.9 4.0

R O jo Caballos 0 0 9 4.5 2.7 2.6 9.0 15 12.5 5.0

Cordero ... . . 24 6.5 24 13,9 9.3 11.0 16.0 24 20.5 9,7

Coal Creek. . 0 0 12 6.4 4,0 4.8 9.8 12 101 4.2

Jacobs Ranch 16 8.2 16 13.6 11.1 13.2 15.6 16 15.3 11.7

Black Thunder. 1 4 10.5 20.5 17.4 13.9 16.5 17.0 20.5 19,4 14.6

Dave Johnston 3.8 3.8 3.8 3.7 3.1 3,7 3.7 3.6 3.6 3 3

198 19.8

4.6 4 6

7.0 10,1

6 7 8.0

6.7 6 6

45 49

6.2 6.2

16.0 360

33.0 320

4,5 4 5

5.6 15.0

11.0 24.0

4.8 12

13.2 156

16.5 20.5

37 3 7

Wyoming

totals 112 62.5 169 123 93 110 144 175 159 101 115 170

Powder River

basin totals. 148 87.2 220 169 130 154 191 226 209 141 159 219

a

This capacity estimate based on remaining reserves.

SOURCE: Office of Technology Assessment

• recent production levels; and

● remaining mine life.

Table 58 summarizes information on capacity, production, and contracts for this decade.

Mine design capacity and production are presented for 1980. Capacity figures for 1986

and 1991 are then followed by estimated production for each of these years under the high

and low demand scenarios discussed in the

preceding section, The amount of coal already contracted for 1986 and 1991 is listed

next, along with the production estimated by

each lessee. Contract information and company estimates of production are taken from

lessee mine plans submitted to the Office of

Surface Mining (OSM) or from communications with the lessees.

Size of Federal Mines in the

Powder River Basin

Acreage: There are over 100,000 permitted mine plan acres for mines with Federal leases in the Powder River basin; 85,000

of these acres contain Federal reserves.

Eighty percent of the permitted acreage is located in the Wyoming section of the basin,

Not all of the Federal lease acreage associated with Federal mines is necessarily included in the permitted mine plan. In the

Montana portion of the Powder River basin,

for example, the five Federal leases associated with the Rosebud Mine cover 8,227

acres but only 75 percent of this acreage is

permitted in the mine plan; the total acreage

permitted in the mine plan at the East Decker

Mine is less than 4,400 acres although the

four Federal leases associated with this mine

cover approximately 9,400 acres,

Lease acreage is important for gaging potential environmental impacts, but it is not

always a good indicator of mine capacity or

production potential. The Dave Johnston

Mine, for example, has a small capacity (3.8

million tons per year) compared to other

mines in the basin even though it includes the

largest total Federal lease acres (9,662) and

the greatest number of mine plan acres

(14,305) in the basin. This mine has been in

production since 1958. At present, mining is

limited to two seams, which average about 45

ft in thickness and are captive to a power-
176 ● An Assessment of Development and Production Potential of Federal Coal Leases

plant that can use only 3.8 million tons per

year.

Reserves: About 90 percent of the nearly 6

billion tons of recoverable reserves associated with approved mine plans or operating

mines with Federal leases in the Powder

River basin are Federal reserves. As table 57

shows, the Federal lease reserves associated

with these approved mine plans and mining

operations are generally large (over 180 million tons). Only three of these mines have Federal lease reserves of less than 100 million

tons.

Mine Life: Mines with Federal leases in the

Powder River basin have substantial production potential manifested by the mine life remaining for these properties. Estimates for

remaining mine life in table 57 are taken from

the lessees’ mine plans. Mine life estimations

are calculated by dividing the remaining recoverable reserves by the lessees’ long term

annual production plans. Should production

fall below the lessees’ estimates, then mine

life would be extended. This could happen in

a number of cases if demand for Powder

River basin coal in 1990 turns out to be close

to the estimates made by the Wyoming task

force (see fig. 34) and does not subsequently

increase rapidly in the 1990’s. Mine life could

also be extended if a lessee obtains additional

reserves.

Most of the mines with Federal leases in

the Powder River basin that opened in the

late 1970’s, or are still under construction,

are expected to remain in production for at

least 25 years. Only two mines (East Decker

in Montana and Buckskin in Wyoming) will

have a capacity of less than 10 million tons

per year by 1991. The two mines that opened

in the 1920’s, Rosebud in Montana and Wyodal in Wyoming, are scheduled to remain in

production for another 40 years. The Dave

Johnston Mine, which opened in the late

1950’s, has 16 years expected mine life (3.8

million tons per year capacity); the Big Sky

Mine, which opened in 1969, has 38 years of

mine life remaining (4.6 million tons per year

capacity).

Trends in Mine Capacity and

Production

Most of the 17 mines with Federal leases in

the Powder River basin are currently operating below capacity. These mines produced

87 million tons in 1980, 61 million tons less

than their combined design capacity of 148

million tons. The design capacity of these

mines is expected to increase by 50 percent in

this decade from 148 million tons per year in

1980 to 226 million tons per year in 1991. The

magnitude of this increase in capacity is illustrated by a comparison of the Belle Ayr Mine

in Wyoming with several of the newer mines

in the basin. Belle Ayr has achieved the highest annual production of coal in the United

States since 1977. However, Belle Ayr’s current capacity (21 million tons per year) is

scheduled to be surpassed by three new

mines in the basin by 1986: Eagle Butte (25

million tons per year), Rawhide (24 million

tons per year), and Cordero (24 million tons

per year). Production at Belle Ayr is expected

to decrease from its present high level.

Demand will dictate whether or not the

design capacity of mines with Federal leases

in the Powder River basin will be fully used

over the next 10 years. Under OTA’s low demand scenario, substantial overcapacity of

these mines will continue and capacity utilization will not move much beyond 60 percent

in either 1986 or 1991. * Under OTA’s high demand scenario, production at these mines

would reach 77 percent of capacity in 1986

and 92 percent of capacity in 1991. According to the lessees’ estimates of production,

capacity utilization will be 87 percent in 1986

and 97 percent

secured for 70

1986 and 1991.

in 1991. Contracts have been

percent of capacity for both

*I! is possible that not all of this capacity would be developed

if markets for Powder River basin coal were weak. The potential for continued overcapacity in the Powder River basin is increased when the undeveloped lease blocks are considered in

the next section,
Ch. 7—The Powder River Basin: A Case Study ● 177

Expansion of New Federal Mines

in the Powder River Basin

Of the 17 mines with Federal leases in the

Powder River basin, 11 are relatively new,

i.e., have opened since 1976 or will open early

in this decade. These new mines now account

for over 90 million tons of capacity and are

scheduled to reach a total capacity of over

165 million tons per year by 1986, and over

170 million tons per year by 1991.

New mines with Federal leases in the Powder River basin have generally followed the

same development pattern, reaching a large

capacity and high levels of production within

a decade after they open. By 1986, according

to the lessees’ production plans, most of the

11 new Federal mines in the Powder River

basin will be producing at least 75 percent of

capacity. By 1991, according to the lessees’

production plans, nearly all of these new

mines will be producing at, or nearly at, full

capacity. Each of these new mines has a contractual commitment for production through

1991. In some cases these contracts represent a substantial amount of capacity.

Several of these new Federal mines illustrate the rapid expansion of Federal mine capacity and production in the Powder River

basin. For example, the Eagle Butte Mine in

Campbell County, produced 3.7 million tons in

1979 after opening in 1978. By 1986, Eagle

Butte is likely to be the largest coal mine with

Federal leases in the United States with a capacity of 25 million tons per year and production of 23.8 million tons per year needed to fill

its contract obligations. Only Federal reserves will be mined at Eagle Butte after

1985. AMAX has contracts for 90 percent of

the reserves planned for production at both

its Eagle Butte and Belle Ayr mines. Coal

from these mines is marketed jointly.

The Black Thunder Mine in Campbell

County, Wyo., is another example of rapid expansion of Federal mine capacity and production in the Powder River basin. This mine,

which opened in 1977, is scheduled to achieve

a capacity of 20.5 million tons per year by

late 1981. Production of Federal reserves

should begin at Black Thunder in 1981 and,

by 1984, Federal reserves will account for all

production. Black Thunder has approximately 80 percent of capacity contracted through

1991.

The Rawhide Mine in Campbell County,

which also opened in 1977, showed low cumulative production (7.2 million tons per year) in

the 1976-79 period. However, the lessee expects to be producing at full capacity at a

rate of 24 million tons per year by 1986, although new contracts to achieve this level

have yet to be signed. This capacity should be

available in 1985, 8 years after the first coal

was shipped from the mine. The lessee, Carter Mining Co., markets coal jointly from its

Rawhide and Caballo mines and has contracts for 16 million tons per year beginning

in 1984. Only Federal reserves will be produced at these mines.

Importance of Federal Reserves

Over the next 10 years, the proportion of

Federal reserves that will be recovered at

these mines will increase substantially. Of

the 11 new Federal mines in the Powder River

basin, three (Rawhide, Eagle Butte, and

Caballo) were producing no Federal reserves

in 1979. However, by 1986, each of these

three new mines will produce only from Federal reserves.

The growing importance of Federal reserves in the Powder River basin is illustrated

in table 59. In 1979, Federal reserves accounted for 42 percent of the total production

of coal from mines with Federal leases in the

Powder River basin. By 1986, according to

lessee mine plans, 90 percent of the coal produced from these mines will be from Federal

reserves. This percentage is expected to hold

for 1991. *

*Note that the estimated percentage of Federal production

differs little between 1986 and 1991 and among the three production estimates. However, the production of non-Federal reserves will decrease substantially in the early 1980’s, from 42

million tons per year in 1979 to 20 million tons per year in

1986 (according to lessee estimates) while, at the same time,

the production of Federal reserves will be increasing substantially.
178 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 59.—Estimates of Federal Portion of Federal Mine Production in the Powder River Basina

1979 actual production 1986 estimated production 1991 estimated production

(million tons per year) (million tons per year) (million tons per year)

Total: 72 OTA high demand scenarioc

Total: 169 Total: 209

% Federal: 89% % Federal: 90%

Federal: 150 Federal: 189

Federal: 3 0 OTA low demand scenarioc Total: 130 Total: 141

% Federal: 89% 0/0 Federal: 89°/0

Federal: 116 Federal: 125

0

/0 Federal: 42°/0 Lessee estimatesb,c Total: 191 Total: 219

% Federal: 90% 0/ 0 Federal: %? O/O

Federal: 171 Federal: 201

a

Federal mines in currently approved mine plans only.

b

Lessee estimates are taken from the mine plans.

C

For 1986 and 1991, in the Montana portion of the powder River basin, the Federal portion of Federal mine production is estimated to be approximately 65 percent in all

three estimates; in the Wyoming portion, the Federal portion is estimated to be over 97 percent.

SOURCE: Office of Technology Assessment

Nonfederal Mines in the

Powder River Basin

Five mines with no Federal reserves in the

Powder River basin (two in Montana and

three in Wyoming) were responsible for 11.7

million tons of coal production in 1980. These

five mines had a combined capacity of nearly

20 million tons per year compared to 148

million tons per year of total Federal mine

capacity in the basin. Table 60 compares the

capacity of currently operating and permitted Federal mines with non-Federal mines

that have favorable production prospects.

Scheduled capacity for these mines is presented for 1986 and 1991. The total non-FedTable 60.—Capacity in the Powder River Basin:

Federal and Non-Federal Mines

1980 1986a1991a

(million (million (million

tons per tons per tons per

year) year) year)

Montana

Federal mines . . . . . . . . 36 52 52

Non-Federal mines . . . . 11 13 30

Total . . . . . . . . . . . . . . 47 65 81

Wyoming

Federal mines . . . . . . . . 112 169 175

Non-Federal mines , . . . 9 16 14

Total . . . . . . . . . . . . . . 121 184 189

Powder River basin totals

Federal mines . . . . . . . . 148 220 226

Non-Federal mines , . . . 20 29 44

Total , ... , . . . . . . . . . 188 249 270

aDoes not include potential capacity from undeveloped Federal leases. See

table 63

eral share of capacity in the basin is unlikely

to go beyond 12 percent in 1986 and 16 percent in 1991.

Table 61 presents information on the capacity and contracts for non-Federal mines in

the Powder River basin that are likely to be in

production by either 1986 or 1991. While the

combined capacity of 12 non-Federal mines

in the Powder River basin could increase

substantially during this decade—to 29 million tons per year in 1986 and 44 million tons

per year in 1991—only three of these mines

Table 61.— Non-Federal Mine Development in the

Powder River Basin, 1986-91

1986 1991

Likely by 1991 Capacity Contracts Capacity Contracts

Montana:

Totals . . . . . . . . . . 13.4 5.1 29.9 5.1

SOURCE: Office of Technology Assessment. SOURCE: Office of Technology Assessment.
Ch. 7—The Powder River Basin: A Case Study ● 179

now have contracts for a total of 10.1 million

tons per year for 1991.

Estimated Cumulative Production

Under OTA’s High and Low Demand

Scenarios for the Powder River Basin

1976=91

Table 62 presents information on the cumulative production of mines with Federal

leases under OTA’s high and low demand

scenarios. Cumulative production from these

mines in the basin from 1980-91 under the

high demand scenario (1,916 million tons) is

30 percent more than that projected under

the low demand scenario (1,480 million tons).

In the 1976-79 period, the cumulative production of mines with Federal leases in the

Wyoming and Montana sections of the Powder River basin were almost identical. However, mines with Federal leases in the Wyoming section of the basin, with their larger

reserves, will dominate coal production in

this decade. Most of this new production will

come from the nine new mines discussed

above. The Eagle Butte Mine, for example,

shipped its first coal in 1978 and produced

only 4 million tons between 1976-79; however, under OTA’s high demand scenario,

this mine would produce 95 million tons between 1980-86, and 110 million tons between

1987-91. The Cordero Mine, which opened in

Table 62.—OTA Estimated Cumulative Productiona

Under High and Low Demand Scenarios for the

Powder River Basin: 1976-91

(millions of tons)

Estimated Estimated Estimated

Cumulative cumulative cumulative cumulative

production production production production

1976-79 1980-86 1987-91 1980-91

Montana portion

of the Powder H -272 H -243 H - 514

River basin. . . . . 112 L -232 L -194 L - 425

Wyoming portion

of the Powder H -677 H -726 H -1402

River basin. . . . . 112 L -561 L -493 L -1054

Total Powder H -948 H -968 H -1916

River basin . . . . . 225 L -793 L -687 L -1480

a

For operating and permltted mines with Federal leases. See table 57, powder

River Basin Federal Mine Statistics. Potential production from undeveloped

leases IS not Included in these tables

1976, also has the potential for high cumulative growth from 1980 to 1991; from 9.8 million tons in the 1976-79 period to 61,4 million

tons in 1980-86 and 72.4 million tons in

1987-91. Similar increases could occur at the

other new mines in the basin. Some increased

production will also come from the expansion

of older mines.

Lessee Production Plans and OTA

High= Low Demand Scenario

Projections: A Summary Comparison

Figures 35 and 36 present a graphic comparison of the production estimates of the

lessees with those under OTA’s high and low

demand scenarios presented in table 58. The

lessees’ estimated production for 1986 is 23

percent (36 million tons) more than production currently under contract for that year;

Figure 35.— Lessee Production Estimates

For operating and permitted mines with Federal leases (see table 58)

225 -

210 -

195 -

180 -

165 -

150 -

135

120

105 -

90 -

75 -

60 -

45 -

30 -

15 -

Million tons

per year

+

. , . .

.- , t’

.,

[ { Key

,,;k . ,$

-.- Contracted production

-“

1979 1980 1986 1991

Year

SOURCE: Office of Technology Assessment SOURCE: Office of Technology Assessment.
180 . An Assessment of Development and Production Potential of Federal Coal Leases

Figure 36.— Production Estimates:

OTA High and Low Demand Scenarios

For operating and permitted mines with Federal leases (see table 58)

for 1991 their estimated production is 38 percent (60 million tons) more than coal currently under contract for 1991.

OTA’s estimates of production under the

high demand scenario in 1991 are only 10 million tons less than the production estimates of

the lessees, however, OTA’s production estimates under the low demand scenario are

substantially lower than those of the lessees.

For 1991, the difference between the two projections is 78 million tons. OTA’s estimates

under the low demand scenario closely parallel production already under contract.

1979 1980 1986 1991

Year

SOURCE: Office of Technology Assessment.

Development Potential and Production Prospects of

Undeveloped Leases in the Powder River Basin

The preceding section examined the production prospects of operating and permitted

mines with Federal leases in the Powder

River basin for 1986 and 1991. The discussion focused on the design capacity, total production, and production of Federal reserves

from these mines over the next 10 years. This

section examines the production prospects of

the 21 undeveloped lease blocks (37 leases) in

the Powder River basin under OTA’s high and

low demand scenarios. The production estimates for each of these leases are based on

OTA’s review of their development potential,

the plans of the lessees, and other considerations likely to affect production,

The potential capacity that these leases

could add to the Powder River basin is significant, totaling 81 million tons per year by the

end of this decade. Under OTA’s high demand

scenario these leases could produce 11 million tons in 1986; under the low demand scenario, 5.6 million tons. In 1991, under the high

demand scenario, these leases could produce

65 million tons per year; their production

would only be 17 million tons in 1991 under

the low demand scenario. However, as table

63 shows, 11 undeveloped lease blocks (20

leases) of the 21 undeveloped lease blocks (36

leases) in the Powder River basin have unfavorable production prospects over the next
Ch. 7—The Powder River Basin: A Case Study . 181

Table 63.—Production Prospects for Undeveloped Leases: Powder River Coal Basin

Capacity 2 Reserve s

Number of Locatio n (million (billion Production prospects’

Development potential Lesse e

4

Leases by county’ Acres tons) tons) 1986 1991

Leases with favorable

development potential

Antelope

N. Antelope

South Rawhide

Rochelle

Dry Fork

E. Gilette Fed.(h)

N. Rochelle

CX Ranch

CX Ranch

Wildcat

Lake DeSmet(e)

Phillips Creek (l)(c)

Resource Development Co.

N. Antelope Coal

Carter Mining

Peabody Coal

Cities Service

Kerr-McGee Co.

Shell Oil Co.

Consolidation Coal

Peter Kiewit Sons, Inc.

Gulf Oil Co.

Texac o

P PL

3

1

1

2

3

3

1

1

1

1

5

4

Favorable(a)

Favorable(a)

Favorable(b)

Unfavorable

Uncertain

Uncertain

Uncertain

Uncertain

Unfavorable

Unfavorable

Unfavorable

Unfavorable

Favorable

Favorable

Favorable

Favorable(e)

Uncertain

Uncertain

Uncertain

Uncertain

Uncertain

Uncertain(e,g)

Unfavorable(e,g)

Unfavorable

Totals 26 44,888 81 (120) 3.3

Leases with uncertain

development potential

Bass Trust(f) R.D. Bass Trust Estate 1 Sheridan 20,701 – L Unfavorable Unfavorabl e

Belco(f,h) Belco Petroleum 1 Johnso n 4,551 — L Unfavorable Unfavorabl e

Gulf (1) & (2)(f) Gulf Oil Corp. 3 Sheridan 4,366 — H M Unfavorable Unfavorabl e

East Wyodak(d) Peabody Coal 1 Campbel l 2,560 — (7.0) LM Unfavorable Unfavorable(e,g)

Pearl Shell Oil Corp. 1 Big Horn, Mt 541 – (2.0) LM Unfavorable Unfavorabl e

Totals 7 32,719 – (9.0) 0.7

Leases with unfavorable

development potential

Armstrong(h) Big Horn Coal 1 Sheridan 80 – s Unfavorable Unfavorabl e

Blue Diamond Wyodak Resources 1 Campbel l 40 — s Unfavorable Unfavorable

Gulf (3)(h) Gulf Oil Corp. 1 Campbel l 756 – s Unfavorable Unfavorabl e

Phillips Creek (2) PPL 1 Converse 40 – s Unfavorable Unfavorable

Totals 4 916 – <0.01

‘Counties are in Wyoming unless otherwise noted

‘Numbers without parentheses show capacities for 1991, numbers in parentheses indicate capacities after 1991

3Where footnote appears under “development potential” it IS relevant to the development of the lease. Footnotes under “productIon prospects” are relevant to production prospects only.

‘See the Working Lease List, app. B, for a Iisting of both parent companies and subsidiaries

Key to production prospects Key to reserve ranking (a) coal already under contract S = small reserves (zero to 30 million tons)

(b) coal may be combined with contracted production of LM = low to mediem reserves (30 million to 100 million tons)

another mine owned by the same company HM = high to medium reserves (100 million to 180 million tons)

(c) plans to incorporate into existing mine plan L = large reserves (over 180 million tons)

(d) may be Incorporated with PRLA to form LMU

(e) production contingent on synfuel development

(f) production dependent on in situ gasification

(g) production contingent on onsite steam electric plant

(h) may be traded under provisions of Public Law 95-554

SOURCE Off Ice of Technology Assessment

10 years even under favorable market conditions.

Undeveloped Leases With Favorable

Development Potential

Four undeveloped lease blocks (7 leases)—

Antelope, North Antelope, South Rawhide

and Rochelle—in the Powder River basin

with favorable development potential have

favorable production prospects for 1991.

These lease blocks cover 18,740 acres; three

contain relatively large reserves.

Only one of these lease blocks, Rochelle, is

not likely to be producing under OTA’s low

demand scenario in 1986. Production at the

Rochelle lease is contingent on the pace of development at the Panhandle Eastern Gasification plant in Douglas, to which 500 million

tons of Rochelle’s reserves have been committed. Panhandle’s plans called for production in 1986, using coal at a rate of about 6

million tons per year with an additional 1 million to 2 million tons per year possibly going to

an associated steam/electric plant. DOE has

funded a feasibility study on the Panhandle
182 ● An Assessment of Development and Production Potential of Federal Coal Leases

Eastern project but production prospects for

the Rochelle lease are unfavorable for 1986

because of the time required for the development of a synthetic fuels project. However, by

1991 the Rochelle lease is assumed to produce 6 million tons of coal under both the high

and low demand scenarios. *

The South Rawhide lease, although without

contracts, would begin production in 1985

and expand to 9 million tons per year by 1991

under the high demand scenario. If no contracts are obtained for this property, the

lessee (Carter Mining Co.) may mine coal at

South Rawhide to blend with the coal produced at the company’s Rawhide and Caballo

mines for which contracts have already been

secured. If this occurs, production at the

Rawhide and Caballo mines would be reduced proportionately.

Coal from the North Antelope lease will be

shipped to Middle South Utilities in Arkansas,

a group of several utilities scheduled to begin

operation in 1984. Using company projections

for this lease, OTA has estimated that approximately 4.5 million tons per year will be

produced under the low demand scenario and

5 million tons per year under the high demand

scenario in 1991 unless construction of the

plants is delayed. Mining operations at North

Antelope will include reserves from the

Rochelle lease.

All planned production from the Antelope

lease is also contracted through 1991; thus,

production prospects for both 1986 and 1991

for this lease are favorable. The lessee plans

to produce 5.6 million tons per year by 1990

and increase production to 12 million tons per

year by 1993.

Four lease blocks (eight leases) with favorable development potential, covering 10,696

acres, have uncertain production prospects

for both 1986 and 1991. Thus, under OTA’s

high demand scenario these lease blocks

could be producing by 1991; however, their

*The 1991 production prospects of the Rochelle lease block

have become less favorable recently because of the withdrawal of two of the partners in the Panhandle Eastern

WyCoal Gas Project.

prospects for production are unfavorable

through 1991 under the low demand scenario. Three of these lease blocks—Dry Fork,

East Gillette Federal, and North Rochelle—

have substantial reserves and favorable

property characteristics. The CX Ranch

lease, held by Consolidation Coal Co., has

small Federal reserves with otherwise favorable property characteristics and is associated with significant amounts of non-Federal coal.

The Dry Fork lease block, held by Cities

Service Co., could produce 0.4 million tons

per year by 1986 and 5.9 million tons per year

by 1991 under the high demand scenario. Six

hundred forty acres of State coal could possibly be included in mining operations. There

are no contracts for coal from the lease at

this time.

According to the Western Coal Planning

Assistance Project, coal produced on the East

Gillette Federal lease block (which could produce 11 million tons in 1991 under the OTA

high demand scenario) will be delivered to

four utilities in Arkansas, Louisiana, and

Oklahoma. Parts of two of the three leases at

East Gillette Federal are included in exchange negotiations authorized under Public

Law 95-554, but the exchanges would not affect the viability of the mining operation. (See

ch. 9 for a discussion of exchanges. )

North Rochelle’s production could reach

5.9 million tons per year by 1991 under the

high demand scenario. The lessee, Shell Oil

Co., plans to apply for a mining permit by

1984 and is currently conducting mine feasibility and environmental studies. It appears

likely that sales of the coal on the lease will

be directed to steam/electric use, at least in

the near term, though none of the coal has yet

been sold. Another option for Shell is to use

the coal to meet contract obligations at

Shell’s Buckskin Mine, where the status of

some recoverable reserves is uncertain because of alluvial valley floor considerations.

Development for synfuels is also a possibility

for the 1990’s.

Consolidation Coal’s CX Ranch could begin

production before 1986; capacity could be 8
Ch. 7—The Powder River Basin: A Case Study ● 183

million tons per year by 1991. Federal coal

has been integrated with State and fee coal

already held by the lessee. Although markets

for the coal have yet to be identified, the

lessee is exploring both steam/electric and

synthetic fuels markets. Environmental studies are underway and the lessee plans to submit a mine permit application in 1981. Under

the high demand scenario, in 1991 Consolidation’s CX Ranch lease could produce close to

6 million tons per year. *

Both the CX Ranch lease, held by Peter

Kiewit Sons, Inc., and Gulf Oil’s Wildcat

lease have unfavorable production prospects

for 1986. Either lease could be producing by

1991 under the high demand scenario but

neither is likely to be producing by 1986 even

under the high demand scenario.

Production from Gulf Oil’s Wildcat lease

could reach 5 million tons per year by 1991

with much of this tonnage expected to be

used for onsite power generation. The lessee

has developed a preliminary mine plan that

may be submitted within the next few years,

However, development of this lease block

may be more difficult and costly than the development of most other leases in Campbell

County because the geology of the coal seams

is very complex. The CX Ranch lease could

have a capacity of 4 million tons per year and

produce close to 3 million tons per year by

1991; however, none of the coal on the lease

has yet been sold.

Two lease blocks (9 leases) with favorable

development potential—one contingent on

synfuels, (Lake DeSmet) the other contingent

on integration into an existing mine (Phillips

Creek (l))—have unfavorable production

prospects for both 1986 and 1991. Thus,

these leases are not likely to go into production by 1991 even under the high demand scenario. Lake DeSmet has large reserves, Phillips Creek small reserves. The Phillips Creek

block, recently acquired by the Pacific Power

& Light Co. is expected to be incorporated into the Dave Johnston Mine. Even if this oc-

*See ch. 10 for a discussion of the alluvial valley floor situation at the CX Ranch leases.

curs, mining of the lease would probably not

take place until after 1991,

Although four of the five Lake DeSmet

leases are not contiguous, the lessee owns all

of the intervening non-Federal coal. Production from this lease depends on the development of synfuels. The lessee submitted a joint

application to DOE for a feasibility study with

Transwestern Coal Gasification Co. However,

this study was not funded. No commitments

or contracts for development of the coal have

yet been obtained.

Undeveloped Leases With Uncertain

Development Potential

Five lease blocks (7 leases) in the Powder

River basin—Bass Trust, Belco, Gulf (l&2),

East Wyodak, and Pearl—have uncertain development potential. These leases contain

32,719 acres and have sizable reserves. Each

lease has unfavorable production prospects

for both 1986 and 1991. It is unlikely, therefore, that these leases would go into production by 1991 even under OTA’s high demand

scenario.

The production prospects of the Bass

Trust, Belco, and Gulf (l&2) lease blocks are

contingent on the development of in situ gasification, which is not likely to proceed before

the 1990s. The Bass Trust lease, the largest

Federal coal lease ever issued, has poor coal

quality, thin seams and a high stripping ratio.

Similarly, the Gulf (l&2) lease block does not

appear to be commercially minable by conventional techniques because of a high stripping ratio. To date, the lessee has not filed

applications to DOE for pilot plant development, and no other plans for development

were identified for the near term. The Belco

lease is authorized for trade under the provisions of Public Law 95-554.

The reserves on the East Wyodak lease

might support an onsite coal conversion plant

if integrated with 640 acres of contiguous

State coal held by the lessee, but stripping

ratios are probably too high to develop a mine

for export markets. In addition, the lessee

also holds a block of PRLAs on land adjacent
184 ● An Assessment of Development and Production Potential of Federal Coal Leases

to East Wyodak. The lessee has expressed

serious intention to bring these reserves into

production when more favorable market conditions prevail.

A final environmental impact statement

(EIS) was submitted on the Pearl lease after

the lessee (Shell Oil Co.) had conducted a

comprehensive planning assessment. In spite

of such an investment of time and resources,

development of this property has been postponed. The amount of lease reserves is marginal and the stripping ratios high. Furthermore, the lease reserves are located in two

blocks separated by unleased Federal coal.

Undeveloped Leases With Unfavorable

Development Potential

Four leases—Armstrong, Blue Diamond,

Gulf (3) and Phillips Creek (2)—have unfavorable development potential and thus unfavorable production prospects, even under strong

market conditions. These leases have small

reserves, poor property characteristics, and

little chance of being integrated with another

coal property to form a logical mining unit.

The owners of these leases have given no indication that they will be developed. The Armstrong and Gulf (3) leases are authorized for

trade under the provisions of Public Law

95-554.

Development Potential and Production Prospects of

PRLAs in the Powder River Basin

There are 58 PRLAs in the Powder River

basin covering a total of 95,228 acres and including recoverable reserves ranging from

less than 30 million tons to over 180 million

tons. Table 64 presents information on the

development potential and production prospects of these 58 PRLAs that are grouped into

19 blocks using the criteria of contiguity and

common ownership applied to undeveloped

leases. Acreage and reserve ratings are also

presented for each block. 1994 is the key year

for which to assess the production prospects

of PRLAs because the stated policy of the

Department of the Interior (DOI) is to process

all outstanding PRLAs by December 1, 1984

(43 CFR 3430.3-l(a)). If this schedule is met,

diligence requirements for all PRLAs will

have to be met by 1994 at the latest. *

None of the PRLA blocks with large recoverable reserves appears to have favorable

development potential. The three PRLA

blocks with favorable development potential

cannot contribute substantially to the capacity of mines with Federal leases in the Powder

River basin because of their small reserves.

*These leases will he subject to post -FCLAA diligence requirements.

The PRLA blocks that might increase Federal

mine capacity substantially in the basin—

Peabody (P4), and Consol (1) and (2)—have

uncertain development potential and production prospects.

PRLAs With Favorable

Development Potential

Only three PRLA blocks (four PRLAs) of the

19 PRLA blocks (58 PRLAs) in the Wyoming

portion of the Powder River basin have favorable development potential. None of these

blocks would add substantially to the capacity of Federal mines in the Powder River

basin. Because of their small size and small

recoverable reserves (each with less than 30

million tons), these three PRLA blocks would

not have favorable development potential if

their incorporation into producing mines or

approved mine plans did not seem likely by

1994.

The Peabody (P2) PRLA, may be incorporated into Carter Mining Co.'s Caballo Mine

because it is located within the boundaries of

the mine area. The Weld-Jenkins (5) PRLA,

with only 80 acres, could be integrated into
Ch. 7–-The Powder River Basin: A Case Study ● 185

Table 64.— Production Prospects for PRLAs: Powder River Coal Basin

Reserves

Number of (millions Production

Development prospects Owner/parent company PRLAs County Acreage of tons) prospects (1994)

PRLAs with favorable

development potential:

Peabody (P2)

Weld-Jenk~ns (5)

North Antelope (1)

Totals

PRLAs with uncertain

development potential

Peabody (P4)

Consol (1)

Consol (2)

North Antelope (2)

Arco (1)

Arco (2)

Peabody (P3)

Western Fuels (1)

(Stevens North)

Dixie (2)

Thunderbird

Weld-Jenkins (l-4)

Totals

PRLAs with unfavorable

development potential

Consol (3)

Dixie (1)

Peabody (Pi)

Peabody (P5)

(Dull Center)

Western Fuels (2)

Totals

Peabody Coal Co. 1 Campbell 520 S Favorable (a)

Weld-Jenkins 1 Campbell 80 S Favorable (a)

North Antelope Coal 2 Campbell 240 S Favorable (a)

Peabody Coal Co.

Consolidation Coal Co.

Consolidation Coal Co.

North Antelope Coal

ARCO

ARCO

Peabody Coal Co.

Western Fuels Assoc.

Dixie Natural Resources

El Paso Coal Co.

Weld-Jenkins

4 840 15

1

3

2

2

1

2

4

3

1

12

13

Converse

Campbell

Campbell

Campbell & Converse

Campbell

Campbell

Campbell

Converse

Converse

Campbell & Johnson

Campbell & Johnson

835

5,610

4,534

1,240

357

240

2,200

8,864

2,276

23,928

28,496

LM (4.0)4

L (7.0)

L (8.5)

s

s

s

LM

HM1

LM

S

2

, L

3

NSR

Uncertain (b,c)

Uncertain (b,c)

Uncertain (b)c)

Uncertain (d)

Uncertain (d)

Uncertain (d)

Uncertain (d)

Uncertain (d)

Uncertain (c,e)

Unfavorable (f)

Unfavorable (f)

44 78,580 1,400

Consolidation Coal Co. 2 Campbell 3,640 LM Unfavorable

Dixie Natural Resources 1 Converse 800 NSR Unfavorable

Peabody Coal Co. 4 Campbell 3,388 S Unfavorable

Peabody Coal Co. 2 Converse 3,628 S Unfavorable

Western Fuels Assoc. 1 Converse 4,352 NSR Unfavorable (f)

10 15,808 127

Key to production prospects.

a = favorable if Integrated into existing LMU (in which case production

of total LMU will count toward diligence requirements)

b = production contingent on onsite development (synfuels and/or steam)

c = possible procedural irregularities and/or overlapping mining claims.

d = favorable if issueed (possible procedural irregularities and/or overlapping

mining claims) and if integrated into existing LMU.

e = possibility exists for local Industrial use of the coal

f = possibilities exist for in situ gasification.

1Reserves with stripping ratio less than 3.5 are probably small.

2Small surface reserves.

3

Large underground reserves.

4Numbers in parentheses indicates potential mine capacity, if lease IS issued.

SOURCE Office of Technology Assessment

SunEDCo’s Cordero Mine. The North Antelope (1) PRLA will likely be developed with

Peabody’s North Antelope lease. Peabody has

contractual commitments on the

Antelope lease with System Fuels for

lion tons of coal beginning in 1985.

PRLAs With Uncertain

Development Potential

North

180 milEleven PRLA bocks (44 PRLAs) covering

78,580 acres have uncertain development potential. Because of their limited reserves, the

development of the North Antelope (z), Arco

s =

LM =

HM =

L =

NSR =

Key to reserve ratings:

small reserves (zero to 30 million tons)

low to medium reserves (30 million to 100 million tons)

high to medium reserves (100 million to 180 million tons)

large reserves (over 180 million tons)

no surface reserves

(1), Arco (2), and Peabody (P3) PRLA blocks is

contingent on their being integrated with

mines already in production. Development of

the Western Fuels (1) PRLA is contingent on

integration into the Dave Johnston Mine, This

PRLA block has thin seams, a high stripping

ratio, and the coal is of low heat content. Procedural irregularities may impede the processing of these PRLAs and their issuance as

leases. The Dixie (2) PRLA would have had

unfavorable development potential because

of small reserves, thin seams, and low heat

content of the coal but there is evidence of

plans to develop the lease for local industrial

use.
186 . An Assessment of Development and Production Potential of Federal Coal Leases

The production of coal from the Peabody

(P4), Consol (l), and Consol (2) PRLAs is contingent on onsite development. The reserves

associated with the Peabody (P4) block could

support an onsite steam electric plant but are

insufficient to support a synfuels project.

Both the Consol (1) and Consol (2) blocks could

support either an onsite steam/electric plant

or an onsite synfuels plant. The issuance of

leases on all three blocks maybe impeded by

overlapping mining claims and/or possible

procedural irregularities. These PRLA blocks

might produce coal if the electrical growth

rate and/or demand for synthetic fuels is

higher than suggested by several estimates.

Consequently, even if these PRLAs are issued

as leases, their production prospects would

be uncertain for 1994.

The Thunderbird and Weld-Jenkins (1-4)

PRLA blocks also have uncertain development potential because their production prospects are contingent on in situ gasification, a

technology that is not likely to be commercially viable by 1984. *

PRLAs With Unfavorable

Development Potential

Five PRLA blocks (10 PRLAs) have unfavorable development potential. Four of these

PRLA blocks have small reserves. The fifth

block, Consol (3) PRLA has unfavorable development potential because it is separated into

four noncontiguous blocks by unleased Federal coal.

* Preference right lease applicants must demonstrate the existence of commercial quantities of coal before a lease can be

issued. Technology for in situ gasification would have to advance to the point of reasonably expected commercial viability

by 1984 (the deadline for processing PRLAs) for coal reserves

that are suitable only for in situ gasification to meet the commercial quantities test. This is unlikely, given the current experimental nature of this technology in the United States.

Comparison of Demand and Supply Projections for the

Powder River Basin

As shown in figure 37 and discussed earlier in this section, most demand projections

for Powder River basin coal for 1990 range

between 163 million tons per year and 275

million tons per year. The Wyoming task

force projected a demand for 206 million tons

per year by 1990 for coal produced in the

Powder River basin. Production projections

for Powder River basin coal can also span a

wide range, from existing contracts with developed mines to full utilization of the mine

design capacity of existing and planned

mines. Figure 37 compares planned production and capacity for 1990 with demand estimates for 1990.

It should be recalled that the estimates of

potential production developed in this chapter are not forecasts of the coal that would be

produced at a given price or a given demand.

They are estimates of the total amount of coal

that could be produced from operating Federal mines and from those Federal leases that

have characteristics comparable to operating

mines in the same region. Coal from these

leases would thus be likely to have mining

costs competitive with costs at currently operating mines in the same area. If the demand

for Federal coal does not increase to the

levels of potential production, then not all the

Federal leases that could technically and economically be developed will go into production.

The existing contracts for delivery of Powder River basin coal in 1990 from operating

Federal and non-Federal mines total 169 million tons (see tables 58 and 61). An additional

17 million tons has also been contracted for

1990 from three undeveloped lease blocks

(Antelope, North Antelope, and Rochelle), of

which 6 million tons is for synfuels (Rochelle).

Thus, there is a total of 186 million tons per

year of Powder River basin coal already contracted for 1990.

The planned production of the lessees for

1990 is larger than presently contracted pro-
Ch. 7—The Powder River Basin: A Case Study ● 187

Figure 37.—Comparisons of Powder River Basin Demand Projections With

Planned Capacity and Production Levels for 1990

(Prelim.)

\

High

Base

(Prelim.)

(Final)

- L o w

(Prelim.)

DOE

438

412

295

275

206

186

Den md projections and goals

1990

aCalculated by adding Sebesta’s figure for the Montana portion of the Powder River Basin (88 mmt) to Glass’ figure for the Wyoming portion (133 mmt)

References

ICF: CEUM: Coal Electric Utility Model Forecasts and Sensivity Analyses of

Western Coal Production, prepared for Rocky Mountain Energy Co

(Washington, D.C : ICF Inc., November 1980)

Sebesta: Demand for Wyoming Coal 1980-1991 Based Upon Projected UtiIity

Coal Market and Demand for Montana Coal 1980.1991 Based Upon Projected Utility Market (Washington, DC.: OTA, October 1980).

Wyoming task force: Result of deliberations of the OTA Wyoming task force,

Cheyenne, Wyo., October 1980.

Silverman: Preliminary results from A. Silverman, University of Montana,

Missoula, Private communication to OTA,

Glass: Wyoming Coal Product/on and Summary of Coal Contracts (Laramie,

Wyo.: Wyoming Geological Survey, 1980)

DOE: Preliminary National and Regional Coal Product/on Goals for 1985, 1990,

and 1995 (Washington, O. C.: DOE, Aug. 7, 1980). See also: Analysis and

Critique of the Department of Energy’s August 7, 1980 Report Entitled:

“Preliminary National and Regional Coal Production Goals for 1985, 1990,

and 1995, prepared for the Rocky Mountain Energy Co. (Washington, D. C,:

ICF Inc., October 1980).

DOE: The 1980 Biennial Update of National and Regional Coal Production Goals

for 1985, 1990 and 1995 (Washington, D. C.: DOE, January 1981).
188 ● An Assessment of Development and Production Potential of Federal Coal Leases

—

duction for 1990. For operating and permitted Federal mines, the sum of the lessees’

planned production for 1990 is about 215 million tons. (See table 58 for 1991 planned production.*) At least another 10 million tons of

production is planned by non-Federal mine

operators (see table 61). When potential production from undeveloped leases is added,

the figure for planned production in the Powder River basin for 1990 increases substantially. Ten undeveloped lease blocks in the

Powder River basin could produce 55 million

tons per year by 1990.** Of this, 17 million

tons per year is presently contracted for; 6

million tons per year of this 17 million tons

per year is committed to synfuels. *** All of

these lease blocks were ranked as having favorable development potential, with market

demand being the most important factor for

their production prospects.

Most of the lessees’ plans call for higher

production in 1990 than what is under contract at present, and planned mine design capacity is, in a number of cases, higher than

planned production. Planned mine capacity

for operating and permitted Federal mines

for 1990 is 226 million tons per year (see table

58). Planned mine capacity for non-Federal

mines adds another 44 million tons per year,

for a sum of 271 million tons per year (see

table 61). When estimated capacity for the 10

undeveloped lease blocks with favorable production prospects is added, the resulting sum

is 348 million tons per year capacity for 1990

(see table 63 for capacity of undeveloped

leases in 1991).

In summary, OTA finds that existing and

proposed mines with favorable development

potential in the Powder River basin could sustain production of 348 million tons per year in

1990, provided the demand existed; only 6

million tons per year of this production is

committed to synfuels development. This

*Note that these tables refer to 1991 production; the numbers in the text above refer to 1990 production, which is slightly less.

* ● Antelope, North Antelope, South Rawhide, Rochelle, Dry

Fork, E. Gillette Federal, N. Rochelle, CX Ranch (Consol), CX

Ranch (PKS), Wildcat. The 1990 production is 10 million tons

less than potential production in 1991.

** *Peabody Coal Co. ’s Rochelle lease block production is

contracted to the Panhandle Eastern project.

figure is substantially larger than most demand projections: over 25-percent higher

than the DOE midlevel projection, over 50-

percent higher than the ICF midlevel projection; nearly 70-percent higher than the

Wyoming task force projection; and 75-

percent higher than the projection of the

Wyoming Geological Survey.

There are several reasons to suppose that

the DOE midlevel projection is outside of the

“most likely” range. (See discussion surrounding fig. 34. ) A more reasonable “likely

high” figure is the ICF base case of 226 million tons per year. Similarly, the ICF low projection of 163 million tons per year, which is

less than present contracts for Powder River

basin coal, is probably outside of the “most

likely” range. Assuming that the “most likely” demand range is from 199 million tons per

year (Glass; Wyoming Geological Survey) to

226 million tons per year (ICF base case), then

potential mine capacity in the Powder River

basin in 1990 may be from 122 million tons

per year (over 50 percent) to 149 million tons

per year (75 percent) above demand.

Potential Coal Mine Capacity in the

Powder River Basin in the 1990’s

The earlier sections of this chapter have

discussed capacity, production and demand

in the Powder River basin up to 1991. This

section briefly examines the additional capacity that might be developed in the 1990’s.

Only capacity that can be sustained without

additional leasing of Federal coal is included.

Table 65 lists all Federal and non-Federal

coal properties that might produce in the

1990’s and the capacity levels that their presently held reserves could support. For those

coal properties likely to be in production by

1991, a total of about 26 million tons per year

capacity over 1991 capacity could be added

in the 1990’s as follows:

●

●

zero from Federal mines in currently approved mine plans (compare with table

59);

about 7 million tons per year from nonFederal mines (compare with table 61);
Ch. 7—The Powder River Basin: A Case Study - 189

Table 65.—Planned and Possible Mine Capacities in the Powder River Basin Beyond 1991a

Operating and permitted

Federal mines and undeveloped Undeveloped leases with

Federal leases with favorable unfavorable production prospects

production prospects for 1991 for 1991 and PRLAs Non-Federal mines b

— —.

Name Capacity Name Capacity Name Capacity

All operating and permitted

Federal mines 226

Undeveloped Federal leases

Antelope 12

North Antelope 5

South Rawhide 12

Rochelle 11

Dry Fork 15

East Gillette Federal 15

North Rochelle 8

Wildcat C 10

CX Ranch (Consol) (Mt) 8

CX Ranch (PKS) (Mt) 4

Leases

Lake de SmetC

East WyodakC

Pearle

Total (leases)

PRLAs

Consol (1)C

Consol (2)C

Peabody (P4)c

Total (PRLAs)

20

7

2

29

7

8.5

4

20

With favorable production prospects

for 1991 51

Likely to come into production after 1991

Mobil (Johnson Co.)C

11

Whitney d

1

Absaloka (II) (Mt) 10

Tanner Creekf

24

Tongue River II (Mt)g

10

Tongue River III (Mt) g 10

Dominy (Mt) 8

Bear Tooth (Mt) 2

Total 127

Total 326 Total leases plus PRLAs 49

a

see tables 58, 81, 63, and 84 for 1991 capacities. (Mt) means mine or lease is in Montana.

b

In Wyoming, capacities of proposed mines that are not associated with existing Federal lease from various sources (primarily Coal Age, 1981, DOE, 1979, and DOE,

1981) total about 67 million tons. However, closer evaluation of these mine proposals indicates that about 40 million tons of this capacity depends on new leasing of

Federal coal and that in several other instances listed capacities exceed the sustainable levels of production when the mine reserves are considered. Mines listed here

are only those mines and potential levels of production that could reasonably be expected to occur without new leasing of Federal coal. Capacities listed here were

developed in consultation with Gary Glass, Wyoming Geological Survey, Laramie (phone conversation, May 18, 1981).

cProductlon is contingent on onsite development for power generation and/or synthetic fuels.

development at this site is unlikely because of problems with alluvial valley floors, but reserves may qualify for exchange for unleased Federal Coal under provisions in

the Surface Mining Control and Reclamation Act of 1977.

eHigh stripping ratios and noncontinuous reserves give this lease unfavorable production prospects in 1991, but the lessee, Shell, has developed a mine plan and wants

to keep options open for possible development at a later date. Undeveloped leases with unfavorable development potential are not listed here

fShell has an option to lease reserves in the Tanner Creek area on the Crow reservation, provided Shell Can find a market for the Coal,

gDevelopment of the Montco and Tongue River mines in Montana is contingent on construction of the Tongue River Railroad. All these mines could also be affected by

the Tongue River unsuitability petition. A larger list of nonfederal mine capacities in Montana (i.e., mine proposals not associated with existing Federal leases) complied from various sources (see sources for table 86 and table A.3.1, vol. II Wyoming task force report) total about 84.4 million tons, excluding the Fort Union region.

SOURCE: Coal Age, 1981, “New Coal Mine Development and Expansion Survey 1980-1989,” Coal Age, February 1981. Department of Energy, 1979 Western Coal Development Morritoring System: A Survey of Coal Mine Capacity in the West, DOE/TIC-10249 (Washington, DC.: DOE, April 1979). Department of Energy, 1981

Western Coal Survey A Survey of Coal Minig Capacity in the West, DOE/RA-0045/1 (Washington, D. C.: DOE, January 1981). Western Coal Planning Assistance Project, 1979 Fact Book for Western Coal/Energy Development, prepared for Missouri River Basin Commission (Billings, Mont.: Mountain West

Research, Inc.).

and

● about 19 million tons per year from undeveloped leases (compare with table

63).

For those coal properties unlikely to be in

production by 1991, a total of about 125 million tons per year of capacity could perhaps

be put in place in the 1990’s as follows:

● about 29 million tons per year from three

undeveloped leases (compare with table

63);

● about 20 million tons per year from three

PRLAs (compare with table 64); and

● about 76 million tons per year from nonFederal mines.

Therefore, an increase of about 150 million

tons per year of mine design capacity over

1991 capacity could perhaps become available in the Powder River basin in the 1990’s

without additional leasing of Federal coal,

giving a possible total post-1990 capacity of

about 500 million tons per year. This amount

should be considered an upper limit rather

than a likely value of post-1990 capacity without additional leasing of Federal coal. About

70 million tons would be suitable only for onsite development for synfuels or power generation.

For the post-1990 period, demand projections become very uncertain. The DOE preliminary midlevel production goals, the ICF

CEUM midlevel production forecast and the

DOE midlevel final production goals for 1995

for the Powder River basin are 382, 306, and

491 million tons per year, respectively. The

DOE final production goal, 491 million tons

per year, reflects several policies about in-
190 ● An Assessment of Development and Production Potential of Federal Coal Leases

creased coal use, notably a very large demand for coal for synfuels, that cause the

number to be higher than other forecasts. Although all demand projections past 1990

should be regarded as very uncertain, the

lower numbers above are, as of now, more

likely to be realized.

Implications for New Leasing

Because of the predominance of Federal

coal reserves in the West, the decisions of

DOI on the quantity, location, and timing of

coal leasing are important not only to the Nation in terms of energy availability, but to the

region with regard to regional and community

development, revenues, and environmental

disturbance, There are two distinct philosophies advanced to govern the leasing of Federal coal: 1) a free market approach based on

the theory that demand for leases should regulate the rate of leasing, and that the Federal

Government should offer leases for development to the extent the market can absorb;

and (z) an approach that emphasizes leasing

coal at a rate that will ensure that coal production can meet the anticipated demand

after considering possible errors in demand

projections and delays that might occur in

developing the leased reserves. The objective

of the second approach is to offer enough coal

to meet the projected supply-demand estimates, allowing a moderate margin in excess

to meet contingencies for delayed development, underestimates in demand or unforeseen constraints on production. DOI has

adopted both of these philosophies at various

times in the past,

Because of the leadtime required from the

acquisition of reserves to full production, the

decisions on the amount, type, and location of

coal to be offered for leasing must be made

more than a decade in advance. Leasing targets have been based on projected estimates

of coal demand, projected estimates of industry’s production capacity, environmental considerations, and the potential impacts on the

social and economic structure of the coal regions. Because leasing targets are based on

forecasts and projections, which in turn rely

on assumptions and estimates of production

factors and projected demands, there are significant uncertainties in setting the quantities

and timing of leasing targets. Experience suggests that supply-demand forecasts are subject to significant errors when extended beyond 5 years, and uncertainties become substantial in projections beyond a decade. (See

ch. 5, Markets, for a discussion of these

factors.)

Some of the uncertainties that may influence the supply and demand for Western coal

during this decade are: Will electricity demand growth remain at current low levels?

How rapidly will foreign exports of Western

coal grow during next two decades? How rapidly and to what extent will the conversion

from oil and gas to coal take place? To what

extent will rising transportation costs restrict

the market areas for Western coal? Will synthetic fuels development place substantial

demands on the Western coal region? To

what extent will the mandatory scrubbing requirements of the Clean Air Act restrict

demand for Western coal? Will there be unforeseen delays in mine development and the

attainment of full production capacity?

Both those who advocate large-scale renewed leasing of Federal coal lands and

those who oppose renewed large-scale leasing as being unnecessary at this time use supply-demand projections and the potential of

current leased reserves as arguments to support their respective positions. The disagreements between these two groups are based

on:

1. differences in what constitute reasonable projections of demand for Western

coal;

Z. differences in estimates of the time required for bringing a mine into produc-
Ch. 7—The Powder River Basin: A Case Study ● 191

tion at full capacity;

3. differences over the acceptable levels of

leased reserve inventories needed by an

operator to ensure competiveness; and

4. differences concerning the safety margins in leased reserves needed to meet

contingencies for higher-than-predicted

demands or to meet shortfalls in supplies

from other regions.

Many industry representatives discount

the efficacy of leasing targets altogether.

They subscribe to the philosophy that public

resources should be freely available to the

private sector for development in accordance

with the demands of the marketplace. As one

spokesman for this philosophy puts it, “the

level of leasing can be safely left to those who

can be punished economically by errors in

judgment and rewarded by sound forward

thinking.<’ However, industry agrees that reasonable performance standards and environmental protection standards are necessary to

prevent irreversible damage to the environment and the socioeconomic structure of the

communities.

Background

Under the leasing program adopted by the

Carter administration, coal leasing targets

are established in a three-part process: DOI,

which has primary responsibility for administering the coal leasing program on Federal

lands, uses DOE regional coal production

goals as a point of departure. Preliminary

leasing targets established by DOI are then

reviewed by Regional Coal Teams, which adjust the target based on public comments and

the position of the affected States represented on the team. The Secretary of the Interior than approves a specific coal leasing

target after reviewing the options presented

in a Secretarial Issue Document (SID). The

Secretary may select one of the suggested options or substitute one of his own.

DOI has changed its basis for determining

leasing targets several times with respect to

DOE regional coal production goals. DOI originally used the 1987 medium production goals

increased by 25 percent for contingencies.

Subsequently, DOI adopted DOE’s midlevel

production goals for 1990 but these were

later supplanted for the powder River basin

by the 1990 high production goals. DOI is currently considering deemphasizing the DOE’s

production goals, and using them as just one

factor in lease sale planning. In place of total

reliance on these production goals, DOI may

adopt an approach that would allow primarily the market demand for leases to determine

when and where and a t what level lease sales

would be held. In order to simplify and expedite the leasing process, consideration is

also being given to revising the planning process to defer the determination of mining suitability and other land use planning functions

until after leasing. DOI is considering working towards having an inventory of reserves

under lease that could support levels two to

four times anticipated production, similar to

the customary practices of the industry.

In making the decision to use the 1990 high

production goals of DOE for the Powder River

basin lease sale, DOI acknowledges that currently planned production will exceed demand through 1990. The new Federal coal

management program was implemented in

June 1979, and will not be fully operational

until 1984 at the earliest. one lease sale was

held in January 1981, in the Green RiverHams Fork region. Other regions selected for

early leasing include:

1. the Powder River basin:

2. Uinta-Southwestern Utah: and

3. Southern Appalachia.

The lease sale in the Powder River basin is

scheduled for early 1982. Since the decision

to hold start-up lease sales was announced,

some have expressed doubts about the necessity of the 1982 sale in the Powder River

basin to meet reasonably anticipated demand

in the 1990’s given the leases outstanding,

available private coal reserves and industry’s

present overcapacity in the Powder River

basin.

OTA estimated that presently operating

and proposed new mines in the Powder River
192 ● An Assessment of Development and Production Potential of Federal Coal Leases

basin, both Federal and non-Federal, would

have a total mine design capacity of 350 million tons of coal annually by 1990. (See fig. 37

and tables 58, 61, and 63. ) This contrasts

with OTA’s “most likely” demand for Powder

River basin coal, which was estimated to be

between 200 million tons and 226 million tons

in 1990. (See this chapter, pp. 171-173 and ch.

5, pp. 100-108.) DOE’s interim midlevel production goal for 1990 is 275 million tons per

year—significantly higher than OTA’s “most

likely” range. DOE’s final midlevel production goal is even higher—295 million tons.

The final high level production goal for 1990,

which is the basis for the Powder River basin

coal sale, is 412 million tons per year.

On June 25, 1981, DOI announced that it

had selected a coal leasing target of 1.4 billion to 1.5 billion tons of reserves for the

Powder River basin to be considered along

with alternative levels analyzed in the

regional EIS. This target was recommended

by the regional coal team; however, at the

time the target was announced, the Assistant

Secretary for Land and Water Resources

commented that:

I am apprehensive about setting a leasing

target that is too low, that would hinder operation of the market, and that would result in

an insufficient amount of coal being leased to

satisfy the demand for reserves in the

region.4

The Secretary of the Interior, at the time he

makes the final determination on the Powder

River basin lease sale, could decide to lease

up to 2.5 billion tons of reserves in the region.

Currently leased coal reserves in the Powder

River basin total 9.2 billion tons.

Existing leases in the Powder River basin

include over one-half of the 16.5 billion tons

of Federal coal reserves presently leased.

With the additional leases scheduled for

1982, the Powder River basin has become the

focus for debate over the timing, pace, and

extent of Federal coal leasing needed to meet

the future energy demands of the Nation.

Those opposed to renewed leasing in the

‘Department of the Interior, News Release, June 25, 1981.

Powder River basin cite the potential for

overcapacity in the early 1990’s as the main

reason why large-scale leasing scheduled for

1982 should be deferred until, perhaps,

1985. * But given the necessary leadtime to

develop a large new mine and reach full production, new leases sold in 1985 could not

confidently be expected to reach full capacity

until 1995. By 1995, the excess capacity probable in the early 1990’s may have been substantially reduced and possibly have disappeared. Estimates of potential capacity and

demand in the post-1990 period are considerably less reliable than similar estimates for

1990. An additional 155 million tons per year

of capacity over the 350 million tons per year

of capacity cited above could perhaps become available in the post-1990 period from

some undeveloped Federal leases, PRLAs and

new non-Federal mines (see table 65).

About 70 million tons per year of the additional post-1990 capacity would be suitable

only for onsite development for synfuels or

steam electric use because of low coal quality.

Therefore, the 155 million tons per year

should be considered an upper limit rather

than a likely value of additional post-1990

capacity without additional leasing of Federal

coal. For the post-1990 period, demand projections are very uncertain.

The ICF CEUM5 midlevel production forecast, the DOE preliminary midlevel production goals, and the DOE midlevel final production goals for 1995 for the Powder River basin

are 306, 382, and 491 million tons per year,

respectively. The DOE final production goal,

491 million tons per year, reflects several policies about increased coal use, e.g., coal for

synfuels, that cause the forecast to be higher

than others. Although all demand projections

past 1990 should be regarded as very uncertain, the lower numbers above are, as of now,

more likely to be realized,

*The debate focuses on large-scale leasing. Leasing in special circumstances, e.g., to maintain production or to avoid bypassing a small area of Federal coal that could not subsequently be economically mined, engenders far less controversy.

5Coal Electric Utility Model Forecasts and Sensitivity Analyses of Western Coal Production, prepared for Rocky Mountain

Energy Co. (Washington, D, C.: ICF, Inc., November 1980).
Ch. 7—The Powder River Basin: A Case Study ● 193

The pros and cons of the proposed Federal

leasing schedule are discussed in the following sections, using the Powder River basin as

a case example.

The Case in Support of Large-Scale

Leasing in the Near Future

Proponents of “start-up” leasing and fullscale leasing programs in the near future cite

four basic reasons for their position:

1. to be able to compensate for the contingencies of increased demand or shortfalls in supply;

2. to ensure competition;

3. to provide additional reserves for production in the post-1990s to accommodate the 10 year (or longer) leadtimes

needed to achieve full production;* and

4. to allow entry of operators not now active in the Powder River basin for equity

and to stimulate competition.**

Proponents of immediate Federal leasing

contend that leasing targets should be geared

to allow margins for unanticipated increases

in demand or unforseen shortfalls in production because of the failure of some planned

capacity to come on line. For example, if only

6 out of the 17 undeveloped properties contributing to the 350 million tons per year of

capacity in 1990 should fail to be developed,

capacity in that year could be reduced by as

much as 60 million tons per year, to 290 million tons per year. Moreover, the “most likely” demand range for Powder River basin

coal in 1990 of 200 million to 225 million tons

per year implies a midrange estimate based

upon judgments of reasonable expectations.

*Eslimates of the time required after lease sale to achieve

full production for a large surface mine range from under 1 0

years to more than 15 years. The upper range reflects a conservative view of the time needed to scale up to full production

after production has commenced: the lower range arises in

part from the belief that permitting times will become shorter

as mine operators and Government regulators alike develop

more familiarity y with the permitting process.

**There are 38 lease blocks in the Powder River basin containing 73 leases. There are 19 lessees: 11 oil companies. 3

utilities, Peabody Holding Co., and four others (see app. B, OTA

Working Lease List),

The 1990 demand for Powder River basin

coal could be somewhat higher than OTA's

“most likely estimate”’ if several events were

to occur:

if electrical demand grew faster than

anticipated;

if boiler conversions from oil and gas to

coal occurred more rapidly than expected;

if synthetic fuels development came online faster than projected;

if foreign export of coal grew more rapidly than anticipated; or

if Powder River basin coal captured an

even larger share of the domestic market

than anticipated.

Leasing proponents claim that underleasing would have a substantial impact on the

coal markets and would drive up marketclearing prices and force shifts in production

to other regions. However, opponents of leasing consider it improbable that coal demand

will increase significantly beyond the “most

likely” demand projections. They further hold

that even if demand increased somewhat or

some shortfalls in production developed,

these would not be large and the capacity and

resources in other regions, including Midwestern coal, could easily make up the difference.

Currently operating Federal and non-Federal mines in the Powder River basin have a

planned capacity of 246 million tons per year

in 1990. (See tables 58 and 61 (including footnote a) and fig. 37.) Most of the currently

operating Federal mines would be operating

in 1991 at or near full design capacity. Any

demand for Powder River basin coal over the

246 million tons per year level would have to

be met by presently undeveloped Federal

leases and undeveloped non-Federal coal

properties. Some proponents of immediately

renewed leasing do not consider the potential

of the undeveloped leased lands as certain

enough to provide a secure safety margin of

production in 1990 in light of the leadtime required from lease sale to full production,
194 “ An Assessment of Development and Production Potential of Federal Coal Leases

A second consideration advanced in support of additional Federal coal leasing in the

powder River basin is the potential for stimulating competition within the coal industry.

Both the Department of Justice (DOJ) and the

General Accounting Office (GAO), in reports

issued in 1980, criticized the setting of lease

targets as being inefficient and potentially

anticompetitive because targets attempt to

match the amount of Federal coal leased to

the amount required to meet given projected

demand. * DOJ'S report concludes that a target leasing system unduly supplants the marketplace as the allocator of coal resources.

The report presents two solutions: 1) abandon

the setting of targets, and begin leasing on demand, or 2) set lease targets at a level far in

excess of the more modest leasing targets

used earlier. DOJ has previously contended

that doubling or tripling the current targets

would be necessary to provide a reasonable

margin for error and to promote competition.

DOJ also recommends the reevaluation of

leasing targets to determine whether it would

be preferable simply to lease what industry

desires. DOI is currently considering deemphasizing leasing targets in favor of the free

market approach as suggested by DOJ. Moreover, the adoption by DOI of DOE high production goals for 1990 for the Powder River

basin is consistent with DOJ's second recommendation to provide liberal targets much

larger than the one to one production-demand

ratios used for lease planning earlier.

However, opponents of near-term largescale leasing in the Powder River basin contend that the excess in potential capacity in

the Powder River basin could ultimately lead

to a decrease in competition within the region. Most of the current leaseholders in the

Powder River basin are large companies that

can afford to take short-term losses; smaller

leaseholders or new entrants who may not

have large amounts of capital might find it

difficult to compete in this situation. This factor is also a cause of concern to some smaller

——

*U.S. Department of Justice, Antitrust Division, Competition in the Coal Industry, November 1980; U.S. General Accounting Office, A Shortfall in Leasing Coal From Federal

Lands: What Effect on National Energy Goals? EMD 80-87,

Aug. 22, 1980.

companies that nevertheless support early

leasing in the Powder River basin.

DOE has recently analyzed Federal coal

leasing activities. One important factor DOE

considered was the effect of leasing on the

conditions for entry into the coal industry. Insofar as easy entry into the industry affects

prices and output as a result of stimulating

potential competition from new entrants, it is

an important factor in assessing the competitiveness of the industry. For regions such as

the Powder River basin, where future mining

will depend in large part on the availability of

Federal coal, the DOE report found that severe limitations on the availability of Federal

coal for lease could create an artificially high

barrier to entry as well as shifting substantial market power to present industry participants, In general, new leasing is one method

of improving entry conditions, and increasing

the number of producers. However, the extent to which the lease sale scheduled for the

Powder River basin is likely to increase the

number of lessees is unclear because: 1) some

present lessees might have an advantage over

new entrants in assembling large minable

tracts because of their existing leases; 2) other

present lessees with large reserves in the

Powder River basin might not care to increase their holdings; and 3) the number of

tracts to be offered for lease is not yet known.

The third factor cited by those advocating

immediate renewed leasing of Federal coal is

the need for creating a pool of reserves well

in advance of planned production to allow for

strategic planning by the industry and to accommodate the 10-year (or longer) leadtime

from lease sale to full production.

For flexibility, industry prefers to operate

on a reserve base that could support two to

four times the anticipated production. Also,

industry contends that any leasing targets

should be geared to meet the maximum possible demand for coal that could occur within a

15- to 20-year planning horizon. Leasing opponents, on the other hand, believe that such

long-range planning and reserve pools are not

necessary. They contend that if demand is

monitored closely, then leases can be offered

when demand trends suggest the need will develop in 10 years or so.
Ch. 7—The Powder River Basin: A Case Study ● 195

If DOI were to eliminate leasing targets as

the determining factor in its coal lease planning in favor of a market-oriented program

for leasing on demand, the market response

still may not result in leasing of reserves that

could support production substantially in excess of demand (“overleasing”). Moreover,

proponents of a liberal leasing policy or leasing on demand claim that overleasing would

not lead to production of coal in excess of demand. The proponents reason that if markets

do not exist, the lands would not be developed

and therefore socioeconomic impacts and environmental impacts because of additional

leasing would not occur.

Those opposing the 1982 Powder River

basin lease sale admit that demand uncertainties must be considered in coal leasing

planning, but they reject many of the projected demand scenarios as being “extreme

assumptions, For example, the DOE final

midlevel production goal of 295 million tons

per year for the Powder River basin in 1990

includes about 35 million tons per year for

synfuels feedstock; this is unlikely to be

achieved. A more likely number is under 10

million tons per year in 1990, To remedy the

uncertainties in long-range demand forecasts

and attempt to bring targets closer to “reasonable” demand expectations, a tracking

system has been suggested to improve the accuracy of demand projections as DOI moves

closer to coal leasing target dates. Demand

projections depend on a number of assumptions concerning electrical growth rate,

transportation costs, and other factors. If in

1982 or 1983 the actual electrical growth

rate or transportation costs differ significantly from those used to bracket the likely

demand range earlier, then the likely range of

demand for a given year could be modified

with increasing confidence.

The prospect of leasing on demand or using

liberal leasing targets raises the question of

speculation. Unlike the situation during the

previous era of liberal leasing, actual production requirements for diligent development now exist in the Federal Coal Leasing

Amendments Act and regulations. * If the demand for Western coal does not increase as

rapidly as liberal leasing proponents generally assume, the diligent development requirements could act as a damper on acquiring leases purely for speculation.

Opponents of a liberalized leasing program

claim that Federal “overleasing” would reduce the revenues from private, State, and Indian coal because of the predominance of

Federal coal in the region and the pressures

that this coal would place on the local markets. They also claim that “overleaping””

would depress the bids on new leases to the

point where the public would not receive a

fair return for its resources.

The Case for Postponing Leasing

Those opposing renewed Federal coal leasing in 1982 in the Powder River basin cite

three reasons for deferring the lease schedule:

1.

2.

3.

the currently operating Federal and nonFederal mines, plus the good quality

properties being actively developed and

the PRLAs that may be developed in the

future will provide substantially more

capacity than will be needed between

1990 and 1995:

slower leasing is needed to allow sufficient time for adequate planning for

leasing by DOI; and

slower leasing would better match the

capability of ‘the State, regional, and

local governments to deal with the socioeconomic impacts of development,

Regarding existing and planned overcapacity, those who favor reconsideration and

delay of the 1982 leasing schedule in the

Powder River basin cite the finding that the

capacity of currently operating mines combined with potential capacity from undeveloped Federal and non-Federal properties that

*1)01 is [it)nsidcrlng various prt)p(wlls I(J prcscn I [I) I) OF; (IJ

lih(?r:ilizc the riiligonm: re[luir(~nlents f[~r lt?i}scs issued prit]r t{)

Auxust 1976.
196 . An Assessment of Development and Production Potential of Federal Coal Leases

have favorable development potential could

reach 350 million tons per year in 1990. This

would be 125 million tons per year more than

OTA’s estimate of the “most likely” 1990 demand for Powder River basin coal. Even if

only 11 out of the 17 undeveloped coal properties were developed, total design capacity

would still be 290 million tons per year. Opponents of renewed Federal leasing in 1982

point out that this tonnage substantially exceeds OTA’s likely estimate of 200 million to

225 million tons per year.

If leasing of Federal coal were deferred until 1985, the newly leased properties would

not be producing at design capacity until

about 1995. As discussed above, available demand projections for 1995 are highly uncertain, and range from 306 million to 491 million tons per year. At this time, the lower portion of this range appears more likely. Leasing opponents consider the overcapacity to be

sufficient to provide adequate coal to meet

demand through 1995 because they believe

DOE’s targets reflect unrealizable policy objectives. The difficulty in making sound projections beyond 1990 precludes a definitive

resolution of the disagreement on supplydemand between the perceptions of the proponents and opponents of additional leasing

in the Powder River basin in 1982.

The prospects for significant production

from the PRLAs in the 1990’s are more speculative. Processing PRLAs will not be completed until 1984. * Until the rights of the applicants are determined, there will be little definitive information about ownership, quantity of coal or quality of the resource. Although

the full extent of reserves within the PRLAs is

not known with certainty, it is estimated that

between 35 million and 60 million tons of coal

per year may be minable from such lands

throughout the West by 1994. Although

PRLAs may contribute to future production,

it is unlikely that they will add much production within the next 15 years; their contribution to production capacity in the Powde r

River basin will probably be limited to about

*See ch. 9 for a discussion of PRLAs.

20 million tons per year or less. (See tables 64

and 65.)

Opponents of the 1982 leasing schedule

also contend that a delay to 1984 or beyond

would allow more time for DOI to prepare environmental baseline studies and permit detailed consideration of the unsuitability criteria that could possible disqualify some proposed lease blocks. However, recent developments within DOI suggest that under proposed changes in the Federal coal leasing program unsuitability criteria would not be considered in processing PRLAs, and a number

of criteria of unsuitability that were applied

in the prelease tract selection stage would

be deferred until later in the process, e.g., the

mine permit stage. Furthermore, it has also

been suggested that fewer prelease determinations of the resource base and mining conditions be made and that other planning features be dealt with by the lessee after leasing

rather than before. However, both the General Accounting Office6 and the American Mining Congress7 have criticized DOI for using inadequate data for land use planning on lease

sales.

Those advocating a delay of the 1982 sale

also claim that the transitional sale scheduled for the Powder River basin was accelerated to show that coal leasing could resume

quickly after the leasing moratorium was

lifted and the new Federal coal management

program was formulated. Because of this,

they suggest, insufficient consideration was

given to competitive factors in the selection of

leasing tracts. Citing the DOJ report on competition in the coal industry that criticized the

leasing program for giving inadequate attention to the pattern of leasing and how existing

ownership may influence the competitiveness

of upcoming lease sales, opponents of immediate leasing claim that deferral of the

1982 lease sale would permit more time for

considering the implication of leasing patterns on competition,

6Mapping Problems May Undermine Plans for New Federal

Coal Leasing, U.S. General Accounting Office, Dec. 12, 1980.

‘Charles F. Cook, Vice President, American Mining Congress, “AMC’s Recommendations 10 Secretary Watt on Reform

of Interior Regulations,’” memorandum, Feb. 17, 1981.
Ch. 7—The Powder River Basin: A Case Study 197

Opponents to the 1982 lease sale in the

Powder River basin also feel that the large

sale will bias the land-use planning process

toward mineral development at the expense

of other Federal resources and make it more

difficult for Federal surface management

agencies to apply effectively the principles of

multiple-use and sustained yield to manage

public resources,

Finally, opponents of the 1982 lease sale in

the Powder River basin claim that by deferring the lease sale until 1984, State, county,

and local governments could have time to

meet the needs of expanded coal development

and plan for the socioeconomic impacts that

will result, Federal coal leasing decisions in

the Powder River basin can have significant

impacts on the local communities and the entire region, Many of the socioeconomic impacts of Federal resource development must

be dealt with by State, county, and local

governments.

Because of the importance of Federal lands

within the basin. the decisions of DOI with

regard to coal development will determine, to

a large extent, the future of the region,

the character of the economy and lifestyle of

its residents. Whether the economic growth

and social change that will accompany development of Federal coal resources is desirable

or undesirable in the context of local and

county planning objectives, the Federal Government, according to those opposing accelerated leasing, is obligated

and coordinate coal leasing

ities and objectives of the

basin.

Another factor in Federal

in the broader sense is to

to carefully plan

with the capabilresidents of the

leasing decisions

ensure that the

benefits and negative impacts of resource development are distributed equitably among

the various regions of the country. All of

these reasons, according to those favoring

delay, can be considered and balanced if sufficient time is given to planning, analysis, and

seeking a balance in approaching Federal

coal leasing among all coal-producing regions.
CHAPTER 8
List of Tables

Page

● ● ● ● * ● .216

.........219
CHAPTER 8

Transportation

The existing transportation network in the

West was generally adequate to move coal

production from Federal leases and private

tracts in 1980, although a number of specific

bottlenecks have been identified, It will be

asked to carry greatly increased quantities of

coal in the future. The key link in this network is rail haulage, which handled about 61

percent of Western coal production in 1979

and is likely to originate even more in 1990.

Most Federal coal leases are and will be

served by rail. The principal constraint that

may materialize in moving future production

of leased coal to its markets is the willingness

of the railroads to invest sufficient capital in

time to satisfy demand for increased rail service from all shippers, including Federal coal.

The mine-to-market transportation costs of

Western coal range from about 10 to over 70

percent of delivered fuel costs and constitute

an important factor in developing future demand.

Western coal is mined at a considerable

distance from most of the ultimate demand it

serves, usually electric utility demand, and is

used in very large quantities at low unit cost.

Coal production therefore creates a substantial requirement for inexpensive bulk transportation services, Western coal now represents perhaps one-third of all the freight

moved in its principal market area.

Utilities are the chief consumers of coal. In

1979 they converted 90 percent of all Western

coal production to electricity (table 66). New

utility projects are subject to long-term planning, ideally for their entire useful lives. Coal

supply, transportation, generating plant siting, and electric transmission are all coordinated, arranged, and fixed. The availability

and cost of different modes of transportation

will influence the final choices, and thereby

shape the future market and transportation

network for western coal,

The two most important ways of moving

Western coal in 1979 were by rail and wire.

Railroads originated* 61 percent of all

Western coal production in 1979 (table 66).

Most of this coal traveled more than 750

miles, and some was delivered to customers

by water, Utilities can also choose to burn

coal in nearby or mine-mouth generating

plants and distribute the electricity to distant

customers through high-voltage transmission

wires, In 1979, 36 percent of all western coal

production was hauled short distances by

truck, tramway, etc., to local generating

plants (table 66). Some of this power was consumed locally, but a substantial amount was

transmitted over hundreds of miles,

Three major long-distance transportation

corridors exist for Federal coal. powder River

basin coal flows east by rail to utilities in the

middle and upper Midwest. Some of this coal

has penetrated Indiana, western Kentucky,

and Ohio markets via the Ohio River (see ch,

5; fig. 26.) A second corridor flows from the

basin south into Arkansas and Texas. This

coal has been shipped entirely by rail, although a coal slurry pipeline is projected to

carry 25 million tons per year from the basin

to Arkansas on completion in the late 1980’s.

The third corridor originates in the tri-State

area of New Mexico, western Colorado, and

Utah. It moves west into Nevada and California. Coal traffic from the northern Rockies

west to Oregon and Washington is beginning

to increase. Another corridor from Colorado

and Utah to southern California may emerge

if an export market for Western coal develops

in Asia.

Other transport modes will not soon

challenge the railroad’s dominant position in

the transportation of Western coal. Economic

and technical considerations restrict the

transmission of electricity over distances

much beyond 500 miles. However, higher

* Rail-originated coal includes: 1) coal hauled exclusively by

rail; 2) coal that is transferred to river haulage; and 3) coal

transferred for shipment on the Great Lakes.

201
202 . An Assessment of Development and Production Potential of Federal Coal Leases

Table 66.—Distribution of Coals (bituminous, subbituminous, and lignite) Produced in the Western

United States During Calendar Year 1979 (thousands of tons)

District of origin

Montana,

Western Arizona, North Alaska,

Interior Colorado California, Idaho and Oregon,

Method of movementa

coal and New and New and South and Western u. s.

consumer use province b Mexicoc Mexicod Wyoming Utah Dakota Washington subtotal total

United States

Electric utilities . . . . . . . 33,933 14,659 22,582 68,529 7,098 13,361

Coke plants . . . . . . . . . .

36,768 196,930 549,774

170 3,362 — 943 —

Other industrial . . . . . .

— — 4,475 76,971

3,866 1,457 2,265 3,148 2,492 1,531 482 15,241 67,140

Retail. . . . . . . . . . . . . . . . 89 66 1 188 182 47 99 672 1,908

Miscellaneous . . . . . . . 18 19 2 5 37 38 706 825 66,771

Total f . . . . . . . . . . . . . . 38,076 19,563 24,850 71,871 10,753 14,977 38,055 218,145 762,564

United States all-rail

Electric utilities ... . . . 3,473 10,519 10,745 50,323 2,071 4,951 22,159 104,241 287,950

Coke plants . . . . . . . . . . 170 3,362 . 943 –

Other industrial . . . . . . .

— — 4,475 46,033

1,145 1,346 2,252 3,009 1,735 1,300 421 11,208 37,707

Retail sales . . . . . . . . . 8 28 — 119 30 31 99 315 729

Total . . . . . . . . . . . . . . 4,797 15,255 12,998 53,451 4,778 6,282 22,678 120,239 372,420

River and ex-river

Electric utilities . . . . . . . 177 — — 4,930 981 – 1,616 7,704 91,100

Coke plants . . . . . . . . . . — — —

Other industrial . . . . . . .

— — — — — 18,989

183 1 — — 184

Retail sales . . . . . . . . . .

— — — 2,650

— — — — — — — — 31

Total . . . . . . . . . . . . . . . 360 1 — 4,930 981 – 1,616 7,888 112,771

Great Lakes

Electric utilities . . . . . . . — — — 5,413

Coke plants . . . . . . . . . .

— — — 5,413

— — —

Other industrial . . . . . . .

— — — — —

— — — 6 45 51

Retail sales . . . . . . . . . .

— —

— — — 4 — — — 4

Total . . . . . . . . . . . . . . . — — — 10 — — 5,459 5,469 20,919

Tidewater . . . . . . . . . . . . . — — — — — — — — 4,881

Truck

Electric utilities . . . . . . . 9,272 4,140 5,622 5,158 2,186 3,746 30,124 78,005

Coke plants . . . . . . . . . .

—

— — — —

Other industrial . . . . . . .

— — — 3,674

1,278

—

109 13 134 758 26 16 2,334 21,862

Retail sales . . . . . . . . . . 80 38 1 65 152 16 — 352 1,107

Total . . . . . . . . . . . . . . . 10,631 4,287 5,636 5,357 3,096 3,788 16 32,811 104,649

Tramway, conveyor and

private railroad

Electric utilities . . . . . . . 21,012 — 6,214 8,118 1,860 4,664

Coke plants . . . . . . . . . .

7,580 49,448 77,875

— — —

Other industrial . . . . . . .

— — — —

1,259

— 1,081

— — — 206 1,465

Retail sales . . . . . . . . . .

— — 1,465

— — — — — — — — —

Total . . . . . . . . . . . . . . . 22,271 — 6,214 8,118 1,860 4,870 7,580 50,913 80,422

aData may not add because of rounding.

b

This province includes all of Kansas, Missouri, Texas, and Oklahoma counties of Coal, Craig, Latimer, Muskagee, Okmulgee, Pitt.sburg, Rogus, Tulsa, and Wagoner.

c

lncludes all of Colorado, and those counties in New Mexico not listed in footnote d.

d

lncludes all of Arizona and California, and the following counties in New Mexico: Grant, Lincoln, McKinley, Rio Arriba, Sandoval, San Juan, San Miguel, Sante Fe, and

Socorro.

e Miscellaneous includes railroad fuel, Great Lakes vessel fuel, Great Lakes commercial docks, coal used at mines and sales tO employees, and destinations and Consumer use not revealable, and exports.

f Includes exports.

SOURCE: Data taken from U.S. Department of Energy, Bituminous and Subbituminous Coal and Lignite Distribution Calendar Year 1979 (Washington, D. C.: DOE,

Apr. 21, 1980), table 1, pp. 7-11.

voltage transmission lines could increase the future. Coal slurry pipelines can compete

economic shipping distance of mine-mouth with railroads over some routes but all the

power, and bulk power is likely to be projects presently proposed would carry less

“wheeled” to more distant consumers in the than half the coal railroads carry now.
Ch. 8—Transportation ● 203

Current Transportation Patterns for Western Coal

The distribution of Western coal production in 1979 between end uses and means of

transportation is presented in table 66, Electric utilities consumed 9O percent of all

Western coal (197 million tons). Of that

amount, 104 million tons—or 53 percent of

the utility-consumed coal—was hauled by

rail; 4 percent by river; 3 percent via the Great

Lakes; 15 percent by truck; and 25 percent by

tramway, conveyor, or private railroad. Most

of the utility-consumed coal that was moved

by rail, river, and Great Lakes traveled at least

750 miles. The coal described as transported

by water had to travel 500 miles or more by

rail to reach a connecting point. The longest

all-rail hauls are about 1,800 miles. Coal

burned in mine-mouth plants and short-haul

coal is typically moved by conveyor, truck, or

private railroad. Much of the electricity produced by this locally burned coal is shipped

by wire over distances up to several hundred

miles. Coke plants used only 2 percent of the

West’s coal production in 1979, and all of that

was hauled by rail. Other industrials consumed about 7 percent of Western coal, almost three-quarters of which was moved by

rail, Fewer than 1 million tons was sold as a

retail product or used for miscellaneous purposes. Railroads moved 55 percent of Western coal output exclusively, and connected

with water for an additional 6 percent.

Table 67 presents origin and destination

data for Western coal production in 1979 by

district of origin and State of destination. In

this table, destination means where the coal

was consumed, not where resulting electricity may have been consumed. Thirty States

consumed Western coal in 1979. Table 68 displays dependence on Western coal for each of

the 30 States. The degree of dependence not

surprisingly was related to the distance from

the Western coalfields: the further the consumer market, the less dependency on Western coal. Western coal’s penetration into

Ohio, Indiana, and Illinois has been related to

sulfur-emission standards, which make Western low-sulfur coal attractive despite the distance and the cost. This market should continue for older plants, but new source performance standards (1979) may make local

coals more attractive to utilities in these

States.

Table 69 ranks these 30 States according to

how much Western coal each consumed in

1979, Texas was by far the largest consumer;

more than half of its consumption was mined

locally and shipped a short distance. However, the powder River basin shipped about

11.6 million tons to Texas by rail. Most of the

16 million tons that Wyoming consumed was

mined locally, for customers such as minemouth plants, All of Illinois’ 15,2 million tons

was shipped by rail, most of it from Wyoming

and Montana. Most of Minnesota’s 12.8 million tons was hauled by rail from Montana.

Kansas, Iowa, and Nebraska tapped the

powder River basin via rail for their coal.

North Dakota used mostly locally mined

coals. Colorado and Arizona consumed local

coals hauled by rail. Little coal moved west to

the Pacific rim.
204 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 67.—Distribution of Coals (bituminous, subbituminous, and lignite) Produced in the Western United States

in Calendar Year 1979 by District of Origin and Method of Movement (tonnage in thousands of tons)

District of origin

Ohio 72,804 3,835 (5%)

River

Indiana

Rail

River

Illinois

Rail

River

Michigan

Great Lakes

Wisconsin

Rail

River

Truck

Minnesota

Rail

River

Great Lakes

Truck

Iowa

Rail

River

Truck

Missouri

Rail

Truck

Tramway, etc.

North Dakota

Rail

Truck

Tramway, etc.

South Dakota

Rail

Truck

Nebraska

Rail

Kansas

Rail

Truck

Florida

River

Tennessee

Alabama

Mississippi

Rail

River

Arkansas

Rail

River

Truck

Oklahoma

Rail

Truck

Texas

Rail

River

Truck

Tramway, etc.

Colorado

Rail

Truck

5%

5,000

7.7%

1.9%

15,297

35.7%

0.1 %

4,353

13.4%

5,546

31.5%

4.8%

0.1

12,786

77.3%

4.6%

7.8%

0.2%

9,382

61 %

5.7%

2.3%

9,339

22.9%

10.5%

4.9%

11,049

21.6%

34.3 %

44%

2,911

94.7%

5.3%

4,929

100%

9,634

83%

17%

33

0.5%

Negf

Negf

957

33 %

1%

1,940

84%

3.8%

9.6%

4,834

95%

4.9%

40,228

32.6%

0.2

13.8%

51.3%

13,046

67%

32%

5

2.3 2.3

4.1 15.4

52,320

42,719

32,385

15,192

14,225

13,571

24,356

11,050

2,912

4,929

9,640

6,193

28,703

25,989

2,820

1,988

4,854

41,090

13,251

(9.6%)

(36%)

(13.4%)

(36.5%)

(90%)

(69%)

(38%)

(1 OO%)

(100%)

(1OO%)

(99.9%)

(0.5%)

(34%)

(98%)

(99.6%)

(98%)

(98.5%)

0.5 2.4

1.9e

Neg

0.1

0.4 15.7

13.4

17.5 14

4.8

0.1

Neg

0.2

0.1

3.4

2.3

9.8

10.5

4.9

Neg Neg

Neg

4.5 52

3.8

3.7 1.1 8.3

9.2 68

4.4

7.8

Neg

Neg 0.8

1.8

Neg

Neg 21.6

34.3

44

0.2 5.8 89

5.3

8.4

3.9

Neg 86 5.6

0.1

Neg

6.7

17

72

0.5

Neg 24 9.5

1

6.3 78

3.8

9.6

3

4.9

0.2 92

2.3 1.6 Neg 24

0.2

13.8

51.3

4.4

43

32

23 Neg

Neg
Ch. 8—Transportation ● 205

Table 67.—Distribution of Coals (bituminous, subbituminous, and lignite) Produced in the Western United States

in Calendar Year 1979 by District of Origin and Method of Movement (tonnage in thousands of tons) —Continued

District of origin

Utah

Rail

Truck

Tramway, etc.

Montana

Rail

Truck

Tramway, etc.

Idaho

Rail

Truck

Wyoming

Rail

Truck

Tramway

New Mexico

Truck

Tramway

Arizona

Rail

Nevada

Rail

Truck

Washington

Rail

Tramway, etc.

Oregon

Rail

California

Rail

30-State total

6,797 6,796

27.3 %

45.3%

27.4%

3,731 3,730

32%

0.3%

68%

516 516

96%

3.9%

16,005 16,005

17%

32%

51%

8,702 8,702

29%

71%

12,878 12,878

100%

4,303 4,303

25%

75%

5,664 5,643

10.5%

89.2%

243 242

100%

2,735 2,730

99.8%

482,565 216,644

(100%)

(100%)

(100%)

(100%)

(100%)

(100%)

(100%)

(100%)

(100%)

(99.8%)

(45%)

18.3

Neg

0.8

2.1

1

4

2

0.3 0.2

2.8 0.8

37.6

28

71

0.4

0.8

3.5

0.2

81

16.5

32

51

95

Neg

75

2.3

89.7

11 51

8.5

44.5

27.4

1.2

13

3.9

0.3

0.3

1

23

7.7

26.3

0.1

68

89.2

6.2

a percentage may not add due to rounding, Neg indicates negligible coal tonnage.

b

Thls province includes all of Kansas, Missouri, Texas, and Oklahoma counties of Coal, Craig, Latimer, Muskogee, Okmulgee, Pittsburg, Rogus, Tulsa, and Wagoner.

c

lncludes all of Colorado, and those counties in New Mexico not listed in fotnote d.

d

Includes all of Arizona and California, and the following counties in New Mexico: Grant, Lincoln, McKinley, Rio Arriba, Sandoval, San Juan, San Miguel, Santa Fe, and

Socorro.

e River transport accounts for only a portion of the route; coal is shipped by rail to barge terminal.

f Delivery is by river

SOURCE: DOE, Bituminous and Subbituminous Coal and Lignite Distribution Calendar Year 1979 (Washington, D. C.: DOE, April 1960). Table 3, pp 27-67.
206 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 68.—Western Coal Consumed as Percent of Total Coal Used

in the 30 States Consuming Western Coal, 1979

Less than 10% 11 to 25% 26 to 50% 51 to 75% 76 to 100%

Ohio . . . . . . . . . . 5% Michigan. . . . . 13% Illinois. . .......36% lowa .. ..69% Minnesota . . . . . . . 89%

Indiana . . . . . . . 1O% Wisconsin . ....36% Arkansas . . . . . . . . 98%

Alabama . . . . . . O% Mississippi. . . . . 34% Oklahoma. . ......100%

Florida . . . . . . . . 1% Missouri . ......38% Texas . . . . . . . . . . . 98%

Tennessee. . . . . O% Colorado. . . . . . . . . 98%

Utah . . . . . . . . . . . . 100%

North Dakota . ....100%

South Dakota . ....100%

Nebraska . .......100%

Kansas . . . . . . . . . . 100%

Montana . . . . . . . . . 100%

Idaho. . . . . . . . . . . . 100%

Wyoming . . . . . . . . 100%

New Mexico . . . . . . 100%

Arizona . . . . . . . . . . 100%

Nevada . . . . . . . . . . 100%

Washington . . . . . . 100%

Oregon . . . . . . . . . . 100%

California . . . . . . . . 100%

SOURCE: Calculations derived from DOE data in table 67,

Table 69.—Destination of Western Coal Production in 1979 (millions of tons)

Less than 3 milIion 3 million to 5 5 million to 10 10 million to 15 15 million tons

Geographic division tons/year million tons/year million tons/year million tons/year plus/year

East North Central Ohio . . . . . . .3.8 Wisconsin .. ..5.5 Illinois .. .15.2

Indiana. .. ..5.0

Michigan .. .4.3

East South Central Alabama . . . . . . Neg. a

Mississippi. .. .1.0

Tennessee. . . . . Neg.a

Florida . . . . . . . .0.01b

West North Central S. Dakota .. ...2.9 Nebraska. .,4.9 lowa . ........9.4 Minnesota .. .12.8

Missouri . . . . ..9.3 N. Dakota. .. .11,0

Kansas. . . . . . 9,6

West South Central Arkansas .. ...1.9 Oklahoma ..4.8 Texas. .. .40.2

Mountain Idaho. ... , .. ..0.5 Montana .. .3.7 Utah . ........6,8 Colorado .. ..13.0 Wyoming .16.0

Nevada . . ..4.3 New Mexico .. .8.7 Arizona. .. ...12.9

Washington .. .5.6

Pacific Oregon ., .. ...0.2

California .. ...2.7

aNegligible tonnage.

b Florlda iS grouped in this category for convenience

SOURCE: Office of Technology Assessment, derived from DOE, Bituminous, and Subbituminous Coal and Lignite Distribution Calendar Year 1979 (Washington, D. C,:

DOE, April 1960).
Ch. 8—Transportation ● 207

Rail: Capacity Assessment

Railroads carry most leased coal because

rail is the only transportation mode currently

available to move large quantities of coal

away from leases. In most cases, a mine is

served by a single rail line.1 Rail transport is

also an efficient, available way to move the

coal over long distances to major consumers.

Western rail lines are adequate to handle

current coal shipments. Car shortages and

traffic bottlenecks were a problem in the past,

but the National Coal Association has not

heard similar reports for more than a year. 2

Railroads are expected to maintain their

dominant position in the transportation of

Western coal, The ability of Western railroads

to handle increased future production of Federal coal will be influenced by: demand for

rail services to transport Federal coal, nonFederal coal, and noncoal commodities; the

capacitities, condition, location, and utilization of rolling stock, tracks, and loading and

unloading facilities; and the management, investment policies, and financial characteristics of rail carriers, shippers, and utilities.

Physical Capacity

Future Western coal traffic may stretch the

physical capacity of the railroads. The National Energy Transportation Study (NETS)

predicted a “, . . potential shortfall in the capacity of the Nation’s railroad system as it

now exists to move the 1990 predicted coal

1

The National Coal Association (NCA) estimates that 85 to 90

percent of Western coal production is “captive” to a single carrier. The Association of American Railroads (AAR) claims

there is no merit in NCA’s assertion. “Such an assessment

overlooks competition among railroads, among different coalproducing areas—served by competing railroads—and competition with other sources of energy, ” according to William

H. Dempsey, president of AAR. DOE could not come to any

firm conclusions regarding possible anticompetitive effects of

railroad involvement in Western coal, although it warned of

“possible” problems if coal is leased to the Burlington Northern. Department of Energy, Coal Competition: Prospects for the

1980s, Draft Report (Washington, DC.: DOE, January 1981),

pp. 270-291.

2

Telephone interview with Joseph Lema of the National Coal

Association, March 1981.

traffic particularly in the West.”3 congestion

was projected to occur at almost 50 Western

rail links in 1990, and a smaller number of

congested links were identified for 1985 at

lower coal traffic. The l990 capacity shortfall

assumes that Western coal shipments by rail

increase from about 97 million tons in 1975 to

625 million tons, and that no new rail investment occurs other than that already underway as of 1979 -1980.4 More recent Department of Energy (DOE) coal production forecasts show smaller increases in Western coal

traffic, projecting that the NETS 1985 traffic

level will not be reached until nearly l990.

This would give the railroads much more

time to improve their facilities.

Several problems in the physical plant of

the Nation’s railroads have been identified

which bear on Western rail capacity. Limited

locomotive-manufacturing capacity may

prove to be one constraint because expected

locomotive requirements in 1990 for all rail

needs are “substantially in excess of current

fleet size,” according to the ICC.5 A doubling

of the current national 28,000 locomotive

fleet is estimated to be needed by l990, which

would require a 15- to 20-percent growth in

locomotive-manufacturing capacity annually,

While some excess capacity in locomotive

manufacturing is currently reported to exist,

heavy demand for locomotives may tax the

capability of this sector to respond.

The adequacy of the hopper-car fleet may

be another question mark. The Association of

American Railroads (AAR) estimates that

285,000 cars, 80 percent of the open-top hopper fleet, were dedicated exclusively to coal.

The fleet averaged 84.5 tons capacity and 25.5

3 U.S. Departments of Energy and Transportation, National

Energy Transportation Study: A Preliminary Report to the President (Washington, D. C.: DOE/DOT, July 1980), p. iii (hereinafter INETS).

4

Ibid., pp. 34, 37.

5

International Commerce Committee, Ex Parte No. 347 Western Coal Investigation-Guidelines for Railroad Rate Structure

(Washington, D. C.: ICC, 1979).
208 ● An Assessment of Development and Production Potential of Federal Coal Leases

trips each in 1979.6 With these figures, AAR

calculated the 1979 theoretical capacity of the

coal fleet at 616 million tons, 23 percent in excess of the 500 million tons estimated to have

been originated on both major and lesser railroads. However, the average coal car made 23

rather than 25 trips in 1979 (with 45 maintenance days), thereby reducing calculated fleet

capacity to about 555 million tons, an excess

of 11 percent rather than 23 percent. It is difficult to determine whether the average coal

car made fewer trips than the fleet average

because of lack of demand or operational difficulties.

Unit trains haul most Western coal and

almost all Federal coal. These trains typically

consist of 100 100-ton hopper cars that shuttle

exclusively between a mine and a utility. A

growing percentage of these cars—now about

40 percent—are owned by the utilities themselves. The amount of rolling stock needed in

the next decade will depend on coal demand

and the time needed to complete a unit train

cycle—loading, hauling, unloading, and

return. The shorter the cycle, the fewer cars

are needed, other things being equal. Cycle

time, which ranges from several days to 14

days or more,7 is a function of the efficiency

of the loading and unloading facilities, rolling

stock, roadway, and traffic control systems.

unit trains typically experience shorter cycle

times than mixed-freight trains—most Burlington Northern (BN) unit trains make their

roundtrips in 4 to 7 days8—and their utilization is generally much higher.9 The coal fleet

6AAR, “Submission to the interagency Coal Export Task

Force,” Oct. 2, 1980, p. 14.

7Data from the Association of American Railroads indicate

that the cycle time of the average coal car was about 14 days in

1979. This figure was derived by dividing 365 by 25.5, the average number of trips per year, according to AAR. See AAR,

“Submission,” p. 16. The Congressional Research Service calculated a 13-day average coal car cycle several years ago, See

U.S. Senate, Committee on Energy and Natural Resources, and

Committee on Commerce, Science, and Transportation, National Energy Transportation, Vol. I—Current Systems and

Movements (Washington, D. C,: U.S. Congress, 95th Cong., 1st

sess., 1977), p. 56.

8

0TA correspondence with Allan Boyce, Assistant VicePresident of Burlington Northern, Feb. 26, 1981.

9Willard D. Weiss and Ronald Dunn, “Modern Railroad Concepts for Transporting Western Coal, ” a paper presented at

Engineering Foundation Conference on Transportation of

Fuels for Utility Consumption (Henniker, N. H., 1976), p. 3.

could be stretched by future coal traffic if current overcapacity is-taken as a sign to reduce

future car orders. If demand for another bulk

commodity, e.g., grain, were suddenly to rise,

coal cars owned by the railroads might be

quickly converted. This kind of situation encourages utilities to invest the $45,000/car in

buying their own hoppers.

Rail capacity did not present a problem in

1980 as the growth in coal demand slowed

and improvements were made in rolling stock

and roadways. Three years ago, a number of

Western coal shippers reported problems in

obtaining hopper cars for mine loadings despite excess capacity on paper. Peabody’s Big

Sky Mine reported, for example, a shortfall

of 200,000 tons—about 9 percent of total

planned production in 1978—due to car

shortages and scheduling difficulties.

10 A

similar situation was reported at ARCO’s

Black Thunder Mine. Coal car shortfalls

forced ARCO to ship less coal than required

by its contracts. The cycle time from ARCO’s

mines to Southwest Public Services’ Barrington Station plant in Amarillo, Tex., jumped

from 87.5 hours (as stipulated in its 1977 BN

contract) to 190 hours in 1978, and the utility

was forced to increase the number of unit

trains and purchase coal from other suppliers. 11

The recent slower growth in demand for

Western coal has reduced the pressure on the

Western railroads. This breathing spell has

enabled the rail lines and utilities to have new

rolling stock delivered before widespread

shortages materialized. The diversification of

hopper-car ownership should also benefit

coal deliveries by creating less pressure on

the rail-owned fleet and by guaranteeing car

availability to large utility consumers. When a

railroad controls the hopper cars, it controls

their distribution and can, if it chooses, favor

some shippers. Utility ownership of hopper

cars then provides an insurance for the utility

that its coal can be shipped.

It does not appear that the reported coal

car shortages of 3 years ago had much to do

l~TA draft report on the Wyoming task force. lllbido
Ch. 8—Transportation ● 209

with technology, fleet capacity, or railroad

finances. Since the railroads have argued that

their capacity has always been adequate—indeed, in excess–the shortages that have developed may have been caused by railroad

policies regarding maintenance, traffic coordination and the like, and management inefficiencies with respect to planning and investment. It is reasonable to assume that the

more Western coal production strains fleet

capacity in the future, the greater the role that

management policy and management efficiency will play,

Two other major rail infrastructure factors—roadway variables and traffic-control

systems —determine the number of trains that

can use existing track at any one time. Carrying capacity is related to track configuration,

the extent of single and double trackage, the

number of sidings, and their length and spacing. Double tracks facilitate fast haulage in

both directions, Sidings on a single track

allow trains to pass in either direction. The

more sidings and the closer their spacing, the

more trains can be run on a single track. The

longer the siding, the longer the train a track

can handle. Traffic control systems determine how close trains can be operated to each

other. Automated Block Signals (ABS), a manual system, is less capable than Centralized

Traffic Control (CTC), a radio and remote

control arrangement, Table 70 estimates the

number of coal unit trains that can be run on

three different track configurations with a

CTC signal system. Longer sidings that are

closer together can double the daily train traffic on a single track. Double tracking has

three to five times more capacity than a single

track.

BN, which originated more than half of the

coal hauled by rail in the West, controls three

key rail corridors from the Powder River

basin:

1.

2.

3.

the line east through North Dakota into

the North-Central States;

the line east through Nebraska and Iowa;

and

portions of the line south through Colorado and Texas.

Table 70.—Estimated Capacity of Alternative Track

Configurations With Centralized Traffic Control

(CTC) Signal System

Average number of

coal unit trains

Configuration of rail line per daya

Single track

21⁄2 mile sidings, 11 miles apart . . . 20-25

21⁄2 mile sidings, 7 miles apart. . . . 30-35

5 mile sidings, 7 miles apart. . . . . . 40-45

Alternating single/double track

10 miles double and 30 miles single

track, with 21⁄2 mile sidings . . . . . . 50-55

10 miles double and 10 miles

single track . . . . . . . . . . . . . . . . . . 60-70

Double track . . . . . . . . . . . . . . . . . . . . 70-125

a Assurnes a capacity of 10,000 tons per train.

SOURCE: Samir A. Desal and James Anderson, Rail Transportation

Requirements for Coal Movements in 1980 (Cambridge, Mass.. Input

Output Computer Services, Inc , 1976), p 2-32.

BN has been upgrading the single track

with sidings on its Nebraska line (between

Alliance and Lincoln), which had an estimated capacity of 15 to 20 trains per day in

the mid-1970’s,l2 A CTC signal system with

double track and alternating single and double tracks are being installed. The Union

Pacific (UP) appears to be better able to transport Wyoming coal east because it doubletracks and uses heavier gage rail. 13 However,

the east-west UP line through southern Wyoming and Nebraska does not originate coal

from the Powder River basin, which is served

exclusively by BN. UP track in Wyoming and

Nebraska is divided about equally between

CTC and ABS traffic control systems.

Financial Considerations

NETS estimated that all railroads will have

to invest $5 billion to $7 billion between 1978

and 1985 in rolling stock to have the capacity

to handle all future traffic. 14 Another $4

billion to $5 billion will be needed to upgrade

existing track and construct new coal-trans12Montana Energy Advisory Council, Montana ‘S Major Energy Transportation Systems: Current Conditions and Future Developments (Helena, Mont.: State of Montana, December

1976), p. 49.

13 Comment from the Wyoming task force, Wyoming Report,

VOl. 1, p. 6 3 .

1

4 NETS, p. 62.
210 “ An Assessment of Development and Production Potential of Federal Coal Leases

port lines.15 Inasmuch as most additional coal

production will occur in the West, it can be

assumed that at least half of these sums will

need to be invested there by Western railroads. Recent coal traffic projections indicate

that this schedule may be stretched out, but

the investment will ultimately be necessary.

Western railroads range from highly profitable to below-average money makers.16 Table

71 presents company performance data for 11

railroads, assembled by Forbes, The two largest Western coal carriers—Burlington Northern and Union Pacific—both ranked near the

top of the list in growth, but were very different in profitability. BN, the major Western

coal line, showed below-average profitability

measures, but UP profitability was well above

average for the railroad industry.

‘

5

1 bid., p. 64.

16The Milwaukee line is bankrupt. A revised reorganization

plan will be presented to a Federal District Court on Sept. 15,

1981. Shippers, States, and other railroads are negotiating the

purchase of Milwaukee track. BN and UP have acquired about

500 miles so far. Standard and Poor rated Western roads in

1979 as follows: Union Pacific (AAA), Santa Fe (AA), Denver&

Rio Grande (A), Southern Pacific (A), Burlington Northern (A),

Missouri Pacific (A-), Chicago & Northwestern (B), and Milwaukee (D). A number of mergers are being negotiated that

may affect coal haulage, including the Union Pacific with the

Missouri Pacific, Burlington Northern with the St. Louis-San

Francisco, and the Santa Fe and Southern Pacific.

A railroad’s ability to borrow capital or

raise it through stock sales is closely related

to its rate of return over a period of time, as

well as expectations of future growth. Many

Western railroads are subsidiaries of diversified companies who must choose where

their capital should be invested. In 1977,

return on rail assets amounted to 8.6 percent

for the Denver and Rio Grande; 3.3 percent,

Burlington Northern; 5.9 percent, Santa Fe;

2.3 percent, Southern Pacific; 7.9 percent,

Union Pacific; 5.8 percent, Missouri Pacific.17

Yet the parent companies of these lines made

at least 10 percent on their other assets

(nonrail transport, real estate, forest, and

natural resources). Table 71 shows a similar

comparison between the rail industry and the

all-industry medians.

Table 72, which summarizes the coal business of the major Western railroads, indicates

that the coal revenues received by the Western roads were low in proportion to coal’s

share of their total freight traffic. Coal, for example, made up 44 percent of BN’s total

freight in 1978, but accounted for only 24 percent of all of BN’s freight revenues,

1 7NET’s, p. 67.

Table 71 .—Railroads: Yardsticks of Management Performance

Profitability Growth

Earnings

Return on equity Return on total capital Sales per share

Latest Debt/ Latest Net

5-year 5-year 12 equity 12 5-year 5-year profit 5-year 5-year 5-year 5-year

Company average rank months ratio months rank average margin average rank average rank

Chicago & North Western . . . . . 27.1% 1 45.9% 2.2 10.2 %

Missouri Pacific . . . . . . . . . . . . . 26.7 2 21.8 1.1 10.9

Union Pacific . . . . . . . . . . . . . . . 13.3 3 15.6 0.3 10.3

Southern Railway. . . . . . . . . . . . 12.9 4 14.3 0.6 8.1

Norfolk & Western Ry . . . . . . . . 12.6 5 15.1 0.3 9.5

Santa Fe Industries . . . . . . . . . . 10.4 6 13.3 0.3 8.9

IC Industries. . . . . . . . . . . . . . . . 9.8 7 10.2 0.7 5.7

St Louis-San Fran Ry . . . . . . . 8.0 8 10.3 0.8 6.3

Burlington Northern. . . . . . . . . . 7.2 9 10.7 0.5 7.0

Southern Pacific . . . . . . . . . . . . 6.9 10 7.1 0.6 4.8

CSX . . . . . . . . . . . . . . . . . . . . . (b) (b) (b) (b)

6 6.6% 4.0% 10.8%a

1 11.2 8.0 14.2a

2 8.9 8.6 19.5

4 7.4 10.6 10.6

3 7.4 13.6 5.9

5 7.2 9.0 13.4

7 6.1 2.7 19.4

9 5.1 5.3 9.4

8 5.2 5.5 14.9

10 4.9 5.3 8.7

(b) 6.7 9.2a

6 20.8% a 3

4 18.7 a5

1 21.0 2

7 13.3 9

11 18.9 4

5 14.3 7

2 13.3 8

8 14.5 6

3 25.5 1

10 6.4 10

9 6 1

a

11

Industry medians . . . . . . . . . . . . 11.5 13.8 0.6 8.5 6.9 6.7 10.8 14.5

All industry medians . . . . . . . . . 15.8 16.1 0.4 11.0 11.1 5.0 14.3 13.9

a

Four year growth.

bNot available: not ranked.

SOURCE: Forbes, Jan. 5, 19b1, p. 92
Ch. 8—Transportation ● 211

Table 72.—Coal Carried and Revenue Received as Percentage of

Total Freight for Western Railroads, 1978

Coal originated Total coal revenues

Coal as Coal revenue as

Tonnage percent of Coal revenues percent of all

Railroad (million tons) all freight (million dollars) freight revenue

Burlington Northern . . . . . 63.0 44 $463.7 24

Union Pacific. ... , . . . . . . 17.3 26 167.6 11

Denver & Rio Grande . . . . 13.2 69 65.7 31

Missouri Pacific . . . . . . . . 9.2 14 63.8 5

Milwaukee . . . . . . . . . . . . . 4.9 19 34.0 8

Chicago & Northwestern . 2.6 6 44.2 8

SOURCE. National Coal Association, Coal Traffic Annual, 1979 Edition (Washington, D C. NCA, 1980), p II-8

—

On the other hand, the unit costs of moving

coal are lower than costs for many other commodities. Western coal haulage costs are lowered by the extensive use of dedicated, highly

cost-effective unit trains, often owned by the

consumer rather than the carrier. Coal shippers, unlike consumers of many other railhauled commodities, even build and operate

their own loading and unloading facilities.

Railroads also use a betterment accounting

system, which tends to show lower earnings

than would depreciation accounting. These

factors mitigate what otherwise seems to be a

generally bleak profit picture for coal haulage

by Western carriers.

Rail-related capital can be raised in many

ways. However, the parent companies of

Western railroads may be reluctant to invest

their limited capital in new rail capacity if

nonrail investments consistently generate

greater returns. Consequently, future rail investment and capacity for Federal coal seems

to be linked more to the investment priorities

of individual railroads than to questions of

physical plant, technology, and capital availability. Although sufficient investment has

been undertaken to provide adequate capacity for current and future coal traffic over the

next few years, constraint on Western coal

production could develop by 1990 or 1995 if

the railroads decide not to make additional

capital stock investment and roadway improvements.

This question of capital application was

spelled out in detail by Richard Bressler,

President and Chief Executive Officer of BN

to Western utility executives, Bressler said:

One of the first things 1 did at Burlington

Northern was to look at where our investments had been made.

Here’s what I found. For many years, Burlington Northern has invested more than its

cash flow,

. . . and a large part of those investments

has gone to coal–into our ability to haul coal

from the Powder River basin to you, the utilities. . . .

about $1 billion has been intvested in

(coal-carrying) capability so far. Our plans

call for the investment of another billion

over the next several years.

. . . Last year, the railroad made $41 million before tax, according to our annual

report.

$41 million–that’s a before-tax rate of return of less than 4 percent on what Burlington Northern recently invested in coal-hauling alone. Less than 4 percent.

I can look at an array of tariffs and

figure out that relatively little of that $41 million came from hauling coal,

. . . we at Burlington Northern will be very

careful about future investments in coalhauling capacity—at least until the picture is

clear.

Burlington Northern has other good investment opportunities, many solid opportunities.

. . . Burlington Northern is prepared to

continue investing in coal capacity. We are

prepared to continue our commitment, assuming there is a reasonable return on such

investments, (Emphasis in the original. )18

18Richard M. Bressler, “Remarks Before the Western Coal

Transportation Association” Denier, Sept. 10, 1980.
212 . An Assessment of Development and Production Potential of Federal Coal Leases

The unclear picture of the future to which

BN’s Bressler referred involves future rail

rates, coal demand, litigation (utilities have 18

separate suits against BN related to coal-hauling contracts), and slurry pipelines. If an appreciable investment is made in pipelines, BN

vice-president Allan Boyce said, the railroad

will cut back its coal-related investment.19

If return is not sufficient to cover anticipated investment, other financing arrangements—such as borrowing, shipper or customer purchase of hopper cars, shipper construction of roadway, or public subsidy,

among others—will be considered. Such arrangements are an increasingly common way

of financing new railroad equipment. Rolling

stock is normally financed through either

leases (often from banks) or equipment trust

certificates, which are, in effect, mortgages.

Utilities that have long-term coal contracts

now frequently finance the hopper cars and

locomotives necessary to transport the coal.

In some cases, utilities and coal shippers are

also providing money to the railroads for improving roadbeds. The Staggers Act of 1980,

which partially deregulated the railroads,

provides the legal framework for utilities to

negotiate long-term contracts with railroads.

Coal industry spokesmen believe that customers and shippers will begin to negotiate such

contracts because they introduce more

predictability into rate and supply issues.

Western railroads have made major capital

investments in recent years to meet expected

coal traffic. The higher efficiencies that this

investment has produced and the slowerthan-expected rate of growth for Western coal

has resulted in excess coal-haulage capacity

throughout the Western rail network. The

railroads have argued that the Interstate Commerce Commission’s (ICC) rates have not produced sufficient return to continue investment at recent levels. Excess capacity is an inefficient use of capital and tends to inflate rail

rates. However, if rail rates are not high

enough, additional needed investment will

not be made. Rates must cover necessary in190TA telephone interview with AlIan Boyce, Assistant VicePresident of Burlington Northern, March 1981,

vestment but not excessive overcapacity.

Even though excess capacity is now a common complaint among railroad operators,

they have argued that ICC rates have not been

adequate to meet their needs. For example,

Thomas J. Lamphier, president of BN’s transportation division, recently wrote:

Unit train coal traffic requires a heavyduty rail system in order to withstand the

continuous impacts of this heavy tonnage on

the rail and roadbed. It also requires long

sidings and automated signaling to allow for

fast movement of coal trains together with

non-coal trains, These requirements involve

enormous amounts of capital to be generated

from internal earnings and from external

sources. Unfortunately, recent ICC and

court decisions have produced an uncertain pricing atmosphere to the point where

it is doubtful that the revenues permit the

recovery of full costs involved in the traffic, much less recovery of the large increases in costs as they arise in today’s

inflationary environment. (Emphasis added.)20

Coal-haul rates vary according to distance,

tonnage, and other factors. A representative

example is the $20.42/ton cost—$0.0127/ton

mile—of hauling Powder River basin coal

from Gillette to Smithers Lake, Tex., a distance of 1,607 miles. 21 (Eastern hauls are

shorter than Western hauls—generally between 150 and 400 miles—and costlier: the

rate for the 346-mile trip from Bluefield, W.

Va., to Norfolk, Va., is $12.59/ton, or

$0.0356/ton mile.) ICC has approved rate increases for Western coal traffic in recent

years, 20 to 30 percent boosts being common

since the late 1970’s.

On the other hand, utilities say that the current transportation charges, which ca n

amount to over 70 percent of the delivered

cost of a ton of Western coal, * are not justi20 Correspondence between Thomas J. Lamphier and Arthur

Ingberman of DOE, Aug. 26, 1980, included in AAR’s “Submission,” p. 23.

21 Rates included in letter from John S. Reed, Chairman and

Chief Executive Officer of the Atchison, Topeka. & Santa Fe

Railway Co. to William Dempsey, President and Chief Executive Officer of the Association of American Railroads, Aug. 19,

1980, included in the AAR’s “Submission, ” p. 20.

*See, for example, table 28 in ch. 5 of this report.
Ch. 8—Transportation “ 213

fied by carrier costs. They argue, further, that

ever higher rail charges and unreliable service are forcing them to develop other sources

of supply and other modes of transportation.

Assuming rail transportation costs continue

to rise, Western coal customers can be expected to consider shifting part of their purchases to closer suppliers. This constitutes an

economic rationalization that may reduce the

growth of Federal coal production, or, at

least, geographically reapportion Federal production. The ICC’s Ex Parte 347 decision on

Western rail rates in November 1980 could

result in an annual increase in Western coal

rates of from 2 to 10 percent annually.22 T h e

Staggers Rail Act of 1980, which deregulated

part of the rail industry, will have little direct

effect on Western coal haulage since ICC retains regulatory authority over “market dominant” commodities, of which ICC considers

Western coal to be a “classic” example,

22Telephone conversation with John Sado, ICC lawyer who

was involved in Ex Parte 347, January 1981. Sado emphasized

that the 2 to 10 percent figure was a reasonable speculation.

Ex. Parte 347 describes the railroads as a “relatively anemic”

industry . . . [whose] shortage of internally generated funds

has led to the deferment of road maintenance and the delay of

road capital . . and an increased reliance on debt and lease

obligations. ” (Ex. Parte 347, pp. 4-23).

Rail: Constraint Analysis

The major potential constraints on increasing Western coal traffic, other than physical

and financial capacity, can be grouped into

two categories: socioeconomic problems and

environmental-safety problems.

In the past, railroads brought economic life

to the communities through which they

passed. Today, increasing coal traffic can

create serious disruptions in Western communities that are bisected by rail lines carrying heavy traffic. If the line has been a heavy

carrier for many years, communities are likely to have adapted or made the necessary investments to resolve delays. Where the increase in traffic occurs suddenly, severe disruption and a lack of resources may combine

to create public concern. The ICC noted that:

increased unit train operations on these

[existing Western] routes may reach a level

which may disrupt transportation, land use,

and social patterns of the residents. . . . It

should be noted, however, that unit trains

will not create any new or unique impacts, . . . Rather, the same railroad/community problems that have existed in the past

may be intensified and what might have historically been regarded as a slight annoyance

could potentially develop into a significant

community problem.23

23 Ex Parte 347, p. 5-86.

Delay caused by train operation is the major

rail-related impact whose disruptiveness

could give rise to community opposition and

become a constraint on Federal coal development, Heavy unit-train traffic during which

dozens of 100-car trains pass through a town

for a number of hours each day can interfere

with normal business, commuting, emergency vehicles, and school schedules. Several

hundred crossings are likely to be affected by

increased Western coal traffic and a somewhat smaller number of grade separations are

likely to be needed.

Grade separations and improved signaling

systems are often prohibitively expensive for

local governments to finance. Western States

are now surveying their specific needs, NETS

discussed alternative sources of financing

new highway grade crossings, among which

are railroad financing, State funding, and

Federal funding (Highway Trust Fund, general revenues, national coal severance tax, and

a carrier tax.)24 NETS did not make a recommendation on this matter but concluded:

Blocking of grade crossings may become a

significant problem both to communities and

to the movement of coal. , . . In the absence

of solutions, communities may take actions

which could affect coal traffic, Local or24NETS, pp. 70-71.
214 ● An Assessment of Development and Production Potential of Federal Coal Leases

dinances prohibiting blocking of crossings

more than a given amount of time per hour,

coupled with speed limits, could adversely

affect the efficiency of coal traffic. Legislation before Congress to limit the length of

unit trains would actually increase congestion at grade crossings. 25

Environmental health and safety is a second potential constraint on rail transport.

Fatalities and injuries associated with rail

haulage are significant, although OTA estimated that a go-percent increase in train traffic would yield a 21-percent increase in death

and injuries.

26 Exposure to train noise is a

hazard whose seriousness depends on factors

such as the location of the rail lines, population density and topographical and architectural configurations. At 50 unit trains per

day, OTA estimates, for example, that

25 Ibid., p. 69,

26 Office of Technology Assessment, U.S. Congress, A Technology Assessment of Coal Slurry Pipelines (Washington, D. C.:

U.S. Government Printing Office, March 1981), p. 106.

Coal

Most Western coal

165,000 persons from Gillette to Dallas would

be exposed to noise levels exceeding the Environmental Protection Agency (EPA) community noise guidelines.27 Air quality is likely

to be reduced somewhat from locomotive

emissions of carbon monoxide, hydrocarbons, nitrogen oxides, particulate, and other

pollutants associated with diesel-electric

engines.

28 Each of these problems could become a constraint on Federal coal were they

to reach serious proportions in a number of

places at about the same time,

Increased use of Western coal by Pacific

Coast States, or the marketing of Western

coal abroad, will enlarge the area affected by

rail transportation impacts, Socioeconomic,

environmental, and safety considerations

could pose particular problems for west coast

communities which already experience congestion and air pollution problems.

27 Ibid., p. 109.

28 Ibid, p. 114, and Ex Parte .347, p. 5-110.

by Wire: Capacity and Constraints

is sold to utilities who

convert it to electricity. As indicated by the

earlier discussion of table 67, 40 percent of

the Western coal sold to utilities in 1979 was

delivered to mine-mouth or nearby generating plants by conveyor, truck, etc., while 60

percent was shipped long distances, principally by rail. Because more than 60 percent

of the electric demand supplied by Western

coal in 1979 was located at long distances

from the mines, a large part of the locally generated electricity was shipped by wire to

serve that demand. Since the cost and efficiency of generating plants is the same regardless of whether it is coal or coal-fired

electricity that is being shipped in bulk, a utility’s decision between the two often revolves

on transportation factors, such as cost and reliability, and environmental impacts that may

prevent siting of new generating plants and

transmission lines in certain areas.

Electricity moves from generating plants

via high-voltage wires. Bulk power is supplied through lines in excess of 230 kilovolts

(kV). * The bulk power is distributed to regional power pools, which are utility-established organizations that regulate the generation and distribution of electricity among

pool members to achieve economic efficiencies. 29 Once electricity is fed into the grid, the

point of origin and final destination of any

particular unit cannot be identified.30

* Utilities also transmit and distribute power. Transmission

lines are between 70 and 230 kV, and distribution lines are 69

kV and less.

29 

U . S. Senate, Committees on Energy and Natural Resources; and Commerce, Science, and Transportation National

Energy Transportation, 95th Cong., 1st sess., publication No.

95-15 (1977), pp. 353-354.

30 The Federal Energy Regulatory Commission (FERC) collects data on interstate shipments of bulk power from utilities

on FERC Form 412, but does not tabulate this information. The

U.S. Senate report cited above did organize these data for CY

1974 (Ibid., p. 372).
Ch. 8—Transportation 215

High-voltage transmission involves losses

in transformers, reactors, and lines that normally consume about 6 percent of the power

generated at the mine-mouth.31 Transmission

losses increase with distance, and can be reduced by raising the voltage. Present voltages

permit efficient power transmission over

distances of several hundred miles. Longer

distances can be achieved by using higher

voltages or by “wheeling,” in which a region

imports power to supply a portion of its own

demand and passes on its own generated

surplus.

Different studies have come to different

conclusions regarding the relative cost efficiencies of rail v. wire transportation. A 1975

study by the Bureau of Mines compared the

two using Powder River basin coal and consumer destination at 1,000 miles southeast

from the mine. This study concluded that

unit-train haulage would be about 30 percent

less costly.32 DOE’s National Power Grid

Study found that a mine-mouth generation

plan “. . . may offer a 15-percent cost advantage over the local generation plan.”33 Highvoltage transmission has a more stable cost

structure than rail haulage, which may constitute its principal economic advantage in

the 1980’s. Its labor and operating costs are

minimal.

Burning coal at mine-mouth plants and

shipping by wire is an attractive option for

many utilities that own both the generating

plant and distribution system, and, thereby,

are not dependent on independent carriers. It

also attracts utilities because of the relative

ease of passing along the costs of capital investment compared with the difficulty of negotiating fuel-adjustment increases. Advantages of this sort might also be viewed as po31 []0 E, Thf, No ( iono I Pot$’f; r (j rid St u[i~’, \’ol. 11, Tech n ;(;U 1

StUdJr Hepf)rts [Washington, DC.: DOE, Septemher 1979), p.

135.

u [;, S, ~~ u r~;lll o f h! i II E;S, D i~r is ion of 1 nterfu els St u(~ if?s, ~’Orn -

porisorl f)f’ E;cwnomic.s f)~ Sr\f2rol Sjst(lms for Pro\iding Coulf?o$(!d ~~nf!rg}r 10 [ ~s[!rs 1,000 ~liff)s southrosterl~’ From F;ostf)rn

l~r~oming C[)ul fJif:l(ls—F’[)ur hlodf:s of F;nergj 7’r(]ns[]cJrtcrtiorl

ond El(v.tricit} i’f’rsus (;[1s ~J nd the F;n(i [ ‘sf’ I+;nf:rg} Form s

(W’ashingtorl, 1).(; ,: [ 1,S, (;okernrmcrrt Printing Office, April

1975).

~sD(3~;, IN”O tjorl[rl P[)\t[:r (;rid Stu[i!r. ~’of. l], p. 149.

tential anticompetitive, cost-increasing developments for electricity consumers. 34

Large future increases in the amount of

Federal coal shipped by wire may be constrained by several factors. The generating

plants require large amounts of water, which

is used to cool the electricity-generating apparatus. 35 An alternative is air-cooling. Scarcity of water in the powder River basin justified the expense of constructing the first drycooling tower in the United States at the Wyodak Power Plant east of Gillette, Wyo.

Water use by plants may limit other economic activity, particularly water-intensive

farming. If mine-mouth plants are planned

for cluster areas together with synthetic fuel

plants, air-quality standards could be exceeded, Constructing mine-mouth plants in

the West also presents local communities

with problems because of intense but shortterm population growth associated with the

construction work force. These problems

have given rise to local opposition in some

cases to expansion of mine-mouth generating

facilities, 36

The transmission lines have also become

objects of controversy. Farmers and other

landowners have objected to losing right-ofway land (15 to 20 acres are required per mile

of transmission line). A direct-current line

from a North Dakota lignite mine to Minnesota’s Twin Cities was protested by farmers

trying to keep the line off their property. 37

Farm opposition is understandable since

radial-spray irrigation systems cannot be

used in fields under transmission lines. 3 8

underground burial of these lines can double

— .

34 DO)j, COO] competition, Supra note 1.

35Jy~:TS pp. 80-81. water-(;ool~~ Stea fll-g[?ll[; l’iit i rl g ~)lil Ilt S IWquire 7 to 8 tons of water per ton of coal, compare(l iiith 1 ton

of water for slurrj’ pipelines and negl ig ihle a moo nts for ra i]

haulage.

3EN[ i(; htlt; ] P;i rfi t, I.(l S t s[on~ u t Ftosebu~i [;reek: ‘‘(~OO f, P() It’f!r,

onrl Prople” [New York: E. P. Dutton, 1980).

37~:~ rry NI, Casper and Pau 1 D. [f’ellstone, PO Lt’f’l’linf’: ‘l’} If’

F’irst Ho~Lle of Am[}rico Enwg~r 11’or (Amherst, hlass.: 1 J ni~rersity of Nlassa(:husetts Press, 1981).

~a~l i[; h a(:) j. ~11] rph ~,, Susanne N! aeder, and J a rnes 1. ~f (: 1 ntirw, 11’~)rthf~rn (;rcat Ploins Cool: Conflicts ond ()[)tions in Dwislon Nloking ( NI inneapolis, Nf i n n.: Upper h! idwest Council,

1976), pp. fj-22.
216 ● An Assessment of Development and Production potential of Federal Coal Leases

to sextuple the costs. 39 Citizens have also

questioned the environmental safety of the

electric and magnetic fields surrounding

high-voltage lines. Problems associated with

corona, noise, spark discharge and ozone

have been identified. The long-term biological

and health implications of high-voltage trans39 Montana Department of Natural Resources and conservation, Draft Environmental Impact Statement on Colstrip Generating Units 3 and 4, 500 Kilovolt Transmission Lines, and Associated Facilities, Vol. 4, “Transmission Lines” (Helena, Mont.:

State of Montana, 1974), p. 37.

mission lines are not known at this time.

However, citizen opposition has made it increasingly difficult for utilities to obtain

Western rights-of-way. Construction of a

765-kV system as suggested in figure 38 to

handle mine-mouth power could give rise to

substantial opposition.

For all these reasons, some industry representatives and environmentalists have urged

that it is preferable to site combustion facilities near to the markets for their electricity.

SOURCE: National Power Grid Study, p. 133
Ch. 8—Transportation ● 217

Truck Haulage: Capacity and Constraints

Trucks hauled almost 33 million tons of

Western coal in 1979, 30 million of which

utilities consumed. This represented about 15

percent of all Western coal production as well

as 15 percent of utility-consumed Western

coal,

Coal is trucked to consumers both on and

off the public highways. Highway vehicles

carry 15 to 30 tons (occasionally more) while

off-road trucks can handle up to 150 tons.

Trucks are more flexible than other coaltransportation modes. They are a cost-efficient mode for short distances and small

quantities of coal, the economical distance

varying according to local conditions. One

company looking at transportation systems

for 5 million tons per year of Texas lignite

concluded that truck haulage was limited to a

maximum of 10 miles and that truck-rail haulage was cost effective for longer distances.40

Truck haulage is a simple and familiar technology whose application is generally deter400TA correspondence with 13. C. Bradley, President of

Chaco Energy Co., February 1981.

mined by economic factors, weight limitations on local roads, proximity of mine to

consumer, and the like. The physical capacity

of truckers to move Federal coal does not appear to represent any constraint on future

production.

Truck haulage of coal presents a range of

environmental, safety, and socioeconomic

problems, particularly where trucks regularly

pass through population centers. Noise, dust,

and pollution are common causes of citizen

complaint. Highway damage is frequently extensive from large coal trucks. More than

other coal-transport technologies, trucks are

local—the technology itself is familiar and

simple; the drivers are local residents who

often own or lease the trucks; the impacts are

readily seen and understood; and effect is

easily related to cause, For such reasons,

citizen opposition to extensive truck haulage

in a given community may emerge more

quickly than opposition to other transportation modes. Even if citizen complaints were

numerous, a constraint on Federal production is unlikely to result because most new

Federal coal will move by rail or wire.

Waterway-Barge: Capacity and Constraints

Almost 8 million tons of Western coal traveled by river in 1979 and another 5% million

tons were shipped on the Great Lakes, Almost

all of this tonnage was shipped to electric

utilities, and all of it originated by rail, Over

half of this coal went to two States, Ohio and

Michigan.

The inland waterway system has been constructed and maintained by public authority,

the Federal Government, with one exception,

Locks are operated by the U.S. Army Corps of

Engineers. Lock size is the principal determinant of the extent of river and lake traffic, The

main access points for Western coal are: Superior, Wis., on Lake Superior; Sioux City,

Iowa, on the Missouri River; and in the St,

Louis area on the Mississippi. The Sioux City

connection is closest to the Western coalfields.

Barge haulage is a very inexpensive way of

moving bulk commodities. Barge service cost

averages 6,86 mills/ton-mile compared with

26 mills for rail.41 The Reagan administration

has proposed to increase the fuel tax for

bargelines to 30 cents/gal in 1983, which the

administration estimates would add less than

4 mills/ton-mile to the operating cost of the

41 Telephone conversation ~v ith IVei ] SC h u stcr, Vice-p rcsid en t

of the A rnerican Waterways Operators, I nc,, januar~’ 1981 .

Schuster stressed that these cost estimates were for a~’erage

revenue for all commodities, and that the costs for coal would

be less for both harge and rail, Cost data were for 1979.
218 ● An Assessment of Development and Production Potential of Federal Coal Leases

barge companies. This would represent a

58-percent increase in average barge service

cost, “Four mills per ton-mile is a phenomenal jump, an awfully significant increase,

when you’re talking six to eight mills to move

coal,” Anthony Kucera, director of the American Waterway Operators Association, said.

“The impact would be incredible. ”

42 A

management consultant recalculated the

Reagan proposal for an industry newsletter

and found that the fuel tax increase would increase expenses by 5 to 8 mills.43

Problems have been noted with the capacity of several locks on the Mississippi-Ohio

River systems, which exceed or are close to

42 Northern Coal, Mar. 11, 1981.

43 Ibid.

exceeding design capacity. 44 NETS found future congestion to be likely at Dam 26 at

Alton, Ill., and the Gallipolis Lock on the Ohio

River unless new facilities are built.45 The extent of any future constraint depends less on

the extent of Western coal movement by

barge and more on how much additional

barge service is required of other commodities, notably oil products.

44 The ICC states that “a waterway reaches capacity when the

average delay time at a lock exceeds 150 minutes, ” ICC, Ex.

Parte 347, p. 4-27 referencing U.S. Department of the Interior,

1979, Federal Coal Management Program, Final Environmental

Statement, Vols. I and 2 (Washington, D. C.: Bureau of Land

Management, 1979). The problem locks include: Locks 50-53

on the Ohio River; Gallipolis Lock on the Ohio; Locks 26 and

27 on the Upper Mississippi; all locks on the Illinois River;

Lock No. 3 on the Monongahela River; and the Winfield Lock

on the Kanawha River. The ICC says these locks require “longterm structural solutions through the modification or replacement of existing locks” (p. 4-27).

45 NETS, p. 74.

Coal Slurry Pipelines: Capacity and Constraints

Coal slurry pipelines have not played a

significant role in coal transportation. Only

one pipeline is currently operating: the Black

Mesa line between Kayenta, Ariz., and southern Nevada that has a 4.8-million-tons-peryear capacity and covers 273 miles. This pipeline handled about 0.6 percent of the coal

mined in the United States in 1980.

A number of slurry pipelines have been

planned or proposed (fig, 39). Nearest to construction is the Energy Transportation Systems Inc. (ETSI) line that would ship Powder

River basin coal to Oklahoma, Louisiana, and

Arkansas. It would have a capacity of 25 million tons per year. A recent DOE contractor’s

report forecast that 70 million to 126 million

tons of coal could be pipelined in 1990, which

would amount to between 5 and 9 percent of

all coal transported.46 This report concluded

that several pipelines were most viable, including Arizona to Nevada; Wyoming to Illinois; Wyoming to Texas; Wyoming to Arkansas, Oklahoma, and Louisiana. OTA’s invesq~ICF, The Potential Energy and Economic Impacts oj’ coal

S1urry Pipelines, Draft Final Report (Washington, D. C.: ICF, December 1979), pp. 1-2.

tigation reported that coal slurry pipelines

66

. . . do represent under some specific circumstances the least costly available means

for transporting coal measured in economic

terms.”

47 On the other hand, the construction

of a number of Western pipelines would directly affect the investment and capacity decisions of competing railroads. Coal slurry

pipelines involve much more complex engineering than gas or oil pipelines and they are

not without environmental and social costs of

their own.48 This report also concluded:

, . . the introduction of coal slurry pipelines

is not likely to affect materially the rate of

coal resource development and use on a national scale. It may, however, affect the

regional pattern of coal mining and distribution in such a way as to expand the use of

WOTA, Coal Slurry pipelines, Summary (Washington, D. C.:

U.S. Government Printing Office, September 1980), p. 8. This

summary updates an earlier report, A Technology Assessment

of Coal Slurry PipeJines (Washington, D. C.: U,S. Government

Printing Office, March 1978). The array of legal, economic and

environment issues involved in the slurry pipeline debate are

discussed in full in OTA’S 1978 Assessment and in the 1980 update.

qaAn extensive discussion of these tradeoffs is found i n

OTA’s assessment, Coal Slurry Pipelines, chs. V and VI.
Ch. 8—Transportation ● 219

Figure 39.—Coal Slurry Pipeline Systems

A

Proposed pipelines . . . . . . . . . . . . ● . ,.,. .,... ● *..

Principal

company

Plpeline a affiliation

A. Existing

1. Black Mesa pipeline (to present) Consolidation Coal Co.

2. Ohio pipeline (1957-1963)

B. Planned or proposed

3.

4.

5.

6.

7.

8.

9.

10.

Allen-Warner Valley Energy System Nevada Power Co.

(Alton pipeline) (1983-19843)

Energy Transportation Systems

Incorporated (ETSI pipeline) (1983)

Continental Resources (Florida Florida Power Co.

pipeline) (1985-1986)

Northwest Integrated Coal Energy

System (Gulf Interstate Snake River

pipeline)

Pacific Bulk Commodity Transporta- Boeing Corp.

tion System pipeline

San Marco pipeline (1983)

Texas Eastern (Wytex pipeline)

(1985)

Vepco pipeline Virginia Electric Power Co.

Total b

●

● Miami

Capacity

potential

Capacity to export

Distance (million (million

Origin Destination (miles) tons/year) tons/year)

Kayenta, Arizona Southern Nevada 273 4.8 None

Cadiz, Ohio Cleveland, Ohio 108 1.3 None

Utah/Arizona Nevada 183-256 11.8 None

Powder River Oklahoma/Louisiana 1,378 25 0.5

basin/Wyoming Arkansas

Southern Illinois/West Georgia/Florida 600 – 40-50 10

Virginia/Kentucky 1,500

Powder River basin Oregon 1,100 25 0.5

Wyoming

Emery, Utah Oxnard, Cal if. 645 10 10

Colorado/ Houston, Tex. 900- 15 None

New Mexico 1,100

Gillette, Wyo. Houston, Tex. 1,260 25 0.5

Southwest Virginia Tidewater, Va. 300 5-1o None

161-176 20-35

a Target operating date, when available, In parenthesis.

b Excluded the closed Ohio Pipeline

SOURCE: Data furnished by Coal Slurry Transport Association, May 1980, and National Coal Association, 1978
220 An Assessment of Development and Production Potential of Federal Coal Leases

western coal to greater distances from its

area of origin.49

The degree to to which pipelines affect rail

traffic depends on whether pipeline operators

win passage of eminent-domain legislation

and on the level of rail rates. As rail rates increase, the economic attractiveness of pipelines increases as well. If Federal pipeline

legislation is enacted, pipeline operators will

enjoy a regulatory advantage over railroads.

The pipeline industry argues that the absence

of Federal eminent-domain legislation is a

significant constraint on pipeline construction. Such legislation would make construction easier and accelerate the construction of

pipelines, but it does not appear to be essen49)T A, Coal Slurry pipelines, Summary, p. 9, September

1980.

tial to the construction of any individual

pipeline.

The principal environmental constraint on

pipeline construction has to do with water.

For any particular pipeline, water availability

may not be a problem. However, when water

demand for all possible new energy facilities

in a western basin, including mine-mouth

plants, synthetic-fuel facilities, and pipelines

are totaled, water availability can become an

important constraint on pipeline construction. Moreover, Montana and Colorado prohibit export of local water, and Wyoming requires legislative approval before export can

occur. Assuming that the legal and environmental water issues are resolved, the only

likely constraint on pipeline development

arising from the operation of the lines would

be citizen objection to spillage from breaks.

Federal and State environmental regulations

may be violated in such accidents.

Port Facilities: Capacity and Constraints

Very little Western coal is being exported

to Asia. If Asian exports are to increase, improved port facilities are required. Domestic

port facilities at Los Angeles, Long Beach,

and Stockton, Calif., are currently capable of

loading only several million tons per year.

plans for expansion of these port facilities

have been announced. The volume of coal

that could be transferred through these ports

may be constrained by area rail system capacity. The port at Vancouver, British Columbia,

now has a capacity of 15 million tons per

year, and could handle some Western coal.

Seattle plans to expand its coal export facilities to 40 million tons per year by 1990, if export sales warrant such an investment. Other

Western ports may also invest in expansion if

the coal export market grows.50

50 see Office of Technology Assessment, Coal Exports and

Port Development, OTA-TM-O-8 (Washington, D. C.: U.S. Government Printing Office, April 1981).

Comments on Regional and State

Transportation Factors

Powder River Basin 72 million tons of this came from mines containing Federal leases. About 160 million tons

The Powder River basin is likely to supply are contracted for 1990 from Federal mines

an increasing percentage of Federal coal. In alone (see ch. 7). Almost all of this coal will be

1979, the Montana-Wyoming Powder River consumed by utilities. Unless coal slurry

basin produced about 80 million tons of coal; pipelines are built, more than 90 percent of
Ch. 8—Transportation ● 221

Federal coal will be hauled by rail, If the three

pipeline projects mentioned in figure 39 are

completed by 1990, they would transport 75

million tons per year.

Texas and Iowa will be two principal consumers of Federal coal from the Powder River

basin in 1990. Other States that have contracted for large amounts of Powder River

basin coal include Montana, Minnesota, Colorado, Wisconsin, Michigan, Indiana, Ohio,

Oklahoma, Wyoming, and Kansas.

A rough idea of the rail traffic these contracted tonnages represent can be calculated

on the assumption that it requires one set of

100 cars making 100 trips to transport 1 million tons. Powder River basin contracted output from mines including Federal leases will

require 16,000 unit-train trips. Traffic past

any given point is doubled to take into account the returning trains.

Assuming that the average coal car makes

46 trips annually (7-day cycle time plus 45

days maintenance), this tonnage would require 348 unit trains with at least 34,800 hopper cars. The time that a particular community is disturbed by train traffic depends on the

amount of traffic, time of day, and train

speed. A town through which 25 loaded and

25 return trains pass daily will be disturbed

from 1 to 5 hours depending on train speed. *

It should be recalled that other traffic (some

non-Federal coal but principally noncoal

commodities) will also be using this rail system, thereby increasing the traffic.

BN, which serves the powder River basin,

will have to expand its capacity if it is to handle 1990 coal traffic. Although most Federal

leases lie within 15 miles of existing rail lines,

roadway limits down the line from the point

of origin may present bottlenecks in the future.

51 Obtaining sufficient rolling stock is

*This would represent an annual tonnage of 91.25 million

tons. Towns on the BN’s track in Wyoming, Colorado, Nebraska, and Iowa can expect this level of traffic. Towns south of

Gillette may have more trains passing through on a daily basis,

depending on Basin output.

51 NETS, p, 33 ff. and fig. 3-2. NETS identified 67 congested

rail links in the coal transportation network nationally. About

three dozen of these bottlenecks were identified in the West

along transport routes for Powder River basin coal. (NETS, fig.

less of a problem than upgrading and constructing adequate roadway. As was noted

previously, likely bottlenecks have been pinpointed on rail lines running east from the

basin through Nebraska and Iowa to Missouri

and south through Colorado and Texas. Traffic through the southerly corridor could be

eased by operation of two proposed 25-million-ton-per-year pipelines: the Texas Eastern

(Wytex) line from Gillette to Houston; and the

ETSI line from the basin through Oklahoma,

Louisiana, and Arkansas. The Wyoming State

Legislature passed a bill in 1974 specifically

authorizing export of water through the ETSI

line. This line has obtained the necessary

rights-of-way, air-quality permits, and EIS

clearance. It could become operational in the

mid-1980’s. Unresolved legislative and waterresource issues have impeded rapid development of slurry pipelines originating in the

basin. The lack of eminent-domain legislation

and a recent decision by the Governor of

Wyoming that pipelines should be developed

only if they use nonwater technologies are

significant constraints.

Managing the transportation of 1990 coal

production from the basin will require cooperation among Western railroads. The BN

and Chicago Northwestern (CNW) recently

constructed a line from Gillette to Douglas,

Wyo., which greatly improves the basin’s

coal-export capacity. But CNW’s coal haulage

also depends on use of UP track that runs

east-west through southern Wyoming. BN has

refused to share a connecting line with CNW,

which prevents that carrier from hauling coal

east on the UP track. CNW has proposed to

build its own connecting track, but has encountered strong opposition from local residents.

52 CNW, however, expresses con3-2). However, NETS used 1975 data that did not take into account post-l975 rail investment beyond what was underway in

that year. BN and other major Western rail haulers have significantly upgraded their mainlines since 1975 to meet heavier

current traffic. The BN, for example, originated less than 19

million tons of coal in 197o compared with 80 million tons in

1980 and 100 million tons forecast for 1981, according to BN

president Richard Bressler,

52 Powder River Basin Resource Council, “WYOBRASKA

Keeps Up the Pressure,” Powder River Breaks, September

1981.
222 . An Assessment of Development and Production Potential of Federal Coal Leases

fidence that it will be able to realize its plans

to haul approximately 45 million tons per

year from the Powder River basin in 1990.53

Other Wyoming Regions

Wyoming will also produce coal from the

Hanna, Rock Springs, and Kemmerer fields

in southern Wyoming, At the present time, all

of the coal produced in this region comes

from Federal mines—23 million tons of production in 1979, Coal production from this

region will increase during the 1980’s. The

UP serves these coalfields. The UP seems able

to haul expected tonnage without difficulty

from this area. Because there are more communities in southern Wyoming than in and

around the Powder River basin and because

UP carries other commodities, some communities may be adversely affected despite the

comparatively modest coal traffic increases.

Fort Union Region of

North Dakota and Montana

It is not cost effective to transport lignite

far from the mining site. Lignite has the lowest energy value and highest moisture content

of the domestically mined coals, These factors force utilities to burn lignite close to the

mine site. All of the powerplants currently

under construction or planned in North

Dakota will burn coal at the mine site.

Only one operating powerplant–the Big

Stone facility—consumed more than 1 million

tons of lignite annually from mines situated

more than 100 railroad miles away, This

South Dakota plant designed and built special

covered hopper cars for hauling lignite from

Knife River Coal Co. ’s Gascoyne Mine 350

miles away. The Milwaukee Road (Chicago,

Milwaukee, St. Paul, and Pacific Railroad)

owns and operates this 350-mile track over

which two unit-trains pass daily, The Milwaukee’s bankruptcy may result in cutbacks

53 Remarks of’ Douglas A. C hristensen, Vice president for

Marketing of C&NW Transportation Co., at the Coal Outlook

Conference Charting the Future of Western Coal, June 8-9,

1981.

in service. The Milwaukee Road Trustee requested a new freight rate, which would increase the transport costs of lignite by 65 percent. The partners at the Big Stone plant rejected this because the trustee was unwilling

to provide guarantees that any portion of the

new rate would be used to maintain the roadbed between the mine and the powerplants.

North and South Dakota have been spending

Railroad Recovery Act funds to maintain this

track, which is considered to be in worse

shape than any other stretch in the Milwaukee system. Milwaukee applied to its

bankruptcy court and to the ICC in May 1981

for permission to abandon this tract. The ICC

will make a recommendation to the court on

September 15, at which time a final decision

will be made.

While Gascoyne production has not been

constrained by transportation factors up to

now, Knife River’s New Liepzig project has

been delayed indefinitely by BN’s unwillingness to invest $20 million to $24 million to

upgrade the track that would carry about 2

million tons per year to a powerplant in Mandan, N. Dak. Knife River wants to prorate the

upgrading costs between itself and BN (which

owns extensive mineral rights along this line),

but BN contends that Knife River should

finance all the costs. BN stands to gain little

from this investment because the expected

traffic volume is so small. On the other hand,

Knife River has no other way to move coal

from this site.

Colorado

Transportation factors play a major role in

determining the market potential of Colorado

coals. Transportation costs are an important

variable because Colorado coal from underground mines must compete with cheaper

surface-mined coal from Wyoming and New

Mexico. Moreover, Colorado coal must be

shipped over the Rocky Mountains to reach

Midwest and South-Central markets, Mine

operators in the Green River region, the

State’s largest producing area, complain that

rapidly escalating rail rates are destroying
Ch. 8—Transportation ● 223

their competitiveness. The Denver & Rio

Grande Western (D&RGW), which serves

western Colorado, argues that its rates are

fair considering the high costs of upkeep

under difficult conditions, such as the Mofatt

Tunnel that leads to Denver and easterly

markets. Higher rates also reflect the cost of

new sidings and the installation of CTCS, the

railroad says. The D& RGW’s continued ability to move projected expanded coal output

from western Colorado to the front range is

open to question despite the railroad’s

assurances. The Green River-Ham’s Fork

environmental impact statement (EIS) found

that with 20 million tons of new annual production from new lease sales, about 75 percent of D& RGW’s capacity would be used.

One alternative that has been suggested by

local governments and mine operators to expand coal transportation capacity in northwest Colorado is construction of an extension

of the UP line from Rawlins, Wyo., to Craig,

Colo. No such extension of the UP into

D& RGW’s service area has actually been proposed.

Other rail capacity questions are apparent.

Until the Tongue Mesa Field and the San

Juan coalfield around Durango are served by

rail, it is unlikely that significant development will occur there. The Federal leases in

the Coalmont Field of the North Park region

probably cannot be developed until the abandoned UP line from Walden to Hebron is substantially upgraded. This line has sharp turning radii and steep grades. These improvements will probably not be made unless

enough coal can be shipped from the area

under long-term contracts to offset the costs.

Several coal mines in the Green River region truck their coal to railheads at distances

ranging from 2 to 30 miles. This has created

additional expense for the mine operators

and road damage to certain highways. Conveyors and rail spurs are being evaluated by

some companies to reduce truck use. One

coal slurry line originating in Colorado has

been discussed—the San Marco line from

Walsenburg to Houston, Tex. However, the

Colorado legislature has barred exportation

of the State’s water. This policy coupled with

other demands on local water resources

makes this pipeline an unlikely prospect

without Federal enabling legislation or legal

resolution of water-rights issues,

New Mexico

The OTA New Mexico task force estimated

that total coal production in the State could

increase from 14,6 million tons in 1979 to as

much as 72 million tons by 1990 under favorable conditions. Of this number, about 55

million tons would be exported, mostly to

utilities in California and Texas. Although

New Mexico has traditionally exported more

than half its in-State produced electricity to

out-of-State customers, the emphasis over the

next decade is likely to be shipping coal by

rail.

The construction of the Star Lake Railroad

in west-central New Mexico is a major factor

in this increased production. This line would

connect the Star Lake-Bisti area of the San

Juan basin, which contains one of the largest

untapped strippable coal deposits in the

Western United States, with the Santa Fe

main line at Prewitt, N. Mex. Five large

undeveloped leases and 28 outstanding preference right lease applications (PRLAs) are

found in this area, as well as large reserves of

fee, State, and Indian coal. The 114-mile Star

Lake line could carry almost 17 million tons

per year by 1990, and, if fully developed, this

area would be able to mine as much as 75 million tons per year. Production of about 8 million tons of coal from Federal leases in 1990

hinges on construction of this railroad, as

does an additional 18 million tons from mines

on land covered by PRLAs. Construction of

the Star Lake Railroad has been delayed

because of difficulties in obtaining all the

necessary rights-of-way. However, progress

has been made; a right-of-way over public

lands has been approved. Several questions

involving rights-of-way over public lands and

individual Indian allotment lands remain to

be resolved. About three miles of tribal trust

lands and 25 miles of allotment lands are involved. It is expected that all necessary rights-
224 Ž An Assessment of Development and Production Potential of Federal Coal Leases

of-way will be obtained. Construction would

begin within a few years after the right-ofway issues are settled and would be completed within 2 years, according the the Santa

Fe’s estimates.

Other transportation issues are relevant to

other coal development in New Mexico. Mine

construction on several Federal lease blocks

will require upgrading of local roads. A

230-kV transmission line would have to be

constructed to link the proposed New Mexico

Generating Station near Bisti with the existing electrical grid 209 miles to the

southeast. Another proposed rail connection

from mines on the Navajo reservation to the

east-west trunk line at Gallup is also under

consideration. The carrier—the Sant a

Fe—has acquired right of way to 22 miles and

the remainder is under discussion. This line

would carry between 4 million and 25 million

tons per year if completed.

Utah

Most Federal leases in central Utah are

located near existing road and rail transportation systems which appear to be adequate to

handle future production. In this area, coal

would be moved by truck, rail, or conveyor to

the powerplant or railhead. Improvements

and repairs to existing systems are underway.

Some mines currently have to truck coal 60

miles to rail connections, but this does not

seem to have been a constraining factor in

mine development, This truck haul would be

reduced when the planned Castle Valley Railroad extension is constructed.

Southern Utah, on the other hand, does not

have a well-developed transportation system

serving potential coal mining areas. Two coal

slurry pipelines 180 miles long would connect

the Alton Mine to the proposed Allen Warner

Valley Power Project. The slurry plan conflicts with Utah law restricting transfer of

water out of State, The Kaiparowits Plateau

Field is not currently served by rail or major

roads. Coal development there depends on

construction of a rail or slurry line to move

coal to market, A minimum of 30 million tons

of annual production is required to offset the

cost of building a rail line from the plateau.

Such a rail line has been under study, but no

date has been proposed for its construction.

Oklahoma

Oklahoma’s coal production, currently at

about 5 million tons per year, is not projected

to increase substantially over the next decade.

Utilities in Oklahoma buy coal from other

States, principally Wyoming, because of its

low-sulfur content. Oklahoma’s high-sulfur

steam coal is exported to generating plants in

other States that have less restrictive air

pollution requirements. Oklahoma’s metallurgical coal markets depend on demand

rather than supply-side or transportation factors. Much of Oklahoma’s current production

is trucked to rail and barge centers throughout the region. County roads and bridges adjacent to Federal coal properties are typically

in poor condition and some cannot accommodate heavy commercial traffic. Coal industry

spokesmen have expressed a willingness to

build new roads or repair existing ones. Rail

lines to major rail and barge connections are

ill-suited to transport large quantities of coal

efficiently, but should prove sufficient to handle expected output with some upgrading.

One Oklahoma coal operator has stated that

the “only way that is economically feasible (to

export Oklahoma coal) is by barge; the rail

rate is simply too high.”54

54 OTA correspondence with J. F. Porter, III, Vice-president

of Garland Coal & Mining Co., February 1981.
CHAPTER 9

Federal Coal Lease Management
Contents

Page

Legal Framework and Policy . . . . . . . . . . . . .227

Historical Development of Federal

Land Policies. . . . . . . . . . . . . . . . . . . . . .. ...227

Federal Coal Leasing Amendments Act

of 1976 ● **. , **o.*.*.....*.?*****.***** 231

Federal Land Policy and Management Act. . .232

1979 Federal Coal Management Program. . .233

Legal Issues Relating to Existing

Federal Leases . . . . . . . . . . . . . . . . . . . . ...238

Diligent Development and Related Concepts. . 238

Common Law Diligence. . .................238

The 1976 Diligence Regulations. . . .........239

Summary of Diligent Development and

Continuous Operations Regulations. .. ....239

Logical Mining Units. . ...................241

Diligence Extensions. . . . . . . . . . . . . . . . . . . .242

Continuous Operations. . .................244

Advance Royalties . . . . . . . . . ..............245

Cancellation of Leases. . ..................245

Application of the 1976 Diligence

Requirements to Existing Leases.. . .......245

Legal and Administrative Issues in the

Enforcement of Diligence Requirements. ..247

Determination of LMU and LMU Reserves

for Diligence ,..,. O*....?. . . . . . . . . ..* * 248

Relinquishments. . .......................252

Potential Production From Federal Coal

Leases and Diligence. . ..................252

Exchanges . . . . . . . . . . . . . . . . . . . . . ● ........252

Preference Right Lease Applications. .. ....255

Potential Production From PRLAs. . . . .. ....255

Procedures for Processing PRLAs. .........256

Litigation Involving PRLAs. . . . . . . . . . .. ....257

Other Legal and Administrative Issues

Related to PRLAs. . ...........9.........260

Unsuitability for Mining . . . . . . . . . . . . ......262

Page

Footnotes for Chapter9. .. ...............265

List of Tables

Talbe No. Page

73. Surface Acreage of Leases and PRLAs

74,

75*

76.

77,

78.

79.

by State and by Surface Ownership:

Sept 30, 1980, . . . . . ...................230

Federal Coal Leasing Amendments Act

of 1976: Summary of Major Provisions. ...232

Department of the Interior Division of

Functions and Responsibilities

Concerning Management of Federal Coal

Between the Office of Surface Mining,

the U.S. Geological Survey and the

Bureau of Land Management. ., ........235

Changes in Definitions of Diligent

Development and Continued Operation,

Proposed and Final Regulations . . . . . ....240

Changes in Definitions of Logical Mining

Unit and Logical Mining Unit Reserves

Proposed and Final Regulations. . .......243

Readjustment Schedule for Pre-FCLAA

Leases in Colorado, Montana, New

Mexico, North Dakota, Utah, and

Wyoming . . . . . . . . . . . . . . . ● .*..*,. ● .,.. 251

Processing Preference Right Lease

Applications . . . . .....................258

List of Figures

Figure No. Page

40. Principal Federal Landholdings in the

Conterminous United States . . . . . . . . . . . .228

41. Federal Land Grants for Railroads.. .. ...229

42. Federal Coal Management Program:

Department of the Interior Agency

Involvement . . . . .....................234
CHAPTER 9

Federal Coal Lease Management

Legal Framework and Policy

The Federal Government has both proprietary and sovereign responsibilities for Federal lands. A proprietary responsibility to

manage the publicly owned lands and natural

resources to meet the Nation’s needs for

energy, minerals, timber, agricultural production, and recreation while ensuring a fair

return on public resources; and a sovereign

responsibility to encourage and regulate commerce while at the same time protecting and

conserving the natural heritage. The statutes

and policies providing the framework of these

Federal responsibilities for the management

of Federal coal resources are reviewed

below.

Historical Development of

Federal Land Policies

Lands owned by the Federal Government

are either: 1) public domain lands, acquired

by cession, treaty or purchase from other sovereign nations; or 2) acquired lands purchased by the Government from private owners after the lands were made part of the

Union. By 1867, approximately 1.8 billion

acres of land had been added to the public domain through a series of purchases and treaties. Most of these public domain lands were

west of the Mississippi River, Figure 40

shows the distribution of federally owned

lands in the conterminous 48 States in 1976.

Federal land policy from the time the Nation gained independence through the end of

the 19th century had five objectives: 1) to produce revenue for the Government; 2) to facilitate settlement and growth in the various regions; 3) to reward war veterans; 4) to promote education and charitable institutions;

and 5) to encourage the construction of internal improvements, e.g., railroads, roads

and canals to promote transportation and

commerce.

Federal land policy has historically been

aimed at disposing of Federal land to private

interests through a number of devices including sales, military warrants, preemption,

homesteading, and direct grants to States

and railroad companies. Through each of

these mechanisms, vast areas of the public

domain were transferred to private ownership. Those areas that were less favorable for

economic use during the period of disposal of

public lands were largely retained by the Federal Government, and today constitute the

major part of the lands managed by the

Bureau of Land Management (BLM).

The intermingled landownership patterns

that are the legacy of earlier public lands

policies in the West have a direct and significant impact on the management of Western

Federal coal lands today. Two aspects, in

particular, created land ownership problems

for the development of Federal coal lands:

1) checkerboard land grants made to the

transcontinental railroads: and 2) severed

estates, the separation of surface ownership

from subsurface mineral ownership.

Railroad Land Grants.—Over 94 million

acres of Federal lands were given to the railroads directly as railroad land grants. An additional 37 million acres were granted to the

States for their use to encourage rail development within their boundaries. Figure 41

shows the location of these railroad grants.

Railroad grants were awarded on oddnumbered sections on either side of the proposed right-of-way, with even-numbered sections retained in public ownership. This resulted in what is called a “checkerboard”

ownership pattern and still influences the development of Western coal, particularly in

areas of North Dakota, Montana, Wyoming,

and in New Mexico where the transcontinental railroads were granted lands under the

Pacific Railroad Act. Many railroads sold

227
228 . An Assessment of Development and Production Potential of Federal Coal Leases

Figure 40.–Principal Federal Landholdings in the Conterminous United States (1976)

SOURCE: U.S. Geological Survey, Special Maps Branch, 1977

their grants both to encourage settlers and to

generate revenues to finance construction. A

substantial amount of railroad land grants

underlain with valuable coal deposits remains in railroad ownership today.

Surface Ownership and Mineral lnterests.—

The early 20th century policy of retaining

Federal ownership of subsurface mineral

rights while granting surface ownership to

private parties subsequently created problems for both parties of interest.’ The values

to the surface owner are in use of the land for

grazing, agriculture, recreation, timber, or

other surface activities. Mining, on the other

hand, frequently involves surface disturbance and can interfere with the surface

NOTE: Footnotes for this chapter are found on pp. 265-269.

owner’s use of the land. In large strip mines,

the surface landowner could be displaced

from the property for as much as 30 to 40

years over the life of the mine. Moreover,

even after mining, reclamation may not fully

restore all of the land’s previous characteristics. Under law, mining is considered the

dominant land use; the surface owner is compensated for any damages to or loss of buildings and other improvements on the land disturbed by mining. Large quantities of Federal

coal may lie below lands whose surface is

privately owned. Achieving an equitable

balance between the interests of the surface

owner and the interest of the public in making

coal resources available for development is

often a contentious and difficult administrative problem in the Western coal regions. Section 714 of the Surface Mining Control and
Ch. 9—Federal Coal Lease Management ● 229

Figure 41.— Federal Land Grants for Railroads

Oregon

he e shading shows the approximate

limits of the areas in which the railroads

I Wyoming ]

(n

Acreage granted

u Y

The shaded areas are in proportion to the acreage

received by the railroads. They do no show the

exact location of the granted lands,

which in general formed a checkerboard pattern.

SOURCE. Bureau of Land Management.
230 ● An Assessment of Development and Production Potential of Federal Coal Leases

Reclamation Act of 1977 (SMCRA)2 bars the

leasing of Federal coal under certain privately held lands unless the surface owner consents to the lease. Section 714 does not apply

to existing leases and preference right lease

applications (PRLAs)

2 which cover over

200,000 acres of privately owned surface

land. Table 73 shows the surface ownership

of Federal coal leases in Western coal States.

Reforms Under the Mineral Leasing Act

of 1920

Before 1920, Federal coal lands were sold

under the authority of the 1873 Coal Lands

Act. 3 Sales were limited to 160 acres for individuals and an association could purchase up

to 320 acres. The enactment of the Mineral

Leasing Act converted the policy of sale of

coal land to a policy of leasing rights to explore, develop, and remove coal and other

fuel and fertilizer minerals.’

Under the 1920 Act, the Secretary of the

Interior could issue prospecting permits that

entitled the permittee to the exclusive right to

prospect for coal in areas with no known coal

deposits. The permits were converted into

preference right leases if the permitters

could demonstrate the discovery of coal in

commercial quantities.

Under the provisions of the 1920 Act, Federal lands containing known commercial coal

deposits were divided into leasing tracts and

leases were awarded competitively to the

highest bidder for a cash bonus,

The Mineral Leasing Act provided for

leases to be issued for an indeterminate

period so long as the lessee could demonstrate diligent development and continuous

operation of the lease. Royalties were originally set at not less than 5 cents/ton of coal

and annual rentals could not be below 25

cents, 50 cents, and $1.00/acre for the first,

second through fifth, and sixth through 20th

years, respectively. The leases were subject

to readjustment of terms and rentals and royalties at the end of each 20-year period after

issuance.

1971 Moratorium on Coal Leasing

Between 1920 and 1970, Federal coal was

virtually leased on demand, i.e., wherever

and whenever anyone requested a lease sale

or permit, In 1970, a study conducted by BLM

found that although the amount of leased Federal coal had increased dramatically in the

previous decade, coal production had significantly declined in comparison to the amount

of coal under lease. ’ This study ultimately led

Table 73.—Surface Acreage of Leases and PRLAs by State and

by Surface Ownership: Sept. 30, 1980

Number of Total —- Federal lands– Native

State leases acres BLM FS Other American State Private

Colorado . . . . . . . . . . 127 126,875 45,773 22,589 0 0 0 58,498

Montana . . . . . . . . . 22 37,445 1,225 80 0 0 0 36,141

New Mexico . . . . . . . 29 44,761 20,047 0 0 9,148 7,086 8,478

North Dakota. . . . . . . 18 17,504 0 0 0 0 0 17,504

Utah . . . . . . . . . . . . . . 204 279,654 187,993 50,102 0 0 28,108 13,450

Wyoming . . . . . . . . . . 98 217,835 93,854 4,440 1,324 0 1,840 116,355

Total. . . . . . . . . . . . 498 724,074 348,892 77,211 1,324 9,148 37,034 250,426

SOURCE. U.S. Department of the Interior, Bureau of Land Management, Off Ice of Coal Management, Automated Coal Lease

Data System, Sept. 30, 1980.
Ch. 9—Federal Coal Lease Management ● 231

to an informal moratorium on further leasing

of Federal coal in 1971. In 1973 the moratorium was formalized by secretarial order

but modifications provided for new leases to

maintain existing mines or to supply nearterm production to satisfy existing market demands. 6 The Department of the Interior (DOI)

immediately began developing an improved,

long-term coal leasing program.

Meanwhile, congressional hearings on coal

leasing (1972-74) focused on whether Federal

coal leases were being held for speculation

and whether enforcement of lease conditions

of diligent development and continued operation were ineffectual. ’ As a result of the hearings, legislation amending the 1920 Mineral

Leasing Act eventually passed over President

Ford’s veto in August 1976.8 The amendments

included provisions limiting the holding of

Federal leases without production.

Energy Minerals Activity Recommendation

System (EMARS)

While Congress was considering changes

to the Mineral Leasing Act in 1975, DOI

announced a new coal leasing program,

EMARS, which involved the industry more directly in the tract selection process.9 Instead

of DOI identifying the areas eligible for leasing or offering leases in response to specific

sale requests, as was the procedure under

the 1920 Mineral Leasing Act, the EMARS

procedure was an integrated planning process for lease sales that involved annual

nominations for coal leasing areas by the industry and the public, The program was opposed by the western Governors and agricultural interests, and environmental groups. In

1975, the Natural Resources Defense Council

(NRDC) sued DOI for insufficiently describing

the EMARS program and its potential consequences in the environmental impact statement (EIS).

Two years later, the District Court for the

District of Columbia, in NRDC v. Hughes,

found the EMARS programmatic EIS inadequate under the National Environmental

Policy Act of 1969 (NEPA). The EIS failed to

consider the impacts of a no-action alternative of not establishing a new leasing program,

10 and the proposed leasing system described in the final EIS differed substantially

from the system described in the draft that

was circulated for public comment. The court

enjoined DOI from implementing the EMARS

program and from any new leasing, except

where the proposed lease was necessary to

maintain an existing mining operation or

necessary to provide reserves to meet existing contracts, until DOI fully complied with

the requirements of NEPA,11

The case was settled on June 14, 1978

under an agreement permitting additional

leasing and the processing of 20 PRLAs while

DOI developed a revised coal program and

EIS. 12 By 1980, leasing under the 1978 settlement had resulted in 29 new leases covering

20,822 acres containing 212 million tons of

recoverable reserves.

The task of preparing an adequate EIS and

formulating changes to the system of leasing

Federal coal reserves fell to the new Carter

administration and the moratorium continued. By April 1979, the EIS process was

completed.

13 In July 1979, under the Federal Coal Leasing Amendments Act of 1976

(FCLAA), l4 the Federal Land Policy and Management Act of 1976 (FLPMA),15 and the settlement of NRDC v, Hughes, DOI promulgated

regulations implementing a new Federal coal

leasing program.16 The first lease sales under

the new program were held in January 1981.

Federal Coal Leasing Amendments

Act of 1976

FCLAA contains several provisions aimed

at what were characterized in the hearings

as problems of speculation and nonproduction. The noncompetitive preference right

leasing system was repealed on the basis that

it did not grant the public a “fair return.” All

new leases are to be issued competitively and

no bid can be accepted for less than the fair

market value of the lease. The amendments

also provide for: 1) the consolidation of leases

into “logical mining units” (LMUS) to assure

maximum economic recovery (MER): 2) dili-
232 ● An Assessment of Development and Production Potent/al of Federal Coal Leases

gent development and continuous operation

on each lease, and 3) preparation of a comprehensive land use plan before coal lease

sales. See table 74 summarizing the major

provisions of FCLAA.

Federal Land Policy and

Management Act

FLPMA is the comprehensive “organic”

act for BLM. Before passage of FLPMA, BLM

operated on a series of authorizing acts, reorganization plans, and secretarial orders

which gave little guidance to the overall management of the public lands. Each act addressed a separate problem, but failed to set

goals and objectives for BLM as it attempted

to balance the use and development of Western lands under its jurisdiction.

In FLPMA, Congress directed BLM to manage the public lands (including Federal mineral interests under private surface) within a

framework of land use plannng. Among the

principles set out in the legislation are the

guidance to manage the lands for “multiple

use” and “sustained yield” and to assure that

the fair market value is received for the sale

or use of public resources. l7 BLM was directed to protect areas of critical environmental concern, to consider present as well

as future uses of public lands, to provide for

compliance with applicable Federal and State

pollution control laws, and to coordinate

planning activities with those of other Federal, State, and local agencies. Section 603 of

FLPMA also directs DOI to inventory and

study BLM roadless lands for potential congressional designation as wilderness areas.

The general requirements for management of

public lands under FLPMA also govern activities on Federal mineral leases.

Table 74.—Federal Coal Leasing Amendments Act of 1976: Summary of Major Provisions

Sec. 2

Sec. 3

All leases are to be sold by competitive bid

with 50 percent of lands offered in any year to

be awarded under a system of deferred bonus

bidding and a “reasonable number” of tracts

are to be reserved for leasing by public bodies.

No bid may be accepted for less than the fair

market value of the tract offered. Minimum

lease size is changed from 40 acres to such

size that “will permit the mining of all coal

which can be economically extracted”.

The Secretary shall not issue a lease to a

lessee who has held a lease for ten years (after

passage of FCLAA) without producing coal in

commercial quantities. All lands to be leased

must be included in a comprehensive land use

plan. DOI must consult with State and local

governments and provide opportunities for

public hearings if requested in preparing land

use plan. Secretary must consider the social,

economic, and other impacts on the communities affected and provide an opportunity

for a public hearing before a lease is issued.

DOI must obtain consent of Federal surface

management agencies outside DOI before leasing lands under their jurisdiction. DOI must

consult with State Governor before leasing National Forest lands. Advance notice must be

given of competitive lease sales including

publication in local newspapers. No mine plan

for leased lands may be approved unless it provides for maximum economic recovery of coal

within the tract. All coal leases are to contain

provisions requiring compliance with the

Federal Water Pollution Control Act and the

Clean Air Act.

Sec. 4

Sec. 5

Sec. 6

Repeals, subject to valid existing rights, provision allowing noncompetitive leasing through

issuance of prospecting permits and

preference right leases. Establishes a system

of nonexclusive exploration licenses. Licensees

must furnish all data acquired to Secretary,

however, information is kept confidential until

after the area is leased.

Repeals, subject to valid existing rights, provision for collective contracts for exploration,

development and operations. Substitutes concept of Logical Mining Unit (LMU). Allows consolidation of Federal leases and non-Federal

lands into single LMU if maximum economic

recovery is served. Lease terms in LMU may be

modified so that requirements imposed on

leases are consistent. Pre-FCLAA leases may

be included in LMU with consent of lessee.

Aggregate production from LMU may be used

to meet diligence and continued operation requirements. Mining plan approved for LMU

must provide for depletion of LMU reserves in

40 years. LMU may not be larger than 25,000

acres.

Amends section 7 of MLA to provide that

leases are for an initial period of 20 years with

readjustments at the end of the initial term and

every 10 years thereafter. Any post-FCLAA lease

not producing in commercial quantities at the

end of 10 years shall be terminated. Minimum

royalty for coal mined by surface methods shall

be 12.5 percent; with a lesser royalty as determined by the Secretary for coal recovered by

underground methods. Allows payment of advance royalties (determined by a fixed reserve to
Ch. 9—Federal Coal Lease Management ● 233

Table 74.—FederaI Coal Leasing Amendments Act of 1976: Summary of Major Provisions—Continued

Sec. 7

Sec. 8

Sec. 9

Sec. 10

Sec. 11

production ratio) in lieu of continued operation,

however, advance royalties may not be accepted

for more than 10 years during the period of any

lease. Requires submittal of a mining and

reclamation plan within 3 years after the lease is

issued; Federal surface management agency

must consent to DO I approval of mine plan.

Establishes program for comprehensive coal

exploration program for Federal lands to support land use planning and leasing operations.

Information from coal exploration program, except for certain proprietary data, is to be made

public.

Requires annual reports to Congress by the

Secretary of the Interior on the management of

Federal coal leases and by the Attorney

General on competition in the coal industry, including an analysis of whether the antitrust

laws are effective in preserving or promoting

competition in the coal or energy industry.

Amends the revenue distribution provisions of

section 35 of the MLA by reducing the amount

paid to the Reclamation Fund from 521⁄2 percent

to 40 percent (and raising the amount paid

to the States by 121⁄2 percent.) Directs that

States may spend their share of the revenues

as each State Legislature provides giving

priority to the needs of communities impacted

by Federal mineral leasing.

Requires Office of Technology Assessment

study of Federal coal leases.

Amends section 27 of the MLA to provide that

no entity may control more than 46,080 acres

Sec. 12

Sec. 13

Sec. 14

Sec. 15

of coal leases and permits in any one State nor

more than a total of 100,000 acres in the United

States. Lessees controlling more than 100,000

acres on passage of FCLAA may continue to

own their leases, but may not acquire more

leases until the total acreage controlled is less

than 100,000 acres. The definition of a lessee

entity is broadened to include a person, association, or corporation, or any subsidiary, affiliate

or persons controlled by or under common control with such person, association or corporation.

Authorizes leases to governmental entities of

acquired lands set aside for military or naval

purposes.

Repeals, subject to valid existing rights,

authority to lease an additional 2,560 acres of

coal lands to a lessee who has exhausted the

reserves in the original lease. Substitutes new

provision allowing noncompetitive leasing of

up to 160 acres as a modification to a contiguous existing lease.

Amends section 39 of MLA to limit authority of

Secretary to waive suspend or reduce advance

royalties.

Requires Secretary to consult with Attorney

General before drafting rules and regulations

or before issuing, renewing or readjusting

leases as to whether the proposed action

would create a situation inconsistent with the

antitrust laws.

SOURCE Office of Technology Assessment

1979 Federal Coal Management Program

Under the 1979 coal management program,

all Federal coal leasing is done under BLM’s

overall land use planning program established in section 202 of FLPMA. Figure 42

shows the lease planning and sales process

under the July 1979 Federal Coal Management Program. The land use planning and

coal management programs include a procedure for reviewing existing and potential

leases to determine their suitability for mining according to a series of “unsuitability

criteria. ” Areas are only considered for leasing if they have a high to medium coal development potential and have been classified as

a known recoverable coal resource area

[KRCRA). DOI’s unsuitability criteria are applied to these lands and a determination

made as to whether the lands are suitable for

leasing. Federal lands that have been leased

also are reviewed for their suitability for mining during the general land management

planning process and on mine plan approval.

The use of unsuitability criteria for existing

leases results in recommendations for mitigation requirements when a mine plan is proposed. The impact of the land use planning

unsuitability criteria on pre-FCLAA leases is

discussed more fully in chapter 10.

Several agencies and departments share

responsibility for management and oversight

of coal leases on Federal lands. Table 75
234 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 42.—Federal Coal Management Program: Department of the Interior Agency Involvement

Management of:

a) Existing leases

b) PRLAs

c) Emergency leases

d) Exploration Iicenses

e) Exchanges

Land use plannlng:

a) Identify coai iands

b} Unsuitabiiity findings

c) Resource tradeoffs

d) Surface owner consultation

w

Activity pianning:

a) Preliminary tract

identification

b) Tract ranking and

proposed tract

seiection

scheduling

within regions

c) Regionai saie EiSs

1

1,

Sales:

a) Decision by Secretary on selection

and scheduling of tracts for Saie

b) Notice of saie

c) Lease saie

Description of action Agency involvement

Regionai production

goais and

ieasing targets:

a) DOE regionai

production goais

b) RCT recommends

regionai leasing

targets based on

DOE goais

c) Secretary adopts

regionai ieasing

targets

Planning update — unsuitability criteria BLM; FWS

Expressions of interest BLM

Tract delineation GS; BLM

Tract site-specific analysis BLM; GS; OSM

Tract ranking BLM; GS; FWS; OSM

Tract selection, scheduling, and analysis BLM; GS; FWS

Regional EIS BLM; GS; FWS; OSM; HC & RS; BR; BIA; Dept

DEIS printing and distribution BLM

Public review period BLM; GS; FWS; OSM; HC & RS; BR; BIA

PFEIS, development, and review BLM; GS; FWS; OSM; HC & RS; BR; BIA

FEIS printing and distribution BLM

DOE review, Governor’s consultation BLM

Secretarial review decision on FEIS Secretary’s office

Prelease sale activities BLM; GS

Lease sale begin BLM

Key.

BIA Bureau of Indian Affairs

BR: Bureau of Reclamation

DEIS: draft environmental impact statement

FEIS: final environmental impact statement

HC & RS: Heritage, Conservation, and Recreation Service

PFEIS: preliminary final environmental impact statement

RCT: regional coal team

SOURCE: U.S. Department of the Interior, Bureau of Land Management, June 1980.
Ch. 9—Federal Coal Lease Management ● 235

Table 75.—Department of the Interior Division of Functions and Responsibilities Concerning Management of

Federal Coal Between the Office of Surface Mining, the U.S. Geological Survey and the Bureau of Land

Management (OSM, USGS, and BLM)

Prime Joint In consultation Concurrence

Functio n responsibility responsibility wit h from

Preleasing functions

Evaluate coal resources

Petition process for

designation of Federal

lands unsuitable for all

or certain types of surface coal mining

operations

Federal coal lands

review

USGS — — —

OSM — Receives petitions Surface Management — —

— Conducts hearings Agency and other

— Issues decisions appropriate State and local

agencies

OSM, USGS and other OSM — Establishes

surface managing ground rules

agencies and criteria

for Federal

coal lands

review

BLM — Applies criteria in —

determination of

suitability

Preparation of regional BLM lead agency (unless other —

EIS or site-specific pre- agency designated lead agency)

lease EIS concerning — Relating to lease tract

lease tract selection selection

OSM, USGS and other —

appropriate agencies

and State and local

interests

Preparation, special BLM —

lease terms and

conditions

OSM (responsibilities USGS, OSM, and DOE

under SMCRA - to

administer protection

requirements of the

act), USGS (responsibilities under the MLA)

Act as Secretary’s

official representative

in dealing with lease

applicants

BLM — — —

BLM (lease tract selection

function)

Surface owner consent — — —

Post/easing premining

functions

Prepare recommendations on applications

for use of federally

owned surface over

leased coal for rights

not granted in

Federal coal lease

BLM OSM and USGS (BLM

receives applications) - prior

to receipt of coal mining

plan it is solely USGS

responsibility to report

on surface use application

USGS before mining –

plan; OSM after mining

plan filed.

Delineation of “permit

area”

None until mining plan filed,

Then OSM assumes responsibility with concurrence of BLM

and USGS

— — BLM and USGS

Review, approval of

mining plans and major

modifications; lead

agency for preparation

of site specific EA/EIS

and coordination with

other agencies outside

DOI

OSM has lead responsibility (formerly assigned to USGS, became

essential function of OSM under

sec. 201, SMCRA)

BLM and USGS BLM regarding special USGS on production

requirements relating and recovery

to protection of natural requirements

resources; USGS regarding responsibilities

relating to development,

production and resource

recovery requirements

Exploration on leased OSM —

coal lands outside a

permit area

USGS receives application and

supervises operations for all exploration outside a permit area

—
236 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 75.—Department of the Interior Division of Functions and Responsibilities Concerning Management of

Federal Coal Between the Office of Surface Mining, the U.S. Geological Survey and the Bureau of Land

Management (OSM, USGS, and BLM)—Continued

Prime Joint In consultation Concurrence

Function responsibility responsibility with from

——.

Exploration on leased

coal lands within a perm it area

Responsibility for all

non-lessee activity on

lease land prior to

operations

Responsibility for deter

mining performance

bond

Functions and responsibilities during mining

operations

Act as Secretary’s

representative in dealing with lessees and/or

operators during

operations

Take necessary action

in emergency environmental situation

Conduct inspection

prior to abandonment

and specify and approve abandonment

procedures

Release of reclamation

bond (permanent

program)

Release of lease bond

OSM

BLM

OSM (BLM for interim period)

OSM (formerly USGS and BLM)

OSM (formerly USGS and BLM)

OSM (primary authority to approve abandonment procedures

and approve abandonment of

operations)

OSM

BLM

OSM and USGS coordinate USGS

a data exchange

— —

— —

USGS retains production —

functions; OSM assumes

environmental and enforcement functions; BLM retains

nonmining functions outside the permit area, including rights-of-way and

ancillary activities related

to mining. USGS and BLM

inspection in connection

with USGS, BLM functions

are coordinated with OSM

inspections (except BLM inspections outside the permit area). USGS makes

royalty audits and other

non field inspections independent of OSM

OSM has primary emergen–

cy authority; BLM and

USGS have such authority

when OSM inspectors are

unable to take action before

significant harm or damage

will occur.

USGS and BLM retain their

present procedures for

emergencies involving loss,

waste, or damage to coal

and other natural resources

and to other M LA functions

OSM, USGS, BLM - all have Private surface owner in

abandonment inspection case of private surface

responsibility

USGS

—

—

—

—

BLM concurrence in

approval of compliance, special requirements: protection

of natural resources

and post-mining land

use of affected lands.

USGS concurrence:

compliance with production and coal

resource recovery requirements.

— — BLM and USGS

concurrence.

— — OSM and USGS

concurrence.

NOTE: These agencies wiII also consult with the US Fish and Wildlife Service, both on a general basis, such as during Iand-use planning, and on a specific basis when

required by laws such as The Endangered Species Act

SOURCE U S. Department of the Interior, Bureau of Land Management, Final Environrnental Impact Statement, Federal Coal Management Program, April 1979, pp. 1.2
Ch. 9—Federal Coal Lease Management ● 237

shows the division of functions and responsibilities among BLM, the U.S. Geological

Survey (USGS), and the Office of Surface

Mining (OSM) within DOI for the administration of the Federal coal management program, BLM is the lead agency for implementing DOI’s preleasing and leasing functions;

OSM is responsible for processing designation petitions and coordinating mine plan

review; and USGS is responsible for evaluating the coal resource and enforcing Mineral

Leasing Act requirements and collecting

lease revenues from production. The Fish and

Wildlife Service is consulted on matters involving wildlife and potential impacts on

refuges. The Forest Service of the Department of Agriculture becomes involved as the

surface management agency for lands in national forests. In addition, the Department of

Energy (DOE) shares responsibility with DOI

for setting production levels, bidding systems

and diligence requirements on Federal energy mineral leases.18

As part of the coal management program

cooperative Federal-State regional coal management teams were formed which institutionalize the requirements in FCLAA for consultation with State and local governments

before leasing. The regional coal teams include representatives of the Western Governors who make specific recommendations to

the Secretary of the Interior on where, how

much, and when coal should be leased on

Federal lands.

DOI and DOE were given collateral responsibilities for establishing regional coal production goals and leasing targets. DOE periodically issues national and regional production goals. These goals in turn are considered

by DOI in establishing regional leasing targets. These production goals and leasing targets are used by the regional coal management teams in the “activity planning process”

which advises the Secretary on the tract

selection, ranking and scheduling proposed

lease sales in the regions.

Establishing regional production goals and

leasing targets is done in two stages: 1) tract

delineation and industry expressions of interest in each land-use planning area; and

2] tract ranking, selection and scheduling,

considered over the entire coal region. In

delineating tracts, BLM considers the interests of the industry, technical data provided by USGS and the States, MER estimates

of USGS, potential LMUs, surface ownership,

and regional leasing targets.

Final regional tract ranking, selection and

scheduling of lease sales is based on two determinations: 1) a site-specific environmental

analysis of the proposed tracts and 2) the regional coal team recommended ranking of the

tracts (high, medium, or low) considering geological and economic factors and potential

environmental and socioeconomic impacts of

mining. At every stage in the overall leasing

program, public participation is encouraged

through open meetings of regional coal teams,

public hearings, opportunities for comment

and review during the leasing target and EIS

processes. Most of this public participation

and consultation with State and local governments is required by FCLAA, After the planning, target setting, tract selection and ranking are completed, the tracts are offered for

sale by competitive bid. The first sale under

the new program was held in early 1981 in the

Green River-Hams Fork region and included

one small tract under a special small business

set aside arrangement.
238 . An Assessment of Development and Production Potential of Federal Coal Leases

Legal Issues Relating to Existing

Federal Leases

Of the 565 Federal leases in effect on

September 30, 1980, 535 leases containing

nearly all of the Federal coal reserves under

lease were issued before enactment of

FCLAA, and are thus subject in part to different legal requirements than leases issued

after FCLAA.

This section examines some of the major

legal issues related to the development and

management of existing Federal leases and

PRLAs including:

●

●

●

●

diligent development, and the related

concepts of continued operation, LMUS,

advance royalties, maximum economic

recovery and cancellation;

exchanges of reserves under existing

leases and PRLAs for unleased Federal

reserves;

processing and validity of pending

PRLAs; and

designation of areas on existing leases

that are unsuitable for surface mining under section 522 of SMCRA.

Diligent Development and

Related Concepts

The concept of “diligent development” of

Federal coal leases evolved over a period of

time. A number of legal uncertainties still

surround its practical application to existing

leases. There are several other important

concepts that are either directly or indirectly

related to diligent development: 1) requirements in the 1920 Mineral Leasing Act for

continued operation of a lease once diligent

development is achieved, 2) definition of

LMUs and logical mining unit reserves to

which diligent development and continued operation requirements apply, and 3) advance

payment of royalties either to encourage

diligent development, or in lieu of requirements for continued operation.

Common Law Diligence

Diligent development as an implied covenant of mineral leases originated in common

law. Under the Mineral Leasing Act, diligent

development is an express condition of every

Federal lease. The condition of diligent development imposes an obligation on the lessee to

produce the mineral so that the lessor receives the agreed royalty to fulfill the lessor’s

interest in the contract.

As applied to private mineral leases under

common law, the courts have generally defined diligence as requiring the lessee to “do

whatever under the circumstances would be

reasonably expected of a prudent operator of

a particular lease, having a rightful regard for

the interests of both the lessor and the

lessee." 19 Market considerations can be taken

into account, however, absence of a market is

not grounds for indefinite deferral of production. Each case is decided on its specific circumstances. Lease provisions can provide

more specific diligence standards such as requiring production to commence within a definite time period or allowing the lessee to pay

advance royalties instead of producing.

Compensation for the rights to explore and

develop mineral resources is often paid in a

two-part process. The initial rights to enter,

explore, and develop a leasehold are granted

to lessees in exchange for payment of a fee

(bonus) generally made at the time the lease is

executed. The second payment is a continuous periodic payment of royalties, usually

based on a percentage of the value of the

product. To ensure that the lessor received

some periodic payment even in the absence of

production, annual rentals are sometimes

negotiated that are based on minima l

payments for holding the lease,

The size of the bonus payment is generally

proportional to the probability of finding and

producing minerals at a profit. If the prob-
Ch. 9—Federal Coal Lease Management ● 239

ability of discovering commercial high-grade

resources is high, the bonus payment will be

large. If the probability of commercial discovery and economic production is highly uncertain, the bonus payment will be low.

Since royalties are not received until production begins, and production must continue

or the royalties will cease; a condition (stipulation) requiring continued operation is often

included in a lease agreement to ensure that

production and income continue. Failure to

pursue diligent development of the leasehold

and to continue production constitutes a

breach of the lease contract. The most viable

remedy available to a lessor harmed as the

result of a contractual breach is cancellation

of the lease, and if the lessor choses, resale

of the lease to one who will develop the

leasehold.

The 1976 Diligence Regulations

Although all pre-FCLAA coal leases by

statute must contain both the conditions of

diligent development and continued production, enforcement of these provisions were

rare until 1976 when the terms and meaning

of the provisions were defined by rulemaking.

Between 1920 and 1976, various lease terms

had imposed minimum investment and production requirements and advance royalties,

but these provisions were not applied universally to all leases.20

In response to an unprecedented period of

greatly expanded leasing during a time of

decreasing Federal coal production, DOI

began grappling with the problem of diligence

in lease development in 1970. Its initial efforts concentrated on policies aimed at applying economic leverage on lessees to ensure

production, e.g., such as gradually increasing

advance payment royalties, which would require front-end payments that would be offset

against future production. Congress, however, preferred the establishment of specific

time limits for development, therefore, in

1974-1975 DOI proposed regulations that

defined diligent development and set time

limits for performance, but also retained the

option for advanced royalty payments (see

table 76 summarizing proposed and final regulations on diligent development). Final regulations were promulgated by DOI in May

1976 shortly before passage of FCLAA, 21

With the approval of the 1976 FCLAA, a dual

system governing diligent development was

established, The legal effect was to create

two similar, but not identical diligence standards, one applying to leases issued before to

August 4, 1976 (pre-FCLAA), and the second

applying to leases issued after that date (postFCLAA). These regulations have remained

largely unchanged since repromulgation in

December 1976 to include FCLAA requirements. 22 The Department of Energy Organization Act of 1977 transferred the Secretary of

the Interior’s authority to issue regulations on

diligence for Federal leases to the Secretary

of Energy.’) The Secretary of the Interior retains the responsibility for enforcement, but

he cannot change these regulations.

Summary of Diligent Development and

Continuous Operations Regulations

Section 7 of the Mineral Leasing Act of

1920 requires that all Federal coal leases are

subject to diligent development and continuous operations. Lessees failing to meet

these conditions can lose their Federal coal

leases. Moreover, under section 3 of FCLAA,

after August 4, 1986, with few exceptions,

lessees who have held a nonproducing lease

for 10 years or more cannot obtain any new

Federal coal leases.24

In 1976, DOI issued regulations defining

diligent development for Federal coal leases

as timely preparation for and actual production of coal in commercial quantities from the

lease, or from the LMU of which the lease is a

part, by June 1, 1986 or within 10 years after

the lease is issued, whichever is later.

These regulations established two separate standards for diligent development of

Federal leases by defining commercial quantities differently for pre-FCLAA and postFCLAA leases. Commercial quantities for

pre-FCLAA leases are defined as “production
240 An Assessment of Development and Production Potential of Federal Coal Leases

Table 76.—Changes in Definitions of Diligent Development and Continued Operation,

Proposed and Final Regulations (1974-79)

Source Diligent development Continued operation

Federal Register

Dec. 11, 1974

(Proposed)

39 F.R. 43229

Diligent development means: preparing to extract

coal from an LMU in a manner and at a rate consistent with a mining plan approved by the mining

supervisor. Qualifying activities and expenditures

include environmental monitoring and baseline

Continuous operations defined as: extraction, processing,

and marketing of coal in commercial quantities from the

LMU without interruptions totaling more than 6 months in

any calendar year except as provided in 30 U.S.C. 207

and in the lease.

studies, geological and geophysical studies,

engineering feasibility studies, mine development

and construction work, and contracts for purchase

or lease of equipment undertaken for the purpose of

obtaining production from the LMU.

Lessee must report on activities in support of

diligent development to mining supervisor every 2

years and indicate plans for continuing diligent

development for following 2-year period.

Federal Register

Dec. 31, 1975

(Reproposed)

40 F.R. 60070

Federal Register

May 28, 1976

(Final)

41 F.R. 21779

Diligent development means timely preparation for

and initiation of production from the LMU of which

the lease is a part so that one-fortieth of the LMU

reserves associated with the lease are extracted

within 10 years from the effective date of the regulation or issuance of the lease, whichever is later.

Additional time for meeting diligence may be

granted for a period equal to the time during which

diligent development was significantly impaired by:

1. a strike, the elements or casualties not attributable to the lessee;

2. an administrative delay in the DOI not caused

by the lessee’s action; or

3. extraordinary circumstances not attributable to

the lessee and not foreseeable by a reasonably

prudent operator (extraordinary circumstances

do not include: conditions arising out of normally foreseeable business risks such as fluctuations in prices, sales, or costs, including

foreseeable costs of environmental protection

requirements; commonly experienced delays in

delivery of supplies or equipment; or inability to

obtain sufficient sales).

Diligent development defined as: timely preparation

for and initiation of production from the LMU of

which the lease is a part so that one-fortieth of the

LMU reserves associated with the lease are extracted within a period of 10 years from the effected

date of the regulations (i.e., by June 1, 1986) or from

the issuance of the lease, whichever is later.

Extensions may be granted for time during which

diligent development is substantially imparied by:

1. a strike, the elements or casualties not attributable to the lessee;

2. an administrative delay in the DOI not caused

by the lessee’s action; or

3. extraordinary circumstances not attributable to

the lessee and not foreseeable by a reasonably

prudent operator.

An extension may also be granted for up to 5 years

(i.e., to June 1, 1991) if the lessee cannot meet

diligence because of:

—time needed for development of an advanced

technology (e.g. in situ gasification or liquefaction processes);

—the large magnitude of the project (ordinarily 2

million tons per year for an underground mine

and 5 million tons per year for a surface mine);

o r

—a contract or equivalent firm commitment for

the sale of the first 21⁄2 percent of the LMU reserves after the 10-year period.

Continuous operations defined as extraction, processing,

and marketing of coal from the LMU after diligent development has been achieved in an amount of 1 percent or

more of the LMU reserves in each calendar year subject

to the exceptions in 30 U.S.C. 207 and in the lease.

Continuous operations defined as the extraction, processing, and marketing of coal in the annual average amount

of 1 percent or more of the LMU reserves computed on a

3-year basis including the 2 previous years.

With approval of the mining supervisor, advance royalties may be paid in lieu of continuous operations for

leases issued or readjusted after the effective date of the

regulations,
Ch. 9—Federal Coal Lease Management 241

Table 76.—Changes in Definitions of Diligent Development and Continued Operation,

Proposed and Final Regulations (1974-79)—Continued

Source

Federal Register

Oct. 15, 1976

(Proposed)

41 F.R. 45571

Federal Register

Dec. 29, 1976

(Final)

41 F.R. 56643

Federal Register

Mar. 19, 1979

(Proposed)

44 F.R. 16800

Federal Register

July 19.1979

(Final)

44 F R 42583

NOTE This table gen

Diligent development

For pre-FCLAA leases not readjusted after Aug. 4,

1976, diligent development means timely preparation for and initiation of production from the LMU

of which the lease is a part so that coal IS actually

produced in commercial quantities by June 1, 1986

(commercial quantities IS defined as production of

one-fortieth of the LMU reserves associated with

the lease). Extensions may be granted under the

same conditions as in the May 1976 final regulations, but the period for meeting diligence cannot

be extended beyond Aug. 4, 1986, or the date the

lease IS first subject to readjustment after FCLAA,

whichever IS later

For post- FCLAA leases and all readjusted preFCLAA leases, diligent development means timely

preparation for and initiation of production from the

LMU of which the lease IS a part so that coal IS actually produced in commercial quantities (defined as

1 percent of the LMU reserves) by 10 years after the

effective date of the lease or by June 1, 1986 or by

the date on which the pre-FCLAA lease IS first subject to readjustment after FCLAA, whichever IS later.

Extensions granted to pre-FCLAA leases can continue in effect after readjustment, but only until Aug.

4, 1986.

For pre-FCLAA leases: Diligent develop-merit meanstimely preparation for and initiation of production

from the LMU of which the lease IS a part so that

coal IS actually produced in commercial quantities

(defined as one-fortieth of the LMU reserves) by

June 1, 1986 Extensions may be granted under

same conditions as May 1976 final regulations.

For post. FCLAA leases: diligent development means

timely preparation for and initiation of production

from the LMU of which the lease IS a part so that

coal IS actually produced in commercial quantities

(defined as 1 percent of the LMU reserves) within 10

years from the effective date of the lease (No provisions for any extensions for post-FCLAA leases are

included in the regulations.)

No substantive changes proposed to December

final regulations (The authority to promulgate

rules relating to diligence and minimum production

requirements for Federal leases was transferred to

the Secretary of Energy by section 302 of the

Department of Energy Organization Act )

No substantive changes to December 1976 final -

regulations—relevant sections renumbered as part

of new coal management program regulations

erally summarizes the regulations rather than quoting them in full.

Continued operation

‘Continued operation means the extraction, processing, and

marketing of coal in the amount of 1 percent of all the

LMU reserves associated with the lease for each of the

first 2 years of continued operation and in an annual average amount of 1 percent of all the LMU reserves associated with the lease for all following years The annual

average amount will be calculated on a 3-year basis with

the 2 preceding years

Continued operation means production of 1 percent of

the LMU reserves in each of the first 2 years after meeting diligence, and production at an annual average rate of

1 percent of the LMU reserves thereafter. The annual average rate IS calculated on a 3-year basis with the 2 previous years

No substantive changes proposed to December 1976

final regulations

No substantive changes to December 1976 final regulations-relevant sections renumbered as part of new coal

management program regulations.

Logical Mining Units

The current regulations define diligence

of one fortieth (21/2 percent) of the recoverable reserves of the LMU of which the lease

is a part. ” For post-FCLAA leases, commercial quantities are defined as “production of and continuous operations requirements acone percent of the lease’s LMU reserves cording to LMUS rather than leases. The bawithin 10 years after lease issuance, ” Under sis of the LMU concept, as generally undercertain circumstances, the diligence period stood, is that geological and engineering

can be extended for pre-FCLAA leases, characteristics should delineate the bound-
242 ● An Assessment of Development and Production Potential of Federal Coal Leases

aries of the area that can be leased and

mined economically with appropriate environmental safeguards. In practice, however,

the legal right to mine coal often dictates the

area to be developed, which can result in a

less than optimal mining unit, especially in

areas with scattered and diverse ownership.

The concept, with some modification, was incorporated into the 1976 diligence regulations and FCLAA. The regulations currently

define an LMU as:

. , . an area of coal land that can be developed and mined in an efficient, economical,

and orderly manner with due regard for the

conservation of coal reserves and other resources. An LMU may consist of one or more

leases and may include intervening or adjacent non-Federal lands, but all lands in an

LMU must be contiguous, under the effective

control of a single operator, and capable of

being developed and operated as a unified

operation with complete extraction of the

LMU reserves within 40 years from the date

of first approval of a mining plan for that

LMU. No LMU approved after August 4,

1976, shall exceed 25,000 acres, including

both Federal and non-Federal coal deposits.25

Notwithstanding this definition, the rules also

provide that “each lease shall automatically

be considered to constitute an LMU on the effective date of the lease or June 1, 1976,

whichever is later. 26 The single lease LMU

can later be modified to add other Federal or

non-Federal coal with the approval of DOI,

but the enlarged unit must meet the general

LMU criteria. The single lease LMU was established in the May 1976 regulations primarily for administrative convenience in applying diligent production requirements, however, it was reinforced at least indirectly by

section 5 of FCLAA which requires the lessee’s consent before pre-FCLAA leases can

be consolidated into a designated LMU under

that section. Table 77 summarizes the development of the LMU concept in DOI regulations.

For pre-FCLAA leases, the LMU is determined by the lease boundaries, and the LMU

reserves for diligence and continuous requirements are the recoverable reserves of

the lease unless the lessee petitions either to

have the LMU boundaries modified to include

other Federal leases or non-Federal coal or to

relinquish portions of the lease reserves that

will not be mined. If a new LMU is designated, the aggregate production from all

lands in the unit can be used to meet diligence

for all producing and nonproducing leases in

the unit.

Diligence Extensions

Extensions can be approved for pre -

FCLAA leases for delays in meeting diligence

because of conditions that are beyond the

control of the lessee. These extensions are required by sections 7 and 39 of the Mineral

Leasing Act.27 These nondiscretionary extensions are granted for a period of time equal to

the time during which diligence is impaired

by: strikes, weather conditions, casualties,

Government delays, or extraordinary circumstances that are not the fault of the operator.

Regulations on whether and under what

circumstances nondiscretionary extensions

might be available to post-FCLAA lessees

have not yet been promulgated.28

In determining whether such extraordinary circumstances exist, the regulations

specifically exclude “any condition arising

out of normally foreseeable business risks

such as: fluctuations in prices, sales, or costs,

including foreseeable costs of compliance

with requirements for environmental protection; commonly experienced delays in delivery of supplies or equipment; or inability to

obtain sufficient sales. ’29

The pre-FCLAA lessee can also apply for a

single extension of up to 5 years, i.e., up to

June 1, 1991, under certain circumstances.

These discretionary extensions may be

granted for: 1) additional time for developing

new coal technologies, such as synfuels or

nonwater-based coal slurry pipelines; 2) extraordinarily large or complex mining operations (generally exceeding 2 million tons per

year for underground mines and 5 million

tons per year for surface mines); or 3) firm

contracts to produce and deliver the first 21⁄2
Ch. 9—Federal Coal Lease Management . 243

Table 77.—Changes in Definitions of Logical Mining Unit and Logical Mining Unit Reserves

Proposed and Final Regulations (1974.79)

Source

Federal Register

Dec. 11, 1974

(Proposed)

39 F.R. 43229

Federal Register

Dec. 31, 1975

(Reproposed)

40 F.R. 60070

Federal Register

May 28, 1976

(Final)

41 F.R. 21779

Logical mining unit

An LMU is a compact area of coal land that can be

developed and mined in an efficient, economical,

and orderly manner with due regard for conservation of coal reserves and other resources and in accordance with an approved mining plan,

The LMU may consist of one or more Federal leaseholds and may Include Intervening or adjacent nonFederal lands insofar as all lands are under the effective control of a single operator. Mining supervisor (MS) authorized to approve or establish an

LMU.

All leases must be included in an LMU within 2

years from effective date of regulations If the

lessee IS unable after a good faith effort to form an

LMU as defined in the regulations, a single lease

will be treated as an LMU for diligence and reporting requirements.

An LMU IS an area of coal land that can be developed and mined in an efficient, economical, and

orderly manner with due regard to the conservation

of the coal reserves and other resources. An LMU

may consist of one or more Federal leases and may

Include Intervening or adjacent non-Federal lands, if

all lands are under the control of a single operator

and can be developed and operated as a unified

mine.

The MS IS authorized to approved or establish

an LMU.

Every Federal lease wiII automatically be considered an LMU; the LMU boundaries may later be

changed:

1. at request of lessee with approval of MS with

concurrence of BLM;

2 at discretion of MS with concurrence of BLM;

3. at request of BLM with approval of MS.

An L-MU IS an area of-coal land that can be developed and mined in an efficient, economical, and

orderly manner with due regard to the conservation

of the coal reserves and other resources. An LMU

may consist of one or more Federal leases and intervening or adjacent non-Federal lands, but all

lands in an LMU must be under the effective control

of a single operator and capable of being developed

and operated as a unified mine

Every lease wiII automatically be considered by

itself an LMU as of the effective date of the lease or

the regulations, whichever IS later,

Any LMU other than a single Federal lease wiII

become effective only on its approval by the MS

where it IS requested by the lessee. Boundaries of

LMU may later be changed on application by the

lessee and with approval of the MS and after consultation with BLM.

Federal Register” An L-MU IS an area of coal land that can be devel - -

Oct. 15, 1976 oped and mined in an efficient, economical, and

(Proposed) orderly manner with due regard for conservation of

41 F.R. 45571 the coal reserves and other resources. An LMU may

consist of one or more Federal leases and intervening or adjacent non-Federal lands, but all lands

in the LMU must be contiguous, under the effective

control of a single operator and capable of being

developed and operated as a unified operation with

complete extraction of the LMU reserves within 40

years of first approval of the mine plan for the LMU,

No LMU, except those approved before Aug 4, 1976,

can exceed a total of 25,000 acres of Federal and

nonfederal lands,

Logical mining unit reserves

No definition proposed

As of a given date LMU reserves are the sum of 1)

estimated recoverable Federal reserves under lease in the

LMU, and 2) estimated non-Federal recoverable reserves

that wiII be mined before extraction of all Federal reserves in the LMU.

Federal LMU reserves will be the estimated reserves on

the effective date of regulations—or the date of the lease,

whichever is later,

Reserves may be adjusted by MS whenever significant

new information becomes available about the amount of

such reserves, including the time at which a mining plan

IS approved for the Federal portion of the LMU.

—.

As of a given date, LMU reserves are the sum of 1) estimated recoverable Federal reserves under lease in the

LMU, and 2) estimated non-Federal recoverable reserves

that wiII be mined before extraction of all the Federal reserves in the LMU. LMU reserves associated with a Federal lease are the estimated LMU reserves as of effective

date of approval of LMU.

LMU reserves may be modified when MS approves modification of LMU boundaries or whenever significant new

information becomes available about the amount of recoverable reserves including when a mine plan IS approved

—- —..

Definition of LMU reserves is the same as May 1976 -

final regulations.

The estimated LMU reserves may be adjusted by the

MS whenever a modification of the LMU boundaries

IS approved, or the lessee surrenders deposits under

lease in the LMU, or whenever additional Information

becomes available about the amount of such reserves

including when a mine plan is approved,
244 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 77.—Changes in Definitions of Logical Mining Unit and Logical Mining Unit Reserves

Proposed and Final Regulations (1974-79)—Continued

Source—

Federal Register

Dec. 29, 1976

(Final)

41 F.R. 56643

Federal Register

July 19, 1979

(Final)

44 F.R, 42583 now

43 CFR 3400.0-5

— — —

Logical mining unit — -——

Notwithstanding the above definition, every Federal

lease will automatically be considered an LMU on

the effective date of the lease or June 1, 1976,

whichever is later.

An LMU other than a single lease LMU will become

effective only at the direction of the MS or by approval of the MS at the request of the lessee.

(These designated LMU’s must meet the requirements of section 5 of FCLAA.) —-.

Unchanged from October 1976 proposed ‘ - -

regulations,

An LMU is an area of coal land that can be developed and mined in a efficient, economical, and

orderly manner with due regard for the conservation

of coal reserves and other resources. An LMU may

consist of one or more leases and may include

intervening or adjacent non-Federal lands, but all

lands in the LMU must be contiguous (i.e., having

one point in common, including cornering tracts),

under the effective control of a single operator, and

capable of being developed and operated as a

unified operation with complete extraction of the

LMU reserves within 40 years from the date of first

approval of the LMU mine plan. No LMU approved

after Aug. 4, 1976 may exceed a total of 25,000

acres of Federal and non-Federal lands.

Notwithstanding the above definition, every Federal

lease will automatically be considered an LMU on

the effective date of the lease or June 1, 1976,

whichever is later.

An LMU, other than a single lease LMU, wiII

become effective only on approval by the MS on application by the lessee, or by direction of the MS, or

by designation during the normal tract delineation

phase of the coal activity planning process. The MS

will not approve the designation of such an LMU

unless maximum economic recovery of all the

Federal coal deposits in the LMU will be achieved.

Logical mining unit reserves

Logical mining unit reserves are the sum of 1) estimated

recoverable Federal reserves under lease in the LMU and

2) estimated non-Federal recoverable reserves in the LMU.

The LMU reserves associated with the Federal lease are

the estimated recoverable reserves on the effective date

of the LMU.

The LMU reserves may be adjusted by the MS whenever

the LMU is modified, or the lessee surrenders deposits in

the LMU, or whenever significant new information

becomes available about the amount of such reserves including when a mine plan is approved.

LMU–reserves mean the sum of 1) estimated recoverable

reserves under Federal lease in the LMU, and 2) estimated non-Federal recoverable reserves in the LMU. The

Federal lease LMU reserves are estimated as of the date

the LMU becomes effective. The LMU reserves may be adjusted by the MS whenever the LMU boundaries are modified or when significant new information becomes available on the amount of such reserves.

— NOTE’ This table generally summarizes the regulations rather than quoting them in full

percent of the coal after the lo-year period. 30

These discretionary extensions are not available for post-FCLAA leases.

Continuous Operations

After attaining diligence, both pre-FCLAA

and post-FCLAA lessees must meet the continuous operations requirements. The regulations define continuous operations for all

Federal leases as production of an average of

1 percent of the LMU reserves annually, with

1 percent produced in each of the 2 years immediately following the year in which the

lessee meets diligence. With approval of DOI,

the lessee can pay advance royalties in lieu of

actual production in order to satisfy continuous operations requirements. Such advance

royalty payments, however, cannot be made

in lieu of continued operation for more than

10 years during the life of the lease. Continuous operations requirements for pre- and

post-FCLAA leases can be suspended during

periods when production is interrupted because of conditions beyond the control of the

lessee. Minimum annual production require-
Ch. 9—Federal Coal Lease Management “ 245

ments can also be lifted when operations on

the lease are suspended with the approval of

the mining supervisor to promote conservation of coal resources. Table 76 shows

the development of continuous operations

regulations.

Advance Royalties

Advance royalties are commonly used by

private coal lessors to ensure that mine production stays on schedule. If production proceeds according to the predetermined schedule, the lessee continues to pay the regular

royalty, but if production is lower than scheduled, advance royalties are collected on the

difference between scheduled and actual

production. The purpose for using advance

royalties is to provide a financial incentive

for the lessee to develop the lease.

Advance royalties have been used in several ways in pre-FCLAA leases: 1) in lieu of

continued operation requirements for leases

issued between 1920 and 1971; 2) as an incentive to begin production for leases issued

during the moratorium between 1971 and

1976 by requiring payment of advance royalties beginning in the sixth year after issuance

of the lease based on a predetermined schedule (similar to the way advance royalties are

used in the private sector); and 3) in lieu of

continued operation for up to 10 years during

the term of the lease as allowed by FCLAA.32

Advance royalties are currently based on

an annual production rate that would exhaust the mine reserves in 40 years (2.5 percent per year) .33 This rate is higher than the 1

percent rate required to satisfy continuous

operation regulations and thus is an incentive

to produce.

Cancellation of Leases

Under section 31 of the Mineral Leasing

Act of 1920 if the lessee fails to comply with

the terms of the lease, a provision of the act,

or general regulations issued under the act

that were in force at the date of the lease, the

Secretary may ask the Justice Department to

sue in Federal court to have the lease forfeited and canceled.34 For pre-FCLAA lessees,

breach of the conditions of diligent development or continued operation could result in

cancellation of the lease in court proceedings

if the court decided that the lessee did not

meet diligence because he or she did not

satisfy the minimum production defined in the

1976 regulations (or some other standard). 35

Section 6 of FCLAA provides that any postFCLAA lease not producing in commercial

quantities 10 years after issuance shall be

terminated automatically. Termination is an

administrative proceeding and is subject to

judicial review. The May 1976 DOI regulations limited the circumstances that the

Secretary could consider in decidin g

whether to cancel a lease for failure to meet

diligence by generally excluding lack of

markets.

36 Both pre- and post-FCLAA leases

must be canceled through court proceedings

brought under the general provisions of section 31 for any other breach of the lease

terms or conditions, or for violation of the act

or DOI regulations.

Application of the 1976 Diligence

Requirements to Existing Leases

Since 1976, DOI has maintained that the

1976 diligence regulations are genera l

regulations implementing the Mineral Leasing Act which are applicable to all coal leases

and that the regulations, thus, need not be

made specifically part of individual leases

through amendment or readjustment. The

diligence regulations and other aspects of the

coal management program are currently

under review by the Reagan administration

and could be modified. Whether or not the

1976 regulations are eventually held to be

generally applicable to all leases, under certain circumstances the diligence requirements can be made part of individual leases:

1) by voluntary amendment of the lease terms

by mutual agreement between DOI and the

lessee; 2) by readjustment at the end of the

lease term; 3) by amendment as part of the

designation of a new LMU under section 5 of

FCLAA; or 4) by operation of existing lease

terms incorporating future regulations. If the
246 ● An Assessment of Development and Production Potential of Federal Coal Leases

requirements are specifically incorporated

into a lease, they are clearly applicable and

enforceable for that lease.

Voluntary Amendment

At the request of DOI, some lessees have

voluntarily agreed to lease revisions incorporating the diligent production requirements. In other instances, DOI could negotiate the lessee’s consent to revise the lease to

include the 1976 regulations as part of

another transaction involving the lease, such

as a modification or segregation, or in exchange for DOI’s agreement not to move immediately to enforce the minimum production

requirements contained in some existing

leases.

37

Readjustment

Pre-FCLAA leases were originally issued

for indeterminate periods subject to readjustment of lease terms, conditions, rentals and

royalties at the end of each 20-year period

following issuance. The Secretary of the Interior has broad discretion in setting new

lease terms. Readjustment generally results

in incorporating any changes in the laws and

regulations governing leases that were not

applicable at the time the original lease was

issued. At readjustment, pre-FCLAA diligence requirements are expressly made part

of the new lease terms. If the new terms are

unacceptable, the lessee can either: 1) decline extension of the lease; or 2) appeal or

protest the revised terms. Leases readjusted

after August 4, 1976 are to include the 1976

diligence requirements that apply to preFCLAA leases. About 244 pre-FCLAA leases

are due for readjustment before June 1, 1986.

Over 200 pre-FCLAA leases are not due for

readjustment until after the initial 1986

diligence “deadline,”

Amendment of Lease Terms on

Designation of a Section 5 LMU

Under section 5(b)(4) of FCLAA, when one

or more leases, including pre-FCLAA leases

with the consent of the lessee, are consolidated into an LMU, the provisions of any

Federal lease in the LMU may be amended so

that mining will be consistent with the requirements imposed on that logical mining

unit. 38 Although “consistency” is not defined

and the Secretary is not required to amend

the lease, the LMU designation may be used

as an opportunity to provide for express application of diligence regulations to leases

within the LMU. However, such revision

would require the lessee’s consent.

As another result of an LMU designation

under section 5(b)(3) of FCLAA, the Secretary

may (but is not required to) provide, “among

other things, that (i) diligent development,

continuous operation, and production on any

Federal lease or non-Federal land in the

logical mining unit shall be construed as occuring on all Federal leases in that logical

mining unit . . .“ Since approval of an enlarged LMU is discretionary, the lessee’s

consent to include the 1976 diligence requirements as a stipulation in the lease might be

used as a condition for obtaining an LMU

approval. 39

Existing Lease Terms That Incorporate

Subsequent Regulations

Federal coal leases issued or renewed

after 1965 contain a provision in the initial

clause of the lease stating that the lease is

issued:

. . . pursuant and subject to the terms and

provisions of (the Mineral Leasing Act of

1920), and to all reasonable regulations of

the Secretary now or hereafter in force

which are made a part hereof . , .40

By accepting the lease with this provision

(referred to as the “hereafter clause”), the

lessee has specifically agreed to be bound by

future “reasonable regulations” made applicable to existing leases without the

necessity of formally amending the lease

terms. As a result of this express agreement,

leases with this clause are subject to the 1976

diligence regulations by operation of the prior

lease term. Violation of the subsequent regulations would, therefore, be a violation of
Ch. 9—Federal Coal Lease Management “ 247

the lease provisions and make the lease subject to cancellation under section 31 of the

Mineral Leasing Act.41 The reasonableness of

any subsequent regulations would be determined according to general principles of administrative law if the issue were ever litigated. The hereafter clause has been used in

thousands of other Federal mineral leases for

over 45 years, The meaning of the “hereafter

clause” and its impact on the applicability of

the 1976 diligence regulations on coal leases

have not yet been judicially construed.

Legal and Administrative Issues

in the Enforcement of Diligence

Requirements

The impact of the 1976 diligence regulations on Federal coal leases is uncertain. The

regulations requiring actual production within 10 to 15 years were generally opposed by

the coal industry, and the major industry

trade groups. The National Coal Association

and the American Mining Congress, have

continued to criticize the policy.

While many lessees have accepted the

1986 deadline, and many will in fact meet

diligence by then (see ch. 6 of this report),

legal challenges are likely if DOI enforces the

requirements against those lessees who are

not in compliance. Among the major legal objections which the industry has raised are:

I) the regulations are arbitrary, unreasonable and exceed the Secretary’s authority

under the Mineral Leasing Act because of the

stringent compliance period imposed and the

lack of flexibility in measuring diligence as

production of 21⁄2 percent of the LMU reserves; 2) the regulations violate the Mineral

Leasing Act by imposing new terms and conditions on the lessee which can only be done

at readjustment; 3) the regulations are ineffective to the extent that they conflict with

specific lease provisions; and 4) the regulations abridge the lessee’s contractual rights,

thus, violating the constitutional prohibition

against deprivation of property without due

process of law or just compensation.

The only litigation challenging the application of the diligence requirements in the 1976

regulations to pre-FCLAA leases, Mobil Oil

Corp. v. Andrus, was settled out of court and

thus did not establish any precedent. 42 As a

result of the settlement, Mobil received approval of a 5-year extension in the period for

meeting diligence for its 1971 lease.

The possible difficulties in enforcing DOI’s

diligence regulations were recognized in the

Secretarial Issue Document for the Federal

Coal Management Program,” One of the major uncertainties is the absence of a prior enforcement history for diligence for Federal

coal leases. Before promulgation of the 1976

regulations, DOI had not issued formal rules

defining diligent development nor had it canceled any coal lease for failure to meet diligence. As an added complication, many lease

forms contain provisions requiring minimum

production beginning in the sixth year of the

lease. Without the adoption of the 1976

regulations superseding the lease terms and

giving 10 to 15 years to meet diligence, many

nonproducing lessees would already be in

violation of their lease provisions. Ultimately,

the issue of the validity and applicability of

the 1976 regulations may be decided by the

courts. The range of possible results of such

challenges include:

The 1976 diligent development regulations are valid and fully applicable to all

leases because all leases are subject to

the conditions of diligence required in

the 1920 Mineral Leasing Act and to the

departmental regulations implementing

these requirements, (the position of DOI

in Mobil. )44

The 1976 regulations are invalid and not

applicable to pre-FCLAA leases because

nothing in the 1920 Mineral Leasing Act

authorizes the Secretary to define diligence solely as achieving specified production levels within a definite period of

time. (Note: The Mineral Leasing Act

and common law diligence conditions

would still be applicable although the

precise standard to be used would remain undefined.)

94-141 c1 - 81 - 17 : ‘lIj 3
248 ● An Assessment of Development and Production Potential of Federal Coal Leases

●

●

The 1976 diligence regulations are valid

but are applicable to pre-FCLAA leases

only on readjustment at the end of their

current 20-year lease terms or by

amendment of lease terms with consent

of the lessee either in response to DOI’s

request or as a possible precondition of

approval for designation of a combined

LMU under section 5 of FCLAA or other

discretionary administrative action.

The 1976 regulations are valid and applicable to pre-FCLAA leases to the extent that they are consistent with the

specific terms and conditions of individual leases issued before the regulations

became effective. The regulations would

apply to leases containing the “hereafter clause” which incorporates future

regulations, as well as to any leases

issued before 1965 that include provisions which do not establish different

minimum production levels or advance

royalty payments to satisfy diligence

conditions.

Leases issued after the 1976 FCLAA are

clearly subject to the diligent development

regulations promulgated under that act and

must produce coal in commercial quantities

within 10 years after issuance or they will be

terminated.

The eventual impact of diligence requirements on pre-FCLAA leases will depend on

the interaction of many variables besides the

legal precedents that may be established on

the applicability of diligence regulations.

These factors include: 1) the extent of voluntary compliance by lessees; 2) how many extensions are granted to lessees who cannot

meet the 1986 production deadline; 3) how

many existing leases are combined with other

leases or non-Federal coal reserves to meet

diligence by forming a designated LMU under

section 5 of FCLAA; 4) how the logical mining

unit reserves are defined for each lease; 5)

the extent to which leases are readjusted on

schedule; 6) the extent of effective enforcement of the 1976 regulations by DOI and the

Department of Justice; and 7) how many nonproducing leases are relinquished.

Determination of LMU and LMU

Reserves for Diligence

Whether or not some existing leases will

meet diligence depends on the USGS determinations of LMU and LMU reserves against

which compliance is gaged. There are two

kinds of LMUs for the purpose of diligence:

1) single lease LMUs and 2) designated LMUs

under section 5 of FCLAA. All existing leases

are single lease LMUs under current regulations. Section 5 of FCLAA prohibits consolidation of any pre-FCLAA lease into an LMU

without the lessee’s consent and no section

5 LMUs had been approved by USGS as of

early 1981.

Single lease LMUs are based on the general authority of the Secretary to manage coal

leases under the Mineral Leasing Act of 1920

and the regulations originally promulgated in

May 1976 before passage of FCLAA. These

LMUs consist of the reserves in a single lease

that can be mined efficiently and economically with due regard for conservation of the

coal resource and other values. They need

not consist of a separate mine or mine plan

for each single lease LMU. Single lease LMUs

need not be contiguous, nor must they be

mined out in 40 years. The major difficulty in

defining the LMU reserves for single leases

occurs in determining which seams to include

when the lease has large multiple-seam reserves either that would not be mined in the

lessee’s normal sequence and method of mining or that do not meet the lessee’s coal quality requirements under existing contracts.

Each such case will be negotiated separately,

depending on the characteristics of each

lease and the lessee’s circumstances. Thus,

in some instances, USGS may omit seams

from the LMU reserves or permit the lessee to

relinquish particular seams or lease areas

that will not be mined.45

If a pre-FCLAA lessee requests designation

of a section 5 LMU combining a pre-FCLAA

lease with other Federal leases or non-Federal lands, the LMU criteria of section 5 also

become applicable to the pre-FCLAA leases.

Specifically:
Ch. 9—Federal Coal Lease Management ● 249

1. the Secretary must find that maximum

economic recovery of the coal deposits is

served by consolidation;

2. all lands in the LMU must be under the

effective control of a single operator, b e

able to be developed and operated as a

single operation, and be contiguous;

3. the total acreage of the LMU must b e

25,000 acres or less; and

4. any mining plans approved after the

establishment of a section 5 LMU must

require such diligent development, operation, and production that the reserves

of the entire unit will be mined in a

period of not more than 40 years. 46

In addition, the terms of individual Federal

leases in the LMU may be amended so that

mining on any lease will be consistent with

the requirements imposed on the entire LMU.

LMU designation of a section 5 LMU is often

to the lessee’s advantage because the Secretary is authorized to provide that diligent

development, continued operation and production occuring anywhere in the unit is considered as occurring on all Federal leases in

the unit, thus, allowing a producing lessee to

keep nonproducing Federal leases in the LMU

after the 1986-91 diligence deadlines and to

mine such leases in the optimum sequence for

that mine. Designation also allows rental and

royalty obligations for all leases in the LMU

to be combined and advance royalties can be

applied against the combined royalties due.

Many existing lessees will probably request LMU designations under section 5 in

order to meet diligence; most of the lessees

should qualify for such approval. Some operating lessees in Colorado and Utah have noncontiguous nonproducing leases that they

intend to mine as part of their existing operations after the diligence date. Unless the requirement that all leases in the LMU be contiguous is modified or reinterpreted, a section

5 LMU could not include these noncontiguous

areas and the lessee would probably shift

production prematurely to the new area from

other Federal leases.

Still other mines on Federal leases have

very large reserves in multiple seams and

could encounter the same difficulty in defining the LMU reserves for a section 5 LMU as

described above for single lease LMUs. Reserves on some of these potential LMUs are

so large that meeting the 21⁄2 percent diligence production target could become a practical impossibility if all the lease reserves

were included. These cases too will be addressed individually and could result in some

seams being omitted from the LMU reserves

or being relinquished.

Maximum Economic Recovery

Prior to enactment of the FCLAA in 1976,

USGS conducted an informal monitoring program to ensure conservation of coal resources and prevent waste on Federal coal

leases under the general authority of the

Mineral Leasing Act to protect the public interest. Section 3 of FCLAA created a formal

requirement for achieving the “maximum

economic recovery” (MER) of Federal coal.

The concept of MER “means that all portions

of the coal deposits within the lease tract

shall be mined that have a private incremental cost of recovery (including reclamation,

safety and opportunity costs) less than or

equal to the market value of the coal.”4 7

Beyond this general definition of the term

MER, guidelines for determining what is required to meet MER have not been promulgated. 48

FCLAA requires that MER be considered

at three stages: 1) at the time the lease is

issued; 2) when the mine plan is approved;

and 3) on approval of a section 5 LMU. At the

prelease stage, the USGS mining supervisor

determines the mining method, e.g., surface,

deep mining, etc., that is likely to yield the

greatest recovery under given economic conditions. The prelease determination is based

on a general examination of the tract and

standard mining practices, and not a detailed

seam-by-seam assessment. The premining assessment of MER, on the other hand, is expected to require a detailed investigation and

the application of more specific engineering

and economic evaluative criteria and may

lead to modifications in the mine plan to en-
250 ● An Assessment of Development and Production Potential of Federal Coal Leases

sure that MER is achieved. Before the Secretary can approve a petition for designation of

a section 5 LMU combining one or more Federal leases with other Federal leases or with

non-Federal reserves, he must find that the

consolidation will serve maximum economic

recovery of the coal resources.

Theoretically, the application of the MER

requirement could lead to the extraction of

marginal coal that was once left behind. The

purpose of the MER standard was to prevent

the possibility that operators on Federal

leases would take only the most economically

profitable coal seams and would leave the

less profitable or marginal reserves in the

ground. By requiring the lessee to average the

costs of mining over all the economically recoverable coal under lease (thus offsetting

the profit from mining high-grade reserves

against the higher costs of taking marginal reserves) more coal is extracted, more royalties

are paid, and less coal is rendered economically unrecoverable, Strict MER guidelines

could result in larger estimates of LMU

reserves, and therefore could affect the

diligence and continuous development requirements for leases. MER determinations

could also result in more complex mining

plans, which would have a concomitant effect

on the lessee’s ability to comply with the time

limits on diligent development. The nature of

the MER concept makes it, in effect, a “continuing performance standard” that may require an operator to continue operating a

Federal coal lease at marginal costs beyond

the point where a lessee would cease mining

in an unregulated operation.

The full extent of the impact of the concept

of MER on Federal leases is unknown, since

regulations implementing section 3 of the

FCLAA have not yet been promulgated, and

scope of its applicability to pre-FCLAA leases

is uncertain.

Timeliness of Readjustment

Pre-FCLAA leases were originally subject

to readjustment of lease terms at 20-year intervals. Section 6 of FCLAA reduced the

readjustment period to 10 years. Consequently, when pre-FCLAA leases reach the end of

their current 20-year term, each will be eligible for an extension of only 10 years. At readjustment, new lease provisions, including

terms incorporating the requirements of the

1976 diligence regulations, are made part of

the lease and the rentals and royalties are

changed to conform to FCLAA. Current DOI

practice is to set the new rental rate at

$3.00/acre and the royalty rate at the

statutory minimum of 12.5 percent of the

sales price per ton for coal mined by surface

methods, and at a lower discretionary rate of

8 percent for coal mined underground. For

producing leases, the major impact of readjustment is financial—an increase in the

royalty paid from (for example) $0.15/ton to

perhaps $1.60/ton (assuming $20.00/ton

for underground coal at eight percent). For

undeveloped leases or leases in pending mine

plans, if the diligence requirements are only

effective on readjustment, the result would

be differing diligence standards for preFCLAA leases. If diligence requirements for

initiating production within 10 years are

made effective only on readjustment, some

lessees would still have to meet the 1986

deadline, while others, conceivably, would

not have to produce until after the year 2000.

As a further complication, during the

1970’s, many lease readjustments were delayed because of DOI personnel shortages

and confusion over the applicability of various regulations due to litigation, legislation,

and changes in the coal management program. At the end of fiscal year 1980, most of

the backlog had been reduced and readjustments were pending for 40 pre-FCLAA

leases.

49 A number of completed readjustments have been appealed to the DOI Board

of Land Appeals and to the courts. Between

January 1, 1981, and June 1, 1986, nearly 200

pre-FCLAA leases in the six Western Federal

coal States are due for readjustment; another

191 of these leases are to be readjusted by

June 1, 1991. At least 39 more pre-FCLAA

leases will not be readjusted until after the

1991 diligence deadline (see table 78).
Ch. 9—Federal Coal Lease Management . 251

Table 78.—Readjustment Schedule for Pre-FCLAA Leases in Colorado, Montana,

New Mexico, North Dakota, Utah, and Wyoming

Readjustments Readjustments

between between Readjustments

Aug. 4, 1976 and June 1, 1986 and after

State June 1, 1986 June 1, 1991 June 1, 1991

Colorado. . . . . . . . . . . . 59 46 10

Montana. , . . . . . . . . . . 9 7 2

New Mexico. . . . . . . . . 18 9 1

North Dakota. . . . . . . . 7 9 1

Utah . . . . . . . . . . . . . . . 105 76 17

Wyoming . . . . . . . . . . . 46 44 8

Total 244 191 39

Note Dates of readjustment obtained from Automated Coal Lease Data System. October 1980 The total readjustments do not

include second readjustments of leases due to be readjusted after FCLAA (Aug. 4, 1976) or first readjustments of new

leases issued after FCLAA

Because of these delays, some lessees have

challenged DOI’s right to readjust their

leases. The lessees have argued that because

DOI did not notify them of its intention to

readjust their leases in a timely fashion

before the expiration of the previous lease

term, that DOI implicitly waived its opportunity to readjust their leases and that the

leases continue for an additional term under

the previous royalties and lease provisions. In

some cases, this position may prevail depending on the specific facts, the anniversary date

and the Department’s actions relating to attempted readjustment. DOI has maintained

that it has the authority to adjust leases even

when the lessee was not notified on or before

the 20-year anniversary date and to adjust

leases with anniversary dates occurring

before the passage of FCLAA to conform to

the minimum royalties required by FCLAA.

At least two Federal district courts have

ruled against DOI on the issue; both cases

have been appealed.50 In the 1979 rulemaking

for the new coal management program, the

regulations governing readjustments were

modified in response to industry comments.

The regulations now provide that for leases

which are subject to readjustment after June

1, 1980, if DOI does not notify the lessee

before expiration of its present lease term of

its intent to revise the lease, DOI will have

waived its right to readjust the lease for the

next lease term.51

Enforcement

The extent that diligence regulations are

enforced will also influence their impact,

Before promulgation of the regulations in

1976, DOI had not canceled any nonproducing leases. Before 1960 there had been little

need for enforcing diligent development as

most leases eventually went into production.

However, in the 1960’s, as coal production

lagged while leased areage increased, the potential for using diligence requirements to

stimulate development increased.

Before a pre-FCLAA lease is forfeited for

not meeting diligence, a judgment must be obtained against the lessee. To do this, the

Department of Justice must sue the lessee in

Federal court at the request of the Secretary

of the Interior. The decision to request enforcement action by the Justice Department is

discretionary with the Interior Secretary,

however, the final decision on whether or not

to initiate a lawsuit is made by the Attorney

General. It is likely that if DOI adopted an aggressive enforcement policy, the cases would

be carefully chosen to establish a strong

precedent, thus many weak or questionable

cases could be deferred.

Under the Secretary’s general discretionary authority to administer leases in the

public interest, DOI can also waive violations

of the Mineral Leasing Act and regulations
252 . An Assessment of Development and Production Potential of Federal Coal Leases

either on its own initiative or through negotiations with the lessees. Generally, such waivers are not binding on DOI or the Government

unless they are: 1) express, 2) written, and

3) executed by the appropriate official.52

Relinquishments

Some leases can be expected to relinquish

their nonproducing leases voluntarily if they

cannot meet diligence rather than go through

court proceedings. Relinquishments must be

found to be in the public interest.53

A significant factor affecting production

potential from existing leases and the leases

that are unlikely to meet diligence by 1986 is

section 3 of the FCLAA that prohibits the issuance of new leases to lessees that have not

produced commercial quantities from any existing leases they have held for 10 years by

August 4, 1986.54 This amendment to the Mineral Leasing Act creates a strong incentive to

relinquish nonproducing leases if the lessee

wishes to lease additional Federal coal

reserves.

Potential Production From Federal Coal

Leases and Diligence

In chapter 5 of this report, OTA presented

the results of its comparison of the expected

production from existing Federal leases with

the minimum production levels required for

diligence. This analysis, which assumed that

the diligence requirements are fully applicable to existing leases, provides some indication of the situations that might arise.

By 1991, over 70 percent of the 502 leases

in the six major Western Federal coal States

could meet the existing diligence requirements.

●

●

●

216 leases with 7.4 billion tons of

reserves are likely to meet diligence by

1986;

29 leases with 2.1 billion tons of reserves

are likely to meet diligence by 1991 with

extensions; and

112 leases with 3.4 billion tons of

reserves are uncertain to meet diligence

by 1991 with major uncertainties tied to

delays in powerplant and transportation

system construction, fluctuations in captive coal needs, and difficulties in defining the logical mining unit for leases with

very large reserves in multiple seams.

Thirty percent of the Western Federal

leases are unlikely to meet diligence by 1991

even with extensions:

●

●

●

Production for 61 leases in the Kaiparowits Plateau with 1.4 billion tons of

reserves is dependent on construction of

a coal transportation system.

Development of 10 leases in the Powder

River basin with 1.4 billion tons of reserves are contingent on commercialization of synfuels technologies, such as

in situ gasification, that can use lower

quality reserves at the mine site.

The remaining 74 leases are primarily

small, scattered leases with poor quality

reserves and are unlikely to be developed by 1991 even with extensions.

Most leases with potential for production

by 1991 could qualify for extensions under

existing guidelines. The exceptions are smallto medium-sized mines that are intended to

serve spot markets and several underground

mines opening in areas with difficult mining

conditions requiring longer construction

periods that do not fit clearly into any of the

current guidelines.55

The 502 leases are divided into a total of

217 mine plans or blocks of contiguous leases;

of these, 146 units could be producing by

1991 and many of these can be expected to

request a section 5 LMU designation so that

aggregate mine production can be used to

meet diligence and with some exceptions

should qualify as LMUs under current guidelines.

Exchanges

Exchange can be used to shift coal development on Federal or non-Federal lands away

from areas where mining conflicts with other

resource values or uses to more acceptable

areas. Exchanges, thus can offset potential

losses in coal production from environmental
Ch. 9—Federal Coal Lease Management ● 253

or land-use restrictions. Because of the requirement in section 2 of FCLAA that all new

leases be awarded by competitive bidding,

DOI has only a limited authority to offer

unleased Federal coal in exchange for relinquishment of existing Federal leases or

PRLAs in areas where mining poses environmental or other problems.

However, under general provisions of the

Mineral Leasing Act, the Secretary can issue

a noncoal mineral lease of comparable value,

coal bidding rights, or modifications of up to

160 acres each to other coal leases in exchange for relinquishment of an existing coal

lease or PRLA.56

Special legislation has been enacted specifically authorizing several proposed “lease

swaps” involving existing Federal leases and

PRLAs in Wyoming, Utah, and New Mexico

and contested Indian leases and permits in

Montana. Other existing Federal leases could

qualify under the special alluvial valley floor

exchange provisions in SMCRA.

Exchanges of Federal coal reserves for

private coal lands have also been suggested.

Under section 206 of FLPMA, DOI has the

authority to exchange interests in Federal

lands, including mineral rights, for interests

in non-Federal lands of equal value if the exchange is determined to be in the public interest. Section 510(b)(5) of SMCRA directs

the Secretary to establish a program of exchanges of non-Federal lands that cannot be

mined because of alluvial valley floor restrictions for available Federal coal lands under

section 206 of FLPMA.

According to information from OTA’s State

task forces, as much as 1.7 billion tons of

Federal coal reserves are involved in various

exchange proposals.57 It is now apparent that

not all of these exchanges will be completed,

however, a significant portion of reserves

that cannot be mined without substantial

adverse social or environmental consequences could be replaced through the exchange mechanisms described below.

Special Exchange Legislation

Under special exchange legislation enacted by Congress, the Secretary of the Interior has been authorized to approve exchange relinquishments of certain existing

leases and PRLAs and contested Indian

leases and permits for new noncompetitive

Federal coal leases. Generally, the Secretary

must find that the exchange is in the public

interest and that the value of the rights to be

traded are approximately equal,

Public Law 95-554—Federal Coal Leasing

Amendments Act of 1978

In the 95th Congress, DOI requested legislation giving it generic authority to exchange

or condemn leases and PRLAs where mining

poses environmental or other problems. Instead, Congress passed the Federal Coal

Leasing Amendments Act of 1978 making

minor amendments to the Mineral Leasing

Act and specifically authorizing exchanges

for all or part of nine leases underlying Interstate 90 and State highways near Gillette in

northeastern Wyoming, and for eight PRLAs

on the Kaiparowits Plateau in southwestern

Utah. 58 The 1978 act also requested a feasibility study on the possible acquisition of private

lands surrounding the Lake DeSmet Reservoir near Buffalo, Wyo., in exchange for Federal coal lands. The rights to be exchanged

must be of approximately equal value, however, a cash settlement of up to 25 percent of

the difference in value would be allowed.

DOI has completed the exchange studies

under Public Law 95-554. In September 1979,

it recommended against the Lake DeSmet exchange .

59 In June 1981, the Utah Power &

Light exchange was rejected because the

PRLAs to be exchanged were determined to

be not of approximately equal value to the

new lease tracts requested. 60 The Wyoming

highway exchanges are proceeding and negotiations with the lessees are continuing on the

leased areas to be relinquished in return for

other Federal coal reserves.61
254 ● An Assessment of Development and Production Potential of Federal Coal Leases

New Mexico Lease Exchange

Public Law 96-47562 directs the Secretary

of the Interior to issue leases for coal on other

Federal land in exchange for all or portions of

two Federal leases in the Bisti area of New

Mexico. The exchange is to be completed

within 30 months, i.e., by April 1983, or as expeditiously as possible. The Bisti lease area

covers about 1,360 acres of the Bisti wilderness study area, as well as other areas with

unusual paleontological, archaeological and

recreational values. 63 The legislation specifically describes the unleased Federal coal

lands that are to be offered in the exchange.

The exchange is to be made pursuant to the

existing land use policies and leasing procedures established by the Secretary. The

leases issued must contain the same terms

and conditions as leases surrendered. The

two leases are due to be readjusted before

the exchange date and would thus be subject

to post-FCLAA requirements.

The exchange involves two leases in the

planned Bisti Mine. The lessee, Western Coal

Co. had sought the exchange and agreed to

defer exploration and mine construction activities in the areas pending administrative

and legislative action. Processing of the exchange is not expected to delay development

on the other Federal leases in the mine area.

Northern Cheyenne Indian Reservation

Lease Exchange

Public Law 96-401 authorizes the Secretary of the Interior to negotiate for the

cancellation of seven leases and 11 prospecting permits on Indian lands on the Northern

Cheyenne Reservation in Montana.

64 T h e

tribe has been contesting the BIA’s issuance

of these coal development rights covering

over half of the tribal reservation. Development of the leases and permits was suspended by the Secretary of the Interior in

response to the tribe’s petition. The act would

allow the Secretary to negotiate with the

lessees and permit holders for cancellation of

their rights in exchange for bypass leases on

Federal coal adjacent to their active mines

and for Federal coal bidding rights equal to

the amounts that they have invested in the Indian coal rights. The act does not provide for

a ton-for-ton or acre-for-acre exchange of

Federal coal lands for the disputed tribal coal

lands, but rather establishes a framework for

the parties to negotiate a settlement and for

the coal companies to recover their out-ofpocket expenses. The settlement authority in

the act does not affect any legal rights that

the parties may have. If they are unable to

reach an agreement, the issues could still be

litigated. 65

Alluvial Valley Floor Exchanges

Section 510(b)(5) of the Surface Mining

Control and Reclamation Act of 1977 requires

that reserves on certain nonproducing Federal leases and private lands in alluvial valley

floors with agricultural potential that cannot

be mined, can be exchanged for Federal coal

if the lessee made substantial legal or financial commitments to developing a mine before

January, 1, 1977.66 It is not yet known how

much, if any, coal in alluvial valley floors will

be exchanged under this provision intended

to compensate mine owners and lessees who

do not qualify for permit approval under the

grandfather provisions of section 510(b)(5). In

general, relatively small amounts of Federal

lease reserves are likely to be affected by the

prohibition on mining agriculturally important alluvial valley floors and the Federal

reserves that would be eligible for exchange

would be even smaller. (See the discussion of

alluvial valley floors in ch. 10 of this report.)

Section 510(b)(5) also directs the Secretary

to establish an exchange program under section 206 of FLPMA to trade title to available

Federal coal lands for title to private lands

that cannot be mined because of alluvial

valley floors. This exchange of private lands

for Federal reserves is mandatory and not

subject to the requirement of previous substantial legal and financial investment. 6 7

There are a number of mines in the Powder

River basin, with substantial reserves of nonFederal coal under alluvial valley floors that

might qualify for these mandatory exchanges.
Ch. 9—Federal Coal Lease Management ● 255

If significant amounts of reserves from these

mines qualify, the net result could be a decrease in available unleased Federal reserves because of the transfers of Federal

coal to non-Federal ownership in exchange

for unminable non-Federal reserves in alluvial valley floors.

Other Exchanges

Under section 206 of FLPMA, DOI can exchange interests in Federal lands, including

mineral rights, for interests in non-Federal

lands of equal value if the public interest is

well served by the exchange. 68 Cash settlement of up to 25 percent of the difference in

value of the tracts exchanged is authorized.

The alluvial valley floor coal exchanges are to

be evaluated under this provision. Several exchanges of non-Federal coal lands for Federal

coal lands have been suggested to preserve

important wildlife habitat from mining, or to

allow “blocking up” of checkerboard lands or

other areas of dispersed mineral ownership

so that both the Federal Government and the

private owner receive title to contiguous

LMUs as a result.69 Exchanges of lands found

unsuitable for mining under SMCRA have

also been suggested; however, exchange of

any Federal lease areas could only be accomplished by specific legislation.

DOI’s limited experience with trying to implement the authorized exchanges discussed

earlier has revealed technical and administrative difficulties involved in working out an

exchange agreement acceptable to both parties. The difficulties in determining an appropriate value for the rights to be exchanged

have been particularly troublesome in Utah

and Wyoming where the reserves to be relinquished are of lower present economic value

than the reserves sought in exchange. Even

so, other leaseholders with reserves that cannot be mined can be expected to press for exchanges through administrative, legislative

and judicial channels. Although all the coal

reserves under existing leases may not be

mined, the eventual result of exchanges could

be little net change in the total amount of Federal coal reserves developed. The location of

mining may change compared to present patterns of Federal lease ownership, but the

amount of Federal reserves committed by

past leasing practices could remain essentially the same.

Preference Right Lease Applications

Under section 2(b) of the 1920 Mineral

Lands Leasing Act, prospecting permits could

be issued for areas where commercial deposits of coal were unknown. The purpose of

this provision, similar to prospecting permit

provisions for other leasable minerals and to

the location patent system under the mining

law, was to encourage the exploration and

development of mineral resources on public

lands. 70 A successful prospector, upon showing discovery of a valuable deposit during the

term of the permit, was entitled to a noncompetitive preference right lease. About

half of the existing Federal coal leases were

issued through the preference right lease

mechanism .7’ Section 4 of the FCLAA repealed the authority to issue preference right

leases except for PRLAs and prospecting permits pending on the date of its enactment.72

Potential Production From PRLAs

As of March 1981, there were 171 actively

pending PRLAs covering over 395,000 acres

and containing over 5,7 billion tons of recoverable reserves. OTA estimates that the

potential production from these PRLAs is between 35 million and 60 million tons per year

depending on how the various legal and environmental problems affecting certain PRLAs

are resolved.73 About 10 million tons of this

annual production is associated with new

mines on existing Federal leases in Colorado

and New Mexico. This estimate is lower than
256 ● An Assessment of Development and Production Potential of Federal Coal Leases

the earlier DOI estimates of 186 million to 248

million tons per year used in development of

the new coal management program and reflects: 1) a reduction in DOI’s estimates of inplace reserves; and 2) OTA’s analysis of the

production potential of PRLAs in Wyoming,

Colorado, and New Mexico. Even the lower

production estimates for PRLAs indicate a

significant potential for contributing to coal

supply in 1990-95.74

The potential impact of the various legal,

planning, and environmental restrictions on

PRLA issuance and hence production was

probably overestimated in the DOI review.

OTA’s examination of the data used in

preparation of the working paper disclosed

that most of the environmental restrictions

were related to wildlife concerns and would

probably result in special lease stipulations

on impact mitigation rather than in deletion

of reserves from the PRLA. The legal problems include some, such as incomplete applications, that are curable during the adjudication process under regulations allowing the

applicant an opportunity to submit additional

data. 75 Other legal problems such as failure to

submit any information about the quantity

and quality of reserves discovered probably

would result in rejection, however, only a few

applications did not contain this information,

so the probable impact is small.76

The true potential production from PRLAs

will not be known until after the pending applications have been processed and those

that meet the legal requirements have been

issued. With few exceptions, processing of

the pending PRLAs was suspended during

most of the past decade: first, because of the

1971 moratorium; then, to allow for development of new leasing policies; and, finally, by

litigation. 77 Following promulgation of final

regulations for the new coal management

program in July 1979, processing of pending

PRLAs was resumed. Under current policy,

all PRLAs should be adjudicated and leases

issued to qualified applicants by 1984.

Many of the legal, administrative, and procedural issues related to the issuance or rejections of PRLAs have been addressed by

DOI and the courts, however, a number of

new questions are likely to arise as the applications are processed and these must be

resolved before the full production from

PRLAs will be realized.

Procedures for Processing PRLAs

Before its repeal in the 1976 amendments,

section 2(b) of the Mineral Leasing Act of

1920 provided:

Where prospecting or exploratory work is

necessary to determine the existence or

workability of coal deposits in any unclaimed, undeveloped area, the Secretary of

the Interior may issue, to applicants qualified under this chapter, prospecting permits

for a term of two years, for not exceeding

five thousand one hundred and twenty acres;

and if within said period of two years thereafter the permittee shows to the Secretary

that the lands contain coal in commercial

quantities, the permittee shall be entitled to

a lease under this chapter for all or part of

the land in his permit.

A prospecting permit could be extended for

. -

2 years; however, the approval of extensions

was discretionary. In practice, they appear to

have been granted routinely at the request of

the permittee. In order to qualify for a preference right lease, the prospector had to submit an application accompanied by evidence

showing the discovery of commercial quantities of coal within the permit area before the

expiration date of the permit. The 1976

repeal was subject to valid existing rights,

thus any pending permits or applications for

preference right leases were not affected and

could be pursued under pre-FCLAA requirements. Any leases issued would, however, be

governed by new lease terms imposed by

FCLAA.

As a result of an internal review of DOI

procedures and criteria for issuing prospecting permits and approving PRLAs, new regulations were issued in May 1976 governing

all pending and future PRLAs. 78 The regulations formally defined the standards for

determining “commercial quantities” under

the Mineral Leasing Act, specified the in-
Ch. 9—Federal Coal Lease Management . 257

formation to be submitted, and established a

two-phase adjudication procedure, The internal review had disclosed that, in some instances, the less stringent “workability”

standard had been used mistakenly to determine whether a PRLA should be issued rather

than the stricter “prudent person” test.79 T h e

regulations formally adopted the “prudent

person” standard applied under the Mining

Law as the appropriate test for determining

discovery of commercial quantities of coal

under the Mineral Leasing Act.

The commercial quantities standard requires that “the coal deposit discovered

. . . shall be of such character and quantity

that a prudent person would be justified in

further expedition of his labor and means

with a reasonable prospect of success in developing a valuable mine. ” The applicant

must present “sufficient evidence to show

that there is a reasonable expectation that revenues from the sale of the coal shall exceed

the cost of developing the mine and extracting, removing, transporting, and marketing

the coal. ” Mining costs include expenses for

environmental protection, reclamation, and

compliance with applicable State and Federal laws and regulations.80

Under the new adjudication procedure, the

application was to be accompanied by an

“initial showing” with reserves estimates

and supporting geologic data, maps, and a

description of the proposed mining operation.

Holders of pending PRLAs were notified to

supplement their applications with the required initial showing. (Table 79 shows the

adjudication steps in processing PRLAs.) The

application and initial showing are first

examined for completeness and compliance

with other Mineral Leasing Act requirements. Incomplete or insufficient applications

can be rejected at this stage, however in

many instances, the applicant will be given

an opportunity to supplement or correct the

missing data. If the PRLA is rejected then or

later in the process, the decision can be appealed administratively to the Interior Board

of Land Appeals.81

The initial showing is followed by a

technical examination and environmental

assessment from which proposed lease terms

and stipulations are formulated. This review

will normally be conducted during the ongoing BLM land use planning cycle established

by each State BLM Office, unless the lessee

requests an accelerated review. The environmental assessment includes a site-specific

analysis to evaluate the suitability of the area

for mining and to develop appropriate lease

stipulations, consultation with State government, and preparation of either an environmental assessment (EA) document or an EIS

as required under NEPA. The Geological Survey reviews the adequacy of the initial showing and recommends lease terms and conditions and bonding, MER, and minimum production requirements for diligence.

The applicant is then provided with the

proposed lease terms and stipulations (including rentals and royalties), the EA or EIS,

and other relevant information and allowed

90 days to submit a “final showing” of commercial quantities. The final showing must include the applicant’s estimated production,

estimated revenues, and mining and reclamation costs. The estimates must have a reasonable factual basis and reflect all costs that a

prudent person would consider before deciding to develop a mine. It must demonstrate

that the deposit can be profitably mined and

marketed under the proposed lease terms and

applicable State and Federal laws. If all the

requirements of the final showing are satisfactorily met, the applicant is entitled to a

lease.

Litigation Involving PRLAs

NRDC v. Berklund

In March 1975, the Natural Resources Defense Council and the Environmental Defense

Fund sued DOI seeking: 1) a declaratory judgment that the Secretary had the discretionary

authority to refuse to issue a PRLA on environmental grounds under the Mineral Leasing Act of 1920 and National Environmental

Policy Act of 1969, and that an environmental
258 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 79.—Processing Preference Right Lease Applications

Review of application and initial showing

1. Review completeness and adequacy of

application.

2. Review completeness of initial showing.

3. Determine whether PRLA conflicts with valid

mining claims.

4. Request additional information needed for

initial showing and mining claims reviews.

5. Determine adequacy of initial showing.

Technical review and environmental assessment

1. Establish priority for review of PRLA in land

use planning process.

2. Conduct environmental analysis including

unsuitability criteria.

3. Review adequacy of EA or EIS; consult with

Governor, Surface Management Agency, other

agencies, and public. Issue final EAIEIS.

4. Set proposed lease terms, conditions, rental,

royalties, bonding, MER, and minimum

production requirements.

5. Request applicant to submit “final showing”

of commercial quantities.

Review of final showing

1. Determine completeness of final showing.

2. Determine whether applicant meets

commercial quantities test.

Reject PRLA for failure to meet MLA requirements if:

—Not filed before prospecting permit expired;

—Not signed by qualified applicant;

—Advance rental not paid; or

—Evidence of discovery of commercial quantities not submitted.

Reject PRLA if:

—Initial showing not filed; or

—Initial showing not timely filed.

Delete areas covered by valid mining claims located before Multiple

Mineral Development Act (1954) and the date prospecting permit was

issued. (Claims must be filed with BLM as required by FLPMA to be

presumed valid); notify applicant of conflict and of procedures for

contesting validity of adverse mining claims.

Reject PRLA if:

—Initial showing fails to show any coal or such limited reserves or

low quality coal that mining could not be expected to take place; or

—After deletion of mining claims, initial showing fails to show

sufficient reserves remaining to sustain proposed commercial

development.

Accept initial showing if all requirements are met; refer application for

technical review and environmental assessment.

Schedule accelerated review on applicant request.

Prepare environmental assessment (EA) or draft environmental impact

statement (EIS).

Request comments on adequacy of EAIEIS, proposed lease terms,

stipulations. Hold public hearing. Prepare final EA/EIS.

Reject PRLA if applicant fails to submit final showing. Request

additional information needed for final showing.

Has applicant demonstrated discovery of a coal deposit of such

character and quality that a prudent person would be justified in

3. Issue final decision on PRLA.

further expenditure of his labor and means with a reasonable prospect

of success in developing a valuable mine with a reasonable

expectation that the revenues from the sale of the coal will exceed

the costs of developing the mine and extracting, removing,

transporting, and marketing the coal? (NOTE: Applicant may delete

areas that are recommended as unsuitable for mining from application

before final showing to exclude costs of mining these areas.)

Accept PRLA and issue lease if applicant meets all requirements and

commercial quantities test.

Reject PRLA if applicant does not meet commercial quantities test on

final showing.

Negotiate with applicant for exchange of PRLAs that meet

commercial quantities test but pose environmental or other problems

if developed.

SOURCE. Bureau of Land Management, Instruction Memorandum 79-846 (revised), Solicitor’s Opinion M-36893, as revised, Jan. 8, 1981.
Ch. 9—Federal Coal Lease Management 259

impact statement must be prepared before issuance of any PRLA that involved a “major

Federal action significantly affecting the environment;" and Z) an injunction barring the

issuance of any such leases without complying with the declaratory judgment provisions

sought.

In June 1978, the District Court of the

District of Columbia held: 1) that the Secretary has no discretion to reject a PRLA if

the applicant successfully meets the commercial quantities test and other requirements of

the Mineral Leasing Act; and 2) that NEPA requires the preparation of an EIS before the issuance of any lease where such action is “a

major Federal action significantly affecting

the environment.”82

In reaching its decision the court further

noted that NEPA requires the Secretary to

“exercise his authority to safeguard society

and prevent irreparable damage to the environment through a careful and complete formulation of lease terms.” 83 The court observed that the Secretary has broad powers

to establish strict standards for proposed

lease terms that could make compliance with

the commercial quantities test difficult or impossible (i.e., the cost of implementing these

terms would make the mining costs exceed

the market value of the coal). Thus, while DOI

cannot deny a PRLA solely for failure to meet

environmental requirements, the court stated

that “if a permittee does not have the technological capability to comply with (strict environmental) standards, the high cost of compliance will outweigh potential coal revenues

and he will fail the commercial quantities

test, ”84

In preparing an EIS prior to the issuance of

a PRLA, the Berklund court ruled that the

Secretary must consider at least three alternatives: 1 ) exchange of the PRLA for a mineral lease of comparable value or coal bidding rights; 85 2) issuance of the lease with

lease terms to protect against irreparable

damage to the environment as required by

NEPA, which will determine whether the permittee will meet the commercial quantities

test, which in turn will determine whether the

lease will be issued; and 3) if the applicant

will not agree to an exchange and the lease

terms do not defeat the commercial quantities

showing, withdrawing the lands or asking

Congress for legislation canceling the lease

on payment of just compensation.86

By clear implication, the decision upheld

the application of the 1976 commercial quantities regulations. The decision was affirmed

by the U.S. Court of Appeals in November,

1979. 87

Utah International Inc. v. Andrus (Utah)88

Utah International, Inc., sued DOI seeking

a judgment that the May 1976 PRLA adjudication procedures and commercial quantities

regulations could not be applied to its

southern Utah PRLA which was filed before

they were effective and also seeking to have

court rule that any lease issued from its PRLA

would have lease terms in effect on date of

application rather than post-FCLAA requirements. The Utah Federal district court held

that the 1976 regulations were proper and

could be made applicable to pending PRLAs;

and that an applicant does not acquire a

vested right to a lease or to have its application judged under a particular standard simply by filing an application. The court further

ruled that an applicant could not sue over the

application of the commercial quantities test

to its PRLA until after DOI had made a final

decision approving or rejecting the application and the applicant had all exhausted administrative appeals in DOI.

Utah International Inc. v. Andrus

(Colorado) 89

Utah International, Inc., also sued DOI

over processing of a PRLA in Colorado—this

time with more success. The Colorado Federal district court decision cited the result in

the Utah case with approval, noting that it is

within the authority of the Secretary to act to

correct errors in the administration of programs committed to his discretion, thus it was

proper to issue new regulations for processing PRLAs and to establish a corrected commercial quantities test fully applicable to
260 ● An Assessment of Development and Production Potential of Federal Coal Leases

pending applications, The Colorado court

then distinguished the PRLA in the case

before it from other PRLAs by finding that

DOI had made a final and binding determination of discovery of commercial quantities on

the PRLA in 1970 before the effective date of

the new regulations. Having made a final

decision, DOI could not subsequently reopen

the case to apply its later requirements. DOI

was ordered to process the application. The

court further held that the applicant, Utah International, was not entitled to the lease

terms in effect when its application was approved, but rather the Secretary had full

discretion to set the terms and conditions of

the lease. The case was appealed by both DOI

and the plaintiff, Utah International. Its value

as precedent for other PRLAs is limited since

the decision was based on the specific circumstances of the case.

Other Legal and Administrative Issues

Related to PRLAs

Unclaimed Land

Under the 1920 Act, prospecting permits

and preference right leases could be issued

only on “unclaimed, undeveloped” lands. A

1977 Solicitor’s Opinion (Solicitor’s Opinion

No. M-36893), interpreting the meaning of

“claimed” as any land on which a valid mining claim had been filed under the Mining

Law of 1872 and was present at the time the

prospecting permit was issued, raised the

prospect that many pending PRLAs would be

invalid in those areas in which they overlapped mining claims.

In response to the Opinion, in August 1977,

PRLA holders were asked to submit a “certified abstract of title” within 160 days listing

previous mining claims affecting land within

their PRLAs.90 A review of the submitted abstracts revealed that lands encompassed by

20 PRLAs were covered in part or in whole by

a total of 465 mining claims that had been

issued prior to the coal prospecting permits.

Most of these PRLAs are in Wyoming, where

14 out of 72 applications, covering 25,586

acres include one or more mining claims.

One application had 239 mining claims. Most

of these claims are for uranium minerals.

On November 19, 1979, the Solicitor issued

a Supplemental Opinion on the effect of the

August 1977 Opinion on the processing of

pending PRLAs. The Supplemental Opinion

concluded that prospecting permits previously issued in “claimed” or “developed”

areas are void and clarified the meaning of

the terms “unclaimed” and “undeveloped”

under the Mineral Leasing Act. The term “unclaimed” refers to the absence of valid mining claims. The term “undeveloped” means

the lack of surface mineral activities associated with the delineation of an ore body or

mineral resource which could reasonably be

expected to disclose knowledge of an area’s

coal or phosphate potential. The Supplemental Opinion also noted that holders of PRLAs

“have an opportunity through private contests, submission of evidence of an area’s

status, or by rebutting a show cause order, to

show that the lands under application were

‘unclaimed, undeveloped’ at the time of prospecting permit issuance."91

Review of the Solicitor’s Opinion on unclaimed areas resulted in a third opinion

issued January 8, 1981. This third opinion

concluded that only claims filed before enactment of the Multiple Mineral Development

Act of 1954 could adversely affect PRLAs,

The opinion further concluded that it is sufficient to only check BLM land office records

for evidence of mining claims thus allowing

DOI to dispense with the requirement for certified abstracts.

The results of this third Solicitor’s Opinion

on the “unclaimed, undeveloped” issue could

make processing of PRLAs simpler and could

result in some PRLAs being approved although they might contain conflicting mining

claims for other minerals. The Multiple Mineral Development Act of 1954 provides that

mining claims located after the date of its

passage do not carry with them the right to

leasable minerals, including coal. 92 Thus, location of a mining claim after that date does

not create a claim that is adverse to the rights

of a coal lessee and, in fact, the Government
Ch. 9—Federal Coal Lease Management ● 261

may lease the coal, phosphate, oil, and gas,

and other leasable minerals on these lands.

The PRLA records examined by OTA do not

indicate when the mining claims that potentially conflict with the PRLAs were filed.

However, it is likely that many of the uranium

claims were located after the passage of the

1954 Act and thus could not result in a conflict with any coal prospecting permits.

The elimination of the requirement for submission of certified abstracts makes use of

provisions of the Federal Land Policy and

Management Act of 1976. Section 314 of

FLPMA requires that holders of unpatented

mining claims file information on the location

of their claim and an affidavit of assessment

work performed with the BLM by October 21,

1979, and annually thereafter. 93 Failure to

file this information is deemed conclusively to

constitute abandonment of the claim. Before

this provision was enacted, there often was

no feasible procedure available to BLM or the

prospector to determine the presence of mining claims on lands covered by applications

for prospecting permits.

If the third Solicitor’s Opinion is implemented, the portions of a PRLA covered by

valid prior claims will be deleted from lease

consideration. This would reduce the lease

acreage of some PRLAs and perhaps completely disqualify others. In Wyoming, PRLAs

with mining claims contain over 600 million

tons of reserves, and 15.5 million tons out of

20,5 million tons potential production capacity from PRLAs could be affected by these

claims. Whether issuance of a preference

right lease is affected by the presence of mining claims depends on: 1 ) how much of the

PRLA is covered by claims; 2) whether the

claims were filed before 1954; 3) whether the

claims have been kept valid through the required work requirements at least up to the

time the prospecting permit was issued; and

4) whether the mining claim holder has made

the required filing with BLM.

Existence and Workability of Coal Deposits

Preference right leases were awarded only

for those lands where commercially valuable

coal deposits were not known to occur. Prospecting permits were issued under the Mineral Leasing Act of 1920 where prospecting

or exploratory work was necessary to determine the existence or “workability” of coal

deposits. If the permittee could show that

land contained in coal in “commercial quantities, ” the permittee was entitled to a preference right lease for the vacant, unappropriated lands described in the prospecting

permit.

The concept of workability for coal preference right leases is similar to the “valuable

deposit test” that applies to other minerals

and is the same as the commercial quantities

test in the current coal regulations.{” To

qualify, the land must be found to contain

“coal of such quantity and quality as would

warrant a prudent coal miner or operator in

the expenditure and labor incident to the

opening and operation of a coal mine or mines

on a commercial basis.”95 In other words, “a

permittee must have found a deposit upon

which a prudent man would expend his labor

and means (a workable deposit) and that to

meet this test, commercial quantities of coal

must be found. ”

In deciding whether a prospecting permit

could be issued, USGS also used a classification standard of workability that assumed

that the coal deposits were marketable and

which focused on whether the known physical characteristics of the coal deposits indicated that the value of the coal was greater

than the costs of extraction. This less stringent classification standard of workability

was for some years mistakenly used to determine whether a permittee was entitled to a

lease. 96 This misunderstanding was corrected

by DOI in the 1976 commercial quantities regulations. This confusion over the correct application of the workability test raised questions about whether some lands had correctly

been open to prospecting.

Some environmental groups have argued

that some prospecting permits in Wyoming

were issued on lands with abandoned underground mine workings or surface coal outcrops and that such lands should have been
262 ● An Assessment of Development and Production Potential of Federal Coal Leases

classified as areas with known coal deposits.

Issuance of prospecting permits in such areas

would violate the statutory requirement that

known deposits must be leased competitively. 97 However, in 1979 in rulemaking for

the new coal management program, DOI rejected a proposal to reexamine PRLAs for errors in determining the presence of known

deposits. 1)01 “will continue to give these

determinations a presumption of administrative regularity;” however, “if a case file does

not contain the required conclusion by USGS

that a prospecting permit could be issued

then the presumption of administrative regularity does not apply,” and DOI “will examine

in such a case whether the permit was properly granted.”98

Unsuitability for Mining

Pre-FCLAA leases can be affected

ways by current requirements and

dures relating to the environmental

in two

proceunsuitability of lands for coal mining: 1) under

sections 510 and 516 of the Surface Mining

Control and Reclamation Act of 1977, performance criteria for mining must be considered before a mine plan is approved, and if

the impacts cannot be mitigated the plan may

be rejected; 2) mining on a pre-FCLAA lease

may be foreclosed if it is within an area that

is designated unsuitable for mining as a

result of the petition process established in

section 522(a) of SMCRA.99

BLM land use plans and coal lease tract

selection include the consideration of suitability criteria for the medium and high

potential coal lands in each BLM district

planning area. Lands that are not unsuitable

are considered further in the land use planning and coal leasing process. Suitability

criteria are also applied by OSM to each nonproducing pre-FCLAA lease when a mining

and reclamation plan is submitted. Before

permit approval OSM consults BLM for special stipulations or recommendations on the

suitability of leased areas for the proposed

mining operation. The impact on pre-FCLAA

leases has been relatively small, although the

status of several hundred million tons of reserves in the Powder River basin potentially

could be affected by alluvial valley floor

restrictions (see ch. 10 for further discussion). Overall, the impacts of unsuitability

criteria and the designation of lands unsuitable for mining are not are not expected

to impair the ability of existing Federal leases

to meet the possible range of demand for

Western coal in the next 10 to 15 years.

Federal lands unsuitability criteria have

two major sources: First, an order issued by

President Carter in May 1977 directing the

Secretary of the Interior to lease coal only in

areas “where mining is environmentally acceptable and compatible with other land

uses” and to review existing leases for compatibility with these standards, and to take

the necessary steps under existing law to

deal with nonproducing, environmentally unsatisfactory leases and applications.

Second, the Surface Mining Control and

Reclamation Act of 1977 (SMCRA) requires

the Secretary of the Interior to review all

Federal lands to identify any areas unsuitable for surface coal mining operations.

Standards of unsuitability in section 522 of

SMCRA focus on environmentally sensitive

areas or areas which are classified for other

uses, such as national parks or wilderness

areas. Other Federal statutes impose additional responsibility on the Federal Government to protect endangered species, historic

and culturally significant sites, etc.; these

were also included in the suitability criteria.

The unsuitability review includes a process

for public participation that considers matters of local or State significance and a procedure for private surface owners to withhold

consent for new Federal coal leases.

Under the July 1979 coal management regulations, unsuitability criteria for new coal

leases are applied during the land use planning process in order to identify those areas

requiring special stipulations to provide necessary protection from adverse impacts of

mining. These criteria apply to all surface

minable areas and also to underground mines

if mining would unduly disturb the surface,

cause subsidence or interfere with surface
Ch. 9—Federal Coal Lease Management 263

occupancy. Exceptions to these criteria are

permitted to protect valid existing rights or

substantial legal and financial commitments

made by operators before enactment of

SMCRA. In some instances, the criteria extend to buffer zones around protected areas,

such as those listed in the National Register

of Historic Places, endangered species habitats and lands with National Resource Waters on site. Section 522 criteria also apply to

mine plans; if sufficient data are not available to determine the minability at the time of

leasing, the issue will be resolved at the mine

plan approval stage.

Designation of Lands Unsuitable for Mining: Section 522(a) of SMCRA establishes a

procedure for petitions to designate lands unsuitable for mining. An unsuitability designation is mandatory if required reclamation is

not technically or economically feasible.

SMRCA also provides for Federal or State

agencies to designate land unsuitable for mining as a matter of discretion based on a review of the petition if:

1. mining is incompatible with existing

State or local land use plans;

2. mining could result in significant damage to important historic, cultural, scientific and esthetic values and natural

systems on fragile or historic lands;

3. mining of renewable resource lands

results in substantial loss or reduction of

long-range productivity of food or fiber

products and water supply; and

4. mining of natural hazard lands (such as

areas subject to frequent flooding and

areas of unstable geology) could substantially endanger life and property.100

The petition process forces consideration

of the cumulative environmental impacts of

surface mining that may be overlooked or inadequately analyzed in the application of unsuitability criteria during individual mine

plan review. It also allows examination of environmental issues that are not specifically

addressed in requirements for mine plan review, such as the impacts of mining on national parks.

By June 1981, two petitions had been filed

in the West to designate lands unsuitable for

mining; one in the Alton area of southwestern

Utah and the other in the Tongue River Valley

of southeastern Montana.

The Alton Petition

On November 28, 1979, the Environmental

Defense Fund, Friends of the Earth, Sierra

Club, and seven residents of the Alton area in

southwestern Utah petitioned the Secretary

of the Interior to designate certain Federal

lands near Bryce Canyon National Park and

Dixie National Forest as unsuitable for surface coal mining, Approximately 325,200

acres, or slightly more than 500 square miles,

were affected, including 29 Federal leases

covering over 26,000 acres containing about

290 million tons of surface minable coal reserves, 100 million tons of recoverable underground reserves, and two PRLAs covering

2,398 acres. The major allegations in the petition dealt with the technological and economic feasibility of reclamation, potential damage

to surface and ground water systems and potential damage to the unique values of the

park and national forest.

The final EIS on the petition, issued by

OSM in November 1980, did not support the

claims that: 1) the Alton land could not be

reclaimed; 2) blasting from mining would

damage geologic formations; 3) wildlife would

be threatened; and 4) mining would cause irreparable damage to water supplies. It did

note that these issues would be reexamined

as part of the permit approval process and

that appropriate stipulations could be required should additional information reveal

any such adverse problems. The EIS did find

that mining in part of the area would impair

scenic vistas from Bryce Canyon National

Park and that high noise levels would occur in

some areas within the park. In December

1980, the Secretary of the Interior declared

9,049 acres containing approximately 24 million tons of coal near Yovimpa Point in Bryce

Canyon National Park as unsuitable for mining because of the adverse impacts on the
264 . An Assessment of Development and Production Potential of Federal Coal Leases

park. The decision stated that mining activities would significantly reduce visibility and

scenic vistas from the park overlooks and

would raise noise levels thus damaging the

values for which the park was established

and diminishing the experiences of the park

visitors. In support of his decision, Secretary

Andrus also cited his responsibility as the

steward of the national parks “to conserve the

scenery and the natural and historic objects

and the wildlife therein and to provide for the

enjoyment of the same in such manner and by

such means as will leave them unimpaired for

the enjoyment of future generations."101

The decision left the two main leaseholders

in the petition area, Utah International and

Nevada Electric Investment Co. approximately 16,700 acres under lease containing 266

million tons of coal to supply the proposed

Allen-Warner Valley Energy System or other

projects.

Utah International challenged the decision

in Federal court alleging that its leases

should be exempt from unsuitability designation because of substantial legal and financial commitments undertaken by the lessees

before SMCRA was enacted. The petitioners,

the Environmental Defense Fund (EDF), also

appealed the decision, alleging that the Secretary failed to consider adequately the effects mining would have on the national park

and on the regional water supply. If EDF’s

suit results in expanding the area unsuitable

for mining, there could be a significant impact on coal production from the area. Up to

now, however, the potential for coal production from the leases in the area has not been

significantly impaired even though 12 of the

29 leases in the area are affected, in whole or

in part, by the Secretary’s decision. The impact of the decision is probably limited to its

unique circumstances since few, if any, other

existing leases border on national parks. 102

The Tongue River Petition

In November 1980, the Northern Plains

Resource Council and three of its affiliates,

the Tri-County Ranchers Association, the

Rosebud Protective Association and the

Tongue River Agricultural Protective Association filed a petition with the Montana

Department of State Land and OSM to designate approximately 100 thousand acres of intermingled Federal, private, and State lands

in the Tongue River Valley in southeastern

Montana unsuitable for surface mining. The

major allegations in the petition are that thin

topsoils and indigenous salts make reclamation technologically and economically

unfeasible, and that strip mining could

damage water supplies and the long-term

productivity of farmlands. The area in the

petition includes an estimated 10 billion tons

of strippable coal and includes the proposed

non-Federal Montco Mine that has a projected production capacity of 12 million tons

per year by 1990. Substantial amounts of

Federal coal are located in the area, but

there is no currently leased Federal coal in

the area, so the petition will not have any

significant impact on the development of existing Federal leases in Montana. The petition

was found to be complete and the allegations

are now under review by the State of Montana and DOI,103 Final decision on non-Federal lands rests with the State; the decision of

Federal lands suitability will be made by DOI.

A decision on the petition will be made by December 29, 1981.
Ch. 9—Federal Coal Lease Management 265

Footnotes for Chapter 9

1

For a description of the public land disposal laws and the

origin of split ownership problems in the West, see Management of Fuel and Nonfuel Minerals in Federal Lands, Office of

Technology Assessment (OTA-M-88), April 1979, p. 86,

2

30 U.S.C. 1304, SMCRA narrowly defines the surface owners to which the consent requirement applies. A ‘‘qualified surface owner” is a natural person (or a corporation controlled by

a natural person) who: 1) owns legal or equitable title to the

land surface, and 2) either lives on the land or personally farms

the land or derives a substantial portion of his income from

such farming or ranching operation, and 3) has met the previous conditions for 3 years before granting consent.

3

See discussion of Coal Lands Act in Management of Fuel

and Nonfuel Minerals in Federal Lands, supra note 1, pp. 86-89.

4Act of Feb. 25, 1920,41 Stat. 438.

5G. Bennethum. Holdings and Development of Federal Coal

Leases (Washington, D, C.: Bureau of Land Management, 1970).

There was four times as much coal acreage under lease in 1970

than there was in 1960. See chs. 3 and 13 of this report for history and extent of coal leasing from 1950 to 1980.

‘Secretarial Order No, 2952, Feb. 13, 1973.

‘Two reports that were widely quoted in these hearings

were: J. Cannon, Leased and Lost; A Study of Public and Indian

Coal Leasing in the West [New York: Council on Economic Priorities, 1974), and U.S. General Accounting Office, Improvements Needed in Administration of Federal Coal Leasing Program, 1972.

8

Federal Coal Leasing Amendments Act of 1976, Public Law

94-377, 90 Stat. 1083, Aug. 4, 1976. In 1976, the House of Representatives approved S. 39 I by a vote of 344-51, and the

Senate accepted the House amendments by unanimous vote.

President Ford vetoed the bill on July 3, 1976. [Weekly Compilation of Presidential Documents, vol. 12, July 3, 1976. ) The Congress overrode the President’s veto. The Senate vote was 76-17,

122 Cong. Rec. 25198, at 25465 (Aug. 3, 1976); the House of

Representatives was 315-86, 122 Cong. Rec. H831O-H832O

(Aug. 4, 1976).

9

The Draft Environmental Impact Statement on the Proposed

Federal Coal Leasing Program issued by DOI in 1974 proposed

an “Energy Minerals Allocation Recommendation System” in

which leasing would be based on a Federal coal allocation

model. The Final Environmental Statement on the Proposed

Federal Coal Leasing Program issued in 1975 described a different system, the “Energy Minerals Activity Recommendation

System, ” described above. Since both systems have the same

acronym, they have sometimes been referred to as “EMARS I“

and "EMARS II. ”

10NRDC v. Hughes, 437 F. Supp, 981 (D.D.C. 1977]; order

modified, 454 F. Supp. 149, 1978,

11See 437 F. Supp. 981,993.

12Specifically the settlement authorized leasing in four circumstances: “bypass,” i.e., leases in which Federal coal might

otherwise be lost if not developed by an existing mine; hardship

(involving seven named lease applications); employment (leases

issued to maintain production and employment in mines existing on Sept. 29, 1977); and leases for certain experimental DOE

projects (i.e., projects authorized under sec. 908 of SMCRA 30,

USC 1328 to conduct and promote research, experiments and

demonstration projects relating to alternative coal mining technologies). Exchanges of Federal leases in alluvial valley floors

under sec. 510(b)(5) (30 U.S. C. 1260(b)(5]) of SMCRA were also

allowed. The Order expired before the PRLAs were processed

and adjudication of these applications is being conducted

under new coal management regulations issued in 1979. See

supplemental opinion NRDC v. Hughes, 454 F. Supp. 48 (D.C.

1978).

13The draft programmatic statement for the Federal Coal

Management Program was issued for review in December

1978; the final statement was filed in April 1979.

14Pub]ic Law 94-377, 90 Stat. 1083, Aug. 4. 1976.

1543 U.S.C. 1701 et seq.

1644 F.R. 42583, July 19, 1979.

“’’Multiple use” means the combination of resource values

that consider changing needs and conditions, long-term needs

for both renewable and nonrenewable resources, land productivity, environmental values, and economic return (43 U.S,C,

1702(c)). “Sustained yield”’ means the achievement and maintenance of high output of public lands natural resources consistent with multiple use (43 U.S. C. 1702(h)). See also 43 U.S. C.

1701(a)(9).

1842 U.S.C. 7 152(b).

19Trust Co. v. Samedan Oil Corp., 192 F.2d 282, at 284 (10th

Cir. 1975). The conditions of diligent development and continued operation are traditional in mineral leases and under

common law the meaning of diligent development evolved with

slightly different meanings for different minerals. Much of the

common law which defined diligent development resulted from

oil and gas leases in which conditions and expectations for diligent development are quite different from coal leases because

the existence of commercially producible oil and gas is usually

not known. The discussion of diligent development here focuses

on the concept as it applies to coal leases. A recent Texas case

involving private leases with an indefinite lease term held that

a coal lessee has a duty to develop the leased lands within a

reasonable period of time unless the lease specifically sets out

the scope of the lessee's duties—such as initiation of production within a specific period of years. See Cleghorn vs. Dallas

Power & Light Co., 611 S.W. 2d 893 (Tex. App. 1981) (Texas Ct.

of Civ. App., Jan. 21, 1981).

20The Mineral Leasing Act of 1920 allowed the DOI to accept

advance royalty payments in lieu of requirements for continued

operation. The DOI issued coal leases permitting payment of

royalties in lieu of continued operations, but until 1973 had effectively nullified the minimum royalty requirements by setting

the minimum royalty equal to the annual rental (i. e., no additional payments beyond the normal rental rates were required). There are a few leases that were issued between 1973

and passage of the 1976 FCLAA that require payment of advance royalties based on a predetermined rate of production

for the sixth and succeeding years of the lease (Office of Technology Assessment, Management of Fuel and Nonfuel Minerals

in Federal Land: Current Status and Issues, Washington, D. C.:

OTA, 1979).

21 See 41 F.R. 21779, May 28, 1976, In considering passage of

FCLAA, Congress was aware of the diligence requirements for

production on existing leases within 10 years in the proposed

and final regulations. Among the reasons cited for vetoing

FCLAA, President Ford said that the May 1976 regulations

made many of the provisions of the Bill unnecessary. See Statement of Representative Mink at 122 Cong. Rec. H8311, at

H8312 (daily cd.) Aug. 4, 1976.

2241 F. F/, 56643, Dec. 29, 1976.

23Public Law 95-51, sec. 302(b), 91 Stat. 579: 42 U.S.C.

7152(b).

24Public Law 94-377, 90 Stat. 1083, 30 U.S.C. 201(a)(2)(A).

The language in sec. 3 of FCLAA is very broad, and, given a

strict interpretation, would bar the issuance of any new leases
266 ● An Assessment of Development and Production Potential of Federal Coal Leases

for coal or for oil, natural gas, or other minerals under the Mineral Leasing Act to any coal lessee who continues to hold a

lease for 10 or more years without producing coal in commercial quantities. The section provides that “The restriction does

not apply if production on the lease has been suspended under

30 U.S.C. 207(b), as amended, because of strikes, the elements,

or casualties not attributable to the lessee. ”

2543 CFR 3400.0- 5(cc).

2643 CFR 3475.5(a)

2730 U.S.C, 207(b) and 30 U.S,C. 209.

28According to 30 U.S.C. 207(b), post-FCLAA lessees are subject to the conditions of diligent development and continuous

operations except when operations are interrupted because of

strikes, the elements, or casualties not attributable to the

lessee. However, the final sentence in the subsection provides

that nothing in this subsection (207(b)) shall be construed to affect the requirement in subsection (a) that leases not producing

at the end of 10 years shall be terminated. This proviso has

been interpreted to mean that no extensions of any kind are

available for post-FCLAA lessees. However, FCLAA did not restrict the Secretary’s authority in sec. 39 of the Mineral Leasing Act (30 U.S. C. 209) to suspend the operation of any lease in

its entirety in the interests of conservation. The Secretary

could suspend the term of a lease, and the diligence obligation,

under the general authority of sec. 39. Thus, providing some

delay in the running of the diligence clock for post-FCLAA

lessees. (Sec. 14 of FCLAA did amend sec. 39 slightly, by limiting the Secretary’s authority to waive, suspend, or reduce advance royalties paid in lieu of continued operation of a lease. )

See “Discussion Paper: Existing Leases and PRLAs,” in U.S.

Department of the Interior, Final Environmental Statement on

the Federal Coed Management Program, app. I at p. I-26, 1979.

30See 43 CFR 3475.4(b)(2). On Feb. 1, 1980, proposed guidelines for deciding on applications for discretionary extensions

under this regulation were published for comment. 45 F.R.

7138. In January 1981 final guidelines were approved by Under

Secretary Josephs of the Carter administration. As of May

1981, the Reagan administration had not yet decided whether

to adopt these guidelines.

3143 CFR 3473.4(d).

32Advance royalties were required of all leases on adjustment under 1976 pre-FCLAA regulations (since rescinded). The

pre-FCLAA advance royalty regulations might have had a significant effect on lease development. Had these regulations remained in force, the schedule for advance royalty payments in

1990 for 249 currently undeveloped leases with no mine plans,

assuming that none of these leases were producing, could have

been over $200 million. This is more than 9 times the $24.6 million paid in coal royalties in 1979. This estimate assumes that

all leases would be readjusted and uses an average royalty rate

of $1.25/ton ( 12.5 percent royalty per ton paid on an average

price per ton of $ 10.00). The annual production schedule for

applying advance royalties to the 249 undeveloped leases

would be $165 million tons (6.6 million tons of recoverable reserves divided by 40 years resulting in annual payments of

$206 million. This amount would probably have been significantly higher than the royalties paid on actual production

to meet the l-percent annual production rate for continuous

operations,

33See 43 CFR 3473.3-2(b).

3430 U.S.C. 188.

35In such proceedings, the interpretation of the law by the

agency charged with enforcing it is given great weight although

it is not necessarily controlling. The lessee can also raise various defenses to the action and to the application of DOI’s diligence standard to his lease. Thus, even if the lessee does not

meet DCI's diligence requirements. the final decision on the

facts and the law will be made by the court.

36"We believe that the Secretary has the discretion to establish standards such as these for lease cancellation. The standard described in 3523.2-1 clarifies those conditions that would

not be considered when a lessee applies for an extension to

avoid lease cancellation.” 41 F.R. 21780, May 28, 1976. The

current regulations on cancellation of leases (43 CFR 3452.2-

1(c)) list a number of adverse circumstances that will not be

considered in deciding whether to cancel a lease. The circumstances listed are essentially the same as those listed in 43 CFR

3475.4(b)(l) as conditions that are not extraordinary, and

hence do not qualify for extensions of diligent development

deadlines. These conditions include: 1) normally forseeable

business risks such as fluctuation in prices, sales, or costs, including foreseeable costs of complying with requirements for

environmental protection; 2) commonly experienced delays in

delivery of supplies or equipment; or 3) inability to obtain sufficient sales. The preamble to the Dec. 29, 1976 final regulations

states that these provisions limit the DOI’s discretion to decide

against cancellation. In its discussion of the reason for setting

minimum production levels for continued operation a 1 percent

rather than 21⁄2 percent annually the preamble says: “If the

lessee produces less than the rate specified in the mining plan,

the DOI may cancel the lease for failure to comply with the

plan; however, if the lessee fails to produce 1 percent annually,

the DOI's discretion to decide against cancellation would be

substantially limited as set forth in 43 CFR 3523.2 -l(b)(1)(i) (remodified as 3452.2-l(c), This ability to elect whether or not to

cancel a lease if annual production is between 1 percent and

the higher rate specified in the mining plan provides the DOI

with leverage to pressure those in arrears to increase production and to cancel leases when there is not a good faith effort to

comply with the mining plan” (41 F.R. 56,646, Dec. 29, 1976).

37 Secretarial Issue Document on Federal Coal Management

Program, Department of the Interior, March 1979, issue paper

No. 14. In the preamble to the May 1976 regulations, it was observed that: “It should be understood that, while the DOI has

provided a definition of diligent development for the future, it

reserves the right to sue for cancellation of existing leases

where lessees have not made a reasonable effort heretofore to

develop the coal resources, ” 41 F.R. 21780, May 28, 1976.

3890 Stat.1086, 30 U.S.C, 202(a)(4).

39After an LMU has been designated under sec. 5 of FCLAA,

any mine plan approved for that LMU “must require such diligent development, operation, and production so that the reserves of the entire unit will be mined within a period established by the Secretary which shall not be more than 40 years."

While not requiring amendment of lease terms to incorporate

the diligence requirements, these conditions on a mine plan approval could result in production exceeding requirements of

the 1976 regulations for diligent development and continued

operations which allow a pre-FCLAA lessee to mine his lease

for 971⁄2 years after meeting diligence,

40See for example, the lease form reprinted in Hearings on

Federal Coal Leasing Before the Subcommittee on Mines and

Mining of the House Committee on Interior and Insular Affairs.

94th Cong., 1st sess. (1975), at p. 41.

41A lease provision incorporating subsequent regulations

makes viola lion of these regulations grounds for cancellation

under sec. 31 of the Mineral Leasing Act which provides that

leases may be canceled for breach of general regulations that

were in effect a t the date the lease was issued. If, however, the

1976 diligence regulations are determined to be only interpretive regulations (i.e., those advising lessees and the public of

the DOI’s view of diligence under the act], then the limitation on

regulations in effect at the date of issuance is not applicable
Ch. 9—Federal Coal Lease Management ● 267

since the cancellation would be for violation of the act as interpreted by DOI. Departmental interpretations of matters committed to their discretion are generally followed by the courts

even though alternative reasonable interpretations be made.

Over time, departmental interpretations of law can become

binding on DOI, See Andrus v. Shell Oil Co.,—U.S.—No.

78-1815, June 2, 1980 (Slip Opinion) p. 15.

42 Mobil sued DOI in the District Court of Wyoming challenging the Secretary’s authority to impose diligent development regulations on its Rojo Caballo lease in Campbell

County, Wyo. The settlement provided that: 1) Mobil agreed to

dismissal of the lawsuit with prejudice: 2) Mobil would take all

steps necessary after mine plan approval so that a mine

capable of producing coal in amounts to meet diligence would

be in place not later than June 1, 1989: and 3) The extension is

applicable to Mobil only and cannot pass with any assignment

of more than 49 percent of the interest in the lease to anyone

other than a Mobil affiliate. On Apr. 23, 1980, Secretary of Interior Cecil Andrus signed a letter approving Mobil’s application for an extension of the diligent development deadline to

June 1, 1991. The extension approval was based on information

submitted by Mobil that it had contracts demonstrating that it

could market the necessary 21⁄2 percent of the LMU reserves

after 1986.

43U.S. Department of the Interior, Secretarial Issue Document on the Federal Coal Management Program, Issue Paper

No. 14, July 1979.

44See defendant’s Brief in Support of Its Cross-Motion for

Summary Judgment, Mobil Oil Corp. v. Andrus, No. C79-110B

(D. WY O. 1980).

45 See 43 CFR 3475.5(c) and 3452.1.

4630 U.S.C. 202(a),

4743 CFR 3400.0-5 defines MER but does not impose specific

requirements on existing leases.

48Proposed rules including MER requirements were published on May 19, 1980 (45 F.R. 321 15). In spring of 1981, DOI

announced that substantially revised proposals for MER and

diligence regulations were under consideration with publication for public comment tentatively scheduled for autumn 1981.

49U.S. Department of the Interior, Annual Federal Coal

Management Report Fiscal Year 1980, March 1981, pp. 26-27.

50California Portland Cement v. Andrus. civil No. C79-0477

(D. Utah, Dec. 30, 1980); Rosebud Coal Sales v. Andrus. civil No.

C-79-1608 (D. Wyo,, June 19, 1980).

51See preamble to final rulemaking on the Federal Coal

Management Program, 44 F.R. 42601, July 19, 1979, and 43

CFR 3451.1(d), 1980. The effect of this presumptive waiver of

readjustment on the applicability of regulations issued after

the prior lease date and of FCLAA provisions to the lease is not

specified. However, since DOI has previously maintained that

readjustment is not necessary to make general regulations applicable to the lease, DOI probably would argue that waiver

would have little effect because the regulations were applicable on promulgation not readjustment.

52See “Discussion Pa per,” Existing Leases and PRLAs, supra.

note 28. p. 1-26.

5343 CFR 3452,1-1.

5490 Stat. 1083, 30 U.S.C. 201(a).

55See 43 CFR 3475. (b)(2).

5643 CFR 3435.

57The exchanges proposed under special legislation include:

over 800 million tons in Federal leases along Interstate 90 in

northeast Wyoming: over 300 million tons of PRLA reserves in

southwestern Utah; and up to 60 million tons on leases in the

Bisti area of New Mexico. Additionally. as much as 400 million

tons of reserves in the Lake DeSmet lease blocks might qualify

for exchange under SMCRA and over 130 million tons of Federal bypass lease reserves could be involved in the Northern

Cheyenne lease cancellations.

58Public Law 95-554, 92 Stat. 2269, Oct. 30, 1978, House Rep.

95-469. See also, Cong. Rec. H11391, Oct. 3, 1978 (daily cd.).

Among other things, the amendments clarified that coal removed during construction of a right-of-way did not have to be

leased competitively and provided that higher minimum royalty

rates did not apply to modified leases until expiration of their

current terms.

59Bureau of Land Management, Lake DeSmet Exchang e

Study, Wyoming State Office, Johnson County, Wyo., July 1979.

Texaco is the major holder of private land and mineral rights

and only holder of Federal leases in the Lake DeSmet area. The

acquired lands would have been used for recreation purposes.

Even though the exchange was not approved, Texaco feels that

reserves on several Federal leases in the block may qualify for

exchange under sec. 510(b)(5) of SMCRA (letter from R.T.

Carter, Vice President, Coal and Energy Resources Department, Texaco. to OTA, dated Dec. 19, 1980).

60Energy Daily, June 17, 1981, p. 3. The rejection followed

negative recommendations by the U.S.G.S. economic evaluation

unit on the value of the PRLAs because the PRLAs are located

far from existing coal transportation networks. (Personal communication to OTA, U.S.G.S. Conservation Division, Denver,

Colo., Dec. 15, 1980. ) GAO also circulated a draft report on the

exchange questioning the validity of the PRLAs because the applicant did not have an approved prospecting permit when exploratory drilling was conducted on two PRLAs: and the lack of

data on the coal reserves required for making the “equal value

determination”: and expressing concern over the competitive

effect of giving Utah Power & Light highly desirable coal lands

in central Utah. Letter of Apr. 2, 1981 from J. Dexter Peach. Director, Energy and Minerals Division. GAO, to James G. Watt,

Secretary of the Interior. The Utah Power & Light exchange is

discussed in the final environmental statement on the UintaSouthwestern Utah Lease Sale, Bureau of Land Management.

1981.

61 Several of the Wyoming leases under consideration for exchange were reviewed by the OTA Wyoming task force and are

discussed in ch. 6 of this report. The Interstate Highway exchange proposal includes parts of the existing Wyodak Mine

and two lease blocks with favorable production prospects by

1986 (Kerr McGee’s East Gillette Federal and Carter’s South

Rawhide Mines). Two other leases—Armstrong and Gulf (No.

3) were given unfavorable development prospects. The final

lease, Belco, has uncertain development prospects-contingent

on in situ gasification—with unfavorable production prospects

in 1986 and 1991. Gulf Oil Co. has requested that the Gulf (No.

3) lease be exchanged for a corridor of unleased Federal coal

that splits its Wildcat lease in Campbell County.

6294 Stat. 2269, Oct. 19, 1980).

63 See Senate Report 96-800. accompanying S. 1455 (June 19,

1980).

6494 Stat. 1701, Senate Report 96-883.

65 See statement of Senator Melcher, 126 Cong. Rec. S. 11142

(daily cd.), Aug. 18, 1980. According to information obtained

at the OTA Wyoming task force, up to 1 billion tons of coal is

covered by these leases and permits. Peabody Coal Co., holder

of the seven leases and three permits, is seeking rights to 130

million tons of Federal bypass coal in return for cancellation of

its tribal lease claims.

6630 U.S.C. 1260(b)(5).

67 Regulations providing for alluvial valley floor exchanges

were challenged as part of litigation involving the surface mining act regulations. The AVF exchange regulations were remanded to DOI to include provisions implementing the mandatory exchange program for non-Federal lands. See con-
268 ● An Assessment of Development and Production Potential of Federal Coal Leases

ference report on H.R. 2, House Report 95-493, July 12, 1977,

pp. 104-105:

The Senate amendment also provided authority for the Secretary of Interior to lease Federal coal deposits as an exchange

relinquishment of a Federal coal lease for coal affected by this

alluvial valley floor constraint. Such an “exchange” would be

limited to those operators who had made a “substantial legal and

financial” commitment to mine such coal prior to Jan. 1, 1977.

Similar exchange authority under sec. 206 of the Federal Land

Policy and Management Act of 1976 was granted the Secretary

with respect to “fee” coal owned in alluvial valley floors. Both of

these authorities were discretionary on the part of the Secretary.

The conferees also stipulated that the Secretary develop and

carry out a coal exchange program for fee coal located in alluvial

valley floors under the provisions of sec. 206 of the Federal Land

Policy and Management Act of 1976.

The language added by the conferees to the “Wallop Amendment” of the Senate version is designed to make it clear that the

Secretary should actively implement the coal exchange program.

This program would apply to all those private coal deposits, regardless of any previous financial or legal commitments, which the

Secretary determines cannot be mined because of the provisions of

sec. 510( b](5]. The program would not apply to privately owned

coal which might have been mined in the same operation but which

can still be mined.

*43 U.S.C. 1716, Regulations implementing sec. 206 have

been promulgated but are under review by the Reagan administration.

‘

q

Exchanges of checkerboarded lands covering critical

winter range for big game species in the Atlantic Rim area near

Rawlins, Wyo, have been suggested. See also, R. C. Anderson

and A, Silverstein, Management of Federal Cod Properties in

Areas of Fragmented Resource Ownership (Washington, D. C.:

Environmental Law Institute, 1980) for discussion of exchanges for unitization of coal reserves.

“’See Management of Fuel and A!on~uel Minerals in Federal

Land, Office of Technology Assessment, April 1979, ch. 3, for

discussion of various provisions for obtaining development

rights for other leasable and hardrock minerals.

“See ch. 3 of this report.

7290 Stat. 1085. There were about 192 prospecting permits

pending on passage of FCLAA and 28 prospecting permits. The

number of PRLAs has dropped as some applications were rejected and now fluctuates between 171 and 178 depending on

the results of various appeals of rejected applications. All prospecting permits have since expired. As of March 1981 the

number of PRLAs had dropped to 171 as a result of: 1) addition

of two new applications because of litigation challenging the

DOI’s denial of extensions of prospecting permits for which no

applications had been filed at the time the 1976 FCLAA was

enacted; and 2) the withdrawal of seven applications.

“The Summary Paper on Management of Preference Right

Lease Applications (Office of Coal Leasing Planning and Coordination, SecreturiaJ Issue Paper: Formulation of Proposal for

Coal Programmatic Environmenkd Impact Statement (Washington, D. C.: U.S. Department of the Interior, June 23, 1978, Tab I)

estimated maximum potential production from pending PRLAs

to range from 186 million tons/year (if legal, probable and

possible planning and environmental restrictions are applied)

to 248 million tons (no restrictions applied). This was based on

40-year mine life on estimated recoverable reserves of 9.9

billion tons. The estimated reserves under PRLAs have been

subsequently reduced to 5,7 billion tons (due primarily to

elimination of an estimated 3.6 billion tons of subbituminous

underground reserves in the Wyoming Powder River basin). If

the lower reserve figures are substituted for those in the

Secretarial issue paper, the range of potential production

drops to between 108 million and 144 million tons, OTA’S analysis of PRLAs in Wyoming indicates that approximately 40 million tons of potential production capacity in this revised number have unfavorable development prospects (see ch. 6 and

OTA’S Wyoming task force report). When OTA’S estimates of

potential production capacity of PRLAs in Wyoming with favorable or uncertain development prospects (20.5 million

tons/year) are substituted for the revised numbers for Wyoming in the Secretarial issue paper, the range of total production potential becomes 69,5 million to 102.5 million tons/year.

OTA’S analysis of production potential of PRLAs in the 1990’s

is based on the following modifications of DOI’S production estimates: Colorado, 9 million to 17 million tons; Montana, zero to

7.7 million tons; New Mexico, 7,5 million to 9.5 million tons;

Oklahoma, zero to 0.4 million tons; Utah, zero to 6.5 million

tons; Wyoming, 20 million tons. OTA’S adjusted annual production totals yield a range of 35 million to 60 million tons including

about 10 million tons of production capacity associated with

existing leases and reflected elsewhere in this report as Federal mine production. Total new annual production potential of

PRLAs would thus be between 25 million and 50 million tons.

Some PRLA reserves in eastern Colorado and Wyoming were

found to have some potential for use as a feedstock in synthetic

fuels processes, but substantial production from these PRLAs

is likely only if there is greatly expanded demand for such coal

in the 1990’s.

741nitial production from most PRLAs can be expected in

1988-94 assuming that it takes about 6 years for mine development from the date of lease issuance. Several groups of PRLAs

will be issued during 1981 to 1982 under an accelerated processing schedule: these PRLAs include four in Colorado and the

Arch Mineral PRLAs in New Mexico.

75105 of 172 applications submitted to BLM did not contain

information proving that commercial quantities had been discovered, but rather stated that the requisite data had been provided to the U.S. Geological Survey, Seventy-five PRLAs were

filed without the required qualifications statement describing

the applicant, and 70 PRLAs were filed without precise descriptions of the acreage covered by the application. In addition, 25 PRLAs did not file initial showings in a timely manner

required under the 1976 regulations (Coal task force No. 124,

An Evaluation of Coed Preference Right Lease Applications,

Washington, D. C., U.S. Department of the Interior, April 1978).

In most instances, the regulations or DOI practices allow the

applicant to correct the application by supplying the required

information, If the applicant does not respond with the requested information then the application can be rejected. See,

for example, 43 CFR 3430.2-2, 1980.

7hCoal task force paper No. 124 identified six PRLAs that did

not properly indicate the existence of recoverable reserves and

four PRLAs that were not filed before the expiration date of the

prospecting permit. Several of these PRLAs have subsequently

been rejected.

“Preference right leases were issued in 1974, 1975, 1976,

and 1977 in accordance with short-term leasing criteria in effect at that time. The four leases (one issued in each of those

years) range in size from 175 to 14,902 acres.

“See 41 F.R. 18845, May 7, 1976 (final rules); see also proposed rules published at 41 F.R. 2648, Jan. 19, 1976.

“According to the Preamble to the Proposed Rules, use of the

workability standard for classification resulted in a determination of commercial quantities “based solely on the physcial

characteristics of the mineral without regard to costs such as

transportation and reclamation, ” The use of this standard was

rejected. 41 F.R. 2648.

’43 CFR 3430.1-2.

8143 CFR 3430.5.

IIINRDC v, Ber~Un~, 458 F. SUpp. 925 (D.D.C. 1978).

‘

3

458 F. %pp. 937.
“458 F. Supp. 937.

“The ability of DOI to exchange leases or PRLAs for unleased Federal coal without specific congressional approval is

relatively limited, but 43 CFR 3435.1 allows PRLAs to be relinquished in exchange for other rights, including: I) the issuance

of coal lease bidding rights of equal value; 2) a mineral lease

other than coal by mutual agreement by the applicant and DOI;

and 3) modification of other coal leases held by the applicant.

“458 F. Supp. 938. The decision notes that it left open the

question of whether such withdrawal would constitute a taking

since, under 43 U.S.C. 1701, withdrawals are subject to valid

existing rights.

“’NRDC v. Berklund, 609 F. 2d 553 (D.C. Cir. 1979).

“448 F. SUPP. 962 (D. Ut. 1979)

‘

9

448 F. Supp. 988 (D. Colo. 1979).

WIA total of 118 certified abstracts were received by DOI, as

well as 21 certificates and 9 letters. Nineteen applicants did

not respond and five PRLA holders were not contacted because

of pending litigation.

“Bureau of Land Management Instruction Memorandum No.

76-646, change 2, Dec. 19, 1979.

“See 30 U.S.C. 521-523, especially 30 U.S.C. 524, 525, 526

and 527.

‘“43 U.s.c. 1744.

‘“43 CFR 3430.1-2

Ch. 9—Federal Coal Lease Management ● 269

“Samuel Pu~ford, 45 L.D. 484, 1916.

‘NRDC v. Berkiund, 458 F. Supp. 925 (D. D.C, 1978).

“The legal basis for this argument is set forth in a letter from

‘rerence Thatcher, counsel for the National Wildlife Federation to Frank Gregg, Director, Bureau of Land Management (re:

comments on Bureau of Land Management Proposed Coal

Leasing Management Regulations: PRLAs, May 18, 1979). In

1975, the Environmental Defense Fund and Natural Resources

Defense Council concluded that a number of PRLAs in the Powder River basin, Wyoming could be challenged on this basis,

but decided that litigation challenging such PRLAs would need

to be done on a case-by-case basis when (or if) the leases were

actually granted.

“844 F.R. 42599, JUIY 19, 1979.

“

qSee 30 U.S.C. 1260(b) abd 30 USC. 1272(a).

““30 U.S.C. 1272(a)(3).

“’’See 16 U,S.C. 1.

“’zSome PRLAs in the San Juan Basin of New Mexico are located within a few miles of Chaco Canyon National Monument

and its “outliers”. Chaco Canyon was established primarily to

preserve the Indian archeological sites there: it is likely that

any protective stipulations on mining in the area would be

directed at minimizing any harmful effects of mining on the

archeological sites and not at preserving scenic vistas.

“’iSee notice at 46 F.R. 30202, June 5, 1981.
CHAPTER 10

Implications-of Environmental

and Reclamation Issues for the

Development of Federal Coal

CHAPTER 10

Implications of Environmental

and Reclamation Issues for the

Development of Federal Coal

This chapter considers the extent to which

environmental and reclamation concerns

may affect the production of Federal coal.

Primary emphasis is placed on documentation of those cases where mining of recoverable coal reserves has been delayed or prevented. A brief discussion is also included on

the effect that environmental and reclamation concerns have on the cost of mining Federal coal. The chapter is not an analysis of

the effects of coal mining on the environment,

although those issues are briefly discussed in

order to provide a context for the chapter.

Background information is also provided on

the environmental characteristics of Western

coal regions and the existing framework for

coal mine regulation.

Environmental Overview of Coal= Producing Regions

The United States can be divided into 12

major coal-producing regions (fig. 43). Federal coal accounts for a large portion of the

coal reserves of the six westernmost regions.

In addition, Federal coal reserves are significant in the extreme southern portion of the

Western Interior region in Oklahoma. * This

section reviews the important environmental

characteristics of these seven coal regions,

pointing out regional similarities as well as

noting differences. Emphasis is placed on discussion of those characteristics that are of

most importance to the mining of Federal coal

reserves, and on the potential for success in

reclaiming mined lands. This section serves

as background to the discussion of reclamation and environmental issues later in this

chapter.

Because Federal coal reserves are concentrated in the Western United States, the en-

*Alaska has substantial coal resources on Federal lands, and

there are also scattered areas of federally owned coal reserves

in the eastern regions and in Texas. These coal regions are not

considered in this report because of the relatively minor

amounts of Federal coal there currently under lease compared

to leased reserves in the seven States of Colorado, Montana,

New Mexico, North Dakota, Oklahoma, Utah, and Wyoming.

vironmental characteristics of mining and

reclamation of Federal coal differ from the

mining of the other coal reserves of the Nation. Only the Federal coal reserves of Oklahoma in the Western Interior region have environmental characteristics similar to the

characteristics of the privately held reserves

of the Midwest and Eastern United States.

The Western United States is notably distinct from the rest of the country in its overall

lack of available water, its shallow soils, and

its high erosion rates. These factors combine

to make reclamation more difficult than in

other parts of the country. Annual mean precipitation in the West is low, ranging from 4

inches or less per year in some of the hot

deserts to over 20 inches in the higher mountains. Droughts are common in the West, and

precipitation is more commonly below average than above. Particularly during periods

of drought, precipitation may occur in short,

intense storms that have the potential to

cause severe erosion. Temperatures in the

West fluctuate widely, and high summer daytime temperatures can quickly dry out soil

and seeds.

273
274 “ An Assessment of Development and Production Potential of Federal Coal Leases

Figure 43.—Tweive Coai Suppiy Regions of the United States

u v

SOURCE: U.S. Department of the Interior, Final Environmental Statement, Federal Coal Management Program (Washington, D. C.: U.S. Government Printing Office.

1979), p. 1-4.

Soil is poorly developed in the semiarid and

arid West. Rocks weather slowly, and organic matter accumulates slowly. The resulting soil profile is loose and undifferentiated

and has little capacity for holding moisture.

In much of the West, rates of erosion are

among the highest in the country, and soil can

be lost because of flash flooding and hillslope

erosion.

Vegetative succession is a slow process in

the West because of climatic severity. A disturbed site in the Eastern United States may

revegetate itself in 5 to 10 years, but decades

or centuries maybe needed for natural revegetation in the West. Thus, natural revegetation cannot be relied on to rehabilitate disturbed sites, and careful planning is needed.’

Tables 80, 81, and 82 summarize the environmental characteristics of the seven coalproducing regions with major reserves of

Federal coal. The information is separated

into three categories: physical characteristics (table 80), environmental resources (table

81), and social characteristics (table 82).

‘Previous three paragraphs adapted from National Academy

of Sciences, Rehabilitation Potential of Western Coal Lands

(Cambrdige, Mass.: Ballinger Publishing Co., 1974),
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal 275

Table 80.—Physical Characteristics

Region: State(s) Physical division and subdivision Topography Soil ordersb Climatec

Western Interior: Central Lowlands Division Gently sloping hills Mollisols Evaporation: 64-80"/lyr.

Oklahoma Upper Missouri Basin Subdivision Inceptisols Mild temperatures: 400 winter

>800 summer

Precipitation: 32-48’’/yr.

Winds: 11-14 mph

Dust storms and tornadoes

common

Fort Union: Great Plains Division Gently undulating land surfaces; Mollisols Evaporation: 46-64’’/yr.

Montana Upper Missouri Basin Subdivision relief less than 20 ft. in Entisols Semiarid continental

North Dakota glaciated areas. Long cold winters, short warm

Gently sloping, roiling prairie, summers.

with isolated buttes, mesas Mean annual temperature:

and badlands in unglaciated 38-45 “F

areas. Precipitation: 12-16’’/yr.

thunderstorms frequent

Winds: 10 mph

Powder River: Great Plains Division Undulating land, Aridisols Evaporation: 48-64’’/yr.

Montana Upper Missouri Basin Subdivision Surface highly dissected in Mollisols Semiarid continental

Wyoming some areas. Entisols Mean annual temperature:

45“F

Precipitation: 14’’/yr. (75% of

ppt. occurs from Apr. -Sept.)

Chinook winds: warm, dry, 25-

50 mph, Aug. windy-12 mph.

Green River-Hams Fork: Middle Rocky Mountain Division Complex mountains and basins, Aridisols Evaporation: 48’’/yr.

Colorado (Wyoming - Big Horn Basin generally a series of parallel Mollisols Semiarid continental

Wyoming Subdivision) ranges. Mean annual temperature:

Local relief up 2,000 ft, but 37-46 “F

generally Iess than 1,000 ft. Precipitation in NW: 16-32’’/yr.

in rest of area: 8-16"/yr.

Uinta-Southwestern Utah: Colorado Plateau Varied: peaks and plateaus Aridisols Evaporation: North 48-64’’/y.;

Colorado Division and Subdivision rising from lowlands. Mollisols South 64-80"/yr.

Utah Extremely steep slopes and Entisols Arid for most of the regions

narrow, vertically walled Alfisols with varied weather patcanyons. terns in the mountains

High plateaus of stratified rock (some of which maintain

cut by deep canyons in year round snow cover)

southwestern Utah. Precipitation: 30% of area

receives 0-8"/yr., rest of

area (except mountains):

8-16’’/yr.

mountains: > 20”/yr.

San Juan River: Colorado Plateau Basins with mesas, rolling Entisols Semiarid

Colorado Division and Subdivision plains, and badlands Aridisols Mean annual temperatures:

New Mexico 48-52 ‘F

Utah Mean annual precipitation:

less than 10” to 20”

Summer thunderstorms.

Evapotranspiration exceeds

precipitation by a factor of

6:1

Denver-Raton Mesa: Southern Rocky Eastern portion: gentle plains Alfisols Evaporation: 64-80’’/yr.

Colorado Mountain Division Western portion: Steep slopes

New Mexico Rocky Mountain, Piedmont and

Semiarid continental

and foothills Mean annual temp.: 48-520 F

Southern Rocky Mountains Precipitation: 13-18’’/yr., low

Subdivision humidity, light rainfall,

periodic droughts

Winds: 10 mph

aphy~ical dlvi~i~n based on classes defined by Nc3vln Fennemen (National Atlas). Physical subdivisions based on classes def!ned by Edwin H. Hammond.

bsoil t ~es listed in chart ,n order of dominance, Deflnltlons Of S011 orders fOllOWS:

Arid {SOIS: These soils are found In arid regions. They have both a low moisture content and absorb precipitation slowly, thus most preclpltatlon runs off. There IS a

period of about 3 months during the year when the soil is both warm and moist enough for plant growth. The vegetation which these SOIIS can support without Irrtgatlon

is Ilmlted to ephemeral grasses and cacti.

Entisols: These soils are In early stages of development, and thus lack defined layers down to a depth of 50 cm. They exhlblt a wide range of moisture content and

temperature. These soIls characteristically develop on steep, actively eroding slopes, and on flood and glacial outwash plalns.

Mollisols: These soIls are found throughout the subhum!d to semiarid plalns of North America. MOIIISOIS retain enough moisture to support perennial grasses and

many have been forested or have had grass vegetation. In areas of suitable c1 imatic condltlons, they are used to produce grains, sorghum, corn, and soybeans

Alfisols: These soIls are characterized by a clay horizon which IS capable of holding moderate amounts of water. Their moisture retention IS sufflctent to sustain plant

growth for at least 3 months of the year, provided the soIl is warm enough

fnceptisols: These soils have weakly differentiated horizons Materials In the soil may have been altered or removed, but have not accumulated. Although generally

moist, these soils tend to dry out in the warm seasons

cEvaporatlon figures are for mean annual evaporation.

SOURCE: Class A pan-National Atlas.
276 . An Assessment of Development and Production Potential of Federal Coal Leases

Table 81.—Environmental Resources of Coal-Producing Regions

Carrying

Agriculture capacity

Air quality Water quantity and quality Vegetation Wildlife and land usea Iivestock b

Western Interior Overall quality: Surface water runoff 7“. Transitional areas: Species typical supports 2.6 acres/

good. Surface water quality good. eastern forests to of forest and crops and A.U.M.

Urban areas: prairie grasses. prairies: deer, timber

moderate NO2

fox, coyote, harvesting.

levels around whitetail deer, Cropland: 52%

Tulsa, Okla. small woodland Pasture: 11%

mammals. Range: 15%

Federally pro- Forest: 10%

tected species: 6

birds, 3 mammals.

Fort Union Uniformly very Annual runoff: 1"/yr. Eastern: Wheat- Varied wildlife: Cropland con- 8.2 acres/

good Surface water availability limited grass, needlegrass. 87 species birds, stitutes 75% A.U.M.

except in major streams. Western: Gramma, 70 species ream- of N. E., 5%

Groundwater available in small needlegrass, wheat- reals, 200 southern

quantities except in alluvial valleys grass. species fish, 20 area.

where more abundant. species reptiles Elsewhere,

Major streams: Missouri, and amphibians. Cropland: 37%

Yellowstone, Knife. Federally pro- Range: 54%

tected species: 4 Principal

birds, 3 mam- crops: wheat

reals. and grain.

Powder River Overall quality: Annual surface water run-off: less Wyoming: Prairie Similar to Fort Grazing and 15.5

generally good. than 0.5”. shortgrass, Union. ranching. acres/

Variations around Surface water limited except along grassland Federally pro- Cropland: 5% A.U.M.

populated areas, major streams. Quality: variable. sagebrush. tected species: 3 Range: 88%

i.e,, Colstrip, Mont. Groundwater availability and quali- Montana: grassland birds, 1 mammal.

is a nonattainment ty: variable. sagebrush, and

area for TSP. Major streams: Yellowstone, Big ponderosa pine.

Horn, Powder, Tongue, Belle

Fourche, and Musselshell.

Green River- Overall quality very Annual runoff: Western half: 10-30” Cold desert biome: 53 mammal Cattle and 9.3 acres/

Ham’s Fork good, however,

Craig, Colo. and

parts of Sweetwater, Colo., and

Wyoming are nonattainment for

TSP.

Eastern half: .1-2” sagebrush. species. sheep ranch- A.U.M.

Quality good in mountains and Salt brush biome: Large numbers of ing, limited

poor in basins. greasewood, moun- big game farming.

Major streams: Green, Yampa, tain shrub, animals. Cropland: 4°/0

Sweetwaters, Shoshone, Greybull. evergreen forests, Varied game and Range: 70°/0

broadleaf forests. non-game fish Forests: 270/o

species.

Wild horse herds.

Federally protected species: 1

fish, 3 birds, 2

mammals.

Uinta- Rural air quality: Annual runoff: 0.1-.5"/yr. Vegetation varies Varied habitat Desert 8.3 acres/

Southwestern very good. Good water quality. with climate. supports many shrubland A.U.M.

Utah Urban areas: occa- Region contains numerous Cold desert biome: diverse species: and open

sional problems tributaries to the Colorado River: salt brush and 90 species ream- woodland

during temperature Green, White, Duchesne, Price, greasewood. reals, 270 grazing.

inversions. Dirty Devil, Paria, Escalante, & Mountain Forest species birds, 26 Crops: 3°/0

Virgin Rivers. biome: pine, fir, species reptiles, Range: 62%

spruce, and 9 species am- Forests: 33°/0

sagebrush. phibians

Federally protected species: 3

fish, 3 birds, 2

mammals.

San Juan River Overall quality Annual runoff: 0.1-O.5’’/yr.

generally good except around industrial areas.

High SO2 levels

near powerplants.

Major streams: San Juan, Colorado,

and Little Colorado.

San Juan River is the only perennial

stream in Federal lease block area.

Ground waters are generally good,

but levels are dropping.

Generally sparse

vegetation.

Lower elevations:

grassland shrub

and grasslands.

Upper elevations:

Pinyon, juniper and

coniferous forests.

Habitat supports:

100 species

mammals, 116

species birds, 28

species amphibians.

Several are

unique to region.

Federally protected species: 1

fish, 4 birds, 1

mammal.

Cattle and 22 acres/

sheep ranch- A.U.M.

ing.

Range: 50%

Forests: 45%

Limited crops:

corn, hay,

wheat, cotton,

and sugarbeets.
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal ● 277

Table 81.—Environmental Resources of Coal-Producing Regions—Continued

Carrying

Agriculture

Air quality

capacity

Water quantity and quality Vegetation Wildlife and land usea Iivestock b

Denver-Raton Overall: very good. Annual runoff: 0.5 inches/yr. Prairie biome: Buf- Typical species: Agriculture 16 acres/

Mesa Urban areas often Surface water: falo grass and blue marmot, ground supports A.U.M.

fail to meet na- Quantity: 5.4 million acre ft/yr. gramma. squirrel, wildcat, sugarbeets

tional standards Quality: good. Coniferous forest in vole, bobcat,

due to inversions

and grain.

Major streams: South Platte, S.W. mule deer, elk, Cropland: 21%

and automobile in- Arkansas. porcupine. Range: 56%

duced pollution. Federally pro- Forests: 21 0

/0

tected species: 1

fish, 3 birds, 1

mammal.

a percentages are of total land area. Only major land uses are listed.

b Refers to the ability of the land to SuPPort livestock, A.U.M. stands for animal unit month, which refers to the grazing requirements of an “averaged” livestock animal

for 1 month.

SOURCE: U.S. Bureau of Land Management, Final Environmental Statement, Federal Coal Management Program, 1979.

Table 82.—Archeological and Cultural Resources of the Western Coal Regions

1975

Major Federal parklands 1975 Pop. per

Region Archeological resources and forests resources population sq. mile

Fort Union Much of the region has some iden- ● Little Missouri National 324,399 5.4

tified archeological value. A few Grassland

areas have large sites and/or high ● Theodore Roosevelt National

site density. There is a high prob- Memorial Park

ability of disturbance to sites in ● Custer National Forest

Custer Co., Mont., and in Mercer,

Williams, and Oliver Co’s., N. Dak.

Powder River There is a high probability of distur- ● Devils Tower National Monument 228,418 4.6

bance to sites in Rosebud, Bighorn ● 65 Sites eligible for, or currently

and Powder River Co’s., Mont, and enrolled on the National Register

in Johnson and Campbel Co’s., Wyo. of Historic sites.

Remainder of region considered to • Thunder Basin National

have some archeological value. Grassland

● Custer National Forest

Green River- The region has some identified ● Flaming Gorge National Recrea- 126,938 2.6

Hams Fork archeological value. Many areas tion Area

have not been surveyed. • Dinosaur National Monument

Uinta-Southwestern There is a high probability of dis- ● Capital Reef, Arches, Can- 406,626 7.2

Utah turbance to Fremont and Anasazi yonlands, Zion, and Bryce Cansites in Emery, Kane and Garfield yon National Parks

Co’s., in Utah. Remainder of region ● Cedar Breaks National Monument

considered to have some archeo- ● Black Canyon of the Gunnison,

logical value. and Colorado National

Monuments

San Juan River This region has been identified as ● Mesa Verde National Park 351,143 7.2

having both great archeological ● 6 National Monuments

and historical value. There is a high

probability of disturbance to sites

in the Chaco Canyon National Monument area.

Denver-Raton Mesa This region has some identified ● Comanche National Grasslands 1,854,205 77.5

archeological value.

a Based on a survey Performed by the National Academy of Sciences of 69 strippable coal areas in the West. Tables A.1, A.3, Rehabilitation potential of Western Coal

Lands, NAS, 1974.

SOURCE: Office of Technology Assessment.
278 . An Assessment of Development and Production Potential of Federal Coal Leases

Physical Characteristics. Table 80 contains information on physiographic subdivisions, topography, soil orders, and climate.

The topography of the Federal lease areas is

varied. The Western Interior region is typified by a gently undulating prairie landscape.

The northern regions (Fort Union and Powder

River) are also generally characterized by

low overall relief and an undulating grassland, but selected areas include badlands,

ponderosa pine forests, and rocky cliffs and

outcrops. The central western regions (Green

River-Hams Fork and Uinta-Southwestern

Utah) are located in mountainous terrain. The

San Juan River region is characterized by

mesas and badlands. Topography in the Denver-Raton Mesa region varies from gentle

plains to rugged slopes and foothills. As noted

earlier, the Western areas tend to be either

semiarid or arid in climate. There are some

exceptions in the mountainous areas, which

tend to create localized weather patterns of

higher precipitation. In all the Western regions, evaporation exceeds precipitation. The

ratio of evapotranspiration* to precipitation

ranges from 2 to 1 in the Fort Union region to

6 to 1 in the San Juan River region. The evaporation rates in the region range from 48 to 64

inches in a year in the northern coal regions

and generally increase to a high of 80 to 96

inches a year in the southern San Juan River

region, Low rainfall and high evaporation

creates moisture stress throughout the coal

lease areas. The moisture stress generally increases from north to south for similar elevations. Soil types reflect the topography, geology, and climate of the regions. Most of the

soils have a low moisture content, but usually

hold enough water to sustain plant growth for

3 months of the year.

Environmental Resources. Table 81 summarizes air quality, water resources, vegetation, wildlife, agriculture and land use, and

livestock carrying capacity of the coal lease

regions. Overall, the air quality of all the

regions is good to very good, although atmos-

*Evapotranspiration means loss of water from the soil both

by evaporation and by transpiration from the plants growing in

the soil.

pheric inversions are common in all the areas

for parts of the day in both summer and winter. The exceptions to good air quality are in

areas with extensive urban or industrial development. Areas with air quality problems

include Billings and Colstrip, Mont.; portions

of Sweetwater County, Wyo.; Craig, Colo.;

areas around powerplant generating stations

in the San Juan River region; and in the urban

Colorado Front Range corridor.

Annual surface water runoff ranges from

0.5 to 2 inches for most of the coal lease

regions, with most areas falling within the

lower part of the range. The major exception

is in the mountainous areas of the Green

River-Hams Fork and Uinta-Southwestern

Utah regions. Water availability in all regions

is greatest in the major river valleys. The

water quality of the regions’ streams is difficult to generalize and ranges from variable

to good. High sediment loads are common.

The coal regions are characterized by

sparse growth in the lower elevations. Prairie

grasses and sagebrush are the predominant

species. The mountainous forests are generally characterized by coniferous tree

species. Large mammals—antelope and mule

deer—range throughout the regions, with the

Green River-Hams Fork and Uinta-Southwestern Utah regions containing the largest number of big game animals. The San Juan River

area contains a number of animal species

that are unique to only that region. The number of federally protected fish, bird, and

mammal species varies from four to nine in

each region.

Except for the fertile Western Interior

region, the predominant land use is grazing.

The semiarid conditions of the West limit

croplands to areas with above-average rainfall or to irrigated or subirrigated areas

generally found in stream valleys. Table 81

indicates the percent of land devoted to both

farming and grazing use. In addition, table 81

summarizes the average regional carrying capacities for livestock, which range from 2.6

acres per animal unit month in Oklahoma, to

22 acres per animal unit month in the San

Juan River region.
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal . 279

Social Characteristics. Table 82 contains

information on population, population density, and features of archeological significance in the coal lease areas. In general, the

population density of the Western regions is

low, except in the Denver-Raton Mesa region

which reflects the significant growth that has

occurred in the Denver region.

The archeological history of most of the

Western region dates back to the PaleoIndian big game hunting tradition of the

pre-8000 B.C. period, and to the Desert Culture of the period from 9000-4000 B.C. The

regions also contain remains of early Indian

cultures, the most significant of which is the

Anasazi people and the remains of their multistoried pueblos in the Southwest that date

back to 1000 A.D. Although all of the regions

are considered to have some archeological

significance, the San Juan River region has

the greatest archeological value.

Regulatory Framework

Federal regulation of the environmental

effects of surface coal mining operations,

including the surface effects of underground

mining, was initiated on August 3, 1977 when

President Carter signed into law the Surface

Mining Control and Reclamation Ac t

(SMCRA) (Public Law 95-87 ).2

In brief, the Surface Mining Act establishes a detailed national program for addressing environmental effects of coal mining. Of particular importance is the act’s

establishment of environmental protection

performance standards (sec. 515) and provisions for designation of lands as unsuitable

for coal mining (sec. 522). The performance

standards of section 515 are minimum standards applicable to various aspects of the mining and reclamation process. Under SMCRA,

the States may, if they choose, impose standards that are more stringent. Among other

things, the standards require:

●

●

●

●

●

maximum utilization and conservation of

the coal being recovered;

restoration of disturbed land to original

or better conditions;

restoration of the approximate original

contour of the land surface;

stabilization and protection of all surface areas;

protection of prime farmlands through

specific reclamation techniques;

2

91 Stat. 445, 30 U.S,C. 1201 et. seq.

84-141 ? - 81 - 19 : u 1, 3

● minimization of disturbances to the existing hydrologic balance; and

● limitation of mining on steep slopes.

Section 522 of the act establishes a procedure to designate lands as unsuitable for

all or certain types of coal mining operations.

The Secretary of the Interior determines unsuitability for Federal lands, while States

have authority over non-Federal lands. Areas

may be designated unsuitable if, upon petition, it is determined that reclamation of disturbed lands is not economically or technologically feasible. Areas may also be designated unsuitable if mining operations will:

● be incompatible with existing land use

plans;

● significantly affect important fragile or

historic lands;

● result in substantial loss or reduction in

the productivity of renewable resource

lands which produce food or fiber; or

● substantially endanger life and property

in natural hazard lands.

The act requires that the Department of

the Interior (DOI) obtain the consent of certain private surface owners before Federal

coal underlying their lands can be leased.

The act restricts mining activities affecting

alluvial valley floors. Section 510(b)(5) of the

act allows the Secretary of the Interior to

trade unleased Federal coal reserves for existing leases or non-Federal lands that cannot

be mined because of alluvial valley floor des-
280 An Assessment of Development and Production Potential of Federal Coal Leases

ignations provided that coal is not yet being

produced from the mine and the operator had

made a substantial legal or financial commitment to develop a mine before January 1,

1977. The act also requires the Secretary to

exchange non-Federal coal lands in alluvial

valley floors that cannot be mined for available Federal coal lands of comparable value;

these exchanges are not subject to the requirement of substantial legal and financial

investments.

The act also created the Office of Surface

Mining Reclamation and Control (OSM) within DOI to implement the statute’s various programs. The act mandates compliance with detailed technical performance standards by

operators on private as well as on Federal

and State lands. The act originally provided

for slightly less than 3 years of Federal enforcement of State-issued operating permits

implementing the most stringent of the act’s

performance standards (known as the “interim regulatory program”) followed by implementation of the remaining standards

(known as the “permanant regulatory program”). At the end of 3 years (June 3, 1980),

primary regulatory responsibility for the program was to have shifted to those States who

had their proposed program for assuming

regulatory primacy approved by DOI. In

those States in which primacy was not

achieved, a Federal program was to have

been implemented and administered by OSM.

Three and one-half years after enactment of

the statute, all mining operations were to

have been in compliance with permits issued

in accordance with the full range of regulatory requirements, as administered by

either the States or OSM.

Litigation brought in the District Court for

the District of Columbia by several of the

major coal companies and trade associations,

as well as by several States, has resulted in

significant changes to this schedule. The

result of these changes has shifted the latest

date for transfer of primacy or implementation of a Federal program from June 3, 1980

to January 3, 1981, and on-the-ground compliance from February 3, 1980 to September

3, 1981. Litigation pending in eight States

(Pennsylvania, Virginia, Ohio, Tennessee,

Kentucky, Alabama, Indiana, and Illinois) enjoining implementation of a Federal program

in those States that did not gain primacy according to the schedule, has further delayed

the implementation schedule. Although the

full surface mining regulatory program was

to have gone into effect on Federal lands 1

year after enactment of the statute (i.e., Aug.

3, 1978), the Secretary of the Interior, exercising his discretion, shifted the effective

date of the permanent program requirements

to coincide with the date on which primacy is

transferred to a State or a Federal regulatory

program is implemented for the State (Jan. 3,

1981).

Several other environmental statutes also

affect the manner and method of mining coal

on Federal leases. The most significant of

these are the Clean Air Act and the Clean

Water Act. Others, such as the Endangered

Species Act of 1973, Bald Eagle Protection

Act of 1969, as amended, Migratory Bird

Treaty Act of 1918, as amended, the National

Forest Management Act of 1976, and the National Historic Preservation Act of 1966, as

amended, may act to prevent mining in certain locations at the mine plan approval

stage. These acts are discussed separately

later in this chapter. The DOI, in implementing the coal leasing process in accordance

with the Federal Lands Policy and Management Act of 1976, has applied most of these

statutory requirements to the process of

selecting tracts for leasing during the land

planning process, i.e., at the earliest stage in

the lease development process. Because of

the preliminary nature of the data available

at this early point in the development process,

decisions on certain criteria cannot be made

concerning the suitability of a given tract for

leasing, and these decisions are considered in

the actual mine plan approval process.

In the West, because much of the coal

reserve underlies Federal lands, OSM has

had direct responsibility not only for enforcing the act’s regulatory requirements, but

also for issuing operating permits on specific
Ch. 10—lmplications of Environmental and Reclamation Issues for the Development of Federal Coal . 281

mines. The responsibility for overseeing mining activities on Federal lands is shared by

the U.S. Geological Survey (USGS), the Bureau of Land Management (BLM), and the

U.S. Forest Service as well as with those

Western States with Federal lands within

their boundaries that have gained regulatory

primacy and have signed cooperative agreements with DOI. USGS has jurisdiction over

exploration on Federal lands outside mine

permit areas, as well as responsibility for

resource conservation, diligence, and royalties under the Mineral Leasing Act as discussed in greater detail in chapter 9 of this

report, BLM is the leading agency for Federal

minerals and, under a variety of Federal statutes, is responsible for the management and

protection of surface resources on Federal

lands. BLM can set postmining land use performance bond limits to assure protection of

these resources. The Forest Service performs

a similar role for National Forest System

lands. Thus, USGS, BLM, and the Forest Service, together with OSM, submit recommendations to the Secretary of the Interior concerning the approval or disapproval of mine

plan applications. The U.S. Department of

Agriculture, acting through the U.S. Forest

Service, must concur in the issuance of mine

plan approvals for mines within the boundaries of any national forest. Applicable Federal, State, and local agencies retain similar

authority with respect to mines that might

adversely affect any public park or site included in the National Register of Historic

Sites.

Each of the Western States with significant

coal reserves had enacted surface mining legislation in the 1970’s prior to passage of the

Surface Mining Act. The stringency of the

State programs varied significantly, with

Wyoming and Montana generally recognized

as having had the most stringent programs,

and Utah and New Mexico the least stringent.

All of the Western States have received approval of their permanent regulatory programs and have qualified for assumption

of primary regulatory jurisdiction under

SMCRA. Thus, the States have assumed primary responsibility for mine plan compliance

and enforcement with the act’s requirements.

Those States with approved permanent plans

that have entered into a cooperative agreement with the Secretary of the Interior acquire the authority to regulate mining on Federal lands within their boundaries. The Secretary of the Interior, however, retains the

authority to approve or disapprove mining

plans on Federal lands and to designate Federal lands unsuitable for mining.

The OSM regulatory program is in the

process of undergoing changes. Secretary of

the Interior James Watt has ordered major

organizational and staff revisions for OSM.

Proposed budgetary cuts for fiscal year 1982

decrease funding for oversight inspections of

mines. Extensive review of existing regulations is expected to result in a significant

decrease in the extent of current regulations

and is expected to increase the use of guidance documents and handbooks to clarify

SMCRA. Reliance on State enforcement programs is expected to increase significantly. In

announcing a plan to reorganize the number

of OSM offices outside of Washington, Secretary Watt said:

As the States move closer to achieving primary responsibility for enforcing the Surface

Mining Control and Reclamation Act of 1977,

the role of the Office of Surface Mining is

shifting to one of assistance, advice and review of state efforts to assure that the environmental protection standards of the Act

are met. 3

The reorganization plan and regulatory review has been critized by conservation and

some agricultural groups and supported by

the coal industry, The ultimate effect of these

changes in the OSM regulatory program is

uncertain at this time,

Selected Environmental Issue Areas

and Their Relationship to the

Development of Federal Coal

The following sections discuss several environmental issue areas: air resources,

‘U.S. Department of the Interior Press Release, May 21,

1981.
282 An Assessment of Development and Production Potential of Federal Coal Leases

water resources, alluvial valley floors, topsoil concerns, and discusses the likely effect of

and spoil handling, revegetation, wildlife, and these concerns on coal production. Emphasis

cultural resources, and analyze how the en- is placed on limitations to recovery of coal

forcement of statutory controls may affect reserves or on the rate of recovery. The genthe production of Federal coal. Each section eral effect of environmental controls on minreviews the specific statutes important to ing costs is considered in the last section of

that issue area, outlines the environmental this chapter.

Air Resources

Laws and regulations protecting air quality affect coal mining activities in three ways.

First, mines must comply with national air

standards as established by the Clean Air Act

and various State implementation programs.

Second, undeveloped leaseblocks whose development is contingent on mine-mouth*

power generation or synthetic fuels development are affected if those facilities cannot

comply with applicable local air quality

standards. Lastly, changes in requirements

for controlling sulfur emissions at powerplants in the market area for Western coal

may affect the competitive cost advantages of

low sulfur Western coal.** Issues related to

direct emissions from mining activities are

focused on fugitive dust and its effect on total

suspended particulate (TSP). No other emission from coal mines is important to national

or State air standards. Standards for sulfur

dioxide (S02

) and nitrogen dioxide (NO2), as

well as for TSP affect emissions from powerplants or synthetic fuel plants.

To date, air quality concerns related to

direct mine emissions have had only a minor

effect on Western coal mine development. In

portions of the Powder River coal basin, fugitive dust emissions have exceeded or are

nearing national ambient air standards, and

mining activities in these areas may have to

adopt better dust control measures. However, the level of production in this region is

not expected to be constrained by air standards.

*Mine-mouth powerplant is a term that refers toa coal-fired

electrical generating facility located at or near the supplying

coal mine.

**This issue is examined in ch. 5.

Some mine-mouth powerplants may experience difficulty in receiving permits because

of their inability to meet air quality regulations. Expanded development of some Federal

mines in North Dakota may be delayed because of the projected impacts of new powerplants and synfuels projects on the pristine

air of the Theodore Roosevelt National Memorial Park, a Class I clean air area. Similarly, powerplants or synthetic fuel plants

may have difficulty meeting air standards in

parts of the Powder River basin and in southern Utah. In some cases, notably in North

Dakota, the quality of the coal that would fire

the mine-mouth plants is too low to transport

any distance. Thus, failure to gain air permits

for major facilities could preclude development of some coal reserves. However, a final

decision on permitting the proposed facilities

in North Dakota has not yet been made.

The potential impact of changes in national

sulfur emission standards on the development

of Western coal is discussed in chapter 5,

Markets. Generally, the requirement to control emissions regardless of the sulfur content of the coal decreases the competitiveness of low sulfur Western coal in market

areas where local high sulfur coal is also

available.

Statutory Control

Surface Mining Control and

Reclamation Act

SMCRA requires that an operator: “stabilize and protect all surface areas including

spoil piles affected by the surface coal mining
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal ● 283

and reclamation operation to effectively control erosion and attendant air . . . pollution”

(sec. 515(b)(4)). Regulations adopted by OSM

pursuant to this section required that an operator “plan and employ dust control measures as an integral part of site preparation,

coal mining, and reclamation operations” (30

CFR 816.95(a) and 817.95(a)). These regulations listed 19 different control measures that

might be employed by an operator to achieve

the best available control of fugitive dust.

However, these regulations were remanded

to OSM by the decision of Judge Flannery of

the district court of the District of Columbia.4

The regulations, as promulgated, were said to

be too encompassing and beyond statutory

mandate. OSM has not proposed a revision of

these performance standards and at this time

is deferring to State regulatory agencies decisions about coal mine fugitive dust emissions.

No date is available for reissuance of these

OSM regulations.

Subsequent to this decision, each Western

State except Montana remanded its State regulations that had mirrored the Federal regulations (30 CFR 816.95, 817.95). In each of

these States, air resource issues are being

handled by the State agency responsible for

State implementation of the Clean Air Act

Amendments and not by the mine reclamation

agency. In Montana, coal mine related air

resource issues are being handled jointly by

the State reclamation agency and the State

air quality agency. Even in Montana, where

surface mine regulations are the strictest in

the West, the standards of the Clean Air Act

still take precedence. Thus, State implementation and enforcement of the Clean Air Act

is the foundation of regulation of air impacts

of coal mining.

Clean Air Act

The Clean Air Act establishes a national

system of air quality regulation. Regulations

and standards under this act are implemented at the Federal level by EPA and at

State levels in conjunction with additional

4

In re Surface Mining Litigation, civil action No. 79-1144

(District of Columbia).

regulations and standards imposed by individual States. The following discussion highlights provisions of the act of significance to

coal mining. Brief mention is also made of

provisions of importance to mine-mouth

facilities.

National Ambient Air Quality Standards

(NAAQS) 5

Regulation under the act focuses on six criteria pollutants: particulate, sulfur dioxide

(S02

), carbon monoxide (CO), nitrogen oxides

(NOX

), ozone (O3), and lead. Two types of ambient air quality standards are designated:

primary standards, which were designed to

protect human health; and secondary standards, which were designed to safeguard

aspects of public welfare, including plant and

animal life, visibility, and buildings. The Nation is divided into 247 air quality control

regions (AQCRs) so that pollution control programs can be locally managed. Each AQCR is

classified as to whether it meets the national

standards.

The classification of an area with respect

to ambient air quality has important consequences. Regions that are found by EPA to be

in nonattainment status are subject to a particular set of restrictions under the act. On

the other hand, nondegradation regions,

where air is cleaner than the standards, are

subject to a different set of regulations,

which are intended for “prevention of significant deterioration” (PSD). Regardless of an

area’s classification, almost every new major

source of emissions is required to undergo a

preconstruction review. (A major source of

emission is defined for PSD purpose at 40

CFR 52.2.l(b)(l)(i).)

To achieve air quality goals, areas with air

cleaner than NAAQS were divided into

classes I, II, and III. Certain national parks,

5

The following discussion draws heavily from An Assessment of 011 Shale Technologies, OTA-M-1 18, June 1980, See

also Final Rules on Requirement for State Implementation PJans

for Prevention of Significant Deterioration, 45 F.R. 52676, Aug.

7, 1980. The rules implement major changes in Clean Air Act

regulations required by the decision in Alabama Power Co. v.

Costle, 13 E.R.C. 1225 (D.C. Cir. 1979]; 13 E.R.C. 1993 (D.C. Cir.

1979).
284 ● An Assessment of Development and Production Potential of Federal Coal Leases

wilderness areas, and monuments that existed when the act was passed were immediately designated as class I areas where air

quality is to remain virtually unchanged. All

other clean air areas were designated class

II—areas in which some additional air pollution and moderate industrial growth were

allowed. Individual States or Indian Tribal

governing bodies can redesignate some class

II areas to class III areas in which major industrial development is foreseen and air

pollution up to one-half the level of the secondary standards would be permitted. The

States or Indian Tribes can also redesignate

class II areas as class 1. Either type of redesignation is subject to hearings and consultations with the managers of affected Federal

lands, or States in the case of Indian action.

State Implementation Plan (SIP)

Each State must submit an implementation

plan for complying with primary and secondary standards. A State can decide how much

to reduce existing pollution to allow for new

industry and development. State plans must

also include an enforceable permit program

for regulating construction or operation of

any new major stationary source in nonattainment areas, or significant modification to

an existing facility. New processing plants

and power stations must also satisfy emission

standards set forth in the State implementation plan.

Each of the Western States has adopted its

own ambient air quality standards (table 83).

For particulate, Colorado has the strictest

standards. For sulfur, important for powerplant emissions, Montana, North Dakota, and

New Mexico have the strictest standards.

The Prevention of Significant Deterioration

All SIPS must specify emission limitations

and other standards to prevent significant air

quality deterioration in each region that has

air quality better than primary or secondary

NAAQS or cannot be classified with regard to

compliance with primary standards because

of insufficient information.

Under these PSD standards, maximum allowable increases in concentration of S 02

and particulate are specified for each class

(table 84). For the other criteria pollutants, maximum allowable concentrations for

a specified period of exposure must not exceed the respective primary or secondary

NAAQS, whichever is stricter.

A State can redesignate a class I or II clean

air area with respect to PSD to allow greater

increases in emissions under procedures set

Table 83.—Federal and State Ambient Air Quality Standards Pertinent to Coal Mine

and Related Facility Development

Concentration in micrograms per cubic meter

Federal Federal

Pollutant (primary) (secondary) Colorado Montana New Mexico North Dakota Utah Wyoming

Particulate:

Annual geometric mean . 75

24-hr maximum . . . . . . . . 260

NOX (as NO,)

Annual arithmetic mean. 100

— 80 53.3

— 365 267

1,300 700 1,334

(1 hr

standard)

60 45 75

150 150 200

100 100 100

600

(3 hr

standard)

53

267

—

60

150

100

200

(24 hr

standard)

75 60

1% 260 150

100 100 100

200

(1 hr

standard)

a Standards for oxidants, CO, lead, and nonmethane hydrocarbons omitted.

SOURCE: Off Ice of Technology Assessment.
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal . 285

Table 84.—National Standards for Prevention of

Significant Deterioration of Ambient Air Quality

(concentration in micrograms per cubic meter, μg/m3)

Maximum allowable increase

Averaging time Class I Class II Class Ill

SOURCE Office of Technology Assessment.

forth in the act. These include an assessment

of the impacts of the redesignation, public

notice and hearings on such a redesignation,

and approval by EPA. However, certain Federal areas cannot be redesignated.

If a facility’s construction began after

January 1, 1975, a special preconstruction

review must be undertaken if it is located in a

nondegradation area. To obtain a permit for

such a facility, an applicant must demonstrate that it will not cause air pollution in excess of NAAQS or PSD standards more than

once per year in any AQCR. Best available

control technology (BACT) must be used for

all pollutants regulated by the act, and the effects of the emissions from the facility on the

ambient air quality in the areas of interest

must be predicted. Impacts on air quality that

could result from any growth associated with

the facility must also be analyzed.

Although coal mines are not subject to PSD

review under Federal regulation, State PSD

permits are required for most coal mines in

North Dakota and Montana. Under proposed

State rules, PSD permits for coal mines in

Wyoming may be required, but final administrative action has not yet been taken.

Implications of the Clean Air Act for

Federal Coal Development

Fugitive dust emissions are the only type of

coal mine emission that has the potential for

violating national or State ambient air quality

standards. Annual mean TSP concentrations

have exceeded standards at Colstrip, Mont.

in 5 of the last 6 years. Prior to 1974, the

primary standard was not exceeded. In 1977,

when the annual mean concentration for TSP

at Colstrip was 92μg/ms, the next highest concentration was 48.1μg/ms, at Ekalaka in eastern Montana, A 120-mi 2 area surrounding

Colstrip was designated as a nonattainment

area in 1978 (fig. 44). Surface mining activities surrounding the town are considered

the primary source of fugitive dust.

Ambient air quality standards have not yet

been violated at Gillette, Wyo. However, the

Wyoming standard for maximum 24-hour

TSP concentration is reportedly being exceeded at some mines.6

Roads are the major source of fugitive dust

from surface coal mining operations and generally are responsible for twice as many

emissions as the next most important source.

Other sources of fugitive dust include unit

trains, coal storage and processing facilities,

spoil piles, and reclamation areas. Options

‘Personal communication with the Wyoming Department of

Air Quality, Sheridan Office.

Figure 44.—Colstrip TSP Nonattainment Area

R. 40 E I fi R. 41 E I R.42E

N

t

Ii

a I T. 2 N.

i

~Burlington

Northern

SOURCE: U.S. Geological Survey and Montana Department of State Lands,

Draft Environmental Statement for Proposed Expansion of Mining

and Reclamation Plan, Big Sky Mine, 1978, fig, 11-11
286 An Assessment of Development and Production Potential of Federal Coal Leases

for controlling fugitive dust emissions include:

I. periodic watering of unpaved roads;

2. chemical stabilization of unpaved roads;

3. paving of roads;

4. enclosing, covering, watering, or otherwise treating haul trucks and railroad

cars;

5. substituting conveyor systems for haul

trucks;

6. minimizing the area of disturbed land;

7. prompt revegetation of regraded lands;

and

8. covering coal storage areas.

Some of these options are employed at each

surface mine in the West. Most mines in

Campbell County, Wyo. pave their haul

roads. Closed conveyor systems replace truck

haulage at Gulf’s McKinley Mine near Gallup,

N. Mex., and at AMAX Coal’s Belle Ayr Mine

south of Gillette. All mines water haul roads

and revegetate topsoil stockpiles. Many

mines now enclose their coal storage areas.

Operations in Nonattainment Areas

The Colstrip, Mont. area has been designated a nonattainment area for TSP. In December 1979, Western Energy filed a petition

against the nonattainment designation with

the Montana Department of Health and Environmental Sciences and EPA. Monitoring

data indicate that the TSP problem exists

only in the immediate vicinity of Colstrip and

not in the entire 120-mi2 area. However, no

redesignation has yet been made. T Criteria for

approval of new facilities in nonattainment

areas are subject to careful regulatory review.

Sources of fugitive dust, most notably Western Energy’s Rosebud Mine, must develop

plans to limit emissions so that TSP concentrations will eventually meet standards. Also,

no new facilities may be approved unless it

can be shown that the new facility will not

add to emissions in the area.

7Montana Department of State Lands, Final Environmental

Impact Statement, Western Energy Company’s Rosebud Mine,

Area B Extension, 1980.

Western Energy has initiated measures to

reduce emissions, including seeding of lawns

in the town, paving of some roads, and chemical treatment of some haul roads. However,

construction of two new powerplants in the

town makes future compliance with TSP

standards uncertain. As long as neither

Peabody Coal, which operates the Big Sky

Mine, also in the nonattainment area, nor

Western Energy proposes increasing their

current capacities, their future applications

for extending their mines will probably not be

affected. However, increasing capacities and

construction of new facilities cannot be approved under SIP unless Western Energy can

demonstrate reduction of other emissions

such that emissions from expanded production will not increase total area emissions,

Because Western Energy plans on extending

capacity by 5 million tons per year in 1984,

the company will have to either achieve other

emission reductions by that time or gain a

favorable decision on redesignation of the

nonattainment area.

Operations in the Wyoming Portion of

the Powder River Coal Basin

As noted, TSP levels in portions of the

Powder River coal basin in Wyoming are approaching the limits set by State ambient

standards. Already, mines are installing controls, including paving of many roads. However, the magnitude and concentration of

mines make compliance difficult (fig. 45). In

particular, north of Gillette, where the Buckskin, Rawhide, and Eagle Butte Mines are adjacent to one another, as well as to the undeveloped South Rawhide, Dry Fork, and East

Gillette leaseholds, compliance with TSP

standards at higher than existing production

rates is of increasing concern. South of

Gillette, the Caballo, Belle Ayr, Rojo Caballos,

and Cordero Mines are adjacent to one

another. Total 1979 production at these four

mines was 20.1 million tons, but may expand

to about 30 million tons in 1985 (see ch. 7).

Although modeling of TSP concentrations

has indicated compliance with standards at

permitted production levels, OSM and Wyo-
Ch. 10—implications of Environment/ and Reclamation Issues for the Development of Federal Coal ● 287

Figure 45.— Lease Blocks in the Vicinity of

Gillette, Wyo.

105 037’30”

44 “30’

44 000’

43°30’

lckskin

4

North Rawhide *I

=3i Eagle Butte

1

d

Fort Union 31 3

.

r

I

South Rawhide ~ ~

(proposed) -g

% !G ~Eaet Giliette

@ropoeed) “ !

I

- Belie Aw .

0

105 037’30” 105 0

00’

SOURCE’ U S. Office of Surface Mining, Draft Environmental Statement Proposed Mining and Reclaimation Plan, RO jO Caballos Mine, 1980,

fig. 1-1.

ming Air Quality officials have expressed

uncertainty about the accuracy of these

modelling projections. 8 Expansion of mining

at the Jacobs Ranch and Black Thunder

Mines in southern Campbell County may increase local TSP concentrations in that area,

as well.

‘Personal communication to OTA, Wyoming Air Quality

Bureau Staff, Sheridan.

If air quality standards are not met, portions of Campbell County could be designated

nonattainment areas, despite prior issuance

of air quality permits. Such designation

would require development of mitigation programs and reevaluation of each operation’s

fugitive dust control plan. Although production rates would probably not be affected, additional control measures might be required.

Some new mines in Campbell County have

not obtained approval of their proposed maximum production rate. For example, the Black

Thunder Mine received a permit for a maximum production level of 20.5 million tons per

year although it applied for a 30 million tons

per year maximum rate. Modeling had indicated that production greater than 20.5 million tons per year would have resulted in

emissions exceeding TSP standards. Black

Thunder’s planned production for 1991 is

20.5 million tons per year; it currently has to

supply contracts 16.5 million tons per year in

1991. (See ch. 7.)

To date, Wyoming has issued permits for

existing and proposed mines in Campbell and

Converse counties that could accommodate

over 250 million tons per year (table 85), This

is three times total production from the entire

Powder River basin in 1979 and is higher

than OTA’s high scenario estimate for coal

production from all Federal mines in the entire Powder River basin, including the Montana portion, in 1991. Only three undeveloped

Federal lease blocks in these two counties

considered by OTA to have favorable production prospects for 1991 have not yet gained

air permits (table 85). Each of these leases is

expected to receive a permit for some level of

production. Six Federal lease blocks have air

permits in excess of their expected 1991 capacity and three lease blocks will have 1991

capacities in excess of air permits (table 85).

Under OTA’s low demand scenario for the

Powder River basin, only the Rochelle and

Antelope lease blocks would need to acquire

air permits to meet projected production

levels. Permits are expected to be issued for

both lease blocks. Under OTA’s high demand

scenario, the Buckskin, North Rochelle, South
288 . An Assessment of Development and Production Potential of Federal Coal Leases

Table 85.—Air Permits and Production Scenarios for Mines in Campbell and

Converse Counties, Powder River Basin, Wyo.

1991 OTA 1991 OTA

high demand low demand

Approved 1991 scenario

Mine

scenario

air permit capacity production production

Developed-Federal

Buckskin . . . . . . . . . . . . . . . . . . . . . . . . . 6

Rawhide . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Eagle Butte . . . . . . . . . . . . . . . . . . . . . . . 29

Wyodak . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Caballo . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Belle Ayr. . . . . . . . . . . . . . . . . . . . . . . . . . 25

Rojo Caballos . . . . . . . . . . . . . . . . . . . . . 20

Cordero . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Coal Creek . . . . . . . . . . . . . . . . . . . . . . . . 18

Jacobs Ranch . . . . . . . . . . . . . . . . . . . . . 16

Black Thunder. . . . . . . . . . . . . . . . . . . . . 20.5

Dave Johnston. . . . . . . . . . . . . . . . . . . . . a

Developed—non-Federal

Fort Union . . . . . . . . . . . . . . . . . . . . . . . . 1.2

Clovis Polnt . . . . . . . . . . . . . . . . . . . . . . . 4.0

Undeveloped-favorable

development prospects

Federal

North Rochelle . . . . . . . . . . . . . . . . . . . . —

Wildcat . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

South Rawhide . . . . . . . . . . . . . . . . . . . . 7

Dry Fork . . . . . . . . . . . . . . . . . . . . . . . . . . 15

East Gillette . . . . . . . . . . . . . . . . . . . . . . . 11

Rochelle . . . . . . . . . . . . . . . . . . . . . . . . . . —

North Antelope . . . . . . . . . . . . . . . . . . . . 5

Antelope . . . . . . . . . . . . . . . . . . . . . . . . . . 12b

6.2

24

25

5

12

11

15

24

12

16

20.5

3.8

0

5.0

6.2 5.5

30.7 14.2

35.2 29.2

4.9 4.0

included in Rawhide

estimates

included in Eagle

Butte estimates

12.5 5.0

20.5 9.7

10.1 4.2

15.3 11.7

19.4 14.6

3.8 3.3

— —

— —

0

0

0

0

0

5.3

4.4

7

a Air Quality permit is not required for this mine.

b Application under review.

SOURCE: Office of Technology Assessment. (Values for approved air permits are from the Wyoming Air Quality Bureau

records. See ch. 7 of this report for mine capacities and a discussion of the OTA high and Iow demand scenarios)

Rawhide, Rochelle and Antelope blocks ar e

expected to need air permits to accommodate

higher production; between them, Buckskin

and South Rawhide would need permits for

2.0 million tons per year of additional production under the OTA high demand scenario.

Permits for capacities in excess of the expected capacity of 22 million tons per year at

North Rochelle, Rochelle, and Antelope are

expected to be issued.

implications for Onsite Powerplants

and Synfuels Facilities

Lignite in North Dakota will be mined for

consumption by local powerplants or synthetic fuel plants. Because of its low heat content and tendency to combust during transport, lignite is, with one exception, not

shipped long distances. Future expansion of

lignite mining in North Dakota is contingent

on continued development of mine-mouth

powerplants and synthetic fuel plants.

However, the prevention of significant deterioration (PSD) provisions of the Clean Air

Act may delay or limit the future development

of new power or synthetic fuels facilities i n

western North Dakota. Although there are no

nonattainment areas in the State, the Lostwood Wilderness Area and the Theodore

Roosevelt National Memorial Park are mandatory Federal class I areas.

Air quality monitoring and modeling conducted by the North Dakota State Department of Health suggests that available air

quality increments of S 02 at Theodor e

Roosevelt National Park may be exceeded if

additional powerplants or synfuels facilities

are permitted in west-central North Dakota.

In 1978, using a model developed by EPA, the

Department of Health obtained results that
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal . 289

indicated that the operation of seven coal

conversion units under review at that time

would result in S02 concentrations that would

exceed allowable standards for the national

park.

These permit applications included United

Power Association’s Coal Creek units 1 and 2,

Montana Dakota Utilities’ Coyote No. 1 facility, Great Plains Gasification Associates’ coal

gasification plants, phase I and II, and Basin

Electric’s Antelope Valley Station units 1 and

2 (fig. 46). Because Basin Electric was the last

organization to file a building permit application, the company had to redesign its plants to

reduce S02 emissions. Basin Electric resubmitted its application and was subsequently

granted permission to build. According to the

model, the Basin Electric project left no room

for additional concentrations of S02 at the

park.

Based on the results of their modeling, the

North Dakota State Department of Health has

not granted any additional permits, beyond

the seven listed above, for construction of

new coal conversion facilities east of the

park. Although powerplant operators have

maintained that the EPA model used to estimate remaining SO2 increments at Theodore

Figure 46.—Relationship of Recently Permitted (1979) Sources to the Theodore Roosevelt National Park

(wind flow vectors indicated)

, - -

.

I

1

.

SOURCE: U.S Bureau of Land Management, Final West-Central North Dakota Regional Environmental Impact Statement on Energy Development, 1978.
290 . An Assessment of Development and Production Potential of Federal Coal Leases

Roosevelt National Park is not reliable

beyond distances of 50 to 70 kilometers, no alternative modeling data has yet been found

acceptable by the State. Most of the development in Mercer and Oliver Counties is taking

place more than 150 kilometers from the

park. Work on improving modeling techniques is currently underway at the North

Dakota Department of Health.

The coal industry must also compete with

expansion of oil and gas production for air

quality increments. Because North Dakota’s

Western oil and natural gas resource areas

overlap the Fort Union lignite region, gas

extraction and refining facilities located near

Theodore Roosevelt National Park would

compete directly with coal development for

any available sulfur dioxide increments. In

general, oil and natural gas production

would not involve major air quality considerations; however, much of the gas in this

area is sour (i.e., contains up to 24 percent

hydrogen sulfide) and presents potential air

quality problems when flared or treated in

sweetening plants. If additional class I increments at Theodore Roosevelt National Park

become available, some could be assigned to

the expansion of the natural gas industry.

At some point, additional lignite development may be dependent on the ability of lignite consumers to design and site facilities

that do not affect the air quality of class I

areas. If increments remain unavailable, potential developers of new coal conversion

facilities will have two choices—either obtain

offsets from existing facilities or obtain Government-issued variances. The first of these

two options is unlikely to be successful.

Most of the existing and permitted facilities

are new and thus have already been fitted

with advanced sulfur dioxide control techniques. In the case of the second alternative,

the State so far has appeared unwilling to exercise its authority allowing waiver of PSD

requirements under certain circumstances to

permit degradation of the air quality of

Theodore Roosevelt National Park. Proposed facilities affected by the situation are

listed in table 86, However, the situation reTable 86.—North Dakota Department of Health

Pending Air Emissions Permits

Company Operation Type Capacity

Nakota

Basin Electric

Basin Electric

Warren

Petroleum

AMOCO

Minnesota

Power & Light

Unnamed Coal to

methanol 96,000 bbl/d

AVS Ill Powerplant 500 MW

Sunrise Powerplant 1,000 MW

Sour gas

treatment 30 MCF/d

Sour gas

treatment 100 MCF/d

Powerplant 1,000 MW

SOURCE: Office of Technology Assessment.

mains unresolved. Considerable uncertainty

stems from the fact that five permitted facilities have not yet been built and therefore

their effect on air quality can only be

estimated.

In Wyoming, class I designations and State

sulfur standards may also affect onsite facilities construction. Class I areas have been

proposed both for the Cloud Peak Primitive

Area in the Bighorn Mountains west of the

Wyoming portion of the Powder River basin

and for Devils Tower to the east. State governments and Tribal governing bodies are

solely responsible for making such a redesignation determination. Air quality considerations may constrain the eventual level of synfuels development in the Powder River basin

and southern Wyoming, but probably not during the next 10 years. However, Wyoming’s

sulfur dioxide emission standard, which is

more stringent than the national standard

(table 83) could create difficulties for onsite

development of coal reserves with high levels

of sulfur. Two undeveloped Federal lease

tracts (the Belco tract in the western Powder

River basin and the Cherokee tract in southern Wyoming) that have reserves sufficient to

supply a power or synfuels plant would require more than 95 percent sulfur reduction

to meet the State standard. * Sulfur removal

efficiencies exceeding 95 percent could be

achieved, but would be expensive.

*The Belco tract is expected to be traded for other Federal

coal lands under provisions of Public Law 95-554.
Ch. 10—lmplications of Environmental and Reclamation Issues for the Development of Federal Coal 291

Air Quality Issues and the SMCRA

Unsuitability Petition Process

Under the SMCRA unsuitability petition

process, areas may be designated unsuitable

for coal mining if it can be shown that mining operations will “affect fragile . . . lands

with significant damage to important. . .

aesthetic values or natural systems” (30

CFR 762.11(b)(2)). In the Alton coalfield of

southern Utah, an area including 28 undeveloped Federal leases covering 26,693 acres

(fig. 47), several petitioners, including local

landowners and three national conservation

groups, alleged, among other things, that

the visibility and air quality values from and

within Bryce Canyon National Park would

be threatened by coal mining. (The park is a

mandatory class I attainment area under the

Clean Air Act. ) The OSM’s analysis of these

allegations used PSD standards as an evaluative benchmark. 9 OSM found that 24-hour

PSD class I increments could be exceeded

one or two times a year in a small portion of

the park. OSM also found that visibility

would be locally reduced by dust plumes

from mining and coal trucks. There was conflicting data from other sources that PSD increments would not be exceeded. The final

decision by the Secretary of the Interior to

designate 9,049 Federal lease acres of the

proposed petition area as unsuitable was

based on the finding that mining in part of

the area would impair scenic vistas visible

from the park and that high noise levels

would occur in some areas within the park,

thus damaging the values for which the park

was established.

“See U.S. Department of the Interior, Statement of Reasons

Supporting Secretarial Decision on Petition to Designate Certain Federal Lands in Southern Utah Unsuitable for Surface

Coal Mining operation, Jan. 13, 1981, OSM ref. No, 79-5-001,

pp. 13-14.
292 “ An Assessment of Development and Production Potential of Federal Coal Leases

Figure 47.—Map of Southern Utah Petition Area Showing Federal and State Coal Leases,

Coal-Slurry Pipeline Route, and Proposed Coal Haul Railroad Routes

113° 112 “

36”

32

T.

33

s.

34

35

36

37

36

39

40

41

42

T.

43

s.

37“

T,

41

N.

40

T.

39

N.

Provo

UTAH Price

Milford

/’

Dixie National Forest

f

Index map showing location of the petition area

J

d

!Ea*il%?&#aw .

A

. . .

a

Known recoverable coal

E

resource area (KRCRA)

Known recoverable coai

resource area (KRCRA)

Boundary of

Petition area

I ~

Area east of dashed ilne inL –n - / w \ dlcates portion designated

unsuitable for mlnln~

\

\

#“ I Kanab

Coal leases

Existing leases on Federal lands

Preference right lease application

(PRLA) on Federal lands

Existing leases on State lands

Coal slurry line, Nevada Electric

Investment Co., et al., to Warner

Valley and Harry Allen generating

stations

Proposed Union Pacific Railroad i

Milford, Utah

m Forest

Dixie National PR4 f%oposed Union Pacific Railroad 1

Cedar City, Utah

R. 6 W. 5 4 3 2 R. 1 W. R. 1 E. 2 3 4 R. 5

0

~“‘i’e s

SOURCE: U.S. Office of Surface Mining, Southern Utah Petition Eva/uat/orr Document, 19S0, fig. 1A-1.
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal . 293

Water Resources

Water is a scarce and valuable commodity

in the West and concern for the water resource is indicated in detailed Federal and

State regulations. Ground and surface water

hydrology data required of proposed coal

mine operators is more extensive than any

other type of data.

Several aspects of the water resource

issue could affect Federal coal development.

However, none has yet resulted in disapproval of a mine plan. Potential for selected

prohibitions exists in cases where water supply diminution or degradation becomes unavoidable, and alternative supplies cannot be

identified. Conflicts with other water users

exist in virtually every coal region; this study

has not attempted to analyze these conflicts

in any detail.

Water resource concerns could result in

the prohibition of mining in some areas

under the unsuitability petition process.

These concerns were part of the Alton coalfield petition but were not critical to the final

secretarial decision, because insufficient information was available on which to make a

determination. The decision noted that the

hydrological impacts of proposed mining

operations would be reviewed when a mine

plan was submitted for approval under

SMCRA.

10 Water resource concerns are central to a recently filed petition for a part of

the Tongue River drainage basin in southeastern Montana (see also ch. 9).

The availability of water for use by mines,

particularly where irrigation is necessary for

reclamation in the Green River-Hams Fork

and San Juan River regions may ultimately

constrain coal development. However, OTA

did not identify any areas where such a constraint was imminent.

10 Ibid, The Alton lessees submitted a mine plan for the Project before SMCRA regulations were implemented. The mine

plan has not been updated to incorporate additional surface

mining permit requirements.

The extent of regulatory control over

water resource issues has been the subject of

criticism from the coal mining industry.

These criticisms are identified and summarized in this section; however, a detailed

study of increased costs and time delays attributed to these regulations is beyond the

scope of this report.

General Impact of Coal Mining on

Water Resources

Coal mining activities affect water both

directly through disturbance by mining,

indirectly through powerplant facility development, and potentially through transportation by coal slurry pipelines. Primary attention has centered on the direct impact of

surface mining, particularly on disruption of

ground water flow and quality. Recently, research has begun on the impacts of underground mining and related subsidence on

water resources.

The opening of a pit for surface mining

affects the level and flow of ground waters.

The mine pit will intercept all ground waters

that are found above the pit floor. Directions

of ground water movement may change and

even reverse as water surrounding the pit in

all directions flows toward the pit. As water

flows into the pit, water levels in surrounding areas, as evidenced in wells, will fall. Ultimately, an equilibrium condition is established based on the characteristics of the

water-transmitting rocks (aquifers) and the

length of time the pits are open. Monitoring

studies have measured the offsite extent of

drawdown, as the lowering of the ground

water level is termed, 2 miles from an active

pit.11

Water quality can also be affected.

Ground water moving through backfilled

11Van Voast and Hedges, Hydrologic Aspects of Existing and

Proposed Strip Coal Mines Near Decker, Southeastern Montana: Montana Bureau of Mines and Geology Bulletin 97.1975.
294 ● An Assessment of Development and Production Potential of Federal Coal Leases

surface mines is known to have substantially

increased concentrations of total dissolved

solids and other constituents. Generally, the

average concentration of dissolved solids is

two to three times greater in spoil waters

than in the waters in undisturbed coal

aquifers.

The overall potential changes are such

that Congress, OSM, and the various States

have developed comprehensive requirements

for the prediction and monitoring of ground

water impacts from surface mines.

Impacts of sedimentation and pollution on

surface waters are more easily understood

and monitored. The primary impact, increased sediment loads in streams caused by

erosion of mine and reclamation areas, can

effectively be controlled by construction of

sedimentation ponds at drainage outlets

from mines. Surface waters can also be affected by seepage of polluted ground waters

into receiving streams. Although not observed to date, this possibility is the basis of

the Northern Plains Resource Council unsuitability petititon for the Tongue River

area. The petition is partly based on a published modeling study predicting this

impact .

Subsidence from underground coal mining

has been documented to impact water resources and the subject is receiving increasing study. Subsidence cracks have caused interception of spring flow, ground water flow,

and stream flow at locations in the UintaSouthwestern Utah coal region. 13 Since subsidence is an expected aspect of all underground mining, regulatory concern over

associated environmental impacts is growing. Subsidence monitoring has been required at several underground mines as a

condition of permit approval.

12Woessner, Osborne, Heffern, Whitman. Spotted Elk, and

Morales-Brink, Hydro~ogic lrnpacts from Potentiul COOI Sfrip

Mining, Northern Cheyenne Reservation. report 10 the EPA Industrial Environmental Research L[iboratory, Cincinnati, Ohio,

1980.

13‘Dunrud, Some Engineering Geologic Factors (lmtroliing

(lx]] Mine Subsidence in U(ah und (ldormh), USGS Professional

Paper 969, 1976.

Powerplants and synthetic fuel plants are

affected by Clean Water Act provisions relating to discharge limitations. Effluent

standards are not a significant impediment

to construction of these facilities, however.

The availability of water and restrictions on

water usage under interstate water use compacts and State law have affected the construction of coal slurry pipelines and, to

some extent, the construction of powerplants,

Statutory Control

Major regulatory review of the water

resource impacts of mining proposals is conducted under the mandate of the SMCRA

and the Clean Water Act. Water resource

data is a major component of a mine permit

application and compliance with several

water resource performance standards must

be demonstrated before an application can

be approved. Mines must also obtain a permit to discharge effluents from an operation

under provisions of the Clean Water Act.

Thus, the agencies most responsible for

review of water resource impacts are OSM

and companion State reclamation agencies

and EPA and companion State water quality

agencies. The following section reviews some

Federal statutes and regulations over water

resources. Implementation in each of the

Western States varies slightly and may be

more stringent than outlined here. No State

has less stringent provisions.

The SMCRA establishes conditions for

permit approval or denial:

No permit or revision application shall be

approved unless the application affirmatively demonstrates and the regulatory

authority finds in writing , . . that:

(3) the assessment of the probable cumulative impact of all anticipated mining

in the area on the hydrologic balance . . . has been made by the regulatory authority and the proposed operation thereof has been designed to prevent material damage to hydrologic

balance outside the permit area (sec.

510b.)
Ch. 10—lmplications of Environmental and Reclamation Issues for the Development of Federal Coal . 295

Section 515(b) of SMCRA also establishes

performance standards related to water resource impacts. A permit application must

demonstrate, among other things, that these

standards can be complied with before approval is obtained:

General performance standards shall be

applicable to all coal mining and reclamation

operations and shall require the operation,

as a

(2)

(4)

(8)

(lo)

minimum to—

restore the land affected to a condition

capable of supporting the uses which it

was capable of supporting prior to any

mining, or higher or better uses of

which there is reasonable likelihood, so

long as such use or uses do not . . . pose

any actual or probable threat of water

dimunition or pollution . . . .

stabilize and protect all surface areas

including spoil piles affected by the surface mining and reclamation operation

to effectively control erosion and attendant . . . water pollution , . .

create, if authorized in the approved

mining and reclamation plan and permit, permanent impoundments of water

on mining sites as part of reclamation

activities , . .

minimize the disturbances to the prevailing hydrologic balance at the mine-site

and in associated offsite areas and to the

quality and quantity of water in surface

and ground water systems both during

and after surface coal mining operations

and during reclamation by—

(A) avoiding acid or other toxic mine

drainage . . .

(B)(i) conducting surface coal mining

operations so as to prevent, to the

extent possible using the best

technology currently available,

additional contributions of suspended solids to streamflow, or

runoff outside the permit area,

but in no event shall contributions

be in excess of requirements set

by applicable State or Federal

law;

(ii) constructing any siltation structures . . . prior to commencement

of surface coal mining operations . . .

(c)

(D)

(E)

(G)

cleaning out and removing temporary or large settling ponds or

other siltation structures from

drainways after disturbed areas

are revegetated and stabilized;

and depositing the silt and debris

at a site and in a manner approved by the regulatory authority;

restoring recharge capacity of the

mined area to approximate premining conditions;

avoiding channel deepening or

enlargement in operations requiring the discharge of water from

mines , . .

such other actions as the regulatory authority may prescribe . . .

The purpose of these requirements is to ensure that long- and short-term adverse

changes in the hydrologic regime that might

be caused by coal mining and reclamation activities will be prevented or minimized.

OSM promulgated comprehensive regulations pursuant to these statutory provisions.

The major subject areas of the regulations of

concern to Western mining are:

● water quality standards and effluent

limitations,

● diversions, sediment control, and sedimentation ponds,

● impoundments,

● protection of ground water and ground

water recharge capacity,

● monitoring,

• water rights, and

• stream buffer zones.

Additional regulations concern alluvial valley floors; these provisions are discussed in a

later section.

Water Quality Standards and

Effluent Limitations

Control of discharges from mining and

reclamation activities is jointly controlled by

OSM and the agency responsible for implementation of the Clean Water Act in each

State. Under sections 301, 304, and 401 of
296 ● An Assessment of Development and Production Potential of Federal Coal Leases

the Clean Water Act, mining operations

must obtain discharge permits and comply

with EPA, or State effluent, limitations for

point source discharges of pollutants to surface waters. However, the Clean Water Act

permit system applies only during the active

phase of mining; it does not extend to reclamation, nor does it cover nonpoint pollution

sources, nor does it consider discharges to

ground water. However, under SMCRA all

water discharged as a result of coal mining

and reclamation activities which could

materially damage the hydrologic system is

regulated. Thus, coal mines must obtain a

permit to discharge from EPA, or administering State water quality agency, for all

point source discharges. These discharges

include effluents from plant facilities and

discharge of ground waters intercepted in a

mine pit. OSM, or State reclamation agency,

review also considers other types of discharges such as those from reclamation

areas, as well as providing input in the

review of point source discharges.

Effluent limitations established by OSM

are generally similar to those adopted by

EPA (table 87). In each State, any stricter

standards supersede these Western regional

standards. For instance, the Montana State

implementation program of the Clean Water

Act includes a provision that no discharge

may degrade the quality of receiving waters,

regardless of conformance with specific effluent limitations. At most Montana coal

mines, the necessity to meet this criterion is

a stricter one than are the direct effluent limitations.

Table 87.—Effluent Limitations for Western Coal

Mines in Milligrams per Liter (mg/l)a

Average of daily

values for 3 0

Maximum consecutive

Effluent characteristics allowable discharge days

Iron, total . . . . . . . . . . . . . . . . 7.0 3.5

Manganese, total . . . . . . . . . 4.0 2.0

Total suspended solids . . . . 45.0 30.0

aEPA has proposed a relaxation of these effluent standards (46 F.R. 28873, May

29, 1961). OSM has proposed to adopt these relaxed standards (46 F.R. 34764,

July 2, 1961).

SOURCE: 30 CFR 616.42(a)(7).

Diversions, Sediment Control, and

Sedimentation Ponds

Sedimentation ponds in conjunction with

other sediment control measures, are considered by OSM to be the “best technology

currently available” to prevent offsite sediment increases, as required by SMCRA.

Generally, OSM and State reclamation agencies require that ponds be constructed on

drainages below all mining and reclamation

disturbance areas. Regulations establish

many of the design characteristics of these

ponds, including their sediment storage volume, detention time, dewatering devices,

methods to prevent short circuits, * spillway

design, sediment removal, freeboard,** and

engineering characteristics of the retaining

dam.

In conjunction with sedimentation ponds,

OSM regulations require sediment control

measures within and around disturbed areas.

These measures include:

• disturbing the smallest area practicable

at any one time during mining,

● stabilizing pit backfill material,

● diverting runoff away from disturbed

areas,

● use of mulches, and

● chemical treatments

Many of the design specifications of diversions are also outlined in regulation.

Impoundments

Regulations also establish minimum standards for permanent and temporary impoundments. These impoundments include any

lakes or ponds proposed to become part of a

reclamation landscape. Section 515(b)(8) of

SMCRA establishes that permanent impoundments may only be constructed if six criteria

are met:

● that the impoundment size is adequate

for its intended purpose;

*Short circuiting: a process which transports sediment

through a pond in less than the detention time necessary for

the sediment to settle out.

**Freeboard: the height above the water surface level when

the spillway is operating at design capacity.
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal ● 297

●

●

●

●

●

that the impoundment dam is designed

to achieve necessary stability;

that the quality of impounded water

will be adequate for its intended use;

that the impoundment water level will

be reasonably stable;

that water users will be provided adequate safety and access; and

that adjacent landowners will not be adversely-affected by the impoundment.

Adopted regulations establish design criteria for impoundments and dams, and require inspections, maintenance, and initial

certification.

Protection of Ground Water and Ground

Water Recharge Capacity

SMCRA requires that the ground water

portion of the hydrologic system be protected along with the surface water portion.

Regulations have been adopted which generally require that backfilling and alinement of

excavations be conducted so as to protect

ground water outside the permit area.

SMCRA also requires that the recharge

capacity of the mined area be restored to the

approximate premining condition. Conceptually, recharge capacity is the ability of the

soil and rock materials to receive water,

store it for a period of time, and slowly

release it, either to a topographically lower

stream or lake, or to a well. Primarily, the

movement of precipitation and surface water

into the soil or rock materials is controlled by

the infiltration capacity of those materials.

Mining and reclamation have the potential of

changing infiltration capacity, primarily

through compaction.

Monitoring

Operators are required under SMCRA to

monitor ground water and surface water

quantity and quality on the permit area and

in the surrounding area before, during, and

after mining. The extent of the required

monitoring varies, but must be sufficient to

describe the premining environment and to

provide enough data for evaluating the effects of mining and reclamation activities.

Monitoring is required of all ground or surface waters which may be disrupted or degraded by mining.

Water Rights

Water rights issues are considered in the

context of the State laws applicable in each

State. OSM had developed regulations on

the water rights issue; however, these were

remanded in the Flannery decision (see p.

283), Generally, in each State, coal mining

operations must replace any water supplies

expected to be degraded or diminished by

those activities.

Stream Buffer Zones

Disturbance of a perennial stream must be

specifically approved under SMCRA. The

regulatory authority must find that the

stream channel will be restored and that undisturbed portions of the channel will not be

affected.

Implications of Water Resource Issues

for Federal Coal Development

Although no mine has yet been prohibited

from operating because of conflicts with

other water users, the potential for conflicts

with municipal, domestic or agricultural

water users exists. Conflicts may be acute in

the Uinta-Southwestern Utah region. In all

Western States, water supplies diminished or

degraded by mining are required to be replaced by the operator. In many cases, mines

choose to redrill nearby wells to deeper

aquifers if impacts from mining are expected.

The following discussion gives several illustrative examples of existing or potential

conflicts.

Municipal and Domestic Impacts

Surface and ground water originating in

the Wasatch Plateau of central Utah is used

by several municipalities. Local water users

are concerned that these waters may be intercepted or contaminated by underground
298 . An Assessment of Development and Production Potential of Federal Coal Leases

coal mining along the eastern edge of the

plateau. For instance, the town of Huntington, located near an active mining area, uses

spring flow for its water supply. This spring

flow may be affected by nearby underground

coal mining. In the nearby Emery coal field,

the town of Emery uses ground water that

could be affected by Consolidation Coal’s

Emery underground mine and proposed surface mine. The effects of this mining are

being studied by the company and USGS.14

If mining were demonstrated to adversely

affect municipal water supplies, mining companies would be required to replace these

supplies or limit their mining areas.

In North Dakota, some lignite seams are

significant aquifers. The Falkirk Mine is

mining such a seam, which is also the water

source for the nearby town of Underwood.

Little data are yet available on the impacts of

continued mining; however, the operator has

made a commitment to provide alternative

supplies should disruption occur.

Agricultural Impacts

The North Fork Gunnison River Valley of

west-central Colorado is an area where underground coal mining may affect the availability of water for agricultural irrigation.

Projected subsidence at the proposed Mt.

Gunnison Mine may divert enough surface

and ground water flow to adversely affect

downstream water users. 15 The State reclamation agency and OSM are advising the operator that if this occurs, the company will

have to purchase or replace the affected

senior water rights in the valley. Otherwise,

the mining company may have to leave recoverable coal in place in order to avoid subsidence and undesired water loss. Other mines

in the Somerset coal field may face similar

situations if projections of subsidence indicate diversion of significant surface flow.

l+ Morri~sey, Lines, and Ba rtholoma, Three-Dim ensionui Digital-Computer Model of the Ferron Sandstone Aquifer near

Emery, Utah, USGS open file report.

l~personal Commun ication to OTA, Technical Analysis Division, Regional Director, Region V, OSM, 1981.

Concern about the effect of underground

mine-induced subsidence on springs is widespread in the Wasatch Plateau. A landowner

above Utah Power & Light’s Deer Creek Mine

has expressed concern about subsidence effects on his springs, and the company has instituted a subsidence monitoring program to

evaluate impacts. All operating or proposed

mines in this area are developing monitoring

programs to measure subsidence and impacts

to springs and surface waters.

At the non-Federal Absaloka Mine in

southeastern Montana in the Powder River

basin, controversy about the projected destruction by surface mining of several seeps

and springs has caused the operator, Westmoreland Coal, to delay proposing mining of

the presumed source area of most of the

springs. The State reclamation agency hopes

that continued monitoring will result in a

better understanding of the hydrologic system before mining is proposed for the recharge area itself.

Throughout the Fort Union region and

Powder River coal basin, numerous domestic

and stock wells obtain water from shallow

aquifers. For example, 60 to 70 percent of

western North Dakota’s domestic and stock

wells tap shallow lignite aquifers. Each of

these water sources, if destroyed, diminished, or degraded by mining activities, is required to be replaced.

Empire Energy Co. is proposing to mine

several seams below the Yampa River in

northwestern Colorado in the Green RiverHams Fork coal region. Regulatory review is

focused on the projected effect of mineinduced subsidence on the river, both in

terms of environmental, and health and

safety impacts.

Water Resource Issues and the SMCRA

Unsuitability Petition Process

The effects of projected mining on water

availability were part of the Alton coalfield

unsuitability petition. The petitioners alleged that water development necessary to

mine and transport coal, and to help reestab-
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal 299

lish vegetation, would result in the drying of

springs and stream recharge critical to

agricultural water users in the same area.

OSM found that “present users of . . . water

. . . would be adversely affected.’’]

’

] In making his final decision on the petition, however, the Secretary of the Interior found that

insufficient information was available on

this issue on which to exclude areas from

mining and that the issue would be reexamined at the time of mine plan permit

review.

The Northern Plains Resource Council

and several affiliates have filed a petition for

designation of lands unsuitable for mining

for a portion of the Tongue River drainage

basin in southeastern Montana. Unleased

Federal coal, as well as fee and State coal

reserves, are affected by the petition. In

part, the petitioners claim that large-scale

mining would have significant regional impacts on water resources. They claim that

large-scale mining would have long-term

degrading effects on the stream, adversely

affecting stock and irrigation water uses.

Because the effects would be experienced

over a long time period, they fear that significant degradation could take place and not

be identified until it was too late to initiate

remedial measures. The petition is presently

under review and a decision is expected by

the State of Montana in late 1981.17

Other Water Resource Issues

Most of the water resource issues outlined

in the discussion on statutory control have

had no effect on the amount of Federal coal

permitted for mining. Although some of the

provisions have received substantial criticism from industry as being needlessly detailed and requiring unnecessary environmental protection, no Federal reserves have

been prohibited from recovery because of

these regulations. The issues of cost and

16U.S. Office of Surface Mining, Southern Utah Petition Evalua tion Document, Document Nos. OShf-PE-l and OSM-EIS-4,

1980.

“Northern Plains Resource Council, Petitian far Designation

af Certain Lands Unsuitable for Mining, 1980.

time delay in collecting required information

are briefly considered at the end of this

chapter, although a detailed examination of

these issues was not undertaken in this

report.

Water quality standards and effluent limitations have not had an effect on the outcome of the permitting process. EPA and

OSM limitations are able to be met at all

Western mines. Some controversy has continued over the standard for total suspended

solids, which industry has claimed to be too

stringent. These standards are being revised

to control total settleable solids, but the new

standards have not yet been released. Industry has criticized the number and size of

sedimentation ponds required of coal mines.

These criticisms center around issues of increased costs. Construction of these ponds,

particularly in steep canyons of the UintaSouthwestern Utah region, has caused extensive disturbance at some areas.

To date, no permanent impoundment has

been proposed under OSM regulatory program in the West. This may be because of

regulatory constraints or because no impoundment has been needed for reclamation.

The requirement to reestablish recharge

capacity has not caused any regulatory

denials; however, permit approval has been

delayed in some cases because the data submitted was found to be insufficient. Monitoring requirements have been criticized as

being overly demanding. However, in general, companies have apparently been able to

bear these costs. The impact of these requirements on small operators is discussed

in the final part of this chapter, Mining near

perennial streams is generally approved

under special conditions. Mining of perennial

streams themselves has not generally been

approved.

Water Availability: Primary and

Secondary Impacts

Limited water supplies, and competition

for those supplies, may ultimately affect the

extent of coal mining development in por-
300 “ An Assessment of Development and Production Potential of Federal Coal Leases

tions of the Green River-Hams Fork region

and in the San Juan River region. In these

water-deficit areas, mines need water not

only for dust control and use in the facilities,

but also for irrigation of vegetation on reclaimed areas. Irrigation is presently used at

some mines in the Green River-Hams Fork

region and all mines in the San Juan River

region. Recent studies in southern Wyoming

of expanded coal leasing indicate that water

shortages are possible as mines, growing

municipalities, and agriculture compete for

the same water sources.18

Expansion of mining in the San Juan River

region may also be affected by limited water

availability. Essentially, surface water is

nonexistent in this area and wells must supply all water needs. However, the Fruitland

formation aquifer is expected to be the primary water supply for the uranium mining industry in the area, as well as for municipalities. According to the OTA New Mexico task

force, if both industries expand in the 1980’s,

available water supplies may not be able to

meet demands.

Water availability may also affect coal

development where coal development is dependent on onsite powerplants, synthetic fuel

plants, or slurry pipelines. See table 88 for

18 U.S. Bureau of Land Management. Final Green River-Hams

Fork Regional Coal Environmental Impact Statement, 1980.

Table 88.—Total Water Requirements for Various

Major Facilities, Northern Great Plains

Water need

Facility (acre-feet/yr)

Water-cooled 1,000 MW powerplant

(about 4 million tons per year) . . . . . . . . . 10,000-15,000

275 million scf/d coal gasification plant. . . 4,500- 8,000

Slurry pipeline (35 million tons per year). . . 13,000-20,000

SOURCE: Office of Technology Assessment.

water requirements for these facilities. Scarcity of water in the Gillette area of the

Powder River basin justified the expense of

constructing the first dry-cooling tower in the

United States at the Wyodak Power Plant

east of Gillette. Proposed sources of water for

slurry pipelines have been the Madison Limestone aquifer and the Little Bighorn River.

Controversy surrounds the use of either

source. Although Energy Transportation Systems, Inc. (ETSI) has a permit from the State

of Wyoming to withdraw about 20,000 acreft/yr from the Madison for its pipeline, the

State of South Dakota is considering bringing

suit against such a water use, claiming adverse impact to its existing uses of the same

aquifer. The State of Montana has decided

that use of water for slurry pipelines is specifically not a beneficial use of water and

water use permits therefore cannot be

granted for use of Montana water in coal

slurry pipelines.

Alluvial Valley Floors

Under provisions of SMCRA, alluvial and regulating Government agencies. Indusvalley floors in the Western United States try has claimed that the alluvial valley floor

are given special protection because of their provisions are overly complex, lead to signifagricultural and hydrologic importance. The icant delays in processing permits, and may

more important alluvial valley floors are pro- ultimately lead to significant loss of recovertected from coal mining and its associated able reserves.

disturbance. The less important alluvial

valleys may be mined, but standards for reclamation are higher than for other types of 1.

mined areas. The impact of the alluvial

valley floor statutory provisions, adopted

regulations, and guidelines have been the

subject of continued debate among industry

Analysis by OTA has found that:

To date, for Federal mines, only one

stream valley in the West (Squirrel

Creek Valley in Montana) has been identified as having the characteristics that

will probably lead to absolute prohibi-
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal 301

2.

3.

4.

5.

6.

tion of mining activities in a portion of

the valley. The affected companies have

asked that this decision be reconsidered.

Numerous stream valleys in the Powder

River coal basin have been, or are likely

to be, identified as having characteristics that will allow mining, but under

stringent alluvial valley floor reclamation standards.

Neither OSM, nor any State reclamation authority, has approved a proposed

reclamation plan for an alluvial valley

floor under the permanent regulatory

program. Thus, no regulatory decisions

have yet been made on which to analyze

the detail and expense that reclamation

of alluvial valley floors will necessitate.

The general perception of both industry

and Government officials is that most

alluvial valley floors are reclaimable

under existing technologies. Subirrigated alluvial valley floors pose the

greatest difficulties for reclamation.

Alluvial valley floors have been identified under formal regulatory processes

in the Powder River coal basin, and

most leaseblocks in that basin are expected to include some areas of designated alluvial valley floor, Alluvial

valley floors are also important in the

Fort Union coal region. In the Green

River-Hams Fork coal region and the

Uinta-Southwest Utah coal region few

alluvial valley floors have been identified,

The alluvial valley floor issue has the

potential to affect more tonnage of

recoverable coal than any other environmental factor. However, in relation to the total Federal recoverable

coal base under lease, and the market

supply relationships anticipated to exist until 1991, no adverse production effects are expected in the next 10 years.

Alluvial valley floor issues are likely to

affect non-Federal coal reserves to a

greater degree than Federal reserves

because of the concentration of nonFederal coal in major river valleys, the

sites of initial

West.

Background and

homesteading in the

Statutory Control

As a general description, alluvial valley

floors are those stream valleys in the

western United States which: 1) are underlain by unconsolidated gravel, sand, silt, and

clay; 2) have a stream flowing through them;

3) have a generally flat valley floor topographic surface; and 4) have an agricultural

importance (fig. 48). The relative importance

of these valleys is a function of the water

supplies available in the specific valley area.

The agricultural activities generally include

irrigated or subirrigated hay lands, developed pasture lands, critically important

grazing areas, or lands that could be developed for any of these purposes.

Alluvial valley floors were one of the more

controversial portions of SMRCA, and were

extensively debated in Congress prior to

passage of the act in 1977. The special role

that alluvial valley floors play in Western

agriculture was central to the debate:

Of special importance in the arid and

semiarid coal mining areas are alluvial valley floors, which are the productive lands that form the backbone of the

agricultural and cattle ranching economy in

these areas, For instance, in the Powder

River basin of eastern Montana and Wyoming, agricultural and ranching operations

which form the basis of the existing economic system of the region could not survive

without hay production from the naturally

subirrigated and flood-irrigated meadows

located on the alluvial valley floors.19

The provisions passed in the act included

specific prohibition from mining certain

alluvial valley floors, and stringent reclamation standards for those alluvial valley floors

that could be mined. The prohibitions to

mining are outlined in section 510(b)(5) of the

19 U. S. House of Representatives, Committee on Interior and

Insular Affairs, Report Accompanying H.R. 2, the Surface Mining Control and Reclamation Act of 1977, House Report 95-218,

95th Cong,, 1st sess., 1977, p, 116.
302 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 48.—Stylized Diagram of an Alluvial Valley Floor

Subirrigated

alluvium

SOURCE: Dollhopf, Wendy, Goering, and Hedsberg, “Hydrology of a Watershed With Subirrigated Alluvial Materials in Crop Production,” Montana Agricultural Expert.

ment Station Bulletin 715, 1979.

act. This section generally states that no

coal mining operation may “interrupt, discontinue, or preclude farming” on alluvial

valley floors, unless the lands that would be

disturbed are “of such small acreage as to be

of negligible impact on the farm’s agricultural production. ” Alluvial valley floors used

as “undeveloped range lands” are not prohibited from mining.

Section 510(b)(5)(B) also states that coal

mining must be prohibited if it would “materially damage the quantity or quality of

water in surface or underground water systems” that supply those important alluvial

valley floors that are prohibited from mining. Thus, mining in areas near important

alluvial valley floors would be prohibited if

material damage were projected.

For those alluvial valley floors not excluded from mining under the provisions of

section 510(b)(5), reclamation standards are

established under section 515(b)(10)(F). This

section states that a coal mine must “minimize the disturbances to the prevailing

hydrologic balance . . . by . . . preserving

throughout the mining and reclamation process the essential hydrologic functions of

alluvial valley floors. ” This requirement to

“preserve” both during and after mining “the

essential hydrologic functions” is a regulation unique to alluvial valley floors.

Regional Studies of Alluvial Valley

Floor Occurrences and Their

Relationship to Recoverable

Coal Reserves

The first studies of the regional pattern of

alluvial valley floor occurrence were conducted prior to passage of the act. 20 T h e

results of these studies are summarized in

table 89. Generally, these studies concluded

that less than 5 percent of the recoverable

coal reserves of the West would be affected

by alluvial valley floor provisions. Reexamination of these studies indicates that about 1

percent of the reserves studied in the above

investigations would likely be affected by the

prohibition provisions of section 510

(b)(5), BLM, in 1980, estimated that almost 60

percent of the available unleased Federal

coal in the Gillette, Wyo. area was overlain

20 Malde and Boyles, 1976; Schmidt, 1977; Hardaway, et al.,

1977. See table 89 for full citations.
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal ● 303

Table 89.—Alluvial Valley Floor Studies

Study area

underlain by

strippable Amount or

coal or area of

amount of strippable

strippable coal coal overlain

Study Study area considered by AVF

Malde and Southeastern Montana 392,000 acres 10,500 acres

Boyles, 1976

Schmidt, East-central Montana

1977

Burns Creek- 2,640 mt 39.2 mt

Thirteenmile Creek

KCLA

Weldon-Timber Creek 657 mt 15.9 mt

deposit

Redwater River 582 mt 46.4 mt

Hardaway, Existing and proposed 914,000 acres 27,000 acres

et al., 1977 mines, Western United

States

SOURCES Jack Schmidt. “Alluvial Valley Floors in East-Central Montana

and their relatlon to strippable coal reserves, ” Denver, Environmental Protection Agency Off Ice of Energy Activities, report No.

8908-4-77-001, 1977.

H. E, Malde and J. M, Boyles. “Maps of Alluvial floors and strip.

pable coal in forty-two 71⁄2 minute quadrangles, Big Horn,

Rosebud, and Powder River Counties, Southeast Montana”, U.S.

Geological Survey Open File 73, Report No. 76-162, 1976,

John E. Hardaway, Dan B. Kimball, Shirley F. Lindsay, Jack

Schmidt and Larry Erickson. "Sub-lrrigated Alluvial Valley floors –

A reconnaissance of their properties and occurrence on coal

resource lands in the Interior Western United States: Louisville, ”

Proceedings of Natoinal Coal Association/Bituminous Coal

Research Symposium, 1977, p. 61-135,

by potential alluvial valley floors. BLM made

no attempt to distinguish between areas likely

to be prohibited from mining and areas where

special reclamation standards would be required. Examinations of this study by OSM indicate that BLM has also identified areas that

will not be classified as alluvial valley

floors. 21 Thus, the BLM study almost certainly

greatly overestimates alluvial valley floor

occurrence.

OSM identified alluvial valley floors in the

Alton, Utah coalfield.

22 No attempt wa s

made to distinguish between areas likely to

be prohibited from mining and areas where

mining would be allowed. Of the 325,000-

acre area considered under the Alton unsuitability petition, less than 5 percent of the

area was designated as alluvial valley floor

of either type.

“Personal communication: OSM Region V, Chief, Branch of

Earth Sciences and Geot echnics.

zzu .s. Office of Surface Mining, Southern Utah Petition Evacuation Document, 1980.

Determinations Made by Federal and

State Reclamation Agencies in the

Powder River Coal Basin

The Montana Department of State Lands,

with the concurrence of OSM, has determined that Squirrel Creek valley in Big Horn

County is an alluvial valley floor, portions of

which are being actively farmed and are significant to agriculture. The stream is a intermittent tributary of the Tongue River and

crosses portions of Federal coal leases held

by the Rosebud Coal Sales Co. (lease No.

M-061686) and the Consolidation Coal Co.

(lease No. M-46292). Areas with significant

farming activities total about 250 acres;

however, the total alluvial valley floor, which

contains Federal and non-Federal coal reserves, is more than 1,250 acres. Alluvial

valley floors, although not necessarily significant to farming activities, cover about 35

percent of the Consolidation Coal proposed

mine plan area and over 40 percent of the

Rosebud Coal Sales proposed mine plan

area. 

23

At this time, it is not known what effect

the alluvial valley floor determination will

have on mining in this area. Areas considered significant to farming cannot be mined,

even if they are reclaimable. On the one

hand, it is possible that no mining of either

lease will take place, particularly if the Montana DSL determines that mining of adjacent areas would result in “material damage

to the Squirrel Creek Valley. ” On the other

hand, mining might still be able to take place

on the surrounding uplands. Consolidation

Coal intends to submit a proposed mine plan

for nonalluvial valley floor areas in early

1982. The companies have estimated that a

total of 100 million tons of Federal and nonFederal coal under both leases would be affected by the alluvial valley floor decision.24

State regulatory authorities, with the concurrence of OSM, have identified alluvial

valley floors that are considered not to be

24Nimick, personal communication, Montana Department of

Stale Lands hydrologist, 1981.

“Ibid.
304 ● An Assessment of Development and Production Potential of Federal Coal Leases

significant to farming at the Buckskin, Rawhide, Eagle Butte, and Coal Creek mines, all

located in the Powder River coal basin of

Wyoming (see table 90). The Coal Creek mine,

operated by the Thunder Basin Coal Co. (a

subsidiary of Atlantic Richfield Co.), obtained approval for its mine in early 1979

and began coal shipments in late 1981. Regulatory authorities designated 846 acres of

the total proposed mine plan area, or about 9

percent, as alluvial valley floors. Although

initial approval was obtained for the first 5

years of mining, the regulatory agencies

have stated that Thunder basin coal must

demonstrate compliance with section 515

(b)(l0)(F) of the act before any additional

mining will be approved. As discussed

earlier, section 515(b)(10)(F) requires an

operator to demonstrate that the “essential

hydrologic functions” of the designated

alluvial valley floors will be protected by

minimizing offsite impacts and restoring the

alluvial valley floors proposed to be mined.

Although only 9 percent of the total mine

plan area has been designated as alluvial

valley floors, Thunder Basin Coal would be

seriously constrained in mining the Coal

Creek if the company could not demonstrate

compliance with section 515(b)(60)(F).25 East

Fork Coal Creek crosses the middle of the

mine plan area. The company maintains that

25Smith personal communication, President, Thunder Basin

Coal, 1980.

Table 90.—AlluviaI Valley Floor (AVF) Summary Table

Developed Coal Reserves in the Powder River Basin

Acres of stream

Acres of designated Acres of designated valley under

Federal lease AVF significant AVF not significant study as

Mine area (acres) to farming to farming potential AVF

Rosebud. . . . . . . . . . . . . . . . . . . 8,226 —a — 386

Big Sky (g)b . . . . . . . . . . . . . . . . . 4,307 0

c

0 0

— — 275

Spring Creek . . . . . . . . . . . . . . . . 2,347 0 0 0

— — 257

West Decker (g) . . . . . . . . . . . . . . 4,961 0 0 0

East Decker (g) . . . . . . . . . . . . . . 9,410 — — 386

Buckskin . . . . . . . . . . . . . . . . . . 599 — 358 0

— — o

Rawhide(g) . . . . . . . . . . . . . . . . . 5,697 0 143 0

0 52 0

Eagle Butte (g) . . . . . . . . . . . . . . . 3,520 0 126 0

— — 10

Wyodak (g) . . . . . . . . . . . . . . . . . . 1,880 — — 240

Caballo. . . . . . . . . . . . . . . . . . . . . 5,360 0 0 0

Belle Ayr (g) . . . . . . . . . . . . . . . . . 2,401 0 0 365

Rojo Caballos . . . . . . . . . . . . . . 3,959 0 0 0

Cordero (g) . . . . . . . . . . . . . . . . . . 6,560 — — 640

non-Federal

Coal Creek . . . . . . . . . . . . . . . . . . 5,806 0 116 0

0 616 0

0 70 0

0 44 0

Jacobs Ranch (g). . . . . . . . . . . . . 4,352 — — 240

Black Thunder(g) ., . . . . . . . . . . 5,884 — — 545

David Johnston(g) . . . . . . . . . . . 9,662 0 0 0

Name of stream

East Fork Armells Creek

Emile (Coal bank)

L & Miller Coulee

Lee Coulee

Spring Creek

South Fork Spring Creek

Spring & Pearson Creek

Deer Creek

Rawhide Creek

Spring Draw

Rawhide Creek

Little Rawhide Creek

Little Rawhide Creek

Dry Fork Powder River

Donkey Creek

Tisdale Creek and

Gold Mine Draw

Cabal lo Creek

Clabaugh and Desmet Draw

Belle Fourche River

Coal Creek

E. Fork Coal Creek and Tributary

Middle Fork Coal Creek

Dry Creek Tributary

Little Thunder Creek

Burning Coal Draw

N. Prong Little Thunder Creek

and Little Thunder Creek

—

Totals:

Federal lease acres . . . . . . . . 84,931 0 1,525 2,704

Federal recoverable reserves

(million tons) . . . . . . . . . . . . 5,300 0 97 299

a

—: Indicates no determination made.

b 

g: Refers to So-called "grandfathered mines;” that is, those mines which were operating prior to passage Of SMCRA.

c

o: Indicates determination by regulatory agency that no AVFS are along indicated streams.

SOURCE: Off Ice of Technology Assessment; mine plan review.
Ch. 10—lmp/ications of Environmental and Reclamation Issues for the Development of Federal Coal . 305

prohibition from mining East Fork Coal

Creek would render the entire operation uneconomic. The entire mine area contains

several hundred million tons of recoverable

reserves. Despite the uncertainty of the

future regulatory decision, Thunder Basin

Coal has proceeded with its development,

and anticipates that mining approval will be

obtained. Even if approval were not obtained

for mining the stream valleys, examination

of mine plan maps suggests that the ultimate economic impact of a regulatory prohibition could be less than predicted by the

company, Individual pits might be developed on either side of the main stream: however, at least 30 million tons underlying the

stream would be lost.

Several regulatory decisions concerning

alluvial valley floors are pending, and have

affected the orderly development of mine

plans. Alluvial valley floor studies are underway, with decisions pending, at 10 mines in

the Powder River coal basin. OSM does not

anticipate that any of the stream valleys in

question will be designated significant to

farming, and thus be subject to prohibition

from mining.26 At those mines operating

prior to passage of the act, mine planning

has proceeded under the assumption that

mining of alluvial valley floors will be approved. However, formal regulatory approval has not yet been obtained. Plans for

mining and reclamation of valleys were submitted by each mine in January 1981, as part

of each mine’s permanent regulatory program submittal. As of late March 1981,

review was proceeding but no State agency

had had sufficient time to approve these

plans.

At two mines approved after passage of

the act, Spring Creek and Buckskin, uncertainty about alluvial valley floor status and

reclaimability has led each operator to avoid

proposing the mining of areas of uncertain

alluvial valley floor status. Studies are

underway in each case that may show that

the streams can be reclaimed. However, at

least temporarily, 59 million tons at Spring

26Kimball, personal communication, OSM, 1981.

Creek and 36 million tons at Buckskin are

not proposed for mining.

The position that State and Federal regulatory agencies take toward compliance with

section 515(b)(10)(F) will have a significant

effect on the quantity of coal reserves affected by alluvial valley floor provisions. If

industry is able to demonstrate that the essential hydrologic functions can be protected

or restored during or after mining, then only

those alluvial valley floors with significant

agricultural activities on them will be prohibited from mining. In that case, it is likely

that only the Consolidation Coal and Rosebud Coal Sales leases referred to above, affecting about 100 million tons of Federal and

non-Federal reserves, will ultimately be prohibited from mining,

Table 91 summarizes potential alluvial valley floor occurrences on all undeveloped Federal leaseblocks in the Powder River coal

basin. Total estimated area of potential alluvial valley floors is about 2,800 acres, which

may include about 219 million tons of Federal

recoverable reserves. Thus, about 5 percent

of the Federal recoverable reserve base of

undeveloped lease blocks in the Powder River

basin is overlain by potential alluvial floors.

Another 2 percent of Federal recoverable reserves in undeveloped lease blocks in the

Powder River basin could be prohibited from

mining because of the significant to farming

provisions. Although the potential for affecting additional reserves through inability to

develop orderly mine plans might increase

the affected reserves somewhat, the increase

is not expected to be substantial.

The impact of alluvial valley floor designations, and the likelihood of identifying areas

significant to farming, is of greater concern

to private coal owners in the Powder River

basin than to Federal lessees. This situation

results from the fact that private coal ownership is often concentrated in major stream

valleys where significant farming operations

are found. This pattern of ownership exists

because the earliest homesteaded lands in

the West obtained mineral as well as surface

ownership rights upon compliance with the
306 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 91.—Alluvial Valley Floor (AVF) Summary Table

Undeveloped Coal Leases

Acres of stream

Lease block Acres of designated Acres of designated valley under

area AVF significant AVF not significant

Lease block

study as

(acres) to farming to farming potential AVF Name of stream

C X Ranch

(Consolidated Coal).. . . . . .

C X Ranch

(Rosebud Coal Sales) . . . . .

Pearl . . . . . . . . . . . . . . . . . . . . .

Armstrong. , . . . . . . . . . . . . . . .

Bass ., . . . . . . . . . . . . . . . . . . .

674 245 300 —a Squirrel Creek

524

541

80

20.701

—

40

0

200

Little Youngs Creek

None

Clear Creek

Powder River

Deadman Creek

several tributaries

Powder River

Robinson Draw

Wild Horse Creek

North Prong Wild Horse

Creek

Boxelder Creek and Tributary

Negio and Dry Creek

Jamison Prong and

Soukup Draw

None

Dry Fork Little Powder River

Prairie Creek

Dry Fork Little Powder River

Tributary

Little Rawhide Creek

Donkey Creek

Dry Fork Little Powder River

Tributary

None

Lee Draw

School Creek Tributary

Porcupine Creek and

Tributary

Holmes Creek

West Fork Creek Tributaries

None

Antelope Creek

Logan Draw

Spring Creek

Phillips Creek

Dry Fork Cheyenne River

—

0

b

o

Arvada. . . . . . . . . . . . . . . . . . . . 4,366 0 0 750

1OC

240

120

Lake DeSmet . . . . . . . . . . . . . .

Belco. . . . . . . . . . . . . . . . . . . . .

Wildcat . . . . . . . . . . . . . . . . . . .

9,417

4,551

1,571

0

0

0

0 — —

Blue Diamond. . . . . . . . . . . . . .

Dry Fork . . . . . . . . . . . . . . . . . .

40

3,580

0

300

—

—

—

—

South Rawhide. . . . . . . . . . . . . 4,782 — — 180

East Gillette . . . . . . . . . . . . . . .

Federal

4,343 160

120

—

—

—

—

Gulf (3) . . . . . . . . . . . . . . . . . . . .

East Wyodak . . . . . . . . . . . . . .

North Rochelle . . . . . . . . . . . . .

Rochelle . . . . . . . . . . . . . . . . . .

756

2,560

2,000

8,821

—

—

—

—

—

—

—

—

—

25

18

North Antelope. . . . . . . . . . . . .

Antelope . . . . . . . . . . . . . . . . . .

320

4,817

—

—

—

—

Phillips Creek (1) & (2) . . . . . . . 4,079 — — 60

Totals:

Federal Lease Acres:. , . . . . 78,523 245 300 2,823

Federal Recoverable

reserves: (million, tons)d 

. 4,000 <I00

e e 219

a—: Indicates no determination made.

b

o: lndicates determination by regulatory agency that no AVFs are along indicated streams.

C There is an estimated 400 million tons of nonfederal coal under a potential alluvial valley floor associated with this lease block.

d Tonnage of coal calculated using average coal seam thickness and the assumption that acre ft of coal = 1,800 metric tons. This calculation tends to overestimate reserves in AVFs due to the assumption that the average coal seam thickness covers the whole area of the AVF.

e Refers to reserves for entire AVF No estimate available for percentage of reserves under nonsignificant to farming AVF which Will be able to be mined

SOURCE: Office of Technology Assessment.

homestead standards. The earliest settlers without transferring mineral ownership. For

were attracted to the valleys with perennial example, proposed mines such as Montco’s,

streams. Thus, the land and underlying coal north of Birney, Mont., and Peter Kiewit

reserves located along those major stream Sons’ Whitney Benefits Mine, north of Shervalleys with the longest history of agricul- idan, Wyo., both on or near the Tongue

tural land use are owned by private entities. River, face substantial issues related to

Only later did the Federal Government begin farming activities on alluvial valley floors.

the practice of transferring surface ownership
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal ● 307

Alluvial Valley Floor Occurrence

in Other States

Alluvial valley floors occur in each of the

other Western coal regions. By definition,

alluvial valley floors do not occur in Oklahoma or other areas east of the 100th meridian. In Western coal regions outside the

Powder River basin, less work has been done

on defining alluvial valley floors; however,

based on the work that has been done, alluvial valley floors probably occur infrequently

in most areas. While only Alderin Creek at

the Glenharold Mine in North Dakota is

being reviewed for alluvial valley floor status

in the Fort Union region, studies by Schmidt

(1977) and Hardaway, et al. (1977) indicate

that up to 10 percent of the reserve base of

that region might be affected by alluvial

valley floor concerns.27 However, the amount

of reserves that will be prohibited from mining will probably be much less because most

valleys in mine areas are not being actively

farmed.

27 see table 89 for full citations.

In the Green River-Hams Fork region, alluvial valley floors may occur in southwestern Wyoming and in northwestern Colorado.

Three blocks in the Kemmerer Field have potential alluvial valley floors covering less

than 200 acres. No alluvial valley floors are

expected to be designated in the Rock

Springs or Hanna fields. In northwestern

Colorado, Empire Energy is proposing mining under the Yampa River, in an alluvial

valley floor. The impact of other alluvial

valley floor areas on mine production is unevaluated at present.

In the Uinta-Southwestern Utah region,

alluvial valley floor determinations may affect mine development in the Alton Field as

discussed earlier. Elsewhere, effects are expected to be minimal because underground

mining generally is not occurring under

stream valleys. Alluvial valley floors are not

expected to be a significant issue in the San

Juan River region because of the general

absence of surface water.

Topsoil, Spoil Handling, and Recontouring

OTA has identified one mine where recoverable coal reserves have been rendered unrecoverable by regulatory decision in this

issue area. That mine, in the Green RiverHams Fork region in Wyoming, estimated

that it lost 5 million tons* due to a limitation

on the area where spoils** could be disposed.

Additional reserves may be affected in the

Green River-Hams Fork region at mines with

characteristics similar to the mine discussed

here. Regulations on this issue have also affected the cost of mining. These increased

costs are discussed under the economic impacts section of this chapter.

*OTA estimates that 15 million tons may ultimately be

removed from mining a t I his mine if the State continues its pattern of interpretation of these regulations.

* *Spoil is overburden material removed by mining operations in the course of exposing coal seams.

The Mining Process

The first step in developing a mine pit is

the removal of topsoil. Topsoil is either

stored in stockpiles or replaced on regraded

spoils elsewhere in the mine. Decisions concerning the depth of topsoil to be salvaged at

any location prior to mining are based on a

soil survey for the mining area. Agreement

between the operator and the regulatory

agency is reached on how much of each soil

type must be salvaged.

Overburden is the rock strata between the

ground surface and the target coal seam and

between the target seams. (Rock strata in

the latter case may also be called interburden. ) Spoil may be removed by dragline,

truck and shovel combination, or scraper

and dozer combination. Depending on the

geology of the coal seams, an open pit, area,
308 An Assessment of Development and Production Potential of Federal Coal Leases

or terrace pit mine may be developed (ch. 11).

Spoil disposal at each type of mine is slightly

different. In open pit mines, spoil is stored

outside the pit since the entire pit is needed

for mining operations. In area or terrace pit

mines spoil is disposed in inactive parts of

the pit from which coal has already been removed. Requirements to limit out-of-pit spoil

disposal or to selectively bury toxic overburden may necessitate different techniques

of overburden removal and spoil disposal.

Statutory Control

SMCRA requires that certain standards

be adhered to in the handling of topsoil and

spoil. Topsoil must be removed prior to mining operations and either stockpiled or immediately placed on a regraded area (sec.

515(b)(5)). If stockpiled, the topsoil must be

vegetated in order to protect it from erosion.

All mined and regraded areas must be covered with topsoil or “the best available subsoil which is best able to support vegetation” (sec. 515(b)(6)). Since some spoil material may be high in concentration of elements

detrimental to vegetation or livestock or may

contribute to ground water pollution, spoil

must be placed in such a manner as to reduce

these effects (sec. 515(b)(10)(A)(19)). The reclaimed land surface must resemble “the approximate original contour of the land.” Special exceptions to this requirement are made

for areas of very thick and very thin overburden. In those cases, the operator is required to

attain the “lowest practicable grade, ” to provide drainage, to cover toxic forming materials, and to ensure land surface stability (sec.

515(b)(3)).

SMCRA regulations for topsoil removal

require that an operator remove topsoil or

other approved plant-growth medium before

beginning mining operations, save it in a

manner conducive to protecting the primary

root medium from contamination and erosion, and redistribute it in a manner that will

enhance its productivity. Regulations governing removal and redistribution are defined in 30 CFR 816.21 to 816.24. Removal requirements define the timing for removal as

being after vegetation is removed and prior to

surface disturbances caused by drilling, mining, blasting, or other such activities. Regulations define which unconsolidated subsoils

should also be removed. Certain overburden

materials may be used in lieu of, or as a supplement to, topsoil if those materials are approved by the regulatory authority.

Once topsoil is removed, it is desirable to

move it only once, placing it where the soil

will be permanently part of a new reclamation landscape. When temporary storage of

topsoil is necessary, 30 CFR 816.23 defines

the procedures to protect the soil from wind

and water erosion, and to maintain its physical and chemical composition. Regulations

also establish standards to be achieved in

replacing topsoil in regraded areas (30 CFR

816.24(b)). Soil tests performed in accordance

with regulatory standards are required to determine whether soil nutrients and amendments are necessary for the replaced soil to

support the proposed revegetation.

Requirements for backfilling and grading

of areas disturbed by surface coal mining are

found at 30 CFR 816.101 to 816.105. The

focus of these regulations is to “insure the

prompt restoration of the disturbed lands to

minimize additional damage to the environment, and to return the land to a productive

use” (sec. 515(b)(3)). General backfilling and

grading requirements consider:

1.

2.

3.

4.

the timing of these activities, subsequent to the removal of coal,

the contour of the land which must be

restored in the final grading process;

the procedures to be used when the final

thickness is less than 0.8 of the initial

thickness* (thin overburden situations);

and

the procedures to be used when the final

thickness is greater than 1.2 of the initial thickness (thick overburden situations).

*InitiaI thickness is the sum of the overburden and coal

thicknesses prior 10 the removal of the coal. Final thickness is

the product of the initial overburden thickness, prior to coal removal, times a bulking factor,
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal . 309

In order to prevent environmental degradation caused by acid and toxic forming

materials, 30 CFR 816.103 requires that “a

minimum of four feet of the best available

nontoxic and noncombustible material (be

placed upon) all exposed coal seams and all

acid-forming materials.”

Implications of Topsoil, Spoil Handling,

and Recontouring Issues for Federal

Coal Development

In the Green River-Hams Fork coal region,

spoil handling requirements have resulted in

the loss of about 5 million tons of recoverable

reserves at the Black Butte Mine in Wyoming,

following a regulatory decision limiting the

area outside the mine pit where spoil can be

disposed. Mining methods employed at this

mine involve development of several distinct

pits, many of which require out-of-pit spoil*

disposal areas. OSM, in its technical review

of the Black Butte Mine plan, determined that

the originally proposed out-of-pit spoil areas

conflicted with four regulatory standards:

1) the requirement to minimize the overall disturbed area; 2) the requirement to achieve

the approximate original contour of the landscape; 3) the requirement to limit disturbance

to wildlife habitat; and 4) the requirement to

limit disturbance in stream channels. OSM

then limited the out-of-pit spoil disposal area,

necessitating mine plan changes that resulted

in the loss of recoverable coal28

Although no other mine in Wyoming or Colorado in the Green River-Hams Fork region

has experienced such a limitation to date, the

similarity of the mining method used by Black

Butte with that of other mines in the region

*Out-of-pit spoils are those spoils removed in the course of

mining that are not backfilled in the mine pit but rather are left

on the natural ground surface.

ZIJU. S. Office of Surface Mining, Technical Analysis, Black

Butte Coal CO. amendment to spoil handling procedures in Area

D, 1979,

suggests that some other mines in the region,

most of which use out-of-pit spoils disposal

methods as part of their mining operations,

may experience regulatory decisions similar

to Black Butte. Other mines where out-of-pit

spoils and approximate original contour considerations may result in loss of recoverable

reserves include Rosebud Coal Sales, Seminoe No. 2, Medicine Bow, Colowyo, and the

undeveloped South Haystack lease. However,

SMCRA allows out-of-pit disposal as part of

the special regulations specific to open pit

mining in the Kemmerer, Wyo, area (special

bituminous coal mine regulations).

Proposed mine methods have bee n

changed because of spoil disposal and spoil

handling requirements. These requirements

have included limitations on placement of

excess spoil (East Decker Mine, Montana),

the need to bury spoil high in sodium concentrations (Spring Creek Mine, Montana), and

the need to bury spoil high in selected elements (Big Sky Mine, Montana; several

mines in the Powder River coal basin, Wyoming). At some of these mines, companies

claimed that the regulatory changes in mining method resulted in increased costs which

are now being passed to the consumer. These

increased costs are examined in the final section of this chapter.

Approximate original contour considerations may have effects in areas of steep

topography even where coal seams are flat

lying. For example, at the Spring Creek Mine

in the Powder River basin, recoverable coal

underlies a steeply sloping area of sandstone

bluffs. The operator is uncertain whether the

approximate original contour can be restored. The effect of this concern is unclear

at this time. At the nearby West Decker

mine, the Montana State reclamation agency has requested the company to mine into

the bluff in order to achieve erosion control

at the highwall. Thus, the impact of approximate original contour regulations is still

uncertain.
310 ● An Assessment of Development and Production Potential of Federal Coal Leases

Public

stringent

Revegetation

Law 95-87 establishes a uniform

standard for revegetation of mined

lands that is particularly challenging in the

West. Section 515(b)(19) requires the establishment of a “diverse, effective and permanent vegetative cover of the same seasonal

variety that is native to the area of land to be

affected and capable of self-regeneration

and plant succession at least equal in extent

of cover to the natural vegetation of the

area. ” The standard also makes allowances

for use of introduced species where desirable

and necessary to achieve the approved post

mining land use plan. The use of introduced

species in the West generally requires more

intensive management to maintain optimum

levels of productivity compared to restoration of native vegetation. This is generally

not feasible in most areas of the West that

will be surface mined because the added

costs of intensive management usually do

not increase productivity sufficiently to pay

off. Consequently, most reclamation in the

West involves reestablishment of native ecosystems.

Revegetation of surface mined lands has

been the subject of considerable controversy

in the West primarily because the arid and

semiarid climate makes the establishment

and maintenance of vegetation more difficult

than in the humid East. A study by the National Academy of Sciences29 concluded that

areas receiving 10 inches or more of annual

precipitation can usually be reclaimed* provided that evapotranspiration is not excessive, landscapes are properly shaped, and

techniques demonstrated to be successful in

rehabilitating disturbed rangelands ar e

used. However, the NAS committee concluded that in drier areas receiving less than

10 inches of precipitation, revegetation will

29National Academy of Sciences, Rehahilitation Potential of

Western Coal Lends (Cambridge, Mass.. Ballinger Publishing

co., 1974).

*The NAS Committee used the term “rehabilitation’” rather

than “reclamation,” but in current usage, the two terms are

usually used interchangeably.

be much more difficult and can probably

accomplished only with major sustained

be

inputs of water, fertilizer and management.

The committee used slightly less stringent

criteria than in SMCRA for defining successful reclamation, and emphasized that its

conclusions were not based on long-term extensive controlled experiments in revegetation.

More recent studies that have evaluated

revegetation practices in the West 30 hav e

noted short term success in revegetation,

but have concluded that the long term success of revegetation through periods of extended drought have yet to be demonstrated, and that revegetation techniques remain essentially experimental in nature,

There is no dispute about whether vegetation can be established on mine land in the

West. This has been accomplished through

the use of irrigation and intensive management even in the driest areas such as the San

Juan River basin and southern Wyoming,

and high levels of productivity have been

measured at several reclaimed sites in the

Northern Plains that have used fertilization

and introduced species. However, disagreement exists as to whether native ecosystems

with similar levels of productivity and

resilience to the stress of drought can be

established. Of particular concern is whether

a suitable mix of native species can be

established that provides good year-round

pasture for livestock in the Northern Plains

without requiring continued intensive management and whether desert and foothillsshrub vegetation associations that provide

critical winter range for large game in the

Rocky Mountain coal areas can be established. Another area of concern is the revegetation of spoils high in sodium concentrations, a problem in the Fort Union and

Powder River regions.

30F. X. Murray (cd.), Where We Agree: Report of fhe National

CfNI) Policy Project, V.2 (Boulder, Colo.:” Weslview Press, 1978)

and D. P. Wiener, Hedoiming the West: The C(MI1 lndus fr~’ IIn(l

Surface Mined Land (New York: INFORM, Inc., 1980),
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal ● 311

Reclamation experts differ in the degree of

optimism or pessimism with which they view

the likelihood of success in reclaiming native

ecosystems in the West, but there is general

agreement that it will be a number of years

before the question is resolved. It has been 7

years since Montana passed the first reclamation law in the West that had stringent

standards for revegetation, and as yet no

land reclaimed under that statute has developed a vegetative cover that qualifies for

bond release, 31 A recent study by the Committee on Soil as a Resource in Relation to

Surface Mining for Coal of the National

Academy of Sciences concluded that the 10-

year time period specified in SMCRA for

bond liability after reclamation is completed

may not be long enough to demonstrate success of revegetation in the arid areas of the

West. 32

The issue of revegetation has not had a

significant impact on the availability for

development of Federal coal under existing

leases. The main reason for this is that while

regulatory authorities recognize that uncer-

—

‘1’(’rso[l;]l ((~nlml]l]i(;lll(}[] u I(h []ru( t; I liI;(l(?I), A(imlllisIr:l Ior of [Ill> R(I( I{]mil Iillll I)i~ isl~lrl (If ltl(~ L!(~Ill(III:I I)f>p:l rlm(}ll[

(If Sli I I(I I,ii ri(ls,

X’;) I iljrli]] R[;s(![ir(h {:oun(il. SIIrf(I( r ,lfImnq S{)II, (,’(MII (IH(j

so{ 1(’t}’ (L\r;lst)l Ilst 011 13.(;, N; I IIIJII,I I A(;!(i(’mv Prws, I ’181).

tainties remain concerning the long-term

success of current revegetation practices,

they do not feel that the probabilility of

serious failure is high enough to justify

rejecting a permit application on the basis of

difficult conditions for revegetation. This

judgment is evident in DOI’s decision on the

petition to designate the Alton area in

southern Utah as unsuitable for mining. One

of the arguments made in the petition was

that conditions in the area were too difficult

for successful reclamation because of the

nature of the soil and the arid climate.

However, DOI concluded that revegetation

would be successful.33

Unless there are dramatic failures in revegetation involving state-of-the-art reclamation practices in the next 10 years, it is

unlikely that difficult conditions for revegetation will prevent any existing Federal coal

leases from being developed, However, concern over revegetation has required, and can

be expected in the future to require modification of mining plans. For example, OSM has

concluded that the Black Butte Mine in

southern Wyoming has very difficult conditions for revegetation and has required the

use of a sprinkler irrigation system.

Wildlife Concerns

Concern about the protection of wildlife

habitat has resulted in minimal prohibition

of mining and production of Federal coal, In

southern Wyoming, in the Green RiverHams Fork region, protection of raptor

habitat along outcrop areas has resulted in

some changes to mining plans, including

contributing to the loss of 5 million tons at

the Black Butte Mine (previously discussed

in the Topsoil, Spoil Handling, and Recontouring section). The inability of a North

Dakota operation to demonstrate reclamation of wooded draws that are important

wildlife habitat has led to delay in approval

of a mine plan. Despite conflicts between

proposed mines

winter range for

place in southern

gered species are

posed mine site, it

and designated critical

game, leasing has taken

Wyoming. Unless endanfound to reside on a prois unlikely that significant

amounts of recoverable reserves will be lost

because of concerns about adverse effects on

wildlife.

Statutory Control

Jurisdiction under SMCRA for protection

of fish and wildlife is based on a provision

which states that an operation must:
312 ● An Assessment of Development and Production Potential of Federal Coal Leases

. . . to the extent possible using the best

technology currently available, minimize disturbances and adverse impacts of the operation on fish, wildlife, and related environmental values, and achieve enhancement of

such resources where practicable (sec.515

(b)(24)).

OSM, in developing its final regulations (30

CFR 816.97), interpreted the term “related

environmental values” to mean habitat for

fish and wildlife. Operators are required to:

1) design electric powerlines and other transmission facilities so as to minimize the potential for electrocution of raptors; 2) locate

and fence roads in order to minimize impacts; 3) exclude wildlife from hazardous

waste areas; 4) protect or restore riparian

areas; and 5) refrain from using persistent

pesticides. Where fish and wildlife habitat is

to be a primary or secondary postmining

land use, an operator must select plant

species on reclaimed areas based on their

nutritional value and their value as cover,

and must distribute these species to optimize habitat. Where cropland is to be established after mining, such as in North

Dakota, fields are to be interspersed with

“trees, hedges, or fence rows. ”

Three important Federal wildlife acts also

affect coal mines: the Bald Eagle Protection

Act, the Endangered Species Act, and the

Migratory Bird Treaty Act. Each of these

acts is primarily enforced by the U.S. Fish

and Wildlife Service (FWS). The Bald Eagle

Protection Act requires, among other things,

that bald eagles’ and golden eagles’ nesting

areas not be disturbed. Since many Western

coal mines have eagle nests located on them,

conflicts with this act have occurred. FWS

has permitted the moving of eagle nests in a

few selected instances.

The Endangered Species Act requires that

a determination be made of the occurrence of

endangered species on any proposed mine

site. If adverse impacts from mining activities are projected, an operator must

mitigate or avoid those impacts. To date, no

endangered species, such as the black-footed

ferret or the peregrine falcon, have been

found to be resident on any proposed mine

site. The Migratory Bird Act requires enhancement and prevention of loss of migratory bird habitats. This act, though considered in the mine review process, has not affected mining planning to date. Potential effects include possible requirements to protect

wetland habitat used by migratory species in

North Dakota.

Implications of Wildlife Concerns

for Federal Coal Development

Generally, wildlife concerns have not had

a significant effect on the ability to produce

coal. However, in selected instances, wildlife

concerns are limiting recoverability of reserves and the manner in which coal is

mined. Particularly in southern Wyoming,

mine plans have had to be adapted for the

protection of raptor habitat, especially that

related to nesting areas for eagles. In North

Dakota, mining is being restricted in wooded

draws, a scarce wildlife habitat in the State.

In northwestern Colorado, surface mining

areas conflict with elk habitat; however,

mitigation strategies are being studied so that

recoverable coal is not lost.

Green River-Hams Fork Region

Topography in southern Wyoming is more

diverse than in the Powder River coal basin

or the Fort Union region. Southern Wyoming is characterized by intricate drainage

features, expanses of rock outcrop, development of long ridges, and other topographic

irregularities that serve as good wildlife

habitat. Also, big game migration patterns

vary from winter to summer, and certain

areas of southern Wyoming serve as critical

winter habitat for game. Without such critical winter habitat, game populations would

decrease substantially.

Eagles and other raptors favor rock outcrops or dead trees along drainages for

nests. Eagle populations, particularly golden

eagles, are high in southern Wyoming. Coal

mine operators generally begin mine pit

excavations at or near the coal outcrop. In

many cases, coal outcrops are found in con-
Ch. 10—lmplications of Environmental and Reclamation Issues for the Development of Federal Coal ● 313

junction with linear sandstone outcrops,

Were it not for concern about raptor habitat

on these outcrops, mining methods would

generally use draglines to open the initial

cuts near the outcrop. The boxcut spoil

would be cast over the adjoining outcrop.

Such spoiling would cover the original outcrop and thus would cover or destroy raptor

habitat. State and Federal reclamation agencies have prohibited this kind of mining

method. For example, at the Black Butte

and South Clock mines, requirements to protect outcrop areas have resulted in the opening of cuts further away from the outcrop

than originally planned. Relocation of the

opening pits has also necessitated some

rehandling of spoils.

In the Hanna Field, at the Seminoe No. 1

Mine, concern about raptor habitat may result in decreased reclamation costs to the

company. An eagle established a nest in an

abandoned highwall prior to the highwall’s

scheduled slope reduction. As a consequence, the highwall may not have to be

reduced.

Although not a significant deterrent to

lease development in southern Wyoming to

date, wildlife values may conflict with future

development of Federal coal. With the exception of the Jim Bridger Mine, which is mostly covered by critical habitat for antelope

and mule deer, most mine development in

southern Wyoming has not been located in

areas designated as critical habitat by the

Wyoming Game and Fish Department, However, a number of new proposals for the development of coal mining in southern Wyoming could conflict with the preservation of

wildlife values, and the Wyoming Game and

Fish Department has expressed its opposition to some of these mines. The Red Rim

tract, recently leased, includes over 2,00 0

acres of critical winter range for antelope in

Wyoming. Several other proposed mines,

such as Red Desert and Atlantic Rim, have

significant areas of critical wildlife range,

and a competitive lease application by Idaho

Power Co. in southern Carbon County, Wyo.,

was rejected several years ago because of

wildlife considerations.

Critics of the Wyoming Game and Fish

Department’s opposition to these mine development proposals in southern Wyoming

have argued that data are insufficient to

determine the critical winter range for large

game. OTA was not able to evaluate this

criticism on a site-specific basis, but did compare areas identified as critical by the

Wyoming Game and Fish Department (1979)

with data on wildlife presented in the Southcentral and Southwest Wyoming Environmental Impact Statements (BLM, 1978) .

This comparison suggests that the Department is rather conservative in identifying

areas of concern for large game. For example, the EIS’s identified seven lease s

(Seminoe No. 1, Black Butte, Hanna South,

Cherokee, Long Canyon, Twin Creek, and

South Haystack) as being partly or completely covered by antelope, elk or mule deer

winter range. However, current areas of

critical winter range mapped by the Wyoming Game and Fish Department show

winter range only on the Long Canyon lease.

Mining may affect wildlife values other

than big game herds. Eight developed leases

in the Powder River basin and 5 developed

leases in southern Wyoming are completely

or partly covered by critical habitat for

upland game birds. Several black-footed ferret skulls have been found on or near the

South Haystack and Rosebud Mines in

southern Wyoming. Rare plant species have

been found within or adjacent to lease

boundaries at the Lake DeSmet Block

(Brownish sedge), North Block (Abie s

lasiocarpa-pinus contorta community), and

the South Haystack lease block (malt sagebrush and stemless wild buckwheat).34

North Dakota

To date, mining activities have not been

affected by the presence of any of the endangered wildlife species that exist in the

State. The destruction of woody plants in

draws, a scarce woodland resource found in

the lignite region of North Dakota, has

become a significant issue at Consolidation

34Wyoming Natural Heritage Program, 1980.
314 . An Assessment of Development and Production Potentia/ of Federal Coal Leases

Coal’s Glenharold Mine. The protection of

these areas is mandated by State, rather

than Federal, statutes. The woody draws,

dominated by green ash, box elder, and

American elm, are found throughout the

Glenharold site in draws, valleys, and along

the north- and east-facing slopes of the project area. The understory, consisting of a

mixture of shrub species provide habitat for

deer and other wildlife. Consolidation Coal’s

plans to mine across these draws have resulted in opposition from the State Public

Service Commission and have delayed approval of Consolidation Coal’s mining permit

application. Consolidation Coal must demonstrate the ability to successfully reclaim

these draws before it can gain regulatory approval for mining these areas. With the exception of the Glenharold Mine, other coal

mining operations in the state either contain

no woodland areas or have managed to avoid

mining these areas.

Other Regions

In northwestern Colorado, surface mines

conflict with elk migration and calving areas.

At the Energy Fuels Mine, a calving area is

being mined. The company, in conjunction

with OSM and the Colorado Division of Wildlife, is experimenting with “habitat manipulation.” The company is attempting to recreate offsite the type of calving habitat that is

being lost due to mining. To date, wildlife concerns in this area are not expected to affect

recoverability of coal because of the extensive mitigation strategies available to operators.

Seven of the eight new leasing tracts of the

Wasatch Plateau in Utah have critical winter

range for big game, Since the tracts involve

underground mining, the potential impacts

are substantially less than those associated

with surface mining,

Cultural Resources

Throughout the Western United States,

archeological and historical sites are frequently encountered. Under current statutes

and regulations, a comprehensive survey

must be undertaken before disturbance. If a

site has significant scientific value, it is

studied and the artifacts are generally salvaged, Only at sites with significant architectural or recreational value would a site be preserved and prohibited from mining.

However, according to the OSM staff, cultural resource issues are perceived as a

“thorn in the side ” by industry. Mine

operators are frustrated by the rejection of

cultural resource surveys determined incomplete by OSM and the subsequent delays in

permitting. OSM staff claim that industry

has had difficulty taking the cultura l

resource issue seriously. Often, companies

have contracted with firms or universities

whose work has been found inadequate by

OSM.

35 Future problems may be alleviated if

the OSM promulgates guidelines for adequate surveys.

The San Juan basin area has the greatest

potential for future conflicts between cultural resources and mining of Federal coal.

The Anasazi cultural features of the region

are generally recognized by archeologists to

have great significance and value. Architectural sites abound and several areas are protected by the National Park Service, Conflicts are likely in the Star Lake-Bisti region

where it is likely that coal reserves are found

beneath remnant “outlier” communities to

Chaco Canyon. Expansion of the Chaco Canyon National Monument to include some of

these communities might also affect coal

recovery. No attempt has yet been made to

quantify these conflicts. — 35Shafer, OSM staff ~rche(]logist, personal communication,

1980.
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal ● 315

Statutory Control

Federal requirements for the protection of

archeological and historic resources are

derived from SMCRA, OSM’s authority to

protect these resources comes from other

Federal laws directed at protecting archeological and histori c resources. These

include:

1,

2.

3.

4.

5.

6.

7.

8,

9.

The

The Antiquities Act of 1906 (Public Law

59-209, 34 Stat. 225; 16 U.S.C. 431-433);

The Historic Sites Act of 1935 (Public

Law 74-292, 49 Stat. 666; 16 U.S.C.

461-467);

The Reservoir Salvage Act of 1960

(Public Law 86-523, 74 Stat. 220; 16

U.S.C. 469-469 c);

The Historic Preservation Act of 1966

(Public Law 89-665, 80 Stat, 915; 16

U,S,C. 470);

The National Environmental Policy Act

of 1969 (Public Law 91-190, 31 Stat.

852; 42 U.S.C. 4321-4347);

Executive Order 11593 (May 13, 1971, 36

F.R. 8921);

Archaeological Conservation Act of

1974 (Public Law 93-291, 88 Stat, 174);

The Tax Reform Act of 1976; and

Archaeological Resources Protection

Act of 1979 (Public Law 96-95, 93 Stat.

721: 16 U.S.C. 470).

more important laws are briefly discussed below. -

Under the Historic Preservation Act of

1966, the historic value of any site in the National Register, or eligible for listing in the

National Register, must be taken into consideration when any project utilizing Federal

funds or under Federal permit might adversely affect such a site. Detailed surveys

of proposed mine sites must be undertaken

to ensure that all eligible sites are identified

prior to mining.

The National Environmental Policy Act of

1969 declares that it is the policy of the

Federal Government to use all practical

means, consistent with other essential considerations of national policy, to—among

other things—improve and coordinate Federal plans, functions, programs, and resources with the objective of preserving nationally important historic, cultural, and

natural aspects of our heritage. It directs that

the policies, regulations, and public laws of

the United States shall be interpreted and administered, to the fullest extent possible, in

accordance with the act. Further, it directs

all agencies to use a systematic interdisciplinary approach that will ensure the integrated use of the natural and social sciences

and the environmental design arts in planning and decisionmaking which may have an

impact on man’s environment, It further requires that, on all federally sponsored or

licensed projects which significantly affect

the environment, the responsible official submit an environmental impact statement that

assesses the impact of the proposed action

and any unavoidable adverse environmental

effects (this has been consistently interpreted

to include impacts to archeological and historic resources), sets forth the alternatives to

the project, identifies the long- and short-term

results, and identifies any irreversible and

irretrievable commitment of resources required by the project.

The Archaeological Conservation Act of

1974 specifically provides for the preservation of historical and archeological data

(including relics and specimens) that might

otherwise be irreparably lost or destroyed as

a result of alteration of the terrain caused by

any Federal construction project or federally

licensed activity or program.

Together, these acts require that OSM ensure that all potential archeological or historic sites are identified and salvaged before

mining. Actual preservation of sites will probably only be required where significant structures exist.
316 ● An Assessment of Development and Production Potential of Federal Coal Leases

Economic Impacts of

Federal

Environmental regulations may have an

economic impact on Federal coal production

in two major ways: 1) income foregone by the

leaseholder in terms of profits, and by the

Federal Government in terms of royalties, as

a result of leaving coal in the ground that

would otherwise be recovered if environmental concerns were not considered; and 2)

increased mining costs because of changes in

mining methods necessitated by environmental regulations.

Losses of reserves attributable to environmental regulations can be quantified

and OTA’s evaluation of existing Federal

leases has found that most mines currently

producing Federal coal have not had to leave

reserves in the ground as a result of environmental requirements. Furthermore,

losses of reserves at those mines at which environmental requirements have, or will, prevent mining of reserves usually involve

small tonnages in comparison to the total

reserves in a mine block. In the Powder

River basin, 700 million tons of Federal

reserves under lease are likely to be under

alluvial valley floors, but only a small portion of these Federal reserves (less than 100

million tons) appear to be subject to clear

prohibition against mining. Delays of mine

plan development at two mines because of alluvial valley floor issues (Buckskin, Spring

Creek) have affected another 95 million tons

of the potential 700 million tons. Most reserves under alluvial valley floors can be

mined if adequate reclamation can be demonstrated; such demonstrations are expected.

Regulatory decisions that have resulted in

prohibitions have affected a total of 29 million tons (see table 92), and the recovery of

perhaps another 200 million tons of Federal

reserves may be delayed or otherwise affected by regulatory decisions. In comparison

to total leased Federal reserves (16.5 billion

tons), these reserves are small.

Environmental Regulations on

Coal Production

Analysis of the impact of environmental

regulations on the cost of mining coal is difficult because of both conceptual and practical problems in quantifying the impact of

such regulations. A recent study that analyzed the economics of reclamation has identified a number of the difficulties involved in

quantifying the cost impacts of environmental regulations as follows:36

1.

2.

3.

4.

A conceptual problem with cost-benefit

analysis of reclamation is that costs are

relatively easy to consider in monetary

terms (i.e., costs imposed on coal operators and consumers of coal), but costs of

not reclaiming mine sites (i. e., the benefits of reclamation) are often difficult, if

not impossible, to measure in monetary

terms.

Reclamation costs are highly site-specific. For example, earth-moving costs associated with reclamation may vary by

a factor of 3 or 4, and since these costs

may be as much as 90 percent of reclamation costs, such variations significantly affect total cost at a site.

Inflation and questions of cost allocation, such as the extent to which earthmoving costs should be considered mining or reclamation costs, make precise

measurement of reclamation costs difficult.

Coal operators are generally unwilling

to disclose the detailed costs of mining

and reclamation for business reasons,

so most cost data available is based on

hypothetical information from engineering studies, or publicly financed experimental projects which often do not create optimum conditions for achieving

the least cost in production.

36National Research Council, Surface Mining: Soil, Coal and

Society (Washington, D. C.: National Academy Press, 1981).
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal ● 317

Table 92.—Summary of Impacts to Federal Recoverable Reserves From

Environmental and Reclamation Considerations

Federal

reserves

affected

Location of (millions

Issue area Specific issue affected area of tons) Effect

Air resources Expansion of mine production rate in a Rosebud Mine, 1.5 ret/y U , effect would be

nonattainment area Colstrip, Mont. after 1985 to limit production

or about rate, not prohibit

30 mt of any mining areas

reserve

Permitting of additional powerplants West-central <100 U , improved air

near class I area where S02 levels for ex- North Dakota quality modeling

isting and permitted but not constructed techniques being

facilities are currently predicted to be at developed

maximum PSD level. The additional

powerplants would be fueled by lignite

mines in the vicinity.

Lands unsuitable Impacts of coal mining will damage Alton Coalfield, 24 Ap -on portion of

for mining important esthetic values of Bryce southern Utah proposed mine area

Canyon National Park designated as

unsuitable; rest

of leasehold

unaffected.

Water resources Subsidence of mine will divert surface

and ground water and adversely affect

other uses

Alluvial valley floor (AVF) in areas

significant to farming

Developed mines with stream valleys

under study as potential AVF where

mine plan development has been

delayed

Designated AVF in developed mines.

Valleys not significant to farming. Mine

plan development affected

Potential alluvial valley floors which existed in developed mines prior to

passage of SMCRA. Reclamation plans

must still be approved

Potential AVFS in undeveloped coal

lease areas

Mt. Gunnison Mine,

west-central Colorado

CX Ranch leases Montana portion of the

Powder River basin

Powder River basin

Buckskin and Spring

Creek mines

Powder River basin

Eagle Butte, Rawhide,

Coal Creek mines

Powder River basin

Big Sky, East Decker,

Eagle Butte, Wyodak,

Belle Ayr, Jacobs

Ranch and Black

Thunder mines

Powder River Basin

23 U, approval likely if

mine will buy or

replace senior

water rights

affected.

<100 Ap uncertain

95 D, mining of valleys

expected

61 U, mining of valley

expected

240 U, mining of valleys

expected

219 U, mining of most

valleys expected

Spoil handling Limitation on out-of-pit spoil area Black Butte Mine 5 Ap

and protection Green River-Hams Fork

of raptor habitat region

Limitation on out-of-pit spoil area Green River-Hams Fork 50 Possible problem;

region resolution

uncertain

Mining in environmentally sensitive Glen Harold Mine, west- 29 D

woody draws central North Dakota

‘Total Federal reserves under lease are 16,500 million tons,

‘Ap-absolute prohlb!t!on; D-delay In approval; U-unresolved

‘Jurlsdlctlon hes with the Montana Department of Health and Enwronmental Sciences.

‘Jurisdiction Iles with the North Dakota State Department of Health

Vleclslon made by the Department of the Inter[or, 1960, Declslon under appeal to Federal courts.

CJur!sdictlon Iles with Colorado Department of Natural Resources and U S Office of Surface Mining.

‘Under sec. 510(b)(5) of SMCRA. Jurisdiction Iles with the Montana Department of State Lands. The department has ruled that the alluwal valley floor is significant

to farming. The lessee has asked the department to reconsider Its declslon,

‘Jurlsdict[on lies with Montana Department of State Lands (Spring Creek) and Wyoming Department of Enwronmental Quallty (Buckskin)

‘Jurlsdlctlon hes wfth Wyoming Department of Enwronmental Oual[ty

‘“Lead declslon made by OSM.

“Permit application denied by North Dakota Publlc Service Commlsslon on grounds that plans for reclamation of wooded draws were Inadequate
318 An Assessment of Development and Production Potential of Federal Coal Leases

Table 93 summarizes “typical” reclamation cost estimates in 1978 dollars in the

West, Midwest, and Appalachia, showing

costs before and after passage of SMCRA. It

is evident that both on a per-ton and a peracre basis, reclamation costs are significantly less in the West than in the Midwest

and Appalachia, The largest part of the cost

increases in the West attributable to

SMCRA is the 35 cents/ton fee for the abandoned mine reclamation program, which is

not strictly an increase in production costs,

but rather is a tax to pay for rectifying the

environmental costs of past mining practices. When this reclamation fee is subtracted from the estimated total reclamation

costs in table 93 to reflect cost increases attributable to changes in mining method,

“typical” reclamation costs in the Midwest

are 8 times higher than in the West and more

than 20 times higher in Appalachia than in

the West. The main reason for this large difference in cost is that much thicker coal

seams are mined in the West, and the large

size of many mining operations allows conTable 93.—Summary of “Typical Reclamation Cost

Estimates (in 1978 dollars)a

$/ton $/Acre

Mid- b Mid- b

Range point Range point

1. Pre-Public Law

95-87 (SMCRA)

a. Appalachia. . . . . . $3.23-7.16 $ 5.19 $2,676-14,915 $9,460

b. Midwest (rowcrop) 1.40-2.73 2.07 7,000-10,000 8,500

c. West . . . . . . . . . . . 0.08-0.39 0.24 1,899- 8,186 5,043

2. Incremental cost

with Public Law

95-87 (SMCRA)

a. Appalachia. . . . . . — 5.24 — —

b. Midwest (rowcrop) – 1.80 — —

c. West . . . . . . . . . . . — 0.57 – —

3. Estimated total reclamation costs

with Public Law

95-87 (1 +2)

a. Appalachia. . . . . . — 10.33 – —

b. Midwest (rowcrop) — 3.87 – —

c. West . . . . . . . . . . . — 0.81 – —

a

Thls table presents cost estimates developed by the NAS Committee on Soil

as a Resource in Relation to Surface Mining for Coal, based on a synthesis of

all studies available as of 1980. However, until more experience is gained with

the reclamation provisions of Public Law 95-87, cost estimates will remain

uncertain. The NAS report notes that these cost estimates are probably higher

than costs will be in the long run.

b

The midpoint values for $/ton and $/acre were derived independently from the

two sets of ranges and thus are not directly comparable to each other.

SOURCE: National Research Council, Surface Mining Soil, Coal and Society

(Washington, D.C National Academy Press, 1981)

siderable economy of scale. The main reasons incremental costs in Appalachia and

the Midwest are greater with Public Law

95-87 compared to the West is that water

pollution control is much more difficult in

Appalachia and in the Midwest. Also, prime

farmland reconstruction requirements require a larger relative change in materials

handling than in the West.

On a site-specific basis, Federal coal may

experience significant cost increases because of environmental regulations, but such

situations appear to be the exception rather

than the rule. Two areas where such impacts

may be significant on a site-specific basis are

the extensive hydrologic data collection and

analysis that is required in Public Law 95-87

for permit applications, and requirements

necessitating changes in spoil handling procedures. The effects of these extensive hydrologic data collection and analysis requirements are greatest on small operators or companies with limited financial backing.

Although OSM’s Small Operator Assistance

Program offsets costs for the smallest size operations, somewhat larger mines may have

difficulty conducting the required studies.

However, comparison of the detail of mine

plan data submittals to OSM indicates that

considerable variation exists in the detail of

hydrologic information considered acceptable. Mine operations in the Northern Great

Plains are required to submit more comprehensive data than mines in other areas.

There are several examples of the impacts

of requirements under SMCRA concerning

spoil handling. The Decker Coal Co, has

claimed that the change in mining methods

necessitated by prohibition of placing spoil

in an intermittent stream valley adjacent to

their East Decker mining area increased the

cost of mining by several dollars per ton.

These costs were passed on to the consumer

in the form of increased coal prices. At present, the city of Austin, Tex., is suing the

Decker Coal Co., challenging the validity of

the increased prices. The case has not been

resolved. At the Black Butte Mine in southern Wyoming, restrictions on placement of

out-of-pit spoils has required significant
Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal 319

modifications of the original mining plan,

but these modifications apparently have not

jeopardized the viability of the mining operation,

In summary, OTA has identified a number

of examples on existing Federal coal leases

where there are demonstrable economic impacts on mining because of environmental

regulations, both in terms of revenues foregone because of the necessity to leave coal in

the ground, and through increases in mining

costs. However, to date, and in the foreseeable future, total reserves lost through such

requirements appear to be relatively small,

and OTA has not identified any situations

where the overall viability of a mining operation has been jeopardized because of increased costs attributable to environmental

requirements. Significant modification of

mining plans to accommodate environmental concerns is not uncommon.

The primary reason that environmental

regulations appear to have had a relatively

small impact on Federal coal production is

that costs resulting from these regulations

are small when compared to other major

coal-producing regions. Current requirements concerning out-of-pit disposal of

spoils have the greatest relative impact on

mining costs in southern Wyoming, and

northwest Colorado, where the mining of

dipping multiple coal seams creates difficult

conditions for surface mining. Improved

spoil handling methods through the reorientation of pits and expanded use of truckshovel combinations rather than draglines

may lead to resolution of many of these problems, but at the present time it appears that

SMCRA has reduced the competitive position of coal mined in southern Wyoming

compared to coal from the Powder River

basin, although this change is difficult to

quantify.
CHAPTER 11

Mining Technology

\
Contents

Page

Introduction and Overview. . ............323

Review of Coal Mining Technologies

Currently Used at Federal Mines. . ......325

Surface Mining Techniques. . .....,........325

Underground Mining Techniques, ,... .. ...328

Analysis of Mining Technology Problems. .333

Recovery Ratio. ...,,,,.. . ..,.,,,........333

Production and Productivity, ,,. . ..,......,334

Environmental . . . . . . . . . . . . . . . . ..........335

Roof Support. . . . .................,...,,.335

Review of Technology Developments in

Europe and the Western United States. ...336

Comparison of Mining Conditions in Europe

and the Western United States. . ..........336

New Equipment Developments. . . . ..,......337

Considerations for Using Improved

Longwall Mining Techniques on Federal

Coal Leases . . . . . . . . . . . . .............339

Page

Capital . . . . . . . . . ........................339

Labor . . . . . . . . . . ........................341

Production and Productivity. . . . . ....,.....342

Environmental . . . . . . . . ..................343

Health and Safety. . ...............,.,,,..343

List of Figures

Figure No, Page

49. Western Strip Mining. ....,.,, . .....,..327

50. Truck and Shovel Terrace Pit Mine With

Two Overburden Benches and Two

Coal Seams. . . . . . . . . . . . . . . . . .........328

51. Room-and-Pillar Underground Mining. ..330

52. Longwall Mining System . . . . . . . . . . . . . . .332
CHAPTER 11

Mining Technology

The Federal Coal Leasing Amendments Act

of 1976 charged OTA to assess the feasibility

of the use of deep-mining technology on

leased areas. With the passage of the Surface Mining Control and Reclamation Act of

1977 congressional interest in the study of

deep underground mining technology shifted

its principal focus from a concern for the protection of surface resources to a concern for

maximum economic recovery and the conservation of the resource. Lessees are required

to mine all coal that can be extracted economically and within the limits of safety and

technology so that coal reserves are not left in

the ground where they can deteriorate and

not later be retrieved. Underground mining

methods usually leave a significant portion of

the coal reserve in the ground, Some underground mines recover only 30 to 50 percent of

the minable resource, although, averaged

over all underground mines in the United

States, the recovery ratio is 63 percent. Surface mines, on the other hand, typically recover from 70 to 90 percent of the minable

resource.

Introduction and Overview

This chapter summarizes OTA’S review of

the mining technologies currently in use on

Federal leases and the potential for commercial mining technologies to extract Federal

coal reserves from deep underground seams.

The chapter discusses:

●

●

●

●

three surface mining techniques that are

used in the West: 1) area strip, 2) open

pit, and 3) terrace pit;

two methods of underground mining in

the West: 1) room and pillar with continuous miners, and 2) longwall mining;

recent underground mining technology

developments in Europe and the Western United States that could affect the

production of coal from Federal leases;

and

factors affecting the choice of these underground coal mining technologies in

the West, including: 1) capital requirements, 2) resource recovery, 3) labor,

4) production and productivity, 5) environmental impacts, and 6) health and

safety.

A number of technological innovations

have been developed recently for underground coal mining, but the greatest nearterm commercial promise for the expansion

of underground coal mining in the Western

United States appears to be the implementation of longwall mining techniques developed

in Europe. Although longwall mining is used

virtually exclusively to produce coal from underground mines in Europe, it accounts for

only 5 percent of annual underground coal

production in the United States. Longwall systems have been used in several European

countries to extract most of the reserves in

30-ft thick seams at depths of 3,000 ft. In the

United States, on the other hand, such recovery of thick, deep underground seams is still

in the development stage,

Some of the largest underground mines in

the West, including several that produce Fed323
324 . An Assessment of Development and Production Potential of Federal Coal Leases

eral coal, have recently converted to longwall

mining. Longwall mining is also scheduled to

be installed at other large underground operations in the West. For these reasons, much

of this chapter compares longwall mining

with the dominant underground mining technology in the West—room-and-pillar mining

with continuous miners.

Federal coal reserves in the Rocky Mountain province provide the greatest near-term

potential for the application of longwall mining. The first successful longwall operation in

the West was the York Canyon Mine of Kaiser Steel located near Raton, N. Mex. Although the York Canyon Mine is not located

on Federal leases, New Mexico provides opportunities for the implementation of longwall

mining on Federal land.

Longwall systems have also been introduced in several mines with Federal leases in

the Book Cliffs Field of central Utah. New

concepts are now being implemented and

tested to extract coal from thick seams and to

mine steeply dipping seams at two mines

with Federal leases in Colorado—the Coal Basin Complex of Midcontinent Resources and

the Snowmass Mine of Snowmass Coal Co.

These projects are likely to encourage the use

of longwall mining to extract other thick or

steeply pitching coal seams in the area.

Longwall systems are also scheduled to be

implemented at two mines with Federal reserves in the Hanna basin of southern Wyoming. In 1981 a longwall system will be introduced at Carbon No. 1 Mine. This system

will be the highest longwall unit (14 ft) in the

West. Much of the area overlying this operation has already been surface mined. In 1984

Energy Development Co. plans to use a longwall unit at the Vanguard No. 2 Mine.

In the Powder River basin of Wyoming and

Montana, where coal is mined inexpensively

from large surface mines, it may be technically possible to extract thick underground

seams. However, the resource information on

deep underground coal deposits in this area

is inadequate to assess the economic feasibility of this. The comparatively low-Btu value of

coal in the Powder River basin and the very

large, inexpensively minable surface deposits

in the basin are economic barriers to underground mining in this region at least throughout this decade.

A potential method for recovering energy

from coal is through in situ gasification of

deep coal seams that cannot be mined by surface mining methods. The thick coal seams in

the Powder River basin are considered attractive in their potential for in situ gasification, and two separate small-scale test sites

have been developed in Campbell County,

Wyo., one by the Department of Energy (Hoe

Creek Site) and another by ARCO Coal Co. In

situ gasification in this country is still in early

experimental stages. A major disadvantage

with in situ gasification is that it does not produce pipeline quality gas. Thus, unless there

are industries nearby that could use low- or

medium-Btu gas, a surface facility must be

constructed to upgrade the gas to pipeline

quality or perhaps to convert it to methanol.

The National Coal Policy Project concluded

that even if in situ gasification experiments in

the Powder River basin are successful, the

distance of the region from centers of demand is likely to limit application of the technology. 2 Considering the present state of development of the technology, in situ gasification is not likely to be used commercially in

the Powder River basin until the mid-1990’s

at the earliest.

To date, the experience with longwall mining both in Europe and the Western United

States points to significant potential advantages in terms of increased resource recovery, higher production and productivity, reduction in the cost of labor and frequently in

the overall costs per ton of coal, the control of

differential subsidence on the surface, and a

reduction in the number of unintentional roof

falls at the face. One should not conclude,

however, that longwall mining will realize

these advantages in all underground mining

environments or that longwall mining can be

2F. X. Murray (cd.), Where We Agree: Report of the National

Coal Policy Project (Boulder, Colo.: Westview Press, 1978).
Ch.. 11—Mining Technology ● 325

used profitably and efficiently in all of the

deep Federal coal seams in the West. The decision to implement a particular underground

mining technology at a particular site can be

made rationally only after the completion of

comprehensive sit e-specific geological,

engineering, economic, and environmental assessments,

In spite of the positive experience with

longwall mining both in Europe and the

United States, many underground coal producers in the West will be reluctant to install

this mining technology because of its high initial capital cost. The cost of a typical longwall

installation is $9 million; total capital cost of

the technology per ton of coal mined over the

life of a system is about $1,50. This compares

to a capital cost of $0.40/ton of coal mined

over the life of the system for the typical

room-and-pillar operation in the West, using

continuous miners. In many cases, the savings in labor and the other advantages of

using longwall mining may not be sufficient to

offset this cost differential. Nevertheless,

longwall systems are likely to figure prominently in mining underground Federal coal

reserves in several areas of New Mexico,

Utah, Colorado, and Wyoming.

Review of Coal Mining Technologies Currently Used

at Federal Mines

Although underground mining was, at one

time, the principal mining method in parts of

Colorado, Montana, Wyoming, and North

Dakota, and continues to be so in Utah, surface coal mining now predominates in most

areas of the West. Because coal seams are

generally thicker and nearer the surface in

most Western States, compared to the East,

they are more amenable to recovery by surface mining techniques. Surface mining

operations are usually well-suited to the

many areas of the West that have not yet experienced the extensive development of

towns, cities, highways, and railroads characteristic of the Midwest and the East.

Surface Mining Techniques

Surface mining of coal is characterized by

the use of large, capital-intensive and efficient mining equipment. First, the overlying

soil and rock layers (overburden) are removed. The coal is then fractured with explosives or machines, and loaded onto vehicles for haulage from the mine site. Finally,

the disturbed land must be fully reclaimed.

Principal considerations in the selection of

surface mining and reclamation techniques

and equipment include the thickness and

character of the overburden, the dip of the

seam, the thickness and number of recoverable seams, and the physical and chemical

characteristics of the coal. The three surface

mining techniques most widely used in the

West are area strip, open pit, and terrace pit.

Area Strip

Area strip is the principal surface mining

technique used in the United States. The technique was perfected in the coalfields of

Illinois, Indiana, Kentucky, and Ohio. The

capacity of a dragline, the machine used to

remove the overburden in strip mining, varies

in size from 10 to over 200 cubic yards. Many

Eastern mines use stripping shovels instead

of draglines; and stripping shovels currently

are being used successfully at several strip

mines in the West such as the Rosebud Mine

in the Montana portion of the Powder River

basin which produces Federal coal.

Area strip mining proceeds by first making

a box cut into the earth to uncover the initial

strip of coal that is to be mined. The strip of

coal uncovered will vary from 100 to 200 ft in

width and from one-quarter to several miles

in length. The actual size of the cut will be determined by the thickness of both the over-
326 ● An Assessment of Development and Production Potential of Federal Coal Leases

burden and the coal and the designed production rate of the mine. After the coal has been

mined from the bottom of the box cut, the

overburden covering the next strip of coal is

removed and placed in the void left by the

mining of the preceding strip of coal. Mining

proceeds with succeeding parallel stripping

cuts until the property limits of the mining

area are reached (see fig, 49).

Even the largest draglines have limits on

how much overburden they can remove from

a given operating location. A single dragline

can generally remove overburden to depths of

100 ft. However, it is possible to extend the

stripping limits to as deep as 200 ft by teaming the principal stripping dragline with additional equipment such as another dragline, a

stripping shovel, a bucket-wheel excavator,

or fleets of trucks and shovels or scrapers.

This additional equipment will increase the

total overburden removal costs and can be

justified only by significant increases in the

amount or quality of the additional coal that

can be recovered.

Open Pit

The open pit mining technique currently

used in the Western United States was initially developed in the metal mining industry.

An open pit mine is characterized by a series

of benches, the number of which increases as

the mine is deepened. Each one of these

benches is 40 to 50 ft in height, and excavation can proceed to depths of hundreds or

thousands of feet.

The use of an open pit for overburden removal is justified only where there is an exceptionally thick seam or a series of seams

that can be mined in sequence, The single

seam mines can be found in the brown coalfields of Germany, but only the multiseam

mines are found in the Western United

States. The best example of the latter type is

FMC’s Skull Point Mine located on Federal

leases in southwestern Wyoming.

Equipment used for overburden removal in

an open pit coal mine is currently limited to

truck and shovels or scrapers. The truck and

shovel or scraper approach typically provides the most flexibility in the development

of a bench system and the mining of coal

seams. However, lower overburden removal

costs might be achieved if rail or conveyor

haulage systems, similar to those used in the

copper mines of the Southwestern United

States, could be implemented in open pit coal

mines,

Terrace Pit

The terrace pit system for surface coal

mining has come into use only during the last

5 years (see fig. 50). This method, which essentially combines the area strip and open pit

techniques, is used in the thicker coal beds

of northeastern Wyoming and southeastern

Montana. In these two areas, the removal of

overburden thickness in excess of the 100-ft

stripping limit of a dragline is justified economically by the mining of exceptionally thick

coal seams.

Terrace pit mines have a system of

benches similar to those designed for open pit

mining. However, the overburden depths that

can be removed economically by the terrace

pit method are currently limited to between

200 and 300 ft. so that the maximum number

of benches will be about seven, Also, unlike

the open pit system, the terrace pit system

does not remain in the same location but

rather moves across the property in a manner

similar to area strip mining. The overburden

that is removed from one side of the pit is

hauled to the other side of the pit and dumped

where the coal has already been mined. As a

result, the overburden removal operation of

the terrace pit moves constantly in a specified direction, usually down dip during the

initial years of mining. The removed overburden is replaced behind the mining operation at a distance determined by the number

and size of the benches.

Equipment used for overburden removal

and coal extraction in the terrace pit system

typically consists of trucks and shovels, although draglines are used at several such

mines in the West, including the Rawhide
Ch. 11—Mining Technology ● 327

Figure 49.—Western Strip Mining

.

. “

.’ “!

.
328 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 50.—Truck and Shovel Terrace Pit Mine With Two Overburden Benches and Two Coal Seams

SOURCE U S Bureau of Mines

Mine which is located on Federal leases in

the Wyoming portion of the Powder River

basin. A maximum of two to three shovels will

typically be assigned to each overburden

bench together with a sufficient number of

trucks to haul the material excavated by the

shovels to the other side of the pit, The number of shovels used in this operation is determined by the length and the rate of development of the pit. As in open pit mining,

other forms of excavation and haulage equipment, such as bucket-wheel excavators and

conveyors, are being considered for terrace

pit mining. However, the dynamic aspect of

terrace pit mining makes it more difficult to

use equipment that does not have the mobility

characteristic of trucks and shovels,

Underground Mining Techniques

Surface mining is generally preferred by

mine operators over underground mining.

The reasons for this preference include

higher percentage of coal recovery, higher

labor productivity, lower operating costs, and

fewer safety and health hazards. Also, some

environmental impacts of underground mining, such as subsidence, acid mine drainage,

and the interruption of aquifers can be

greater than those of surface mining, All of

these factors are important and will be discussed in more detail later in this chapter. In

cases where coal seams are too deeply buried

to be recovered economically using surface

mining techniques, it is likely that the coal
Ch. 11—Mining Technology “ 329

will be mined using one of the two underground mining techniques discussed below,

Furthermore, several companies mining Federal coal in the West have had to shift from

surface to underground mining as their surface minable reserves became exhausted.

Access to underground mine workings will

be by one of three methods. If the coal seam

outcrops at the surface it is possible to mine

directly into the seam from the surface; this

type of mine is referred to as a drift mine.

Most underground mines in the West are

drift mines. If the minable seam is located

under shallow cover then it may be possible

to reach the coal bed through the use of an inclined drift (slope); this type of mine is referred to as a slope mine. If neither of these

forms of access is possible, then it is necessary to sink a vertical shaft from the surface

to the minable seam; this type of mine is referred to as a shaft mine.

The initial capital cost for developing a

slope mine may be slightly more than that for

developing a shaft mine because, for the

same overburden thickness, a slope is approximately three times longer than the depth

of a corresponding vertical shaft. However,

over the long term, a slope mine has lower

operating costs because of the relatively low

cost to move men and materials into the mine

and coal out. A slope mine is typically more

economical when the overburden is less than

500 ft; a shaft mine when it is over 1,000 ft. In

the 500- to 1,000ft range a site-specific economic evaluation is usually necessary to determine what type of mine should be

developed.

Room and Pillar

In the room-and-pillar method, the voids

left by removed coal form the rooms and the

unmined coal forms the pillars (see fig. 51).

The pillars are left in place to support the

weight of the overlying strata. The principal

factors determining the percentage of coal

that can be removed from a seam are the

thickness of the seam, the strength of the

seam and the confining rock strata, the presence of faults or fractures, and the depth of

the seam. The deeper the seam, the greater

the weight of overlying rock that must be supported; thus the size of the pillars generally

will be greater for deeper mines.

The extraction of the coal in a room-andpillar mine is accomplished using either

conventional mining or continuous miners.

Conventional mining declined in popularity

during the 1960’s and most of the 1970’s but

continues to account for 35 to 40 percent of

the underground coal production in the

United States. The first step in conventional

mining, which is more labor-intensive than

continuous mining, is to cut a slot into the

seam with a machine that looks like a large

chain saw mounted on a large, rubber-tired

vehicle (see fig. 51), Holes are then drilled

into the face and loaded with explosives.

After blasting, the coal is fragmented and

allowed to drop on the floor of the mine. A

roof-bolting machine is used to drill vertical

holes into the roof and install bolts for roof

support. A loading machine is then used to

gather up the coal and to load it into rubbertired shuttle cars which haul the coal from

the loader to a conveyor belt for transport out

of the mine. In a few instances, a series of

bridge conveyors are used in place of the

shuttle cars.

Continuous miners are equipped with a rotating head with cutting bits that is used to

break coal from the face (see fig. 51). The design of the cutting head and the form of rotation will vary with the manufacturer, but all

continuous miners typically break the coal

from the face and load it directly into shuttle

cars or onto conveyors. As in conventional

mining, a roof-bolter is used to install bolts

for roof support. The labor requirement for

continuous miners is at least 10 percent less

than that of conventional mining systems.

While continuous miners generally are more

efficient, conventional mining can be more

readily adapted to certain difficult mining

conditions and to large inclusions in the

coalbed.
330 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 51 .—Room-and-Pillar Underground Mining

I Conventional mining I I

I Continuous mining I

Roof bolting(continuous and conventional)

Plan v iew (contin uous and conventional showing coal support pillars)

SOURCE Office of Technology Assessment
Ch. 11—Mining Technology ● 331

Longwall Mining

The basic longwall system consists of a set

of supports that are located parallel to the

mining face, a conveyor system that runs

along the base of the face, and a machine that

moves back and forth along the face, cutting

the coal and loading it onto the face conveyor

for transport out of the face area (see fig. 52),

In addition, continuous miners are required

for the development of longwall panels. The

length of the mining face will depend on a

number of factors (discussed in more detail

later in the chapter), but will generally range

from 400 to 650 ft, with 500 ft being typical.

The basic longwall support system consists

of hydraulic rams positioned vertically to support the roof when they are extended. Depending on the size of the mining operation,

the rams are arranged into one or more pairs

located in the plane perpendicular to the

face, When more than one pair of hydraulic

rams are used, they will be structurally connected to one or more other pairs to ensure

lateral stability. The exact configuration of

the rams and the method of interconnecting

them will vary according to model or manufacturer. For additional support, a shield

support system may be employed. This system

uses a protective canopy as a structural part

of the support mechanism to protect miners

working along the face from roof falls.

The longwall chain conveyor system is

mounted on the mine floor in front of the base

plate used for the roof support rams or on

separate supports, In either case, the conveyor assembly must be flexible to allow for

bending as the supports are advanced one

after another to keep pace with the advancing face. As the supports are advanced, the

roof is allowed to collapse behind them. The

typical conveyor mechanism used on a longwall chain conveyor system has a series of

horizontal bars or flights that are located

perpendicular to the longitudinal axis of the

conveyor, These flights are spaced approximately 1 ft apart and are fastened together

with chains connected to their ends or centers, The chain-connected flights move along

the top and bottom surfaces of the chain conveyor system through the force of a gear

mechanism which engages the chain. Sideboards are mounted along the top surface of

the system so that coal falling into the trough

formed by the sideboards will be pulled along

by the chain-driven flights.

The machine used to cut the coal from the

face and load it on the face conveyor is

either a plow or a shearer. Plows are favored

in West Germany because of the thin coal

seams and soft coal deposits in that country.

The cutting action of a plow is just as the

name indicates. The height and the depth of

the cut will be limited by the amount of pulling force that can be applied to the plow. In

the case of shearers, however, the cutting

force comes from a rotating drum with cutting bits mounted on it. The diameter of the

drum will typically be somewhat greater than

one half the face height so that two passes of

the drum will be required to mine the full

height of the face. The top half of the face is

mined first. Since a shearer drum is designed

to operate only in one direction, a doubleended shearer makes it possible to cut the upper and lower portions of the face without

having to return the shearer to the same end

of the face to begin each cut.
332 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 52.—Longwall Mining System

Elevation view

Overburden

Mining Conveyor

machine

Plan view

Conveyor

Suppo

Slumped

overburden

I

Mining

rts machine

Tunnel

L Air Main tunnel

SOURCE Off Ice of Technology Assessment
Ch. 11-Mining Technology ● 333

Analysis of Mining Technology Problems

The preceding descriptions of surface and

underground mining techniques currently in

use on Federal coal leases are very general.

They are intended to introduce the reader to

the basic differences between surface and

underground coal mining. This section will

discuss in more detail the problems that are

encountered in using these coal mining technologies. These problems will be illustrated

with examples from mines currently operating on Federal coal leases.

Recovery Ratio

Recovery ratio is the percent of minable

coal recovered from the seam. Generally, the

recovery ratio for surface mining will be

higher than that for underground mining because some coal must be left in place in underground mines to support the roof and limit

surface subsidence. According to the Bureau

of Mines, the average recovery ratio from all

surface mines in the United States is 83 percent; for underground mining the national

average is 63 percent.

Thick single-seam surface mines often have

recovery ratios in excess of 90 percent. For

example, the thick-seam mines of the Powder

River basin of Wyoming are achieving recovery ratios of 95 percent. The reason for this is

that the coal lost at the seam boundaries in a

thick seam is a small fraction of the total coal

being mined. The operator often does not recover 6 to 12 inches of coal at the upper and

lower seam boundaries, because this coal

usually contains significantly more mineral

matter than the remainder of the seam, The

proportionate amount of the seam thickness

lost is much less for a 50- or 100-ft thick seam

than it is for a 5- or 10-ft thick seam.

A multiseam surface operation will often

have a lower recovery ratio than a singleseam mine because a certain thickness of

coal is lost for each boundary between a coal

seam and the surrounding material. Hence,

even though the cumulative thickness of the

seams in a multiseam mine approaches or exceeds the seam thickness in many single-seam

mines, the percentage of coal not recovered

will be greater.

Recovery ratios in surface coal mines also

can be adversely affected by such factors as

extreme seam dip, faults, and characteristics

of the overburden material that interfere

with stripping operations. Such problems are

common in the surface mines of northwestern

Colorado and southwestern Wyoming. However, mines such as the Colowyo and the

Trapper mines encounter a combination of

these problems but still achieve recovery

ratios in excess of 80 percent. Seam dip at the

Canadian Strip Mine in north-central Colorado is so steep that it has been necessary to implement what is essentially a contour strip

operation. Here a bench is cut into the hillside and all of the coal in the bench area is

mined. Even though the ratio of waste material removed to coal mined is on the order of

15 or 20 to 1, only a small percentage of the

coal is not recovered.

The recovery ratio for underground mining

will usually be less than for surface mining as

a certain amount of the coal must be left in

place around access facilities such as shafts,

slopes, drifts, main entries, and submain entries. Additional coal is also lost that is left in

boundary pillars around the perimeter of the

property and in pillars in the mined out areas

to support the roof and prevent or lessen subsidence of the surface.

Recovery ratios for room-and-pillar mines

will vary from a low of 20 percent to a high of

80 depending on the completeness of the secondary recovery of pillars from the mining

panels. The average recovery ratio for all

room-and-pillar mines in the country is 62

percent. Several equally important factors

determine the recovery ratio of these mines

including the dip of the seam, the presence of

igneous or other intrusions in the seam, faults

(vertical displacements in the seam), and the

depth of the seam. The depth of the seam is

important in the West where many mines are
334 An Assessment of Development and Production Potential of Federal Coal Leases

2,000 to 3,000 ft deep. The greater the depth

of the seam, the more overlying rock strata

that must be supported by pillars left around

access facilities and in the mining areas. To

avoid failure of these support pillars due to

excessive loading, they must have larger

cross-sectional areas, If the pillars ar e

larger, then the amount of coal that can be recovered will be correspondingly less. Support

problems caused by the depth of the seam can

be aggravated by the presence of faults, poor

competency of the rock strata forming the

floor and roof of the mine, and excessive

water. Several of these conditions are found

at mines with Federal coal leases in western

Colorado. Conditions became so severe at

U.S. Steel’s Somerset Mine that one of the

mining levels had to be abandoned, Stresses

induced in support pillars at this mine caused

the pillars to fail explosively, However, according to a spokesman for the Bureau of

Mines, this problem has been brought under

control at Midcontinent’s Coal Basin complex

in Colorado,

Recovery ratios for longwall mining range

from a low of 50 percent to a high of 80. The

average recovery ratio for all longwall mines

in the country is 75 percent. * Longwall mining generally results in higher recovery ratios

than those achieved in room-and-pillar mining when the latter does not include full extraction of the pillars. A good example of the

recovery ratio increases which can be expected from longwall mining when compared

to room-and-pillar mining is found in the Deer

Creek-Wilberg mine complex of Utah Power &

Light in central Utah. These mines had

operated a s room-and-pillar mines with

recovery ratios of 55 to 60 percent. The com-

‘Pcrsf)nal [:(JmlmuIlic;i]liorl to O’1’A from John hf. Karhnak,

hlarmger of (Jround Contro]. Division of Minerals. Health &

%lfety ‘1’echnology, U.S. E3urci~u of hlines, Mar. 31, 1981.

*’rhc average recovery riiti[) ft}r sh~)rtwail mining in th e

United Stales is even higher [84 percent). As in longwall mini nx, short w{] U mining uses ch(x:ks for roof” support. However,

ronlinuous” m incrs are used in short w:) II opera t ions 10 mine {he

c(N]1 ;+nd haul[~ge is done bv shut tlc (:[~r rather I han with a continuous (xlnvey(]r. Shurtwall mining may he used in the future

in the 14’es t in ciiscs where :) 600-fl fi~(’e is not ava il[lble. PerS( ~n;{ I (Jomm un ir:i t ion t( ) ()’I’A from I):\ n iel J. Sn\’der, 111, Pres ident. (I()]{)rild~J-Wcs tnlf)rt; ltlrl(i. In(’., June 15. 1981.

pany has already installed one longwall

system and plans to install a second. The

recovery ratio for the longwall system at this

mine is approximately 80 percent.

Production and Productivity

Although there is no hard and fast relationship between the production rate for a mine

and its rate of labor productivity, it is often

true that those mines with high production

rates also will have relatively high rates of

labor productivity, The reason for this is that

both surface and underground mines with

high production rates generally have training

programs and equipment that will generate

higher labor productivity y.

The large surface mines of the Western

United States have long been characterized

by high rates of labor productivity. The productivity of some of these mines is as high as

30 to 35 tons per worker per day. The average productivity rate for all surface coal

mines in the United States is approximately

15 tons per worker per day, Since labor is one

of the major costs for any mining operation,

productivities on the order of 30 or more tons

per worker per day translate into significantly reduced unit operating costs. However, high rates of productivity are typically

achieved as the result of greater investments

in equipment, so that the reduction in unit operating costs will be partially offset by increases in the unit capital costs. Furthermore, capital costs for initial infrastructure

development and interest charges are the

most significant costs in coal mining.

Because there are fewer operating constraints, surface mining will generally present fewer problems with respect to achieving high production rates and concomitantly

high labor productivity rates. The achievement of these goals in underground coal mining, however, requires good mining conditions

as well as good management and a willingness to invest in the appropriate equipment.

A good example of the high level of productivity that can be achieved in underground mining is the Soldier Canyon Mine of California
Ch. 11—Mining Technology ● 335

Portland Cement Co. in central Utah. Using a

longwall system, this mine is achieving a

labor productivity of 23.5 tons per worker per

day and an annual production rate of over 1

million tons. This productivity rate is not only

much higher than the national average of 8.6

tons per worker per day for underground coal

mining but also exceeds that achieved by

most surface coal mines,

It is generally accepted that longwall

mining represents a better opportunity for

achieving higher production rates, higher

labor productivity rates, and better safety in

underground mining. A room-and-pillar operation using continuous miners can readily

achieve shift production rates of 350 to 400

tons. Rates in excess of 700 tons per shift are

exceptional, In the case of longwall mining,

shift production rates in excess of 1,000 tons

are common in the West and rates of 1,500 to

2,000 tons per shift have been achieved at a

number of longwall operations.

Environmental

Environmental problems resulting from

coal mining operations in the arid West are

more likely to be associated with surface mining than underground mining. Environmental

issues are discussed in detail in chapter 10.

Although the siting of surface facilities for

underground mining operations will generally

have limited environmental impacts, a potentially greater problem associated with increased underground mining on Federal coal

leases is surface subsidence. * The impact

from subsidence depends on the location of

the mine and is greatest in highly built-up urban areas. This problem is most often associated with cities and towns in the Eastern

United States but has also occurred in Western towns such as Rock Springs, Wyo., where

buildings and other facilities located in

several areas of the city have been endangered.

*Acid mine drainage, which can be an acute problem in

many mining areas in the East, is not a significant problem in

most arid regions of the West.

Surface subsidence can also be a problem

in rural and unpopulated areas. Differential

subsidence can break through to the surface

in the form of fractures and sinkholes. More

typically, subsidence will manifest itself in

the form of a generally lowered surface elevation, This will not be a problem unless it

occurs under a stream, railroad, highway,

building, or dam. Even then, the adverse effects of subsidence can be minimized if the

mine is properly planned. In several European countries, especially West Germany,

where the art of deploying planned subsidence is well developed, entire towns have

been lowered as a result of underground mining without adverse effects.

It is becoming apparent that longwall mining is usually preferred to room-and-pillar

mining where surface subsidence may be a

problem. The reason for this is that longwall

mining is more likely to produce more uniform

and predictable subsidence. Concern about

the potential impact of surface subsidence on

springs and ground water hydrology has been

expressed by local residents in mining areas

in Utah and Colorado. Subsidence tends to be

differential in room-and-pillar mining and

may not occur until years after mining operations have been completed. It may then occur

without warning and with potentially catastrophic results. However, full recovery of the

pillars will usually result in the more uniform

subsidence comparable to that achieved with

longwall mining.

Roof Support

Deeper mines require that larger support

structures be left in place in the underground

workings. Greater support can be accomplished by leaving the coal in place or by replacing it with substitute support structures,

For longwall mining there is increasing evidence that controlled subsidence of the

mined areas reduces support stresses on

boundary pillars that are left in place along

main and submain entries. In some longwall
336 ● An Assessment of Development and Production Potential of Federal Coal Leases

mines it has been necessary to install supple- much less than that required to support the

mentary supports such as packs or cribbing, full weight of the overlying rock strata.

but the amount of support provided has been

Review of Technology Developments in Europe and the

Western United States

This section reviews mining technology developments in Europe and the United States

and discusses possible solutions of the mining

technology problems described in the preceding section.

Because surface mining techniques and

equipment in the United States are relatively

advanced compared to underground coal

mining technology in the United States, only

new underground technology developments

will be discussed in this section. As the

number of underground mining operations increases in the West, improvements in underground mining technology can lead to significant improvements in coal production, recovery ratios, productivity rates, and safety.

Comparison of Mining Conditions in

Europe and the Western United States

Mining conditions on Federal coal leases

vary from nearly ideal to some of the most

difficult conditions anywhere in the world.

For example, in certain locations in northwestern Colorado and in northwestern New

Mexico the minable seams are a few hundred

feet deep and from 6 to 30 ft thick, the dips of

the seams range from the horizontal to a few

degrees, there are few faults, and the floor

and roof rocks are nearly ideal for support. In

contrast, the conditions found at some existing mines with Federal leases in western Colorado and central Utah include depths of

cover that are over 3,000 ft, seams that range

from 4 to over 40 ft in thickness, seam dips

that approach 350, extreme fracturing and

faulting of both the coal seams and the confining rock strata, and floor and roof rocks of

very poor competency. Many mines in Colorado and Utah extract coal from seams that

are over 1,000 ft deep.

Mining conditions vary in other areas

where there are substantial Federal leaseholdings. For example, in the Powder River

basin of northeastern Wyoming the depth of

coal seams ranges from a few hundred feet to

an undesirable 2,000 to 3,000 ft. However,

most other mining conditions are good in this

area. Difficult mining conditions in the Star

Lake-Bisti area of New Mexico include seam

dips up to zoo and faults. In Oklahoma,

high concentrations of methane gas and undulating, thin seams cause extremely difficult

mining conditions on most Federal leases.

Direct comparisons of coal mining in European countries with coal mining in the Western United States can be misleading because

many mining conditions are different in these

two areas. The principal coal mining countries of Europe—France, Great Britian,

Czechoslovakia, the Soviet Union, Poland, and

West Germany—are currently mining coal

from seams that would be considered unminable in the United States. A condition which is

present in all of these countries, but which

has not been observed in the Western United

States, is extreme folding of the coal seams.

In the case of folding, it is necessary to deal

not only with steeply dipping seams but vertically oriented seams as well. Most of the

coal mined in England is extracted from

seams that are deeply buried, thin, folded,

and faulted. Both France and Poland are currently operating deep mines with almost full

extraction of coal seams 20 to 30 ft thick.

However, even though many mining conditions in Europe differ from those in the

Western United States, the use of longwall
Ch. 11-Mining Technology ● 337

mining in Europe to extract deep, thick seams

is relevant to assessing the technical potential for extracting deep, thick seams in the

Western United States.

New Equipment Developments

The equipment developments discussed below include both refinements to existing underground mining technology and new equipment concepts that are still in the prototype

and testing stage. New equipment and concepts could solve many of the problems described in the section on mining technology

problems.

Longwall Mining Improvements

Modern longwall mining technology

emerged in its present form in Germany, the

Soviet Union, and Great Britain during the

latter part of the 1950’s after more than 20

years of continuous development in these

countries. Refinement and improvement of

longwall equipment and techniques have

since continued in these countries. The

United States has been a late entrant into the

use of longwall mining, and the equipment

manufacturers in this country have made relatively few contributions to the technology

during the past 10 years.

Many of the recent developments in longwall technology have dealt with improvements in reliability and production capability,

although there also has been considerable effort to improve safety conditions associated

with longwall mining. The discussion of these

improvements of longwall mining technology

will be organized according to the three principal components of a longwall system; roof

support, the face conveyor, and coal cutting

and loading.

Principal improvements in the longwall

support system have included increases in

the load-carrying capability of the hydraulic

rams, increased maneuverability of the supports, better stability, and refinements in the

controls. Most manufacturers of longwall

supports now offer units that have maximum

yield loads of 1,000 tons or more, The increases in the maximum yield loads also have

been accompanied by the development of

shields and chock-shields that offer greater

stability and more protection to the miner.

Advancement and alinement of the supports

now can be done remotely which not only reduces the time required for advancing the

support system, but also allows locating miners away from the moving support and out of

the way of falling material caused by movement of the support.

The transport of the cut coal away from

the longwall face by the face conveyor still

remains a major potential bottleneck in the

longwall mining system. A breakdown in the

conveyor can result from broken flight

chains; minor delays also are caused by oversized lumps of coal becoming stuck in conveyor transfer points. The broken flight chain

problem has been partially solved by the use

of a “twin-inboard” chain at the center of the

flight which reduces stress on the flight

chains as the flight conveyor bends around

curves. The need for a transfer point at the

headgate where the face conveyor meets the

panel belt conveyor in the headgate entry has

been eliminated by the recent innovation of

the roller curve in West Germany. The roller

curve allows the face conveyor to turn the

900 corner at the headgate and to dump coal

directly onto the panel gate conveyor or into a

feeder-breaker which reduces the size of

oversize lumps and then feeds the coal onto

the panel belt conveyor.

The majority of the longwall cutter-loaders

installed in the United States are shearers

rather than plows. Two major hazards associated with the use of shearers have been

high coal dust concentrations created by the

cutting action of the rotating shearer drums

and the danger from a break in the chain that

is used to pull the shearer back and forth

along the face. Significant reduction of dust

concentrations has been reported through the

use of a “Shearer-Clearer” water spray system which was developed by Foster-Miller

Associates in conjunction with the U.S. Bureau of Mines. This system partitions the airflow around the shearer into a clean split
338 ● An Assessment of Development and Production Potential of Federal Coal Leases

through the use of water sprays. The coal

dust cloud is confined to the vicinity of the

coal face while the shearer operators remain

in the clean split on the support side of the

cutting machine.

The broken chain hazard has been solved

by equipment manufacturers in Great Britain, West Germany, and the United States

which now offer chainless drives, These drive

systems are all based on a variation of the

rack and pinion gear system. Initial indications are that these chainless systems

already have gained wide acceptance by the

operators.

One additional development in longwall

technology is a system designed specifically

for steeply dipping seams. The system is

called the “Troika” and is offered by Hemscheidt America Corp. It is designed for use

in seams that dip up to 750 and is scheduled

to be used to extract Federal coal from a

seam pitching 330 at the Snowmass Mine in

Colorado. It consists of three shields connected to a central structural beam by a

double-acting ram assembly. The beam is connected mechanically to the center shield and

to the outer shields by the rams. The center

shield, which has no double-acting ram, is

moved by the outer shields with the rams

through the beam. The outer shields follow

this beam during movement.

The new equipment developments for longwall mining are potentially important, but

better use of available equipment is an equally important aspect of technology development for this system. An example of the latter

is the use of available longwall technology to

extract the maximum thickness possible from

seams that are thicker than the approximately

12-ft seams currently being mined with conventional longwall systems.

One approach to thick seam extraction in

underground mining is the double lift longwall method currently being developed to

mine Federal reserves at the Coal Basin Complex of Midcontinent Resources under a costsharing contract with the Department of

Energy. With this system, the coal seam is extracted by taking two successive passes of

the longwall. Total thickness of the coal seam

is 25 ft; by taking two 10- to 12-ft lifts, all but

5 ft of the seam will be recovered. Although

this is less than the total seam thickness at

Coal Basin, it is a significant improvement

over the extraction of 8 to 10 ft of coal

achieved with the single lift approach. Conceptually, this method could be extended to

extract the full coal seam, using three or

more lifts.

Another approach to thick-seam mining

using a longwall system, developed in France,

uses a single-lift longwall operation under the

bottom of the sea. The roof supports on this

system have been modified to allow the portions of the seam located above the longwall

to cave in behind the supports under the overlying broken roof rock. The broken coal is

then collected on a conveyor belt running behind the supports.

Room-and= Pillar Mining Improvements

For some time there has been an awareness that the cutting action used by existing

continuous miners is less efficient and produces more dust than alternative cutting actions. Tests of the linear-cutting miner experimental concept developed by the U.S. Bureau

of Mines have indicated that deeper cuts at

constant depth in the coal face can be made

more efficiently, while reducing the respirable dust that is normally generated by continuous miners. It is estimated that this new

cutting concept would produce three times

the amount of coal with one-third of the dust

and would use one-third to two-thirds less

electrical power, depending on the cutting

depth. However, the development of the commercial machine is not likely for another 20

years.

A concept for extracting more coal from

pillars during secondary recovery operations

is the underground auger miner developed by

FMC under contract to the U.S. Department

of Energy. In addition to the recovery of coal

in pillars, the system shows a potential for

mining out prepared panels of coal at significantly lower cost than conventional methods.
Ch. 11l—Mining Technology 339

The system consists of an underground

augering machine, a two-stage coal conveyor,

and auxiliary ventilation and rock-dusting

equipment. The auger miner excavates coal

by drilling a series of large holes side by side

into [he coal seam. The conveyor carries the

coal to the mine’s face haulage system, The

in-hole ventilation and rock-dusting equipment is used to dilute methane gas and coal

dust to nonexplosive concentrations,

The availability of efficient and reliable

haulage systems has long been one of the

goals of underground mining technology development. Existing rubber-belt conveyor systems have gone a long way to satisfy this requirement, but major deficiencies remain at

the face. The principal need is for a continuous haulage system which is sufficiently

flexible to adapt to the multitude of configurations experienced during the development

and product ion from a coal panel. Besides the

need for flexible components, there is also a

need for an efficient method for transferring

coal from one component to another, e.g.,

from shuttle cars to panel belt conveyors. *

* This need is also eveident for panel development in longwall

mining

Long-Airdox has introduced a continuous

haulage concept that is based on the use of

mobile bridge carriers and piggyback bridge

conveyors. A piggyback bridge is atttached

directly to the boom of the continuous miner

at one end and is supported by a dolly at the

other end. This dolly is designed to move freely along rails mounted on top of the sides of a

separate mobile bridge. Coal flows from the

miner to a piggyback bridge to a mobile

bridge to a piggyback bridge, and so on, until

it reaches the last piggyback bridge’s dolly

and is dumped onto the panel belt. Four

standard mobile conveyors (each 30 ft) coupled with five standard piggyback conveyors

(each 3 to 41 ft) can provide an effective

reach of over 300 ft in a seven-entry mining

projection.

Other concepts of continuous haulage that

have been tested include the use of air and

water as the carrying media for crushed coal

in pipelines. Although this approach offers

some advantages, it is still more difficult to

implement than are concepts based on the

use of conveyor belts. A slurry pipeline system has been installed in one Eastern mine,

however,

Considerations for Using Improved Longwall Mining

Techniques on Federal Coal Leases

The preceding sections of this chapter

have provided an overview of mining systems

currently in use on Federal coal leases and

have considered several of the technology

problems associated with the use of these systems. This section will address: 1 ) the cost in

capital and labor and the time needed to implement longwall mining and 2) the comparative production advantages and some of the

physical, environmental, and social consequences of using this technology.

Capital

During the 20-year period that reliable

longwall mining systems have been on the

market, an important reason for the reluctance of coal producers to use this technology

has been the initial cost of installation. The

installation of a complete longwall mining

system, not including the cost of development

workings and other mine infrastructure, requires the expenditure of a single large lump

sum of capital, usually $1.5 million per 100 ft

of face length. This cost includes: 1 ) the face

support subsystem, 2) the face conveyor subsystem, and 3) the coal cutting-loading subsystem. The total installed cost of the three

longwall subsystems will vary significantly

from mine to mine. The more important variables which determine the cost of a specific

longwall system include the length of the
340 ● An Assessment of Development and Production Potential of Federal Coal Leases

face, the height of the coal to be cut, the geological conditions of the seam, the thickness

and quality of the roof rocks (which determine the capacity of the face support subsystem required), and the rated capacity of the

system.

The typical longwall system now being installed in the Western United States has a designed face length of 600 ft and a rated production capacity of 1,250 tons of coal per

shift. However, the actual production capacity obtained varies from 700 to 1,500 tons per

shift because of variations in mining conditions and in the ability of producers to operate longwall systems. This compares with a

national average of 400 tons per shift for

longwall systems in 1980.

The cost of this typical longwall installation

in 1980 dollars is estimated at approximately

$9 million. Assuming that the mine operates

250 days per year and two shifts per day, the

rated annual production capacity of the typical longwall system will be 625,000 tons. * If

the longwall system is assumed to have a productive life of 10 years, which is not unrealistic if the system is adequately maintained

and there is selective replacement of the

more expendable system components, then

the total production capacity over the 10-year

life will be 6,250,000 tons of coal. Hence, the

total installed capital cost of the longwall

system over the life of the system will be approximately $1.50/ton of coal mined.

The significance of capital cost for longwall mining can be illustrated by the following example. Utah Power & Light installed a

longwall system in its Deer Creek mine near

Huntington, Utah, in April 1979. The system

was designed for a 480-ft face and a 10-ft

thick seam. The initial production capacity of

the system was 1,500 tons per shift. However,

after only 3 months of operation longwall production reached an average of 2,500 tons per

shift, Using a schedule of two shifts per day,

the initial 3,000-ft long panel was mined out

*This figure takes in!{) arc[)unt the am(mnl of time the sys[em

is m )1 i n opera I i ( )n [iu ring I his pf?ri(d hcra use () f m:] in Iena rice,

t?t c.

in a period of 6 months for an average production of 2,200 tons per shift.

The impact of the success of this initial

longwall system on the entire Deer Creek operation is dramatic. Prior to the installation

of the longwall unit, daily production capacity at the mine was 7,000 tons. To achieve

this production rate it was necessary to use

as many as 10 continuous miner sections.

With the implementation of the longwall

system the daily production has increased to

in excess of 10,000 tons and the monthly production to 220,000 tons. Of this 220,000 tons,

a total of 115,000 tons is produced by the

single longwall unit and the balance by eight

continuous miner sections. With the installation of a second longwall, the company expects the requirement for continuous miners

to drop to four sections. Two of these sections

will be used for longwall panel development

and two to extract pillars from sections of the

mine which have already been mined using

the room-and-pillar technique.

Prior to the installation of the first longwall

unit the Deer Creek Mine was producing 1.75

million tons of coal per year, This rate was

achieved through the use of 10 continuous

miner sections. Assuming an average investment of $700,000 per section, the total investment in mining equipment was $7 million.

Based on a 10-year life for the continuous

miners and auxillary equipment, the total

capital cost per ton of coal mined over the 10-

year period was $0.40. Assuming an installed

cost of $9 million per longwall unit, a similar

calculation for the 2-longwall and 4-continuous miner production system now producing

2.64 million tons of coal per year results in a

capital investment of $0.80/ton of coal produced over a lo-year period, assuming the

longwall units and the continuous miners

have productive lives of 10 years. Considering the cost of money at 20 percent and total

financing of the equipment, the all continuous

miner system cost becomes $0.85/ton and the

cost for the mixed system $1,65/ton.

Although the capital cost per ton of coal

produced is higher for the longwall system,

labor costs are reduced. Assuming that the
Ch. 11—Mining Technology 341

longwall and the continuous miner sections

both require 10-person crews for their operation and that the size of the maintenance support staff is the same for both the all continuous miner mine and the combined longwall

and continuous miner mine, the combined operation will require 80 fewer hourly employees to operate on a two shift per day basis.

Based on a direct hourly rate of $9/hour and a

fringe benefit rate of 35 percent, each of

these 80 employees costs approximately

$25,000 per year. Therefore, the total savings

in labor costs for the mine configuration using

the combined systems is $2 million per year,

This sum is 14 percent of the difference in

capital cost between the combined operation

($21 million) and the all continuous miner

operation ($7 million). When the fact that the

combined operation produces 900,000 additional tons of coal per year is factored in,

then the payback period becomes of the order

of 2 years.

There are a number of existing and

planned underground mines on Federal coal

leases that could use development strategies

similar to that of the Deer Creek Mine. The

Skyline Mine of Coastal States Energy Co.,

which is located near Price, Utah, is scheduled to open in 1982 with an initial production

rate of 437,000 tons per year, This rate ultimately will be increased to 5.4 million tons

per year. Over 40 percent of this production,

2.3 million tons, is scheduled for three longwall units ranging in capacity from 702,000

to 864,000 tons per year. Because of extreme

variations in seam thickness and the presence of faulting on the property, problems

which do not exist at the Deer Creek Mine,

the balance of the annual production will be

mined with continuous miners. It is estimated

that 14 continuous miners will be required to

produce their 3. l-million-ton share of the annual production.

Labor

As the above section shows, increased capital costs for longwall mining can be offset by

reduced labor costs and increased production, Because the costs of capital and labor

will be the major inputs into any mining system, both surface and underground, there

always will be some tradeoff between the

two, which will vary from mining system to

mining system. However, several aspects of

labor requirements for longwall systems differ from the labor requirements for roomand-pillar systems. These differences cannot

be readily quantified in terms of direct cost.

Western coal mines usually recruit their

miners from the general labor force. Some

workers may come to the industry with a

background in construction or some other related occupation, but few have any mining experience. Therefore, if a mine using longwall

mining hires a new employee, there is frequently no need to retrain an individual recruited from room-and-pillar operations. This

ability of the Western coal miner to adapt

readily to the longwall mining environment

has been noted by a number of companies. As

indicated above in the discussion of the Deer

Creek Mine, the production rate from its newly installed longwall face increased from

1,500 tons per shift to 2,500 tons per shift in

little more than 3 months of operation. The

only experiences longwall miners at the time

the longwall unit was installed were the three

shift foremen. The Coal Basin Mine longwall

operation in western Colorado and the Sunnyside Mine in central Utah also have had

good experiences with the installation of their

first longwall units. Like Deer Creek, these

mines have achieved production rates much

higher than those obtained at many of the

longwall units located in Eastern coal mines.

Another benefit of longwall mining from

the point of view of the mine operator is the

reduced labor requirement when compared

to room-and-pillar systems. This factor is an

advantage both with respect to finding

enough qualified employees to staff an operation and in reducing the amount of infrastructure needed where a mine is remotely

located and requires development of a supporting community infrastructure to serve

employees, Since minable coal deposits in the

West often are located in sparsely populated

areas, the availability and the housing of
342 ● An Assessment of Development and Production Potential of Federal Coal Leases

employees are two major considerations. In

the case of a mine such as Skyline, which is

located in a large rural area of Utah that

already has seen the expansion and development of a number of large mines, attracting

skilled labor becomes a problem. Thus, reduction in the total number of operating employees required from 480 for a mine using all

continuous miners to 340 for a mine using a

combination of continuous miners and longwall units is significant,

There are other advantages to the mine operator of reduced overall manpower requirements. These include the reduced potential

for personnel turnover, less need for employee training, and an overall reduction in

personnel support costs. Operating with a

smaller labor force also means that fewer

people will be exposed to the hazards of underground coal mining per ton of coal produced. This will be discussed in greater detail

in the section on health and safety,

Production and Productivity

As has been discussed in preceding sections of this chapter, production and productivity are related but separate operational considerations. An increased production rate is of interest to the operator who has

the reserves to support large market commitments but who is not able to produce the coal

required of these commitments because of deficiencies in the production system. In contrast, productivity is of interest to all mine operators, Productivity is usually discussed in

terms of coal output in tons per unit of labor

expended, but is equally applicable in terms

of coal output per unit of machine time expended. Whether stated in terms of labor productivity or equipment productivity, the objective is to maximize coal production per

unit of resource used.

The question of improved productivity and

longwall mining has been addressed. In the

discussion of the capital cost of longwall mining, the potential for improving labor productivity through the installation of longwall

equipment was illustrated by two examples.

It was also shown that even though the improved labor productivity was achieved

through the use of longwall equipment which

was more expensive than the continuous

miners it replaced, the overall effect was a

reduction in the total cost per ton of coal

mined.

The underground coal mining industry in

the United States has undergone significant

change in the past 10 years. A 500,000-tonper-year mine, formerly considered a large

mine, is now considered of small to average

size. With this change, production equipment

and the scheduling of equipment have become

more complex. Whereas a 50(),0()0-ton mine

could operate with two to three continuous

miners on a two shift-per-day schedule, mines

such as the Skyline Mine discussed above

would require 24 continuous miners to sustain its 5,4-million-ton-per-year production

rate, Coping with the production scheduling

in a mine where there are 24 operating sections which require the assignment of manpower, equipment, maintenance, and transportation is an extensive and demanding task.

The Skyline operation is not unique in this respect. Other existing and planned underground mines on Federal leases that eventually will be producing in the 5-million-tonper-year range include the Price River Coal

Co. mine (formerly Braztah) in Utah and the

Loma Complex in Colorado. In the 2-millionto 3-million-ton-per-year range there will be

SUFCo in Utah, Mt. Gunnison in Colorado,

Energy Development in Colorado, and potentially La Ventana in New Mexico, The mines

in the l-million- to 2-million-ton-per-year

range are even more numerous.

Nearly all of these mines will install longwall units, One of the major considerations in

arriving at the decision to use longwall mining at these mines has been the need to

achieve high production rates. A single longwall unit can produce 750,000 tons of coal

per year. The longwalls at the Deer Creek

Mine are producing in excess of 1 million tons

per year per unit, The Wilberg Mine, a sister

mine of Deer Creek, is installing a longwall

unit that is rated at 3,000 tons per shift. This

translates into 1.5 million tons per year,
Ch. 1 l—Mining Technology ● 343

Coastal States Energy Co. is currently

studying the feasibility of using longwall mining at its SUFCo Mine which is located on

Federal leases near Salina, Utah. The minable

seam, the Hiawatha, varies from 6 to 15 ft in

thickness. However, the average thickness is

12 ft and with the exception of thinning on

one part, the lease tends to maintain this average over extensive areas. There is little dip to

the seam and little noticeable faulting. In

sum, these conditions suggest that installation of at least one longwall unit to replace

some of the existing 10 continuous miner

units would simplify the operation and might

reduce the cost of mining.

In summary, Western underground mines

need to continue to pursue methods for increasing their production rates and improving their productivity. These combined goals

will lower their unit mining costs and thereby

enable them to compete more effectively with

the coal mines in the Eastern United States

and the large surface mines in the West.

Other than reduced mining costs, an additional advantage of the increased production

rates could be the ability to use unit-train

transportation to move coal to markets and

thereby recover some of the transportation

cost penalty associated with supplying coal to

Midwestern and Eastern markets.

Environmental

In the arid West, the impact of underground coal mining on the environment is generally less than that resulting from surface

coal mining. Longwall mining can further

reduce the environmental impacts normally

resulting from room-and-pillar operations.

Subsidence from underground mining can

take the form of either a wide-area lowering

of the ground surface or sinkholes and fractures that break through to the surface. The

results of several studies, conducted both in

the United States* and Europe, indicate that

longwall mining is most likely to result in

wide-area subsidence and to cause little differential subsidence that can result in breaks

in the ground surface. These studies also

have indicated that surface subsidence is

generally limited to an amount equal to onehalf the thickness of the coal being extracted,

although it can exceed 50 percent and can go

as high as 90 percent of the seam thickness.

For the thicker seam longwall operations, this

would generally mean a subsidence of about

6 ft. A lowering of the surface elevation of

this magnitude could be a problem in the

Western United States and would have to be

handled on a case-by-case basis. However,

the areawide form of subsidence likely to

result from longwall operations is preferable

to the differential subsidence that is more

likely to result from room-and-pillar operations,

Health and Safety

Regardless of the type of mine, underground coal mining takes place in a hazardous environment. Fewer workers will be exposed to these hazards in a longwall operation than in other underground coal production met hods for a given level of production.

Because of the fundamental differences between room-and-pillar and longwall mining

systems it is difficult to make a direct comparison as to which provides a healthier or

safer environment for the worker. The basic

hazards—coal dust, methane gas, spontaneous combustion, roof falls, bumps, and

moving machinery in confined spaces—are

present in both types of mining. In some cases

there are tradeoffs in hazards, The control of

excessive coal dust at the longwall face is a

problem that must be solved, although there

are some potential breakthroughs. On the

other hand, however, the protection from roof

fall hazards provided by longwall supports

is superior to that available to the continuous

miner operator.

Equipment advances that improve the underground mining environment with respect
344 ● An Assessment of Development and Production Potential of Federal Coal Leases

to worker health and safety will continue. tivity and a concomitant reduction in the

However, the most direct results will be ob- number of workers that must be exposed to

tained through increases in labor produc- the dangers of underground coal mining.
CHAPTER 12

Revenues and

Socioeconomic Impacts
Contents

Page

Introduction ● . . . . . . . . . . . . . . . . . . . . . . . . . . 347

Background. . . . . . . . . . . . . . . . . . . . . . .......347

Potential Federal Coal Leasing Revenues. ..348

OTA Estimates of Potential Revenues From

Federal Coal Leases. . ...................349

Bonuses . . . . . . . . . .......................349

Rentals . . . . . . . . . . . . . . . ..................350

Royalties . . . . . . . . . . . . . . . . . . . . . . . ........350

State Allocation of Federal .Mineral

Leasing Revenues. . . . .................352

Colorado . . . . . . . . . . . . . . .................352

Wyoming, . . . . .. ., $ .....................353

Utah . . . . . . . . . . . . .......................353

Other Western States . . . . . . . . . . . . . ........354

Federal Programs To AssistEnergyImpacted Communities. . . .............354

Loans Against Future Leasing Revenues. ....354

Payment in Lieu of Taxes (PILT). . ..........354

Abandoned Mine Reclamation Funds. ......355

“601” Program . . . . . . . . ..................355

Other Federal Programs. . .................355

State Programs. . .......................35 6

Severance Taxes . . . . . . . . . . . ..............356

State Energy Facility Siting Programs. .. ....359

Effects of Expanded Federal Coal

Production . . . . . . . .**..*** ● ..*.*.* . . . 360

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 361

Utah . . . . . . . . . . . . .......................363

New Mexico . . . . . . . . . . ..................364

Wyoming and Montana . . . . . . . . ...........365

North Dakota . . . . . . . . . . ..................367

Oklahoma . . . . . . . . . . . . . . . . . . . . . . ........368

List of Tables

Table No. Page

94. Federal Coal Production and Royalty

Revenues, by State: Fiscal Years 1979

and 1980.. . . . . . . . . . . . . . . . . . . . . .. ....348

95.

96.

97.

98.

99.

100,

101.

102.

103.

104.

105.

106.

List

Page

Competitive Coal Lease Sales on Public

Lands Fiscal Years 1954-1980..........350

Estimated Rental Payments for Federal

Leases in 1986 and 1991. . .............350

1986 and 1991 Competitive Mine-Mouth

Prices by Federal Coal Production

Regions . . . . . . . . . . ..................351

Federal Royalties and State

Distributions From Potential Coal

Production on Federal Leases 1980

and 1986, 1991... . ....................352

Colorado Allocation of Federal

Coal Royalties . . . . . . . . . ..............352

Wyoming Allocation of Federal Mineral

Lease Revenues. . ....................353

Utah Allocation of Federal Mineral

Lease Revenues. . ....................353

Payments in Lieu of Taxes by State. .....354

Coal Severance Taxes. . ...............357

Allocation of Coal Severance Tax

Revenues . . . . . . .....................358

Demographic Characteristics of

Selected Counties in Colorado, Utah,

and New Mexico. . ...................362

Demographic Characteristics of

Selected Counties in North Dakota,

Wyoming, and Montana. . .............366

of Figures

Figure No. Page

53. Total Severance Tax Revenues. . . , .. ....357

54. Counties of the Rocky Mountain

Study Area. . . . . . . . . . . ................361

55. Counties of the Great Plains Study Area. ..365
CHAPTER 12

Revenues and Socioeconomic Impacts

Introduction

This chapter responds to the third of

OTA’s tasks under Public Law 94-377: calculation of potential Federal revenues from

existing leases, It provides an estimate of

revenues from rentals and royalties based on

OTA’s analysis of lease development and production prospects. The chapter also describes the various methods used by the

Western coal States to distribute their share

of mineral leasing revenues and discusses

Federal and State programs for ameliorating

the adverse impacts of energy development.

Areas that potentially will be affected by expanded Federal coal development are identified.

Background

Rapid growth and its consequent social

disruption have been characteristic of much

energy development in the Northern Great

Plains and Rocky Mountain regions. Large influxes of people, associated with the construction and operation of energy projects,

have come to rural towns. Prior to this, many

of the communities had stable or declining

populations and economies based on service

to agriculture.

With the sudden increases in population,

local social structures have been hard

pressed to meet the needs of the residents.

Both public and private sectors have faced

difficulties. Among the consequences of rapid

growth have been:

● acute housing shortages with rapid cost

escalations;

inability of the public sector to provide

services, such as sewer and water, in a

timely way;

dislocations in the private sector, such

as business failures and labor shortages;

manifestations of increased socia l

stress, such as crime, truancy, and suicide;

accompanying pressure on health, welfare, public safety, and mental health

services;

discontent expressed by both old and

new residents; and

high turnover rates and declines in productivity among employees of energy industries.

Financial shortfalls during the early stages

of rapid growth have been particularly acute.

These are called front-end financing difficulties. New public works, such as water or

sewer systems, cannot be built quickly and

they are expensive. In some instances, local

voters have been reluctant to approve bond

issues for public works, fearing that after the

boom they will be left with a large debt. In

other cases, towns have been limited by State

statutes in the amount of debt they can incur.

As a result, most Great Plains and Western

States have devised mechanisms to assist

local governments in meeting both their frontend financing requirements and the other

needs arising from rapid growth. Federal

mineral leasing revenue payments are an important source of funds for impact assistance. A variety of types’ of other Federal aid

also are available.

347
348 ● An Assessment of Development and Production Potential of Federal Coal Leases

Potential Federal Coal Leasing Revenues

Under section 35 of the Mineral Leasing

Act of 1920, each State receives a share of

the revenues derived from sales, bonuses,

rentals and royalties from mineral activities

on public lands within its borders.1 Originally, a State’s share was 37.5 percent; it was to

be spent by the State legislature “for the construction and maintenance of public roads or

for the support of public schools or other public educational institutions.’” Of the remaining revenues, 52.5 percent went to the Reclamation Fund to be used for water projects,

and 10 percent went to the U.S. Treasury. {

From 1920 to June 30, 1976, over $1.3 billion

was distributed to the Western States for

public roads and schools. There was no requirement that the areas most affected by

mineral development on Federal lands receive priority in the allocation of the States’

share.

In 1976, section 35 was amended to increase a State’s portion of the revenues from

1

30 U.S.C. 191.

2Act of Feb. 25, 1920, c. 85, sec. 35, 41 Stat. 450.

‘As part of its statehood entitlement, Alaska receives 90 percent of the Federal mineral leasing revenues generated within

the State since it does not participate in the Reclamation Fund.

See 30 U.S.C. 191. The Reclamation Fund was established by

the Act of June 17, 1902, c. 1093, 32 Stat. 388, now codified at

43 U.S.C. 391, as amended. Moneys in the Fund are to be used

for the reclamation of arid and semiarid lands through construction of dams, reservoirs, and irrigation projects, and for

other specified purposes for the benefit of 17 Western States.

37.5 to 50 percent. The amount paid into the

Reclamation Fund was reduced to 40 percent.

In addition, purposes for which the State distributions could be spent were broadened. ’

Each State legislature can now allocate mineral leasing revenues “giving priority to those

subdivisions of the State socially or economically impacted by the development of minerals leased under this chapter for 1) planning,

2) construction and maintenance of public facilities, and 3) provision of public service.”5

This language established for the first time a

specific priority for use of the revenues for

impact assistance,

According to the Congressional Budget Office (CBO), a total of $210 million in Federal

mineral royalty payments were distributed to

the States in fiscal year 1979,’) Most of these

payments came from oil and gas leases; only

$14 million (about 7 percent) came from coal

leases on Federal lands in the West, according to CBO. Table 94 shows the total Federal coal production and total coal royalties

reported by the Department of the Interior

4The major amendments to sec. 35 (raising the Stale’s share

and broadening the purposes) were made by sec. 9 of the Federal Coal Leasing Amendments Act of 1976. Public Law 94-377,

90 Stat. 1087 (1976).

5

’30 U.S.Sc. 191.

‘Energy Development, Local Growth, and the Federal Role,

Congressional Budget Office, U.S. Congress, June 1980, p. 24.

Table 94.—Federal Coal Production and Royalty Revenues, by State:

Fiscal Years 1979 and 1980

FY 1979 FY 1979 FY 1980 FY1980

coal production royalty revenues coal production royalty revenues

State (tons) ($) (tons) ($)

Alabama . . . . . .

Colorado. . . . . .

Kentucky. . . . . .

Montana . . . . . .

New Mexico . . .

North Dakota . .

Oklahoma . . . . .

Utah . . . . . . . . . .

Washington . . .

Wyoming. . . . . .

1,777

7,401,530

59,637

7,964,316

4,660,225

589,079

333,773

6,778,615

215,662

31,136,664

1,916

3,852,839

62,385

1,298,325

1,048,550

134,622

789,681

1,476,612

43,124

7,411,170

27,780

8,562,862

9,219

10,345,255

6,546,224

1,418,129

299,599

8,616,415

0

36,130,862

Total . . . . . . . 59,141,237 16,119,225 71,958,165 24,568,692

SOURCE: U.S. Department of the Interior, Federal Coal Management Report” Fiscal Year 1980, 1981.
Ch. 12—Revenues and Socioeconomic Impacts 349

(DOI) for fiscal years 1979 and 1980; the

States received one-half of these receipts,

Royalties are expected to increase substantially in the next decade, although the

magnitude of the increase depends on the

assumptions of the forecaster. CBO estimates

that total payments from all types of mineral

leases will reach $450 million to $500 million

by fiscal year 1985. State shares of revenue

from coal, CBO projects, will grow from $14.1

million in fiscal year 1979 to $65 million to

$85 million by fiscal year 1985.

Budget figures prepared by DOI for fiscal

year 1982 show an expected increase in total

coal royalties from existing and new leases in

all States from $24,6 million in fiscal year

1980 to $131 million in fiscal 1985, and to

$792 million in fiscal 1990 (again the States

would get half these revenues).7 OTA’s estimates of potential revenues from coal production on existing Federal leases also show a

significant rise in payments (see below).

The increases can be attributed to several

factors: the anticipated expansion of Federal

coal production, the scheduled readjustments

of existing leases to, and the issuance of new

leases at the higher minimum royalty rate of

12.5 percent for surface mines required under the Federal Coal Leasing Amendments

Act of 1976 (FCLAA).

OTA Estimates of Potential Revenues

From Federal Coal Leases

Section 10 of FCLAA directed OTA to provide an estimate of the “receipts to the Federal Government” from existing Federal

leases. OTA calculated the potential rentals

and royalties for 1986 and 1991 based on

OTA’s estimates of the production prospects

for Federal leases presented in chapter 6 of

this report. The estimates include increased

royalty rates on all leases that are due for

readjustment over the next decade.

‘Personal communication, U.S. Geological Survey, Conservation Division, Royalty Accounting Section, February 1981.

According to OTA’s analysis, total Federal

royalty revenues from existing leases in the

six Western coal States should increase from

$31.5 million in 1980 to $193 million to $215

million in 1986, and to as much as $336 million to $544 million in 1991 (depending on the

rate of development of existing leases). The

States will receive half these revenues. In the

past, the amounts received as the States’

shares of bonuses and rentals have been

small compared to the front-end costs of

meeting the impacts of coal development.

Only when royalty payments started with

commercial production have the States received significant benefits from coal lease

revenues.

Bonuses

When Federal coal leases are offered competitively, the successful bidder pays a lump

sum or “bonus” for acquisition of the lease as

well as an annual rental and percentage royalty on production. Under the current bidding

system, DOI establishes the rental and royalty

before the lease sale and the lease is

awarded to whoever offers the highest bonus

bid. FCLAA requires that half of the leases

for sale in any year be offered on a system of

deferred bonus bidding, which allows lessees

to pay the bonus in installments. No bid can

be accepted for less than the fair market value

of the coal, which is established before the

sale by the U.S. Geological Survey (USGS).

No bonus is paid for the acquisition of a

noncompetitive preference right lease. About

half of the existing leases were issued

through the preference right system and the

more than 170 pending preference right lease

applications (PRLAs) could result in new additional noncompetitive leases. When new

leases are offered, the States receive half of

the bonuses paid.

Table 95 shows the bonus payments received for Federal coal leases between 1954

and 1980. Since 1954 over $15 million has

been received in bonuses for competitive

leases. Of this amount, $1.4 million was paid

after the 1976 amendments raising the State
350 ● An Assessment of Development and Production Potential of Federal Coal Leases —

Table 95.—Competitive Coal Lease Sales on

Public Lands Fiscal Years 1954-1980

(acreage, bonus payments, average bonus per acre)

.

Fiscal year

1954 .: . . . .

1955 .. .

1956 ... . ,

1957 .

1958 .

1959 . . . . .

1960 . . . . . . . . .

1961 . . . . . . . . . .

1962 . . . .

196 3

1964 .

1965 . .

1966 . . . . . . . . . .

1967 . . . . . . . . . . .

1968 . . . . . . . .

1969 . . . . . . . . . . . .

1970 . . . . . . . . .

1971 . . . . . . . . . .

1972 . . . . . . . . . . . .

1973 . . . . . . . .

1974 . . . . .

1975 . . . . . . . . .

1976 . . . . . . . . . . . .

1977 . . . .

1978 ,.,.,.

1979 . . . . . . . . .

1980 . .

Total . . . . . . . . .

Total acres

400

0

4,316

3,863

15,375

8,805

4,358

12,733

38,976

20,780

10,768

23,264

44,894

43,885

88,037

0

18,493

28,386

0

0

3,989

0

0

0

574

6,395

7,817

385.408

$ 420

0

4,317

6,064

19,176

224,179

9,055

20,531

202,404

143,023

39.532

146,258

753,727

721,294

3,077,736

0

370,395

7,618,634

0

0

390,776

0

0

0

31,380

803,408

582,369

$15.164.678

$ 1.05

.

1.00

1.57

1.25

25.46

2.08

1.61

5.19

6.88

3.66

6.15

16.79

16.44

34.96

0

20.03

268.39

0

0

97.96

0

0

0

54.69

125.62

74.50

. , $ 39.35

SOURCE:U.S Department of the lntertor,U.S.Geological Survey, Conservation

Division, Federal and Indian Lands Coal, Phosphate, Potash, Sodium,

and Other Mineral Production, Royalty Inccome and Related Statistics.

CY 1980.

share to 50 percent. Throughout the period,

individual bonus payments ranged from as

low as $O.25/acre to hundreds of dollars per

acre depending on when the sale was held

and on the location and quality of the reserves.

Rentals

Estimated rentals from Federal leases are

shown in table 96. The rentals are small compared to the revenues received from royalties. However, for States with large amounts

of Federal lands under lease but with small

amounts of production, rentals can be a significant component of their Federal revenue.

Before passage of FCLAA, the amount of annual rental paid was subtracted from the royalties due. New leases and leases readjusted

after August 4, 1976 do not allow rentals to

be subtracted from royalties and require payment of annual rentals as well as production

royalties. The amount of rental charged is set

by the Secretary of the Interior before the

lease sale and at readjustment. Most preFCLAA leases have rentals of $1.00/acre;

minimum rentals for post-FCLAA and preFCLAA leases at readjustment are currently

set at $3.00/acre, although some leases have

rentals as high as $7.0()/acre.

Royalties

Federal coal royalties are based on either a

straight fee per ton, generally between $0.15

and $0.22/ton for many pre-FCLAA leases, or

a percentage royalty of the sale price per ton

of coal produced with a statutory minimum

of 12.5 percent for surface mined coal, The

1979 annual Federal coal management report

noted the following about the percentage ad

valorem royalty provision:

The amount of money collected under a centsper-ton royalty does not increase as the value of

the coal production increases. During the 1970’s,

the Department shifted to percentage ad valorem

royalties which provide that royalty payments to

the Government will increase as the value of the

coal increases. Conversely, the Government will

share the risk with the lessee, receiving in abTable 96.—Estimated Rental Payments for Federal Leases in 1986 and 1991

Number of 1986a1991a

State leases Total acres total rentals total rentals

Colorado . . . . . . . . . . 127 124,091 $253,886 $373,748

Montana ... , . . . . . . . 21 37,327 73,992 111,858

New Mexico . . . . . . . . 29 44,760 119,772 133,596

North Dakota . . . . . . . 20 18,048 46,684 57,556

Utah . . . . . . . . . . . . . . 204 279,416 650,721 855,186

Wyoming . . . . . . . . , . 101 217,067 548,072 660,734

Total . . . . . . . . . . . . 502 720.709 $1,693,129 $2,192,678

a Rentals not reduced for portion of rentals credited to royalties due for unadjusted leases

SOURCE: Office of Technology Assessment
Ch. 12—Revenues and Socioeconomic Impacts ● 351

solute terms, less royalty money should the future

price of coal decrease.

In calculating the potential royalty payments, OTA used the production estimates

derived from the OTA analysis of the development prospects of Federal leases (ch, 6 ),

These production estimates are expressed in

ranges of production that reflect uncertainties based on markets, transportation availability, and the rate of mine construction.

Consequently, royalty estimates reflect similar uncertainties, Because detailed long-term

contract information and individual mine cost

data were not available, OTA used a regional

competitive mine-mouth price of coal in calculating future royalty payments. The actual

mine-mouth sales price may be higher or

lower than the regional figures used. The

competitive mine-mouth prices were derived

from an economic analysis done for OTA and

are based on projections of the potential demand for Western coal. For the Hanna basin

and Denver-Raton Mesa coal fields, which

were not included in the economic analysis,

OTA substituted an estimated mine-mouth

price based on a review of DOE’s national

coal model supply curves and on OTA contractor surveys of mine operators, Table 97

shows the competitive mine-mouth prices

used in the royalty calculations.

The estimates for all leases that are due

for readjustment before 1991 reflect higher

rental and royalty rates—$3.()()/acre rental

and 12.5 percent surface and 8.0 percent underground royalties, Pre-FCLAA lease rentals were generally set at $1.()()/acre and royalties at $0.15/ton. The increases in royalty

payments from readjustments will be substantial. For example, for underground coal

mined at $20.0()/ton, the current royalty may

be as low as $().15/ton; on readjustment, it

would be raised to 8 percent of $l.60/ton—

more than 10 times the previous level, For

surface mined coal, the increase will also be

substantial. Total Federal coal royalty

payments in calendar year 1980 were about

$32 million on total production of 69 million

tons, Table 98 shows the potential Federal

coal production, total royalty revenues, and

State distributions estimated for 1986 and

1991.

Some existing underground mines have requested royalty reductions from the current

minimum of 8 to 5 percent or lower under the

provisions of section 39 of the Mineral Leasing Act and current regulations, H There is no

statutory minimum royalty for underground

’30 U.S.C. 207

Table 97.—1986 and 1991 Competitive Mine-Mouth Prices by Federal Coal

Production Regions (1979 dollars per ton)

1986 1991

Region Btu/lb dollars/ton dollars/ton

Fort Union . . . . . . . . . . . . . . . . . . 6,000 6.00 Surface 6.00 Surface

Powder River basin . . . . . . . . . . 8,500 7.40 Surface 7.40 Surface

Hanna basin . . . . . . . . . . . . . . . . 10.500 16.50 Surface 16.50 Surface

Green River-Hams Fork:

Wyoming . . . . . . . . . . . . . . . . . 10,000 14.50 Surface 18.60 Surface

25.30 Underground 25.30 Underground

Colorado . . . . . . . . . . . . . . . . . 10,000 20.00 Surface and 23.90 Surface and

underground underground

Uinta . . . . . . . . . . . . . . . . . . . . . . . 12,500 24.00 Underground 24.20 Underground

Southwestern Utah . . . . . . . . . . . 11,000 11.80 Surface 11.80 Surface

24.00 Underground 24.20 Underground

San Juan . . . . . . . . . . . . . . . . . . . 10,000 15.10 Surface and 15.30 Surface and

underground underground

NOTE All prices are for steam coal

SOURCE Off Ice of Technology Assessment
352 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 98.—Federal Royalties and State Distributions From Potential Coal Production on Federal Leases

1980 (actual) and 1986, 1991 (estimated) (1986 and 1991 royalties are in constant 1979.1980 dollars)

1980a1986b1991b

Federal lease Royalty State Federal lease Federal lease

production total share production Royalty State production Royalty State

(millions of (millions of (millions of total share (millions of total share

State tons) dollars) tons) (millions of dollars) tons) (millions of dollars)

Total (West). . . . . . . . 68.8 31.5 16.2 204-250 193-215 95-108 245-405 336-544 168-277

Details may not add to totals because of independent rounding.

a U.S. Department of the Interior, U.S. Geological survey, Conservation Division, Federal and Indian Lands, Coal, Phosphate, Potash, Sodium, and Other Mineral Production, Roya/ty /rrcome, and Re/ated Staristlcs, Ca/endar Yaar 1980, June 1981.

b Royalty estimates assume timely readjustment of leases to a minimum royalty of 12.5 percent for surface coal and 8 percent for underground coal.

c Excludes about 8 million tons of Federal PRLA production and about $15 million in PRLA royalties.

mines as there is for surface mines. In some revenues could be lowered in States such as

areas where underground mining costs are Colorado and Utah where underground prohigh, the royalty paid for underground mined duction is significant. But in return, since the

coal can be higher per ton than that charged royalty reduction is intended to allow the

for surface mined coal. It is possible that, if mine to be operated at a profit, it assures conmany underground operations receive under- tinued production, employment, and other

ground royalty rate reductions, total royalty revenues.

State Allocation of Federal Mineral Leasing Revenues

In response to the 1976 amendments and to

local priorities for impact assistance, each

Western State has established its own formula for spending Federal revenues. As the

income from Federal production grows and

local needs change, the States can alter these

disbursement formulas. Current State practices (surveyed by OTA in 1980) are described in the following section.

Colorado

Colorado distributes its Federal mineral

revenues in four different ways (table 99).

The Mineral Impact Fund is dispensed by the

Executive Director of the Department of Local Affairs, after a recommendation procedure involving local, regional and State entities. (State severance tax receipts are handled in the same way.) The Fund is used for

planning, construction and maintenance of

public facilities and for the provision of

Table 99.—Colorado Allocation of

Federal Coal Royalties

State public school fund . . . . . . . . . . . . . . . 25%

Water Conservation Board . . . . . . . . . . . . . 10%

Mineral Impact Fund . . . . . . . . . . . . . . . . . . 15%

Counties (limited to $2(X),000 per county

per annum; any excess to school fund) . 50%

Total ., . . . . . . . . . . . . . . . . . . . . . . . . . . . 100%

SOURCE: Colo. Rev. Stat. 1973, 3463-101, 102, as amended.

public services. Priority is given to “political

subdivisions socially or economically impacted by the development, processing, or

energy conversion of minerals” from lands

leased from the Federal Government or subject to State severance taxes.9

A limitation of $200,000 per year on the

direct county allotment means that major

energy-producing counties receive much less

9 Co1o. Rev. Stat, 1973, §§34-63-102 and 39-29-110 (1979

Supp.).
Ch. 12—Revenues and Socioeconomic Impacts 353

than 50 percent of the revenues. The excess

goes into the public school fund, In fiscal year

1980, for example, Rio Blanco County generated $5.86 million and Moffat County $1.07

million of the $20.3 million that came back to

the State. The $200,000 that each received

amounted to 3.4 and 18.6 percent of the

respective royalty revenues they generated.

Six Colorado counties reached the $200,000

limitation; the spillover was $7.7 million (38

percent of the amount the State received),

which raised the school revenues to $12.7

million (63 percent of the total receipts).

The original $200,000 per county limitation

was enacted at a time when total mineral

lease revenues were low and some Colorado

counties were receiving far greater oil and

gas revenues than their sparse populations

could justify. These conditions have changed

dramatically with substantial growth from

coal development and expected change from

proposed oil shale processing; as a result,

legislation to raise the maximum has recently

been proposed.

Wyoming

In Wyoming, revenues from the Federal

mineral royalties are assigned according to a

complex formula (table 100). About 19% percent is available for local assistance, including 21A percent for roads, 71/2 percent

for public facilities, and 93⁄4 percent for communities.

The Wyoming Farm Loan Board allocates

grants from the Impact Assistance Account

and has the authority under the Joint Powers

Act

10 to issue $60 million in loans to energy

impacted jurisdictions. (See discussion on

severance taxes, below, for a description of

additional Wyoming mitigation programs. )

Utah

In Utah, 32% percent of the mineral leasing revenues are dedicated to a Community

Impact Account (table 101). Established in

1977, it is a revolving fund for loans and

10 Wyo. Stat. §§9-1-l 29 through 136.

Table 100.—Wyoming Allocation of Federal Mineral

Lease Revenues

State Highway Fund for construction and maintenance of permanent roads and highways in

impacted counties . . . . . . . . . . . . . . . . . . . . . . . . .

Public School Foundation Fund. . . . . . . . . . . . . .

State Highway Fund ., . . . . . . . . . . . . . . . . . . . . .

University of Wyoming (pledged to bond

issues). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Incorporated cities and towns for planning, construction or maintenance of public facilities or

providing public services ($10,000 plus

formula). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Wyoming Government Royalty Impact Assistance Account (Farm Loan Board) . . . . . . . . . . . .

(a) For impacted incorporated cities and

towns, counties, joint powers boards without

existing revenue sources; and

(b) To fund planning, construction and maintenance of public facilities, provisions of public services or equipment purchases.

School District Capital Construction Account. .

2.25%

37.50

26.25

6.75

7.50

9.75

10

100%

SOURCE: Office of Technology Assessment

Table 101 .—Utah Allocation of Federal Mineral

Lease Revenues

Community impact account revolving fund . . . . . . 32.5%

Board of Regents-institutions of higher learning . 33.5%

State Board of Education. . . . . . . . . . . . . . . . . . . . . 2.25%

Geological and Mineralogical survey . . . . . . . . . . . 2.25%

State Water Research Laboratory . . . . . . . . . . . . . 2.25%

General fund appropriation . . . . . . . . . . . . . . . . . . . 27.25%

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100°/0

SOURCE: Utah Code Ann. 1953, 63.51-1 through 4

grants to political subdivisions that are

socially or economically impacted by mineral

resource development. 11 The account is particularly important since Utah is the only

Western coal-producing State without a coal

severance tax. For the 1978-79 period, Utah

received $13 million in mineral leasing

moneys of which $4,2 million was allocated to

the Community Impact Account. However, impacted communities requested more than $11

million. Most of the funds have been used for

water and sewer projects in communities

with critical growth problems.

The State requires that a majority of the

funds given to the Board of Regents for higher

education be spent for research, educational,

11 Utah Code Ann. 1953, §§53-7-l and 2: 65-1-64 and 65; and

65-1-1 15( 1979 Supp. ).
354 ● An Assessment of Development and Production Potential of Federal Coal Leases

and service programs to benefit communities provements. How much of this money ends up

economically or socially affected by mineral in energy impacted communities is difficult to

leasing activities. determine. New Mexico designates virtually

all of its Federal mineral revenues to the

Other Western States General Permanent Fund for the public

school textbook fund

The other Western States distribute funds North Dakota similarly

by a variety of formulas. Montana currently in the general fund for

provides 62.5 percent of its Federal royalties schools.

for schools and 37.5 percent for highway imand other purposes.

places all its royalties

distribution to public

Federal Programs To Assist

Energy-Impacted Communities

Loans Against Future

Leasing Revenues

Section 317(c) of the Federal Land Policy

and Management Act of 197612 authorizes the

Secretary of the Interior to make loans to

States against their share of anticipated

mineral leasing receipts for any prospective

10-year period. The loans, intended to address front-end financing problems, are to be

made specifically for relieving the socioeconomic impacts associated with Federal

mineral development activities. The program

has yet to be extensively used by the States. ”

Payment in Lieu of Taxes (PILT)

The Payment in Lieu of Taxes Act of 197614

provides Federal funds to local units of

government as compensation for taxes that

they cannot levy on the tax exempt Federal

lands within their boundaries. With regard to

coal development, annual payments are made

to local jurisdictions that contain land administered by the Bureau of Land Management (BLM) or the U.S. Forest Service. The

12 

Publjc Law 94.579: !IO Stat. 2743; 43 U.S.C. 1747.

1 IAccording to the CBO study, note 6 supra, the loan Program

met with initial objections from the executive branch because

of the low interest rates provided, In 1978, the act was amended to allow higher rates, thus removing the major objection. A

total loan level of $212 million was authorized through fiscal

year 1982, although no funds have been appropriated, and $40

million of the authorization expired in fiscal year 1979. See

Public Law 95-352, sec. l(c), 92 Stat. 515, Aug. 20, 1978.

“Public Law 94-565.

PILT funds are allocated under a formula

based on acreage, population, and revenue

producing programs on public lands such as

timber, grazing and mineral development.

Although not so designated, the funds are

often used for energy impact assistance. ’s

Total (coal and other) payments under PILT in

1979 were $105 million and in 1980 amounted

to approximately $108 million (table 102).

An important feature of PILT is that the

payments given to local governments are reduced by the amount of Federal mineral lease

revenues redistributed to these jurisdictions

by the States. That is, any lease revenues that

flow directly to local areas are deducted from

the per-acre PILT payments. This arrangement serves as an incentive for States to use

mineral royalties for purposes other than

returning them directly to impacted jurisdictions. But it makes no difference to the local

15 P1LT payments are made almost exclusively to county governments, since cities and towns generally do not contain BLM

or Forest Service lands.

Table 102.—Payments in Lieu of Taxes by State

State FY1980 payment

Colorado . . . . . . . . . . . . . . . $7,507,361

Montana. . . . . . . . . . . . . . . . 8,078,067

New Mexico . . . . . . . . . . . . . 9,589,751

North Dakota . . . . . . . . . . . . 571,552

Utah . . . . . . . . . . . . . . . . . . . 8,146,654

Wyoming . . . . . . . . . . . . . . . 6,550,736

SOURCE: Department of the Interior.
Ch. 12—Revenues and Socioeconomic Impacts ● 355

governments, since they receive equal sums,

either from Federal PILT payments or from

the State’s share of mineral lease receipts.

Abandoned Mine Reclamation Funds

The Surface Mining Control and Reclamation Act of 197716 provides for annual grants

to States to help develop, administer, and enforce statewide reclamation programs. The

programs are for Federal and non-Federal

lands disturbed by coal mining. The act also

establishes Federal and State abandoned

mine reclamation funds, financed primarily

by revenue derived from a reclamation fee of

$0.35/ton of surface-mined coal and $0.15/ton

of underground-mined coal, or 10 percent of

the gross value of the coal, whichever is less.

Fifty percent of the reclamation fees collected annually in any State must be allocated to the State’s abandoned mine reclamation fund. This in turn must be used to reclaim

any land mined for coal and abandoned (or

otherwise left in an inadequate reclamation

status) prior to 1977. If all such land in a

State has been reclaimed, the State may use

its 50 percent of the fees for construction of

public facilities in communities impacted by

coal development. 17 The State must certify,

and the Secretary of the Interior agree, that

there is a need for such facilities and that the

moneys available under the Mineral Leasing

Act or the PILT payments are inadequate for

such construction.

Since the Western States until recently

have had little large-scale coal mining, they

have fewer abandoned, unreclaimed coal

mines than the Eastern States. Therefore

they are more likely to qualify to use their 50

percent for public facilities in coal impacted

communities, This could be a major source of

funds for Western States with approved

reclamation programs.

16Public Law 95-87, 91 Stat. 445, 30 U.S.C. 1201 et seq. Title

4 of the act established the Reclamation Fund.

’

7

30 U.S.C. 1233(g)(1).

"601" Program

A Federal program for energy impacted

areas was established by section 601 of the

Powerplant and Industrial Fuel Use Act of

1978.

18 Administered by the Farmer’s Home

Administration in the Department of Agriculture, it provides funds for planning assistance and acquisition of land for housing and

public facilities in communities affected by

coal or uranium development. Individual

States have not received much assistance

from section 601 programs because of the relatively small appropriation ($20 million in

1979 and $50 million in 1980), the statutory

limitations on the use of the money, and the

large number of States that have applied for

assistance.

Other Federal Programs

BLM is supporting a project on the social

effects of the Federal coal management program in the West.19 The project will develop a

guide for social impact assessment to help fill

existing data gaps and remove some theoretical uncertainties about community disruption. Because it is designed to improve the generic process, the project should, in the long

run, significantly improve the social and economic mitigation aspects of Federal leasing

efforts.

A variety of other programs, not directed

at energy or mineral development, is also

available to State and local governments;

however, only a few deal with socioeconomic

problems. According to various authors, from

30 to 165 programs have been useful to boomtown communities.20

,8PUh]iC La-w 95.620; 92 stat. 3323 [ 1978).

1gBLM Social Effects Project, Mountain West Research, Inc.,

Billings, Mont.

?OThe following reports provide information USf3ful tO impacted communities:

An Assessment of Oil Shale Technologies (ch. 10), OTA, GPO

stock No. 052-00340759-2 (Washington, D. C.: Government

Printing Office, 1980).

Energy Development in the Western United States—Impact

on Rural Areas, Murdock and Leistritz (New York: Praeger

Publishing,1979).

Report to the President-Energy Impact Assistance, Energy

Impact Assistance Steering Group (Washington, D. C.:
356 ● An Assessment of Development and Production Potential of Federal Coal Leases

State Programs

Each State has developed ways of providing technical and financial assistance to

energy impacted areas. In addition to traditional revenue sources such as sales, income,

and excise taxes used to support general programs, Western States have relied on three

specific sources for energy impact mitigation.

These are Federal mineral royalties, State

severance taxes, and bonding authority. In

most States, severance tax revenues contribute the most aid.

Severance Taxes

A severance tax maybe broadly defined as

a special levy assessed at flat or graduated

rates on the extraction of natural resources.

Severance taxes are distinguished from other

taxes by their imposition on the removal of

the natural resource rather than on the resource itself. Legally, severance taxes are

generally held to be excise rather than property taxes and, as such, are not subject to the

constitutional requirements placed on property taxes of uniformity and equality. There

has been much controversy on the nature,

level, and distribution of severance taxes.

Some of the arguments cited in support of

severance taxes include:

●

●

Natural heritage.—A State’s natural resources are an irreplaceable heritage of

the people of the State. A severance tax

is compensation for a portion of the irretrievable loss of this wealth.

Conservation of natural resources.—If a

tax is high enough, the increased price

of the extracted mineral should slow the

rate of resource exploitation and stimuContinued from p. 355.

DOE/IR-0009, 1978).

Mitigating Adverse Socioeconomic Impacts of Energy Development, Denver Research Institute (Denver: DRI, 1977).

Federal Assistance for Energy Impacted Communities,

Mountain Press FRC (Denver: MPFRC, 1979).

The Direct Use of Coa~ (ch. 6), OTA, GPO stock No, 052-

003-00664-2 (Washington, D. C.: U.S. Government Printing Office, 1979).

●

●

●

late the substitution of alternative technologies and/or renewable resources.

Internalization of socioeconomic costs,

—The significant public costs associated

with large-sale mineral development can

be internalized by levying a severance

tax. If the tax is shifted to consumers, a

price for the resource can be established

that reflects a truer cost of production,

both public and private.

Capture of economic rent.—According

to the concept of economic rent, the finite nature of natural resources results

in a market price that includes a portion

representing pure surplus that can be

taxed away without affecting consumer

price, production levels, or allocation of

resources. For example, in passing the

Montana Coal Severance Tax Act, the

Montana Legislature declared tha t

“coal in Montana, when subbituminous

and recoverable by strip mining, is in

sufficient demand that at least one-third

of the price it consumes at the mine may

go to the economic rents of royalties and

production taxes.”

Statewide sharing of tax benefits.

—Since mineral development oftenoccurs in less populated rural areas, more

populous regions sometimes feel they deserve a larger share of the benefits from

this development. In addition, areas

away from the immediate energy-producing regions can be affected by energy

development. For example, between

1975 and 1978, approximately 75 percent of Colorado’s growth in mining

employment occurred not in the outlying

resource areas but in the Denver metropolitan area. A severance tax can help

spread benefits throughout the State.

State Income From Severance Taxes

Colorado, Montana, New Mexico, North

Dakota, and Wyoming impose severance

taxes. Of the coal-producing States, only Utah

does not; however, Utah does impose a mining
Ch. 12—Revenues and Socioeconomic Impacts . 357

—— --.-— --- - —

occuaption tax on various minerals (excluding coal). Figure 53 shows severance tax income from all minerals, not just coal, and the

portion of total State revenues contributed by

severance taxes. Wyoming ranks highest in

percentage (25 percent) of State revenue

derived from severance taxes. New Mexico

received the largest amount ($159 million in

fiscal year 1979), although only 13 percent

was from coal. A common trend is the increase over the pastI 5 years in funds available to the States through these taxes.

In general, coal severance taxes are calculated either as a flat rate of production or as

a percentage of net or gross value of the coal

produced. Table 103 shows the different

bases currently used for assessing severance

taxes. The 30-percent rate in Montana is the

highest of the Western States and its constiFigure 53.—Total Severance Tax Revenues

(all minerals)

Thousands of dollars Percent of State revenues

1975 1976 1977 1978 1979

Fiscal years

SOURCE: Office of Technology Assessment.

Table 103.—Coal Severance Taxes

Colorado

Coal—Surface $0.63/ton

Underground $0.315/ton

Adjusted by wholesale price index.

Montana

Heating

quality Surface

(Btu/pound) mining

Under 7,000 $0.12 or 20% of value

7,000-8,000 $0.22 or 30% of value

8,000-9,000 $0.34 or 30% of value

over 9,000 $0.40 or 30% of value

Underground

mining

$0.05 or 3% of value

$0.08 or 4% of value

$0.10 or 4% of value

$0.12 or 4% of value

Resource indemnity trust tax (all minerals):

$25.00 plus 0.5 percent of gross value of product

if in excess of $5,000.

New Mexico

Coal—Steam coal $0.57/ton

Adjusted by consumer price index escalator (in 1981

total tax is $0.73 per ton)

North Dakota

Coal—Steam coal $0.50/ton

Adjusted quarterly based on wholesale price index.

Wyoming

Coal 10.50/0 of gross value

SOURCE: CERI, Mineral Severance Taxes in Western States; A Comparison,

PP. 5-15 and Office of Technology Assessment survey of State

Revenue Agencies, January 1981

tutionality has been challenged by mining

companies and coal consumers. On July 2,

1981. the U.S. Supreme Court ruled that Montana could impose a severance tax this high

without violating either the Commerce Clause

or the Supremacy Clause of the United States

Consitution. 21

Allocation of Severance Taxes Revenues

Table 104 summarizes the distribution of

coal severance tax revenues. New Mexico

does not follow a specific allocation formula;

instead, all its revenues are placed in the

Severance Tax Bonding Fund. Each year the

legislature authorizes the issuance of bonds

for a variety of projects, including impact

assistance. Any portion of the fund that is not

pledged to the principal and interest on

outstanding bonds is deposited in the Severance Tax Permanent Fund. The Community

Assistance Authority makes recommendations for the issuance of bonds for projects in

areas affected by mineral and energy develop21Commonwealth Edison Co. v. Montana, No. 80-581, July 2,

1981 (slip opinion).
358 “ An Assessment of Development and Production Potential of Federal Coal Leases

Table 104.—Allocation of Coal Severance Tax Revenues

Category Colorado Montana New Mexicoa North Dakota Utahb Wyoming

General fund . . . . . . . . . . . . . . . . O% (1981 and after) 19.00% 30% 19.0%

(20% 1980)

Permanent trust fund . . . . . . . . . 50% (1981 and after) 50.00% 15% 23.9%

(35% 1980)

Local government . . . . . . . . . . . . 50%c

8.75% 10% 35%d

19.0 %

e

Other . . . . . . . . . . . . . . . . . . . . . . . 22.25%f

20%g

38.1 ‘/Oh

a Reallocated annually by legislature

b Utah has no severance tax

C

15 percent of local government severance tax fund is automatically distributed to affected jurisdiction in proportion to the number of mine employees who reside in

the county’s unincorporated areas. Remaining 85 percent is distributed at discretion of Executive Director of Department of Local Affairs, with advice from an energy

impact assistant advisory committee.

d The Coal Development Impact Fund is administered by Coal Development Impact Office that makes discretionary grants to impacted communities

e The Coal Impact Fund, administered by the Farm Loan Board consisting of key State officials, makes grants to local governments in special districts affected by coal

production for financlng water, sewer, highway, road and street projects.

f This category includes 5 percent for school equalization, 10 percent education trust, 0.5 percent county planning, 2.5 percent alternative energy research, 1.25 percent

renewable resource development, 25 percent parks, hlstorical and cultural sites and 0.5 percent library commission.

g Distributed to counties on the basis of the proportion of the total State coal production In that County

h This is comprised of 14.3 percent in water development fund, 95 percent in highway fund, and 14.3 percent in capital facilities fund which is used for State government facilities, school buildings, and community colleges.

ment, and $10 million is allocated annually

for the specific purpose of making grants to

impacted communities.

Colorado gives energy developers a credit

against their severance taxes for certain approved contributions made to local communities to assist with preventive efforts before

a project begins operation.

Colorado, Montana, North Dakota, and

Wyoming place a percentage of their coal

severance tax revenues in trust funds. These

funds are intended to compensate future generations for depletion of nonrenewable resources. The purposes of the funds are stated

in general terms; the most common areas for

investment are the reestablishment and diversification of the economic base in anticipation of the day when the mines are exhausted.

The funds also can be used to redress any

long-term environmental consequences of

prolonged coal mining, They are in part a response to the boom and bust cycles that have

historically characterized mineral development in the West.

Four of the seven Western coal-producing

States—Wyoming, Montana, New Mexico,

and North Dakota—have passed constitutional amendments establishing permanent

mineral trust funds. The term “permanent”’

means that a three-fourths vote of both

houses of the legislature is necessary before

the principal can be disbursed for any purpose. Such precautions are designed to

preserve the integrity of the principal. Colorado has a permanent trust fund established

by statute that has no restriction on payments

from its principal; however, the State has not

yet spent any of the principal. In most States,

the income from investment of the permanent

trust funds is either deposited directly in the

general fund or otherwise made available for

legislative appropriation. Thus, these permanent trust funds, unlike the remainder of the

severance tax revenues, do not contribute a

large proportion to impact assistance.

Table 104 also shows the percentage of

severance taxes placed in the State general

funds. These percentages are relatively low

(30 percent in North Dakota is the highest).

The allocations to local governments represent direct distributions to communities, and

do not include any remaining percentages indirectly available to these jurisdictions. In

Montana, for example, impacted towns are

directly allocated only 8.75 percent of revenues, but they could also receive indirect

benefits from general fund disbursements,

such as county planning appropriations, or

cultural and historic site moneys.

In addition to mechanisms to dispense revenues, Wyoming has created several govern-
Ch. 12—Revenues and Socioeconomic Impacts ● 359

mental agencies to help mitigate the socioeconomic impacts. In 1974, the legislature

passed the Joint Powers Act 22 to encourage

various levels of government to cooperate in

the financing of public facilities. Local governments (e.g., cities, counties, school districts) can join together to become eligible for

Joint Powers Loans.

In 1975 the legislature created the

Wyoming Community Development Authority

(WCDA) to help alleviate housing shortages.’{

It is designed to compensate for the lack of

funds in the private mortage lending market.

WCDA is authorized to issue up to $250 million in bonds that provide assistance through

private lending institutions and through purchase of mortgages in areas of capital shortage. The program became fully operational in

1979 and more than $200 million in WCDA

bonds were committed as of the end of 1979.

Several other programs are valuable to

jurisdictions with rapid growth. For instance,

if a school district is nearing the limit of its

bonded indebtedness and faces expenses beyond its financial capacity, it may apply to

the Farm Loan Board for emergency construction funds, A $2 million account within

the Permanent Trust Fund is reserved for this

purpose. In addition, the legislature has

granted counties the authority to institute an

additional l-percent sales tax.24 This tax must

be distributed on the basis of population; as a

result, cities and towns with increased population get a greater proportion of the revenue than counties.

State Energy Facility Siting Programs

While most States analyze the physical environmental effects of siting major energy facilities, only a few have developed programs

to deal directly with the socioeconomic aspects of this siting. Montana and Wyoming

are two that have mechanisms specifically

addressing such impacts. The primary aim of

these programs is to ensure that industry participates in appropriate mitigation efforts.

The Wyoming Industrial Development Information and Siting Act was passed in 1975

largely in response to the social and economic conditions in boomtowns such as Rock

Springs and Gillette. ” The act requires that,

prior to construction, major energy developers predict likely social and economic impacts and commit themselves to a number of

monitoring and mitigation strategies. An Industrial Siting Council has broad latitude to

determine compliance with an elaborate set

of criteria. The council must approve all projects with a total cost of over $63 million and

certain other projects with the potential for

substantial community or environmental impact.

The Montana Major Facility Siting Act26)

has a checklist of socioeconomic criteria requiring an applicant to give consideration to

impacts on the population already in the

area, on the population attracted by construction and operation of the facility, and on

public services and facilities. Coal mines producing more than 500,000 tons per year, most

electric generating facilities, and synfuels

plants must obtain a siting certificate.

The Montana Board of Natural Resources

and Conservation has discretion to place conditions on the siting certificate. For instance,

in the case of the application for generating

units 3 and 4 at Colstrip, the Board asked

Montana Power to set up a training program

for Northern Cheyenne Indians wishing employment in the construction and operation

work force.

“Wyo. Stat. tj~9-1-129 through 136.

~BWyo. Stat. $~g-18-lol through 123.

ZWIIYO, Stat. 5$39-6-412.

zswyo. Stat. cjtj35-I 2-101 through 121 ~ ZbMont. Rev. (lodes Ann. $~75-20-101 through 1205 (1979

Supp.)

 0 - 81 - 24 : ‘ 1, 3
360 “ An Assessment of Development and Production Potential of Federal Coal Leases

Effects of Expanded Federal Coal Production

Industrial development in sparsely populated rural regions inevitably brings changes

in the established social patterns. Thes e

changes are seen as mixed blessings. On the

one hand, a larger tax base, the expansion of

retail services, and an improvement in public

services are viewed as positive. On the other,

housing shortages, crowding of facilities such

as schools, and locally high inflation are seen

as negative impacts. Residents respond in a

variety of ways. Some welcome the changes

as indications of prosperity; others lament

them for the loss they bring to the earlier

ways of life.

Whether communities are able to adapt to

rapid growth depends on a complex set of elements, many of them site-specific. In any

case, the combined efforts of private entities,

especially the energy developers, and public

agencies, particularly local and State governments, are necessary to deal with th e

changes.

The effects of expanded Federal coal leasing will depend on the interaction of many

factors. These include:

●

●

●

Magnitude of the growth.—The direct

and indirect population influx from a

large energy project may double o r

quadruple the size of a small rural community.

Pace of the development. — Energy-related growth occurs suddenly and progresses rapidly, frequently with major

impacts in the first few years of the d e -

velopment. Rural communities often are

ill-prepared for this surge.

Fluctuating nature of the growth.—During the construction period there may be

large increases and decreases in population. The permanent operating forc e

often is significantly smaller than the

construction one. Communities must prepare for large temporary populations,

especially in the case of powerplant construction.

●

●

●

●

●

Uncertainty. —The timing of develop

ment is often uncertain because o f

changes in project economics and financing, shifts in State and Federal policy, and the risks associated with large

energy projects. The unpredictable future of development makes initial investment in community facilities and services risky and difficult.

Condition of existing municipal services

and facilities, —Existing facilities have

little excess capacity or elasticity. In addition, they may require extensive upgrading. The condition of many services

and facilities is such that replacement

may be required; and an isolated location usually means higher construction

costs.

Availability of fiscal and other aid.—Improvement of public services and facilities must occur during the early stages

of industrial expansion; this takes place

before an enlarged tax base is established. The front-end financing problem

is usually one of timing rather than a

long-term shortfall, since the increase in

public revenues may ultimately exceed

the total cost of municipal expansion.

That the problem is one of timing rather

than net loss in the long term, however,

does not make it less severe.

jurisdictional problems.—A new energy

facility and the increased tax base it

generates are frequently located in one

political subdivision while the population settles in another. For example, energy facilities may be located in the unincorporated portions of counties (which

derive revenues from the project), while

the majority of new workers settle in adjacent towns (which legally cannot share

in these revenues).

Private sector [commercial) infrastruc -

ture.—As in the public sphere, private

sector services often require expansion;

small towns generally have only basic

commercial establishments. Lack o f
Ch. 12—Revenues and Socioeconomic Impacts 361

capital. absence of experienced entrepreneurs, and competition with energy

industries for labor and supplies can all

contribute to delay in the expansion of

local businesses.

• Characterstics of the region. —Some

areas have experienced past booms and

busts and are accustomed to their disruptive effects; others have not and the

residents may be unprepared for boomtown problems.

● Concurrent expansion of other indus -

tries in the same location.—Many of the

most severe problems have been associated not with coal mining, but with major powerplant construction. Although

major disruptions in sparsely populated

and homogeneous communities could

occur from the number of mines and ancillary activities necessary to support

large-scale coal production, the biggest

problems will come from total energy development. Thus, the greatest potential

for major socioeconomic dislocations exists where more than one energy-related

development is expected.

The remainder of this chapter examines

the potential for adverse social and economic

consequences in the coal development regions studied by OTA. The State task force reports, from which the following discussions

are drawn, include consideration of how socioeconomic conditions could influence Federal coal development. The task forces concluded that socioeconomic and community

conditions would not be a significant constraint on the development of existing leases.

This is because industry is concerned with

problems such as labor turnover, and State

and local governments have experienced

some adverse consequences of coal-related

growth. As a result, prospective developers

and impacted communities will probably take

appropriate steps to deal with any emerging

problems,

Colorado

To handle the negative effects of energy development, Colorado has adopted an impact

mitigation strategy involving local citizens,

regional Councils of Governments, and a

statewide office to coordinate efforts. The

strategy has been successful in developing

both public and private solutions to growth

problems. Nevertheless, some communities

have already experienced negative consequences from coal development, and the potential for future difficulties exists. OTA’s estimates of potential production (see ch. 6) indicate that areas already experiencing problems are the most likely to face future difficulties.

The northwest and west-central are such

regions (fig. 54 and table 105). For example,

all eight of the proposed new lease tracts in

Colorado are within 25 miles of Craig. The

erection of two new coal-fired units at the

Craig station, possible building of a synthetic

fuels plant, and construction of major regional reservoirs in the next 10 years could

Figure 54.—Counties of the Rocky Mountain Study

Area

I

h !, f.

\

. “, . . I I 1

. . v > . . . .

,.. ,,,

. ,.,

., .?’.

. .

I.-.<,

/

m .“ ..,. , .“. ., . . . .

(’ . .,.4 ,,.

. . . ,.

!., ..,

~

. .

“.. ,.

.,, . ,,

I .,.

SOURCE: Office of Technology Assessment.
362 . An Assessment of Development and Production Potential of Federal Coal Leases

Table 105.—Demographic Characteristics of Selected Counties in Colorado, Utah, and New Mexico

Colorado

Percent Total acreage Average

Total change Percent of land in Percent

population a

size of

1970 to Land areab People 65 years farms b

of all land farms b

County 1970 1980 1980a

(mi2) per mi2b and olderb (1,000 acres) in farmsb(acres)

Delta . . . . . . 15,286 21,225 38.90/o 1,154 15 18.90/o 282 38.1 0/0 338

Elbert . . . . . . 3,903 6,850 75.5 1,864 3 11.0 2,106 90.6 2,106

Garfield . . . . 14,821 22,514 51.9 2,996 6 10.5 397 20.7 1,161

Gunnison. . . 7,578 10,689 41.1 3,110 3 4.6 262 12.7 1,638

Jackson . . . . 1,811 1,863 2.9 1,622 1 8.4 470 45.3 5,114

Las Animas . 15,744 14,897 – 5.4 4,794 3 15.6 2,118 69.0 5,205

Moffat . . . . . 6,525 13,133 101.3 4,743 2 8.3 1,146 37.8 4,604

Montrose. . . 18,366 24,352 32.6 2,238 9 11.0 429 30.0 558

Ouray . . . . . . 1,546 1,925 24.5 540 3 9.7 157 45.5 2,097

Pitkin . . . . . . 6,185 10,338 67.1 973 9 2.8 49 7.8 1,016

Rio Blanco. . 4,842 6,255 29.2 3,263 2 8.3 480 23.0 2,907

Routt . . . . . . 6,592 13,404 103.3 % 2,330 4 6.30/o 650 43.60/o 2,391

Utah

Carbon. . . . . 15,647 22,179 41 .7% 1,476 12 10.3% 363 38.4% 2,523

Emery . . . . . 5,137 11,451 122.9 4,439 1 9.9 219 7.7 589

Garfield . . . . 3,157 3,673 16.3 5,158 1 10.6 120 3.6 668

Kane . . . . . . 2,421 4,024 66.2 3,904 1 9.4 205 8.2 1,831

Sevier. . . . . . 10,103 14,727 45.8% 1,929 6 18.1% 199 16.2% 483

New Mexico

Colfax . . . . . 12,170 13,706 12.6% 3,764 3 12.4% 2,269 94.2% 8,561

McKinley . . . 43,208 54,950 27.2 5,454 9 4.4 3,363 96.4 28,264

Rio Arriba . . 25,170 29,282 16.3 5,843 5 8.0 1,468 39.3 2,531

Sandoval . . . 17,492 34,799 98.9 3,714 6 7.6 790 33.2 3,249

San Juan . . . 52,517 80,833 53.9% 5,500 12 5.3% 1,912 54.3% 4,698

a 1980 Census of population and Housing: Advance Reports, U.S. Bureau of the Census March 1981 (PHC80-V).

b 1975 data, City and County Data Book, U.S. Bureau of the Census, 1977

SOURCE: U.S. Bureau of the Census.

add to the population influx from coal development.

Craig has been handling growth for some

time (the population of Moffat County has

doubled since 1970) with the help of State impact assistance funds and professional city

management. However, the amount of money

that is returned to Craig from Federal royalties and State severance taxes is small compared to the revenues generated, and this disparity is a sore point with local leaders,

new coal miners and construction workers to

settle there, the town expanded its waterworks. But the growth failed to materialize,

and now Hayden residents are having trouble

paying the debt from this expansion. Similarly in Craig, the population dropped from layoffs a t mines and from completion of unit 2 at

the powerplant, but the voters have had to

decide on a referendum for a $7 million bond

issue to double the current capacity of the

water system.

Nearby, at Hayden, the problem of fluctu- Meeker illustrates the difficulties of planating growth cycles can be seen. Expecting ning ahead for growth. Work force estimates
Ch. 12—Revenues and Socioeconomic Impacts . 363

for possible oil shale projects range from

2,200 to 3,600 people per facility; including

families and secondarily induced service personnel, over 10,000 people could conceivably

move to the town. If the oil shale endeavors

proceed according to some plans, the area

could experience a 400- to 600-percent increase in population by 1985.27 The uncertainties associated with oil shale development,

however, make it difficult to prepare for this

growth, Concurrent expansion of coal production would add to these difficulties,

Rangely illustrates the problem of jurisdictional mismatches. This town, already the

center for oil and gas development, is ready

to absorb some new residents. Workers will

come from the Federal oil shale tracts in Colorado once a road is completed. They are also

apt to come from coal and oil shale developments in Utah, since Rangely is closer to these

sites than Vernal, Utah. In this case, Rangely

will bear the costs of accommodating the

workers without the benefit of tax revenues

from the properties.

Rio Blanco County has recently completed

an agreement with Western Fuels Associates

for impact mitigation. The company's proposed Deserado mine near Rangely will supply coal for a powerplant at Bonanza, Utah.

Under the agreement, support will be provided for expansion of water and sewer facilities, schools, highways, and both municipal

and county services (planning, medical, fire

protection, recreation, and other services).

The arrangements are based on the expected

arrival of 1,500 new residents in the Rangely

area. About $15 million will go for mitigation;

this is 5 percent of the projected $300 million

cost of the development,

In recognition of the fact that unpleasant

living conditions lead to low productivity and

high worker turnover, many energy developers have taken the initiative to help communities. Industry has contributed to the provision or upgrading of facilities and services,

has assisted with housing development for

workers, has prepaid taxes, and has taken

“Meeker’s population was 1,597 in 1970 and 2,356 in 1980.

other steps such as offering training programs for local workers. For example, early

in 1981, Northern Coal Co. announced it had

arranged to build 18 apartments in Meeker

as temporary housing for its employees. Approval has been given for a 104-lot development, sponsored by industry, for permanent

housing. In addition, Northern Coal has prepaid $318,500 in severance taxes to help fund

municipal improvements.

Utah

Utah has two major coal regions with Federal leases— the Uinta region including Carbon, Emery, and Sevier Counties in the central part; and the Southwestern region encompassing Garfield and Kane Counties in

southern Utah (fig. 54 and table 105).

The central area has historically been a

coal producing region. Mining and related

construction have been, and remain, the major economic activities, In the past, conditions

in the coal market have had a direct effect on

these counties. From 1950101970, during depressed market times, they experienced declining populations. Since 1970, with an improved market, they have had significant

growth: for instance, mining employment increased over 200 percent in Emery County in

the first half of the 1970’s.

There is disagreement over whether or not

increased coal development will cause socioeconomic problems in central Utah. For example, in preparation of the DOI final environmental impact statement for coal development, the most extensive criticisms revolved

around the social impact analysis.

The disagreements were also reflected in

the OTA task force for Utah that reviewed

the data for this assessment, The task force

generally assumed that impacts could be

dealt with adequately and community requirements would not be a factor discouraging mine development. However, county

commissioners and other local residents interviewed by OTA staff expressed concern

about the capability of the area to absorb and

support development without major disrup-
364 “ An Assessment of Development and Production Potential of Federal Coal Leases

tion of existing communities and displacement of their ways of life; they cited loss of irrigated cropland and higher real estate assessments among their concerns.

The State government has adopted a policy

to promote dispersed development. The intention is to spread the benefits and impacts of

coal development more evenly and thus avoid

the adverse consequences of more concentrated growth.

Development of coal leases in the Alton and

Kaiparowits coalfields in southern Utah

would require new or expanded facilities.

The area is sparsely populated and rural,

without large communities. Agriculture and

tourism are the principal industries. A significant portion of the work force needed to operate coal mines would have to be brought into

the area; new communities would have to be

constructed to provide for the miners, support personnel, and their families.

One of the greatest concerns about coal development in Utah is the potential for change

in the character of the communities. Many

believe the entry of new residents would alter

the generally homogeneous religious and

cultural composition of the present social

fabric. This perception of “outsiders” is a

relatively recent development, and may stem

in part from the residents’ greater recognition of the magnitude of the development being proposed. The view residents have of activities elsewhere may also be contributing to

their concern. In southern Utah the impression of the Price area (in the central part of

the State) is that of a boomtown, similar to

Rock Springs, Wyo. Many southern Utah residents feel that substantial changes in Price’s

character have taken place and they wish

to avoid similar alterations. The possible

changes in community composition or way of

life are also a predominant concern behind

much of the local opposition to the proposed

MX missile system.

In sum, the potential for socioeconomic

changes appears high in Utah, assuming that

planned coal development proceeds. At the

same time, there is widespread disagreement

as to whether these would be undesirable

changes. Central Utah has been an historic

coal mining area; booms and busts are not unknown to these towns. Southern Utah is

sparsely populated and coal development

would require establishing a different social

and economic infrastructure to meet the

needs of a larger and more , diverse population.

New Mexico

Like Utah, New Mexico has the potential

for extensive socioeconomic changes, and the

probability of these changes being negative

appears high. The State recognizes the possible effects of industrial expansion on local

government and has funded studies and projects in preparation for energy development.

Large-scale expansion of coal mining and

construction of powerplants or synthetic fuel

projects in the San Juan basin could severely

strain existing social and economic institutions. The problems would be particularly severe in remote coal regions where there are

now few or no community facilities and services (table 105; fig. 54),

OTA’s analysis (see ch. 6) indicates coal

production could double or triple in the Star

Lake-Bisti region (assuming the completion of

the railroad). The towns of Cuba, Grants, and

Milan would be most affected by the new

mines and the construction, operation, and

maintenance of the proposed Star Lake Railroad. Uranium and oil and gas development

are also planned, and considerable public

concern about the impact of uranium mining

on the community of Grants has been expressed.

The town of Cuba is located near several

new Federal coal developments; it is the closest community to the proposed La Ventana,

Star Lake, and Black Lake mines. Cuba lacks

the capability to provide the services needed

to handle the expected growth. For example,

water quality in this region is poor and its

availability for domestic use is limited. Transporting water to Cuba from other parts of the

State has been under study. The town is cur-
Ch. 12—Revenues and Socioeconomic Impacts ● 365

rently burdened with financial obligations, including $651,000 in outstanding bonds, that

limit its ability to underwrite new projects.

The Farmington, Bloomfield, and Aztec

areas expect a construction boom that is projected to peak in 1985-86. A State Commission

has established as high priority the repair

and construction of new roads from the

Farmington area to Cuba needed to handle

the expected increase in coal traffic. In Farmington a housing shortage exists and water

for residential use is not plentiful.

Because of the landownership patterns in

New Mexico, off-reservation Indian lands

and communities will be affected by the development of existing Federal leases. Mitigation efforts will require, in addition to State

government participation, involvement of Tribal governments and local Indian pueblo

councils, as well as consultation with DOI’S

Bureau of Indian Affairs.

Wyoming and Montana

OTA focused on two regions in Wyoming

and Montana: the Powder River basin, and

southern Wyoming. A map of these areas and

the nearby communities is found in figure 55;

demographic indices are in table 106.

An early study of the socioeconomic impacts of increased coal development in the

Northern Great Plains28 reached the following

conclusions:

●

●

●

Population increases attributable to coal

development will be large, and attendant

problems will be compounded because

such increases will be both rapid and

unevenly distributed.

Most communities in the Northern Great

Plains are not prepared to deal with the

magnitude of change attending regional

coal development.

The rapid influx of population will cause

a proportionally greater increase in de28Northern Great Plains Resource Program, 1974. This extensive study covered the five States of Montana, Nebraska, North

Dakota, South Dakota, and Wyoming; it was funded in large

part by the Department of the Interior.

SOURCE” Off Ice of Technology Assessment.

mand for services because newcomers

often have higher expectations for services than native residents.

Public service requirements will increase at a much faster rate than revenue collection, especially in the early

years of development. The service areas

of particular concern are housing,

health care, and education.

These expectations were confirmed by subsequent experiences in the region. For example, Rock Springs, located in Sweetwater

County in southwestern Wyoming, was the

subject of a classic study of boomtown phenomena.

29 The population increased from

18,931 to 36,900 from 1970 to 1974. The ability to provide municipal and other local services declined markedly. The ratio of doctors

4

29 John S. Gilmore, and Mary K. Duff, Boom town Growth Management: A Case Study of Rock Springs—Green River, Wyo.

(Boulder, Colo.: Westview Press, 1975).
366 ● An Assessment of Development and Production Potential of Federal Coal Leases

Table 106.—Demographic Characteristics of Selected Counties in North Dakota, Wyoming, and Montana

North Dakota

Percent Total acreage Average

Total change Percent of land in Percent size of

population 1970 to Land areab Peopleb

65 years farms b

of all land farms b

County 1970 1980 1980a(mi2) per mi2and olderb (1,000 acres) in farmsb

(acres)

Bowman . . . 3,901 4,229 8.40/o 1,170 4 10.3% 712 95.6% 1,873

Burke . . . . . . 4,739 3,822 – 19.4 1,119 3 16.2 661 92.4 986

Grant . . . . . . 5,009 4,274 – 14.7 1,666 3 10.7 1,091 95.6 1,230

Hettinger. . . 5,075 4,275 – 15.8 1,134 4 11.3 758 99+ 1,244

McLean . . . . 11,251 12,288 9.2 2,065 6 14.3 1,236 93.5 935

Mercer ., . . . 6,175 9,378 51.9 1,042 6 12.1 608 91.2 944

Oliver . . . . . . 2,322 2,495 7.5 721 3 7.6 419 90.9 1,072

Ward . . . . . . 58,580 58,392 – 0.3 2,044 30 7.4 1,256 96,0 881

Williams . . . 19,301 22,237 15.20/o 2,064 9 10.60/0 1,241 93.90/0 1,122

Wyoming

Campbell. . . 12,957 24,367 88.1 “/0 4,756 3 5.0% 7,069 95.5 ”/0 7,069

Carbon. . . . . 13,354 21,898 64.0 7,905 2 7.9 2,628 51.9 10,905

Converse . . . 5,938 14,069 136.9 4,281 2 9.6 2,440 89.0 8,904

Johnson . . . 5,587 6,700 19.9 4,175 1 15.2 2,127 79.6 8,645

Sheridan . . . 17,852 25,048 40.3 2,532 8 14.7 1,471 90.8 3,226

Sweetwater. 18,391 41,723 126.90/o 10,429 3 6.40/o 1,764 26.40/o 16,640

Montana

Big Horn . . . 10,057 11,096 10.3% 5,023 2 7.20/o 2,648 82.50/o 5,212

Madison . . . 5,014 5,448 8.7 3,528 2 13.1 1,191 52.8 3,103

Musselshell. 3,734 4,428 18.6 1,887 2 15.1 1,210 99+ 5,628

Rosebud . . . 6,032 9,899 64.1 0/0 5,037 2 6.50/o 3,009 93.30/0 8,798

a 

1980 census of population and Housing: Advance Reports, U.S. Bureau of the Census, March 1981 (PCH80-V)

b

1975 data. City and County Data Book, ‘U.S. Bureau of the Census, 1977.

SOURCE: Bureau of the Census.

to population changed from 1:1,800 in 1970 to

1:3,700 in 1974 (in contrast to an average

statewide ratio of 1:1,100). In 1974, county

schools were short an estimated 128 schoolrooms; approximately 1,397 homesites had no

municipal services; and 4,599 mobile-home

spaces were needed. Caseloads in mentalhealth clinics increased eightfold. Crime

rates increased by 60 percent between 1972

and 1973 alone, while police services remained relatively constant.

Other towns affected by nearby coal mining include Forsyth and Colstrip, Mont.; and

Sheridan, Gillette, and Douglas, Wyo. Some

of them have been better able to handle the

impacts than others; and the mining company

mitigation efforts have been different in each

community.

Colstrip was originally developed by the

Montana Power Co., for its workers at the

Rosebud Mine and the Colstrip Power Plants.

Workers at Peabody’s nearby Big Sky Mine

had to commute daily from Forsyth, about 40

miles away. In the last few years, Montana

Power has begun to transfer ownership of the

town of Colstrip, and Big Sky Mine workers

are purchasing houses there.

Sheridan, Wyo., has grown from mining developments around Decker, Mont. Workers at

the East and West Decker and Spring Creek

mines live in Sheridan although they work in
Ch. 12—Revenues and Socioeconomic Impacts ● 367

Montana. Sheridan has taken this growth in

stride, although the county has difficulty obtaining sufficient funds for its general budget

to meet operating expenses. 30 Increased housing costs, in large part from energy development, have created hardships for elderly residents on fixed incomes.31

Gillette, too, has had difficulty. During an

oil boom in the 1960’s, the adverse psychological effects of rapid growth were so pronounced that they came to be known as the

“Gillette syndrome.” Now, with coal development, careful planning appears to be controlling some of the problems seen in the

earlier period. A new town, built to hous e

workers at mines south of Gillette, was able

to accommodate a population of 1,400 within

3 years after construction began.32

Douglas, Wyo., which already has experienced rapid growth, will have substantial additional impacts with the development of new

projects, and Rock Springs continues to show

boomtown symptoms, Workers for the Jim

Bridger, Black Butte, and Stansbury mines

live there. The Wyoming Industrial Siting

Council has asked industry to reevaluate the

impacts of the Jim Bridger Mine and Power

Plant on Rock Springs. The community is seen

as an undesirable place to live and turnover

is growing at the mines. The development of a

better environment in Rock Springs “is a matter of good business, ” according to industry

sources.

33

In summary, Wyoming has experience d

some of the most extensive social and economic changes from energy development, Different communities have responded in different ways; some have become boomtowns,

others have coped with rapid growth without

excessive disruption. The State has developed a wide array of mitigation strategies to

assist the affected counties and communities.

30 D. Pernula, “But What Happens When Coal’s in Montana

and Growth’s in Wyoming?" The Western Planner 1(7):9 September 1980.

“P. Primack, “Expanding Energy Town Narrows Life for

Elderly, ” High Country News, 11(19]:1 Oct. 5, 1979.

“R. E, Huff, “Wright’s Success Reflects Commitment and Coopera tion, ” The Western Planner 1(7):15 (1980).

“Persona] communication from J. Larsen, 1980.

The greatest potential for additional coal

production from existing leases is in the

Wyoming portion of the Powder River basin

(see ch. 7), Campbell and Converse Counties,

therefore, are the most likely to experience

additional growth, and possible disruption

from Federal coal development.

North Dakota

Coal mining on Federal land in North

Dakota occurs in the Fort Union region in the

western portion of the State. Most of the major mining operations are located in the four

west-central counties of McLean, Mercer,

Oliver, and Ward (see fig. 55). In recent

years, Federal, State, and local governments

have been major employers (28 percent of the

population in 1975), with agriculture next (25

percent), Large farms and ranches, producing wheat and cattle, are characteristic. The

largest urban area is Bismarck; small towns

with stable populations are found throughout

this part of the State (see table 106).

Rapid growth has already come to the

towns of Beulah and Hazen, Energy developers in the Beulah area have pooled resources to provide housing for incoming

workers, and Bismarck and nearby Mandan

(within an hour’s drive of the major lignite developments) have absorbed some of the new

population,

There generally has been little local opposition to industry expansion in those areas

where lignite mining and powerplant construction have already taken place (e. g.,

Oliver and Mercer Counties). This may be

because much local income comes from the

nearby mining operations. Negative public

reaction has been pronounced in Dunn County, however. The combination of public opposition to the siting of Natural Gas Pipeline

Co. ’s (NGPL) planned gasification facility in

the Dunn Center area and the lack of available air quality increments at Theodore

Roosevelt Park led to NGPL’s decision to

abandon the project. To date, no large coal

related facilities have been located in the immediate vicinity. The opposition of Dunn
368 . An Assessment of Development and Production Potential of Federal Coal Leases

County residents is shared by some Native

Americans on the Fort Berthold Indian Reservation directly to the north of NGPL’s proposed site.

Almost all of the existing Federal leases

are in already developed areas (Mercer and

Oliver Counties), Social and economic impacts are not likely, therefore, to affect the

further development of Federal coal resources. This situation would change with the

leasing of new tracts in previously undeveloped parts of the State. For example, the

western edge of the State is an area where

social and economic impacts from several

ventures could accumulate. Oil and gas exploration is taking place here now, and

although the operations are well removed

from existing Federal lease areas, the potential exists for future problems.

Oklahoma

Federal coal leases are located in four

counties in the east-central region of Oklahoma. Economic conditions are poor in this

part of the State. A continuing decline in coal

production since 1950 combined with a

failure of other industries to flourish in this

region has led to economic stagnation. Most

civic leaders and many residents would welcome a rejuvenation of the coal industry .34

However, as discussed in chapter 6, the prospects are not encouraging for extensive development of coal on Federal land in Oklahoma during the 1980’s.

Development of the Federal leases could

require underground mining in many instances. However, surface mining has dominated the Oklahoma industry for the past

two decades, and few local miners have had

extensive underground experience. Consequently, the initiation of mining by the companies holding Federal leases would probably

require the recruitment of workers from outside the State.

Four mines are currently operating on

Federal leases, Any increase in population

that might result if additional Federal leases

were developed over the next 10 years would

not impose an unmanageable burden on community services. The population of many

towns is still smaller than when coal mining

was more extensive. Most elementary and

high schools could increase their enrollments

without building new facilities or hiring new

teachers, and health and recreational facilities are adequate. However, in several communities that have been hard hit by economic

recession, commercial and residential buildings have deteriorated and would require extensive repair or replacement. -

34This is documented in BLM’s public participation file and

was supported by individuals in private industry and in Federal

and State agencies contacted during OTA's survey of the Oklahoma coal industry.
CHAPTER 13

Patterns and Trends in

Ownership of Federal Coal

Leases and PRLAs 1950=80
Contents

Page

ownership by Business Activity Category. .372

Electric Utilities . . . . . ● . . . . . . . . . . . . . . . . . . ● 376

Energy Companies. .... . ................377

Peabody Coal Co . ..,................. .37 7

Steel Companies . . . . . . .. ... ... .. ...377

Independent Coal Companies . . . . . . . . .. ....378

Oil and Gas Companies (Minor). . ..........378

Unincorporated Individuals . . . . . . . ........378

Natural Gas Pipeline Companies. . ..........379

Nonresource-Related Diversified Companies .379

Kemmerer Coal Co.. . . . . . . . . . . . . . . . .. ....379

Metals and Mining Companies .. ... ,. ...379

Landholding Companies. ...., .., ... ... .. 38O

“Other” Lessees . . . . . . . . . .. .. .. ... ... ...38O

Federal Coal Production by Business

Category 4******** ● ********* ● ***.**** 380

The Business Organization of Coal Lease

and PRLA Owners. . . . . . . . . . . . . . . . . . . . 381

Unincorporated Individuals . . . . . . .....,...382

Independent Corporations. ............,..382

Subsidiary Corporations. ,.. . .............382

Multicorporate Entities . . . . . . . . . .~..... 383

Implications of Lease and PRLA

‘ Ownership Patterns and Trends. ... .....384

Concentration. . . ...............,........38 4

Diversification. . .. . .. ..... ... .. 0

.

0 03 $ 4

Leasing Policies . . . . . . . . . ........... 386

List of Tables

Table No. Page

107. Number of Acres and Percent of Total

Leased Land Held by Business

Activity Category . . . . . . . . . . ..........373

Table No. Page

108. Changes in Federal Coal Lease

Own&shin Because of Recent Major

109.

110.

111.

112.

Corporate-Ownership Changes. .. .....373

Number of Acres and Percent of Land

Under PRLAs Held by Business

Activity Category . . . . . . . . . ...........375

Federal Leaseholdings and Production

by Business Category. . ...............376

Number of Acres Under Lease by Type

of Business Organization 1950-1980 and

Percent of Total Leased Land by Type

of Business Organization. . ............381

Acres and Percent of Total Acres Under

PRLAs Held by Business Organization

Category . . . . . . . . ..........9..-......382

List of Figures

Figure No. Page

56.

570

58.

59.

60.

Total Acres of Federal Coal Under -

Lease 1950-80. .......................371

Number of Federal Coal Acres Under

Lease by Business Activity Category,

1950-80. . . . . . . . . . . . . . . . . . . . . . . . . .. ...374

1980 Coal Leaseholdings by Business

Activity Category . . . . . . . . . ............375

1980 PRLA Holdings by Business

Activity Category . . . . . . . . . . ...........376

Number of Federal Coal Acres Under

Lease by Type of Business Organization,

1950-80 ...,..* . . . . . . . . ● .**..** .. ... 382
CHAPTER 13

Patterns and Trends in Ownership of

Federal Coal Leases and PRLAs 1950-801

The Federal coal leasing program makes

Federal coal land available for mining by the

private sector. Hence, the amount and location of leased land helps define the extent of

the coal reserve base of the industry. Figure

56 shows the total number of acres under

Federal coal lease from 1950 to 1980, The

regions with leased coal lands in the West are

shown in figure 17 and discussed in chapter

4.

This chapter summarizes the results of a

study of the ownership histories of each of

the 538 Federal coal leases and 176 preference right lease applications (PRLAs) in existence as of September 30, 1979. * The

chapter identifies the participants in the coal

leasing program between 1950 and 1980 and

examines the changing ownership patterns of

Federal coal leased to the private sector. The

ownership histories of companies, grouped

according to similar business activities or

business organizational structures, are considered separately.

The principal data used for this chapter

were case histories of the legal ownership of

the titles to each Federal lease and PRLA. **

1

For further information on this subject, see the OTA ‘I’erhnical hlcm(jrandum, P(I t ferns und Trends in Fwicrd Coal Lewsr

ou’ncrshi~) 1950-80, () I’A-’I’hf-hl-7. klarrh 1981. The Terhnical

Nlemorandurn is available from the Superintendent of

Documents, [J. S. Government Printing office, Washington, D.C.

20052, at $4.00 per copy. Its GPO stock number is

052-003-00799-1.

*In its ownership work, 0’I’A did not analyze leases or

PRLAs that were relinquished prior to Sept. 30.1979 or the fem.

leases issued in Iatr 1979 or in 1980. Thus, the coal lease

acreage tf)ta 1s in this chapter and I he tota 1 number of leases

considered in this chaJjtf!r differ slightly from the totals in the

rest of the report, whirh include a 11 lmises in existence (m Sept.

30, 1980. A (I(]mplete prf?scntation of the methodology and findings of the ownership study is contained in the OTA ‘1’e(:hni{{il

hlemorandurn referenced above.

**(ITA examined the (~wners of record of leases and PRLAs.

It did not stud}’ companies participating in the le:ising program

in other c:]parit ies such as “’rtcsi~nated operators’” of mines

work i ng under ron [ ra c t to lessees (jr ‘‘s u hlcssee’ investors,

Figure 56.—Total Acres of Federal Coal Under Lease

Acres

800,000

I

700,000

600,00 0

500,000

400,000

300,000

200,000

100,000

1950-80

I I I I I I

1950 1955 1960 1965 1970 1975 198 0

Year

SOURCE Office of Technology Assessment

This information was collected from primary

sources, principally serial books and case

files maintained by State offices of the

Bureau of Land Management. From this data,

lists of all owners of leases and PRLAs at

each of seven analysis dates were developed

and the holdings of each owner tabulated.

The analysis dates were January 2 of the

years 1950, 1955, 1960, 1965, 1970, 1975,

and 1980. Next, each present and past owner

371
372 “ An Assessment of Development and Production Potential of Federal Coal Leases

of Federal coal during this period was classified according to its principal line of

business activity (if an individual or an independent corporation] or by the business activity of its controlling interest or interests (if

a wholly owned subsidiary or a joint venture).

In addition, all present and past owners were

categorized according to their type of business organization structures. Detailed and

separate analyses were then done for any

business activity category and business

organization structure that controlled at least

5 percent of all land under lease or PRLA at

one of the dates listed above. Individual

analyses were also done for any company

that did not clearly fall into an identifiable

business category but nonetheless controlled

5 percent of leased land or land under PRLA

at one of the dates selected for analysis. Remaining owners were grouped in an other

category.

Thirteen categories of business activity

groups holding leases and 10 categories of

PRLA owners were identified and studied.

Also, four types of business organization

categories were identified for both lease and

PRLA owners. The business activity categories for leaseowners and PRLA holders

are as follows:

Business Activity Categories Defined by OTA

Leaseholders*

Electric utilities

Energy companies

Peabody Coal Co.

Steel companies

Independent coal companies

Oil and gas (minor)

companies

Unincorporated individuals

Natural gas pipeline

companies

Nonresource-related

diversified companies

Kemmerer Coal Co.**

Metals and mining

companies

Landholding companies

“Other” lessees

PRLA holders

Unincorporated

individuals

Energy companies

Natural gas pipeline

companies

Kemmerer Coal Co.**

Metals and mining

companies

Electric utilities

Oil and gas (minor)

companies

Landholding companies

International

Geomarine and Coal

Conversion Co,

“Other” lessees

*The categories include 10 industries, two individual companies that were classified as distinct business categories for

various reasons and an other category for the remaining

lessees, Each of the 13 business categories controlled or controls at least 5 percent of all land under lease al some time between 1950 and 1980.

**In March, 1981 Kemmerer Coal Co. was purchased by

Gulf Oil Corp.

Ownership by Business Activity Category

Tables 107 and 108 and figure 57 summarize data on the relative and absolute

growth and decline in leaseholdings by the 13

business activities defined and studied by

OTA. Table 109 provides similar information

for the 10 categories of PRLA owners. These •

tables and the figure show that:

●

●

The electric utilities, major energy companies, oil and gas (minor) companies,

natural gas pipeline companies, and ●

nonresource-related diversified companies have all increased their Federal

coal landholdings significantly since

1965 both in absolute and relative terms.

Independent coal companies and unincorporated individuals dominated coal

leasing in the 1950’s and the first half of

the 1960’s but their leaseholdings, expressed as a fraction of the total land

under lease, have steadily declined since

1950. Individuals are still the dominant

class of PRLA holder.

Peabody Coal Co. and Kemmerer Coal

Co. have played important and long

standing roles as large individual leasing

parties.

Steel and metals and mining companies

were early leasing participants, but

steel industry influence has declined

steadily in relative terms since 1955,

although the acreage held by the steel industry has steadily increased since

1950. Metals and mining company leaseholdings have varied widely, due in part
Ch. 13—Patterns and Trends in Ownership of Federal Coal Leases and PRLAs 1950-80 ● 373

Table 107.—Number of Acres and Percent of Total Leased Land Held by Business Activity Category

— ——

1950 1955 1960 1965 1970 ‘-1975 1980 -

Acres Land Acres Land- Acres ‘Land Acres Land Acres Land Acres Land Acres Land

held leased held leased held leased held leased held leased held leased held leased

(#) (%) (#) (%) (#) (%) (#) (%) (#) (%) ( % )

(#) (#) (%)

Electric utilities. . . . . . . . . 0 0 2,000 3% 8,26 3 6% 45,363 15% 132,038 18% 142,077 19% 163,259 21%

Energy companies . . . . . . 0

Peabody Coal Co. . . . . . . . 0

Steel companies . . . . 4,993

Independent coal

companies . . . . . . . . . . 14,584

Oil and gas (minor)

companies . . . 0

Unincorporated

individuals . . . . . . . . . . . 11,129

Natural gas pipeline

companies . , . . . 0

Nonresource-related

diversified companies 0

Kemmerer Coal Co. a. . . . . 475

Metals and mining

companies . . . . . . . . . . 5,009

Landholding companies. 1,360

“Other” lessees. . . . . . . 2,907

0

0

12

0

0

14,817

0

0

19

0

0

19,888

0

0

14

9,491

(6,251)

34,158

132,274

(59,121)

46,114

18

(8)

6

138,409

(68,923)

49,448

18 -- .- --

(9)

6

155,024 20

62,009 8

60,015 8

55,410 7

45,926 6

43,215 5

36,317 5

35,675 5

32,191 4

17,620 2

4,661 ‹1

77,861 10

35 25,022 33 41,557 29 77,273 25 78.297 11 58.837 8

0 0 0 0 0 2,080 1 26,911 4 42,193 6

27 17,618 23 25,678 18 41,475 13 78,995 11 66,515 9

0 0 0 0 0 0 0 0 0 32,522 4

0

1

0

1,752

0

2

0

6,849

0

5

4,610

18,504

1

6

10,015

33,793

1

5

12,580

33,988

2

4

12

3

7

5,009

4,576

3,240

7

6

4

9,266

11,504

18,288

6

8

13

17,708

13,411

39,134

6

4

13

107,504

43,581

41,153

15

6

6

118,300

26,225

37,051

15

3

5

NOTE Uncategorized lessees hold less than 2 percent of land under lease at any analysis date

Numbers might not add to 100 percent because of the holdings of uncategorized lessees

Numbers in ( ) tabulated in metals and mining category (1970 and 1975) or in independent coal company category (1965)

Uncategorized 1035 1,915 2,453 5,147 2643

Lessees 2% 3 % 2 % 2 % < 1 %

6,848

1%

1845

< 1 %

a ln March 1981, Kemmerer Coal Co was purchased by Gulf Oil Corp.

SOURCE Off Ice of Technology Assessment

Table 108.—Changes in Federal Coal Lease Ownership Because of Recent

Major Corporate Ownership Changes

Corporate

—

Number of

.

Number of Change in Change in

ownership of leases of acres business activity business organchang e

a

involved involved category izatlon category —

Kemmerer Coal Co. 26 37,191 From Kemmerer Coal No change

purchased by Gulf Oil Corp. Co. to energy

companies

St. Joe Minerals Corp. 1 280 From metals and No change

purchased by Fluor Corp.b mining companies to

nonresource-related

diversified companies

Energy Fuels Corp. 5 4,521 From independent coal From independent

purchased by Getty Oil companies to energy corporations to

Corp. c

companies subsidiaries

Belden Enterprises 1 42 From independent coal From independent

purchased first by Grand companies to “other” corporations to

Mesa Coal Co., which was and natural gas pipe- multicorporate

bought by Eastern Gas and Iine companies entitles

Fuel Associates jointly with

Nicor, Inc.

CONOCO, Inc. purchased 31 43,442 From energy No change

by E I du Pent de Nemours companies to non-

& co resource-related diverSum: (lOO

/. of total leased sified companies

Federal coal acreage) 80,476

— —. . ——— — a The table does not reflect lease ownership changes that have occurred because of the assignment of leases after Jan 1,

1980 and which, consequently, are not reflected in any tables, figures or text in this chapter

b The lease involved iS held by a subsidiary, Anchor Coal CO

c Getty now holds the leases by a subsidiary, Getty Mining Co.

d The leases involved are held by Consolitdation Coal CO

SOURCE Off Ice of Technology Assessment
374 - An Assessment of Development and Production Potential of Federal Coal Leases

Acres

800,000

700,000

600,000

500,000

400,000

200,000

100,000

Figure 57.— Number of Federal Coal Acres Under Lease by

Business Activity Category, 1950-80

Other lessees

o

Year

sOURCE: Off Ice of Technology Assessment
Ch. 13—Patterns and Trends in Ownership of Federal Coal Leases and PRLAs 1950-80 ● 375

Table 109.—Number of Acres and Percent of Land

Under PRLAs Held by Business Activity Category

1955-65 1970 1975 1980

Unincorporated UP to 5,890 147,022 115,317 80,559

individuals (loo%) (46%) (28%) (20%)

Energy 22,008 30,738 65,784

companies — (7%) (7%) (16%)

Kemmerer Coal 33,190 39,160 39,160

Co. a

. (10%) (9%) (10%)

Metals and mining 17,278 39,461 36,514

companies . (5%) (9%) (9%)

Other lessees 9,874 57,427 58,216

— (3%) (14%) (14%)

Unknown 260 260 3,077

— (less than (less than (1%)

1%) 1%)

Total percentages might differ from 100 percent because of rounding.

a ln March 1981, Kemmerer Coal Co. was purchased by Gulf Oil Corp.

SOURCE Office of Technology Assessment

to the 1977 sale of Peabody Coal Co. by

Kennecott Copper Corp.

● Independent land companies played a

significant role in leasing in the 1950’s

and 1960’s, but they have largely liquidated their holdings over the past

decade.

Table 107 and figure 57 also summarize

the absolute changes in leaseholdings that

have occurred over the past 30 years. They

show the steady increase in acreage held by

the steel companies, independent coal companies, and unincorporated individuals through

1970, followed by the slow decline in the

holdings of the latter two groups since then.

Table 107 and figure 57 also illustrate how

the significant but relatively modest increases in the holdings of these three groups

during the 1960’s compare to the more substantial acquisitions of some new entrants to

leasing in that period, (Table 108 summarizes

the major changes in corporate ownership

that have occurred since early 1980 that affect the acreages held by the major coal

leaseholding categories shown in table 107.)

Figure 58 shows that the leaseholdings of

the 13 major business activities ranged, in

1980, from 21 percent of all land under held

by the electric utilities, to less than 1 percent,

held by independent land companies. The

major energy companies hold 20 percent of

leased acreage. With the exception of the

utilities and the major energy companies, all

the categories hold less than 10 percent of

leased coal acreage.

Eight business activity groups currently

hold at least 5 percent of all land included in

PRLAs. A ninth holds over 1 percent (see fig.

59). Each group also appears on the list of

major leaseholding categories, although there

are differences in the rank ordering of the

groups in the two cases. Individuals hold a

larger share of land under PRLAs (20 percent) than any other category. Individuals are

followed by major energy companies and

natural gas companies and then by four industries each of which holds between 8 and

10 percent of land under PRLAs.

Two companies, International Geomarine

Corp. and Coal Conversion Corp. held, at different times, PRLAs covering more than 10

percent of all land under permit. (See table

Figure 58.— 1980 Coal Leaseholdings by Business

Activity Category (percent of total leased acreage)

SOURCE: Off Ice of Technology Assessment,
376 “ An Assessment of Development and Production Potential of Federal Coal Leases

Figure 59.— 1980 PRLA Holdings by Business

Activity Category (percent of total acres under permit)

from leased land in fiscal year 1979, more

Federal coal than mined by any other business activity category (see table 110). (Nationwide, all utility coal production accounted for

11 percent of the coal industry’s total production in 1979).

More than any other industry group examined in this survey, utilities have undergone complicated internal restructuring related to coal lease management. Several utilities now hold leases or PRLAs in the name of

one or more subsidiaries, e.g., coal mining

subsidiary, resource development subsidiary,

landholding subsidiary, or legal entity without employees or business activities. Also,

SOURCE Off Ice of Technology Assessment

109.) They do not appear on the list of current

PRLA holding groups because they have assigned all of their PRLAs to other parties.

The future disposition of PRLAs has several uncertainties. * The current Department

of the Interior leasing policy calls for the

processing of PRLAs in sequence between

1981 and 1984, but it is unclear how many

will be converted to leases or what restrictions on development will be included among

the terms of leases that are granted. It would

thus be speculative to add lease and PRLA

holdings into grand totals, and OTA has not

done so. The following pages discuss briefly

both types of holdings by each business activity category in order of decreasing size of

holdings.**

Electric Utilities

Electric utilities currently hold more Federal coal land under lease than any other business category identified by OTA; they rank

sixth in PRLA holdings. Seventeen utilities

and one utility fuel acquisition association

now control 21 percent of leased acreage and

9 percent of land under PRLAs. These companies mined 30 percent of all coal produced

* see chs. 3, 6, 7, and 9 for more information about the status

of PRLAs.

* *The only exception is the other category that is discussed

at the end.

Table 110.—Federal Leaseholdings and Production

by Business Category

Fiscal year

1972 1979

coal coal

production production

1970 from 1980 from

Business activity leased Federal leased Federal

category acres leases acres leases

18% 4 7 % 21% 30%

Electric utilities . . . . . 132,038 4.8 163,259 17.8

18% 5% 20% 16%

Energy companies. . . 132,274 0.51 155,024 9.9

Metals and mining 12% 12% 2% 16%

companies . . . . . . . . 107,504 1.2 17,620 9.3

Oil and gas com- 4% 2% 6% 9%

panics (minor) . . . . . 26,911 0.23 45,926 5.3

6% 4% 10% 9%

“Other” companies . . 41,153 0.46 77,861 5.2

Independent. 11% 2 0 % 7 % 7 %

coal companies . . . . 78,297 2.0 55,410 4.4

Natural gas pipe- 0 % 0 % 5 % 4 %

line companies . . . . 0 0 36,317 2.4

Peabody Coal 8 %

a

0 %

a

8 % 4 %

Co.. . . . . . . . . . . . . . . a a 62,009 2.2

6 % 7 % 8 % 2 %

Steel companies . . . . 46,114 0.77 60,015 1.3

Nonresource-related 1 % 0 % 5 % 2 %

diversified companies 10,015 0 35,675 1.0

Unincorporated 1 1 % 3 % 6 % 1 %

individuals . . . . . . . . 78,995 0.27 43,215 0.72

Kemmerer Coal 5 % 0 % 4 % below 1%

Co. b 

. . . . . . , . . . . . . . 33,793 0 32,191 0.06

94 % 100% 99%0 100%

Total . . . . . . . . . . . . 687,094 10.3 784,522 59.5

NOTE: Percentage sums might not equal totals because of rounding. All land

holdings listed as acres. All production listed in million tons of coal.

a Peabody 1970 land holdings and 1972 productions totaled In metals and mining category.

b ln March 1981, Kemmerer Coal Co, was purchased by Gulf Oil Corp.

SOURCE: Office of Technology Assessment.
Ch. 13—Patterns and Trends in Ownership of Federal Coal Leases and PRLAs 1950-80 . 377

utilities have been active in several joint venture leasing and multicorporate development

projects, One utility currently holds different

leases in the name of five subsidiaries and is

involved in three multicorporate lease development projects. The internal restructuring

of utilities and their involvement in multicorporate leasing ventures appears to indicate a

policy decision by some utility managements

that coal leasing and mining activities should

be separate from electrical generation activities because of the different management

skills that these activities require. Furthermore, this division enables utilities, as a regulated industry, to clearly distinguish among

totally regulated, partially regulated, and unregulated business activities.

Utilities made their most significant lease

acquisition gains in the mid to late 1960’s at

the same time as the energy companies and

the smaller oil and gas companies, but before

the entry of the natural gas pipeline companies. Most utility-mined coal is used in

powerplants owned by the leaseholding company (captive production), although increasing amounts of utility-mined coal are being

sold on the open market. Utilities play a

unique role in the coal industry as both an important producer of coal and the major consumer of coal. Utilities burned 77 percent of

all domestically used coal in 1979.

Energy Companies

Energy companies in this survey include

the 18 largest privately owned oil companies

based on worldwide petroleum production.

Eleven of these companies now own leases or

PRLAs. They rank second in both categories,

holding 20 percent of leased land and 16 percent of land under PRLAs. Energy companies

produced 16 percent of the coal mined from

leased land in fiscal year 1979.

The late 1960's marked the period of

greatest growth in Federal coal landholdings

by energy companies, well before the Arab oil

embargo and the energy shortage conscious

1970’s. Most of the leases obtained by these

companies were acquired through lease assignments or by the purchase of a company

that held leases among its assets. * Only 16 of

110 leases acquired by energy majors were

obtained by de novo leasing directly from the

Federal Government. Similarly, only 7 of 27

PRLAs now owned by energy majors were obtained de novo. Energy companies appear to

be continuing to acquire land through assignment and corporate mergers. In 1980, three

leaseholding companies were purchased by

energy companies and several lease assignments to energy companies were made. (See

also table 108. )

Peabody Coal Co.

Peabody Coal Co. owns leases covering

more Federal coal land than any other company or individual. Its leases cover 8 percent

of all land under lease. In addition, Peabody

controls 17 PRLAs, all located in Wyoming.

Peabody accounted for 4 percent of Federal

coal production in fiscal year 1979.

Peabody operated as an independent coal

company from its founding until 1968 when it

was purchased by Kennecott Copper Corp.

The acquisition was challenged by the Federal Trade Commission on anticompetition

grounds and a divestiture order was issued in

1973. In 1977, Kennecott sold the company to

the Peabody Holding Co., the ownership of

which is shared by six companies with business interests as diverse as aerospace,

mineral extraction, and life insurance. Because of its unique ownership structure and

because of its large holdings, Peabody was

treated in the OTA survey as a separate business activity after 1977.

Steel Companies

Steel companies were among the earliest

participants in Federal coal leasing, owning

12 percent of all land under lease in 1950.

The industry is still well represented (five

companies control 8 percent of leased land)

but its importance in Federal coal leaseholding has declined because of the entry of

*See chapter 3 for a discussion of methods used to acquire

coal leases,
378 ● An Assessment of Development and Production Potential of Federal Coal Leases

many companies from other industries. Steel

companies currently do not own any PRLAs.

Steel companies produced 2 percent of all

Federal coal mined in fiscal year 1979. Most

of this production was for captive use as a

raw material for coke ovens at steel mills.

Hence, the industry has focused its attention

on leasing in the coal fields of Oklahoma, Colorado, and Utah that contain metallurgical

grade coal.

Independent Coal Companies

In 1950, 18 independents constituted the

largest leaseholding business group, controlling 35 percent of all land under lease. Today

they control just 7 percent. Only one PRLA is

held by an independent coal company. Historically, changes in ownership patterns by

independents have occurred at a rapid pace.

Over 60 independents have held leases, but

none of the current 21 independent lessees

was among the original 18 in 1950. Rising

mining costs, the preference of utilities for

large supply contracts from single producers,

and a slow growth in local domestic or industrial coal use restrict the business opportunities of independent coal companies.

As a result, many leaseholding independents

have assigned their leases to principally noncoal companies or have been acquired as subsidiaries. At least 10 leaseholding companies

that are now wholly owned coal mining subsidiaries once operated as independent coal

producers.

In spite of these trends, independents remain the fifth largest leaseholding business

category. Furthermore, several present lessees, notably Garland Coal and Mining Co.

and North American Coal Corp., have built

substantial coal reserve bases through the

leasing program. Also, several other independents have entered the Western coal

fields for the first time in the last decade. Independent coal companies accounted for 7

percent of Federal coal production in fiscal

year 1979.

Oil and Gas Companies (Minor)

Eight oil and gas companies (those companies not large enough to appear among the

energy majors and which do not operate large

natural gas pipelines) now control about 6

percent of all land under lease and 8 percent

of land under PRLAs. They rank sixth and

seventh in total holdings respectively. Oil and

gas companies entered coal leasing in the

mid-1960’s and their holdings have grown

slowly but steadily ever since.

Lessees and PRLA owners in this category

range from small oil wildcatters to large companies such as Kerr-McGee Corp. and Quaker

State Oil Refining Corp. These companies accounted for about 9 percent of the total production of Federal coal in fiscal year 1979.

Unincorporated Individuals

The role of unincorporated individuals in

the leasing program, at one time second only

to the independent coal companies, has greatly declined in relative importance. On the

other hand, although their holdings of PRLAs

have also declined, individuals still have the

largest share of land under PRLAs of any

business category.

In 1950, unincorporated individuals constituted the second largest leaseholding group

and held 27 percent of all acreage under

lease. Their share of leased acreage has

declined to 5 percent today. Many leases held

by individuals include mines that have been

closed for years and exhibit little potential

for reopening. One percent of fiscal year

1979 Federal coal production occurred on

leased land held by individuals.

In 1970, unincorporated individuals held

46 percent of all land included in PRLAs.

Over the past decade, many of these PRLAs

have been assigned to corporations and the

share held by individuals has dropped to 20

percent. Although unincorporated individuals are still the major PRLA owners, the

decline in the number of PRLAs held by individuals is likely to continue.
Ch. 13—Patterns and Trends In Ownership of Federal Coal Leases and PRLAs 1950-80 . 379

The decline of lease and PRLA holdings by

individuals reflects a decreasing use of the

“sole proprietorship” business organization

by small mining firms in favor of some form of

incorporated business structure. Another

reason for this decline is the abolition of the

preference right leasing program, a popular

and low cost lease acquisition route for individuals, including land agents operating

under contract to corporations and individual land speculators. Finally, the leasing moratorium of the 1970’s, which increased the

assignment value of existing leases and

PRLAs, and the diligent development requirements defined in the 1976 coal leasing regulations may have been incentives for individuals to sell leases that they could not mine.

Natural Gas Pipeline Companies

Natural gas pipeline companies are the

eighth largest leaseholding business group

and the third largest group holding PRLAs.

Six of these companies hold 5 percent of

leased land and 12 percent of land under

PRLAs. They mined 4 percent of all Federal

coal produced in fiscal year 1979.

All leases and PRLAs now owned by

natural gas pipeline companies have been acquired since 1971 during a period when opportunities to acquire leases de novo were

limited. Twenty-five of 27 leases and 27 of 29

PRLAs were obtained by assignment or segregation from existing leases or PRLAs rather

than directly from the Government,

Nonresource-Related Diversified

Companies

The nonresource-related diversified business category includes companies with principal lines of business activity that are not

energy or mineral related, but which complement or could be integrated with resource

development. It includes, for example, several chemical companies, which might use

coal as a chemical feedstock or might develop

synfuel technologies, and companies such as

General Electric and General Dynamics that

sell electrical generation equipment.

The companies in this category are latecomers to Western leasing, Their leaseholdings have increased from 1 percent in 1965 to

5 percent in 1980. They form the ninth largest

leaseholding category, In addition, such companies hold three PRLAs. They produced 2

percent of all Federal coal mined in fiscal

year 1979, The most significant increase in

holdings by companies in this category occurred in 1976 when General Electric purchased Utah International, which controlled

nearly 25,000 acres of leased land. Utah International was an independent metals and mining company prior to its acquisition by General Electric.

Kemmerer Coal Co.

Kemmerer Coal Co, is one of the oldest

Western coal producers, dating back to the

late 19th century. Since 1926 Kemmerer has

been owned by the Lincoln Corp., a holding

company of Kemmerer family interests. * In

September 1980, the family announced its intention to sell Kemmerer Coal. Its recent sale

to Gulf Oil Corp. marks a major shift in lease

and PRLA ownership.

Kemmerer now owns 4 percent of all land

under lease and 10 percent of all land under

PRLAs. Kemmerer produced less than 1 percent of Federal coal mined in fiscal year

1979. The company ranks as the 10th largest

leaseholding category and the fourth largest

holder of PRLAs,

Metals and Mining Companies

Metals and mining companies entered

Western coal leasing early, Although recent

corporate acquisitions have sharply reduced

their leaseholdings, these companies continue to account for significant Federal coal

production.

* Kemmerer was studied separately by OTA rather than as

an indepenedent coal company because of its ownership by

Lincoln Corp., which includes noncoal business among its

interests .
380 An Assessment of Development and Production Potential of Federal Coal Leases

Metals and mining companies held 12 percent of all land under lease in 1950 and 15

percent in 1975. This total has dropped to 2

percent over the past 5 years, principally

because of the divestiture of Peabody Coal by

Kennecott Copper Corp. and the purchase of

Utah International by General Electric. Both

actions resulted in the removal of large

acreages from the totals of the metals and

mining category. In spite of these developments, metals and mining companies produced about 16 percent of all coal mined from

Federal land in fiscal year 1979.

Amax, Inc., a company grouped in the

metals and mining category, currently holds 9

percent of the land under PRLAs. These holdings alone rank fifth among the business categories studied by OTA. *

Landholding Companies

Independent land companies, like individual land agents, featured prominently in

the early history of the leasing program. They

acquired large blocks of coal bearing land for

eventual resale to coal developers or other investors. Their role peaked in 1960 when they

*Amax has been placed in the metals and mining category

instead of being listed separately because of its identifiable

business activity and because prior to 1980 other companies in

this category held PRLAs.

held 8 percent of all land under lease. In

1980, seven landholding companies owned

leases covering less than 1 percent of the

acreage under lease and PRLAs covering 1

percent of the land under PRLAs. They account for no Federal coal production.

The reasons for the liquidation of the

holdings of most independent land companies

are similar to those for individual land

agents: the abolition of preference right leasing, the diligent production requirements,

and the impact of the moratorium on the resale value of leases and PRLAs.

“Other” Lessees

This last category includes lessees that do

not fit into one of the business categories

established during the survey and which, on

their own, do not control more than 5 percent

of the land under lease or permit. Such companies presently hold about 10 percent of all

leased land and about 15 percent of all land

under PRLAs. This other category includes

lessees with an amazing diversity of interests. For example, it includes a railroad

holding company, a heavy construction company, a cement company, two banks, three

conglomerates, and a religious institution.

About 9 percent of all coal produced on

Federal land comes from leases held by

lessees in the other category.

Federal Coal Production by Business Category

Ownership of leases covering Federal land

is only one measure of involvement of companies and individuals in the leasing program. The amount of coal production from

leased land is another measure. Based on

limited information available for past Federal

coal production on a lease-by-lease basis,

OTA has compared acreage holdings of business activity categories in 1970 and 1980

with Federal coal production by these catDuring the 1970’s the total number of acres

leased by the 12 business categories* that

now mine coal increased 14 percent from

687,094 acres to 784,522 acres. Between

1972 and 1979, on the other hand, total coal

production summed over all these categories

jumped nearly sixfold, from 10.3 million tons

to 59.5 million tons. In terms of percentage of

total production, the share of production conegories in 1972 and fiscal year- 1979. (See *In fiscal year 1979 no production was contributed by indetable 110.) pendent land companies.
Ch. 13—Patterns and Trends in Ownership of Federal Coal Leases and PRLAs 1950-80 381

tributed by utilities decreased from 47 to 30

percent and the share of independent coal

companies dropped from 20 to 7 percent. In

both cases, absolute production increased

substantially, by nearly a factor of four for

the utilities and by over a factor of two for the

independent coal companies. During the

same period, the shares of production of the

energy companies increased from 5 to 16 percent. Production by natural gas companies,

metals and mining companies, and oil and gas

companies also increased sharply, Production by unincorporated individuals also rose

nearly threefold, although declining from 3 to

1 percent of total Federal coal production.

Electric utilities, metals and mining companies, and oil and gas companies are all producing Federal coal at levels greater than

their share of leased acres would suggest.

The level of production of the metals and mining companies is particularly high relative to

their share of leased acres. Present production by energy companies, Peabody and Kemmerer Coal, steel companies, nonresourcerelated diversified companies, and individuals is below the share suggested by their

current acreage holdings. *

*Many currently nonproducing leases arc being activelv developed. See ch. 6.

The Business Organization of Coal Lease

and PRLA Owners

OTA also examined the changes in the

organizational structures of coal lease and

PRLA owners, Four types of business organization structures were defined and analyzed.

They are:

●

●

●

●

Unincorporated individuals — persons,

including sole proprietorships, partnerships, and estates.

Independent corporations — companie s

not wholly owned by one or more other

companies.

Subsidiary corporations — companies

wholly owned by a single other company.

Multicorporate entities — companies

wholly owned by two or more companies

(such as joint ventures) or two or more

companies holding shares in leases or

PRLAs.

Table 111 and figure 60 trace the history of

lease ownership by the four organization

categories. They show that the relative importance of unincorporated individuals in

leasing has been sharply reduced since the

1950’s. They reveal the dominant role of independent corporations in the 1950’s and

1960’s and their recent decline in relative importance. They show that the subsidiaries

category has grown in importance over the

years. Finally, they show that muIticorporate

entities are the newest type of business

organization to attain significance in Western leasing,

The role of the four business organizations

as owners of PRLAs between 1970 and 1980

Table 111 .—Number of Acres Under Lease by Type

of Business Organization 1950-1980

and Percent of Total Leased Land by Type of

Business Organization

Unincorporated Independent Subsidiary

indivduals corporations corporations

11,129 18,504 10,824

1950. , 2 7 % 4 5 % 2 6 %

17,618 40,495 15,921

1955. . 2 3 % 5 3 % 2 1 %

Multi- Uncategor.

corporate ized

entities companies

1,035

0 % 2 %

1,915

0 % 3 %

25,678 79,717 36,058 2,453

1960. . 18% 55% 25% 0% 2%

41,475 169,402 91,690 640 5,147

1965. . 13% 55% 30% <1 % 2 %

78,995 319,847 271,329 60,504 2,643

1970. . 1 1 % 4 4 % 3 7 % 8 % < 1 %

66,515 257,637 321,576 112,418 6,848

1975. . 9 % 3 4 % 4 2 % 1 5 % 1 %

43,215 204,612 343,865 197,491 1,845

1980. . 5 % 26% 43% 25% <1 %`

SOURCE. Off Ice of Technology Assessment
382 ● An Assessment of Development and Production Potential of Federal Coal Leases

Figure 60.— Number of Federal Coal Acres Under

Lease by Type of Business Organization, 1950-80

Acres

700,000 —

600,000 —

500,000 “

400,000 —

300,000 —

200,000 —

100,000 —

L

Table 112.—Acres and Percent of Total Acres Under

PRLAs Held by Business Organization Category

1955

1960 &

1965 1970 1975 1980

Unincorporated 160-5,890 147,022 115,317 80,559

individuals 100% 46% 28% 20%

1950 1955 1960 1965 1970 1975 1980

Year

SOURCE Off Ice of Technology Assessment

is summarized in table 112. The patterns and

trends are very similar to those observed for

leaseholders with exceptions that unincorporated individuals play a larger role among

holders of PRLAs and independent corporations have a smaller share of PRLA land than

leased land.

Unincorporated Individuals

The relative importance of individuals in

the leasing program has declined significantly both in terms of leases and PRLAs. Unincorporated individuals control just 5 percent

of all land under lease, down from 27 percent

in 1950; they hold 20 percent of all land under

Independent corpora- — 107,558 89,345 47,480

tions — 33 % 22% 12%

Subsidiaries – — 68,145 143,344 177,783

— 21 % 34% 44% — .

Multi-corporate — — – - — 67,613 95,002

entities — — 16% 24%

Unknown — 260 260 3,077

— — — 1%

Total 160-5,890 322,725 415,619 403,800

1 00% 100% 100% 100%

. . —

PRLAs, down from 46 percent in 1970. Individuals today hold fewer leased acres than

any of the four business organizations examined and rank third in PRLA holdings. Incorporation provides increased legal and

financial protection over the sole proprietorship form of business. This advantage provides one of many reasons for the declining

role of individuals. Other reasons were

presented in the individuals “business activity category” earlier in this chapter.

Independent Corporations

From 1950 to 1970, independent corporations held the largest share of leased land of

the four organizational categories. Since

1970, their role has declined and they now

hold 26 percent of leased land and 12 percent

of land under PRLAs. Independent corporations are the second largest leaseholding

group and the smallest PRLA holding group

among the four organizational categories.

Subsidiary Corporations

OTA has defined a subsidiary corporation

as a company wholly owned by one other

company. Subsidiary companies currently

own more leases and PRLAs than the other

three organizational groups. The leaseholdings of subsidiaries have grown steadily from

21 percent of all land under lease in 1955 to
Ch. 13—Patterns and Trends in Ownership of Federal Coal Leases and PRLAs 1950-80 383

43 percent in 1980, Their share of PRLAs increased from 21 percent in 1970 to 44 percent in 1980.

Subsidiaries have used four different

methods to increase their lease and PRLA

holdings, First, subsidiaries have acquired an

increasing share of leases and permits issued

de novo by the Government. Secondly, many

leases and permits held by individuals or independent corporations have been obtained

by subsidiary companies through assignment.

Thirdly, some independent companies have

undergone internal reorganization or formed

new subsidiaries, resulting in the transfers of

title to leases or PRLAs to a subsidiary within

the corporation. Finally, dozens of independent corporations have been purchased by

other companies thereby changing their

status from independent to subsidiary companies. Title to leaseholdings was frequently

retained by the formerly independent company rather being transferred to the purchasing company,

The present large holdings of subsidiaries

is particularly prevalent in two business activity categories examined by OTA, coal mining and landholding,

In 1950, 18 independent coal companies

comprised the largest leaseholding category

while only three coal subsidiaries of noncoal

parent companies held leases, By 1980, 36

wholly owned coal mining subsidiaries held

36 percent of land under lease, while the

share held by independent coal companies

had dropped to 7 percent, Similarly, only one

PRLA is held by an independent coal company today, while 33 are owned by coal subsidiaries.

In many cases, there is a direct link between the decline of independent coal companies and the growth of subsidiaries, At

least 10 of the wholly owned coal mining subsidiaries holding leases today previously

operated as independent companies. A larger

number of independent coal companies went

out of business after selling their assets—including coal leases— to noncoal companies

that subsequently organized coal mining subsidiaries to which the leases were assigned.

Landholding companies provide another

example of the trend towards 1easing by subsidiary rather than independent companies.

In 1960, 8 percent of all land under lease was

controlled by independent landholding companies that hoped to profit from the eventual

assignment of their leases to coal development companies. Today the independent landholding companies hold less than 1 percent of

all land under lease. On the other hand, starting in the early 1960’s, leaseholdings by landholding companies that are subsidiaries of

companies with principal business activities

other than coal mining has increased steadily.

Today nine landholding subsidiaries control

more acreage than the independents ever did.

Similarly, only two PRLAs are owned by independent land companies while 30 are

owned by land subsidiaries.

The two leasing trends among landholding

companies appear to be unrelated. Most independent landholding companies acquired

leases as speculators and they have gradually liquidated their holdings over the past

decade. Many of the companies now holding

leases—most notably the energy companies

and utilities—have formed landholding subsidiaries to which leases have been assigned.

These subsidiary landholding companies are

legal entities through which large corporations hold land, usually for future development.

Multicorporate Entities

OTA has defined multicorporate entities as

companies wholly owned by two or more companies (such as joint ventures) or two or more

companies sharing ownership of leases.

Over the past decade there has been a substantial increase in lease and PRLA holdings

by various types of multicorporate business

organizations. They represent the newest

form of business organization to gain a significant share of the Federal coal leasing program. Since 1970, leaseholdings by such entities have increased from 8 to 25 percent and
384 An Assessment of Development and Production Potential of Federal Coal Leases

PRLA holdings have increased from zero to

24 percent. Multicorporate entities are now

the third largest leaseholding business organization studied by OTA and the second

largest PRLA holding group.

Three types of business arrangements are

included in the multicorporate entity category. The first includes two or more corporations holding shares in leases or PRLAs.

For example, 10 leases are held jointly by

Consolidation Coal Co. and Kemmerer Coal

Co. and 10 PRLAs are co-owned by Fannin

Square Corp. and Eastern Associated Properties Corp. Secondly, this category includes

companies that represent legal joint ventures

of two or more companies formed to develop

specific business interests. These include

companies such as Colowyo Coal Co., a joint

venture of W. R. Grace & Co. and Hanna Mining Co., and Cumberland Coal Co., a joint venture of subsidiaries of Peter Kiewit Sons and

Union Pacific Corp. Finally, this category includes Peabody Coal Co., (which is owned by

six companies through participation in the

Peabody Holding Co.), and Ark Land Co.

(which is owned by Ashland Oil and two Hunt

business enterprises).

Implications of Lease and PRLA Ownership Patterns

and Trends

The OTA analysis of the historical roles of

different business activity and organizational

structures in coal leasing suggests several

observations.

Concentration

The data obtained in this study reveal little

evidence of a concentration of lease or PRLA

holdings among fewer companies. The number of participants in leasing nearly doubled

from 1950 to 1980, from 84 to over 160. The

four largest leaseholders in 1950 controlled

32 percent of all land under lease while the

top eight controlled 34 percent in 1980.

Hence the number of participants has increased and the concentration of ownership

among the top companies has remained nearly unchanged. The number of PRLA holders

has increased from 37 in 1970 to 47 in 1980.

Other evidence suggesting the absence of

concentration is provided by the entry of

lease and PRLA holders from an increasingly

wide assortment of businesses. In 1950, only

four business activity categories were identified in this survey as holding at least 5 percent of all land under lease. By 1980, nine

such categories were identified. Also, while

six business categories contributed 5 percent

or more of the total production from Federal

land in 1972, seven categories provided at

least that level of output in fiscal year 1979.

In both 1970 and 1980, six business activity

categories held at least 5 percent of all

acreage under PRLAs.

While the above data suggest that concentration has not occurred, other data show

that leaseholding entities typically hold larger blocks of Federal coal land and more Federal coal leases than in earlier years. During

the 30-year period when the number of leasing participants nearly doubled, the total

number of acres under lease increased 18

fold and the number of leases increased sixfold. On the average, a lessee held 3.38 leases

and 4,975 acres under lease in 1980, 10 times

more than the 493 acres held, on the average,

and three times the 1.04 leases held, on the

average, by lessees in 1950. Little change is

noted for average number of acres held by

PRLA holders. For PRLAs, the average number of acres held was 8,722 in 1970 and 8,591

in 1980.

Diversification

The increased involvement in the Federal

coal leasing program by widely different
Ch. 13—Patterns and Trends in Ownership of Federal Coal Leases and PRLAs 1950-80 ● 385

types of businesses is complemented by a

trend toward increased diversification of

business interests within the lease and PRLA

holding companies. Three patterns within

this trend are noteworthy.

First, there is a growing involvement in the

leasing program of horizontally integrated

companies. The energy companies, natural

gas pipeline companies, and smaller oil and

gas companies together hold 31 percent of the

land under lease, In 1965, the companies in

these three categories combined held only 4

percent of Federal coal acreage under lease.

These companies also control 36 percent of

all land under PRLAs, up from 15 percent in

1970. For these companies, involvement in

coal leasing appears to be part of a strategy

to branch into several energy resource fields.

Growing involvement of companies for

which coal reserves acquisition represents a

vertical integration of business activities is a

second trend in lease ownership patterns.

Steel companies and electric utilities—which

together hold 29 percent of all land under

lease today—are the two principal examples

of leasing by vertically integrated companies.

Steel companies have for decades mined significant quantities of coal and have participated in the leasing program since its inception. The growth of utility involvement in

Western leasing since 1965 to its position as

the largest leaseholding business activity

category in 1980 represents a new and significant type of vertical integration among

lessees. The Federal coal leasing program

has provided an important avenue for utility

entry into the coal industry. Utilities provided

11 percent of the Nation’s coal output in

1979. They hold 21 percent of all Federal coal

land under lease and produced 30 percent of

all coal mined on Federal land. Approximately one-fourth of all utility “captive” coal production was mined from leased Federal

reserves.

A third trend reflects the growing involvement of large, already diversified companies

in coal leasing. These include metals and mining companies that are diversifying their

mineral extraction skills to include coal. They

also include chemical and high-technology

companies for which entry into the coal industry represents a diversification related to,

but not integrated with, existing business activities.

The shift in leaseholdings to large, diversified and integrated companies in turn suggests several observations. First, lease development decisions are increasingly shaped

by priorities that reflect business opportunities and capital availability unrelated to

coal development. Secondly, these ownership

changes can cause a relocation of final decisionmaking authority affecting coal development from local managers to those sometimes

working hundreds or thousands of miles from

lease sites. Thirdly, the internal business arrangements established by large companies

to manage coal leases result in complex decisionmaking processes. While all three of

these trends might contribute to increased efficiency in the coal industry, they make understanding coal industry priorities an increasingly difficult task.

Another result of ownership changes is the

appearance of more lessees with the financial resources available for coal development

that far exceed the resources available to the

earlier, smaller coal leasing companies. Increasing participation by larger and more

complex corporate entities is not surprising

considering the large capital requirements

posed by today’s coal development.

Next, the increasing tendencies of the

large, diversified companies holding leases to

establish multicorporate development projects could raise competition concerns not

posed when leasing was dominated by many

small independent companies. Multicorporate lease development ventures provide a

means for corporations to distribute the risks

involved in undertaking large-scale coal development projects. They also increase the

capital generating capacity of the project as

a whole. At the same time, they increase the

level of intercorporate information exchange

and communication. Finally, joint venturing

through subsidiaries far removed structur-
386 “ An Assessment of Development and Production Potential of Federal Coal Leases

ally from the parent organization has recently provided indirect entry into coal leaseholding by railroads. * (Railroads are prohibited

by the Mineral Leasing Act of 1920 from direct lease ownership.**)

Leasing Policies

Several recent studies have pointed to the

potential importance of Federal coal leasing

policies as a determining factor in the organization and development of the coal industry

over the next several decades. The Harvard

*See ch. II, sec. 6 M, Other Leaseholders, of the OTA Technical Memorandum for further in formation. See reference on

p. 371.

**A recent Justice Department report recommends striking

from Federal law prohibitions againsl the issuance of Federal

coal leases 10 ra ilr(xads or their a ffilia [es. (Competition in the

Coal Industry. Report of the U.S. Department of Justice, /)urswn t to sect;(m 8 f~f the Federf]l C(NII Leasing Arnendrnen (S Acf

of 1976 for F“iscxd Year 1 !)79; U.S. Dcpartmen t of Justice AnIitrust Divisifm: November 1980. )

Business Study, Energy Future, for example,

observes that: “competition can be protected

by methods short of horizontal divestiture,

such as existing antitrust laws, setting limits

on the share of reserves any single firm can

control, and innovative leasing policies. The

last can be especially effective.”***

The present study shows that over the past

30 years, ownership patterns on leased public coal land have generally been similar to

the pattern of industry restructuring typical

for private land. Indeed, some developments

on Federal coal leases—such as the growing

role of utilities as “captive” coal producers—

seem to be leading indicators of the changing

character of the American coal industry.

* * *R. Stobaugh and D. Yergin (cd.), Energy Future: Report of

the Energy Project of the Harvard Business School (New York:

Random House, 1979).
Appendixes
APPENDIX A

Development and Production of

Federal Coal Leases in the Southern

Rocky Mountain States

Colorado

Overview

Colorado has Federal leases in four coal regions: the Green River, the Uinta, the San Juan,

and the Denver Raton Mesa regions, (See table 34

in ch, 6 for a summary of acreage and reserves

under lease.) The San Juan and the Denver-Raton

Mesa regions contain the fewest number of Federal leases. There is one Federal lease in an approved mine plan in the San Juan region. Six Federal leases in the Denver-Raton Mesa region are

currently undeveloped. Most of Colorado’s 127

Federal leases and reserves are located within the

Uinta and Green River regions. In the Green River

region, 31 leases are in approved mine plans, 3 are

in pending mine plans, and 23 are not in mine

plans. In the Uinta region, 22 leases are in approved mine plans, 18 are in pending mine plans,

and 23 are not in mine plans. (See fig. A-l.)

In total, Colorado’s 127 Federal coal leases

cover more than 126,000 acres of land and contain

over 2.2 billion tons of recoverable coal reserves.

The State thus ranks second to Utah, and before

New Mexico in lease acreage and reserves in the

Southern Rocky Mountain region. In 1979, Colorado mines with Federal leases produced almost

16 million tons of coal, as compared to roughly 10

million tons from Federal mines in Utah, and

about 8 million tons from New Mexico Federal

mines.

Overall the maximum production capacity for

Colorado’s existing and proposed Federal mines is

almost 45 million tons per year. production from

these mines in 1986 could exceed 29 million tons.

Production from undeveloped leases in 1986 is

only 0.6 million tons, By 1991, production from

existing and proposed Federal mines could increase to about 35 million tons, and production

from currently undeveloped leases could also increase substantially, to about 8 million tons,

The Department of Energy (DOE) 1985 production goals for Colorado of 34 million to 38 million

tons are higher than OTA’s estimate of potential

Figure A-1 .—Coal Mines on Federal Lands

in Colorado

MOFFAT

●

6“!

RIO BLANCO

Map locations

1- Canadian Strip 15- Somerset

2- Colowyo 15- Blue Ribbon

3- Eagle Nos. 5, 9 16- Loma Complex

4- Trapper 17- Bear

5- Deserado 17- Mt. Gunnison

6- Meeker Area 18- Coal Basin

7- Apex No. 2 19- Hawksnest East & West

8- Edna 20- Ohio Creek No. 2

8- Trout Creek 21- Windjammer No. 1

9- Energy Fuels Nos. 1, 2 22- Cameo Nos. 1, 2

10- Johnnies 22- Roadside

11- Seneca, 2W 23- Coal Canyon

12- National King Coal 24- Cottonwood Creek

13- Orchard Valley 25- Snowmass

14- Red Canyon No. 2 26- Marr

SOURCE: Office of Technology Assessment.

production from Federal mines in 1986 (29.4 million tons), The difference in large part will probably be offset by production from non-Federal

mines and from mines on Federal preference right

lease applications (PRLAs), The OTA Colorado

task force estimated that 1986 minimum State production would be about 26 million tons from all

mines. By 1991, the Colorado task force projected

that minimum State production would range from

389
390 An Assessment of Development and Production Potential of Federal Coal Leases

32 million to 38 million tons. OTA’s analysis

found that potential production from mines with

Federal leases could reach 43 million tons in 1991

exceeding the task force projection and almost

equaling the DOE high-level 1990 production goal

of 43.3 million tons. (The DOE low-level goal is 28

million tons and the midlevel goal is 35 million

tons,) By the 1990’s Federal mines are expected to

contribute a larger share of total State production.

Green River Region

Of the four coal regions in Colorado, the Green

River region is the most important in terms of its

total coal reserves, its total mine capacity, and its

past and anticipated coal production. Roughly 60

percent of the region’s total Federal lease reserves

are not yet included in any mining plans. Only 2.5

percent of the region’s lease reserves are contained within mine plans pending with the Office

of Surface Mining IOSM), The remaining 38 percent of the reserves are included within approved

mining plans. (Additional Federal production

could come from the first new lease sales under

the Federal coal management program which

were held in the Green River-Hams Fork region of

Colorado and Wyoming. Almost 56 million tons

were leased in the January 1981 sale, and an additional 64 million tons were sold in April 1981).

Approved Mine Plans.—There are 10 mine plans

involving 31 Federal leases that have been approved in the Green River region. Of these, 8 were

actively in production in 1979 and produced a

total of 11.2 million tons of coal in that year. Two

mines were not producing in 1979, Six mines are

surface operations and accounted for 93 percent

of the production in 1979. All of the approved

mines in this region are expected to be in production in 1986; moreover, all are expected to meet

Department of the Interior’s (DOI) diligent development requirements by that year. Total operating

capacity for these mines is estimated at 23.6 million tons per year, of which 21 percent is underground capacity. According to mine plan projections, production for 1986 will reach about 19 million tons and could increase slightly to almost 20

million tons per year by 1991. These production

levels represent 83 and 88 percent of maximum

design capacity for existing mines. The total

capacity of currently approved mines will decline

slightly as 2 mines exhaust their existing lease

reserves, several other large surface mines in the

region will exhaust their strippable reserves in the

1990’s and plan to shift eventually to underground

operations to maintain production.

Most of the currently operating Federal mines

in the Green River region are large operations

with annual capacities ranging from 1.1 million to

4,8 million tons per year. The five largest mines

account for 80 percent of the operating capacity;

the mine with the greatest planned capacity is an

underground mine, the multilease Meeker Area

Mine, operated by Northern Minerals. This operation, which produced less than 0.1 million tons in

1979, is projected to be in full production by 1991,

and will be a four-mine complex with a capacity

of 4.8 million tons per year.

Of the approved, operating mines in the Green

River region, the two with the greatest current

production are surface mines. These are the Trapper Mine, operated by Utah International, Inc.,

and the Energy Nos. l&2 Mines, operated by Energy Fuels Corp. Both of these mines, with 1979 production of 2.3 million and 3.4 million tons, respectively, are producing at roughly 85 percent of their

maximum capacity.

Pending Mine Plans.—There are three mine

plans with a total of four Federal leases in the

Green River region that are currently pending approval, Two mines, Western Fuel’s Deserado

Mine, and Gulf Oil’s Trout Creek Mine, are expected to produce a total of 1.3 million tons in

1986. The Trout Creek Mine is a separate underground mine proposed to operate on a Federal

lease that is also included in Gulf Oil’s existing

Edna Strip Mine. This mine is expected to be

operating at its maximum capacity of 0,5 million

tons per year in both 1986 and 1991. The Deserado

Mine in the Lower White River Field will supply

the Moon Lake Electric Co. ’s new powerplant in

Bonanza, Utah. production from proposed mines

in this region is expected to increase from the

1986 level as a result of increased production from

the Deserado Mine. Total projected production

from pending mine plans in this region is 1.8

million tons per year in 1991. One proposed small

mine on a post-FCLAA lease will probably not go

into production because of financial difficulties

caused by the delay in issuing the lease.

Undeveloped Leases.—The Green River region

has the greatest amount of undeveloped reserves

and the highest estimated future production from

its undeveloped leases of any region in Colorado.

The region has 23 undeveloped leases which

contain approximately 816 million tons of coal

within about 24,400 Federal lease acres. These

leases are relatively large, both in acreage and in

reserves, For example, 10 of the leases are greater

than 1,000 acres in size and contain from 20 million to 250 million tons of recoverable coal reserves each.
App. A—Development and Production of Federal Coal Leases in the Southern Rocky Mountain States ● 391

Of the 23 undeveloped leases in the Green River

region, 16 leases in 14 blocks with 792 million tons

of recoverable reserves are promising new mine

properties. The remaining 7 leases with less than

24 million tons of reserves could not support independent viable mining operations, (See table 44

in ch. 6.) Two leases have favorable development

prospects. Seven have unfavorable development

prospects; most of these leases with poor development potential have insufficient reserves to support an economically viable mine of minimal size.

Based on OTA’s evaluation, the majority of the

reserves, 738 million tons contained within 14

leases, have uncertain development prospects,

The two leases in this region which have favorable development prospects are held by Peabody

Coal Co, One lease is located midway between

Peabody’s existing Seneca and Seneca 2W operations, and is expected to be surface mined at a rate

of about 0.6 million tons by 1986. This is the only

undeveloped lease block that is projected to be in

production in that year. It will supply the nearby

Hayden powerplant under a dedication agreement, and will maintain Peabody’s current capacity and production levels, Production from the

other favorable lease, which will be an underground mine, is projected to begin in 1987 and

will share existing nearby facilities. Maximum

production capacity for this mine would be 1.0

million tons per year.

By 1991, 5 of the 14 leases with uncertain development potential ratings, are projected to be in

production, Total production from undeveloped

leases in the Green River region is estimated to be

6.4 million tons in 1991. Production will be concentrated in the Yampa, Danforth Hills, and North

Park coalfields. Actual production may vary from

these estimates. Current production from the

Green River region goes primarily to utilities.

One of the small leases with anticipated production for 1991, held by AMCA Coal Leasing, was

previously mined by underground methods, However, it also contains strippable reserves of bituminous rank which could be developed as a small

mine to serve spot market or local needs. It is located in an active mining area where strip reserves are gradually being mined out, thus making

its marginal strip reserves more desirable, production is estimated to be as much as 50,000 tons per

year by 1991.

The 1991 production from the lease held by

W. R, Grace & Co. could be as high as 1.4 million

tons per year. Considerable uncertainty surrounds

this projected production since one possibility for

the lease’s development is linked to Grace’s proposed synthetic fuels plant in Moffat County. Recently, their initial coal conversion goals were

scaled down from 5,000 to 500 tons per day. If the

smaller plant proves to be successful, Grace could

scale up to its original size. Grace could also develop this tract as an alternative source of coal for

more conventional uses when strippable coal reserves in northwestern Colorado are expected to

be depleted in the 1990’s.

There are seven large Federal leases in the Danforth Hills Field of the Green River region: six are

held by Consolidation Coal Co., and one is held by

Utah International, Inc. Production from these

leases is contingent on resolution of uncertainties

involving the issuance of associated PRLAs and

negotiations with surface owners, including a potential competitor, W. R. Grace & Co, Production

from Consolidation Coal’s lease blocks could

reach 1.3 million tons per year by 1991 with an

eventual capacity between 3 million and 6 million

tons per year, The lease held by Utah International, although reported to have sufficient reserves to sustain an average-sized new mine,

would probably only be developed if the lessee obtained sufficient additional acreage and reserves

from its PRLA or new lease sales to allow operation of a very large surface mine similar to the adjacent Colowyo Mine, If development proceeds

smoothly, OTA estimates that product ion from

this mine could reach 1,3 million tons by 1991 out

of a potential annual capacity of 3 million to 6

million tons,

The remaining coalfield in the Green River

region that may have production by 1991 is the

North Park Field in Jackson County. Possible production of 0.5 million tons per year from leases

shared by Kemmerer and Consolidation Coal companies is estimated for 1991, however development is contingent on improvements in coal transportation from the area, No production is projected for 13 remaining undeveloped leases in the

Green River region.

Uinta Region

The Uinta region contains 63 leases covering

nearly 70,000 acres with a total of over 800 million

tons of recoverable reserves, Approximately 203

million tons of reserves are contained in 22 leases

in approved mine plans, about 427 million tons

are in 18 leases with pending mine plans, and 173

million tons of reserves are in 23 leases without

mine plans. Total maximum capacity is 8 million

tons per year for approved mine plans and over 11

million tons per year for Federal leases in pending
392 ● An Assessment of Development and Production Potential of Federal Coal Leases

plans. potential capacity for leases without plans

is estimated at 1.5 million tons.

As displayed in table 37 in ch. 6, projected production for 1991 is 7.4 million tons per year for

pending plans, 5.8 million tons per year for approved plans, and up to 1.3 million tons per year

for leases without plans.

Approved Mine Plans.—In the Uinta region there

are eight operating mines which include 22 Federal leases. All but one of these mines began producing in the late 1970’s and all of them reported

production for 1979. Furthermore, past and anticipated future rates of production indicate that

all of the mines will satisfy DOI’s diligent development requirements by 1986.

Federal lease reserves total 203 million tons in

approved mine plans. Total mine plan reserves

are 208 million tons. All of the reserves are high

volatile bituminous and all are best suited for recovery by underground mining methods. Several

mines in the region produce high-grade metallurgical coal.

Total maximum design capacity of these mines

is almost 8 million tons per year. The maximum

capacity of individual mines varies widely—from

0.1 million tons per year for the small Ohio Creek

No. 2 Mine to 1.4 million tons per year for Western Slope Carbon’s Hawksnest complex. Western

Slope’s 1979 production was only 31 percent of

their design capacity. However, they expect to be

operating at full capacity by 1991, The Coal Basin

Mine’s multilease operation held by Mid Continent Resources, represents another large increment of capacity for approved mine plans. Their

underground operation is designed to handle 1.3

million tons per year, and their projected production for both 1986 and 1991 of 0.9 million tons is

expected to account for about 65 percent of this

capacity,

Two mines, the Bear Mine, operated under a

sublease from ARCO, and the Roadside Mine,

operated by Cambridge Mining, are expected to

exhaust their reserves by the end of this decade.

The Bear Mine is currently operating at close to

its capacity of 0.26 million tons per year and will

shut down in the next few years before operations

begin on ARCO’s larger, Mt. Gunnison mine on

the same lease. The Roadside Mine, which began

producing in the 1900’s and which has a capacity

of 1.2 million tons per year, is reducing its operations and anticipates production of only about

0.3 million tons by 1986.

The Orchard Valley Mine operated by Colorado

Westmoreland will exhaust its current lease reserves by the mid-1980’s at its present production

rate. The mine is expected to continue operations

with the acquisition of new Federal lease reserves.

Pending Mine Plans.—The Uinta region has 18

Federal leases in 8 currently pending mine plans.

In total, there are about 427 million tons of recoverable reserves on over 34,700 lease acres. One of

these proposed mines, the Loma complex of Sheridan Enterprises, reported production for 1979.

This was the result of development work at the

mine site.

By 1986 five new mines are projected to produce approximately 2.8 million tons of coal. At

this rate of production, three of these mines, the

Blue Ribbon, Loma complex, and Windjammer

mines, seem likely to meet DOI’s development requirements by 1986. All eight of the proposed

mines are expected to be in production by 1991,

and all but one seems likely to meet diligence

development requirements by then.

When all mines are brought into production,

maximum operating capacity is expected to exceed 11 million tons per year. Given this capacity

base, anticipated 1986 production of 2.8 million

tons will represent approximately 25 percent of

total mine capacity, and projected production of

7.4 million tons for 1991 will represent 67 percent

of full capacity. several of the newer mines will

probably not achieve full capacity until after l990.

Operating capacity for individual mines ranges

from 0,12 million to 5.0 million tons per year. Two

mines—the Loma project, operated by Sheridan

Enterprises, and the Mt. Gunnison Mine, operated by ARCO—account for 70 percent of the total

capacity for pending mine plans in the Uinta

region.

When completed, the Loma project is expected

to be producing from six underground mines

using both longwall and room-and-pillar methods.

Estimated production for 1991 is expected to be

about 56 percent of the 5.0 million tons per year

eventual planned capacity for the Loma Mines.

The Mt. Gunnison Mine is projected to begin

production in 1983, and to take approximately 10

years to reach the estimated operating capacity of

2.8 million tons per year. The coal will be recovered by room and pillar underground mining

methods, The reserves in the Mt. Gunnison leases

are very large. If all seams in the lease, including

seams not currently mined, are made part of the

logical mining unit (LMU) reserves for diligence,

Mt. Gunnison might have some difficulty in meeting the 2,5 percent production required for diligence.

Undeveloped Leases.—The Uinta region has a

total of 173 million tons of recoverable reserves
App. A—Development and Production of Federal Coal Leases in the Southern Rocky Mountain States ● 393

contained within 23 undeveloped leases. The majority of these reserves are recoverable by underground mining only, and their quality ranges from

subbituminous to bituminous. Based on OTA’s review of these leases, 18 leases in 6 blocks covering

about 17,660 acres and containing approximately

159 million tons of reserves could sustain new

mining operations. The remaining five leases,

containing about 14 million tons of recoverable

reserves do not have sufficient good quality

reserves to support viable new mines.

Not all of the 18 viable leases, are likely to be developed. Eight leases were classified as favorable

development prospects, three leases have uncerthin development prospects, and the remaining

seven leases have unfavorable development potential.

None of the Uinta region undeveloped leases

are expected to be in production by 1986. For

1991, OTA projects that two lease blocks held by

U.S. Steel with a total of nine leases could be producing up to 1.3 million tons. Of this production,

up to 0.75 million tons of high-quality metallurgical coal could be produced from eight U.S. Steel

leases in the Coal Basin Field. There is some

uncertainty about this production, however, due

in part to the lease area’s steeply dipping seams,

faulting, and deeply buried seams which will

make underground mining difficult and the fact

that U.S. Steel has been purchasing production

from the neighboring Coal Basin Mine. U.S. Steel

has no current plans to develop the Coal Basin

leases before 19$10. Two other mining companies

have developed or planned development of adjoining mine properties which have similar property

characteristics, indicating that the adverse mining

conditions can be overcome. The remaining uncertainty concerns the currently depressed market for metallurgical coal. Three other lease blocks

held by U.S. Steel in the Somerset-Paonia area

have uncertain development prospects based on

the expectation that they would be developed as

part of a company strategy to expand coal operations to steam coal, since the coal on these blocks

is not of metallurgical quality. U.S. Steel has an

existing mine in Somerset that supplies its

Geneva, Utah steel plants. The OTA Colorado task

force estimated that, by making use of their existing loading and other facilities, surface mining

production from the other leases could reach 0.5

million tons per year by 1991, Alternatively, the

leases might be assigned to an independent operator.

No production is anticipated from the remaining 14 leases in the Uinta region including two

blocks with a total of 7 leases held by Kemmerer

Coal Co. in the Tongue Mesa Field. These leases

have sufficient high-quality reserves to support a

new mine, but there is not an adequate coal transportation system in place.

Denver-Raton Mesa Region

Currently there are no active Federal mines or

any pending mine plans for Federal leases in the

Denver-Raton Mesa region of southeastern Colorado. The region contains six Federal leases without mine plans, which OTA has organized into

four lease blocks. Based on a review of the quality

of leased coal, the size of the reserve base and the

lessee’s development capabilities, four of the

leases in two blocks are considered to be viable

mining properties. Peabody Coal Co. holds the

four favorable lease properties which contain a

total of over 48 million tons of surface recoverable

reserves,

These leases have uncertain development prospects largely because the coal is lignite. Development of these tracts will likely require a near site

use, such as a mine-mouth powerplant or synfuels

facility, in order to overcome the less favorable

economics of transporting the lower quality coal.

The four leases could be producing up to 0.5 million tons in 1991, and thus may satisfy the DOI’s

diligent development requirements by that year,

although this is still speculative. The other two

leases in the region have unfavorable development potential. The lease held by CF&I Co., has

unfavorable development prospects for 1991 because the lessee has available more attractive nonFederal reserves than those contained within this

single lease block composed of small scattered

parcels of Federal coal.

The remaining lease, a 40-acre tract with underground reserves, is not considered a viable mining

property due primarily to its small reserves base.

San Juan River Region

The San Juan River coal region is located in Colorado and New Mexico; the larger portion of the

region lies in New Mexico. There are six active

non-Federal mines operating in the Colorado portion. The only Federal lease in the region is in the

National King Coal Mine, a small operation producing about 70,000 tons per year for sale to local

consumers. Coal was first produced from the

lease in 1936 and production is expected to decrease from 83,000 tons in 1979 to 65,000 tons per

year by 1986. The Federal lease reserves are expected to be mined out by 1991.
394 ● An Assessment of Development and Production Potential of Federal Coal Leases

Summary of Production Potential

In 1979, the 19 mines with Federal leases produced over 16 million tons of coal with about half

of this production (7.7 million tons) from Federal

reserves. By 1986, two of the currently operating

mines are expected to deplete their reserves, however, nine new Federal mines are expected to be

in production. Overall, OTA projects that, total

production from Federal mines will increase to

nearly 30 million tons—almost double the 1979

production. The percentage of total production

from Federal reserves is also expected to increase.

By 1991, 35 mines containing Federal leases are

projected to produce 43.1 million tons of coal,

About 8 million tons of this production could

come from currently undeveloped leases.

New Mexico

Overview

The 29 Federal coal leases in New Mexico

cover over 44,000 acres and contain 447 million

tons of recoverable coal. The State has the fewest

leases and leased reserves among the three

Southern Rockies States and fewer leased reserves

than any major coal-producing Western State except North Dakota. Three of the leases are in the

Raton Mesa region of northeast New Mexico and

the other 26 are found in the San Juan basin in the

northeastern part of the State.

Only one large coal mine complex is operating

in the Raton Mesa region, It is located entirely on

non-Federal land, No extensive development is expected to occur in this region on either Federal or

non-Federal land, although an additional mine

could be developed in the region. Coal is found in

small scattered deposits throughout the rough and

mountainous terrain of this region. Though the

Raton Mesa contains high-quality and metallurgical-grade coals with a Btu content averaging

14,340 Btu/lb and sulfur levels averaging less than

one percent, the difficult terrain, small reserves,

and lack of markets has inhibited development.

Other problems facing developers of three small

leases here include limited local rail capacity

(although the region itself is served by a main line

of the Santa Fe Railroad), and complicated coal

land access problems involving intermingled Federal, railroad, Spanish land grant, and private

land blocks.

The San Juan basin contains 96 percent of the

remaining coal resources in New Mexico, including nearly all of the strippable reserves, A substantial portion of the basin’s reserves are controlled

by the Navaho Tribe. Over 80 percent of the 1980

coal production of 16.5 million tons in the State

came from this region and by 1990 it could account for over 95 percent. Typical San Juan coal

has a Btu content of 10,492 Btu/lb and a sulfur

content of 0.84 percent. It has relatively high

average ash levels of 13.8 percent, although the

ash content can be as high as 25 percent in some

areas.

Mining currently occurs in two areas within the

San Juan basin, There is at present little or no production in the central part of the basin (see fig.

A-2). Production from the northwest corner, including the San Juan Mine on Federal land, is

used at mine-mouth generating stations. Production from the McKinley Mine on Federal and Indian land in the southwest part of the region is

shipped by rail mostly to Arizona and other

Western markets. Most of the San Juan basin coal

reserves, including areas with leased Federal coal,

are not served presently by rail transportation.

This central region of the basin is one of the

largest untapped strippable coal deposits in the

Western United States. The Santa Fe Railroad has

proposed to build a 114-mile line into the area,

Figure A-2.—Coal Mines on Federal Lands in

New Mexico

I

SOURCE: Office of Technology Assessment.
App. A—Development and Production of Federal Coal Leases in the Southern Rocky Mountain States ● 395

called the Star Lake Railroad. The final environmental impact statement has been issued. The remaining uncertainty involves 3 miles of right-ofway that cross land owned by Indian allotment

holders. Rugged terrain makes rerouting across

other land prohibitively expensive. Negotiations

with the Indian allottees are underway and the

railroad has asked the Secretary of Interior to

waive the landowner consent requirement. The

Bureau of Land Management had deferred granting of the rights-of-way across Federal land until

resolution of the allottee issue, though it has approved use of Federal land for the project. The

Star Lake-Bisti Regional Coal Environmental

Statement projected that coal production associated with the railroad could eventually reach 75

million tons per year, About 8 million tons of

Federal mine production in 1991 is tied to development of the Star Lake Railroad,

The 29 New Mexico Federal coal leases can be

divided into 16 lease blocks. Three of these units

are single leases in the Raton Mesa. The other 13

are located in the San Juan region.

Nine leases in two lease blocks are currently

part of operating mines. These two mines produced 9.7 million tons of coal in 1980, about half

of the State’s total production with about 6.3

million tons produced from Federal reserves.

Three lease blocks including nine leases are part

of proposed mine plans which are now pending

before DOI. The remaining 11 leases and 10 lease

blocks are undeveloped and no mine plans to

develop them had been submitted to DOI as of

September 30, 1980.

Approved Mine plans.—The two producing

mines which include Federal coal leases are the

McKinley and San Juan Mines. The McKinley

Mine includes four Federal leases owned by Gulf

Oil Corp. and Indian and private lands. The San

Juan Mine includes five leases owned by Western

Coal Co., a joint venture of Public Service Co. of

New Mexico and Tuscon Electric Co. It is operating almost entirely on Federal lands, although

possible expansion onto coal lands on the Ute

Mountain Indian Reservation to the north is being

considered. Both are surface mines. The approved

mine plans for these projects call for small increases in mining on Federal land over the next

decade. The McKinley Mine is scheduled to increase production from 4.6 million to 5.0 million

tons by 1991 and the San Juan Mine is scheduled

to increase from 5.1 million to 5,5 million tons.

The San Juan Mine will shift a portion of its capacity to underground operations on a new Federal lease acquired in 1980.

Pending Mine Plans.—Like the operating mines,

the three lease blocks for which mine plans are

pending are located in the San Juan region. Five

leases are part of the La Ventana Mine project proposed by the lessee, Ideal Basic Industries. It is the

only active or proposed mine on Federal leases in

New Mexico that will be solely an underground

operation. At least seven inactive leases in the La

Ventana area once supported small underground

mines, but these were closed due to structural and

fire hazards, inability to comply with health and

safety regulations, and the decline of the domestic

coal market in New Mexico, The proposed La

Ventana Mine plan has been designed to resolve

what had been difficult safety problems involving

poor roof conditions and the tendency of La Ventana coals for spontaneous combustion, A market

for at least part of the coal produced exists at

Ideal’s cement plant in Albuquerque, The mine is

scheduled to produce 1.1 million tons by 1986 and

1.5 million tons by 1991; it has an eventual capacity of 3 million tons per year.

The other two pending mine plans with four

Federal leases are located in the area of the San

Juan basin presently without rail service. Development of these tracts will depend on either the construction of the Star Lake Railroad or the construction of mine mouth power or synfuels plants,

The proposed Bisti Mine includes three leases

owned by Western Coal Co. Public Service Co. of

New Mexico has proposed building a mine-mouth

powerplant near this mine, but that project is in

only preliminary planning stages and the construction schedule is still uncertain. The second

lease block is a single lease owned by Peabody

Coal Co., and Thermal Energy Co. The mine proposed for this site, however, is being developed by

Chaco Energy Co., a subsidiary of Texas Utilities,

Inc. The Star Lake Mine, as it is called, will likely

supply powerplants owned by the parent company or serve other utility markets. The Star Lake

Mine eventually will include reserves from pending PRLAs. The Bisti Mine is scheduled to produce 2.5 million tons by 1986 and 3 million tons by

1991. The Star Lake Mine is scheduled to produce

3 million tons in 1986 and between 3 million and 6

million tons by 1991. Coal from Star Lake would

be shipped via the Star Lake Railroad.

Undeveloped Leases.—Eleven leases in ten lease

blocks are inactive and have no mine plans for

their development pending before DOI, although

some planning work is underway on several of

these. The three small leases in the Raton Mesa

region fall into this category of undeveloped

leases, The group also includes six small leases
396 ● An Assessment of Development and Production Potential of Federal Coal Leases

and two large leases in the San Juan region. These

two large leases are part of proposed mining projects which have not yet reached the completed

mine plan stage. Production from these mines is

likely before the end of the decade, Some preliminary investigations of mine development on several of the smaller leases as part of mine development on adjacent lands has been reported, however, prospects for production before 1991 are unfavorable.

The two leases that might be in production by

1991 include 98 percent of all the undeveloped

Federal lease reserves in New Mexico. The first

lease is owned by Cimmaron Coal Co. and is part

of the proposed LaPlata surface mine in northwest New Mexico. The mine could serve the supply needs of the nearby San Juan powerplant as

reserves from the San Juan Mine are mined out.

Based on a review of a wide range of factors, including coal quantity and quality, transportation

access, environmental issues, engineering problems, and markets among others, OTA found that

the lease has a favorable development potential.

Production is scheduled to total 0.2 million tons in

1986 and between 1 million and 2 million tons in

1991.

The second large New Mexico lease (1,910

acres) is located along the route of the Star Lake

Railroad. It is owned jointly by Fannin Square

Corp. (a subsidiary of Texas Eastern Transmission

Corp.) and Eastern Associated Properties Corp. (a

subsidiary of Eastern Gas and Fuel Associates).

The lease also received a favorable development

prospect rating by OTA though several uncertainties cloud its future. The lessees are likely to need

additional coal reserves adjoining the lease in

order to create an economical mining unit for

large-scale operations. The companies hold

PRLAs for much of this land which might be converted to lease shortly. Texas Eastern Transmission received a DOE grant in 1980 to study the

feasibility of building a major synfuels complex

near the lease and supplied with coal from it.

Prospects for building such a plant are uncertain,

Any export use of the coal on this lease will be dependent on the completion of the Star Lake Railroad. The companies nevertheless are proceeding

with plans for the Black Lake Mine, which if it

proceeds, is likely to produce between 0.7 million

and 6 million tons by 1991 depending on the companies’ coal needs and the rate of development of

adjoining reserves.

Of the nine small leases in eight lease blocks

that are not likely to be in production before 1991,

four blocks received uncertain development prospect ratings by OTA and four were rated as unfavorable for development.

Two of the leases with uncertain development

ratings are located in the Raton Mesa region. The

lessees of both are studying mining projects that

include the leases, but small reserves, mining and

transportation problems caused by the rough terrain earned these leases an uncertain rating at

best. The other two lease blocks receiving uncertain ratings adjoin the proposed La Ventana Mine

site, Each of these lease tracts once were underground mines, but they were closed because fires

and explosions made them unsafe and uneconomical to mine. If Ideal Basic Industries acquires

these leases and incorporates their reserves into

the La Ventana Mine plan, these problems could

perhaps be overcome. The leases would probably

be surface mined. In their present status it is

unlikely that individual mines on these blocks

could ever compete.

The final four lease blocks, one in Raton Mesa

and three in the San Juan region, received unfavorable development prospect ratings by OTA

and were judged to have minimal production potential. All four are isolated tracts with small reserves. Underground mines serving local markets

once operated on them, but they have been closed

for at least a decade because of safety, engineering, and economic problems. There is currently

little or no effort on the part of the present lessee

to develop new mine plans and no published expressions of interest on the part of outside parties

to acquire the leases.

Production Potential

To summarize the production potential of existing Federal coal leases in New Mexico:

Two mines are currently producing about 9.7

million tons of coal per year; and by 1986 these

two mines with approved mine plans are scheduled to produce 10.0 million tons. In addition,

three mines which currently have mine plans

pending at DOI could be producing 6,6 million

tons, and one mine which is now in the premineplan stage could be producing 0.2 million tons by

1986.

By 1991, the six existing and proposed mines

are scheduled to produce between 19.0 million

and 23.0 million tons. One other mine is due to

begin production after 1986, and is scheduled to

produce between 0.7 million and 6.0 million tons

by 1991. Total 1986 production from mines on existing leases is projected to be 16.8 million tons

and 1991 production is projected to be between

19.7 million and 29.0 million tons.
App. A—Development and Production of Federal Coal Leases in the Southern Rocky Mountain States ● 397

If these projections hold true, 6 of the 16 lease

blocks covering 79 percent of the leased reserves

will be included in active mining operations in

1986. By 1991, 7 lease blocks covering 20 of the 29

New Mexico coal leases and over 98 percent of

the coal reserves under lease are likely to be associated with active mining projects.

The DOE 1985 production goals of 33 million to

44 million tons are higher than OTA’s estimate of

potential 1986 production from Federal mines of

16.8 million tons. The OTA task force estimated

that 1986 total State production would be 30

million tons, and recent New Mexico Energy and

Minerals Department estimates have set planned

production from all mines in the State for 1985 at

47 million tons. Most of any shortfall between the

DOE goals and potential Federal mine production

in 1985 to 1986 would probably be absorbed by

mines on Indian and non-Federal reserves, which

currently provide more than half of New Mexico’s

annual coal output.

For 1991, the OTA task force estimated that the

maximum production potential of all mines in the

State would reach 72 million tons—higher than

both the DOE 1990 high level goal of 67 million

tons and the recent State government estimate of

68 million tons of production in 1990. According

to OTA’s analysis, production from mines with

existing Federal leases could reach 20 million to

29 million tons in 1991.

Actual production levels could vary from the

OTA’s projections. Several obstacles to coal mining could lower actual production below these

projections, while the removal of some barriers to

development and a strong coal market could

cause production to increase above these levels.

A key determinant of actual coal production

from New Mexico leases will be the level of out-ofState utility coal demand specifically and coal

market considerations generally. A market study

prepared for OTA concluded that the price competitiveness of New Mexico coal in major Eastern

and Western markets is considerably underestimated. ” Actual market demand will depend on a

wide range of issues including the growth of electric consumption, coal supply decisions of Texas

utilities (Texas is the major potential new market

for New Mexico coal), and the growth or decline

in coal use relative to substitute fuels for power

generation. Within New Mexico, the rate of commercialization of synfuels technology and the possible construction of additional powerplants to

See Energy and Environmental Analysis, Inc., Feos]bilit~, of [ ~sing

Cool ,Jlorket Projections To Appruiw Potential Production of FwjmmJ

CorIl Leaseholds, draft report, May 1980.

serve out-of-State customers are two additional

factors bearing heavily on demand.

The lack of rail service to the central portion of

the San Juan basin is the second most significant

factor affecting the growth rate of New Mexico

coal production, As explained above, the proposed Star Lake Railroad is in an advanced planning stage, but a right-of-way acquisition problem

could still delay or prevent its construction.

Other major issues and uncertainties that will

affect the future of the New Mexico coal industry

include environmental impacts, land-use conflicts, socioeconomic impacts on local communities, and the amount of additional Federal reserves made available for mining through PRLAs

and new lease sales. Mining and associated industrial development such as synfuels plants pose

potentially unacceptable and unavoidable air

quality impacts in this arid region. Mining in the

Bisti area conflicts with protection of three

wilderness study areas and with potentially important archeological and paleontological sites.

An exchange of existing leases for new Federal

coal to avoid some of these conflicts is under consideration. (See discussion in ch. 9.) Demand for

adequate water supplies for mining, reclamation,

synfuels development, and community needs and

the need to protect water supplies from possible

degradation could create conflicts between coal

development and other users. Because of the arid

climate, sparse vegetation, and high susceptibility

to wind and water erosion, reclamation of

surface-mined lands in the San Juan basin may

prove more difficult than in other areas of the

West, This difficulty is not, however, expected to

restrict mine development. Most of the expanded

coal development on Federal leases in New Mexico will occur in areas that are relatively isolated

and sparsely populated. Associated population increases and demands for community services will

impose additional administrative and financial requirements on the existing communities, Moreover, because Native Americans own or occupy

substantial acreages throughout the basin, resolution of potential conflicts between mining and

Native interests will require cooperation with

tribal governments and the U.S. Bureau of Indian

Affairs. (See ch, 12.)

There are currently twice as many acres under

PRLAs than under existing leases in New Mexico.

Processing of PRLAs in New Mexico will have a

significant effect on the future of Federal coal

development there. Two proposed Federal mines

could be adversely affected by loss of reserves if

adjoining PRLAs are rejected. New leased re-
398 . An Assessment of Development and Production Potential of Federal Coal Leases

serves from other PRLAs will compete in the market with other Federal and non-Federal coal currently available for mining.

Utah

Overview

Utah has the largest number of Federal coal

leases of any State. There are 204 leases currently

outstanding in Utah covering over 279,000 acres

and more than 3.2 billion tons of recoverable coal

reserves. Utah also has 25 pending PRLAs totaling

over 75,000 acres and containing over 1 billion

tons of recoverable reserves. According to U.S.

Geological Survey (USGS) estimates, about 82 percent of the coal resources in Utah are federally

owned, This high percentage is due, in part, to the

fact that most of the coal deposits occur in the

rugged mountainous terrain and the upland plateaus of central and southern Utah—areas that

have largely remained in Federal ownership,

while State and private land selections, land

grants, and homesteads were concentrated in the

valleys and flatlands. Most of Utah’s known coal

reserves are underground minable.

Utah has two major coal regions: the Uinta

region which includes the Wasatch Plateau, Book

Cliffs, and Emery coalfields in central Utah; and

the Southwestern Utah coal region, which includes the Alton, Kolob, Kaiparowits Plateau, and

Henry Mountain coalfields.* There are 108 Federal leases in the Uinta region and 96 leases in the

Southwestern Utah region. The recoverable reserves are divided almost equally between the two

regions.

Nearly 65 percent of the Federal leases in Utah

are part of existing or proposed mines and thus

their development and production plans are included in mine plans filed with DOI. The 14 mines

with approved mine plans are all located in the

Uinta region and contain 50 Federal leases with a

total of 792 million tons of reserves, Eleven new

mines have been proposed covering another 78

leases and 1.3 billion tons of reserves. Over 1

billion tons of new mine plan reserves are contained in the three proposed new mines in the

Southwestern Utah region. The remaining 76 Federal leases without mine plans include several

large tracts of good quality minable reserves that

could be producing by 1990, as well as many

* The BLM coal productlon region Uinta-Southwestern Utah combines the Uinta coal region of Utah and Colorado and the Southwestern

Utah coal region into a single region for coal management program and

production target purposes.

smaller tracts that once supported small mines

that will probably not be reopened. The Uinta

region has 44 undeveloped leases and about 447

million tons of undeveloped reserves, The Southwestern Utah region has 32 undeveloped leases

with 744 million tons of reserves—most of which

are on the Kaiparowits Plateau.

Production Potential

In 1979, Utah mines produced 11.8 million tons

of coal with 10.4 million tons of this from mines

with Federal leases. Federal production was 6.9

million tons in 1979 and came from 27 leases. In

1980, total State production increased to 13.1

million tons with 8.7 million tons coming from

Federal reserves. All production in the State came

from underground mines in the Uinta region.

Figure A-3 shows the location of active and proposed mines with Federal leases in Utah.

Most of the coal produced was used by electric

utilities, but a significant portion (about 1 million

to 2 million tons) was used by the steel industry.

About 40 to 50 percent of the coal produced in

1979 was used in the State; the rest was exported

to consumers in the Southwest, west coast, and

Midwest, Up to 2 million tons reportedly was

stockpiled in 1979 because of soft market conditions. However, by the end of 1980 most, if not all,

of Utah’s excess production had been sold, in

part, because of increased foreign export sales. In

1981, at least one Utah Federal mine was shipping

coal under contract to Asian markets,

Coal production and mine capacity in Utah are

expected to increase substantially during the

1980’s as new mines are opened and existing

mines reach full capacity. Production from mines

with Federal leases will account for most of the

growth. By 1986, total output from mines with

Federal leases is expected to be as much as 30.2

million tons with up to 6.2 million tons of this

coming from proposed new mines. By 1991, production from mines with Federal leases is expected to reach as high as 47 million to 74 million

tons. About 7 million to 8.6 million tons could

come from undeveloped leases in central Utah.

Up to 25 million tons of coal could come from new

mines in Southwestern Utah. The total capacity of

existing mines on Federal leases at full production

is 32.2 million tons per year, If all the pending

mine plans went into production they would add

43 million tons of annual capacity. OTA estimates

that the undeveloped leases could support an additional 18.5 million to 28.0 million tons of annual

capacity. Southwestern Utah Federal coal produc-
App. A—Development and Production of Federal Coal Leases in the Southern Rocky Mountain States ● 399

Figure A-3.— Coal Mines on Federal Lands in Utah

Salt Lake City

! 1

0

IN Utah region

Map locations

1- Geneva 10- Des-Bee-Dove

1- B Canyon 10- Wilberg-Deercreek

2- Braztah 11. Emery

3- C & W No. 1 12- Hiawatha Complex

4- Pinnacle (Deadman) 13- Huntington Canyons

5- Gordon Creek No. 2 Nos. 4, 5

6- Sage Point-Dugout 14- Trail Mountain

Canyon 15- Alton

6- Soldier Canyon 16- Kaiparowits

7- Sunnyside Nos. 1, 2, 3 17- Red and Blue

8- Belina No. 1 18- Convulsion Canyon (Sufco)

8- O’Connor 19- Skumpah Canyon

8- Skyline 20- Ute Nos. 1, 2

9- Star Point Nos. 1, 2

tion could grow from nothing in 1979 to over 25

million tons in 1991, with an estimated total annual capacity of 36.3 million to 45.8 million tons.

However, it is highly uncertain whether such

levels of production would be achieved in the

Southwestern Utah region because of the major

transportation, economic, and environmental disadvantages facing coal development there.

OTA’s estimate of planned production from

mines with Federal leases in Utah of 30 million

tons in 1986 agrees with the DOE 1985 midlevel

production goal of 30,2 million tons, but is considerably higher than OTA’s Utah task force estimate of 1985 production of between 15 million

and 18 million tons. At least part of the difference

between the conservative task force estimates and

the OTA estimates and DOE goals is due to deferred powerplant construction. For 1991, OTA

found that potential Federal mine production

ranged from 47 million to 74 million tons with

about 25 million tons of production in Southwestern Utah classified as uncertain. In comparison,

the task force projected that 1990 production

would range from 18 million to 40 million tons,

with a likely level of 30 million tons which excludes any production in Southwestern Utah or

for synfuels development. The DOE 1990 production goals for Utah range from a low of 36 million

tons to a high of 63 million tons with a midlevel

goal of 49 million tons.

The development and production potential of

Federal leases in Uinta and Southwestern Utah

coal regions are described in more detail in the

following sections.

Central Utah

The central Utah portion of the Uinta region includes the Book Cliffs and Wasatch Plateau coalfields near the town of Price and the Emery coalfield near the town of Emery. The Book Cliffs and

Wasatch Plateau coalfields are underground mining areas. The Emery Field has both surface and

underground minable reserves. The central Utah

coalfields have supported mining operations for

over a century. Two active mines in the Book

Cliffs Field—U.S. Steel’s Geneva Mine and Kaiser

Steel’s Sunnyside Mine—suppIy metallurgical

coal to their Western steel operations. The

Wasatch Plateau Field is the major producing area

in the State. (See figs. A-4 and A-5.)

There are 108 Federal leases outstanding in

central Utah. There is only one pending PRLA in

the region. * Federal leases in central Utah cover

128,930 acres and contain an estimated 1.5 billion

tons of recoverable coal reserves, including about

21 million tons of surface recoverable reserves in

the Emery field, The 50* * leases in the 14 mining

operations with approved plans cover over 55,000

acres and more than 792 million tons of recoverable reserves and have a total maximum design

capacity of 32.2 million tons per year. There are

* Possible impacts of issuance and development of this PRLA are examined in the Final [ rin to-!jou I}] wws[ern [ Itoh Cool Enl,ironmentaj Sto tPment, Februar}, 1981.

* *Tbrec leases in the C)’ Connor mine area are also partly included in

the approved mine plans for the Belina and Skyline mines,
400 ● An Assessment of Development and Production Potential of Federal Coal Leases

\
App. A—Development and Production of Federal Coal Leases in the Southern Rocky Mountain States “ 401

Figure A-5.— Federal Coal Leases, PRLA’s and New Lease Tracts in the

Emery Coai Fieid, Utah

TO PRICE

T“o

,

\ . .

‘. I

\ I

..\;d - - \

, .

/‘

\A

c

%

@.f

i

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1 [/ /

.

“-”-” \ \ Coastal States ‘. f.+ . I I

.-

- SUFCO

— ~ [..> I II Link Flat I

, 1 a

a

1>1

1 m a

8 1 , n

1 lx 1

1 1 r

r

11

o New lease tract (1981 sale)

SOURCE U.S. Department of the Interior, Bureau of Land Management, Uinta-Southwestern Utah Final Coal Environrnental

Impact Statement, February 1981.
402 ● An Assessment of Development and Production Potential of Federal Coal Leases

also eight proposed new mines in the Uinta region

with 14 leases that are in pending mine plans. *

These leases cover 25,711 acres and contain about

264 million tons of recoverable reserves. The proposed new mines have a total annual capacity of

over 13 million tons per year.

The remaining 44 leases in central Utah are

undeveloped. These leases cover 47,679 acres and

more than 447 million tons of reserves. When the

contiguous leases held by the same owners are

grouped together into minable blocks, the undeveloped leases in central Utah form 20 lease

blocks with 12 blocks each composed of only 1

lease.

The active mines in central Utah range from a

few small underground operations producing less

than 100,000 tons per year to new large mines producing over 1 million tons per year. Several mines

are in the process of expanding their production

capacities to produce up to 5 million tons per year

or more by 1985, The 14 approved mining operations on Federal leases in central Utah are all underground mines and all, but the newly approved

Skyline Mine, were producing in 1980, In 1980,

over 8.7 million tons of production from Federal

leases were reported to USGS for royalty purposes.

By 1986, production from operations with approved mine permits is projected to reach 24

million tons, more than double the 1979 production levels. By 1991, production from these mines

could rise to 29 million tons. One small operation,

the Trail Mountain Mine is expected to be depleted by 1991 unless it acquires additional reserves to maintain production. Both U.S. Steel’s

Geneva Mine and Kaiser Steel’s Sunnyside Mine

are expected to be nearing the limit of their economically recoverable reserves by the late 1980’s

and would then begin to shift production to new

mines on their other Federal leaseholdings. OTA’s

mine plan review indicates that about 5 million of

the 32.2 million tons of capacity on approved

mine plans might not be constructed as planned

because of changes in the lessee’s captive coal

needs out-of-State.

Six of the operating mines are captive operations, including two mines operated by steel

companies, two complexes run by Utah Power &

Light, the Soldier Canyon Mine run by California

Portland Cement, and the Braztah Mine complex

“These leases include two leases that are partially included in two

different mines: the newly approved Skyline Mine and the adjacent

Belina and O'Connor mines which are dissected by several fault zones

and the lessees executed operating agreements to mine those portions of

the leases on their respective sides of the fault.

held by a subsidiary of American Electric Power

(AEP) and supplying AEP powerplants in Indiana.

Total production for these mines in 1979 was 6.1

million tons—over half the total production in the

State. By 1986 captive production from Federal

mines is expected to total about 13 million tons

making a slight decline in its share of total State

production. The captive segment of the Utah coal

industry is expected to maintain it’s position in

the 1980’s and 1990’s since a significant amount

of production from new mines on Federal leases

would supply captive markets.

Pending Mine Plans.—The eight proposed new

mines on Federal leases would, if all were developed as scheduled, add more than 13 million tons

of annual production capacity in central Utah by

1990. One new mine, Eureka Energy’s 3.2 million

tons per year Sage Point-Dugout Canyon Mine, is

intended to supply a new 1,600-MW coal-fired

powerplant to be built by its parent Pacific Gas

and Electric Co. U.S. Steel’s new B Canyon Mine

would replace the existing Geneva Mine when

that operation reaches the limits of its economically minable reserves. Mountain States Resources’ Ute Nos. l&2 mines near Emery would

include both underground and surface operations.

Several of the proposed new mines have been in

planning stages for 5 years or more, however,

mine permitting and construction activities have

been deferred by the lessees because of soft market conditions and slower than expected electricity demand growth.

If all the proposed new mines meet their

planned production schedules, six of the eight

mines will be operating by 1986 with an estimated

total production of 5.6 million tons. By 1991, all

eight mines could be producing a total of 11.3 million tons according to the mine plan estimates.

However, because at least two of the new mines

are captive operations, their construction and production schedules are dependent on the needs of

their parent companies. Current indications are

that the Sage Point-Dugout Canyon Mine and the

B Canyon Mine could be deferred several years,

thus making about 4.2 million tons of 1991 production capacity somewhat uncertain.

Undeveloped Leases.—The 44 leases in central

Utah without mine plans cover 47,679 acres and

contain 447 million tons of recoverable reserves.

These leases are 57.9 percent of the undeveloped

leases, 42 percent of the undeveloped lease acres

and 37 percent of the undeveloped Federal lease

reserves in the State of Utah. The 44 undeveloped

leases in the Uinta region are divided into 20 lease

blocks ranging in size from 80 acres to more
App. A—Development and Production of Federal Coal Leases in the Southern Rocky Mountain States ● 403

18,000 acres. Most of the reserves are underground minable only—however, one tract contains some surface recoverable reserves. About six

of these lease blocks have supported some mining

activities in the past. All of the undeveloped lease

reserves in central Utah are bituminous with heat

value of 11,000 Btu/lb or more, sulfur contents of

1.5 percent or less, and ash contents of 15 percent

or less.

Eight undeveloped lease blocks with 30 leases

have enough good quality minable reserves to sustain a new average-size mine of 500,000 tons per

year with a 30-year mine life. These 30 leases contain a total of 417 million tons of recoverable

reserves. The remaining 14 leases in 12 blocks did

not have enough reserves for a new large mine. At

least three of these blocks (six leases) have adequate reserves for a small mine, however. Two of

the three blocks have been mined previously and

probably would not be reopened because construction and safety costs would be prohibitive,

Four undeveloped leases without enough reserves

for a new independent mine are adjacent to active

or proposed operation and could possibly be

added to those mines through assignments or

operating agreements,

After reviewing the quality and amount of reserves, the mining conditions, transportation

availability and the expected market conditions

over the next decade, OTA classified as favorable

development prospects the eight lease blocks with

adequate reserves to support new mines, These

eight blocks with a total of 30 leases and 417 million tons of reserves have almost 95 percent of the

undeveloped lease reserves in central Utah. Three

one-lease blocks were rated as uncertain development prospects depending on the availability of

additional reserves. The remaining 11 leases in

nine lease blocks have unfavorable prospects for

development.

The eight blocks with favorable prospects include two large tracts with a total of eight leases

held by Kaiser Steel in the Book Cliffs Field and

one very large block of eight leases in the Emery

Field with more than 18,000 acres jointly held by

Consolidation Coal Co. and Kemmerer Coal Co.

Two other favorable blocks are held by companies

with active mines on Federal leases: one lease

block held by a subsidiary of ARCO, Beaver Creek

Coal Co. (successor to Swisher Coal Co.), and a

three lease block held by Energy Reserves Group,

Inc., adjacent to its proposed Skumpah Canyon

operation,

Three more blocks with favorable development

prospects are located in a single township near

two proposed Uinta new lease sale tracts and

several active mines on existing leases. * These

blocks include: one tract of five leases in Rilda

Canyon owned by Utah Power & Light near its

Deer Creek-Wilberg Mine; a two-lease block controlled by Nevada Electric Investment Co, adjacent to the Hiawatha Mine complex; and another

block that was originally a single lease and was

recently segregated into two leases, one assigned

to Northwest Carbon Corp. and the other to COP

Coal Development.

Development plans for four of the eight favorable blocks are known based on company interviews. Kaiser Steel plans to develop the two-lease

Sunnyside North tract which has metallurgical

coal reserves as replacement capacity for the existing Sunnyside Mine when it reaches the economic limits of its minable reserves. The block is

not contiguous to the existing mine. The six-lease

Sunnyside South block with lower quality, metallurgical-grade reserves could be mined for steam

coal. Consolidation Coal, which already has one

proposed mine on Federal leases in the Emery

Field, plans to combine surface and underground

mining operations in developing its remaining

eight leases near Interstate 70 in Emery County,

Utah Power & Light is expected to mine its five

undeveloped leases as either a new mine or as an

expansion of the Deer Creek-Wilberg Mine. Utah

Power & Light is also actively seeking the Meetinghouse Canyon and Rilda Canyon new lease

tracts adjacent to these lease blocks to supply its

coal-fired powerplants.

The two blocks held by Beaver Creek Coal Co.

and Energy Reserves Group will probably be

mined when those companies shift operations

from existing mines as they are depleted. Production plans for the two remaining blocks are unknown, however, it is expected that they will be

developed since all three lessees involved own additional reserves in the same area and one lessee,

Nevada Electric, is a major consumer of Utah

coal.

The total estimated capacity that could be supported by the favorable lease blocks is 12 million

tons per year, By 1986, none of the leases are expected to be producing, However, by 1991, the

‘All of these blocks have been acquirwi h~ the (,urrrrlt Icssm; within

the []ast 2 years, onc hlock of fite Icas(!+ was rm;[,ntl~ a{ {Iuirt,(i })}, IJlah

Power & I,]ght (;orp. I rom P{,ill)()(j} (;oi]l (;(), Another I)lo(:k of leas(,s

was segregated and lmrt was ,]cqulrrd hy hlorthuwst Carhon (;orp. The

r(:malndrr \\,as assigned to COP Coal Development and i]noth(.r l)lo(:k

m’as acquired h} (;O1] Coal I)t:\,[;iol)l?][~t~t (~orp trorn Pcaho(i},. A not hrr

hlo( k is held h) the IN(N ada E:Ic( t ri( I n~ mtment. a suhs)diary of Nma(]a

Po~flr Co.
404 ● An Assessment of Development and Production Potential of Federal Coal Leases

leases could produce between 7,0 million and 8.6

million tons.

No production is estimated for the three leases

with uncertain development prospects or for the

11 leases with unfavorable development prospects

since these leases are not likely to be producing

during the next 10 years unless they are combined

with other reserves controlled by the lessee or

mined as part of an adjoining operation, Two of

the uncertain leases and four of the leases with unfavorable prospects are adjacent to or contiguous

with existing or proposed mines.

Some of the major concerns involving coal development in central Utah are: potential impacts

on water availability and water quality such as the

interruption of springs due to subsidence, interception of aquifers during mining operations,

discharges into streams, increased sediment load,

and leaching of salts, trace elements, and heavy

metals from strata disturbed during mining. Other

concerns include: losses in wildlife habitat from

expansion of the areas disturbed by mining; impairment of air quality; and population increases

from mine development resulting in concentration of socioeconomic impacts in the Price-Helper

area. These issues are addressed more fully in the

environmental impact statements on central Utah

coal development and the recently completed

final environmental impact statement for the

Uinta coal lease sales.

One area that could have substantial impacts

from new mining on Federal leases is the Emery

Field. The coal leases belonging to Consolidation

and Kemmerer Coal companies are bisected by Interstate 70-a major tourist route, However, because the area would most likely be underground

mined and the coal reserves in the vicinity of I-70

are of poorer quality, it is unlikely that any mining

would be done near the highway. The Emery area

is just west of the San Rafael Swell—a scenic area

of geologic interest—and expansion of mining activities could contribute to increases in airborn

particulate and to reduced visibility, especially

during dry spells. The Emery Field is not currently served by rail transportation so existing mines

truck coal to loadout facilities near Price. The proposed Castle Valley Railroad would extend along

the Wasatch Plateau to the Emery coalfield. Construction of the railroad is dependent on expanded mine production in that area.

Southwestern Utah

The Southwestern Utah coal region includes

the Alton, Kolob, Kaiparowits Plateau, and Henry

Mountains coalfields. The Henry Mountains Field

has no Federal leases, it does, however, have three

PRLAs. The southwestern Utah coalfields have

both underground and surface minable reserves,

however, underground reserves predominate.

There are no active mines in the region, although

there were several small mines operating on Federal leases that supplied coal to local markets.

Three new large mines have been proposed for the

Alton and Kaiparowits fields. Proposed mining

operations in the Alton Field have encountered

substantial opposition from environmentalists

because of its proximity to several major national

parks, the possible impacts on visibility and

ground water, and potential reclamation problems. Mining on the Kaiparowits Plateau has been

opposed because it would occur in one of the last

remaining undisturbed roadless areas in the

United States outside of Alaska, and also because

of potential air quality impacts.

There are 96 Federal leases in the Southwestern

Utah coal region covering over 150,000 acres and

1.75 billion tons of recoverable coal reserves. The

24 pending PRLAs in the region cover an additional 72,000 acres and over 1.0 billion tons of recoverable reserves. Three new large mines have

been preposed in southwestern Utah: The Alton

Mine with combined surface and underground

operations on 28 leases held by Nevada Power and

Utah International, Inc.; and two proposed underground mines on the Kaiparowits Plateau—El

Paso Energy Co.’s Red and Blue Mines and the

Kaiparowits Mine on leases held by resource

development subsidiaries of three Southwestern

utilities. These three proposed mines include 64 of

the existing leases

over 93,000 acres

reserves.

The remaining 32

and 743.5 million

in southern Utah and cover

and over 1 billion tons of

leases cover over 57,000 acres

tons of recoverable underground reserves. These undeveloped leases are divided into 11 lease blocks—seven single lease

blocks and four multilease blocks. Several of the

leases supported small mines in the past. Six lease

blocks with 27 of the leases are located in the Kaiparowits Plateau.

Pending Mine Plans.—The three mine plans proposed for southwestern Utah contain over 1 billion tons of recoverable reserves with about threequarters of the reserves underground minable.

The proposals include the Alton Surface Mine
App. A—Development and Production of Federal Coal Leases in the Southern Rocky Mountain States ● 405

and two underground mines on the Kaiparowits

Plateau. Total annual production capacity of the

proposed mines is 30 million tons. Estimated production in 1986 is about 600,000 tons. If all mine

plans were approved in the next decade, production in 1991 could be as much as 25.4 million tons.

All of these proposals face substantial uncertainties over whether and when they will go into production, All are located in remote areas that are

not currently active mining areas and which are

not served by rail transportation. All present potential environmental conflicts. All have substantial uncertainties over where the coal will be sold.

The Alton Mine located near the town of Alton,

just south of the Paunsaugunt Plateau and Bryce

Canyon National Park, is probably the best known

of the southern Utah mine proposals because of its

location and concern over its potential impacts on

the park (see fig. A-6). The Alton Mine is part of

the Allen-Warner Valley Energy Complex and is

the closest to development of any of the proposed

mines in southwest Utah because it has successfully obtained several necessary permit approvals

and, until recently, appeared to have a definite

consumer for its coal production. But, recent developments have clouded its future and the operator, Utah International, Inc., has deferred initial

production until at least 1986. The mine would

initially be a surface mine, but after about 20 years

of operation, would begin underground mining on

more deeply buried reserves.

In December 1980, Interior Secretary Andrus

issued his decision on the citizens’ petition to

declare Federal lands in the Alton coalfield unFigure A-6.– Federal Coal Leases in Southwestern Utah

i

7

Mt. Carmel JI

Escalante

Rubys Inn

/

Paunsaugunt PIateau

Dixie National

Kodachrome

[ I

— I

3

1 — I

21/2

2

Zion Nat’1 Park

Consolidation lease

37 block

/

Arizona

SOURCE US Department of the Interior, Bureau of Land Management, Uinta-Southwestern Utah Final Coal Environrnental Impact Statement, February 1981.
406 . An Assessment of Development and Production Potential of Federal Coal Leases

suitable for mining under the Surface Mining

Control and Reclamation Act of 1977 (SMCRA).

This was the first section 522 unsuitability petition accepted. Secretary Andrus declared Federal

lands adjacent to Bryce Canyon National Park as

unsuitable for surface mining and the surface effects of underground mining. The decision affected about 9,049 acres on the eastern side of the

Alton Field out of the more than 26,000 acres leased by Utah International and Nevada Power. As a

result of the decision, about 24 million tons of the

more than 290 million tons under lease would not

be minable. The decision cited the potential

adverse impacts on the park from blasting, heavy

truck traffic, air quality degradation, and noise

from the mining operations which would have extended to within 5 miles of the Yovimpa Point

lookout in Bryce Canyon Park. The original petition had requested that Andrus declare a total of

325,000 acres (240,000 acres of Federal land) as

unsuitable for mining. The lessees have filed suit

in Federal District Court in Salt Lake City challenging the adequacy of the technical information

supporting the decision and alleging that the

Alton leases should be exempt from the unsuitability provisions because of substantial legal and

financial commitments to development made

before passage of the act.

In Feburary 1981, two of the partners in the

Allen-Warner Valley Power project, Southern

California Edison and Pacific Gas & Electric,

withdrew their applications for participation in

the project from consideration by the California

Public Utility Commission. The decision was, in

part, based on the decisions by the Secretary of Interior and EPA to approve permits for construction of one portion of the project, the Harry Allen

plant in Nevada, and to withhold approval of the

smaller Warner Valley Plant in Utah pending additional study. Southern California Edison also attributed its decision to a shift in company policy

to the use of renewable energy sources. Substantial questions thus still remain over construction

of the two plants and of the proposed slurry line

from the Alton Mine to the powerplants.

The Alton lessees have submitted an informal

mine plan proposal for use in environmental analyses. The lessees have reportedly deferred submittal of a final plan until after the Alton unsuitability

decision was made. The proposed mine would

produce up to 11.2 million tons of coal annually.

The impact of the unsuitability petition on development is still unclear—about 10 percent of the reserves were withdrawn from production. Should

the decision stand, the lessees are expected to seek

an exchange of the affected leases for other comparable Federal coal lands in the area. Interior

had previously indicated it would give prompt attention to such a request.

Two mine plans have also been submitted for

underground mines on the Kaiparowits Plateau.

El Paso Energy proposes to open a large underground mine complex on its 40,00()-acre” lease

tract. The first two mines, the Red and Blue

Mines, would produce a total of about 1.1 million

tons per year. El Paso plans to expand production

on the plateau in other reserve areas to reach an

eventual annual capacity of 6.8 million tons per

year.

The Kaiparowits Nos. 1-5 complex is proposed

by a consortium of three resource development

subsidiaries of electric utilities: Mono Power, a

subsidiary of Southern California Edison; Resources Co., a subsidiary of Arizona Public Service Co.; and New Albion Resources Co., a subsidiary of San Diego Gas & Electric Co. These leases

are located on the southern portion of the plateau

just south of the El Paso leases. The lessees plan to

open several underground mines on the jointly

held lease tract of over 47,000 acres which would

eventually produce 12 million tons per year. The

leases were originally acquired as PRLAs and

were intended to supply electric utilities in the

Southwest or, possibly, a powerplant near the

mine area. Because of concerns about impacts on

the region’s air quality and water supply, powerplant construction at or near the mine complex to

serve out-of-State consumers is now considered

unlikely.

Development of the two planned mines on the

Kaiparowits Plateau is uncertain. Both mine plans

were submitted before the implementation of

SMCRA and have not been updated to reflect the

current mine plan requirements. The major uncertainties affecting their development are lack of

transportation to move coal to market and lack of

any definite market for the production. Estimates

by the Union Pacific Railroad are that a minimum

production of 30 million tons per year would be

necessary to offset the costs of construction of a

rail line to the plateau. The two proposed mines

would produce 18.8 million tons at full capacity—

just over 60 percent of the minimum required production. It is very uncertain whether a market for

the required 30 million tons or more of Kaiparowits coal will materialize over the next decade. An

additional factor that affects the development of

these mines is the remote location and the need to

provide a supporting infrastructure for mine development. The nearby communities are few,
App. A—Development and Production of Federal Coal Leases in the Southern Rocky Mountain States . 407

—-—

small, and far between, Mine construction would

bring an increase in population and greater demand for services such as roads, utilities, water,

and housing to serve the mine employees. These

requirements could put southwestern Utah development at a disadvantage when compared to

other established mining areas.

Undeveloped Leases.—There are 32 undeveloped leases in southwestern Utah. These leases

cover 57,537 acres and 744 million tons of recoverable underground reserves. The leases are divided into 11 lease blocks, 7 of these are single

lease blocks ranging in size from 40 to 1,440 acres.

There are four multilease blocks ranging in size

from 6,400 acres to more than 25,500 acres, Six of

the lease blocks are located on the Kaiparowits

Plateau, and the five others are small leases that

are scattered across the region. Four of the five

small lease blocks have previously operated as

small mines but were shut down in the 1950’s and

1960’s as local markets diminished.

In reviewing the development potential of these

lease blocks, OTA found that four of the six tracts

on the Kaiparowits Plateau each had sufficient

reserves of good quality coal that could support independent mining operations. These four blocks

include two separate tracts held by Peabody Coal

Co., one large tract on the northern portion of the

Plateau held by Consolidation Coal Co., and a

three-lease tract held by Hiko Bell Oil & Mining

Co. on the southern edge of the plateau near the

Glen Canyon Recreation Area withdrawal. Two

tracts on the plateau did not meet the minimum

quality and reserve requirements for new mines.

One block held by El Paso has difficult mining

conditions relative to the lease configuration and

is separated from the company’s other leases in

the Red and Blue mine plan proposal, The other

block, a lease owned by an individual, is on the

southern portion of the plateau with generally

lower quality reserves and more difficult problems of access to the seams because of topography.

All of the leases on the Kaiparowits Plateau are

in an isolated, rugged area, not served by existing

transportation systems capable of moving coal to

market. Access for mine development is difficult

because of the steep, highly dissected cliff faces of

the plateau and the complex geology of the multiple coal seams. The area would require more exploratory and developmental drilling, and construction of roads, utility lines and other supporting services before substantial mining operations

could begin. The 25 leases in the four lease blocks

on the plateau that could support new mines were

thus rated as having uncertain development prospects. The two single lease tracts were classified

as unfavorable development prospects.

The five remaining small lease tracts in

Southwestern Utah were found to have unfavorable development prospects as new mines. They

generally did not have sufficient reserves to support a new large mining operation. Their locations made them potentially suitable to serve limited local markets only, The reserves on the small

tracts are also generally poorer quality coals. Two

leases located near Zion NationaI Park have some

potential environmental problems (wildlife and

water quality impacts) although they have been

mined in the past and are not located in highly

visible areas so they would not, as compared to

Alton, pose a visual intrusion onto the park areas.

An analysis of the production potential of the

four tracts on the Kaiparowits Plateau with uncertain development prospects indicated that they

could support a total annual production of 7 million to 16 million tons depending on the choice of

mining technologies and mine life. This calculation was made on the basis of available information on the reserves, geology, topography and possible mining conditions that could be encountered. Full production capacity is expected to be

attained in 3 to 6 years from initial commercial

production. At a minimum, because of the time

needed for mine plan development and other construction, it was estimated that 1987 is the earliest

date that production could begin on the plateau.

This date assumes 2 years for mine plan submittal,

another 2 years for approval of the mine plan and

other permits, and about 2 to 3 years of preliminary mine development and construction. It is not

known how long it would take to construct the required railroad or supporting community infrastructure. If the potential 7 million to 16 million

tons annual production capacity from the undeveloped leases is added to the 18 million tons of

production proposed from the Kaiparowits and El

Paso mine complexes, the annual regional production approaches the range required to support

construction of the rail line. It was suggested in

the regional environmental impact statement for

Southwestern Utah that initial production from

mines could be trucked to Page, Ariz., and used

for power generation there—however, that appears an unlikely alternative at present. It is

becoming clear, however, that development of existing Federal leases on the Kaiparowits Plateau is

very much an all or nothing proposition.
OTA

APPENDIX B

Working Lease List

and Lessee Index

1. OTA working Lease List

Federal Mines and Undeveloped Lease Blocks

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...............409

Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 416

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........419

North Dakota... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............421

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................423

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............426

Wyoming . . . . . . . . . . . . 0 . . . . . . . . . . . . . . . . . . ...............434

II. Lessee Index

A. Leaseholding Subsidiaries: Key for Locating Parent Companies. ....440

B. Federal Coal Lessees: Leaseholdings by Parent Company for

the Seven Western Coal States Studied by OTA.. . ..............442
App. B—OTA Working Lease List and Lessee Index “ 409

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— —

.

LEASEHOLDING SUBSIDIARY

Amax Coal Co.

Amca Coal Leasing, Inc.

Anchor Coal Co.

Ark Land Co.

Beaver Creek Coal Co.

Belden Enterprises

Big Horn Coal Co.

Bridger Coal Co.

Black Butte Coal Co.

Cambridge Coal Co.

The Carter Mining Co.

CF&I Steel Co.

Coastal States Energy Co.

Colorado Westmoreland Co.

Colowyo Coal Co.

Conotton Land Co.

Consolidation Coal Co.

Coteau Properties, Inc.

Cumberland Coal Co.

Eastern Associated Properties Corp.

El Paso Energy Resources Co.

El Paso Natural Gas Co.

Empire Energy Corp.

Energy Development Co.

Energy Fuels Co.

Eureka Energy Co.

Evans coal coo

Falkirk Mining Co.

Fannin Square Corp.

Franklin Real Estate Co.

Freeman United Coal Mining Co.

GEX Colorado

Kanawha & Hocking Coal

& Coke Co.

Kemmerer Coal Co.

Kerr Coal Co.

Kerr-McGee Coal Corp.

Knife River Coal Mining Co.

Lone Star Steel Co.

Materials Service Co.

Medicine Bow Coal Co.

Midcontinent Limestone Co.

Mining Systems Corps.

Mono Power Co.

LISTED UNDER PERENT

Amax, Inc.

Amca Resources

St. Joe Minerals Corp.

Ashland Oil & Hunt Interests

Atlantic-Richfleld Co.

Eastern Gas & Fuel Assoc.

(50 percent)

Peter Kiewit Sons, Inc.

Idaho Power Co.

(33.3 percent)

Peter Kiewit Sons, Inc.

(50 percent)

General Exploration, Inc.

Exxon Corp.

Crane Co.

The Coastal Corp.

Westmoreland Coal Co.

Hanna Mining Corp.

(50 percent)

Cravat Coal Co.

Conoco, Inc.

North American Coal Co.

Peter Kiewit Sons, Inc.

(50 percent)

Eastern Gas & Fuel Assoc.

The El Paso Co.

The El Paso Co.

Standard Oil of Indiana Co.

Iowa Public Service Co.

Getty oil co.

Pacific Gas & Electric Co.

Armco Steel Corp.

North American Coal Corp.

Texas Eastern Transmission

Corp.

American Electric Power Co.

General Dynamics Corp.

General Exploration, Inc.

Quaker State Oil

Refining Co.

Gulf Oil Corp.

Getty oil Corp.

Kerr-McGee Corp.

Montana-Dakota Utilities

Northwest Industries, Inc.

General Dynamics Corp.

Ashland Oil & Hunt

Interests (50 percent)

Midcontinent Resources, Inc.

Standard Equipment, Inc.

Southern California

Edison Co.

JOINTLY OWNED BY:

. -

- -

- -

NICOR, Inc.

(50 percent)

- -

Pacific Power & Light Co.

(66.6 percent)

Union Pacific Corp.

(50 percent)

- -

- -

—

- -

W.R. Grace & Co.

(50 percent)

- -

- -

Union Pacific Corp .

(50 percent )

- -

—

- -

- -

- -

- -

- -

- -

- -

- -

- -

- -

- -

—

- -

- -

- -

- -

Union Pacific Corp .

(50 percent)

—

- -

- -
Nevada Electric Investment

New Albion Resources Co.

North Antelope Coal Co.

co.

Northern Minerals Corp.

Northwest Carbon Co.

Northwestern Resources Co.

Peabody Coal Co.

Plateau Mining Co.

Resource Development Co.

Resources Co.

Rosebud Coal Sales

Sheridan Enterprises, Inc.

Spring Creek Coal Co.

Stansbury Coal Co.

Sunland Mining Corp.

Sunoco Energy Development Co.

Sweetwater Resources, Inc.

Thunder Basin Coal Co.

U.S. Fuel Co.

Utah International, Inc.

Western Coal Co.

Western Energy Co.

Western Nuclear, Inc.

Western Slope Carbon, Inc.

Wyodak Resources Development Co.

Wyoming Fuels Co.

App. B—OTA Working Lease List and Lessee Index . 441

Nevada Power Co.

San Diego Gas & Electric Co.

Panhandle Eastern Pipeline

Co. (50 percent)

Internorth Corp.

Northwest Energy Corp.

Montana Power Co.

Peabody Holding Co.

Getty Oil co.

Pacific Power & Light Co.

Arizona Public Service Co.

Peter Kiewit Sons, Inc.

Occidental Petroleum Corp.

Pacific Power & Light Co.

Ideal Basic Industries

(50 percent)

Consolidated Gas & Oil Corp.

The Sun Co.

Monsanto Co.

Atlantic-Richfield Co.

Sharon Steel Corp.

General Electric Co.

Public Service Co. of

New Mexico

(50 percent)

Montana Power Co.

Phelps Dodge Corp.

Northwest Energy Corp.

Black Hills Power & Light Co.

Kansas Nebraska Natural

Gas Co.

- -

Peabody Holding Co.

(50 percent)

- -

- -

—

- -

- -

- -

- -

- -

Union Pacific Corp.

(50 percent)

--

- -

- -

—

. -

- -

Tuscon Electric Co.

(50 percent)

- -

- -

- -

- -
442 ● An Assessment of Development and Production Potential of Federal Coal Leases

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APPENDIX C

Acronyms, Abbreviations, and Glossary

Acronymns and Abbreviations

AAR

ABS

ACLDS

AMC

AQCR

AQS

AVF

BACT

BIA

BLM

BN

bt

CBO

CEUM

CFR

CNW

CSMRI

CTC

DEIS

DOE

DOI

DRI

DSL

EA

EDF

EGR

EIA

EIS

EMARS

EPA

E.R.C.

ERCOT

ETSI

F.2d

FCLAA

FEIS

FERC

FLPMA

— Association of American Railroads

—Automated Block Signals

— Automated Coal Lease Data System

— American Mining Congress

— air quality control region

— air quality standards

— alluvial valley floor

–best available control technology

— Bureau of Indian Affairs

— Bureau of Land Management

— Burlington Northern Railroad

—billion tons

—Congressional Budget Office

–Coal Electric Utility Model

(Forecasts)

— Code of Federal Regulations

–Chicago and Northwestern Railroad

—Colorado School of Mines Research

Institute

—Centralized Traffic Control

— draft environmental impact

statement

— Department of Energy

— Department of the Interior

— Data Resources, Inc.

— Department of State Lands

(Montana)

— environmental assessment

— Environmental Defense Fund

— electric growth rate

— Energy information Administration

— environmental impact statement

— Energy Minerals Activity

Recommendation System

— Environmental Protection Agency

— Environmental Reporter Cases

— Energy Reliability Council of Texas

— Energy Transportation Systems Inc.

— Federal Reporter, Second Series

— Federal Coal Leasing Amendments

Act of 1976

— final environmental impact

statement

— Federal Energy Regulatory

Commission

— Federal Land Policy and

Management Act of 1976

F.R.

F. Supp.

FWS

GAO

GMO

GPO

ICC

KRCRA

LMU

MARCA

MER

mt

mty

NAAQS

NCA

NERC

NEPA

NETS

NSPS

OSM

OTA

PILT

PKS

PPL

PRB

PSD

PRLA

SERI

SID

SIP

SMCRA

SPP

— Federal Register

— Federal Supplement

— Fish and Wildlife Service

— General Accounting Office

—General Mining Order

—Government Printing Office

— Interstate Commerce Commission

— known recoverable coal resource

area

—logical mining unit

– Mid-Continent Area Reliability

Coordination Agreement

— maximum economic recovery

— million tons

— million tons per year

— National Ambient Air Quality

Standards

— National Coal Association

– National Electric Reliability

Council

— National Environmental Policy Act

of 1969

— National Energy Transportation

System

— new source performance standards

— Office of Surface Mining

— Office of Technology Assessment

— payment in lieu of taxes

— Peter Kiewit Sons, Inc.

— Pacific Power & Light Co.

— Powder River basin

— prevention of significant

deterioration

— preference right lease application

— Solar Energy Research Institute

— Secretarial Issue Document

— State implementation plan

– Surface Mining Control and

Reclamation Act of 1977

— Southwest Power Pool

SunEDCO – Sun Energy Development Co,

TSP — total suspended particulate

UP — Union Pacific Railroad

U.S.C. — United States Code

USGS — U.S. Geological Survey

WSCC — Western Systems Coordination

Council
App. C—Acronyms, Abbreviations, and Glossary . 467

Glossary

Acre Foot: A measure of water 1 ft deep by 1 acre

in area, or 43,560 cubic feet.

Alluvial Valley Floor: Those stream valleys

located west of the l00th Meridian which: 1)

are underlain by unconsolidated gravel, sand,

silt, and clay; 2) have a stream flowing

through them; 3) have a generally flat valley

floor topographic surface; and 4) have an agricultural importance. The relative importance

of these valleys is a function of the water supplies available in the specific valley area. The

agricultural activities generally include irrigated or subirrigated hay lands, developed

pasture lands, critically important grazing

areas, or lands that could be developed for any

of these purposes.

Approximate Original Contour: The surface configuration achieved by backfilling and grading

the mined area so that the reclaimed area, including any terracing or access roads, closely

resembles the general surface configuration of

the land prior to mining and blends into and

complements the drainage pattern of the surrounding terrain, with all highwalls and spoil

piles eliminated.

Aquifer: A subsurface zone that yields economically important amounts of water to wells; a

water-bearing stratum or permeable rock,

sand, or gravel.

Area Strip Mining: A mining technique characterized by the use of a power shovel, dragline,

or bucket wheel excavator for removing overburden. This type of mining first proceeds by

constructing a trench or box cut in the overburden to uncover the initial strip of coal that

is to be mined. After the coal has been removed from the bottom of the box cut, the

“spoil” or overburden material covering the

next strip of coal is removed and placed in the

void left by the mining of the preceding strip

of coal. Mining proceeds with succeeding

operations until the limits of the mining area

are reached.

Automated Coal Lease Data Systems (ACLDS): A

computerized information system maintained

by the Bureau of Land Management of the Department of the Interior for Federal coal

leases and lease applications. ACLDS contains a wide variety of technical and administrative information on every lease and preference right lease application.

Best Available Control Technology (BACT): 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.

British Thermal Unit (Btu): The quantity of heat

energy required to raise the temperature of 1

lb of water 1° F at, or near, its point of maximum density (39.1° F).

Continuous Miner: A machine with rotating cutting bits used in underground mining to cut

relatively soft coal from the coal face. The

coal is removed by breaking the coal from the

face and then transferring it to loading machines.

Continuous Operation: Requirement that a Federal lease must produce at least an annual

average of one percent of logical mining unit

reserves after diligent development has been

achieved.

Conventional Mining: An underground mining

technique in which specialized machines are

used in sequence to perform individual mining operations. The mining face is first undercut with a cutting machine resembling a chain

saw. A drill is then used to bore holes into the

face at an appropriate spacing; the holes are

then filled with an explosive. After blasting,

the coal is fragmented and allowed to drop on

the floor of the mine in front of a new face.

The coal is removed, the roof is bolted for

support, and the mining sequence is repeated.

Conventional mining accounts for 35 to 40

percent of underground mining in the united

States.

"De novo” Leasing: The original issuance of a

lease or prospecting permit by the Federal

Government.

Development Potential: An assessment of the

prospects for a lease or lease block being developed and mined within the next decade,

taking into consideration the reserves, mining

conditions, geographic location, status of adjacent properties, surface resource values, environmental impacts, potential markets, transportation availability and community infrastructure. Three development classifications

were used by OTA in this report:

●

●

Favorable-development potential—The lease

or lease block has favorable development

characteristics overall; the lease(s) meet the

threshold criteria for a viable mining property; there are no major technical or permitting problems or uncertainties associated

with the lease development.

Uncertain development potential—The lease
468 ● An Assessment of Development and Production Potential of Federal Coal Leases

or lease block has uncertain development

potential because development is contingent on factors such as transportation availability or synfuels development or because

of lack of information about the lessee’s development intentions, Property characteristics can be good or marginal.

● Unfavorable development potential—The

lease or lease block has unfavorable development potential, generally because it has

one or more of the following property characteristics: small reserves, difficult mining

or reclamation conditions, poor quality

coal, or isolated location.

Diligent Development: As used in this report, diligent development generally refers to the requirement in the Mineral Leasing Act that all

lessees must make a reasonable effort to bring

the lease into production. The Department of

the Interior has issued regulations that define

diligent development for Federal coal leases

as actual production of commercial quantities

of coal from the lease or the logical mining

unit of which the lease is a part by June 1,

1986, or within 10 years after the lease is

issued, whichever is later. Under certain conditions, the period for meeting diligence can

be extended to June 1, 1991, for leases issued

before passage of the Federal Coal Leasing

Amendments Act of 1976.

Face: The solid unbroken surface of the coal seam

exposed at the advancing end of the working

place.

Federal Coal Lease: A lease issued under the

Mineral Leasing Act of 1920 which grants the

exclusive right to mine Federal coal subject to

conditions set in the act, the lease, and applicable State and Federal laws and regulations.

Federal Coal Reserves: Coal reserves owned by

the United States,

Federal Lands: Lands or interests in land, including subsurface mineral rights, that are

owned by the United States, regardless of how

ownership was acquired.

Federal Mine: A mine that includes a Federal coal

lease in its mine area.

Grading: The leveling or elevation of land to a relatively smooth horizontal or sloping surface.

Lease Assignment: The sale or transfer of a lease

or a partial interest in a lease from the current

lessee to another.

Lease Block: A single lease or a group of two or

more contiguous leases owned or controlled

by the same lessee(s) or operator.

Lease Segregation: The division of an existing

lease into two or more parcels at the request of

the lessee. A new lease is then issued for each

new parcel and the surviving lease is modified

to reflect the reduced acreage, Lease segregation requires the approval of the Department

of the Interior. Segregation is frequently used

as a form of partial assignment.

Longwall Mining: An underground mining system that consists of a set of roof supports or

“jacks” that are located parallel to the mining

face, a conveyor system that runs along the

base of the face, and a cutting mechanism that

moves back and forth along the face cutting

the coal out of the face and dumping it on the

face conveyor for transport out of the mine. In

a longwall system, parallel entries (typically

from 300 to 600 ft apart are driven into the

coal seam using continuous miners. Then an

interconnecting passage is made between the

entries. The exposed seam is then mined in

successive slices using the longwall system.

As the slices or panels are removed, the roof

support system is moved forward and the unsupported roof is allowed to collapse into the

mined-out area left behind.

Maximum Economic Recovery (MER): Requirement that all portions of the coal deposits

within a lease having an incremental cost of

recovery (including reclamation, safety, and

opportunity costs) less than or equal to the

market value of the coal, must be mined.

Mine Development: As used in this report, the

process of acquiring detailed geological, engineering, environmental, technical, and economic data for mine planning, construction,

and initial commercial operation,

Mine Plan: As used in this report a mine plan

refers to: 1) an operating plan for a mine with

Federal leases submitted to the U.S. Geological Survey (USGS) under the requirements of

the Mineral Leasing Act of 1920; or 2) a mining and reclamation plan for a mine with Federal leases submitted to the U.S. Office of Surface Mining (OSM) under the Surface Mining

Control and Reclamation Act of 1977. A mine

plan is a detailed description of the operator’s

proposed method, rate and sequence of mining, environmental protection measures, and

reclamation strategies. The mine plan must be

approved by USGS and OSM and appropriate

State agencies before mining can begin.

Mine Size: As used in this report: A small mine

produces 100,000 tons of coal per year or less;

a medium-sized mine produces between
App. C—Acronyms, Abbreviations, and Glossary ● 469

100,000 to 500,000 tons per year; a large mine

produces over 500,000 tons per year.

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.

Non-Federal Coal Reserves: Include private,

State, local government, and Indian coal reserves.

Open-Pit Mining: A system of surface mining

characterized by a series of benches, the

number of which increases as the mine is

deepened. These benches are each 40 to 50 ft

in height and allow excavation to hundreds or

thousands of feet.

Overburden: Earth, rock, or other consolidated or

unconsolidated material that overlies a commercially valuable mineral deposit, such as a

coal seam, especially those deposit which are

mined from the surface through open cuts.

Preference Right Lease: Noncompetitive coal

lease issued to the holder of a prospecting permit who discovers coal in commercial quantities on the land under permit.

Public Lands: Lands and interests in land owned

by the United States and administered by the

Secretary of the Interior through the Bureau

of Land Management without regard as to

how the United States acquired ownership,

except lands located on the Outer Continental

Shelf and lands held for the benefit of Indians,

Aleuts, and Eskimos. Public lands are generally divided into public domain lands, which

have never left Federal ownership, and acquired lands, which are not in the public domain and which have been obtained by the

United States through purchase, condemnation, gift, or exchange.

Reclamation: Restoring mined lands to productive use; including replacement of topsoil, restoration of surface topography, and revegetation,

Recoverable Reserves: The amount of coal that

can be economically extracted from a coal deposit of known location, quantity, and quality

using currently available technologies. (See

ch. 4 of this report for additional discussion of

coal resource classifications.)

Recovery Rate: The percent of minable coal actually recovered. Typically 90 percent for a

Western surface mine and 40 to 50 percent for

an underground mine.

Room-and-Pillar Mining: An underground mining method in which coal is removed in a systematic pattern leaving behind mined-out

‘rooms’ and unmined coal ‘pillars’ to support

the overlying rock. The actual extraction of

coal in the room-and-pillar mine is accomplished with either conventional mining or

continuous miners.

Royalty: A payment, either on straight fee per ton

or as a percentage of the value of coal produced, to the owner of the resource for permitting another to mine and sell coal.

Severance Tax: A special levy, assessed at flat or

graduated rates, on the extraction of natural

resources.

Spoil: The overburden or material removed in

gaining access to the commercially recoverable coal deposit, also called waste.

Spoil Pile (or Bank): An area where spoil or overburden material is deposited before backfilling; that part of the mine where the coal and

other materials that are not marketable are

left,

Surface Subsidence: The settling or sinking of the

surface as a consequence of collapse of underlying strata because of underground mining.

Terrace Pit Mining: This method of surface

mining combines the area-strip and open-pit

mining techniques and is designed for the

thick coal beds of northwestern Wyoming and

southeastern Montana. The terrace pit mine

has a system of benches like the open pit mine.

However, there are more benches (six or

seven) than with open pit mining. Also, the

terrace pit mine, unlike the open pit mine,

does not remain in the same location but

rather moves across the property in a manner

similar to a strip mine. Overburden is removed from one side of the pit, hauled around

the pit ends, and dumped on the other side

where coal has already been mined.

Undeveloped Lease: A lease for which no mine

plan has been submitted,
APPENDIX D

Some Key References

Cannon, J. S., Leased and Lost: A Study of Public and Indian Coal Leasing in the West (New

York: Council on Economic Priorities, 1974).

Cannon, J. S., Leased and Lost 1975, Council on

Economic Priorities Newsletter N5-9 (New

York, Oct. 19, 1975).

Cannon, J, S., Leased and Lost, 1976, Council on

Economic Priorities Newsletter N6-8 (New

York, Sept. 13, 1976).

Cannon, J. S., Mine Control: Western Coal Leasing

and Development, Council on Economic Priorities (New York, 1978).

Colorado School of Mine Research Institute (for

OTA), SynfueIs Potential of Western Coal,

Draft Report (Washington, D. C., October

1980).

Colorado School of Mine Research Institute (for

OTA), Criteria for Determining Viable Mining

Properties on Existing Federal Coal Leases in

the Western United States (Washington, D. C.,

March 1980).

Council of Energy Resource Tribes, The Control

and Reclamation of Surface Mining on Indian

Lands (Washington, D, C,: CERT, Sept. 30,

1979 .

Department of Economic Planning and Development, 1975 Wyoming Mineral Yearbook (Cheyenne, Wyo. 1976).

Deurbrouck, A. W., Sulfur Reduction Potential of

Coals in the United States, RI 7633 (Washington, D. C.: U.S. Government Printing Office,

1972).

Energy and Environmental Analysis, Inc. (for

OTA), Feasibility of Using Coal Market Projections to Appraise Potential Production of Federal Coal Leaseholds (Washington, D, C., EEA,

Inc., 1981).

Federal Energy Regulatory Commission, Status of

Coal Supply Contracts for New Electric Generating Units 1979-1988, draft report, February

1981.

Glass, Gary B., Wyoming Coal Production and

Summary of Coal Contracts (Laramie, Wyo.:

The Geological Survey of Wyoming, 1980).

Hachman, F. (for OTA), Market Factors Associated

With the Assessment of the Development Potential of Federal Coal Leases in Utah (Washington, D. C., 1980).

ICF Inc., Analysis and Critique of the Department

of Energy’s August 7, 1980 Report Entitl1ed

—“Preliminary National and Regional Coal

Production Goals for 1985, 1990 and 1995, ”

ICF, Inc., Washington, D. C., October 1980.

ICF Inc. (for DOE), Final Report, Survey of United

States Coal Mine Expansion Plans (Washington, D. C.: ICF, Inc., August 1980.

ICF Inc., Forecasts and Sensitivity Analyses of

Western Coal Production (Washington, D. C.:

IFC, Inc., November 1980).

Martin, J. E, (for OTA), Market Factors and Production Contingencies Determining the Present

and Future Demand for Colorado Coal, draft

report (Lakewood, Colo.: Colorado Energy Research Institute, October 1980).

McMeans, G. B., The Economic Viability of Proposed West Coast Coal Port Sites (Oakland,

Calif.: Kaiser Engineers, Inc., 1981).

Mining Information Services, 1979 Keystone Coal

Industry Manual (New York: McGraw-Hill

Mining Publications, 1979).

Mining Information Services, 1980 Keystone Coal

Industry Manual (New York: McGraw-Hill

Publications, 1980).

Murray, F, X. (cd,), Where We Agree: Report of the

National Coal Policy Project (Boulder, Colo.:

Western press, 1978),

National Academy of Sciences, Rehabilitation Potential of Western Coal Lands: A Report to the

Energy Policy Project of the Ford Foundation

(Cambridge, Mass.: Ballinger Publishing Co,,

1974).

National Coal Association, NCA Long-Term Forecast (Washington, D. C.: NCA, 1981).

National Coal Association, Survey of Existing and

Proposed Synthetic Fuel Facilities (Washington, D. C,: NCA, September 1980).

National Research Council, Surface Mining: Soil,

Coal, and Society (Washington, D. C.: National

Academy Press, 1981).

Sebesta, J. J. (for OTA), Demand for Wyoming and

Montana Coal, 1980-1991, Based Upon the Projected Utility Coal Market (Washington, D. C.,

October 1980).

U.S. Department of Energy, Bituminous and Subbituminous Coal and Lignite Distribution

(Washington, D. C.: U.S. Government Printing

Office, April 1980).

U.S. Department of Energy, The 1980 Biennial Update of National and Regional Coal Production

Goals for 1985, 1990 and 1995, DOE/FE-0013

470
App. D—Some Key References ● 471

(Washington, D. C.: U.S. Government Printing

Office, March 1981).

U.S. Department of Energy, Western Coal Survey:

A Survey of Coal Mining Capacity in the West,

DOE/RA-O045-l (Washington, D. C.: U.S. Government Printing Office, January 1981).

U.S. Department of the Interior, Annual Report on

Coal (Washington, D. C.: U.S. Government

Printing Office, FY 1977).

U.S. Department of the Interior, Federal Coal

Management Report (Washington, D. C.: U.S.

Government Printing Office, FY 1978).

U.S. Department of the Interior, Federal Coal

Management Report (Washington, D. C.: U.S.

Government Printing Office, FY 1979).

U.S. Department of the Interior, Final Coal

Management Report (Washington, D. C.: U.S.

Government Printing Office, FY 1980).

U.S. Department of the Interior, Final Environmental Statement, Development of Coal Resources in Central Utah (Washington, D. C.:

U.S. Government Printing Office, 1979).

U.S. Department of the Interior, Final Environmental Statement, Development of Coal Resources in Southwestern Wyoming (Washington, D. C.: U.S. Government Printing Office,

1978).

U.S. Department of the Interior, Final Environmental Statement, Development of Coal Resources in Southern Utah, FES 79-21 (Washington, D, C,: U.S. Government Printing Office,

May 1979).

U.S. Department of the Interior, Final Environmental Statement, Federal Coal Management

Program, Stock No. 024-011 -00099-2 (Washington, D. C.: U.S. Government Printing Office, 1979).

U.S. Department of the Interior, Final Environmental Statement, Northern Powder River Basin Coal, Montana, FES 80-1 (Washington,

D. C.: U.S. Government Printing Office, January 1980).

U.S. Department of the Interior, Final Environmental Statement: Northwest Colorado Coal

(Washington, D. C.: U.S. Government Printing

Office, 1976].

U.S. Department of the Interior, Final Environmental Statement, Permanent Regulatory Program Implementing Section 501(b) of the Surface Mining Control and Reclamation Act of

1977, OSM-EIS-1 (Washington, D. C.: U.S.

Government Printing Office, January 1980).

U.S. Department of the Interior, Final Environmental Statement, Proposed Development of

Coal Resources in Eastern Powder River Wyoming (Washington, D. C.: U.S. Government

Printing Office, 1979).

U.S. Department of the Interior, Final Environmental Statement, Proposed Leasing, Carbon

Basin Area (Washington, D. C.: U.S. Government Printing Office, July 1979).

U.S. Department of the Interior, Final West-Central Colorado Coal Environmental Statement

(Washington, D, C.: U.S. Government Printing

Office, 1979).

U.S. Department of the Interior, Secretarial Issue

Document, Federal Coal Management Program, stock No. 0-295-110/6267 (Washington,

D, C.: U.S. Government Printing Office, 1979),

U.S. Department of the Interior, Final West-Central North Dakota Regional Environmental Impact Study on Energy Development (Washington, D. C.: U.S. Government Printing Office,

October 1978).

U.S. Department of the Interior, Final Environmental Impact Statement, Proposed Federal

Coal Management Program (Washington,

D, C.: U.S. Government Printing Office, September 1975).

U.S. Department of the Interior, Green RiverHams Fork Final Environmental Statement

(Washington, D. C.: U.S. Government Printing

Office, August 1980).

U.S. Department of the Interior, Uinta-Southwestern Utah Final Environmental Statement

(Washington, D. C.: U.S. Government Printing

Office, February 1981).

U.S. Department of the Interior, Southern Utah

Petition Evaluation Document, Final 522

SMCRA Evaluation OSM-PE-1 and Environmental Statement OSA4-EIS-4 (Washington,

D. C.: U.S. Government Printing Office,

November 1980).

U.S. Department of Justice, Competition in the

Coal Industry, stock No. 027-000 -00678-7

(Washington, D. C., U.S. Government Printing

Office, May 1978).

U.S. Department of Justice, Competition in the

Coal Industry, FY 1978, stock No. 027-000-

00790-2 (Washington, D, C.: U.S. Government

Printing Office, May 1979).

U.S. Department of Justice, Competition in the

Coal Industry, FY 1979 (Washington, D. C., November 1980).
472 ● An Assessment of Development and Production Potent/a/ of Federal Coal Leases

U.S. General Accounting Office, Issues Facing the

Future of Federal Coal Leasing, EMD 79-47

(Washington, D. C., June 25, 1979),

U.S. General Accounting Office, Innacurate Estimates of Western Coal Reserves Should Be Corrected, EMD 78-32 (Washington, D, C., July 11,

1978).

U.S. General Accounting Office, Mapping Problems May Undermine Plans for New Federal

Coal Leasing, EMD 81-30 (Washington, D. C.,

Dec. 12, 1980).

U.S. General Accounting Office, Improvements

Needed in Administration of Federal Coal Leasing Program, B-169124 (Washington, D. C.,

Mar. 19, 1972),

U.S. General Accounting Office, A Shortfall in

Leasing Coal From Federal Lands: What Effect

on National Energy Goals? EMD 80-87 (Washington, D. C., Aug. 22, 1980),

Wiener, Daniel P., Reclaiming the West: The Coal

Industry and Surface Mined Lands (New York:

INFORM, Inc., 1980),
APPENDIX E

Availability of OTA Working Papers

The following OTA staff and contractor papers

were used in the preparation of this report and

will be made available in early 1982 through the

National Technical Information Service:*

J, Russell Boulding and Deborah L. Pederson, Development and Production Potential of Undeveloped Federal Coal Leases and Preference

Right Lease Applications in the Powder River

Basin and Other Wyoming Coal Basins, Final

Report, November 1981.

Douglas W. Canete, Iris A. Goodman, and Deborah L. Pederson, Development and Production Potential of Existing Federal Coal Leases

in the Fort Union Region of North Dakota and

Montana, Final Report, December 1981.

James S. Cannon, Karen L. Larsen, and J. Stephen

Schindler, The Development Prospects for Federal Coal Leases in New Mexico, 1980-1991, Final Report, November 1981.

James S. Cannon and Cheryl A. Stevenson, Federal Coal Preference Right Lease Applications:

Their History, Ownership and Current Status,

Final Report, December 1981.

Colorado School of Mines Research Institute, Criteria for Determining Viable Mining Properties

“ Rw]ue\ts for thew reports shnuld be directed to National Te(.hnl( al Informa

tmn Service, U S Department nf Commerce, Sprtngfleld, \’A 22161

on Existing Federal Coal Leases in the Western

United States, Final Report, March 1980.

Dames & Moore, Analysis of Federal Coal Leases in

Mine Plans in Colorado, New Mexico, and

Utah, final draft report, December 1980.

Karen L. Larsen and Nancy Greenebaum, Review

of Undeveloped Federal Coal Leases in Utah:

Results of Utah Coal Leasing Task Force, Final

Report, May 1980. (Includes: Frank Hachman,

“Market Factors Associated With the Assessment of the Development Potential of Federal

Coal Leases in Utah, Draft Report” [University of Utah, Bureau of Economic and Business

Research), May 1980,)

Jack C, Schmidt, Sanna Porte, and Arnold J.

Silverman, A Review of Current Production

and Anticipated Future Production on Federal

Mines and Selected Undeveloped Lease Blocks

in Montana and Wyoming, Final Report (Geoservices West), December 1981.

Martin E. Zeller, Karen L. Larsen, Iris A. Goodman, The Development Prospects for Federal

Coal Leases in Colorado, 1980-1991, Final Report, November 1981. (Includes: Joan E. Martin for Colorado Energy Research Institute,

“Market Factors and Production Contingencies Determining the Present and Future Demand for Colorado Coal, ” final draft report,

December 1980.)

o

473