an assessment of development and production potential of ...sheridan enterprises, inc. archie carver...

An Assessment of Development andProduction 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 FederalCoal Leasing Amendments Act of 1976 (Public Law 94-377) “to conduct a com-plete study of coal leases entered into by the United States under section 2 of theact 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 ac-tivities, present and potential value of said coal leases, receipts of the FederalGovernment from said leases, and recommendations as to the feasibility of the useof deep mining technology in said leased area. “ “Present and potential value”have been defined as the amount of potential coal production from Federal leasesin 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 anestimation of the likely production from the existing 548 Federal coal leases in theseven major Western coal States. Although technical factors, mostly of a geologi-cal 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 inColorado, New Mexico, Oklahoma, Utah, and Wyoming. The task forces, com-posed of participants from State governments, local and Federal agencies, in-dustry, citizens groups, and local universities were of inestimable help to OTA inevaluating the development potential of undeveloped leases and in providing in-sights on the factors affecting coal development in these regions,

The estimates of potential production from Federal leases made in this reportare not forecasts of the coal that would be produced at a given price or a given de-mand. They are estimates of the total amount of coal that could be produced fromexisting and planned Federal mines and from those undeveloped Federal leasesthat have mining costs competitive with costs at currently operating mines in thesame area. If the demand for Federal coal does not increase to these levels of po-tential production, then not all the Federal leases that could technically and eco-nomically be developed will be mined.

We hope that this report will provide Congress with helpful insights for theimpending debates on Federal coal leasing and coal use goals for the UnitedStates.

‘Director

iii

Federal Coal Leasing Advisory Panel

Lynton K. Caldwell, ChairmanDepartment of Political Science, Indiana University

Jack Simon, Co-chairrnanDirector, Illinois State Geological Survey

James Boydprivate Consultant

C. Wayne CookDepartment of Range ScienceColorado State University

Lloyd ErnstManager of OperationsWestern Fuels Association, Inc.

Thomas FrancePrivate Consultant

Gerrie GreeneLegislative RepresentativeNational Association of Counties

James R. JonesDirector of Environmental QualityPeabody Coal Co.

Carla KishWestern Organization of Resource Councils

Robert Lang*Plant Sciences DivisionUniversity of Wyoming

Jonathan LashSenior Project AttorneyNatural Resources Defense Council, Inc.

Alfred Petrick, Jr.Petrick Associates

Daniel J. SnyderPresidentColorado-Westmoreland, Inc.

Gary Tabak* *Western Fuels Association, Inc.

Joseph YancikVice President, Research and Technical ServicesNational Coal Association

iv

Federal Coal Leasing Project Staff

Lionel S. Johns, Assistant Director, OTAEnergy, 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 MaterialsProgram wishes to acknowledge the assistance and cooperation of the following contractors and con-sultants in the collection and analysis of data.

Hope M. BabcockChristopher J. BiseLynda L. BrothersDouglas W. CaneteCartography, Inc.Colorado Energy Research InstituteColorado School of Mines Research InstituteDames & MooreEarth Satellite Corp.Energy and Environmental Analysis, Inc.Hoffman-Muntner Corp.Mel HorwitchVladumir J. HuckaThomas W. Hunter

Joan E. MartinSanna PortePowder River Basin Resource CouncilResource Consulting Group, Inc.James J. SebestaCurtis SeltzerArnold J. SilvermanCheryl A. StevensonThe Tosco FoundationU.S. Fish and Wildlife Service (WELUT)University of UtahUtah Geological and Mineralogical SurveyJohn D. WienerMartin 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 PhillipsAlbert 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 andorganizations:

American Mining CongressAssociation of American RailroadsColorado Department of Natural ResourcesMontana Bureau of Mines and GeologyMontana Department of State LandsNational Coal AssociationNew Mexico Energy and Minerals DepartmentNorth Dakota Geological SurveyNorth Dakota Public Services CommissionNorth Dakota State Department of HealthOklahoma Department of MinesOklahoma Geological SurveyPittsburgh Mining Technology Center

U.S. Department of EnergyU.S. Department of the Interior

Bureau of Land ManagementBureau of MinesGeological SurveyOffice of Surface Mining

Utah Geological and Mineralogical SurveyWestern Organization of Resource CouncilsWyoming Department of Environmental QualityWyoming Game and Fish DepartmentWyoming Geological SurveyWyoming Natural Heritage Program,

The Nature Conservancy

In addition, OTA wishes to express its appreciation to the many individuals, organizations and com-panies who acted as reviewers for this report, and to the many Federal coal lessees without whosecooperation this report would not have been possible.

vi

Participants in the State Task Forces

Colorado

William BosworthSheridan Enterprises, Inc.

Archie CarverU.S. Geological Survey

C. Wayne CookColorado State University

Henry E. DavisPeabody Coal Co.

Doran GilletteBureau of Land Management

Scott GraceU.S. Environmental Protection Agency

Dewitt JohnDepartment of Natura Resources

Dan KimballOffice of Surface Mining

Carla KishWestern Organization of Resource

CouncilsLewis Ladwig

Colorado Geological SurveyDan Martin

Bureau of Land ManagementD. Keith Murray

Colorado School of Mines ResearchInstitute

Chris SeglemColorado-Westmoreland Inc.

Greg SpanskiU.S. Geological Survey

Robert TurnerNational Audubon Society

New Mexico

W i l l i a m G . B r a d l e yChaco Energy Co.

Robert CalkinsBureau of Land Management

Cubia L. ClaytonEnvironmental Improvements Division

New Mexico Health and EnvironmentDepartment

William DarmitzelNew Mexico Mining Association

James Edwards, Jr.U.S. Geological Survey

Lucy FoxNew Mexico Energy and Minerals

DepartmentSteven J. Frost

New Mexico Bureau of Mines andMineral Resources

D. Eugene GrayState Engineer’s Office

Louis MartinezN e w M e x i c o E n e r g y a n d M i n e r a l s

DepartmentMat Millenbach

Bureau of Land ManagementJoseph A. Pierce

New Mexico Health and EnvironmentDepartment

Charles RoybalNew Mexico Energy and Minerals

DepartmentJon Samuelson

New Mexican State Planning Office

WyomingWalter C. Ackerman

Department of Environmental QualityStephen Berg-Hansen

Rocky Mountain Energy Co.Jerry Boggs

Office of Surface MiningC. Wayne Cook

Colorado State UniversityNorman Dalstead

Colorado State UniversityFred Eiserman

Energy Transportation Systems, Inc.John Eichenauer

NERC0, Inc.

Joseph EvansDepartment of Economic Planning and

DevelopmentChris Farrand

Peabody Coal Co.Thomas M. France

Northern Rockies Action GroupGary B. Glass

Wyoming Geological SurveyJoseph M. Hamner

Carter Coal Co.Harry J. Harju

Wyoming Game and Fish DepartmentBernice Heilbrunn

Exxon Coal USA, Inc.Carla Kish

Western Organization of ResourceCouncils

Ron KisickiWyoming Highway Department

John LaneWyoming Highway Department

Marion LoomisWyoming Mining Association

Arnie MattilaRock Springs District Mining Office

J. Stan McKeeBureau of Land Management

Richard Mooreindustrial Siting Administration

Kenneth NationU.S. Geological Survey

James J. SebestaColorado State University

Frederick ScheererArco Coal Co.

Mark R. StrombergWyoming Nature Conservacy

Richard TupperBlack Hills Power & Light Co.

James VandelWyoming Highway Department

Warren WhiteOffice of the Governor

John WienerEnvironmental Consultant/Attorney

Reed ZarsPowder River Basin Resource Council

Oklahoma

Ernest AchterbergU.S. Geological Survey

Robert BrownBureau of Land Management

Ray BrubakerU.S. Department of the Interior

Michael E. CyrB u r e a u o f L a n d M a n a g e m e n t

William DahlgrcnDahlgren Contracting Co.

Samuel A. FriedmanOklahomo Geological Survey

James GegenBureau of Land Management

Homer G. MeyerBureau of Land Management

Jeff Porter, IIIGarland Coal Mining Co.

Blaney QuallsOklahoma Department of Mines

Nick M. SpanosArmco Materials Resources

Utah

Gordon AndersonFriends of the Earth

C. Wayne CookColorado State University

Ron DanielsUtah Department of Natural Resources

Hellmut DoellingUtah Geoligical and

Mineralogical SurveyJohn Garr

Coastal States Energy Corp.Frank Hachman

University of UtahDan Kimball

Office of Surface Mining Region VJack Moffitt

U.S. Geological SurveyLyman Moore

Bureau of Land ManagementRobert Moore

Utah Coal Operators AssociationMax Nielson

Bureau of Land Management

Ken RiddleUtah Department of Transportation

Carol SendenBureau of Land Management

Vll

Contents

Chapter Page1.2.3.

4.5.6.

7.8.9.

10.

11.12.13.

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Background and Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37Federal Coal Leases and Preference Right Lease Applications:An Overview. , , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47Federal Coal Resources, ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Markets and Projected Demand for Federal Coal. . . . . . . . . . . . . . . . . . . 79Development Potential and Production Prospects ofFederal Coal Leases. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .113The Powder River Basin: A Case Study. . .........................169Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........201Federal Coal Lease Management. . . . . . . . . . . . . . . . . . . . . . . .........227Implications of Environmental and Reclamation Issues forthe Development of Federal Coal.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .273Mining Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........323Revenues and Socioeconomic Impacts. . . . . . . . . . . . . . . . . . . . . . . . ...347Patterns and Trends in Ownership of Federal Coal Leases andPRLAs 1950-80 . . . . . . . . . . . . . . . . . . . . . . . . .......................371

Appendixes

A. Development and Production of Federal Coal Leases inthe Southern Rocky Mountain States. . . . . . . . . . . . . . . . . . . . . . .......389

B. OTA Working Lease List and Lessee Index . . . . . . . . . . . ..............408C. Acronyms, Abbreviations, and Glossary . . . . . . . . . . . . . . . ............466D. Some Key References. .. . . . . . . . . . . . . . . . . . . . . . . . ..............470E. Availability of OTA Working Papers . . . . . . . . . . . . . . . ...............473

ix

—

CHAPTER 1

Executive Summary

PageOverview ● . . . . ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ 3

Status of Federal Coal Leases . . . . . . . . . . . . . 6Federal Coal Resources and Production . . . . . 7Ownership of Federal Coal Leases.. . . . . . . . . 10Lease Development Status. . . . . . . . . . . . . . . . 11

Potential Production From Federal CoalLeases in 1986 and 1991. . . . . . . . . . . . . . . . . 16

Development Prospects of UndevelopedFederal Coal Leases. . . . . . . . . . . . . . . . . . . . 16

Production and Capacity Estimates for 1986and 1991: Developed andUndeveloped Leases. . . . . . . . . . . . . . . . . . . . 17

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

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

Factors Affecting Federal Lease Developmentand Federal Coal Production . . . . . . . . . . . . . 25

Market Factors. . . . . . . . . . . . . . . . . . . . . . . . . 25Environmental Factors. . . . . . . . . . . . . . . . . . . 26Laws and Regulations on Management ofExisting Federal Leases. . . . . . . . . . . . . . . . . 29

Transportation Considerations . . . . . . . . . . . . 31Revenues and SocioeconomicConsiderations. . . . . . . . . . . . . . . . . . . . . . . . 32

List of Tables

Table No. Pagel. Federal Leaseholdings and Production by

Business Category . . . . . . . . . . . . . . . . . . . . 132. 1979 and 1980 Coal Production From the

Seven Federal Coal States Studied inThis Report . . . . . ● , . . . . . . , . . , . ● . 15

3. Development Potential ofUndeveloped Leases. . . . . . . . . . . . . . . . . . . 16

4. Summary of Impacts to FederalRecoverable Reserves From Environmentaland Reclamation Considerations . . . . . . . . . 27

5. Federal Royalties and State DistributionsFrom Potential Coal Production onFederal Leases 1980, 1986, and 1991 . . . . . 32

List of Figures

Figure No. PageI. Potential Production From and Planned

Capacity of Federal Mines Summed Overthe Six Major Federal Coal States . . . . . . . 4

2. Generalized Coal Provinces of theUnited States. . . . . . . . . . . . . . . . . . . . . . . . 7

3. Sketch Map Showing Major Coal RegionsWith Leased Federal Coal, andGeneralized Location of Strippable andMetallurgical 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 StateProduction in 1979, by State, for theSeven Federal Coal States Consideredin This Report . . . . . . . . . . . . . . . . . . . . . . . 9Number of Leases, Acreage Under Lease,and Federal Coal Production From1950 to 1980....... . . . . . . . . . . . . . . 10

7. Annual Coal Production From the SixMajor Federal Coal-Producing States inthe West, 1957-79. . . . . . . . . . . . . . . . . . . . 11

8. Number of Federal Coal Acres Under

9

10

Lease by Business Activity Category,1950-80 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12The Development Status of FederalCoal Leases . . . . . . . . . . . . . . . . . . . . . . . . . 14Planned Capacity and PotentialProduction of All Mines With FederalLeases in the Powder River Basin,Southern Wyoming,andFort 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 thePowder River Basin . . . . . . . . . . . . . . . . . . 22

13. Dilligent Development Summary for theSouthern Rocky Mountain Region . . . . . . . 22

14. Comparisons of Powder River Basin -Demand Projections With PlannedCapacity and Production Levels for1990 . . . . . , . .. . . . . . . . . . ...... 24

CHAPTER 1

Executive Summary

Overview

As of late 1980, there were 565 Federalcoal leases* in existence in 14 States cover-ing 812,000 acres and containing 16.5 billiontons of recoverable reserves. This study ex-amines the development potential and pro-duction prospects for the 548 Federal coalleases in the seven States of Wyoming, Mon-tana, Colorado, Utah, New Mexico, NorthDakota, and Oklahoma, with principal em-phasis on the 502 leases in the first six Stateslisted above: the six major Western Federalcoal States. These six States contain over 98percent of leased Federal reserves and ac-count for over 99 percent of Federal coal pro-duction. The 17 small leases in Alabama,Alaska, California, Kentucky, Oregon, Penn-sylvania, and Washington, with 0.5 percentof leased Federal coal reserves and 0.2 per-cent of Federal coal production, were not ex-amined in this study. Furthermore, the devel-opment potential and production prospects ofcurrently unleased Federal coal were not ex-amined in this study. Therefore, the findingsof this study on potential Federal coal produc-tion and its relation to likely markets forFederal coal refer only to currently leasedFederal coal in the seven States of Colorado,Montana, New Mexico, North Dakota, Okla-homa, Utah, and Wyoming.

A Federal coal lease may be convenientlyclassified by its mine plan status: in an ap-proved mine plan, or in a mine plan submittedto and pending approval by the U.S. Depart-ment of the Interior (DOI), or with no mineplan. The 565 Federal coal leases aregrouped as follows:

1. There are 198 leases in approved mineplans covering nearly 280,000 acres,and containing 7.4 billion tons of recov-erable reserves.

*The leases sold in early 1981 under the new Federal coalmanagement program are not included in this total and werenot considered in this study.

2.

3.

Of these 198 leases, 182 are located inthe six major Western Federal coalStates listed above. The 182 leases areincluded in 69 approved mine plans. Ofthese 69 Federal mines, 64 producedcoal in 1979; the remaining 5 are sched-uled to begin production within a fewyears.

Total coal production from these 64Federal mines in 1979 was 138 milliontons. The Federal portion of this produc-tion was 60 million tons, up from 7.3 mil-lion tons in 1970.** In 1979, Federal pro-duction in the six States of Wyoming,Montana, Colorado, Utah, New Mexico,and North Dakota accounted for 7.7 per-cent of the total U.S. coal production of776 million tons, In 1980, Federal coalproduction in these six States grew to 69million tons, or 8.4 percent of the totalU.S. coal production of 820 million tons.There are 118 leases in 32 pending mineplans covering nearly 195,000 acres andcontaining 2,5 billion tons of recoverablereserves.There are 249 leases not in mine plans

A

covering nearly 338,000 acres and con-taining 6.6 billion tons of recoverable re-serves. (These leases are called undevel-oped leases in this report. ) However,many of these leases are in the processof being developed and could be in pro-duction within the decade.

**Coal from Federal coal leases is referred to as Federalcoal. A mine that includes a Federal lease is called a Federalmine. Sometimes, for the sake of efficiency of recovery oreconomy of operations, intervening State or private coal ismined with Federal lease(s) in the same mine. This practice isthe rule in southern Wyoming and North Dakota, for example.Thus, many Federal mines produce both Federal and non-Fed-eral coal. A mine that contains no Federal coal is called a non-Federal mine. Total coal production in a State or region is thusthe sum of: 1 ) Federal coal production from Federal mines plus2] non-Federal coal production from Federal mines plus 3) non-Federal coal product ion from non-Federal mines.

3

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

Approximately 5 percent of currentlyleased Federal reserves appear undevelop-able because of poor property characteris-tics, remote location, or environmental pro-hibition. Considerable uncertainty surroundsthe likelihood of the development of another15 to 20 percent of leased Federal reserves(some of them in the pending mine plan cat-egory) because of factors such as construc-tion of transportation systems, synfuels de-velopment, pace of associated powerplantconstruction, availability of additional Fed-eral reserves, and lessee development pri-orities. Delays in development and productioncaused by these factors and by market uncer-tainties might result in leases containing over7 billion tons of reserves, or 43 percent of allcurrently leased reserves, to fail to meet dili-gent development requirements by 1991;leases containing over 3.5 billion tons of re-coverable coal are unlikely to meet diligenceby 1991; leases containing approximately 3.4billion tons of recoverable reserves haveuncertainties surrounding attainment of dili-gence by 1991.

The following estimates of potential pro-duction from Federal leases are not forecastsof the coal that will be produced at a givenprice or a given demand. They are estimatesof the total amount of coal that could be pro-duced from operating Federal mines andfrom those Federal leases that have charac-teristics comparable to operating mines in thesame region. Coal from these leases wouldthus be likely to have mining costs competi-tive with costs at currently operating mines inthe same area. If the demand for Federal coaldoes not increase to these levels of potentialproduction, then not all the Federal leasesthat could technically and economically bedeveloped will go into production.

Production from existing Federal coalleases is likely to increase substantially overthe next 10 years. Planned production capac-ity for 1986 for Federal mines is 400 milliontons per year; for 1991, over 535 million tonsper year (see fig. 1). OTA estimates that pro-duction from Federal mines could range be-tween 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 thesix major Western Federal coal States 1

1979

A:

B:

c:

1966 1991Year

Potential annual production, b

Lessees’ planned annual production fromFederal mines in currently approved mine plansonly

Lessees’ planned annual production fromFederal mines in currently approved and pendingmine plans

The sum of B, above, plus estimates of potentialproduction from presently undeveloped Federalleases

a Wyoming, Montana. Colorado, Utah. New Mexico and North Dakotab 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 verystrong market for coal) In many cases (e.g., currently approved mines m thePowder 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 fallshort of using planned capacity to the full. Some mines, particularly newermines in the Southern Rockies wiII not attain their planned maximum capacityuntil the 1990’s. In all cases, however, the capacities planned for 1986 or 1991were used in deriving fig. 1, above, not the higher numbers for planned max-imum capacities in the post 1991 period For most Federal mines in theSouthern Rockies, the planned productions for 1986 and 1991 are close to theplanned capacities for those years

Explanation of rangesC: 92 million tons per year range in 1991

65 mty = Dominant uncertainty IS the development of markets for the coal22 mty = Dominant uncertainty IS the construction of two railroads, one to the

Kaiparowits Plateau in Utah (14 mty) and one to the Star Lake. Bistiarea of New Mexico (8 mty)

5 mty = Dominant uncertainty IS the schedule of synfuels developmentD 22 million ton per year range in 1991

Dominant uncertainty IS the construction of the two railroads mentionedabove, under C

SOURCE Office of Technology Assessment

year in 1991 depending on markets, synfuelsdevelopment, and rail construction. Actualproduction in 1991 could fall below thisrange, however, because of competition withnon-Federal mines and new Federal coalleases in the West and from other coal-pro-

Ch. l—Executive Summary ● 5

ducing regions of the country and becauseoverall demand for coal may not grow suffi-ciently during the next decade to support thislevel of production from Federal mines.

During the 1990’s, demand for coal in gen-eral and Western and Federal coal in partic-ular may grow rapidly, particularly if coal-based synfuels and exports of Western coalto foreign countries become important.

The Powder River basin of Wyoming andMontana was the source of about 50 percentof coal produced from Federal mines in 1979(71.7 million tons) and contains 56 percent ofrecoverable Federal coal reserves underlease (9.2 billion tons). In 1979, there wasmore than 75 million tons of overcapacity inFederal mines in the Powder River basin. ThePowder River basin can increase productionsubstantially by 1990. For 1990, 186 milliontons of Powder River basin coal have alreadybeen contracted: 159 million tons from cur-rently operating Federal mines, 17 milliontons from undeveloped Federal leases, and 10million tons from currently operating non-Federal mines. Planned capacity for 1990 forall coal properties in the Powder River basinlikely to be in production by that year isapproximately 350 million tons per year. Thelikely demand range for Powder River basincoal for 1990 falls substantially below thisplanned mine capacity.

The States of Colorado, New Mexico, andUtah contain 360 Federal coal leases, about athird of which (113 leases) are in activemines, The five major coal-producing regionsin these three States have a wide range ofcoal quality and mining conditions, The areacontains both large and small active surfaceand underground mines.

In 1979, mines with Federal leases in Col-orado, New Mexico, and Utah produced 35million tons of coal, Little overcapacity in coalproduction existed in these three States in1979, New mine plan proposals have beensubmitted for another 108 Federal leases and96 out of the 139 leases that are not in mineplans might be developed over the next dec-ade. By 1991, Federal mines in these three

States could sustain 110 million to 146 milliontons per year of production, 65 million tonsper year from currently operating Federalmines, 28 million to 49 million tons per yearfrom new Federal mines with plans are pend-ing approval and 17 million to 32 million tonsper year from presently undeveloped leases.These estimates are subject to two principaluncertainties: 1) whether demand for coalfrom this region will increase as generally ex-pected; and 2) whether proposed coal trans-portation systems will be constructed to con-nect currently inactive coal mining areas insouthwestern Utah and the San Juan basin ofNew Mexico with potential markets. At pres-ent, only the proposed Star Lake Railroad inthe San Juan basin is nearing approval. How-ever, the above numbers suggest that therewill be little overcapacity in coal productionin this three-State region over the nextdecade.

The potential for continued overcapacity inthe Powder River basin over the next 10years has caused questions to be raised aboutthe timing, extent, and location of large-scaleleasing under the new Federal coal manage-ment program. The debate focuses on the roleof competition and the free market in re-source supply, the potential costs to the socialand physical environments of the coal-pro-ducing areas of “overleaping,” the length oftime needed to bring a new lease into fullscale production, the margin of supply safetyneeded for prudent planning on a nationaland a corporate level, questions of equityraised by restricted opportunities for new en-trants to Federal leaseholding, a fair returnto the public for the use of its resources, andthe levels of demand likely in the early to mid-1990’s. Many proponents of large-scale newleasing in the Powder River basin in the nearfuture cite the long moratorium on such leas-ing and its effect of restricting entry possibili-ties to leaseholding as one reason for promptresumption. They also contend that post-poning leasing will unduly interfere with theworkings of the free market and will restrictcompetitition. They anticipate high demandfor coal by 1995 and fear that the presentleased reserve base in the Powder River

6 . An Assessment of Development and Production Potential of Federal Coal Leases

basin will not provide enough certainty orflexibility to meet that demand efficiently.Opponents of large-scale new leasing in thePowder River basin as scheduled in 1982 citethe potential for overcapacity through theearly 1990’s as proof that such leasing is notnecessary at this time. They contend thatleasing can be safely deferred until its neces-sity is clearly indicated by realistic demandforecasts. They hold that large-scale leasingsubstantially beyond that necessary to meetlikely demand in 1990 will place an unneces-sary strain on orderly planning in the com-munities of the region, shift demand to thePowder River basin that could have been metby Midwestern supply, depress the value ofleases so that the public will not receive a fairreturn for its resources, and, moreover, beunlikely to increase competition significantly.

Minability of Federal coal reserves in theWest is affected by administrative and regu-latory decisions in several aspects of environ-mental concern. These areas of concern in-clude air quality, water resources, alluvialvalley floors, return to approximate originalcontour, and wildlife resources. The effect ofenvironmental regulations on the production

of Federal coal has been to remove smallamounts of minable coal from the recoverablereserve base, to delay development of otherrecoverable reserves, to increase the com-plexity of the mine permit process, and to in-crease the overall cost of mining.

The percentage of recoverable Federal re-serves currently under lease on which miningcould be prohibited or delayed over the next10 years because of environmental regula-tions is between 5 percent and 10 percent ofthe total currently leased reserves, Less than1 percent of currently leased Federal re-serves appear likely to be subject to completeprohibition from mining; the remainder ofcurrently leased Federal reserves that maybe affected may be subject to delay in miningbecause of unresolved environmental ques-tions, but the available evidence indicatesthat most of these reserves will be mined.There are additional leased reserves (mainlyin the Kaiparowits Plateau in southern Utah)over which there are potential environmentalconflicts, but impediments to development ofthese reserves are primarily related to nonen-vironmental factors such as transportationavailability y.

Status of Federal Coal Leases

In terms of tonnage, a little over one-half ofthe U.S. recoverable coal reserves lies westof the Mississippi River; in terms of heat con-tent, a little less than one-half lies west of theMississippi River. According to the best avail-able data, the Federal Government owns be-tween 50 and 60 percent of the coal reservesin the six major Federal coal States;* thepercentage varies considerably among coalregions.

Since 1920, DOI has leased rights to mineFederal coal to the private sector. During thepast 60 years, over 16 billion tons of coal on812,000 acres have been leased and remainin 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 bythe Federal Government are presently underlease.

A lease is necessary to mine Federal coal.The lease grants the lessee exclusive rights tomine coal subject to stipulations in the leaseestablished by DOI and subject to Federaland State laws. Historically, most leases havebeen issued in two ways: 1) competitivelythrough bidding at lease sales, and 2) non-competitively through an application processcalled preference right leasing. **About halfof 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 leasetract is split into two or more units. A new lease(s) is issued forthe new unit(s) and the acreage of the original lease is cor-respondingly reduced.

Ch. l—Executive Summary ● 7

each method, but the Federal Coal LeasingAmendments Act of 1976 abolished the pref-erence right system and required competitiveleasing of all Federal coal. As of January 1,1980, 176 preference right lease applications(PRLAs) covering nearly 404,000 acres andcontaining 5.8 billion tons of recoverable re-serves were in existence, All these applica-tions are scheduled to be processed by DOI by1984,

DOI began issuing leases under the newcoal management program in January 1981,after a lo-year moratorium on all but leasingfor special purposes. * Given the 5- to 12-yearleadtime required to develop a coal mine, pro-duction from presently unleased land will berelatively small during most of the 1980’s.

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

Federal Coal Resources and Production

The Federal Government owns coal re-sources in all the major coal regions of theUnited States. However, the vast majority ofFederal coal is located in two coal regions inthe Northern Great Plains coal province andseven regions in the Rocky Mountain coalprovince. Federal leases in these two prov-inces include over 98 percent of the 16.5billion tons of recoverable coal currentlyunder lease. Three-quarters of the Federalcoal reserves on leases outside of the North-ern Great Plains and Rocky Mountain coalprovinces are contained in 46 leases inOklahoma, which is geologically part of theInterior coal province, The remaining re-serves (0.5 percent of the total under lease)are in 17 leases in the States of Alaska, Ala-bama, California, Kentucky, Oregon, Penn-sylvania, and Washington (see figs. 2 and 3).

Figure 2.— Generalized Coal Provinces of the United States

Dominion of Canada.-. /... New I/ “ .

Legend

Bi tumlnouscoal

Subbi tuminouscoal

.. Ligni te

Mexico

Atlantic Ocean

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

8 4 - 1 4 1 0 - 8 1 - 2 : 0 L 3


Figure 3.—Sketch Map Showing Major CoalRegions With Leased Federal Coal, andGeneralized Location of Strippable and

Metallurgical Coal Deposits

Powder River Region

IUtah region

Raton Mesa region

SOURCE Base Map National Academy of Sciences, Rehabilitation Potential ofWestern Coal Lands, Cambridge, Mass, Ballinger Press, 1974)

Figure 4 summarizes 1980 Federal coalproduction and the distribution of leases,leased acreage, and leased recoverable re-serves among the Federal coal States. Figure5 summarizes 1979 Federal production, Fed-

Figure 4.— Distribution of Production, Reserves.Acres, and Number of Leases by State ‘

Montana

Utah

NewMexico

1 1 1 1 I 1 io 10 20 30 40 50 60

Percent of totals

69.2

16.5

812,001

565

Totals

million tons (ret) of Federal coalproduction in 1980

billion tons (bt) of recoverable coalreserves under Federal coal lease

acres under Federal coal lease

Federal coal leases

a mt million tonsbbt billion tons

CO 14 million tons in 1979

SOURCE Off Ice of Technology Assessment

eral mine production, and total production byState for those seven States. The States ofWyoming and Montana together contain 61percent of leased reserves and accounted for63 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 mt71.8 mt

8.6 mt27.4 mt32.5 mt

7,7 mt16.0 mt18.1 mt

6.9 mt10.4 mt11.8 mt

5.4 mt8.4 mt

15.1 mt

1.1 mt14.1 mt15.0 ml

0.3 mt0.3 mt4.8 mt

““ !.

Montana

Colorado

Utah

I New MexicoSums forthe seven

States:

North Dakota Federal production: 60.1 mtFederal mine production: 144 mtTotal State production: 169 mtTotal Federal coal production

in the U.S. in 1979: 60.2 mtC

Oklahoma Total U.S. coal productionin 1979: 776 mt

I I I I 1 I I10 20 30 40 50 60 70

KeyMillions of tons

Federal productionFederal mine productionTotal State production

aSee the footnote on page 8 for definitons of Federal production, Federal mine production, and total productionbmt = milion tonscThe other States contributed 0.14 mt of Federal production in 1979


Most of this came from the large surfacemines in the Powder River basin. Coloradoand Utah, which have 59 percent of leases,contain 33 percent of recoverable reservesand produced 26 percent of Federal coal in1980. Mines are smaller on the average inthese two States than in the Powder Riverbasin and underground mining currently ac-counts for about 40 percent of production.New Mexico and North Dakota contain pre-dominantly large surface mines; coal prop-erties in North Dakota have relatively small

amounts of Federal reserves in conjunctionwith large amounts of private coal.

Heat content of Colorado and Utah coal isgenerally higher than that of the PowderRiver basin; leased New Mexico coal is gen-erally of higher heat content than PowderRiver basin coal, but lower than Colorado andUtah coals. Utah, Colorado, New Mexico, andOklahoma all contain metallurgical gradecoal under lease, North Dakota coal is alllignite of low heat content and in general issuitable only for onsite use.


The quality of coal reserves presently un-der lease and PRLA does not appear to im-pose any serious limitations for meeting thedemand that is likely for Western coal overthe next 10 to 15 years. Most leased reserveshave low-sulfur and ash content and are suit-able for use by utilities, which constitute thesingle largest user of Western coal.

Because of low heat content, the coal on allFederal leases in the Fort Union region ofNorth Dakota and Montana and about 50 mil-lion tons of potential annual production ca-pacity from Federal reserves under lease andPRLA in the Wyoming Powder River basin*are probably suitable only for onsite develop-ment for electric power or synfuel plants.(The large majority of leased Federal re-serves are, however, of sufficiently high qual-ity to be exported out of the producing State.)Deposits of metallurgical-grade coal are rel-atively limited in the West, but demand forWestern metallurgical coal is also limited;the availability of Federal and non-FederalWestern metallurgical coal is probably suffi-cient to meet the limited demand for this coalanticipated in the foreseeable future.

Federal coal production has risen steadilyover the past 10 years. Figure 6 shows thechange since 1950 in the number of leases,the acreage under lease, and Federal coalproduction. Whereas the sharp rise in leasingoccurred in the 1960’s, the sharp rise in pro-duction from leased land started 10 yearslater, in the 1970’s. Figure 7 compares Fed-eral coal production and total coal productionin the six major Federal coal producingStates. Production from leased land startedits sharp rise approximately 5 years laterthan overall Western production and hasrisen faster in most years since then. Duringthe next decade, coal production from Feder-al leases will probably increase at a fasterrate than non-Federal coal production in theWest because of the large increases in Feder-al production expected in the Powder Riverbasin.

*Forty-five million tons out of the 50 million tons are unlikelyto be in production by 1991 but could come into production inthe 1990'5.

1950 1960 1970 1980Year

SOURCE Acreage and number of leases data from Office of TechnologyAssessment review of U S Department of Interior case files Federalcoal production from the U S Department of the Interior, FederalCoal Management Report, F/sea/ Year 1978, March 1979 and from theACLDS.

Ownership of Federal Coal Leases

The ownership of Federal coal leases hasundergone marked changes over the last 30years. Figure 8 shows how the leaseholdingsof 11 groups of lessees and two major lease-holding companies have changed since 1950.

Independent coal companies and unincor-porated individuals dominated coal leasing inthe 1950’s and 1960’s, but their relative im-portance has steadily declined since 1950. Incontrast, the electric utilities, major energycompanies, and natural gas pipeline compa-nies have increased their Federal coal hold-


Figure 7. —Annual Coal Production From the SixMajor Federal Coal-Producing States in the West,

1957-79a

1955 1960 1965 1970 1975 1980

Year

aThe 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 En-v i ronmenta l Sta tes Federa l Coal Management Program

(Washington, D.C.; U.S. Government Printing Office 1979) 1978data from table A 2, U S Department of Interior Federal CoalManagement Report Fiscal Year 1979 (Washington D C U SGovernment Prlntlng Office. 1980), 1979 data from table 16, ch. 3 ofthis report

ings significantly since 1965 both in absoluteand relative terms. Steel companies andmetals and mining companies were earlyleasing participants, but steel industry influ-ence has declined steadily in relative termssince 1950, although the acreage held by thesteel industry has steadily increased since1950. Metals and mining company leasehold-ings have varied widely, due in part to the1977 sale of Peabody Coal Co. by KennecottCopper Corp. Independent land companiesplayed a significant role in leasing in the1950’s and 1960’s, but they have largely liqui-dated their holdings over the past decade.

Table 1 shows the acres held under leaseby the principal categories of leaseholders

and the amount of Federal coal they pro-duced in the early and late 1970’s. There is afairly close correspondence between theshare of Federal leased acreage and theshare of coal production in 1979. A strikingexception is the case of the metals and miningcompanies, which accounted for 16 percentof Federal coal production in 1979 whileholding only 2 percent of leased acreage.

The ownership data reveal little evidenceof concentration of leaseholdings between1950 and 1980. The number of leaseholdersapproximately doubled in that period, from84 to over 160 while the number of leases in-creased sixfold from 88 to 565 and the leasedacreage increased by nearly a factor of 20,from about 41,000 acres to 812,000 acres,The four largest leaseholders in 1950 con-trolled 32 percent of all land under leasewhile the largest eight controlled 34 percentin 1980. Leaseholders in 1980 came from ninebusiness categories, up from four categoriesin 1950. On the average, a leaseholder heldthree times as many leases and 10 times theacreage in 1980 as in 1950.

Three trends in the nature of leaseholdersare noteworthy: 1) There is a growing involve-ment in the leasing program by horizontallyintegrated companies, The energy companies,natural gas pipeline companies, and thesmaller oil and gas companies together hold31 percent of leased acreage and produced29 percent of Federal coal in fiscal year 1979.2) There is a growing involvement of compa-nies for which coal production represents avertical integration of business activities.Steel companies and electric utilities are theprincipal examples of vertical integrationamong leaseholders, Together, the twogroups hold 29 percent of coal land underlease. 3) There is a growing involvement oflarge, already diversified companies in coalleasing, including metals and mining com-panies and chemical and high technologycompanies.

Lease Development Status

A principal objective of this study is toassess the development potential of existing


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

300,001

lOO,OOC

- 1 .... -

... \ ... \I~Natural gas:<;-.I~ - -'I, .-:: pipeline companle~

Oil and gas"'-~ -(~ companies (minor)

I Nonresource·related

Ene'gy companies


Table 1 .—Federal Leaseholdings and Production byBusiness Category

Fiscal year1972 1979coal coal

production production1970 from 1980 from

Business activity leased Federal leased Federalcategory 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% 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

Non resource 1% 0% 5 % 2 %diversified companies 10,015 0 35,675 1.0

Unincorporated 11 % 3 % 6 % 1 %i n d i v i d u a l s . . 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 landholdings listed as acres. All production Iisted in million tons of coal.

a Peabody 1970 land holdings and 1972 productions totaled In metals and min-ing category

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


leases, For this analysis, OTA combined theexisting leases into units or blocks, A leaseblock, as defined in this report, consists ofone or more leases owned by the same les-see(s) that are contiguous or sufficiently closetogether to form a compact minable unit,

Using this approach, OTA divided the 565existing coal leases into 256 blocks. Thesmallest blocks contain one lease covering 40acres, The largest, located in southern Utah,includes 21 leases and 47,000 acres.

OTA conducted a comprehensive study ofmining and development activities and pro-duction prospects for the 548 Federal leasesin 244 lease blocks located in the seven States

of Colorado, Montana, New Mexico, NorthDakota, Oklahoma, Utah, and Wyoming. Tofacilitate this analysis, OTA grouped thelease units in three categories based on thestatus of the mine plan.

Before a coal mine can produce coal fromFederal land, a mine plan must be approvedby DOI. Hence, determining mine plan statusis a useful first step in assessing leasedevelopment potential, Accordingly, the leaseblocks in this report are grouped in thefollowing three development categories basedon a review of all mine plans on file at theOffice of Surface Mining (OSM) on Septem-ber 30, 1980:*

. producing or have approved mine plans,● have mine plans submitted and pending

approval, and• have no submitted mine plan (“undevel-

oped”),

Figure 9 summarizes the mine plan statusof leases, leased acreage, and recoverablereserves by State for the seven principal Fed-eral coal States.

Approximately one-third of all Federalleases are either producing or have approvedmine plans. This category also includesleases issued in 1979 and 1980 to permit thecontinued operation of existing mines (re-gardless of whether or not they have formallybeen included in approved mine plans) andleases which have been included in amend-ments to approved mine plans.

The highest percentage of leases in the ap-proved mine plan category is in Montana: 67percent of leases covering 69 percent of theleased reserves in the State. Utah andOklahoma have the smallest percentages ofleases and the lowest percentage of leasedreserves in the approved categroy.

Although not every lease falling into the ap-proved mine plan category is producing coal,all Federal coal production was mined fromleases in this category. In 1979, 60 milliontons of coal were mined from 83 Federal

*Both surface and underground mine plans are on file at theU.S. Office of Surface Mining.

14 ●

An

A.s.sessrnent

of D

evelopment

and P

roduction P

otential of

Federal

Coal

Leases

. .

.-

m

Wyoming

North Dakota

Percentage of total number of leases

565 = Totial number of leasesb

~e also table 14 in ch. 3 of the full report.

Figure 9.-The Development Status of Fedenil Coal Leasesa

••••• Wyoming

North Dakota

5 15

Percentage of total number of acres

812,001 = Total acreageb

Key: Status of leases

_ In approved mine plan _ In pending mine plan _ With no submitted mine

plan ("undeveloped")

bAIIhough 17 leases in seven SIales covering 3.555 acres and wilh about 0.1 billion Ions of recoverable reserves are nol plotted in Ihis figure. Ihese leases. Iheir acreage and Iheir reserves are conlained in Ihe: ,e lolals.

SOURCE: Office of Technology Assessment


leases, over 40 percent of the leases in the ap-proved category. * In 1979, Federal coal con-tributed 36 percent of all production from theseven Federal coal States shown in figure 9.Federal coal provided 58 percent of Utah’scoal production, 42 percent of Wyoming’scoal production, 7 percent of the coal minedin North Dakota, and 6 percent of the coalmined in Oklahoma (see fig. 5). The pattern issimilar for 1980 (table 2).

Approximately 20 percent of all leases and15 percent of leased reserves are included inmine plans which are pending approval atOSM. This category does not distinguishamong lease units according to the quality ofsubmitted mine plans, their date of submis-sion, or the present position of the mine planin the regulatory review process.

Utah and New Mexico have the highestpercentage of leases in the pending mine plancategory, 38 and 31 percent, respectively. On

*Because only a portion of the approved permit area ismined in any given year, it is unlikely that all Federal coalleases in approved mine plans will be producing at one time.

the other hand, no pending mine plans forMontana leases have been submitted to DOIand only one of Oklahoma’s 46 leases is in-cluded in a pending mine plan.

Forty-four percent of all leases, 42 percentof all leased acreage, and 40 percent ofleased reserves have not been developed tothe point of a mine plan submission to OSM.Preliminary development activity varieswidely on these undeveloped units, from ex-tensive exploration drilling and mine planpreparation on some units to no activity at allon others.

Oklahoma has the highest percentage ofleases and leased acres and reserves inthe undeveloped category; five of the sevenWestern States have over 30 percent of theirleased Federal reserves in this category.Thirty-eight percent of New Mexico’s leasesand 40 percent of North Dakota’s leases haveno mine plans but they cover just 22 percentand 19 percent, respectively, of leased re-serves. These are lowest percentages of re-serves in the undeveloped lease categoryamong the seven Western States.

Table 2.—1979 and 1980 Coal Production From the Seven Federal CoalStates Studied in This Reporta (all production in millions of tons per year)

1979 1980

Productionfrom Total Total

Federal Federal State Federal StateState production minesb production production production

Colorado . . . . . . . . 7.7 16.0 18.1 9.4 19.5Montana . . . . . . . . 8.6 27.4 32.5 10.4 36.1New Mexico. . . . . . 5.4 8.4 15.1 6.3 16.5North Dakota . . . . 1.1 14.1C 15.0 0.6 17.2Oklahoma . . . . . . . 0.3 0.3 4.8 0.3 4.9Utah . . . . . . . . . . . . 6.9 10.4 11.8 8.7 13.1Wyoming . . . . . . . . 30.1 67.5 71.8 33.4 94.0

Totals. . . . . . . . . 60.1 144.1 169.1 69.1 201.4aTOTAL 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 withFederal lease(s) in the same mine This practice iS the rule in Southern Wyoming and North Dakota, for example Thus, manyFederal mines produce both Federal and nonfederal coal A mine which contains no Federal coal IS called a non-Federalmine 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 ofthis 56 million tons iS from non-Federal reserves

SOURCES 1979 Federal productlion from U S Geological Survey accounting office1979 State production from the U S Energy Information Agency, Weekly Coal Production Report, Aug.16, 19801980 Federal production from U S Geological Survey, Federal and Indian Lands, Coal, Phoshpate, PO-tash, Sodiurn and Other Mineral Production, Royalty Income and Related Statistics (Washington, D CU S Government Printing Office, June 1981).1980 State production from the U S Energy Information Agency, personal communication to OTA,July 27, 1981


Potential Production From Federal Coal Leasesin 1986 and 1991

The development and production estimatespresented in this report are based on infor-mation in mine plans, the deliberations of theOTA State task forces* and communicationswith the lessees. Although OTA based itsevaluations of likelihood of development andlevels of potential production on the best dataavailable for each lease at the time, as addi-tional information based on further explora-tion and development becomes available, theprospects for any given lease could change.

These estimates of potential productionfrom Federal leases are not forecasts of thecoal that will be produced at a given price orgiven demand. They are estimates of the totalamount of coal that could be produced fromcurrently operating Federal mines and fromthose Federal leases that have character-istics comparable to operating mines in thesame region. Coal from these leases wouldthus be likely to have mining costs com-petitive with costs at currently operatingmines in the same area. If the overall demandfor Federal coal does not increase to theproduction levels that are possible, then notall of the Federal leases that could technical-

*OTA task forces were held in Colorado, New Mexico. Okla-homa. Utah, and Wyoming. For a complete listing of task forceparticipants, see p. vii of this report.

ly and economically be developed will go intoproduction.

Development Prospects ofUndeveloped Federal Coal Leases

Of the 502 leases in the six major Westerncoal States of Colorado, Montana, New Mex-ico, North Dakota, Utah, and Wyoming, 203are not in mining plans. These leases covernearly 265,000 acres, contain 6.4 billion tonsof recoverable reserves, and have the poten-tial to contribute substantial coal productionwithin the next 10 years. Along with fiveleases in three pending mine plans in Wyo-ming, OTA called these leases “undeveloped”and has evaluated the likelihood that theywill be developed within the next 10 years(see table 3), Geological, technical, owner-ship, environmental, transportation, andcommunity factors were considered in theevaluation process,

Of the 208 leases analyzed as undeveloped,80 leases containing 4.1 billion tons of recov-erable reserves have favorable prospects fordevelopment by 1991. The majority of thesereserves are concentrated in the Wyomingportion of the Powder River basin (3,2 billiontons 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 ofState leases of tons) leases reserves leases reserves leases reserves

Wyoming, . . . . . . . 54 4.2 35 3.5 7 0.67 12 0.03Montana . . . . . . . . 7 0.37 2 <0.1 1 <0.1 4 <0.3Colorado. . . . . . . . 52 1.06 10 0.08 21 0.82 21 0.16Utah. . . . . . . . . . . . 76 1.19 30 0.42 28 0.70 18 0.06New 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

alncludes five leases in Wyoming in three pending mine plans.bOne-half million tons.



Uinta region of Utah (0.4 billion tons of under-ground reserves). In almost all cases, thelessees are actively developing these leases.

Another 65 leases containing 2.3 billiontons of recoverable reserves have uncertainprospects for development by 1991. The largemajority of these reserves (about 90 percent)are about evenly divided among the Kaiparo-wits Plateau coalfield of southwestern Utah,the Green River region of Colorado and theWyoming portion of the Powder River basin,Development depends on factors such aspace and scale of construction of associatedpowerplants or synfuels projects, develop-ment of in situ gasification, availability ofadditional Federal reserves from pendingPRLAs or from new lease sales, constructionof transportation systems, and lessee devel-opment priorities.

Considerable uncertainty faces the threelease blocks (with a total of 0.6 billion tons ofrecoverable reserves) in the Powder Riverbasin whose development is dependent onin-situ gasification, a technology in the ex-perimental stage which is not likely to beready for commercial application before the1990’s. Considerable uncertainty also facesthe 25 undeveloped leases with 0.7 billiontons of reserves located on the KaiparowitsPlateau coalfield of southwestern Utah. Theleases in this large, isolated, rugged area faceuncertainty in potential development over thenext decade because construction of the railor slurry transportation systems to connectthe area with potential markets depends on aminimum production in the area of over 30million tons per year—a scale that is unlikelyto be reached in the next decade.

Finally, 63 leases with approximately 0.5billion tons of recoverable reserves are un-likely to be developed. Most of these leaseslack sufficient minable reserves of market-able quality to be developed as new mines.Many also have difficult mining conditionsthat would make them expensive to develop.Some of the leases are located outside activemining areas and lack adequate transporta-tion. For example, a seven-lease block in Col-orado that meets the minimum requirements

for an average new mine in its region islocated in a remote area without rail service.It is unlikely that it will be developed in thenext decade, given the availability of othercoal sources with adequate transportationand which are closer to potential markets.

Production and Capacity Estimates for1986 and 1991: Developed and

Undeveloped Leases

Production estimates for 1986 and 1991were made on a lease-by-lease basis andsummed by region and State. The 63 undevel-oped leases in the above six States with un-favorable development prospects were as-sumed to have zero production. A range ofproduction was usually estimated for the 145undeveloped leases with favorable or uncer-tain prospects for development. With a fewexceptions, the lessee’s estimates for produc-tion were used for leases in mine plans.

North Dakota, Montana, and Wyoming

In 1979, mines with Federal leases in thesethree States produced 109 million tons ofcoal, over 90 percent of the total amount ofcoal produced in this area. The lessees planto increase production from currently oper-ating Federal mines substantially, to 280million tons in 1991. Currently undevelopedleases could add another 20 to 80 million tonsper year of production in 1991, for a total pro-duction from Federal mines in that year of300 million to 360 million tons.

In the Powder River basin of Wyoming andMontana, Federal mines accounted for 88percent of total coal mine capacity in 1980.This percentage is projected to remain rel-atively constant throughout the decade, How-ever, production from Federal leases them-selves is projected to increase from less than40 percent of total coal production in thebasin in 1979 to approximately 80 percent in1991. In southern Wyoming, essentially allcoal production is from Federal mines, withabout one-third of the production from theFederal reserves. This pattern is expected tocontinue, with the contribution from Federal


reserves rising to perhaps 40 percent by1991. In 1979, Federal mines in the NorthDakota portion of the Fort Union region ac-counted for over 90 percent of the State’scoal production; the amount produced fromFederal reserves was less than 7 percent.This situation is expected to continue, withhowever, production from Federal reservesrising to perhaps 20 percent in 1991.

Figure 10 summarizes potential productionand planned mine capacity for Federal minesover the next decade for the Fort Union re-gion of North Dakota and Montana, for thePowder River basin of Montana and Wyo-ming, and for southern Wyoming. The uppercapacity lines (lines D) in this figure repre-sent OTA’s estimate of the maximum coalproduction from Federal mines that could beachieved in these three regions under strongmarket conditions. Several features of figure10 should be noted:

1.

2.

3.

The Powder River basin will continue toincrease in importance as a coal-produc-ing region. By 1991, Federal mine pro-duction in the Powder River basin couldaccount for about 80 percent of Federalmine production in these three States.All estimated Federal mine productionfor 1991 for the Powder River basincomes from currently approved minesand from undeveloped leases with favor-able development potential. (Undevel-oped leases with uncertain developmentpotential contribute no productionthrough 1991. ) The large range in esti-mated production from undevelopedleases arises from demand uncertainty.However, several undeveloped leases inthe Powder River basin have contractsfor delivery of coal before 1990.By 1991, the capacity of Federal minesin the Powder River basin could be ashigh as 310 million tons per year. Ac-cording to the lessee’s plans, the overca-pacity in presently operating Federalmines in the Powder River basin, whichwas greater than 75 million tons peryear in 1979 will diminish to nearly zeroby 199l.

4.

5.

The maintenance of total capacity ofFederal mines in southern Wyoming de-pends on the development of new mines.Although capacity of presently oper-ating mines is projected to decrease overthe next 10 years, their production willprobably not decline. Most of the rangein production arises from uncertainty inthe pace of a synfuels project.The potential increase in production andcapacity of Federal mines in the FortUnion region will occur largely frommines in North Dakota with leases incurrently pending mine plans. Undevel-oped leases are not likely to contributemore than 1 million tons per year by1991. Federal mine production in theMontana portion of the region is likely toremain constant at 0.3 million ton peryear.

Colorado, New Mexico, and Utah

In 1979, mines with Federal leases in thesethree States produced a total of 35 milliontons of coal, about 77 percent of the totalamount of coal produced in this area. Manyof the Federal mines in the area are relativelynew and have not yet reached full productionlevels; consequently, the lessees plan to in-crease production from currently operatingmines substantially, to 65 million tons peryear by 1991. Over the next decade, severaloperating mines are expected to be at, ornear, depletion of their current mine planreserves. Part of this reduction in capacitywill be offset by replacement capacity fromnew mines on Federal leases. About 5 millionto 10 million tons are potentially involved.

If all currently operating and proposedmines that include Federal leases are devel-oped and produced as planned, productionfrom these mines could reach 75 million tonsby 1986, and between 110 million and 146million tons by 1991. The production increasewould be greatest in Utah, where productionfrom Federal mines might rise from about 10million tons in 1979 to as much as 74 milliontons by 1991.


Figure I0.— Planned Capacity and Potential Production of All Mines With Federal Leases in thePowder River Basin, Southern Wyoming, and Fort Union Region

Millions of tonsper year

. “

40

30

20

10

1979 1986 1991

Year

Millions of tonsper year

300

250

200

150

100

50

I Powder River Basin

I I I I I1979 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 presentlyundeveloped Federal leases

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


Over the next decade, the percentage of Federal production from existing leases intotal State production coming from existing New Mexico is expected to remain relativelyFederal coal leases is expected to increase in stable, although, output from PRLAs could in-Utah and Colorado as new, large Federal crease the total share of annual State produc-mines 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 productionfor Federal mines over the next decade forthe States of Colorado, New Mexico, andUtah. Several features of figure 11 should benoted.

1. Most of the projected increases in pro-duction will come from new mines on

Figure 1 1.— Potential Production Capacity ofAll Mines With Federal Leases in Colorado,

New Mexico, and Utah

Millions of tonsper year Colorado

40

3020

10

1979 1986 1991

Millions of tonsper year New Mexico

1979 1966 1991

Millions of tonsper year Utah

A: Lessees’ planned annual production capacity for Federal minesin currently approved mine plans only.

B: The sum of A, above, plus estimates of production capacity forFederal mines in pending mine plans and for presentlyundeveloped Federal leases.

SOURCE. Office of Technology Assessment

2.

3.

4.

leases in pending mine plans and on cur-rently undeveloped leases that will notachieve full design capacity until after1991. The projected 1991 productionrange of 110 million to 146 million tons isless than the total capacity of about zoomillion tons per year that could be sup-ported by mines on existing Federalleases in these States by the mid-1990’s.In the late 1990’s, however, the capacitysupported by existing leases will begin todecline as many of the mines that arenow operating exhaust their reserves.For Colorado, the increased productioncomes from new mines with pendingmine plans and from undevelopedleases. The new mines could add from 25million to 30 million tons of new annualcapacity split almost evenly betweensurface and underground operations.About 1.9 million tons of projected 1991production is tied to synthetic fuel proj-ects but could be sold to other customersif the proposed projects were delayed.The major uncertainty facing increasedproduction in Colorado is whether ex-panded markets will materialize as ex-pected.The range of potential production fromnew mines in New Mexico in 1991 re-flects the uncertainties in the rate ofmine development because of possibledelays in the construction of the StarLake Railroad and in the availability ofreserves in pending PRLAs associatedwith two new mines. Production levelsand mine capacity for the Black LakeMine will also be influenced by the re-quirements of a proposed coal gasifica-tion project. Two other new mines areunaffected by PRLA availability or rail-road construction, but are tied to thecoal needs of new powerplants.The range of 27 million tons per year in1991 production in Utah arises from un-certainties in development in the Altonand Kaiparowits coalfields of south-western Utah. Coal development insouthwestern Utah depends on expan-sion of potential markets only the Alton


mine currently has a purchaser for itscoal) and, more importantly, on the con-struction of a rail or slurry transporta-tion system to serve potential con-sumers, A minimum of 30 million tonsannual production is required to offsetthe costs of constructing a rail line ontothe Kaiparowits Plateau,

Oklahoma

In 1979, approximately 0.3 million tons ofFederal coal was produced in Oklahoma.Four mines with Federal leases are currentlyproducing coal in this State; however, theFederal reserves on three of these mines areexpected to be depleted before 1986. No un-developed leases in Oklahoma are expectedto produce coal in commercial quantitiesbefore 1991, Three main reasons accountfor the unfavorable production prospects ofthese leases: 1) difficult and costly under-ground mining conditions, 2) a depressedmetallurgical coal market, and 3) a high Fed-eral royalty relative to royalties charged forfee 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 2½ percent of logicalmining unit** (LMU) recoverable reserves byJune 1, 1986, or be subject to cancellationproceedings. Under certain specific circum-stances, the Secretary of the Interior maygrant an extension to mid-1991, (See ch. 9 formore detail. )

Most leases with potential for productionby 1991 could qualify for extensions underexisting guidelines. The exceptions are minesthat do not fit clearly into any of the currentguidelines, specifically several proposedsmall- to medium-sized mines that are in-

* Thc 38 leases issued after August 4, 1976. are subject to aSlightly 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 leaseas an LNIU. ‘[’ills definition may be. but is not ne(x?ssarll},superseded when :~ mine plan is nppr[wed. In [) mine plan. :) nLN![J mav consist of more thi)n one Fmicrnl lease t~ncf m:]~ in-clude non-Federal coal 1.

tended to serve spot markets and several un-derground mines with difficult mining condi-tions requiring longer construction periods.

OTA has examined estimated productionschedules to assess the likelihood that a leaseblock will achieve diligence by 1986 or 1991.

By 1991, over 70 percent of the 502 leasesin the six major Western Federal coal Statesmight meet the existing diligence require-ments.

•

●

●

216 leases with 7.4 billion tons of re-serves are likely to meet diligence by1986 (45 percent of total leased re-serves).29 additional leases with 2.1 billion tonsof reserves are likely to meet diligenceby 1991 with extensions (13 percent oftotal leased reserves).112 leases with 3.4 billion tons of re-serves (20 percent of total leased re-serves) are uncertain to meet diligenceby 1991. Major uncertainties are tied todelays in powerplant, synfuels andtransportation system construction, fluc-tuations in captive coal needs, develop-ment of markets for the coal, and diffi-culties in defining the logical mining unitfor leases with very large reserves inmultiple seams. Development of marketsfor the coal constitutes a particularly im-portant uncertainty in the Powder Riverbasin where market demand will be animportant factor in determining whether1.2 billion tons of recoverable reservesunder lease will meet diligence by 1991.

Thirty percent of the leases in the six majorWestern Federal coal States containing 20percent of total leased reserves are unlikelyto meet diligence by 1991 even were they tobe granted extensions:

● Production for 61 leases in the Kaiparo-wits Plateau with 1.4 billion tons ofreserves is dependent on construction ofa coal transportation system that is un-likely to be in place by 1991. Moreover,even if the Kaiparowits Plateau leasesbegin producing at the earliest feasibledate, 1987, it is unlikely that they would


●

●

produce enough to meet diligence re-quirements because of the large amountof underground reserves involved.Development of 10 leases in the PowderRiver basin with 1.4 billion tons of re-serves depend on onsite synfuels devel-opment; 0.6 billion tons of these are suit-able only for in situ gasification, assum-ing that technology is developed.The remaining 74 leases are primarilysmall, scattered leases with poor qualityreserves that are unlikely to be devel-oped.

Figure 12.— Dilligent Development Summary for thePowder River Basin

The Powder River Basin Montana portion of the73 Leases Powder River Basin38 Lease blocks ! 15 Leases9.2 Billion tons of recoverable I 8 Leaseblocks

reserves under Federal lease I 0.9 Billion tonsI /I /

Wyoming portion ofPowder River Basin

58 Leases30 Leaseblocks8.3 Billion tons

the

PercentKey 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 summarizethe results of OTA’s diligent development an-alysis for the Southern Rocky Mountain re-gion (Colorado, Utah, and New Mexico) andfor the Powder River basin.

Figure 13.— Diligent Development Summary for theSouthern Rocky Mountain Region

(Colorado, New Mexico, and Utah)

Number Percent Percentof of of

Key leases leases Reservesa reserves

■ Likely to meetdiligence by 1986 136 28 2.0 34

■ Likely to meetdiligence by 1991 15 4 0.3 5

a Billions of tons.


Powder River Basin

The Powder River basin is particularly im-portant to Federal coal development becauseit contains over one-half the recoverable re-serves under lease, accounts for about one-half the coal produced from Federal mines,contains the largest pool of Undeveloped

leased Federal coal reserves in the UnitedStates, and has the largest market area ofany Western coal-producing region. Federalmines accounted for 88 percent of mine ca-pacity in the Powder River basin in 1980. ThisPercentage is projected to remain relatively— ,

Ch 1—Executive Summary ● 23

constant throughout the decade. However,production from the leases themselves is pro-jected to increase from less than 40 percentof total coal production in the basin in 1979 toapproximately 80 percent in 1991. *

A number of projections for this region sug-gest that the most likely range of demand forPowder River basin coal in 1990 will be 200million to 225 million tons per year (see fig.14), The Department of Energy (DOE) interimmidrange production goal of 275 million tonsper year is probably high.**

Contracts already exist for delivery of 186million tons per year of Powder River basincoal in 1990. Of this amount of contractedcoal production, 159 million tons is from cur-rently producing mines with Federal leases,10 million tons is from non-Federal mines,and 17 million tons is from presently undevel-oped Federal leases,

For 1990, lessees and non-Federal mine op-erators have plans to produce a total ofnearly 100 million tons per year more thanthe presently contracted level for that year.Production plans for 1990 total 280 milliontons per year; of this amount, 215 million tonsis from currently producing mines with Fed-eral leases, 10 million tons is from non-Fed-eral mines, and 55 million tons is from pres-ently undeveloped leases which have favor-able production prospects for 1990 understrong market conditions. Only 6 million tonsof this production is contingent on synfuelsdevelopment.

Mine design capacity planned by lesseesand non-Federal mine operators for 1990 isconsiderably higher: 348 million tons peryear. Mine design capacity is an upper limitto long-term production levels that can bereached with a leadtime of a year or so. Cur-rently operating Federal mines are scheduledto reach 97 percent of mine design capacity

*’I’hc pcrmntt~gc of F’cdcrt]l UI;II pr(du(lion will lx: ICSS Ih;lnth(! perrentagc of F’ecferal m i n e r:]p:]ritf. t)wause l-’e(ier:~lm 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 ( I l l 011 l)])

169-173 and I ig. 34. S[w also [jp 100-102 for a (1 is(llssion of theI) OF: find [)ro(iu(:tion goal+

by 1991. Therefore, given sufficient marketdemand, production levels of close to 350million tons per year are attainable in theearly 1990's from currently operating minesplus good quality properties currently beingactively developed.

These levels of capacity and production de-pend on all plans being realized for bothFederal and non-Federal properties, If only

11 out of the 17 undeveloped properties con-tributing to this projection are developed,total design capacity could be reduced by upto 60 million tons per year; total design capac-ity would then be 290 million tons per year.Nevertheless, planned capacity in the Pow-der River basin seems likely to be adequate tomeet demand into the early 1990's.

Potential capacity in the post-1990 periodis considerably more difficult to estimate, asis potential demand. An additional 155 mil-lion tons per year of capacity could perhapsbecome available in the post-1990 periodfrom undeveloped Federal leases, PRLAs andnew non-Federal mines. About 70 million tonsper year of this capacity would be suitableonly for onsite development because of lowcoal quality, This amount ( 155 million tonsper year) should be considered an upper limitrather than a likely value of additionalpost-l990 capacity without additional leasingof Federal coal. For the post-1990 period, de-mand projections become very uncertain, TheDOE preliminary midlevel production goals,the ICF CEUM* midlevel production forecastand the DOE midlevel final production goalsfor 1995 for the Powder River basin are 382,306, and 491 million tons per year, respec-tively. The DOE final production goal. 491million tons per year. reflects several policiesabout increased coal use (e. g., coal for syn-fuels), that cause the number to be higherthan other forecasts. Although all demandprojections past 1990 should be regarded asvery uncertain, the lower numbers above are,as of now, more likely to be realized.

The potential for continued high overca-pacity in the Powder River basin has caused

* See footnote on fig. 14 for citation.


Figure 14.—Comparisons of Powder River Basin Demand Projections WithPlanned Capacity and Production Levels for 1990

(Prelim.)

High

(Final)

\

Base

PPrelim.)

~

(Final)

- L o w

(Prelim.)

CEUM

High

Demand projections and goals1990

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 (LaramieWestern Coal Production, Prepared for Rocky Mountain Energy Com-pany, (ICF Incorporated; Washington, D. C.: November 1980), DOE:

Sebesta: Demand for Wyoming Coal 1980-1991 Based Upon Protected UtilityCoal Market and Demand for Montana Coal 1980-1991 Based UponPrptected Utility Market (Washington, D. C.; Office of TechnologyAssessment: October 1980).

Wyoming Task Force; Result of deliberations of the Off Ice of TechnologyAssessment Wyoming Task Force; Cheyenne, DOE:Wyoming. October 1980.

Silverman: Preliminary results from A. Silverman, University of Montana,Missoula. Private Communication to Office of TechnologyAssessment.

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, 1980Report Entitied: “Preliminary National and Regional Coal ProductionGoals for 1985, 1990, and 1995, prepared for the Rocky MountainEnergy Company, (ICF Incorporated; Washington, DC.: October 1980)

The 1980 Biennial Update of National and Regional Coal ProductionGoals for 1985, 1990 and 1995. U.S. Department of Energy (WashingtonD.C., January 1981).


questions to be raised about the timing, ex-tent and location of renewed large-scale leas-ing under the Federal Coal Management Pro-gram. The debate focuses on the role of com-petition and the free market in resource sup-ply, the potential costs to the social andphysical environments of the coal producingareas of “overleasing,” the length of timeneeded to bring a new lease into full-scaleproduction, the margin of supply safetyneeded for prudent planning on a nationaland corporate level, questions of equityraised by restricted opportunities for new en-trants to Federal leaseholding, a fair returnto the public for use of its resources, and thelevels of likely demand in the early to mid-1990’s,

Many proponents of large-scale new leas-ing in the Powder River basin in the nearfuture cite the long moratorium on such leas-ing and its effect of restricting entry possi-bilities to leaseholding as one reason forprompt resumption. They also contend thatpostponing leasing will unduly interfere with

Factors Affecting FederalFederal Coal

There are a number of market, environ-mental, legal and regulatory, transportation,and socioeconomic factors thatFederal lease development andtion.

Market Factors

could affectcoal produc-

Most energy forecasts predict that the ma-jor Federal coal States in the West will at-tract larger shares of the total coal marketover the next 10 years. Several studies pro-ject that Western coal, which supplied 28percent of the 1979 U.S. demand, will supplyas much as 49 percent of the market by1990. *

the workings of the free market and will re-strict competition. They anticipate high de-mand for coal by 1995 and fear that the pres-ent leased reserve base in the Powder Riverbasin will not provide enough certainty orflexibility to meet that demand efficiently.Opponents of large-scale new leasing in thePowder River basin as scheduled in 1982 citethe potential for overcapacity through theearly 1990's as proof that such leasing is notnecessary at this time. They contend thatleasing can be safely deferred until its neces-sity is clearly indicated by realistic demandforecasts. They hold that large-scale leasingsubstantially beyond that necessary to meetlikely demand in 1990 will place an unnec-essary strain on orderly planning in the com-munities of the region, shift demand to thePowder River basin that could have been metby Midwestern supply, depress the value ofleases so that the public will not receive a fairreturn for its resources, and, moreover, beunlikely to increase competition significantly.

Lease Development andProduction

Many factors will influence the demand forWestern coal and the competition betweenWestern coal States for markets, but threeare particularly significant: demand by do-mestic electric utilities, growth of new non-utility markets, and transportation avail-ability y and cost.

The principal markets for Western coalare utilities in the Western coal-producingStates, the Midwest, and the SouthcentralStates. The electrical growth rates in theseregions will probably be the single most im-portant factor affecting demand for Westerncoal. Also, growth rates and fuel preferencesof utilities for new plants in regions such asCalifornia, which currently do not burn coal,and the extent of conversion of existing oil- orgas-fired powerplants to coal will shapeWestern coal demand. The present new


source performance sulfur dioxide (S0 2)emission standards, which require sulfurreduction of all coals (thus, reducing the costadvantage to utilities of burning low-sulfurcoal), and the decline in electrical growthrates in recent years suggest that the growthin Western coal demand might not be as highas some earlier forecasts had predicted.

New nonutility markets could increase thedemand for Western coal, These include for-eign coal users, particularly Japan, and theincipient domestic synfuels industry, al-though neither is likely to substantially affectWestern coal demand before 1990. Moderateincreases in industrial coal use could in-crease demand for Western coal somewhat.

Access to reliable, efficient, and low-costtransportation is critical to the success ofWestern coal producers in selling to out-of-State coal markets. In all Western coalregions, coal transportation costs are in-creasing, Because these costs can account forover 70 percent of the delivered price of coalin out-of-State markets, the competititiveposition of Western coal in these markets isnot likely to be as favorable in the next 10years as it was in the previous 10 years.

Environmental Factors

Because almost all Federal coal reservesare located in the Western United States, theenvironmental and reclamation concernsabout Federal coal development are largelythose characteristic of Western coal mining.The dominant issues include concern aboutfugitive dust and its impact on the good tovery good air quality of the West, the effect ofmining on the sparse water resources of theregion, the ability to revegetate mined areaswith semiarid and arid climates, the effect ofvarious spoil handling and recontouring re-quirements on the ability to mine coal, the ef-fect of mining and associated populationgrowth on the region’s wildlife populations,and the effect of mining on the region’s ar-cheologic resources.

Several important laws and regulationshave been adopted to deal with these con-

cerns, The effect of these regulations onFederal coal production has been to removesmall amounts of minable coal from the re-coverable reserve base, to delay developmentof other recoverable reserves, to increase thecomplexity of the mine permit process, and toincrease the overall cost of mining, The per-centage of recoverable Federal reserves cur-rently under lease that may be prohibited, orsubject to delay from mining over the next 10years because of environmental regulationsis between 5 percent and 10 percent of thetotal currently leased reserves.

Less than 1 percent of currently leasedFederal reserves appear likely to be subjectto complete prohibition from mining. The re-mainder of currently leased Federal reservesthat may be affected may be subject to delaysin mining because of unresolved environmen-tal questions, but the available evidence in-dicates that most of these reserves will bemined. There are additional leased reserves(mainly in the Kaiparowits Plateau in south-ern Utah) over which there are potential envi-ronmental conflicts, but impediments to de-velopment of these reserves are primarilyrelated to nonenvironmental factors such astransportation availability. These estimatesof Federal leased reserves adversely affectedby environmental requirements are con-siderably lower than earlier estimates by DOIwhich indicated that as much as 10 percentof leased reserves might not be developed be-cause of environmental considerations.

The Surface Mining Control and Reclama-tion Act of 1977 (SMCRA) addresses most ofthe concerns about the environmental effectsof Western coal mining. The act establishesperformance standards for mining and recla-mation and criteria that must be met beforemining permits can be approved. The act isadministered in the West largely by theStates, with oversight responsibility remain-ing with OSM. Various other statutes, such asthe Clean Water Act, the Clean Air Act, andlegislation to protect wildlife also affect coalmining operations. Also, the Federal LandManagement Policy Act included environ-


mental provisions in the Federal coal leasingprogram,

The coal mining industry has severly criti-cized the regulatory programs generated bythese statutes. Criticism has centered onoverlapping and inconsistent regulations,problems with enforcement, excessive paper-work requirements, and increases in thecosts of mining and in the time needed todevelop mines,

This report does not evaluate the issues ofcost or the lengthened development process

caused by regulations nor does it evaluate theextent to which recoverable Federal reserveswill be affected by environmental concernsunder the renewed Federal coal leasing pro-gram. However, this report does examine theamount of currently leased Federal coal thathas been or that may be prohibited from de-velopment or subjected to extra delay fromrecovery. Table 4 summarizes the results ofthis analysis.

Air-quality concerns. North Dakota coal islignite, which is uneconomical to transportover any distance and which must therefore

Table 4.—Summary of Impacts to Federal Recoverable Reserves FromEnvironmental and Reclamation Considerations

Federalreservesaffected’

Location of (millionsIssue area Specific issue affected area of tons) Effect 2

Air resources Expansion of mine production rate in a Rosebud Mine, 1.5 ret/ynon-attainment area Colstrip, Montana after 1985

or about30 mt ofreserve

U3, effect would beto limit productionrate, not prohibitany mining areas

Permitting of additional power plants West Central <1oonear class 1 area where SO2 levels for ex- North Dakotaisting and permitted but not constructedfacilities are currently predicted to be atmaximum PSD level. The additionalpower plants would be fueled by lignitemines in the vicinity.

Lands unsuitable Impacts of coal mining will damage Alton Coalfield, 24for mining important aesthetic values of Bryce Southern Utah

Canyon National Park

Water resources Subsidence of mine will divert surfaceand ground water and adversely affectother uses

Mt. Gunnison MineWest Central Colorado

Alluvial Valley floor (AVF) in areassignificant to farming

Developed mines with stream valleysunder study as potential AVF wheremine plan development has beendelayed

Designated AVF in developed mines.Valleys not significant to farming. Mineplan development affected

CX Ranch leases Mon-tana portion of thePowder River basin

Powder River basin,Buckskin, and SpringCreek mines

Powder River basin,Eagle Butte, Rawhide,Coal Creek mines

U4, improved airquality modellingtechniques beingdeveloped

A p5-on portion ofproposed mine areadesignated asunsuitable; restof leaseholdunaffected.

23 U, approval likely ifmine will buy orreplace seniorwater rightsaffected. 6

<100 Ap uncertain7

95 D, mining of valleysexpected 8

61 U, mining of valleyexpected 9

.


Table 4.—Summary of Impacts to Federal Recoverable Reserves From Environmental andReclamation Considerations—Continued

Federalreservesaffected 1

Location of (millionsIssue area Specific issue affected area of tons) Effect2

—

Potential alluvial valley floors which ex- Powder River basin, 240 U, mining of valleysisted 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 BlackThunder mines

Potential AVFS in undeveloped coal Powder River basin 219 U, mining of mostlease areas valleys expected8

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

and protection Green River-Hams Forkof 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 D11

woody draws Central North Dakota1Total Federal reserves under lease are 16,500 million tons.2Ap-absolute prohibition; D-delay in approval, U-unresolved.3Jurisdiction lies with the Montana Department of Health and Environmental Sciences4Jurisdiction lies with the North Dakota State Department of Health.5Decision made by the Department of the Interior, 1980. Decision under appeal to Federal courts6Jurlsdtction Iies with Colorado Department of Natural Resources and U.S. Office of Surface Mining7Under 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 significantto farming. The lessee has asked the department to reconsider its decision.

8Jurisdiction lies with Montana Department of State Lands (Spring Creek) and Wyoming Department of Environmental Quality (Buckskin)9Jurisdiction lies with Wyoming Department of Environmental Quality

10Lead decision made by OSM11Permit 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 orsynfuels facilities. Permitting of additionalcoal conversion facilities in west-centralNorth Dakota is currently being delayed,pending further information on the effect ofexisting and permitted plants on the air qual-ity of nearby Theodore Roosevelt NationalPark.

Additional Federal coal development couldbe affected by possible fugitive dust prob-lems. At Colstrip, Mont., where fugitive dustlevels presently exceed ambient air stand-ards, future mine expansion will have to ad-dress and minimize air impacts.

Lands unsuitable for mining. In Utah, 24million tons of Federal coal have been re-moved from mining because of adverse im-pacts on nearby Bryce Canyon National Park.The remainder of the leased surface minablereserves in the area, about 270 million tons,

are unaffected by the decision. The decisionhas been challenged in Federal court.

Water resource concerns could affect over700 million tons of Federal recoverable re-serves. However, less than 100 million tonsmay be prohibited from mining. These re-serves are located beneath an alluvial valleyfloor significant to farming and thus can beabsolutely prohibited from mining underSMCRA. * Alluvial valley floor concerns mayaffect another 600 million tons; however min-ing of these reserves is likely, with especiallystringent reclamation standards applied. De-velopment of over 20 million tons may hingeon purchase or replacement of senior waterrights that could be affected by mine sub-sidence.

*The Montana Department of State Lands has ruled that thealluvial valley floor in question is significant to farming. Thelessee has asked the Department to reconsider its decision.


Spoil handling and protection of raptorhabitat* have removed 5 million tons of Fed-eral recoverable reserves from mining insouthern Wyoming. Spoil handling concernscould affect perhaps as much as another 50million tons in southern Wyoming and north-ern Colorado. Development of 29 million tonshas been delayed in west-central NorthDakota because of concerns about reclama-tion of wooded draws.

In summary, approximately 1 billion tons ofleased Federal recoverable reserves out of16.5 billion tons of leased Federal recover-able reserves have been or could possibly beaffected in the following ways by environ-mental laws and regulations:

29 million tons have been absolutely pro-hibited from mining;up to another 100 million tons may be ab-solutely prohibited from mining;124 million tons have been delayed in theapproval process;573 million tons could be affected or de-layed but approval is likely; andup to another 150 million tons could beaffected or delayed and approval isuncertain.

Several reclamation issues where furtherdata are needed or where regulatory deci-sions have yet to develop a clear pattern,such as the long-term success of revegetation,the hydrologic effects of mining, and the abil-ity to achieve approximate original contour,have not yet resulted in any prohibitions tomining but could become important issues inthe future. The long-term success of reclama-tion in the West is still unproven, but reg-ulatory authorities have approved continuedmine expansion based on the short-term suc-cess achieved to date.

Laws and Regulations on Managementof Existing Federal Leases

The development of existing Federal coalleases may be affected to varying degrees bythe resolution of the following legal issues:

*Especially eagle habitat.

●

●

●

●

application and enforcement of diligentdevelopment requirements;exchange of lease and PRLA reservesfor unleased Federal coal;processing of pending PRLAs; anddesignation of areas unsuitable for sur-face mining under SMCRA.

Diligent Development

Under current regulations, leases issuedbefore passage of the Federal Coal LeasingAmendments Act of 1976 (FCLAA) (pre-FCLAA leases) that do not produce 2 l/z per-cent of the lease’s logical mining unit re-serves by June 1, 1986, can be canceled, Ex-tensions to this diligence deadline may begranted by the Secretary of the Interiorunder certain circumstances; however, lackof markets is not solely a basis for extensions.Leases issued after August 4, 1976 (post-FCLAA leases) will be terminated automat-ically if they do not produce coal in com-mercial quantities within 10 years after thelease is issued. Section 3 of FCLAA (30 U.S.C.201(a)(2)(A)) also provides that, with a few ex-ceptions, after August 4, 1986, no new leasescan be issued to any lessee who is still holdinga coal lease from which he has not producedcoal for 10 or more years.

The current regulations defining dili-gence as actual production of coal werefirst promulgated in May 1976 in responseto concerns over the large amounts of Fed-eral coal that had been leased in the 1960’sduring a period of declining Federal coalproduction.

Since May 1976, the diligence regula-tions have been modified slightly to in-clude provisions required by FCLAA andminor editorial clarifications, b u t t h eproduction requirements for pre-FCLAAl e a s e s h a v e r e m a i n e d v i r t u a l l y u n -changed. *

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

*In 1977, the Department of Energy organization” Act trans-ferred the Secretary of the Interior’s authority to establish dil-igence requirements and minimum production rates for Feder-al 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 ofothers will not and prospects for some re-main uncertain. (See Diligent Developmentsection on p. 21, ) Since the current diligencestandard could change within the broad lim-its set by statute as a result of policy redirec-tion or court decisions, it is difficult to pre-dict the precise impact of diligence require-ments on pre-FCLAA leases.

DOI’s diligence standard requiring produc-tion of coal on existing leases within 10 yearswas opposed by mining industry trade groupsand many lessees. Legal challenges by lesseesto the reasonableness of the regulations andtheir applicability to pre-FCLAA leases arelikely.

The impact of diligence requirements onpre-FCLAA leases will depend on the interac-t ion of many factors besides the legal prece-dents that may be established on the appli-cability of the regulations. These factors in-clude: 1) the extent of voluntary complianceby lessees; 2) how many extensions to the1986 deadline are granted; 3) how many ex-isting leases are combined with other leasesor non-Federal coal reserves to meet dili-gence by forming an approved LMU; 4) howLMU reserves are defined for each lease: 5)the extent to which leases are readjusted onschedule; 6) the extent of effective enforce-ment of the 1976 regulations by DOI and theDepartment of Justice; and 7) how many non-producing leases are relinquished,

Exchanges

Because of requirements in FCLAA that allnew leases must be offered by competitivebid, the possibilities for trading new Federalleases for Federal leases where mining posesproblems is limited to exchanges specificallyauthorized by Congress and to leases in allu-vial valley floors where mining is prohibitedby SMCRA. The congressionally authorizedexchanges would offer unleased Federal coalfor relinquishment of certain existing leasesin Wyoming and New Mexico and PRLAs inUtah, and for contested leases on Indianlands in Montana, Exchanges of non-Federal

coal lands in alluvial valley floors that cannotbe mined for available Federal coal reservesis also authorized under SMCRA. Generally,to be approved by DOI, the tracts exchangedmust be approximately equal in value and theexchange must serve the public interest. Ex-changes can thus offset possible losses in coalproduction from areas that cannot be mined.

Preference Right Lease Applications

Processing of the 176 PRLAs over the next3 years will confront several legal, adminis-trative, and procedural issues before the po-tential for coal production from pending ap-plications will be known. Among the ques-tions to be resolved are: 1) how many PRLAswill be affected by conflicting mining claims,2) how many rejected prospecting permitsand PRLAs will be reinstated on appeal, and3) how many PRLAs will fail to meet the morestringent commercial quantities test for dis-covery of a valuable deposit. The productionpotential from PRLAs could range from 35million to 60 million tons per year in the1990’s, depending on the extent that legal,planning, and environmental considerationsaffect the issuance of preference rightleases. * This is considerably less than earlierestimates made by DOI on production poten-tial from PRLAs but still represents a signifi-cant contribution from Western coal in the1990’s.

Areas Unsuitable for Mining

Section 522 of SMCRA allows DOI to des-ignate areas on Federal lands as unsuitablefor mining. Two petitions affecting Federalcoal have been filed. One petition involvingexisting leases in southwestern Utah hasbeen decided, In December 1980, the Sec-retary of the Interior declared 8 percent ofthe leased surface minable reserves in theAlton area (about 24 million out of 290 milliontons) as unsuitable for mining because of ad-

*This range includes about 10 million tons of PRLA produc-tion rapacitv ass(mia ted with new mines on exislln~ E’wicralle[ises. Addili(m:il PRI,A prlxiurlit)n is p(wsihle from PR1,As InWI St e rn 0)1( )ra(io o nd \4’\oming i f :] vt?rv s [ rt mg (iomo n(i ii risesfor (>(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 Na-tional Park. The Secretary found that miningactivities would significantly reduce visibilityand scenic vistas from park overlooks and in-crease noise levels in the park, damaging thevalues for which the park was establishedand the experience of the park’s visitors. Thedecision has been challenged in Federal courtin Utah by both the environmental groupswho brought the petition and by the Altonlessees.

The second petition submitted jointly toOSM and the State of Montana involves inter-mingled Federal, State and private lands inthe Tongue River area of Montana, The peti-tion area does not cover any existing Federalleases but does include the non-FederalMontco Mine with a proposed capacity of 12million tons per year as well as areas underconsideration for the 1982 Powder Riverregion coal lease sale.

Transportation Considerations

The two most important modes of trans-porting Western coal in 1979 were by railand wire. Railroads originated more than 60percent of all Western coal production in1979. Most Federal coal was hauled by rail toutilities. Mine-mouth and other nearby gen-erating plants use locally mined coal and dis-tribute it as electricity through high-voltagetransmission lines.

Other transport modes are currently lessimportant to Western coal production. Onlyone coal slurry pipeline presently operates,It has a 4.8-million-ton-per-year capacity.Trucks handle about 15 percent of Westerncoal tonnage, mainly for local markets inUtah and Colorado. About 2 percent of West-ern coal is moved by rail to port terminals onthe Great Lakes, and another 4 percent toriver connections, About 23 percent wasmoved by tramway, conveyor, or privaterailroad.

The Western rail transportation networkhas the ability to increase its capacity tomove coal from mine to market during the1980’s and 1990’s. Most Federal coal leases

are and will be served by rail. The mine-to-market transportation cost of Western coalranges from about 10 percent to over 70 per-cent of delivered fuel costs and constitutes animportant factor in determining future de-mand. The existing rail transportation net-work in the West was generally adequate tomove coal production from Federal leasesand private tracts in 1980, although a num-ber of specific bottlenecks have been identi-fied. The principal constraint that mightmaterialize in moving leased coal to itsmarkets is the willingness of the railroads toinvest sufficient capital in time to satisfy de-mand for increased rail service from all ship-pers, including Federal coal,

Increasing amounts of Federal coal arelikely to be burned at nearby powerplantsand the electricity transmitted by wire. How-ever, plans for construction of powerplants inthe West to export electricity must considerair quality standards, competition for water,and possible opposition to granting of rights-of-way for high-voltage transmission lines.These plants are attractive to utilities whichown both the generating plant and distribu-tion system and, thereby, become independ-ent of other carriers. Various studies havereached different conclusions regarding therelative cost efficiency of rail v. wire trans-portation.

Although coal slurry pipelines have notplayed a significant role in coal transportationto date, a number of slurry pipelines areplanned or proposed. Nearest to constructionis the Energy Transportation Systems Inc.line that is planned to ship 25 million tons peryear of Powder River basin coal to Oklahoma,Louisiana, and Arkansas. OTA found in anearlier study* that:

. . . [coal slurry pipelines] . . . do representunder some specific circumstanecs the leastcostly available means for transporting coalmeasured in economic terms.

*Office off Technology Assessment, U.S. Congress. CoalSlurry Pipelines, Summary, Washington, D.C., U.S. Govern-ment 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)(JISl~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.


This report also stated that:

. . . the introduction of coal slurry pipelines isnot likely to affect materially the rate of coalresource development and use on a nationalscale. It may, however, affect the regionalpattern of coal mining and distribution insuch a way as to expand the use of Westerncoal to greater distances from its area oforigin,

Revenues and SocioeconomicConsiderations

Energy development, including recentlarge-scale coal mining, has frequentlybrought rapid growth to Western ruraltowns. Many communities have been hardpressed to deal with the sudden influx of peo-ple. Typically, they have found themselvesshort of housing, municipal services, healthcare facilities, and other elements of anextensive community infrastructure. Sometowns have shown symptoms of social disrup-tion, such as increased crime, alcoholism andsuicide, and of economic dislocation, such aslocal business failures and labor shortages.

The communities have had varied degreesof success in coping with these boomtownproblems. Mitigation is complicated becauseit is hard to anticipate which towns are apt tohave severe difficulties. Both public and pri-vate sectors are engaged in preventive ef-forts; industry actively participates because

successful mitigation helps stabilize its workforce.

The ability to solve the problems is ham-pered by a lack of timely revenues; expandedfacilities and services are needed before newlocal taxes are available, Planning and con-struction must start in the early stages ofrapid growth, but this is before mines orother industries come on the local tax rolls.Several ways have been used to meet theearly costs. These include State revenuemechanisms, such as severance taxes, andprivate contributions, such as the prepay-ment of taxes. The States’ share of Federalmineral leasing revenues can be used, butthese payments do not increase substantiallyuntil coal is produced. Consequently, Stateand local governments have looked to otherFederal programs for assistance.

Each Western State (except Alaska) re-ceives 50 percent of the revenues from min-eral leases of public lands in the State. Thesefunds are distributed according to prioritiesset by each State legislature. Section 10 ofFCLAA directed OTA to provide an estimateof future rentals and royalties from existingFederal coal leases. Based on potential pro-duction and expected coal prices for each re-gion, OTA has derived estimates for 1986 and1991. Table 5 shows the current allocationand estimates by State. The estimates indi-cate a substantial increase over the amount

Table 5.— Federal Royalties and State Distributions From Potential Coal Production on Federal Leases1980 (actual), 1986, and 1991 (estimated)

1 9 8 0a –—

1986b 1991 b —

Federal leaseproduction(millions of

State tons)

Colorado . . . . . . . . . . . . . . 9.4Montana . . . . . . . 10.4New Mexico. . . . . . . . . 6.3North Dakota. . . . . . . . 0.6Utah . . . . . . . . . . . . . . . . . . . . 8.7Wyoming . . . . . . . . 33.4

Royalty Statetotal share

(millions of dollars)

8.9 4.52.7 1.3

3.5(0.3) 04.5 4.4


tons)

2723-31

9-11about 6

26113-150


(millions of dollars)-

49 2421-27 10-1415-16 7-8

about 4 248 24

57-71 28-36


tons)

33-4025-4012-16C

634-66

133-238


(millions of dollars)

78-94 39-4723-37 12-1921-28C 11-14C

5 264-122 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 coalcExcludes about 8 million tons of Federal PRLA production and about $15 million in PRLA royalties.

SOURCE: Off Ice of Technology Assessment.


of revenues distributed in 1980, These rev-enue increases come primarily from ex-panded Federal production and readjust-ments to the higher royalty rates required byFCLAA,

There is, however, considerable debateover whether existing private and govern-mental programs will be adequate to meet thefinancing 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 ruralindustrialization (such as synfuels and pow-erplant development) are occurring, couldstrain the capacities of communities in thePowder River basin, the western slope of Col-orado, central and southern Utah, and theSan 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3838

40

40

41

43

44

CHAPTER 2

Background and Introduction

The Federal Government owns between 50and 60 percent of the coal reserves west ofthe Mississippi River. Over 16 billion tons ofthese Federal reserves are currently underlease, * In 1979, coal production from leasedFederal land was about 60 million tons. AsWestern coal production expands to meetnew demand, the development of Federalleases will become increasingly important.

Since 1920, the Department of the Interior(DOI) has administered a leasing programthat allows the private sector to mine coal onFederal lands, A lease grants to the lessee theexclusive right to mine coal subject to theterms of the lease and to State and Federallaws. Historically, leases have been issued bytwo methods; 1) competitively, to the highestbidder at a lease sale and 2) noncompeti-tively, through an application process called“preference right leasing, ” to prospectorswho discovered commercial coal reserves onFederal land, About half of all existing leaseshave been issued by each method. The Fed-eral Coal Leasing Amendments Act of 1976(FCLAA), which abolished the preferenceright system, requires competitive leasing ofFederal coal.

In 1970, a Bureau of Land Management(BLM) study of the Federal coal leasing pro-gram found that from 1955 to 1970 theamount of coal under lease had increasedsharply while the amount of production fromFederal leases had declined. (See fig, 15 inch. 3,) In response to this study, BLM imposedan informal moratorium in 1971 on the issu-ance of new leases. The purpose of this mora-torium, which was made formal in February1973, was to provide time to reassess Federalcoal leasing policies. Over the next severalyears a number of issues were examined dur-ing 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 Fed-eral coal reserves in the West.

Public concern and debates about theseissues and about the structure and manage-ment of the leasing program led to con-gressional hearings and to passage of FCLAA(Public Law 94-377). Section 10 of this actdirects the Office of Technology Assessmentto conduct an independent review of existingFederal coal leases. Specifically, the actdirects OTA to:

● analyze all mining activities on Federalcoal leases;

• determine the present and potential val-ue (production) of Federal coal leases;

● estimate the Federal receipts from leaserentals and royalties: and

• assess the feasibility of using deep-mining technology in leased areas.

To meet these requirements, OTA com-pleted a comprehensive inventory of Federalcoal leases, which identifies the location ofeach lease, its major geotechnical character-istics (e.g., amount and quality of coal, depthand thickness of the coal seams), and thebusiness experience and capability of thelessee. After completing this inventory, OTAanalyzed the development potential and pro-duction prospects of the 565 Federal coalleases in existence on September 30, 1980. *OTA estimated the mine design capacity andannual production that these leases couldsustain from 1980 to 1991, considering themining and reclamation conditions antici-pated on the leases and the market condi-tions, environmental, transportation, legal,and institutional factors affecting their devel-opment. In addition, OTA analyzed the pros-pects for increasing coal recovery by un-derground methods on Federal leases andestimated the revenues from present andpotential production.


Scope of the Assessment and MethodologyThere are currently 565 Federal coal

leases and over 170 pending preference rightlease applications (PRLAs) in 14 States. Thisreport focuses on the leases in Colorado,Montana, New Mexico, North Dakota, Okla-homa, Utah, and Wyoming. These sevenStates account for 97 percent of the existingleases and over 99 percent of the leased re-coverable reserves (16.5 billion tons). OTAdid not examine the development potentialand production prospects of unleased Feder-al coal reserves, proposed new leasing tracts,or the small quantity of reserves under leasein Alabama, Alaska, California, Kentucky,Oregon, Pennsylvania, and Washington.

Coal leases in this report are classified ac-cording to their mine plan status on Sep-tember 30, 1980. Submittal of a mine plan isan important milestone in lease development.DOI must approve a mine plan before a lesseecan mine coal from Federal land. Each mineplan details the development plans of thelessee, includes technical information on theresource characteristics of the lease(s), anddescribes the proposed mining operation. Ac-cordingly, OTA grouped the leases in threecategories of development: 1) leases with ap-proved mine plans; 2) leases with mine planssubmitted and pending approval; and 3)leases with no submitted mine plan. Leaseswithout mine plans are called “undeveloped”leases in this report.

Evaluation of the development potentialand production prospects of existing Federalcoal leases and PRLAs involved extensivedata collection and analysis. Developmentand production of Federal coal will depend ona variety of property characteristics, includ-ing: 1) the quantity and quality of reserves, 2)the geological features of the coal deposits, 3)the size and configuration of the leases (coalleases vary from 40 acres to more than20,000 acres and are often interspersed withnon-Federal coal), and 4) environmental, min-ing, and reclamation conditions. The miningexperience and capital resources of the les-see are also important to consider in esti-

mating the development potential and pro-duction prospects of a lease. The productionprospects of many Federal leases will also de-pend on other factors including the level ofdemand and location of markets for Westerncoal, the impacts of State and Federal pol-icies and regulations, and the availability oftransportation.

Information Sources

OTA obtained information from a varietyof sources, including: 1) Federal and Stategovernment agencies; 2) special studies; and3) interviews and special State task forces.

Federal and State Government Agencies

In addition to the mine plans submitted bythe lessees and the lease records, two impor-tant sources of technical data used in thisstudy, especially for the analysis of undevel-oped leases, are the Automated Coal LeaseData System (ACLDS) and the informationsubmitted by lessees under General MiningOrder No. 1 (GMO No. 1).

ACLDS is a computer-based inventory ofFederal coal leases and lease applications.The system is managed by BLM and is up-dated every 6 months. The purpose of ACLDSis to store in a readily accessible format arange of technical and administrative infor-mation on every existing lease. The system isstill being developed and both the quality andamount of information vary among leases.The U.S. Geological Survey (USGS) is cur-rently revising the reserve information foreach lease in ACLDS, integrating the informa-tion on mining methods and conditions ac-quired by USGS officials and geophysicaldata from its files with data prepared undercontract and with each lessee’s submittalunder GMO No. 1.

GMO No. 1 establishes a standard proce-dure for estimating in-place, minable, and re-coverable reserves. The order also requiresthe lessee to submit other information on a

Ch. 2—Background and Information ● 3 9

lease such as overburden thickness, strippingratio, and seam thickness according to uni-form reporting criteria. GMO data are re-viewed and processed in regional offices ofUSGS. Because there are differences in theinterpretation of this data among USGS of-fices, the process of developing a uniform,comprehensive data base for Federal coalleases is still continuing. When GMO datawere not available, OTA was often able to ob-tain information on coal reserves from thelessees themselves or from regional environ-mental impact statements (EISS), other pub-lished sources, or independent calculations.

Special Studies

In addition to reviewing numerous pub-lished and unpublished reports on Westerncoal development and Federal coal leasing,OTA conducted several special studies tosupport the assessment, These include:

● Ownership study, Analysis of ownershiptrends of Federal coal leases that identi-fies and classifies the types of businessorganizations that have acquired Fed-eral coal reserves from 1950 to 1980.1

● PRLA study. Review of the history ofpreference right leasing, the location ofexisting PRLAs, and the ownership pat-terns and business organizations of theholders of PRLAs.

● Mine development study. Review of themajor geotechnical and economic fea-tures of coal mining in the seven West-ern States covered in this assessment.“Mine profiles” are developed for eachregion.

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

●

●

Market studies, Analysis of the likelymarkets for coal produced in Wyoming,Montana, Colorado, and Utah, and of thefactors that are expected to affect de-mand for this coal in the 1980’s.Synthetic fuels study. Analysis of thecoal quality requirements an-d technicalissues affecting potential development ofcoal-based synthetic fuels projects in theWestern United States.

Interviews and Task Forces

OTA conducted personal and telephone in-terviews with representatives of coal com-panies, industry associations, Governmentagencies, and technical and policy special-ists. OTA also convened five State task forcesto assess the development potential of unde-veloped Federal leases in Colorado, NewMexico, Oklahoma, Utah, and Wyoming andto review the factors affecting coal develop-ment in these States. These task forcesbrought together participants from Federaland State government agencies, industry, en-vironmental groups, and the general tech-nical community. * The results of task forcedeliberations contributed to the six OTAState reports, which assessed the develop-ment and production prospects of undevel-oped leases and analyzed the factors affect-ing Federal coal development in each of theseven States.**

*A complete listing of the task force participants is at thefront of this report.

**Six State reports were prepared. Reports on the undevel-oped 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 developedand undeveloped leases. These reports will be availablethrough the National Technical Information Service.

4 - : 1, ‘ — ,. - 1.


—

Analysis of Leases in Mine Plans

The primary source of information used toestimate potential production for leases in ap-proved or pending mine plans was the mineplan itself.

Some of the important mine plan data re-viewed by OTA include:

●

●

●

quantity and quality of the reserves,total permitted and total disturbed acre-age, seam thickness, and depth of over-burden;mining and reclamation methods, permitrequirements, and pending regulatoryactions;mine design, anticipated resource re-covery rates, peak capacity of the mine,and the lessee’s estimated annual pro-duction from 1981 to 1990.

After reviewing this information, OTA pre-pared a summary of each mine plan that iden-tifies the location, size, and type of the miningoperation; the Federal leases, and the Stateand private lands in the mine plan or contigu-ous with or close to the mining area; surfaceownership; and the quality and quantity ofthe coal reserves.

The summary also identifies the geological,environmental, and mining conditions that

could potentially increase or decrease the re-coverability of the coal reserves at the mine.The summary also considers the complete-ness of the mining plan, the status of geo-logical exploration and monitoring activitiescompleted at the site, and access to transpor-tation networks.

The quality and amount of the informationcontained in the mine plans, and the range ofissues they covered, vary considerably. Someof the mine plans exceed 20 volumes. Manyprovide a great deal of information on the en-vironmental factors discussed in this report,especially those pertaining to reclamation.Comprehensive technical and environmentalassessments prepared by the Office of Sur-face Mining (OSM), and technical and policymemoranda prepared by OSM and USGS dur-ing the mine plan review are also included inthe official Government files on many of thelarger mine plans, along with contractorreports and correspondence between lesseesand Government officials. *

*A few leases in mine plans that were incomplete or inactiveor submitted after August 1980 were included in the assess-ment of undeveloped leases.

Analysis of Undeveloped Leases

Nearly 45 percent of the existing Federalcoal leases (249 leases) are not covered by ap-proved or pending mine plans. For these un-developed leases, detailed descriptions of thelessee’s development plans are not readilyavailable. State task forces were convened toassist in assessing the development potentialand production prospects of these undevel-oped leases. Task forces were held in Col-orado, New Mexico, Oklahoma, Utah, andWyoming.

Before each task force, OTA conducted apreliminary evaluation of the developmentpotential of the undeveloped leases in the

State. All adjoining undeveloped leases heldby the same lessee and forming a compactand contiguous geographic unit were com-bined into a single lease block for purposes ofanalysis. The property characteristics of thelease blocks were then compared with a pro-file of economically viable mines in the State.(Mine profiles for average new mines weredeveloped for each Western coal basin withFederal leases.) The following questions wereasked 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 amining unit?

● Coal reserves. Are there enough recov-erable coal reserves within the leaseblock to support a competitive new min-ing operation?

● Coal quality. Do the coal reserves meetminimum Btu, sulfur, and ash qualitystandards for the expected end use (e.g.,electric power generation, industrialuse, synthetic fuels)?

● Geological characteristics. Do the geo-logical and topographical conditions ofthe coal reserves—such as depth ofoverburden, seam thickness, and dip—permit economic coal recovery?

● Ownership. Does the lessee have the fi-nancial capability and mining expertiseto develop the lease block?

The task force members drew on their ex-tensive experience and knowledge of localconditions to assess the influence of otherfactors on the development potential of theleases, including potential markets, geo-graphic location, status of adjacent prop-erties, surface resource values, transporta-tion availability, community infrastructure,and environmental impacts. Following thisreview, OTA, with the assistance of the Statetask forces, classified the lease blocks ashaving:

●

●

•

Favorable development potential.—Thelease or lease block has favorable de-velopment characteristics overall; thelease(s) meet the threshold criteria for aviable mining property; there are noidentified major technical or permittingproblems or uncertainties associatedwith the lease development.Uncertain development potential.-Thelease or lease block has uncertain devel-opment potential because developmentis contingent on factors such as trans-portation or synfuels development or be-cause of lack of information about thelessee’s development intentions. Prop-erty characteristics can be good ormarginal.Unfavorable development potential.—The lease or lease block has unfavorabledevelopment potential, generally be-cause it has one or more of the follow-ing property characteristics: small re-serves, difficult mining or reclamationconditions, poor quality coal, or isolatedlocation.

Finally, each State task force estimated theproduction prospects for all undevelopedleases with either uncertain or favorabledevelopment potential. The results of eachtask force were reviewed by OTA and sup-plemented with additional information whereneeded.

Analysis of Diligent Development

The 1920 Mineral Leasing Act originallyprovided that a Federal lease be issued for anindeterminant period of time, subject to therequirement that the lease be diligently devel-oped. The act also included a clause requir-ing continuous operation after the lease wasbrought into production. Failure to abide bythese conditions was grounds for cancellationof the lease. Between 1920 and 1970, how-ever, the diligence requirements for Federalcoal leases were not specifically defined. Nolease was ever canceled because it failed to

meet diligence. In 1976, FCLAA removed theindeterminate term for Federal leases and re-quired that new leases be canceled if they donot produce coal in commercial quantitieswithin 10 years of issuance. Also in 1976, DOIissued regulations specifying that 2½ per-cent of the recoverable reserves on leasesissued before the passage of FCLAA (pre-FCLAA leases) must be mined by June 1,1986, to fulfill the terms of diligent develop-ment and that 1 percent of the recoverablereserves on leases issued after August 4,


1976 (post-FCLAA leases) must be mined 10years after the date of issuance. Continuousoperations requirements were also specified.

Under the 1976 regulations, the Secretaryof the Interior can grant up to a 5-year exten-sion of the 1986 deadline for pre-FCLAAleases. (Post-FCLAA leases are not eligiblefor this 5-year extension.) The grounds forgranting an extension are: 1) time needed tocomplete the development of an advancedtechnology such as synthetic fuels, 2) timeneeded because of the magnitude of the proj-ect such as a large mine, or 3) a contract forsale of the first 2½ percent of the leasereserves after 1986. In addition to the abovereasons, lease terms can be suspended be-cause of delays in meeting the diligence re-quirements that are beyond the control of thelessee (e.g., accidents, strikes, or adminis-trative delays). Poor market conditions do notconstitute grounds for suspending the leaseterms or extending the deadline for diligence.

In light of the diligence requirements pro-mulgated in the 1976 regulations, 2 years areparticularly important in OTA’s analysis ofFederal coal development: 1986 when leasesissued prior to August 4, 1976, must meet thediligent production requirement of 2½ per-cent of the recoverable reserves, and 1991when those pre-FCLAA leases that have beengranted a 5-year extension must produce 2½percent of the recoverable reserves. OTAanalyzed its estimates of future productionfrom Federal coal leases to determine howmany leases are likely to meet diligence by1986 or by 1991. *

Patterns of coal ownership in the West arenot always consistent with the most efficientand 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 thesepost-FCLAA leases are associated with active mines and willmeet diligence by or before their due date as part of the largermining operation.

will include coal that is owned by the FederalGovernment, by a State Government, or by aprivate party. In recognition of this possibilityand to promote the economical and efficientdevelopment of Federal coal leases, the con-cept of logical mining unit (LMU) was in-cluded in FCLAA and the 1976 regulations.An LMU is defined in the FCLAA as “an areaof coal land that can be developed and minedin an efficient, economical and orderly man-ner with due regard for the conservation ofcoal reserves and other resources.” Ac-cording to the regulations, no LMU may belarger than 25,000 acres. All areas within anLMU must be contiguous and under the con-trol of a single operator.

LMU is an important concept in this reportbecause it defines the physical boundarieswithin which recoverable reserves are identi-fied for diligence requirements. By regu-lation, BLM has defined every lease as anLMU whether or not it meets the statutoryLMU description. Therefore, unless a lesseerequests that a lease be included in an LMUwith other Federal leases or non-Federalcoal, the recoverable reserves on a lease willestablish the reserve base on which diligentproduction requirements will be calculated.

In cases where a lease is included in anLMU with other Federal leases or non-Fed-eral coal, compliance with diligent develop-ment and continued operations requirementswill be calculated on the total recoverablereserves in the LMU, not just the Federalreserves. Consequently, a Federal lease in anLMU with non-Federal coal could meet dili-gence requirements before any Federal coalis mined, and in any year could fulfill contin-uous operations requirements even if no coalwere mined from the lease itself. Under cer-tain circumstances a lessee may petition torelinquish certain areas of the lease or cer-tain seams or beds, in order to lower the re-coverable reserves so that diligent develop-ment can be achieved.

Ch. 2—Background and Information ● 43

Uncertainties in the AnalysisOTA’s analysis draws on extensive geo-

logical, technical, and market data, and in-formed judgments about the development po-tential and production prospects of Federalcoal leases made by OTA and the OTA taskforces on the basis of these data. Many ofthese judgments were reviewed by the les-sees and by technical specialists. Neverthe-less, uncertainties remain in the analysisboth of leases in mine plans and of undevel-oped leases.

Many undeveloped leases with good prop-erty characteristics, with owners activelydeveloping the property, and with marketsidentified and, in some cases, with signedcontracts are likely to be producing coal inthe next 10 years. There is little uncertaintyin ranking many of these leases as havingfavorable development potential and produc-tion prospects.

Many of the undeveloped leases classifiedas having unfavorable development potentialhave poor property characteristics comparedto mines currently operating in the area andwould be expensive to bring into production.Small reserves, poor coal quality, difficultmining and reclamation conditions, or com-binations of several of these factors meanthat there is little uncertainty in classifyingthese leases as having unfavorable develop-ment potential. However, even for some of theundeveloped leases with poor property char-acteristics, the lessee might be able to inte-grate the lease into an operating or plannedmine or develop the lease for synthetic fuelsproduction. Consequently, several undevel-oped leases with poor property characteris-tics have favorable or uncertain developmentpotential.

The development potential of many otherundeveloped leases was clouded by uncer-tainties, In several cases, lease developmentwas dependent on factors such as a favorableclimate for synfuels or the construction of anew transportation facility.

Markets and the demand for Western coalover the next 10 years were particularly im-portant considerations for those undevelopedleases with favorable or uncertain develop-ment potential. Coal production in the Westduring this period will likely be demanddriven. OTA assessed the potential demandfor coal from States with major Federal coalreserves. However, demand projections forWestern coal are subject to numerous uncer-tainties, ranging from the rate of increase ofelectricity demand to the amount of coal to beexported to foreign countries. Moreover,even if demand for Western coal could be ac-curately and precisely forecast, predictingthe success of a given lessee in capturing ashare of this demand would still be subject touncertainty. In the buyer’s market that islikely for Western coal in the next 10 years,there will be strong competition for newsales, including competition from non-Federalcoal mines in the West, from new Federalleases, and from coal produced in other re-gions. A number of factors, but especially themarketing success of the lessee, will ulti-mately decide whether or not a given undevel-oped lease is brought into production and atwhat level. Even for those leases in approvedmine plans with definite production goals andin many cases with contracts, the amount ofcoal that will be mined annually over the next10 years is subject to uncertainty.

Thus, the estimates of potential productionfrom Federal leases made in this report arenot forecasts of the coal that would be pro-duced at a given price or a given demand.They are estimates of the total amount of coalthat could be produced from operating andproposed Federal mines and from those unde-veloped Federal leases that have characteris-tics comparable to operating mines in thesame region. Coal from these leases wouldthus be likely to have mining costs competi-tive with costs at currently operating mines inthe same area. If the demand for Federal coaldoes not increase to these levels of potential


production, then not all the Federal leasesthat could technically and economically bedeveloped will be brought into production.Moreover, although OTA based its evalua-tions of likelihood of development and levelsof potential production on the best data avail-able for each lease or mine at the time, as ad-ditional information based on further explo-ration and development becomes available,the prospects for any given lease or minecould change.

Estimating production from Federal leaseswas complicated by the fact that many coaloperations in the West include Federal, State,or private (fee] coal. This pattern is most pronounced in southern Wyoming, the Colstriparea of the Montana portion of the PowderRiver basin, and in North Dakota. For NorthDakota, Wyoming, and Montana, OTA has es-timated what fraction of the annual produc-

tion of mines with Federal leases is likely tobe from Federal reserves. In many cases, thegeological characteristics of the mine and thedirection of mining operations are such thatlittle variation occurs from year to year in theratio of Federal to non-Federal production; inother cases, however, large changes in thisratio will occur over several years. Whereverpossible, OTA followed the judgments of thelessee’s mine plan.

In any work that evaluates a large num-ber of units, random statistical errors andchanges tend to cancel one another. Whileevents could prove OTA’s estimates of leasedevelopment wrong in a number of individualcases, taken in the aggregate by region orState, the estimates presented in this reportshould constitute a reasonably accurate pic-ture of Federal coal development over thenext decade.

Focus of Subsequent Chapters

Chapters 5, 6, and 7 present OTA’s find-ings concerning the development potentialand production prospects of Federal coalleases. Chapter 5 identifies the factors thatare likely to affect the markets for Westerncoal over the next 10 years and reviews thedemand projections for Western coal thathave been developed and considered by in-dustry and Government. Chapter 6 presentsthe findings of the assessment on the amountof Federal coal that is likely to be producedover the next 10 years and the number ofleases likely to fulfill diligence requirements.Chapter 7 is a case study of Federal coal de-velopment and production in the PowderRiver Basin of Wyoming and Montana.

Chapters 3, 4, and 13 review the status,distribution, geotechnical characteristics,

and ownership of existing Federal coalleases, Federal coal reserves, and PRLAs.Chapters 8, 10, and 12 examine the impactson Federal coal development and productionresulting from transportation availability andcosts, environmental statutes and regula-tions, and socioeconomic factors. Chapter 12also presents OTA’s estimate of revenuesfrom rentals and royalties from Federal coalproduction over the next decade. Chapter 9provides an overview of Federal coal leasemanagement issues, and chapter 11 presentsOTA’s analysis of the feasibility of increasingFederal coal recovery through undergroundmining methods.

CHAPTER 3

Federal Coal Leases andPreference Right Lease

Applications: An Overview

Contents

PageHistory 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 . . . . 0 4 . . 0 0 . . 0 0 . . 0 . . . 0 . . . . . 0 . 0 $ ● . 0 0 . . 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

48495051

51

52535455

Page47

4849495051

52535454

555656

Figure No. Page15. Number of Leases, Acreage Under Lease, and Federal Coal Production From

1950 to 1980. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

CHAPTER 3

Federal Coal Leases and PreferenceRight Lease Applications: An Overview

As of September 30, 1980, there were 565Federal coal leases in 14 States (see table 6].Ninety-seven percent of the total, or 548leases, are located in seven Western States:Colorado, Montana, New Mexico, North Da-kota, Oklahoma, Utah, and Wyoming. These548 leases were examined by OTA in somedetail. * Utah has 204 or 36 percent of allleases, more than any other State, Coloradoand Wyoming have the next largest numberof leases, 127 (22 percent) and 101 (18 per-cent) respectively, With 20 leases, NorthDakota has the fewest leases among theseven States studied by OTA.

*OTA did not examine coal leases that have been relin-quished or canceled and made only a limited review of leasesoutside this seven State region because of the small reserves in-volved. OTA did not study unleased Federal coal.

Table 6.—Extent of Leasing(includes all leases in existence as of Sept. 30, 1980)

Recoverable coalNumber of Acreage reserves

leases under lease (billions of tons)

127 126.893 2.2Colorado . . . . . . . (22%)a (16%) (13%)

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

because of rounding.bThe “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 ofFederal land, 7 percent of the 11.5 millionacres of Federal coal land classified asknown recoverable coal resource areas(KRCRA) as defined by the Department of theInterior (DOI) in March 1978. Utah, Wyo-ming, and Colorado have a major proportionof leased acreage with 34, 27, and 16 percentrespectively. North Dakota has the fewestleased acres among the seven principalStates studied.

OTA estimates that 16.5 billion tons of re-coverable coal reserves are now under leasein the seven States with 97 percent of theleases. Production from these reserves to-taled 60 million tons in 1979 and 69 milliontons in 1980; in the same years, total U.S. coalproduction was 776 million tons and 820 mil-lion tons, respectively.

Currently leased Federal reserves are lessthan 20 percent of the estimated total of over80 billion tons of Federal recoverable coalreserves (see table 7). The percentage of totalFederal coal reserves under lease in eachState varies from a high of 50 percent in Utahto a low of 5 percent in Montana and about 3percent in North Dakota. The percentages offederally owned coal to the total known re-coverable coal reserves in each State varyfrom under 10 percent in Oklahoma to 85 per-cent in Utah with an average of about 60 per-cent for the seven States. *

Leases range from 40 acres to 20,701acres. Approximately 60 leases are under100 acres and 4 leases are over 10,000 acresin size. In terms of recoverable coal reserves,some small leases contain negligible amountsof coal (i. e., under 10,000 tons) while severallarge leases contain over one-half billion tonsof recoverable coal.

*These percentages represent best available data on coalreserves and ownership, but these data are incomplete. Seefootnotes to table 7.

47


Table 7.—Leased, Federal, and Total Recoverable Coal Reserves in the Principal WesternCoal-Producing States (all reserves shown in billion tons)

Estimates of Estimates ofRecoverable total Federal Estimates of Recoverable total Federal Estimates ofcoal under recoverable total recoverable coal under recoverable total recoverable

Iease a reservesb coalc Iease a reservesb coalc

Colorado. . . . . 2.2 10 17 Oklahoma. . . . 0.2 0.2 2Montana . . . . . 1.2 26 40 Utah . . . . . . . . 3.2 6.4 7.5New Mexico . . 0.45 4 9 Wyoming . . . . 8.9 26 36North Dakota . 0.3 - 1 0 25 to 35 Total . . . . . . 16.5 - 8 3 -140

aLeased reserve figures from Automated Coal Lease Data System as modifiedby Office of Technology Assessment.

bThe numbers in this column are estimates of the total Federal recoverablecoal reserves in each State. The figure for New Mexico was supplied to Officeof Technology Assessment by the New Mexico Bureau of Mines and MineralResources and the figure for Utah by the Utah Geological and Mineral Survey.See footnote c, below. The figures for the other states were estimated bymultiplying the estimate of total recoverable coal in the State by the percen-tage of Federal coal acreage in Known Recoverable Coal Resource Areas ineach State These percentages were taken from table 21 in ch. 4 and are: Col-orado (580/0), Montana (640/0), North Dakota (327.), and Wyoming (730/0). InMontana, the Federal percentage may be high because the KRCRAs do not in-clude Indian reservations with significant reserves of coal. The Coloradopercentage may also be high because the KRCRAs do not include the Denver-Raton Mesa coal region which has a high percentage of non-Federal coalownership.

cTotal State recoverable reserves from the following sources:Colorado. Keith Murray, Colorado School of Mines Research Institute. Per-

sonal communication to Office of Technology Assessment, Feb-ruary 1981. The figure of 17 billion tons IS based on his earlier workat 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 wasderived from the reported figure of 50 billion tons of strippablereserves and a recovery rate of 80 percent. This figure does not in-clude 71 billion tons of underground demonstrated reserve basealso listed in the 1979 Keystone Coal Industry Manual from datasupplied by the U.S.B.M.

Office of Technology Assessment.

New Mexico: New Mexico Bureau of Mines and Mineral Resources, Personalcommunication to Office of Technology Assessment, August 1981.The figure does not include an additional 59 billion tons ofrecoverable underground reserves between 250 ft depth and 3,000ft depth because insufficient information was available for theNew Mexico Bureau to determine the portion of these reserves inseams that are likely to be mined In the next decade.

North Dakota: North Dakota Geological Survey, Personal communication toOffice of Technology Assessment, August 1981. A recovery rate of90 percent has been assumed by the North Dakota Survey.

Oklahoma: Friedman, S.A. Investigation of the Coal Reserves in the OzarksSection of Oklahoma and their Potential Uses (Norman, Okla.:Oklahoma Geological Survey, 1975).

Utah: Utah Geological and Mineral Survey, Personal communication to Off Iceof Technology Assessment, August 1981. The Utah Survey cau-tions that this figure is low, because it is based on stringent stan-dards for ident i f i ca t ion and cor re la t ion o f economica l lyrecoverable reserves.

Wyoming: Gary Glass, Wyoming Geological Survey, Personal communicationto Office of Technology Assessment, August 1981. The abovefigure is derived from a surface reserve base of 26.3 billion tonswith a recovery rate of 80 percent and an underground reserve baseof 29.5 billion tons with a recovery rate of 50 percent. Glass cau-tions that the underground recovery rate of 50 percent may be toohigh for Wyoming.

General caution: The total recoverable coal reserve figures were obtainedfrom seven different sources and are not based on uniformstandards.

History of Leasing

Federal coal has been leased since enact-ment of the Mineral Leasing Act on February25, 1920. The oldest lease still in effect,issued on January 17, 1921, originally cov-ered 2,080 acres in Utah. Of the currently ex-isting leases, 88 were issued before 1950 (seetable 8). These include 16 percent of all ex-isting leases, but only 5 percent of all landunder lease as of September 30, 1980. Eighty-six percent of all leases covering 90 percentof all land under lease are at least 10 yearsold. *

*A total of 526 of the 565 existing leases were issued beforeAug. 4, 1976, the date of enactment of the Federal Coal LeasingAmendments Act of 1976 (Public Law 94-377]. Technicallythese are the “existing” leases subject to OTA scrutiny undersec. 10 of that law.

The number of leases and leased acreageincreased slowly in the 1950’s but accel-erated sharply in the 1960’s (see fig. 15). Thesolid line (number of leases) and the dashedline (acres under lease) in figure 15 crossaround 1965 because of a trend during the1960’s to include larger acreages in singleleases. The moratorium on most new leasingby DOI from 1971 through 1980 slowed leas-ing to the levels of the 1950’s.

Historically, trends in Federal coal produc-tion did not coincide with trends in leasing.Production declined from 7.1 million to 5.4million tons from 1950 to 1960 and remainedat 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 mil-lion 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

aTable includes only leases in existence on Jan 2 of each year Iisted 1950-75and which were still valid on Sept. 30, 1980 The 1980 figures report alI leasesin existence on Sept. 30, 1980

bpercentages are percent of 1980 totals.


Figure 15.— Number of Leases, Acreage UnderLease, 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 casefiles Federal coal production from the U S Department of Interior,Federal Coal Management Report Fiscal Year 1978, March 1979 andfrom the ACLDS

Lease Issuance Methods

Existing leases were issued by one of threemethods: 1 ) competitive bidding at a leasesale, 2) noncompetitive preference right leas-ing, or 3) segregation of an existing lease (alsocalled partial assignment).

The Mineral Leasing Act of 1920 requiresDOI to lease competitively public land knownto contain commercial quantities of coal, Sev-eral bidding procedures have been used inthe past, including sealed written bids andopen verbal auctions. Leases have beenawarded to the party offering the highest one-time cash bonus payment. Other biddingmethods besides the cash bonus proceduremay be used for future leasing. Althoughthese lease sales were open to all bidders,more than half of all lease sales held before1979 attracted only one bidder. In total, 52percent of all existing leases have beenissued under the lease sale method (seetable 9).

Preference right leasing under the 1920leasing act was limited to land without knowncommercial quantities of coal for which addi-tional prospecting work was needed to deter-mine the existence of economically minablecoal deposits. In these cases, applicants couldreceive a prospecting permit from DOI to per-form exploration and drilling. If coal wasfound in commercial quantities within the 2-year permit period (extendable once), theprospector was entitled to a preference rightlease. As an incentive to promote explorationof public lands, no bonus was required onpreference right leases. Of all existing leases,42 percent were issued under the preferenceright method.

In 1971, DOI suspended issuance of newprospecting permits and delayed processing

Table 9.—Lease Issuance Method forExisting Leases

Issuance method Number of leases 0/0 of leases

Lease sales . . . . . . . . . . . 294 520/oPreference right , . . . . . . 237 420/oSegregation . . . . . . . . . . . 34 60/0


50 ● An Assessment of Development and production Potential of Federal Coal Leases

of pending preference right lease applica-tions (PRLAs). In 1976, in the Federal CoalLeasing Amendments Act, Congress repealedprovisions for preference right leasing, sub-ject to valid existing rights. The preferenceright program no longer exists except for theapplications for leases based on the prospect-ing permits issued prior to the 1971 leasingmoratorium (nearly all dating from 1967 to1971). Applications for leases were not com-pletely processed by DOI when the mora-torium began; processing largely ceased dur-ing the moratorium and resumed in late 1979.(About 176 applications remain.) ThesePRLAs are discussed in more detail in thenext section.

Another leasing procedure is called seg-regation or partial assignment. Here, an ex-isting lease is divided into two or more par-cels at the request of the lessee(s). Suchactions require the approval of DOI. A newlease(s) is then issued for the new tract(s) andthe terms of the surviving lease are modifiedto reflect a reduced acreage. Only 6 percentof outstanding Federal leases have been cre-ated by segregation.

Pending PRLAs

As of January 1, 1980, there were 176pending applications for preference rightleases. They stem from prospecting permitsissued between 1955 and 1971—with 172 (98percent) originating after January 1, 1965.These permits expired just before or shortlyafter the initiation of the leasing moratoriumin 1971 and the resulting lease applicationswere neither approved nor denied. They haveremained unprocessed for a decade, althoughthey have been the subject of lawsuits, Gov-ernment studies, and congressional actions.

Nearly 98 percent of the PRLAs are locatedin the seven Western State region studied byOTA (see table 10). The remaining four are inAlaska. In total, 403,800 acres of Federalcoal land are included in PRLAs and involvean estimated 5.8 billion tons of recoverablecoal reserves. Wyoming, with 74 PRLAs, hasthe largest number of applications. They in-

Table 10.—Extent and Location of PRLAs

Recoverable coalNumber of reserves

PRLAs Acreage (billions of tons)

Total . . . . . . . . . . . 176 403,800 5.8aAll percentages equal percent of total for all PRLAs.bFigures 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, 1979and reported in U S. Department of the Interior, Federal Coal Manage-ment Report, March 1980.

elude 43 percent of the reserves and 34 per-cent of the acreage in all PRLAs. Coloradoranks second with 37 PRLAs including 18 per-cent of total reserves and New Mexico isthird with 28 PRLAs including 26 percent ofthe reserves.

Acreages and reserves under the PRLAsare substantial. If all the applications are ap-proved and converted to leases, total landunder lease will increase by 50 percent andleased recoverable coal reserves will beraised by 35 percent.

Most of the legal and administrative prob-lems preventing the processing of the PRLAshave been resolved in recent years. The cur-rent Federal coal lease management programadopted by DOI in July 1979 calls for the proc-essing of the applications to be completed by1984. Environmental, legal, and technicalconsiderations could lead to the rejection ofsome of the PRLAs or result in acreage modi-fications or the addition of lease stipulationswhich restrict subsequent coal mining. Theseissues are discussed in more detail inchapter 9.

—

Ch. 3—Federal Coal Leases and Preference Right Lease Applications: An Overview ● 51

Lease or PRLA Acquisition Methods

Although each lease or prospecting permitwas originally issued by DOI, there are sev-eral other methods by which the presentowners have obtained leases or PRLAs.

The issuance of a lease or prospecting per-mit by the Federal Government is termed inthis study de novo leasing or permitting. OTAfound in a study of the 538 leases and 176PRLAs outstanding as of September 30, 1979,that only 117 leases (22 percent of the leasetotal) and 19 PRLAs (11 percent of the totalPRLAs) are still held by the original owner(see table 11). The remaining 78 percent of allleases and 89 percent of all PRLAs have beenobtained by their present owners from pre-vious owners through one of two methods:1) assignment and 2) segregation.

Owners of leases or PRLAs may sell ortransfer their contracts to other parties withapproval of DOI. This process is called as-signment. Assignments are essentially pri-vate transactions and any cash, property,service agreements, or overriding royaltiesare, with few limitations, between the buyerand seller.

Table 11.— Lease and PRLA Acquisition MethodUsed by Present Owner

Number and percent Number and percentAcquisition method of leases of PRLAs

De novo . . . . . . . . . . . . 117 (22%) 19 (11%)Assignment ., . . . . . . . 403 (75%) 133 (76%)

First . . . . . . . . . . – 146 –76Second. . . . . . . . . . . – 124 - 2 7Third or more . . . . . – 133 –30

Segregation. . . . . . . . . 1 8a ( 3 % ) 24 (14%)aThe "Segregatlon" total in this table differs from the number (34) Iisted in table9 because eight segregated leases were subsequently assigned to their pre-sent owners Also, table 9 includes 27 leases issued in late 1979 and in 1980These leases were not Included in the above analysis


Approximately 75 percent of the outstand-ing leases and PRLAs were obtained by theircurrent owner through assignment. Multipleassignments have been made on many leasesand PRLAs; 124 leases have been assignedtwice and 133 have changed hands three ormore times. The 176 PRLAs have been as-signed a total of 227 times.

Segregation, already discussed in thischapter (see table 9), has been used by thepresent owners of 18 leases and 24 PRLAs.Like assignments, segregations are largelytransactions among private parties that arethen recorded by the Federal Government.

Control of a coal lease or PRLA can beobtained without actually acquiring titlethrough the de novo, assignment, or segrega-tion procedures, This involves the purchaseof a controlling interest in a firm whichalready owns leases or PRLAs. The acquiredfirm can then become a subsidiary of the pur-chaser and the purchaser is able to make de-cisions affecting the leases or PRLAs. Al-though transfers of title by assignment fromthe acquired company to the purchasing com-pany often occur, they are not obligatory.

Corporate mergers and acquisitions havefrequently involved leases and PRLAs. Forexample, at least 10 of the 36 leaseholdingcompanies now operating as wholly ownedsubsidiaries once held leases as independentcorporations. As another example, in 1980three firms holding leases were purchased bymajor energy companies. Because lease titletransfers do not always accompany corpo-rate acquisitions, it is difficult to precisely de-termine the role of mergers in the leasing pro-gram; however it is clearly significant.

Ownership of Leases and PRLAs

Ownership of leases and PRLAs is shared ventures involving some of the largest corpo-by 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 1950to 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 orindirectly control them through subsidiariesor joint ventures. In addition, as of January 1,1980, 59 individuals held leases in their ownname. As of January 1, 1980, 29 companiesand 18 individuals owned PRLAs.

Electric utilities hold 21 percent of all out-standing acreage under coal lease as of Sep-tember 30, 1979, more than any other singlebusiness category defined by OTA. Seventeenutilities now own leases. Eleven of the 18 larg-est oil companies (i.e., the oil majors) control20 percent of leased acreage. Seven otherbusiness activity categories own leases cover-ing at least 5 percent of all land under lease,ranging from 8 percent owned by PeabodyCoal Co. (the largest single lessee) to 5 per-cent owned by nonresource-related diversi-fied companies such as General Electric orMonsanto (see table 12 and ch. 13).

Unincorporated individuals hold 20 per-cent of all land included in PRLAs, more thanany of the eight business categories identifiedby OTA as major PRLA holders. The majorenergy companies rank second, with 16 per-cent. Other principal holders of PRLAs in-clude natural gas pipeline, metals, oil or gas,and electric utility companies.

OTA found that lease and PRLA holdersrepresent one of four types of business or-ganizations. Most of the acreage under lease(43 percent) and under PRLA (44 percent) isheld by subsidiaries of larger parent com-panies. Only 26 percent of all leased land and12 percent of land under PRLAs is controlledby independent firms. Multicorporate enti-

Continued from p. 51.

ship is discussed in considerable detail in the OTA TechnicalMemorandum Patterns and Trends in Federal Coal Lease Own-ership: 1950-80, OTA-TM-M-7, March 1981.

Table 12.—Major Business Activity CategoriesHolding Federal Coal Leases and PRLAs in 1980a

Percent of Percent of landleased land included in PRLAs

Electric utilities . . . . . . . . . . . . .Energy companies . . . . . . . . . .Peabody Coal Co. . . . . . . . . . . .

Steel companies . . . . . . . . . . . .Independent coal companies.

Oil and gas (minor) companiesUnincorporated individuals . . .Natural gas pipelinecompanies . . . . . . . . . . . . . . . .

Nonresource-relateddiversified companies . . . . . .

Kemmerer Coal Cob . . . . . . . . .Metals and mining companies.Landholding companies . . . . . .“Other” companies. . . . . . . . . .

21%20

8

87

65

5

542

<110

12(In “other”)

(less than 5%)1091

14aThe office of Technology Assessment analyzed separately any business

activity category (including Individual companies with unique business struc-tures) holding at least 5 percent of all land under lease or PRLA at at least 1 of7 analysis dates between 1950 and 1980. (See ch. 13). The analysis includesthe 538 leases and 176 PRLAs in existence as of Sept. 30, 1979,

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


ties, such as joint ventures, are the newestbusiness organizations to control significantpublic coal land; they hold 25 percent ofleased land and 22 percent of land underPRLAs. Finally, unincorporated individualscontrol 5 percent of land under lease and 20percent of land under PRLAs.

Over the past 30 years, there has been ageneral decline in the percentage of leasesand PRLAs held by small independent com-panies and unincorporated individuals. Theproportion of leases held by large diversifiedfirms and companies operating on leasedland through subsidiary and multicorporatearrangements has risen. There has also beenan increase in the number of different indus-tries holding major shares in Federal leasing.The number of business categories holding atleast 5 percent of all land under lease grewfrom four to nine between 1950 and 1980.

Lease Development Status

A principal objective of this study is to existing leases and PRLAs. During this analysisamine mining activity on Federal leases and OTA divided the existing leases into units orto assess the development potential of ex- blocks. A lease unit, as used by OTA, consists


of either all leases included in the same ac-tive or proposed mine as defined by the mineplan, or one or more undeveloped leases thatare owned by the same lessee and that arecontiguous or sufficiently close together toform a compact minable unit. *

OTA divided the 565 existing coal leasesinto 256 units (see table 13). The smallestunits contain one lease covering 40 acres.The largest, located in southern Utah, in-cludes 21 leases and 40,277 acres. Colorado,Utah, and Wyoming together account for 176lease units, 69 percent of the total.

OTA evaluated mining activity and minedevelopment prospects for the 244 lease unitslocated in the seven principal Western coal-producing States listed in table 13. The leaseunits were grouped in three categories ac-cording to stages of development. Each of thecategories required a different type of datacollection and analysis. The three develop-ment 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 inthese categories based on OTA’s review of allmine plans on file with the Office of Surface

‘See ch. 2 for more information on the OTA methodology.

Table 13.—Number and Location of Leasesand Lease Units

State Number of leases Number of lease units

Colorado. . . . . 127Montana . . . . . 21New Mexico . . 29North Dakota . 20Oklahoma . . . . 46Utah. . . . . . . . . 204Wyoming . . . . 101Other States . . 17

6613151426565412

Total . . . . . . 565 256


Mining (OSM) on September 30, 1980. * Thenumber of leases and lease units, acreage,and recoverable coal reserves in each of thethree categories is shown in table 14 (see alsofig. 9 in ch. 1). Information in this table issummarized below.

Leases With Approved Mine Plans

Approximately one-third of all leases andall lease units have approved mine plans.Many of the mines in this category are ac-tively producing; however, some mines onlyrecently received permit approval and havenot yet begun commercial operations, The ap-proved category also includes a small numberof new leases issued in 1979 and 1980 to en-sure the continued operation of existingmines (even if the approved mine plan has notyet been formally modified to add the newleases) and several leases included in pend-ing amendments to approved mine plans.

In Montana, 54 percent of the lease units,containing 69 percent of the leased reservesare in approved mine plans (see table 15).New Mexico and Oklahoma have the smallestpercentage of lease units in the approved cat-egory and Oklahoma and Utah the lowest per-centage of leased reserves in the approvedcategory.

Before a lessee can mine coal from aFederal lease, DOI must approve the pro-posed mining operation. Because only a por-

*Before coal can be produced from Federal land, a mine planmust be submitted to and approved by DOI. Hence, mine planstatus provides a convenient yardstick by which to measurelease development. There are two separate requirements formine plans for Federal leases. First, a mine plan must be sub-mitted to comply with the general provisions and regulationsunder the Mineral Leasing Act of 1920 (MLA), as amended, andsecondly, a mining and reclamation plan must be submitted forall surface and underground mines to comply with the SurfaceMining Control and Reclamation Act of 1977 (SMCRA) whetheror not Federal lands are involved. Under DOI directives, asingle mining plan is submitted to OSM to meet both MLA andSMCRA requirements, however, OSM and the Geological Sur-vey each retain their separate responsibilities for enforcementand permit approval.


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- Recover-able able able

Number Number Number reserves Number Number Number reserves Number Number Number reservesof 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


Table 15.—Leases in Production andWith Approved Mine Plans

Number Number Recoverableof of lease reserves

leases units Acres (billions of tons)

tion of the approved permit area is mined inany given year, it is unlikely that all Federalcoal leases in approved mine plans will beproducing at one time. In 1980, coal wasmined from about 100 Federal leases, whichis about half of the leases in the approvedcategory. Sixty-nine million tons of coal weremined from the producing leases in the sevenWestern State OTA study region (see table16). Federal coal contributed 34 percent of allproduction from these States. In 1980, Fed-eral coal provided 66 percent of Utah’s entireoutput, 36 percent of Wyoming’s production,but only 3.5 percent of the coal mined inNorth Dakota and only 5 percent of the coalmined in Oklahoma.

Leases With Pending Mine Plans

Approximately 21 percent of all leases and15 percent of leased reserves are included in


Table 16.—1979 and 1980 Coal Production From Federal Leases and From Western States

alncludes Federal production from Kentucky, Alabama, and Washington.bTotal 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 Pro-duction 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 ln-come, and Related Statistics, June 1981. 1960 State production from the U.S. Energy Information Agency, Personal Communication to the Office ofTechnology Assessment, July 27, 1961.

the 13 percent of all lease units for whichmine plans have been submitted to OSM andfor which Federal approval is pending. Thisclassification does not distinguish amonglease units on the basis of quality of sub-mitted mine plans, their date of submission,or the current stage of the review of the mineplan.

New Mexico, Utah, and North Dakota eachhave 20 percent of their lease units falling inthe pending mine plan category. On the otherhand, no pending mine plans affecting Mon-tana leases are being studied by DOI and only1 of Oklahoma’s 26 lease units is included in apending mine plan (see table 17).

Leases Without Mine Plans

Over half of all existing lease units, 44 per-cent of all leases, 42 percent of all leased

Table 17.—Leases With Pending Mine Plans



0 0 0 0Montana. . . . . . . — — — —

aPercentags are percent of total for each State except percent of total whichis percent of seven State total.


8 4 - 1 4 1 0 - 81 - 5 : O L 3

56 ● An Assessment of Development and production Potential of Federal Coal Leases

acreage, and 40 percent of leased reserveshave not been developed to the point of a mineplan submission to OSM.

Preliminary development activity varieswidely on these undeveloped units, from ex-tensive exploration drilling and mine planpreparation on some units to no activity at allon others (see ch. 6).

Oklahoma has the largest proportion ofFederal coal leases without mine plans, andfive of the seven Western States have over 30percent of their leased Federal reserves inthis category (see table 18). Sixty-seven per-cent of New Mexico’s lease units have nomine plans, but they cover just 22 percent ofleased reserves.

Table 18.—Leases for Which No Mine PlansHave Been Submitted



241 138 329,522 6.6Total . . . . . . . . (44%) (57%) (41 %) (40%)

aPercentages are percent of total for each State except percent of total whichis percent of seven State total.


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

70707171

73

76

Table No. Page

19.

20.

21.

22.

23.24.

25.

Distribution of Recoverable Coal Reserves Under Federal Lease and PreferenceRight Lease Application by Major Coal Production Region. . . . . . . . . . . . . . . . . . . .Distribution of Recoverable Coal Reserves Under Federal Lease and PreferenceRight Lease Application by State ● **.* , . . , , , , . , , , . . . . , ● * , * * * , * , . , . . . , , ●

Federal Coal Ownership in Coal Regions and Known Recoverable Coal ResourceAreas in the Six Major Federal Coal States ● ******* ● ***.**** ● *..***** .,.*.,Uses and Market Areas of Coal From States With Significant Amounts of LeasedFederal Coal .**. ***, o*, .*** ***, **, , . , , , . , , . , , . , . . .* ,* . ,Classification of Coals by Rank ● . * * * * * * , * . . * * , . . , . * , , , *Coal Quality Characteristics of Federal Leases and Major Coalfields WithFederal Leases * , . * * * * o , . * * . , * * , . , e * * , , , . . . * * * * * . . * 0 . * * a o * * . # . * 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, andGeneralized 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 thewest, 1957-70 .. . . ... . **** * * . . * * * * * * * * . . * . * * * ....*..**

Page

63

64

67

6970

7274

60

6162

65

CHAPTER 4

Federal Coal Resources

Coal quality, geologic conditions, mining ●

methods, and end uses of Federal coal are im-portant factors that affect the development ofindividual Federal coal leases, and also the ●

general development of coal resources in theWestern United States. The following topics ●

are discussed in this chapter:● geographic location of Federal surface •

and underground coal reserves underlease and preference right lease applica-tions (PRLAs) in the major Western coalregions;

trends in Federal surface and under-ground coal production in the differentregions;uses and market areas of coal from themajor Federal coal States;

quality of coal in the Western coalregions, and characteristics of majorleased coal reserves and coalfields; andgeologic conditions and mining methods—in the major coal regions that are impor-tant in the development of Federal coalreserves.

Location of Leased Federal Coal ReservesLeased Federal coal reserves are located

in 14 States and in 5 of the 6 major coalregions of the United States (fig. 16). How-ever, most Federal coal is located in two coalregions in the Northern Great Plains coalprovince and seven coal regions in the RockyMountain coal province (see fig. 17). * Federalleases in these two provinces include over 98percent of the approximately 16.5 billion tonsof recoverable coal presently under lease.

Three-quarters of the leased Federal coalreserves outside of the Northern Great Plainsand Rocky Mountain coal provinces are con-tained in 46 leases in Oklahoma, which is geo-logically part of the Interior coal province.The remaining reserves (0.4 percent of thetotal under lease) are found in 17 leases inthe States of Alaska, Alabama, California,

*A number of different terms are used to describe areas inwhich coal deposits are located. Coal provinces cover a largegeographic area where coal deposits have a relatively similargeologic and physiographic setting. The continental UnitedStates has six major coal provinces (see fig. 16). Coal provincesare usually divided into geologically distinct coal regions (orbasins, where the geologic structure of the region is in the formof a basin) which also cover relatively large areas (generallyhundreds of thousands to millions of acres) of coal-bearingrocks. Coal regions may be further divided into coal fieldswhich generally cover areas of thousands or tens of thousandsof acres, and identify specific deposits of minable coal, or anumber of coal deposits with a similar geologic setting. Fig. 17also shows the location and names of the major coal regionsand fields in which Federal coal is leased.

Kentucky, Oregon, Pennsylvania, and Wash-ington. Leases in these seven States were notanalyzed by OTA. Leases in Oklahoma wereevaluated by OTA and some data on thisState is included in this chapter, but Okla-homa is discussed in less detail than themajor Federal coal States of Colorado, Mon-tana, New Mexico, North Dakota, Utah, andWyoming.

The United States has several hundred bil-lion tons of recoverable coal reserves, whichare approximately evenly distributed be-tween the Eastern and Western halves of thecountry.* These reserves are very large com-

*Various terms are used to describe quantity of coal. In-place resources (also called the resource or reserve base) in-clude all coal deposits, regardless of depth, thickness, oreconomic recoverability. Minable resources represent the por-tion of the in-place resource that can be mined under presenttechnology and economic conditions. Recoverable reservesrefer to the amount of coal that can actually be recovered; thisis always less than minable resources because some coal is lostduring mining, and in some cases, some coal may be unavail-able because of environmental and regulatory factors. Use ofthe term reserves in this chapter is synonymous with recover-able reserves. The demonstrated reserve base in the UnitedStates is estimated to be 475 billion tons (DemonstratedReserve Base of Coal in the U.S. on Jan. 1, 1979, EIA, May 1981].An earlier OTA report has estimated recoverable reserves inthe United States to total 283 billion tons (The Direct Use ofCoal p. 63, OTA-E-86, April 1979). Experts differ in specificestimates of total recoverable reserves in the United States, butgenerally agree that it is on the order of several hundreds ofbillion 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 . At lant ic 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 pro-duced in the United States in 1980. Slightlymore than half of the recoverable reserves interms of tonnage and slightly less than half interms of heat content are found in theWest. *

Federal coal leases are located primarilyin six coal production regions in the West:Fort Union, Powder River, Green River-HamsFork, Uinta-Southwest Utah, Denver-Raton

*Coals in the West have generally a lower heat contentthan coals in the East (i.e., more coal must be burned to providethe same amount of energy). About 60 billion tons of under-ground subbituminous coal in the Powder River Basin of Wyo-ming and Montana cannot be economically mined now. (F. X.Murray (cd.), Where We Agree: Report of the National CoalPolicy Project V.2 (Boulder, Colo.: Westview Press, 1978).) Ifthis coal is subtracted from the reserve totals, the West’s shareof recoverable reserves according to heat content drops to ap-proximately 40 percent of total U.S. reserves (National Re-search Council, Surface Mining: Soil, Coed and Society,Washington, D. C.: National Academy Press, 1981).

Mesa, and San Juan River (see fig. 18). Thesecoal production regions have been delineatedalong administrative boundaries of the Bu-reau of Land Management (BLM) for the pur-pose of implementing the new Federal coalmanagement program and do not exactly co-incide with geologic coal region boundaries.For example, the Danforth Hills coal field,which is geologically part of the Uinta coal re-gion, is located within the Green River-HamsFork production region. Also, some areas ofthe Uinta-Southwest Utah coal productionregion are geologically part of the San JuanRiver coal region. Unless coal productionregions are specifically referred to (as intable 19), discussion in this chapter refers togeologic coal regions. *

*There are a few Federal leases that are located in coal re-gions that are not included in the Federal coal production re-gions. These include two small leases in the Bighorn basin in

Ch. 4—Federal Coal Resources ● 61

Figure 17.—Sketch Map Showing Major CoalRegions With Leased Federal Coal, andGeneralized Location of Strippable and

Metallurgical Coal Deposits

Coal reserves under Federal lease andPRLAs are unevenly distributed among theseven major Federal coal States (see table20). Wyoming alone contains more than half(56 percent) of the reserves under lease, andUtah, the State with the next largest leasedreserves has 20 percent of the total. Wyomingand Utah together contain more than three-quarters of the reserves under Federal lease.Wyoming also has the largest percentage ofreserves under PRLA (43 percent), followedby New Mexico (26 percent) and Colorado (18percent). These three States account for

Hams Fork region nearly 90 percent of the reserves underPRLA. Most Federal leased reserves are sur-face minable (1 1.3 billion tons, or 69 percent)as are most of the reserves under PRLA (3.6billion tons, or 63 percent). The majority ofleased reserves in Montana, New Mexico,

Utah reglon -

~ Area of coal - Generalized O Major areas ofreserves location of metallurgical

strippable coalreserves

Numbers show locations of major coal fieldswith leased Federal coal:

1. Colstrip 13. Danforth Hils2. Decker 14. Somerset3. Buffalo 15. Book Cliffs (CO)4. Powder River 16. Book Cliffs (UT)5. Gillette 17. Wasatch Plateau6. Glenrook 18. Emery7. Hanna 19. Alton8. Little Snake River 20. Kapalrowits Plateau9. Rook Springs 21. Fruitland

10. Kemmerer 22. Bisti11. Yampa 23. Star Lake12. North Park 24. Carbondale Coal Basin

SOURCE Base Map National Academy of Sciences, Rehabilitation Potential ofWestern Coal Lands (Cambridge, Mass Ballinger Press, 1974)


north-central Wyoming and one small lease in the Yellowstoneregion in southwestern Montana. Very small reserves are in-volved with these leases so these regions are not discussed inthis chapter.

North Dakota, and Wyoming are surface min-able; most of the leased reserves in Colorado,Utah, and Oklahoma will have to be mined byunderground methods.

Table 19 shows the distribution of Federalcoal reserves under lease and PRLA by coalproduction region. The Powder River regionin Montana and Wyoming, contains 59 per-cent of the leased reserves and the Uinta-Southwest Utah production region in Utahand Colorado contains 25 percent of theleased Federal reserves. The two regionscombined contain 84 percent of the coalunder lease.

The large amount of leased Federal coal re-serves in the Powder River basin reflects theregion’s large reserves in thick flat-lying coalseams that can be easily surface mined andthe high percentage of Federal coal owner-ship in the area. The thick seams in thePowder River basin can be mined at a sub-stantially lower cost than other U.S. coaldeposits. Federal coal leases are concen-trated in the Uinta-Southwest Utah region be-cause of its diversity of high-quality coals in-cluding metallurgical coal. The region is oneof the oldest active mining areas in the West.The majority of reserves under lease in theUinta-Southwest Utah region must be minedunderground. The Green River-Hams Fork


Figure 18.–Coal Production Regions in the United States: Nov. 9,1979

I Regionm

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 south-western Wyoming has a fairly even divisionbetween surface and underground minablereserves.

Of the total Federal reserves covered byPRLAs, 45 percent are located in the PowderRiver basin. The 2.4 billion tons of PRLAreserves in the Powder River basin includesome 760 million tons that are recoverableonly by underground or in situ methods. Con-sequently these underground reserves areunlikely to be developed commercially withinthe next 10 years. 1 If these underground

1J. R. Boulding and D. Pederson Development and ProductionPotential of Undeveloped Federal Coal Leases and Preference

PRLA reserves are excluded from the totalreserves under PRLA, the Powder River basinstill contains 35 percent of the total. The SanJuan River region with 28 percent (32 percentif Powder River underground reserves aresubtracted) and Denver-Raton Mesa regionwith 14 percent (or 16 percent) also havesubstantial amounts of reserves under PRLA.

Right Lease Applications in the Powder River Basin and OtherWyoming Coal Basins, final report (Washington, D. C.: Office ofTechnology Assessment, 1981). PRLAs must have commercialquantities of coal to qualify for a lease. It is possible that in situgasification may allow development of underground coal in thePowder River basin, but this technology is still experimental innature, and is likely to be so until after 1984, which is thedeadline for processing all PRLAs, Consequently, it is possiblethat areas under PRLA that include only underground reservesmay not have leases granted.

Ch. 4—Federal Coal Resources . 63

Table 19.—Distribution of Recoverable Coal Reserves Under Federal Lease and Preference Right LeaseApplication by Major Coal Production Region

Recoverable reserves (billions of tons)b

FY79

Coal Preference right Federa l coal product ion

p r o d u c t i o n Number ofUnder lease lease appl icat ions (millions of tons) f

. — .region State Ieases a S u r f a c e U n d e r g r o u n d

—

Total S u r f a c e U n d e r g r o u n d Total Surface U n d e r g r o u n d

Fort Union ND 17 0.25 0 0 0 0M 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 AFEW 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 informationfFor 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 ProductionIn 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 inwhich nearly 99.5 percent was produced in Federal coal production and total coal pro-the six major Federal coal States of Colorado, duction from 1957 to 1979 in these six States.


Table 20.—Distribution of Recoverable Coal Reserves Under Federal Lease and Preference Right LeaseApplication 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( 1 0 0 % ) (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.

alncludes 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 INCH. 3 AND CH. 6. FOR THE PURPOSE OF DISCUSSION IN THIS CHAPTER. THESE DIFFERENCES ARE NOT SIGNIFICANT.

cReserves not shown due to confidentiality requirements.dlncludes 315.2 million tons of surface and 15.8 million tong of underground reserves in eight PRLAs in Montana and Oklahoma.eThere 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 fromthese States ranged between 3.2 and 3.8 per-cent of total U.S. production, but productionincreased dramatically during the 1970’s to21 percent in 1979 and 24 percent in 1980.Federal coal production from these Statesduring this same period ranged between 0.9and 1.3 percent of total U.S. production andincreased to about 8 percent in 1979 and1980.

Figure 19 also shows the changes in per-centage contribution of Federal coal to totalcoal production for these six States. Between1960 and and 1972 the share of Federal coalproduction in the six States declined fromabout 40 percent to 20 percent. Since 1973the percentage of Federal coal productionhas shown a general increase, although in1979, even though total Federal productionwas more than eight times higher than in1970, its percentage share of all production

(36 percent) was less than in 1960. During thenext decade, Federal coal production willprobably increase at a higher rate than non-Federal coal production because of the largeincreases from the Powder River region,where most coal reserves are owned by theFederal Government.

The current trend in production of West-ern Federal coal is toward large surface orunderground mines producing more than 1million tons per year. In Utah and Coloradowhere underground mines are common,small- and medium-sized mines ranging from200,000 to 1 million tons per year in capacitystill represent a significant and vital share ofactive and planned mines. Several mines onFederal leases in the Powder River basinhave planned capacities exceeding 20 milliontons per year. Annual production from one ofthese mines will exceed the individual 1979total production from Colorado, New Mexico,


Figure 19. —Annual Coal Production From theSix Major Federal Coal-Producing States

100

80

60

40

20

1955 1960 1965 1970 1975 1980

Year

aThe six States are Colorado, Montana, New Mexico, North Dakota, Utah, andWyoming

SOURCE Data for 1957.77 from table 2-7, U.S. Department of Interior, FinalEnvironmental States F e d e r a l C o a l M a n a g e m e n t P r o g r a m(Washington, D C U S Government Printing Office, 1979) 1978 datafrom table A-2, U S Department of In tenor Federal Coal ManagementReport Fiscal Year 1979 (Washington, D C U S. Government PrintingOff Ice, 1980) 1979 data from table 16 ch. 3 of this report

North Dakota, or Utah (18.1 million, 15.1 mil-lion, 15.0 million and 11.8 million tons, re-spectively).

The trend toward large mines contrastssharply with coal production from the period1920 to 1960. Most of the leases issued duringthis period were to individuals or small min-

ing companies that produced relatively smallamounts of coal for domestic or local indus-trial consumption. For example, about half(65 out of 138) of the leases issued before1960 produced coal at one time, but are nolonger producing coal. Most of the productionfrom these leases was from small under-ground mines, and sum total cumulative pro-duction from 59 of these leases was less thana million tons.2 This is less than the annualproduction of typical new mines on Federalleases.

The last two columns in table 19 show thebreakdown between Federal surface and un-derground coal producton from the differentcoal regions. Surface mines accounted for48.8 million tons, or 83 percent of Federalproduction in 1979. Since only 70 percent ofreserves under lease, and 61 percent of re-serves under PRLA* are surface minable,present production is concentrated moreheavily on leases with surface reserves thanunderground reserves. Many leases withlarge surface reserves in the Powder Riverbasin were not producing coal in 1979, so theemphasis on development of surface reserveswill probably continue over the next 10 yearsor so. However, full development of existingreserves will have to rely increasingly onmore costly underground mining methods.

2Data from Automated Coal Lease Data System, Summary ofFederal Leases—Oct. 1, 1979 prepared by the Bureau of LandManagement for OTA, including cumulative production fromeach lease, and production in fiscal year 1979. Of the otherleases issued between 1920 and 1960, 38 (27 percent of total)produced coal in 1979, and 35 (25 percent of total) never pro-duced coal.

*Table 19 shows that only 61 percent of the reserves underPRLA are surface minable, but if the subbituminous under-ground reserves in the Powder River basin are subtracted. asdiscussed earlier, the percentage changes to 71 percent.

Coal Ownership PatternsProduction 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 theownership 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 ownershipWest until the late 19th century, Federal coal of the coal and other mineral rights in lands


patented to settlers. Passage of the MineralLeasing Act of 1920 ended the era of disposalof Federal coal lands and established a leas-ing system for coal and other fuel and fer-tilizer minerals on Federal lands. The patternof coal ownership in the West has been gen-erally stable since then. * The major cate-gories of non-Federal coal ownership are: In-dian, railroad, State, and private (oftencalled fee coal because the owner holds feesimple title to the coal).

Sixty percent is a figure that is commonlycited as the amount of coal resources con-trolled by the Federal Government in theWest. This figure originates from estimatesmade by State BLM offices of Federal coalownership in coal-bearing lands (i.e., geologicformations known to contain coal deposits) inthe major Federal coal States (see table 21)and probably does not accurately reflect thepercentage of Federal ownership of recover-able coal reserves. This is because: 1) coaldeposits are not evenly distributed through-out areas of coal-bearing rocks, and 2) thepercentage of Federal coal landownershipvaries between coal regions.

A closer approximation (but still not en-tirely accurate, as discussed later) of Federalownership of coal resources can be obtainedby looking at the percentage of Federal coalland ownership in known recoverable coal re-source areas (KRCRAs). A KRCRA is an ad-ministrative and technical classification es-tablished by the U.S. Geological Survey todesignate areas where the location andamount of minable coal deposits have beenreasonably well-defined by geologic mappingand coal exploration. KRCRAs must be for-mally designated by publication in theFederal Register. Minable coal reserves arefound outside KRCRAs, but generally there isless information available about the extent ofthe reserves and little or no commercial coalmining in these areas. Table 21 shows that

*Further changes in coal ownership patterns are possiblethrough exchanges of Federal and non-Federal coal, but theamounts of coal involved are relatively small compared to totalleased reserves and the overall relationships among categoriesof coal ownership are likely to remain much the same. Ex-changes are discussed in more detail in ch. 9.

the six major Federal coal States contain116.7 million acres of coal-bearing lands, butthat only 17.5 million acres (15 percent) hadbeen included in KRCRAs as of March 1978.

Table 21 also shows that the percentage ofFederal coal acreage varies considerably be-tween States and coal regions. The percent-age of Federal coal ownership in KRCRAsrange from a low of 32 percent in NorthDakota to a high of 90 percent in the Coloradoportion of the Uinta region. Other KRCRAswith a high percentage of Federal coalownership are the Wyoming portion of thePowder River basin (82 percent), the NewMexico portion of the San Juan region (82 per-cent) and Utah (85 percent).

Overall, the percentage of Federal coalownership in KRCRAs in the six major Fed-eral coal States is higher than the percentageof Federal ownership in coal-bearing areas(65 percent v. 52 percent). Furthermore, theDOI estimates that the Federal Governmentowns about 72 percent of the recoverablecoal reserves in KRCRAs because of the highpercentage of Federal coal ownership in thePowder River basin where coal seams are ex-ceptionally thick. 3 However, Federal owner-ship of total recoverable coal reserves in theWest is probably lower than this percentagefor several reasons: 1) a number of Indiantribes control substantial amounts of coal re-serves that are not included in KRCRAs* and2) identification of KRCRAs has tended tofocus on areas of high Federal coal owner-ship and active coal exploration or leasing in-terest. Identification of new KRCRAs maytend to be located in areas where the per-centage of Federal coal ownership is lower(such as the Raton Mesa region). When all

3U.S. Department of Interior, Final Environmental StatementFederal Coal Management Program (Washington, D. C.: U.S.Government Printing Office, 1979), p. 2-5.

*Twenty Indian reservations in the West contain coal-bear-ing rocks and Indians control an estimated 15 percent of thestrippable coal reserves in the United States (Council of EnergyResource Tribes, The Control and Reclamation of Surface Min-ing on Indian Lands, Washington, D.C.: CERT, Sept. 30, 1979).Indian reservations with significant amounts of minable coalreserves are: Craw and Northern Cheyenne in southeasternMontana, Fort Berthold in North Dakota, and the Hopi andNavajo in Arizona and New Mexico.


Table 21 .—Federal Coal Ownership in Coal Regions and Known RecoverableCoal Resource Areas in the Six Major Federal Coal States

Known recoverable coalFederal coal Total coal resource areasd

State/coal acreage a acreage Federal coal Total coalproduction 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) 1.2Powder 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) 4.0Green River-Hams Fork 1.2(55) 2.2

Total 11 .8(39) 30.5 4.5(73) 6.2(19)

Colorado/Green River-Hams Fork 0.3(68) 0.5Uinta 0.5(90) 0.6San Juan 0.2(59) 0.3Denver-Raton Mesag 0.1(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) 2,3Raton Mesag o 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)c 150.2 — —

aFrom table 1-31 US. Department of the Interior, Final Environmental Impact Statement, Proposed Federal coal Leasing pro-gram (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.cThis total includes 23.4 million acres (97 percent of total Coal acreage) of Federal coal in Alaska and 0.4 million acres (4 p e r -

cent of total coal acreage of Federal coal in Oklahoma).dK nown 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 inKRCRAs.

eFrom 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 paren-theses Indicate percent of total KRCRA acreage in the State or region. Percentages may not match numbers in tablebecause 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,


these factors are taken into consideration,Federal ownership of total recoverable re-serves in the six major Federal coal States isprobably somewhere between 50 percent and60 percent.

Overall, the landownership patterns in theWest are probably no more complex thanthose found in the East and Midwest, how-ever, because Federal, State, and Indianlands generally cannot be sold, a coal oper-ator cannot gain ownership or control of apotential mine area through purchase of thetitle to surface and mineral rights as he mightin other regions. Consequently, a single min-

ing unit in Western States will often includecoal reserves of several different ownershipcategories to allow maximum recovery of thereserves and Federal and non-Federal coalreserves are frequently mined as part of thesame operation. * For example in CampbellCounty, Wyoming, which has a high percent-age of Federal coal, 16 out of 20 lease unitsinvolving Federal leases have non-Federalcoal associated with them, Federal coal is in-

*Mining of coal held by a single owner is often possible andhas been done in areas of mixed ownership, but in some casesrecovery rates are reduced because mining operations cannotbe designed for maximum efficiency.

68 • An Assessment of Development and Production Potential of Federal Coal Leases

terspersed with alternate sections (a sectionis a square mile and covers 640 acres) of rail-road coal over hundreds of thousands ofacres in the Fort Union region, the Montanaportion of the Powder River region and theWyoming portion of the Green River-HamsFork region. This situation also exists inlimited areas of the San Juan Basin in NewMexico. Mining in these areas usually in-volves both Federal and non-Federal coal. Inparts of North Dakota, on the other hand, cur-rent development of lignite reserves is con-centrated in areas where relatively smallamounts of Federal coal are interspersedwith State and private coal. The Crow andNorthern Cheyenne tribes in southeasternMontana own large blocks of surface minablecoal (estimated to exceed 5 billion tons) mostof which can be mined without involving Fed-eral, State, or private coal. About one-third ofthe 168 million tons of potential productioncapacity from the Montana Powder River

basin involves only Indian coal.4 All the majorcoal deposits in Arizona are located on theNavaho and Hopi Reservations, and all coalproduction in the State comes from thoselands. The Navaho tribe also has importantcoal reserves in New Mexico. Current pro-duction of coal in New Mexico comes from In-dian, Federal, State, and private land. Onlyone currently operating mine involves mixedownership of Indian, Federal, and privatecoal.

4See table 65 of this report. See also tables 6.8, vol. 1 andA.4.3, vol. 2 of J. R. Boulding and D. Pederson, Development andProduction Potential of Undeveloped Federal Coal Leases andPreference Right Lease Applications in the Powder River Basinand Other Wyoming Coal Basins, Final Report (Washington,D. C.: Office of Technology Assessment, 1981). Note that the168 million tons per year production capacity cited here ishigher than planned capacity for 1990; the 168 million tonsfigure is potential capacity in the post-1990 period. It does notdepend on new leasing of Federal coal, but does depend on anumber of factors including, for example, the building of theproposed Tongue River Railroad.

Coal Use and Market Areas

Table 22 summarizes current uses andmarket areas for coal produced in States withsignificant amounts of leased Federal coal.Possible new markets for Federal coal arediscussed in chapter 5. By far the largest enduse of coal for all States is steam electric gen-eration. In Wyoming, North Dakota, and NewMexico, over 90 percent of all the coal minedis used by electric utilities. There is consid-erable flexibility in the quality of coal thatcan be used for new powerplants because aboiler can be designed to accommodatealmost any coal. Existing powerplants haveless flexibility because use of coal with heatcontent and sulfur and ash content signifi-cantly different from coal for which the boilerwas designed often reduces its efficiency.

In contrast to the electric utility industry,the steel industry has much stricter specifica-tions for its coal. Coke, which is made frommetallurgical-grade coal, is used in the pro-duction of steel from iron ore. Metallurgical-

grade coal generally requires a low sulfurand ash content and medium to low content ofvolatile matter, as well as other specific phys-ical characteristics. Although low-sulfur andlow-ash coal is found throughout the West,relatively few coal deposits have the othercharacteristics necessary for the productionof coke. Colorado, Utah, New Mexico, andOklahoma are the only Western States withsignificant commercial deposits of metal-lurgical-grade coal. Major deposits of high-grade metallurgical coals are found in por-tions of the Uinta region in Colorado and Utahand in the Raton Mesa region of Colorado andNew Mexico. Smaller occurrences of metal-lurgical coal have been found in other areasof New Mexico and Montana (see fig. 17).

Other major industrial uses of coal in theWest include cement and lime processing,sugar processing, other metals processing,and, in Wyoming, processing of the mineral


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/ ln-State

out-of-Utility commercial Residential State State Non-utility usesb Utility Industrial

Colorado . . . .

M o n t a n a

New Mexico. . .

North Dakota.

O k l a h o m a

Utah .

W y o m i n g .

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 0d

75

16

1.8 47

22

45

89

40

25

84

53

78

, ., , ,, ., , A

CoKe for steel, cememt, sugarprocessing, metals processing,railroad.

Cement, sugar processing.

Cement, metals processing(copper), drilling mud, coke forsteel (Raton Mesa),

Sugar processing, Ieonardite,charcoal briquets.

Lime and cement (16% total)coke for steel (3% total)

Coke for steel (about half non-utility use), cement, metalsprocessing.

Trona processing, syntheticcoke, cement, sugarprocessing.

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).

apercentage breakdown in use categories taken from Office of Technology Assessment State assessment and market survey reports. In-State/out-of-State Per-centages 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


trona. * Like utilities, most industrial users(other than steel manufacturing) use coal forheat rather than its physical and chemicalproperties. However, industrial users gen-erally do not require large amounts of coalcompared to utilities, so economies in trans-portation costs through the use of unit-trainscannot be realized. Because of this, high heatcontent is a premium for industrial and com-mercial users, and it is the coal regions thatproduce coal with the highest heat content(Green River-Hams Fork, Uinta and Okla-homa) that have the widest market areas forindustrial uses of coal.**

*Trona is a mineral that is refined to soda ash, which in turnis used in the production of glass, woodpulp and paper process-ing, and manufacture of other chemicals. Southwestern Wyo-ming contains the only known commercial deposits of trona inthe world (Department of Economic Planning and Development1975 Wyoming Mineral Yearbook, Cheyenne, Wyo.: DEPAD,1976).

* *One notable exception to the premium on heat content isthe mining of leonardite in North Dakota, Leonardite is a soft,earthy coal-like substance that results from the oxidation of lig-nite. It is a poor fuel (about 4,000 Btu/lb) but is useful as a soilconditioner, and for various industrial uses such as manufac-ture of oil well-drilling muds, water treatment and stains forwood-finishing.

All of the States that produce Federal coalhave either a nearly even division betweencoal that is used in-State and out-of-State(Colorado and Utah) or export most of thecoal that is produced in the State, either ascoal (Montana, Oklahoma, and Wyoming] oras coal and electricity generated at mine-mouth plants (New Mexico and North Da-kota). Table 22 also shows the current marketareas for coal that is exported out-of-State.Wyoming has by far the largest market areaof any Western State, with 1979 coal pro-duction for utility use going to 14 States andnonutility use to 13 States. In contrast, NorthDakota has the most limited market area,because of the low heat content of the coal.Colorado and Utah are the Western Statesthat produce significant amounts of coal forindustrial uses (26.6 and 24.9 percent respec-tively) and the importance of this market isshown by the fact that coal from Coloradoand Utah was shipped to more States for in-dustrial uses than for utility uses (16 v. 10States for Colorado, and 11 v. 7 States forUtah). Chapter 5 discusses the reasons forthe differences in market areas between theStates in more detail.


Quality of Federal Coal Reserves

User needs related to coal quality havebeen discussed briefly in the previous sec-tion. Except for metallurgical-grade coal(where several additional physical and chem-ical characteristics are important), the pri-mary parameters of coal quality that are ofconcern to coal users are: 1) heat content, 2)sulfur content, and 3) ash content.

Heat Content

The large majority of coal is used for itsenergy value, which is usually expressed asthe number of British thermal units (Btu) perpound of coal. * Coals vary considerably inheat content, ranging from less than 5,000Btu/lb for low rank lignites to more than14,000 Btu/lb for bituminous and anthracite

*A Btu is the quantity of heat required to raise the temper-ature of 1 lb of water 10 at, or near, its point of maximum den-sity (39.1 0 F).

coals.* (See table 23.) This possible range inheat content of coal can make a substantialdifference in the amount of coal that is used.

*Coal deposits are classified into 13 different ranks basedprimarily 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 offwhen coal is heated in the absence of oxygen). Table 23 showsthe standards for classification of coal by rank that have beenestablished by the American Society for Testing and Materials(ASTM). Lignite and subbituminous coal are classified accord-ing to heat content calculated on a moist mineral-matter-freebasis. Bituminous coals are classified based on both heat con-tent and percent volatile matter in the coal. High-volatile bitu-minous coal (greater than 31 percent volatiles) are classifiedinto three ranks based on heat content. Coal with less than 31percent volatile matter are classified as low or medium-volatilecoal irrespective of heat content, Anthracites have very lowcontent of volatile matter (less than 8 percent), Heat contentsreported in this chapter are on an as-received basis, which dif-fer from the heat contents which would be used to rank the coalusing ASTM procedures, because corrections have not beenmade to account for ash content (for lower rank coals) or ashand moisture content (for higher rank coals). The as-receivedheat content of a coal sample is lower than the heat contentthat is used to classify the sample according to rank.

Table 23.—Classification of Coals by Rank

Fixed carbonlimits, in per-

cent (dry,mineral-matter-

free basis)

Equal orgreater Less

Class Group than than

Volatile matterlimits, in per-

cent (dry,mineral-matter-

free basis)

Equal orgreater Lessthan than

Calorific valuelimits, in Btu per

pound (moist,mineral-matter-

free basis)a

Equal orgreater Less Agglomeratingthan 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 10,500Subbituminous C coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,300 9,500Lignite A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,300 8,300Lignite B, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,300

aMoist refers to coal containing Its natural inherent moisture but not including visible water on the surface of the coal.blf 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.dlt 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 withinthe 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 fromAmerican 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)


For example, a powerplant using lignite mayburn more than twice as much coal as a pow-erplant using bituminous coal to produce thesame amount of electricity. However, themost important concern of the user in relationto heat content is the cost per unit of energyin the coal (usually expressed as cents ordollars per million Btu) rather than the heatcontent itself. Thus, a low rank coal that hasa lower delivered price per Btu in generalcompares favorably with a higher rank coalat a higher delivered price.

Sulfur and Ash Content

Sulfur content has become an importantaspect of coal quality since passage of theClean Air Act of 1970, which established lim-itations on sulfur dioxide emission from coal-fired powerplants. The effect of sulfur emis-sion standards on the demand for Westerncoal is discussed in more detail in the follow-ing chapter on markets. Ash content may be aconcern to users if its percentage reaches alevel (generally greater than 15 percent)where ash begins to build up in boilers andreduce their efficiency. High ash content alsoincreases the cost of ash disposal after thecoal is burned. Boiler design must also takeinto account the physical and chemical prop-erties of the sulfur and ash in the coal that isused. To some extent, sulfur and ash can beremoved from coal before it is burned, how-ever this process adds to the cost.

Variations in Coal Quality by Region

Coal ranks in the Northern Great Plainsprovince fall within a fairly narrow range oflignite and subbituminous coals. In the RockyMountain coal province, on the other hand,the different coal regions have a considerablerange of coal ranks. The Uinta-SouthwestUtah region has the widest range of coalranks, ranging from lignite to anthracite, al-though current production is entirely bitu-minous coal. The diversity of coal ranks in theRocky Mountain province resulted from thefact that the processes promoting the forma-tion of coal—heat and pressure—have oper-ated with varying degrees of intensity over

the geologic history of different deposits. TheNorthern Great Plains province, on the otherhand, has had a relatively simple geologic his-tory in which coal forming processes havegenerally not been very intense.

Table 24 summarizes some of the impor-tant coal quality characteristics of leasedFederal coal and major coal fields with Fed-eral leases. The location of these fields isshown in figure 17. The data shown for theFort Union and Powder River regions showsthe range of values for existing leases,whereas data for other coal regions is for thewhole coal field, which is generally widerthan the range for actual Federal leases inthe field.

All coals in the Fort Union region are lig-nites, whereas Federal coal reserves underlease in the Powder River basin are primarilysubbituminous coal. The leased coal in theDecker and Colstrip areas in Montana havehigher heat contents than leased reserves inthe Wyoming portion of the Powder Riverbasin, but the Colstrip area also has highersulfur contents. Leased reserves in the Wyo-ming portion of Green River-Hams Fork re-gion are generally higher quality subbitu-minous coals [greater than 9,000 Btu/lb) andbituminous coals. Maximum sulfur content ishigher than in the Powder River basin, butoften coal from higher sulfur seams can beblended with low-sulfur coal to produce coalwith acceptable levels of sulfur.

Major fields with leased Federal coal inColorado and Utah contain mostly bituminouscoals, except for the Alton field in southwestUtah which contains leased reserves of subbi-tuminous coal. Leased reserves in the SanJuan River region in New Mexico are mostlysubbituminous coals with generally higherheat content than in the Powder River basin.There are leased Federal reserves of metal-lurgical-grade coal in the Uinta region in Col-orado and Utah and the Raton Mesa region inColorado and New Mexico. There are somereserves of lignite under Federal lease in theDenver region of Colorado, but total reservesleased in this area are small and not likely tobe developed in the next 10 years.

84-141 0 - 81 - 6 : 21 ‘?


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 contentState 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 6,660-6,740Powder 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 — 6,500-7,500Glenrock 8-12 0.4-0.5 7,300-8,000

Green River 8 4 Hanna 4.8-18.3 0.4-1.4 9,400-11,460Rock Springs 2.8-17.5 0.6-1.2 9,000-13,670Little 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 YampaNorth Park 2 1 —dUinta 8 8 Book Cliffs

Danforth HillsSomerset

San Juan River 4 2 —dDenver 2 1 — d

Raton Mesa 2 1 —d

3-202-195-232-1o3-113-274-455-22

0.3-1.80.2-1.60.4-1.70.3-1.40.5-0.80.5-1.30.2-1.10.4-1.3

9,800-12,6006,500-11,3009,800-13,600

10,100-12,00010,000-13,5009,400-14,7003,600-10,800

10,200-13,900

Utah Uinta 15 3 Book Cliffs 6-7 0.4-1.0 12,500-13,000Wasatch Plateau 6-7 0.6 12,200-12,700Emery 9-20 0.5-2.5 11,400-12,300

Southwest Utah 4 2 Alton 9 1.1 9,600Kaiparowits 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 9,800-10,600Bisti 18.5 0.4-0.9 7,500-10,000Star Lake 15-20 0.4-0.7 9,400-10,200

Raton Mesa 1 1 Raton 9-14 0.6 14,300aNumber 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 EnergyAdvisory 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 assessmentreports; Colorado and Utah — Colorado School of Mines Report cited in footnote a; New Mexico — J. W. Shomaker, E. C. Beaumont and F. E. Kottiowski, StrippableLow-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


A notable characteristic of all the Westerncoal fields with leased Federal reserves istheir generally low-sulfur content. Only theEmery field in Utah has a maximum sulfurcontent greater than 2 percent. In contrastsulfur contents exceeding 2 percent are typ-ical in the Midwest and Appalachia, exceptfor West Virginia, which produces a signifi-cant amount of low-sulfur coal. Althoughmany Western coal fields have coal seamsthat exceed 1 percent sulfur, mining is gen-erally concentrated in seams that averageless than this percentage. For example, a re-cent survey of mine expansions and proposednew mines by ICF, Inc., found that only 1 minewill produce coal with more than 1 percent

sulfur5 of 55 mines responding in the PowderRiver basin and southern Wyoming. All minesresponding in the Rocky Mountain coal prov-ince will produce coal with less than 1 per-cent sulfur. In contrast, only 6 percent of themines surveyed in the Midwest and 25 per-cent in northern Appalachia will producecoal with less than 1 percent sulfur. *

‘Percentages calculated from table 11, ICF, Final Report,Survey of United States Coal Mine Expansion Plans preparedfor the Department of Energy (Washington, D. C,: ICF, Inc.August 1980). The percentage is calculated for only thosemines for which coal quality information was reported, whichranged from 71 to 87 percent of all mines included in the surveyfor the different regions mentioned in the text,

*It should be noted that differences in sulfur content areslightly less when they are compared on a uniform Btu basis.


The same ICF mines survey shows that, ex-cept for the San Juan River region, ash con-tent is also generally lower in the West thanin the Midwest and Appalachia, although thedifferences are less than with sulfur. Accord-ing to the ICF survey, all new mines and mineexpansions in the Northern Great Plains and88 percent of the mines in Utah and Coloradowill produce coal with less than 10 percentash. In the Midwest 68 percent and in north-ern Appalachia 65 percent of mine expan-sions and new mines involve less than 10 per-cent ash. The San Juan River region in NewMexico is the only area with leased Federalcoal where ash content seems to be a signifi-cant coal quality factor. Eighty-five percentof the mines in the ICF survey from this areawill produce coal with greater than 10 per-cent ash and most of these mines will producecoal that exceeds 14 percent ash. At mines inthe San Juan River region of New Mexico, thecoal is frequently cleaned to reduce ashbefore it is burned.


Because Western coal has generally lower heat content thancoal from Appalachia and the Midwest, its effective sulfur con-tent is higher than a comparison based on percentages wouldindicate. Table 12 of the ICF survey cited above comparesmines according to pounds of sulfur per million Btu. In theNorthern Plain, for example, 67 percent of the mines will pro-duce coal with less than 0.83 lb sulfur per million Btu (coal lessthan this can comply with the 1970 new source performancestandards with small amounts of sulfur reduction) compared to30 percent of the mines in northern Appalachia. Western coalstill has a lower sulfur content on the whole than Eastern coal,but the difference is not as great as sulfur percentage compari-sons suggest.

In general, the quality characteristics ofleased Federal coal reserves would not pre-vent development of the coal, based on userneeds, provided the coal can be sold at aprice that is competitive with coal producedfrom other mines or regions. There are a fewexceptions to this generalization. All Federalleases in the Fort Union region and about 50million tons per year potential production ca-pacity from Federal reserves under lease andpreference right lease application in theWyoming Powder River basin are suitableonly for onsite development because of lowheat content. * Similar constraints for leasedevelopment exist for NERCO’s Cherokeelease block in the Little Snake River field insouthern Wyoming and several leases in theDenver region of Colorado.

The demand for metallurgical coal in theWest is expected to remain relatively stableduring the next decade because most coalcurrently produced is used at steel plants inthe region. Production of metallurgical coalcould increase slightly to meet expandedforeign exports. The availability of Federaland non-Federal coal from the metallurgicalcoal areas in the West is expected to meet de-mand in the foreseeable future.

*Forty-five million tons out of the 50 million tons are unlikelyto be in production by 1991, but could come into production inthe 1990’s.

Geologic Conditions and Mining Methods

The diversity of geologic and topographicconditions in which coal is found in the Westrequires a variety of mining methods. Thissection describes the different geologic condi-tions in the West that affect the choice of min-ing methods and the ease or difficulty of min-ing coal. Chapter 11 describes in more detailthe surface and underground mining methodsthat are currently used in the West and an-alyzes the potential for use of more advancedmining technologies.

Table 25 summarizes data on seam thick-ness and dip (the inclination of a coal seamexpressed as degrees from the horizontal) inthe major coal regions in which Federal coalis leased and the dominant mining methodsand common mining problems encountered.The thickness and dip of a coal seam affectthe ease and cost of mining. In most of theseregions coal seams can be very thick. Two re-gions, the Powder River and Hams Fork, havesingle coal seams that exceed 100 ft. All other


Table 25.—Geologica and Mining Characteristics of Major Federal Coal States

Coal production Coal—

Typicalregion 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 ForkHams 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 Springsarea, Wyoming. No serious problems inColorado because dips are generally lesssteep than in Wyoming.

Uinta-southwest 1-30 (CO) Less than 10” (Uinta) Mostly underground in Uinta Uinta area: some methane, floor and roofUtah (CO, UT) 3-25 (UT) generally less than 70 but region at present. No present stability, faulting, steep dips (CO), sand-

UP to 15” (SW Utah). production in southwest Utah, stone dikes (CO), thick overburden (UT andbut both surface and under- CO), variable dips (UT), water (UT, CO),ground possible. rugged terrain (UT, CO). Southwest Utah:

discontinuous beds, burned coal, undulat-ing roof, water, difficult terrain, splits andpartings 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 under-ground 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 Ex-

isting Federal Coal Leases in the Western United States, Final Report prepared by the Colorado School of Mines for the Office of Technology Assessment, March1980. Some additional data on coal rank and seam dips comes from Summary Geologic Description of the United States Coal Provinces and Coal Regions, Preparedfrom 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. Miningproblems 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 TechnologyAssessment State assessment reports.

cThere 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 con-tent 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 hasbeen 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,


regions have coal seams that range up to 30to 50 ft, except Oklahoma and the RatonMesa.

Thick coal seams are advantageous for sur-face mining because less overburden must beremoved per ton of coal compared to the thin-ner coal seams (generally less than 6 ft) thatare mined in the Midwest and Appalachia.On the other hand, in underground mines re-covery of coal reserves is considerably de-creased where coal seams exceed 10 or 12 ftin thickness, although full seam extraction ofcoal seams 20 to 30 ft thick is currentlyachieved in mines in France and Poland.However, the high costs of the methods used

to achieve high recovery rates in thick coalseams has prevented use of these methods inthe United States where underground coalmines must compete with inexpensive sur-face mined coal.

Coal seams in the West range from horizon-tal to vertical, but there are considerable re-gional differences in the typical dips of coalseams (see table 25). The Fort Union, PowderRiver, Raton Mesa, and San Juan River coalregions have generally flatlying beds whichare easily surface mined. Difficulties may beencountered in the Colorado portion of theRaton Mesa region because of factors other


than dip (see table 25). The Green River andSouthwest Utah regions and the Oklahomaportion of the Western Interior coal regionare generally characterized by coal seamsthat dip less than 70, but some coal leases inthe Rock Springs field in the Green Riverregion and in Oklahoma have more steeplydipping beds that can create difficulties formining. The Hanna field and the Hams Forkcoal region in Wyoming typically dip morethan 100, The dipping seams in the Hannafield, located in the northeast part of theGreen River region (see fig. 17) present someof the most difficult surface mining conditionsin the United States, and special methods ofusing draglines to handle overburden havebeen developed.

At this time, only surface mining methodsare used to produce coal in the Powder Riverand Fort Union regions because thick seamsand low heat content make underground min-ing economically unfeasible, In-situ gasifica-tion in the Powder River region may permitdevelopment of deeper coal beds (more than500 ft of overburden) in the future. All pro-duction at present from the Hams Fork regionin Wyoming and the San Juan River region inNew Mexico is from surface mines, but sev-eral operators are planning or consideringunderground mining in these areas becausethe higher heat content of these coals makesit economically feasible to do so. Coal in theUinta and Raton Mesa regions and the Col-orado portion of the San Juan River region iscurrently mined by both surface and under-ground methods, Mining in the Utah portionof the Uinta region is almost entirely under-ground, and there is no mining in the South-west Utah region at this time, although bothsurface and underground mining is possible.

Geologic conditions that make mining diffi-cult are also very site specific, but there are

definite regional differences in the extent towhich problems can be expected to occur.The Fort Union, Powder River, and San JuanRiver regions generally have few, or minormining problems, although highwall stabilitymay be a problem locally in the NorthernGreat Plains. Steep dips in the Hams Fork Re-gion and the Rock Springs and Hanna fields inthe Green River regions of Wyoming createdifficulties for both surface and undergroundmining as mentioned previously. In under-ground mines a variety of difficulties can beencountered in the Uinta, Southwest Utah,Raton Mesa regions and in Oklahoma. Thenumber and relative importance of under-ground mining problems varies betweenthese regions (see table 25) but include: meth-ane hazards, roof and floor instability, dikesand intrusions in the coal, faulting, steepdips, thick overburden, variable dips, thinseams, undulating or discontinuous beds,splits and partings in coal, water, and burnedcoal.

Mining conditions found on Federal leasesinclude almost the whole range of possiblecombinations that make mining easy or diffi-cult. The Gillette field in northeastern Wyo-ming presents some of the most ideal miningconditions found anywhere, with thick, flat-lying coal seams under shallow overburden.Underground mining conditions on Federalleases in western Colorado and central Utahrange from very favorable to very difficult,Among the most difficult underground miningproblems that are sometimes encounteredare: overburden that exceeds 3,000 ft, seamdips that approach 350, extreme fracturingand faulting in both the coal seams and theconfining rock strata, and unstable floor androof conditions. Chapter 11 examines in moredetail geologic conditions as they affectunderground mining methods.


Summary

Leased Federal coal reserves encompass awide range of coal types, qualities, and geo-logic conditions for mining. This section sum-marizes some of the important points made inthis chapter.

1. Federal coal leases are located in 1 4States, but the vast majority of leased Fed-eral coal reserves (98 percent) are locatedin six Western States: Colorado, Montana,North Dakota, New Mexico, Utah, andWyoming. Coal reserves under lease andPRLA are very unevenly divided betweenthese six States. Wyoming has by far thegreatest reserves under lease and PRLA(56 and 43 percent respectively of total re-serves under lease and PRLA in the sixStates). Wyoming and Utah together con-tain more than three-quarters of the re-serves under Federal lease, and Wyoming,New Mexico, and Colorado contain nearly90 percent of the reserves under PRLA.Most of the reserves under lease and PRLA(about 70 percent for both)* can be minedby surface methods, but a majority of theleased reserves in Colorado and Utah mustbe mined by underground methods.

2. Although the Federal Government ownsapproximately 60 percent of the coal re-serves in the six major Federal coal States,production from Federal coal leases be-tween 1957 and 1979 fluctuated betweenonly 20 and 45 percent of total production.Since 1973 the quantity and percentageshare of Federal coal production in these

‘Table 19 shows that only 61 percent of the reserves underPRLA are surface minable, but if the subbituminous under-ground reserves in the Powder River basin are subtracted, asdiscussed earlier, the percentage changes to 71 percent.

3.

States has shown a general increase. How-ever in 1979, even though total Federalproduction was more than eight timeshigher than in 1970, its percentage shareof all production in the six States was lessthan in 1960. During the next decade,Federal coal production will probably in-crease at a higher rate than non-Federalcoal production because of the large in-creases from the Powder River regionwhere the Federal Government owns alarge percentage of coal reserves.

The quality of coal reserves presentlyunder lease and PRLA does not appear toimpose any serious limitations for meetingthe demand that is likely for Western coalover the next 10 to 15 years. Most leasedreserves have low sulfur and ash contentand are suitable for use by utilities, whichconstitute the single greatest user of West-ern coal. All Federal leases in the FortUnion region and about 50 million tons peryear potential production capacity fromFederal reserves under lease and PRLA inthe Wyoming portion of the Powder Riverbasin are probably suitable only for onsitedevelopment for power or synfuels plantsbecause of their low heat content. (How-ever, the majority of Federal reservesunder lease are of sufficiently high qualityto be exported out of the producing State. )The demand for metallurgical coal in theWest is expected to remain relatively sta-ble during the next decade and even whenpossible increases in demand for foreignexport are considered, the availability ofFederal and non-Federal metallurgical coalin the West appears to be adequate for theforeseeable future.

CHAPTER 5

Markets and Projected Demandfor Federal Coal

—— —

Contents

PageFactors Affecting the Demand for Coal. . . . . 79User Needs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80Cost Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80Institutional Constraints. . . . . . . . . . . . . . . . . . 82

Trends in Factors Affecting the Demand forWestern Coal: 1980-90 . . . . . . . . . . . . . . . . . 82

Electrical Growth Rate. . . . . . . . . . . . . . . . . . . . 83Sulfur Reduction Standards. . . . . . . . . . . . . . . . 85Mine Costs.... . . . . . . . . . . . . . . . . . . . . . . . . . . 86Transportation Costs . . . . . . . . . . . . . . . . . . . . . 87Reclamation Costs . . . . . . . . . . . . . . . . . . . . . . . 88Royalty Rates and Severance Taxes . . . . . . . . . 88Industrial Demand . . . . . . . . . . . . . . . . . . . . . . . 89Synthetic Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . 90Foreign Export . . . . . . . . . . . . . . . . . . . . . . . . . . 92Institutional Constraints . . . . . . . . . . . . . . . . . . 93Factors Affecting Competition Between

Western Coal States. . . . . . . . . . . . . . . . . . . 93North Dakota... . . . . . . . . . . . . . . . . . . . . . . . . . 93Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96New 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 andProduction Goals. . . . . . . . . . . . . . . . . . . . . . . 99

Fort Union Region . . . . . . . . . . .............105Powder River Basin . . . . . . . . . . . ... ... ... ..105Southern Wyoming.. . . . . . . . . . . . . . . . . ... ..105Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105Utah. . . . . . . . . . . . .......................106New Mexico . . . . . . . . . . ..................107Comparisons of Forecasts . . . . . . . . .........107Demand for Western Coal: 1990-2000........108

Summary ● .. ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ 110

List of Tables

Table No, Page26. Factors Affecting Market Demand for

Western Coal... . . . . . . . . . . . . . . . . . . . . . . 8127. Comparison of Historical Forecasts of

Annual Growth Rate of Total ElectricGeneration. . . . . . . . . . . . . . . . . . . . . . . . . . . 83

28. Representative Mine-Mouth Prices andTransportation Costs for Western Coal. . . 87

29. Major Market Advantages andDisadvantages of the Major FederalCoal-Producing States. . . . . . . . . . . . . . . . . 94

SO. Market Relationships Between the SixMajor Federal Coal-Producing States . . . . . 99

31. Comparison of Demand Projections for

32

33

Major Western Federal Coal Regionsand States With OTA Task ForceDemand Estimates . . . . . . . .. ... ... .., ..103Demand and Production Forecasts forCoal for the United States: 1985-2000...,.104Forecasted Changes in Contribution ofWestern Coal to Total U.S. Production, ,..ll0

List of Figures

Figure No. Page20, Market Areas of the Six Major Federal

Coal-Producing States. ,, ...,... . . . . . . . 9821. Demand Projections for the Fort Union

and Powder River Coal Regions andSouthern Wyoming, Compared toOTA Task Force Estimates . . . . . . . .. ....106

22. Demand Projections for Colorado, Utah,and New Mexico, Compared to OTATask Force Estimates. . . . . . . . . . . . . . . . ..107

23. Demand and Production Forecasts forthe United States: 1985-2000 and theSix Major Federal Coal States: 1985-90....108

CHAPTER 5

Markets and Projected Demandfor Federal Coal

The concentration of Federal coal re-sources in the West means that the demandfor Federal coal is closely tied to the demandfor Western coal. The demand for Westerncoal is determined by the dynamic interactionof various economic and institutional factorsthat affect: I) coal use in the far West, 2) thecompetitive position of Western coal in en-ergy demand centers in the Midwest, North-Central and South-Central United States withrespect to other coal provinces (the GulfCoast and Interior provinces primarily), and3) the competitive position of Western coalwith respect to competing fuels such as oil,gas, and uranium.

This chapter first examines in a generalway the factors that affect the overall de-mand for coal, and then looks a little moreclosely at the effect these factors have on themarket situation for Western coal as of 1980.The impact that likely or possible trendscould have on Western markets through to1990 are then examined in some detail. Next,

the major market advantages and disadvan-tages of coal produced from the six majorFederal coal-producing States (North Dakota,Montana, Wyoming, Colorado, Utah, andNew Mexico)* are summarized with an anal-ysis of the relative competitive position ofcoal production from these States in differentregions of the country. Finally, the results ofrecent market studies and forecasts of the de-mand for Western coal in the period 1980 to1990 are analyzed in relation to demand esti-mates that were developed by OTA to eval-uate potential production from existing Fed-eral coal leases. The chapter concludes witha general look at the range of possibilities fordemand for Western coal in the context oftotal U. S. coal demand between 1980 and2000.

*Arizona produced almost as much coal in 1979 as NewMexico, and thus ranks as a major Western coal-producingState. However, all production in Arizona is from Indian landand is thus not considered in this chapter.

Factors Affecting the Demand for Coal

The demand for coal is primarily the resultof individual consumers - or users makingchoices based on suitable quality and theprice of coal from different regions and,when other fuels can be substituted for coal,the price of alternative noncoal energy re-sources. Although these relative prices maybe significantly affected by “nonmarket” fac-tors, such as Government policy, in thischapter the term “market demand” refers toleast-cost energy purchasing decisions madeby users, ** “Nonmarket” factors in the form

* * It should be noted that coal quality factors affect purchas-ing decisions and may result in the purchase of higher costcoal. For example, higher delivered cost of Western low-sulfurcoal East of the Mississippi compared to local high-sulfur coalhas been accepted by some utilities because retrofitting old

of Government policy can have a significantimpact on the demand for coal, but a distinc-tion can be made between Government pol-icies that: 1) change the institutional contextof the market system and 2) directly stimulatethe demand for coal. Policies in the firstcategory include most environmental regula-tions that change the relative cost of usingcoal from different regions. The market sys-tem itself makes the necessary adjustments tothe new institutional context. Thus, the mar-

plants with stack gas scrubbers was considered too costly andrisky due to uncertainties surrounding the reliability of avail-able scrubbers. However, even in this case the decision to pur-chase more expensive coal is based on the belief that in thelong run the cost of generating electricity would be cheaperthan 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 thelevel of demand and regional shifts in coalproduction are based on least-cost energypurchasing decisions. Government policiesthat directly stimulate demand for coal in-clude Government subsidies for a commercialcoal-based synthetic fuels industry and theoff-gas requirements of the Powerplant andIndustrial Fuel Use Act. * At the present timeGovernment intervention in the market sys-tem to directly increase demand for coalforms a small percentage of coal use in theUnited States. However, if Government sub-sidies are seen as necessary to develop alarge-scale coal-based synthetic fuels in-dustry, this situation could change.

Table 26 lists some of the major factorsthat affect demand for coal. These factorsfall into three broad categories: 1) userneeds, 2) costs (mine mouth, delivered, andcosts of converting into useful energy), and3) institutional constraints on production.

User NeedsUser needs are the primary determinant in

the demand for coal. High levels in the elec-trical growth rate, high steel production, andextensive conversion of industrial and elec-tric utility boilers to coal from oil and gas willall mean an increase in coal demand. Highlevels of coal-based synthetic fuels develop-ment and high overseas demand for coal willalso increase coal markets. The importantrole that coal is expected to play in the U.S.energy picture is largely the result of the highcost and less certain availability of oil. Coal’smain competitors as substitutes for oil andgas are nuclear power and energy conserva-tion. ** Low levels of energy conservation and

*The off-gas requirements in this act actually have elementsof both kinds of policies: the law requires conversion from gasto 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 openmarket will determine where the utility buys its coal based on anarrower set of least cost considerations. These requirementshave now been repealed by Congress (see third footnote, nextcolumn),

**If conservation reduces the total level of energy consumption which is served by oil and gas, there is less need to substi-tute other energy sources. Without conservation the demandfor coal as a substitute to oil and gas would be higher, and it isin this specific sense that conservation is a competitor to coal.

nuclear power growth would contribute to in-creased demand for coal.

Coal markets are also affected by the ex-tent of substitutability of alternative sourcesto meet user needs. Electric utility needs canbe met by oil, gas, uranium, conservation*and a wide range of coal qualities. For a newpowerplant the primary determinant in utilitychoice of fuels is the relative cost of produc-ing electricity. Once a choice has been madeand a powerplant built to meet the specifica-tions of the chosen fuel some substitutionsbecome impossible (i.e., nuclear to coal) andmost become costly (i.e., oil or gas to coal andshifts from one coal type to another). On theother hand, there is little substitutability inthe demand for metallurgical-grade coal.**

Cost Factors

For a coal producer to sell his coal, he mustusually produce it at a price such that de-livered cost per Btu to the consumers (mineplus transportation cost) is lower than thedelivered cost per Btu of coal offered by com-peting coal producers. If the offered price ishigher, then the coal must be more attractiveto the prospective buyer, either because thecoal quality characteristics are more suitablefor his need, or for some other reason such aslower costs to produce electricity or greaterassurance of reliable delivery.*** Basic mine

*Conservation in this context refers to utility investments inactivities that reduce total demand or reduce peak demand(such as time-of-day pricing, load management, insulation loanprograms) because they are cheaper than investments that in-crease generating capacity. This kind of conservation is differ-ent from conservation by electricity users that is purely inresponse to increased cost of electricity. The latter form of con-servation reduces the amount of electricy a utility needs to pro-duce, but does not fulfill the needs of the utility as a business.

**To a limited extent low-sulfur, low-ash coals that do nothave normal coking properties can be blended with metallur-gical-grade coal to produce coke, Newly developing technologyfor production of “form coke” can take a wide range in rank ofcoal, although sulfur and ash content are still important.

***The Powerplant and Industrial Fuel Use Act which man-dated conversions to coal from gas in utility and large in-dustrial boilers may result in the choice of coal as a fuel wherecost comparisons would indicate staying with gas. However,the impact of this law has been reduced by the Omnibus BudgetReconciliation Act passed by Congress in August 1981 whichrepealed the ban on use of natural gas in 1990 in section 301 ofPIFUA, Instead, utilities that use natural gas as a primary fuelare required to develop conservation plans to reduce currentannual power production attributable to natural gas by 10 per-cent 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 trendsFactor when factor is: when factor is: situation in West (1980-90)

User needsUtilities

Electrical growth rateSO, emissions standards

Competing energy sourcesCost of oil & gasNuclear power growth

IndustrialSteel productionIndustrial boiler conversions

Synthetic fuels development

Foreign export

High (>5%)1970 NSPS, limitson total emissions

HighLow

HighHigh

High

High

Low (<3%)1979 NSPS or noemissions limits

LowHigh

LowLow

Low

Low

LowCurrent standardsreduce demand com-pared to 1970 NSPS.

HighLow (in West)

LowLow

Low

Low

Low - moderateAmendments to Clean Air Actcould change situation either way.

HigherLow (in Western coal’s market area)

LowLow - 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 (NorthernPlains) moderate(Rockies)

Low High Moderate

Low High Low - moderate

Low High Low

Low High Low - surface minesHigh - underground mines

Low H i g h Low - existing leasesHigh - new leases

Low High Low - high

Delivered costTransportation Low High Low (mine-mouth plants)

High (export)

Technologies for clean burning Highd Low Moderate - highof coal (cost)

Little change

Little change

Little change

Little changec

Little changeLittle change

Increases as existing leases comeup for adjustment

Some increase or decrease at Statelevel is possible

Additional increases likely with railderegulation and increased fuelcosts. Possible decreases in somelocalities with slurry pipelines

Decreases possible through in-creased experience andtechnological improvements

Institutional constraints at mine Low High Institutional constraints are highly site specific. See chs. 8 and10 for specific examples.

aFor 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.CLittle 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 en-forcement 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 fac-tor, with low reliability favoring Western coal and high reliability favoring Midwestern coal.


costs include the cost of equipment purchase,operation and maintenance, labor, and thecost of reclamation and improving health andsafety conditions for miners. Additional costsmay be added as a result of royalties thatmust be paid to the owner of the coal andseverance taxes imposed by States in whichthe coal is mined. Low costs in all these fac-

tors relative to other coal producers improvesthe competitive position of a coal deposit.Heat content can make an important dif-ference in the unit-energy cost of coal. At anygiven price, all other things being equal, coalwith a higher heat content is cheaper to usefor a given job than coal with a low heatcontent.


Coal is a commodity with a low specificvalue compared to other commodities, oftencosting less than a cent per pound at the mineand sometimes considerably less. Conse-quently transportation costs represent a sub-stantial portion of the delivered cost of coal ifthe user is a significant distance from themine. Low transportation costs relative toother coal producers increase marketing po-tential. Transportation costs can bean impor-tant limiting factor where coalfields are dis-tant from existing networks that transportcoal. For example, the high cost of building acoal transportation infrastructure to connectthe coalfields in southwest Utah with existingnetworks is an impediment to developing thisarea.

Institutional Constraints

In some situations a coal reserve may beavailable for development at a cost that iscompetitive with coal from other sources, butthe coal cannot be mined because of environ-mental reasons, labor or equipment short-ages, or possibly limited or nonexistent trans-portation capacity. An example of an envi-ronmental threshold that might eventuallydelay or possibly limit expansion of coal de-velopment appears to exist in North Dakota.All currently proposed mines in North Dakotaare associated with proposed nearby powerand synthetic fuel plants. Operation of allcurrently permitted plants may exceed the“prevention of significant deterioration” airquality increments for sulfur dioxide (S02). Ifthis is the case, the level of mine developmentmay be limited as well. (Additional discussionof this situation can be found in ch. 10. ) Laborshortages and limits to transportation capac-

ity are usually relatively short-term condi-tions that can be corrected in the presence ofstrong demand for coal from a region. Spe-cific transportation and environmental issuesaffecting Western coal development are dis-cussed in more detail in chapters 8 and 10,respectively.

Institutional constraints are more signifi-cant in their impact on production at a spe-cific locality than on the demand for coal ingeneral, Unless institutional constraints limitproduction in a large number of coal-produc-ing regions, demand is met by increased pro-duction from regions that do not experienceconstraints. Such shifts in production mayresult in some cost increases, but unless pro-duction is constrained in a number of regions,causing rapid increases in production of mar-ginal coal reserves that cost more to minethan existing mines, such cost increases arenot likely to be large. ’ If reasonable environ-mental and socioeconomic thresholds setlimits on coal production in an area, cost in-creases resulting in shifts in coal productionto other areas can be considered part of in-ternalizing the environmental and socialcosts of mining coal. *

1The cost impact of such regional shifts in productiondepends on both changes in mine mouth cost and transporta-tion cost. ICF has noted that moderate shortfalls in some re-gions can be compensated for by increased production fromnearby regions which are less constrained and which have ade-quate reserves of comparable coals available, but that if con-straints are widespread, the net costs to society can be high(ICF, Inc., Analysis and Critique of the Department of Energy’sAugust 7, 1980 Report Entitled “Preliminary Nationcd and Re-gional Coal Production Goals for 1985, 1990 and 1995,Washington, D. C.: ICF, Inc., October 1980).

*However, it must be recognized that there may be consider-able disagreement as to what constitutes a “reasonable” envi-ronmental or socioeconomic threshold at a specific location.

Trends in Factors Affecting the Demand forWestern Coal: 1980-90

The last two columns in table 26 give a gen- sible trends in these factors in the perioderal view of the current market situation in from 1980 to 1990. The following text dis-the West with respect to the factors affecting cusses only the most salient factors listed onthe 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 signifi-cant user that will be affecting the demandfor Western coal. In 1979 utilities purchased70 to 96 percent of the coal produced in themajor Western Federal coal-producing States(see table 22, ch. 4). The electrical growthrate will probably be the single most impor-tant factor affecting demand for coal fromWestern States during the next 10 years. Theelectrical growth rate in the last few yearshas declined significantly compared to ratesfollowing World War II. The average growthrate of total net generation of electricity from1945 to 1973 was 7 percent. Average annualgrowth since 1973 has slowed substantiallyand has averaged less than 2 percent duringthe last few years (total U.S. consumption ofelectricity in 1979 was 1.9 percent higherthan in 1978 and in 1980 the increase was 1.4percent).

The decrease in the electrical growth ratehas been largely the result of conservation inresponse to increasing costs of electricity,although the economic situation of the pastfew years has been an important factor in re-cent very low growth rates. This decline inthe electrical growth rate is a major reasonfor the decreases in projections for demandfor Western coal over the last few years. Forexample, the Department of Energy’s (DOE)1990 production goals for the western North-ern Great Plains (which also includes south-ern Wyoming) dropped from 529 million tonsin the 1978 forecast to 336 million tons in the1980 preliminary forecast. Most of this dropcan be attributed to a reduction in the elec-trical growth rate used in the forecast.

Efforts to project longer-term electricitygrowth rates have historically not been veryaccurate, but table 27, which compares pro-jected growth rates over the last decade,show there has been a consistent downwardtrend in projected growth for similar timeperiods in the future. Table 27 shows that re-cent electrical growth projections for theperiod from 1979 to 1985 range from 2,5 to4.1 percent. The low projections are higherthan growth rates in the past few years, re-flecting a belief that an economic upturn will

Table 27.—Comparison of Historical Forecasts ofAnnual Growth Rate of Total Electric Generation

Projectedg r o w t h

Scurce and year of study rate Time per iod

U.S. Energy Outlook–1971 . . . . . . . . .Department of the interior—1972 . . . . .Oak Ridge National Laboratory–1973Lawrence Livermore Laboratory— 1974Technical Advisory Committee—1974.Oak Ridge National Laboratory—1975Westinghouse—1975. . . . . . . . . . . .Electrical World—1975 . . . . . . . . . . . .Exxon Co.—1977 . . . . . . . . . . . . . . . . . .ElA’s Annual Report to Congress—

1978 ......, . . . . . . . . . . . . . . . . . . . .C O N A E S – 1 9 7 8 . . . . . . . ,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 InformationAdministration—December 1980 . . .

1980 actuala . . . . . . . . . . ., . . . . . . .aRate of increase experienced for the first 47 weeks of 1980 over corresponding

period of 1979.

SOURCES:

(percent)7.26.14.45.66.05.15.05.84.8

4.70.7-3.2

4.1

3.73.03.53.0

2,51,4

1971-851971-2000

1974-851974-851974-851974-851974-851975-851977-90

1977-851975-2010

1979-89

1981-901978-851979-851985-90

1979-851980

Forecasts from 1971 to 1978 from table 39, U S Department of En-ergy, Short Term Energy Outlook, DOE/EIA-0202/2 (Washington,DC U.S. Government Printing Office, February 1980) Projectionsof the Demand and Conservation Panel of the Committee on Nucle-ar and Alternative Energy Systems as scenario B cited in Science,Apr. 14, 1978, p. 151

National Electric Reliablilty Council, 1980 Summary of ProtectedPeak 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 notedthat this is a drop from the 4 4-percent rate projected by the Re-gional Councils in their April 1980 reports to the U S. EconomicRegulatory Administration,

National Electric Reliability Council, Electric Power Supply andDemand 1981-1990 (Princeton, N.J.: NERC, July 1981)

Department of Energy, Preliminary National and Regional CoalProduction Goals for 1985, 1990 and 1995 (Washington, D C DOE}

Aug 7, 1980), From table 19ICF, 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 Ener-gy, Proposed Changes to Generating Capacity 1980.89 for the Con-tiguous United States, DOE/RG-0047 (Washington, D C DOE, De-cember 1980,) The 25 percent was derived by combining the esti.mates by the Economic Regulatory Administratlon of 21 percentfrom 1979 to 1983, and latest estimates by the Energy InformationAdministration of 32 percent from 1978 to 1995

increase demand for electricity. The upperrange of 4. I percent projected by the Na-tional Electric Reliability Council (NERC) inJuly 1980 is considered by a number of ob-servers to be somewhat high. The NationalCoal Association (NCA), for example, uses theNERC electrical growth rate for their highprojection and an electrical growth rate of3.5 percent for their most likely projection ofU.S. coal production.’ Also the electrical

‘National Coal Association, NCA Long-Term Forecast (Wash-ington, D. C.: NCA, March 198 1).


growth rate projected by NERC in July 1981was reduced by 10 percent from their earlierprojection, to 3.7 percent.

There are analysts who expect the elec-trical growth rate to continue to decline in thefuture. For example, the Solar Energy Re-search Institute (SERI) projects an electricalgrowth rate of 0.4 percent annually between1978 and 2000 if cost-effective efficiency in-vestments are made (excluding investmentsin solar).3 According to this study, construc-tion programs already underway could sup-port such an increase in demand over thenext 20 years even if: 1) no plants are broughton line after 1985, 2) all fossil plants builtbefore 1961 are retired, and 3) 80 percent ofall oil- and gas-burning generating plants areretired. The SERI study also concluded thatvigorous onsite solar investments (active andpassive solar space and water heating) com-bined with extensive development of cogener-ation and onsite wind and photovoltaic sys-tems could result in a negative growth rate inthe demand for electricity between now andthe turn of the century.

More important than the overall electricalgrowth rate in the United States are theregional growth rates in the potential marketareas for Western coal. Recent projections byNERC, NCA, and ICF all assume electricalgrowth rates (EGR) in the far West that arelower than, or near average compared to theUnited States as a whole. For the period 1980to 1990 NERC projects an EGR of 3.8 percentin the West compared to a national averageof 3.7 percent. ICF projects a slightly lowerrate for the West (2.8 v. 3.0 percent from1979 to 1990) and NCA projects a signif-icantly lower rate in the West than the na-tional average (2.9 v. 3.5 percent) for thesame time period.4 On the other hand, all

3House Committee on Energy and Commerce, Report on Build-ing a Sustainable Future, prepared by the Solar Energy Re-search Institute (Washington, D. C.: U.S. Government PrintingOffice, April 1981), p, 152,

4The geographic areas for these projections do not entirelycoincide. The NERC projection is for the Western Systems Co-ordination Council (calculated from table 19, Electric PowerSupply and Demand 1981-1990 (Princeton, N.].: National Elec-tric Reliability Council, July 1981). The ICF projections coverapproximately the same area as the WSCC but include parts ofMontana and New Mexico that are in other regional reliabilitycouncils (calculated from table 3-2, app. A, Forecasts and Sen-

three of these sources project higher thanaverage electrical growth rates in the Mid-west and South-Central United States, bothimportant market areas for Western coal. Inmuch of this area coal from the Gulf Coastlignite province and the Midwest competewith coal from the major Federal coal States.

Another important factor affecting the util-ity demand for Western coal is the regionalgrowth rate in coal-fired generation. In someareas in the United States, such as in theMidwest, where coal is already meeting mostgeneration requirements, increases in coaldemand are fairly directly tied to the growthin demand for electricity. However, in areaslike the South-Central United States wherecoal-fired capacity is being added in a systemprimarily dependent on more expensive fuel(i.e., oil or natural gas), demand for coal mayincrease through replacement of oil and/orgas base load generation even if there is nototal generation growth. Regional growthrates in coal-fired generation between 1980and 1990 are projected by NERC to be 3.1percent in the West (WSCC and MARCA re-gional reliability councils) and 10.0 percentfor the South-Central United States (ERCOTand SPP reliability councils).* NCA projectshigher growth rates for essentially the sametime period (1979-90) of 5.0 percent in theWest and 13.1 percent in the South-CentralUnited States.

It is apparent that the electrical growthrate and conversions from gas to coal in theSouth-Central United States will be a majordeterminant in the rate of increase in the de-mand for Western coal. In 1979 the South-Central United States consumed 26 percent oftotal Western coal production used by util-ities. ** NCA projects that 40 percent of the

sitivity Analysis of Western Coal Production, Washington, D, C.:ICF, Inc., November 1980). The NCA projections include boththe WSCC and the Mid-Continent Area Reliability y CoordinationAgreement (MARCA) which covers the upper Midwest (seefootnote 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 footnote4 for sources of projections cited in this paragraph.

**Total Western coal production includes production fromthe Northern Plains, Rocky Mountain, and Gulf Coast coalprovinces, the western part of the Interior coal province,Washington State, and Alaska.


coal produced in the West in 1990 will beused in the South-Central region, and NERCprojects that 47 percent of Western coal pro-duction for utilities will be used in this area.The reasons for this projected large increaseare: 1) replacement of gas with coal-fired gen-eration, as originally required by the Power-plant and Industrial Fuel Use Act (PIFUA];and 2) higher gas prices. Increases in theavailability of natural gas since passage ofPIFUA has decreased some of the pressuresto switch from gas to coal, and there remainssome uncertainty as to how much of a shiftfrom gas to coal will actually occur in thisregion by 1990,

Sulfur Reduction Standards

Before passage of the 1970 Clean Air Act,sulfur content of coal was not a significantfactor affecting utility coal purchase deci-sions. The 1970 new source performancestandards (NSPS) for S02 that set a maximumemission rate of 1.2-lb/million Btu, created alarge market for “compliance” coal (i.e., coalthat could be burned without stack gas scrub-bing and meet the 1.2-lb standard). * A signifi-cant amount of the increased demand forWestern coal between 1970 and 1979 can beattributed to the fact that Western coalfieldscould produce compliance coal that had a de-livered price in the Midwest that was lowerthan the delivered price of high-sulfur Mid-western coal when the added cost of scrub-bing the high-sulfur coal was factored in.

The 1977 Clean Air Act Amendments,which required sulfur reduction for all coalsburned by utilities, significantly reduced themarket advantage enjoyed by low-sulfurWestern coal under the 1970 NSPS for SO2.The 1979 NSPS for SO2 which apply to newpowerplants, establish a dual standard forsulfur reduction based on both sulfur contentand 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/millionBtu since that amount of sulfur would convert to 1.2 lb of SO2.

**The final 1979 NSPS were published on June 11, 1979 (44Federal Register 33613-33624) but apply to all electric utilitysteam generating units for which construction commencedafter Sept. 18, 1978.

emission rate of less than 0.6 lb SO2/millionBtu, a higher sulfur reduction is not neces-sary. All higher sulfur coals must have 90-percent reduction in sulfur, but emission ofS O2 cannot exceed the 1970 NSPS of 1.2lb/million Btu.5 For “high” sulfur coal, thistranslates into a maximum of 6.0 lb sul-fur/million Btu (90-percent reduction of thisamount equals 1.2 lb SO2/million Btu). For lowsulfur coal this translates into a maximum of1.0 lb sulfur/million Btu (70-percent reductionof this amount equals 0.6 lb SO2/million Btu).Most current production in the West wouldqualify for a 70-percent sulfur reduction rate.

The cost of stack gas scrubbing for West-ern low-sulfur coal is generally lower than forhigh-sulfur coal because scrubbing processesfor low-sulfur coal (mostly dry) are cheaperthan wet processes needed for high sulfurcoal. However, this advantage is largely off-set by allowances in the present regulationsthat give credit for sulfur reduction by pre-combustion cleaning (i.e., sulfur reduction bycleaning can reduce the percentage of sulfurreduction required by stack gas scrubbing).According to studies by the Bureau of Mines,mechanical cleaning of coal from northernAppalachia and the Midwest can result inaverage reductions in sulfur of 33 and 23 per-cent respectively.’ This means that sulfurreduction by stack gas scrubbing would typi-cally need to range from 57 to 67 percent

5The 1979 NSPS have been challenged in court on thegrounds that there was irregular ex parte communication dur-ing their formulation. The regulations have been upheld in dis-trict court and the decision has been appealed by industry, It ispossible that the regulations will be revised as a result of thislitigation. Legislative modifications to sulfur reduction stand-ards are also in early stages of consideration by Congress.Revisions that would allow a more flexible sliding scale forsulfur reduction would lessen the adverse impact of the 1979NSPS on the competitive position of Western coal in Midwest-ern markets, but not eliminate it. For example, the Mining TaskForce of the National Coal Policy Project concluded before the1979 NSPS were promulgated that the Clean Air Act Amend-ments of 1977 (which require utilities to install the bestavailable control technology on all new plants) would meanthat coal production in the Northern Great Plains was not likelyto increase as much as would happen under the 1970 NSPS.F. X. Murray (cd.), Where We Agree: Report of the NationalCoal Policy Project V.2 (Boulder, Colo,: Westview Press, 1978).

6A. W. Deurbrouck, Sulfur Reduction Potential of Coals in theUnited 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 com-pared to 70 percent for low-sulfur Westerncoal. Coal cleaning is not generally practicedon Western coal primarily because of the gen-erally low heat content of these coals that areused by utilities, and because Western coalstend to be high in organic sulfur, which is notamenable to reduction by conventional me-chanical cleaning processes.

The 1979 NSPS for S02 have not been in ef-fect long enough to allow full evaluation oftheir effect on coal markets, but it appearsthat stack gas scrubbing costs for high-sulfurcoal (with credits for sulfur reduction bycleaning before combustion) and for low-sul-fur Western coal will not differ greatly. If thisproves to be the case, it would largely elimi-nate sulfur content in coal as a key factor incoal purchasing decisions for new power-plants by electric utilities, although there aresome situations where Western coal may re-tain a competitive advantage based on sulfurcontent. For example, in nonattainment areaswhere further development hinges on reduc-ing total emission of S02, low-sulfur coal mayhave an advantage because full (i.e., 90 per-cent) stack gas scrubbing of low-sulfur coalemits less total S02 than the same amount ofscrubbing of high-sulfur coal.

In summary, the competitive position ofWestern coal varies according to the kind oflimitations that are set on the emission of SO2.At one extreme, the absence of restrictionson S02 emissions would make the deliveredprice, rather than the sulfur content of thecoal, the key factor in purchasing decisions.The 1979 NSPS will probably achieve a sim-ilar result. In contrast, the 1970 NSPS gavelow-sulfur Western coal a significant com-petitive edge, and strict limitations on thetotal level of emissions also favor Westerncoal.

The full effect of the 1979 NSPS (if they arenot modified) will not be felt until the late1980’s because a large percentage of newcoal-fired capacity that will come online be-tween 1980 and 1985 was ordered before the

NSPS went into effect.7 The major impacts ofthe 1979 NSPS in the next decade will be inthe effect it has on determining which coalregions will supply those new coal-firedplants that will be built in the late 1980’s andthat have not signed long-term contracts forcoal.8

Mine Costs

Now that sulfur content will probably be aless significant factor in the marketing ofWestern coal, the single most important com-petitive advantage retained by Western coalis its low cost at the mine mouth. Table 28summarizes recent representative steam coalcontract prices in January and June 1981 forthe major Federal coal-producing States andranges of prices within the Midwestern andAppalachian coal regions. In January 1981,typical price per ton from the Powder Riverbasin in Wyoming and Montana ranged from$6.75 to $12.00/ton, and in the other Westerncoal States, for higher Btu coal, from $16.00to $20.75/ton. In contrast, prices for Mid-western 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 spreadis a little less when these prices are trans-lated into cost per million Btu. For examplethe low price for coal in the Midwest of

‘Eighty-three percent (49,200 of the projected 59,400 giga-watts total net capacity) of new coal plants that are planned tocome on line between 1979 and 1985 will be constructed tomeet the 1970 NSPS rather than the 1979 NSPS, and an addi-tional 5,800 gigawatts planned to come on line between 1985and 1990 will be under the old standards because orders forboilers were made before the new standards took effect (num-bers calculated from tables 3-7 and 3-9, app. A, Forecusts andSensitivity Analysis of Western Coal Production, Washington,D. C.: ICF, Inc., November 1980).

8It should be noted that the present administration has pro-posed that the mandatory scrubbing requirements in the 1977Clean Air Act Amendments be eliminated. However, if the1979 NSPS are repealed, it is not certain that low-sulfur West-ern coal would be as attractive to Midwestern utilities as it wasin the 1970’s. For example, a study by Data Resources Inc.(DRI) has concluded that eastern and Midwestern electricutilities would continue to favor local high-sulfur coal, even ifthe mandatory scrubbing requirements were dropped (Coal

Week, May 18, 1981). The reason for this is that DRI’s projec-tions of rail rate increases for Western coal offset the cost sav-ings 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

10,0009,500

to12,000

11,200to

13,000

9.75 0.57 Colstrip MT 11 .46a

21.44 b

(22.31)Decker MT —

—

18.69 a

(18.26)—

18.94a

(18.00)—

12.00 0.65 —

Wyoming. . . . 6.75(7.00)16.50

— —

14.24 a

(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 ratebSingle car ratecPowder 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 lowprice for Western coal, but on a Btu basis thespread is reduced to a factor of 1.7. The lowcost of mining Western coal can be attributedprimarily to low production, labor and recla-mation costs for both surface and under-ground mines with coal seams that are thick-er than those in the Midwest and Appalachia.

shown here, except from Hanna, Wyo., therail transport costs exceed the mine-mouthcost. The cost advantage of unit train rates isalso clearly shown in this table. From Col-strip, Mont., to Minneapolis, Minn., single carrates are almost twice unit train rates. Thedifference works to the disadvantage of Col-orado and Utah where single mines often can-not produce enough to justify commitment ofunit trains. Table 28 also shows that railrates are changing at a faster rate than minecosts in the West. During the first 6 months of1981 all except one rail rate changed, andmost of the changes involved increases of$1.00/ton or more. In contrast, most coalprices in the West remained unchanged dur-ing this same period.

There is a general consensus that railtransportation costs over the next 10 yearsare likely to increase at a faster rate than in-

Transportation Costs

Western coalfields are located far fromthe main centers of coal demand in the Mid-west and South-Central United States. Conse-quently, transportation costs are one of themajor market disadvantages experienced byWestern coal and are probably the singlelargest overall factor in market decisions con-cerning Western coal. Table 28 shows somerepresentative rail rates from points in theWest 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 reducetransportation costs between certain points,but there is no consensus as to how signifi-cant these cost savings may be, nor is theremuch certainty as to the magnitude of real in-creases that can be expected in rail transportcosts (see ch. 8).10 However, the net effect ofreal increases in transportation costs will ad-versely affect the competitive position ofWestern coal with respect to Midwesterncoal because longer distances are involved.

The alternative to shipping coal to centersof demand is to generate electricity at themine mouth and ship the energy by wire.North Dakota, which is relatively close tocenters of electricity demand in ‘the upperMidwest, and New Mexico, which is rela-tively close to centers of demand for electri-city in southern California both export signifi-cant amounts of electricity by wire. However,several factors tend to limit the level of mine-mouth generation to primarily what is neededwithin the Western Federal coal-producingStates and adjacent States: 1) long-distancetransmission of electricity is generally expen-sive because of high capital costs, 2) theavailability of water is less (although use ofdry-cooling towers can reduce some of the

9 Participants in a conference held in Cctober 1980, shortlyafter the Staggers Rail Act of 1980 was signed into lawreached the general conclusion that there would be an almostimmediate impact in terms of increased rates for shipping coal(Coal Week, Oct. 20, 1980). The Department of Energy assumeda 15-percent real increase in rail transportation costs between1978 and 1985 in setting its preliminary regional coal produc-tion goals. However, ICF has found that between 1978 and1980 alone real increases (i. e., adjusted to account for infla-tion) were 10.5 percent, almost as much as DOE’s projected in-crease over the 7-year period. This underestimation of likelyrail increases resulted in a considerable overestimation of de-mand for coal from the Powder River basin (ICF, Inc., Analysisand Critique of the Department of Energy’s August 7, 1980Report Entitled “Preliminary Notional and Regional Coal Pro-duction coals for 1985, 1990 and 1995” (Washington, D. C.: ICF,Inc., October 1980). ] In the final production goals, DOE in-creased assumed escalation of transportation costs to 25 per-cent. Rocky Mountain Energy Co. projects a 40-percent real in-crease in rail transportation costs in southern Wyoming be-tween 1980 and 1990 (personal communication, Stephen Berg-Hansen, 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 sum-mary updates an earlier report, A Technolo~y Assessment ofCool Siurry Pipelines (Washington, D. C.: U.S. GovernmentPrinting Office, March 1978),

problems related to water availability), and3) the relative environmental and social im-pacts of large-scale powerplants are greaterin the arid and semiarid West compared tothe Midwest and South-Central UnitedStates. 11 Transportation by wire is discussedin more detail in chapter 8.

Reclamation Costs

Reclamation requirements under the Sur-face Mining Control and Reclamation Act of1977 give Western coal a decided competitiveadvantage compared to Eastern coal becausethe relative cost increases attributable to theAct are small in the West compared to theMidwest and Appalachia. Typical incremen-tal costs with Public Law 95-87 have recentlybeen estimated to be $5.24/ton in Appalachia,$1.80/ton in the Midwest and $0.57 ton in theWest. [z The incremental cost differential be-cause of reclamation requirements betweenWestern and Midwestern coal (a factor of 3)is more significant than the cost differentialbetween Appalachian and Western coal (afactor of 10) because Western and Appa-lachian coal serve different market areas,whereas the market areas for Midwesternand Western coal overlap. Less stringentreclamation requirements for mining wouldprobably have the effect of improving thecompetitive position of Midwestern coal withrespect to Western coal because cost reduc-tions from less stringent reclamation stand-ards would generally be greater in theMidwest.

Royalty Rates and Severance Taxes

Royalty rates on coal produced in WesternStates were generally very low before the1970’s reflecting the relatively low value at-tributed to Western coal reserves. The in-creased demand for coal in the West in the1970’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 Proj-ect 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’sanalysis of reclamation costs is discussed in more detail in ch.10.


as coal was perceived by both the owners andpotential lessees as having a higher value. In-dian tribes and private leaseholders led theway in exacting higher royalty rates in theearly 1970’s. The 1976 Federal Coal LeasingAmendments Act (FCLAA) set minimum pro-duction royalty rates on surface coal at 12½percent; a lower royalty rate (currently 8 per-cent) is permitted for underground coal. Sev-eral States followed suit in raising royaltyrates, and new leasing transactions of non-Federal coal generally follow minimum levelsset by the Federal Government.

The overall effect of changing royalty rateshas been to create considerable differentialsin royalties between “old” ‘and “new” leasedcoal. Federal leases before 1976 containednominal royalties by today’s standards. Theaverage royalty rate on Federal coal mined in1977 was 18.8 centslton. Royalty rates at cur-rent contract prices at rates set in FCLAAmay be more than 10 times that. The Depart-ment of the Interior (DOI) is required to raiseroyalty rates when leases come up for adjust-ment, consequently over the next 10 to 15years as leases are adjusted, there will exista dual royalty standard that could affect thecompetitive position of individual Federalleases with respect to other Federal leasesand non-Federal coal. Without a systematicanalysis of the intraregional and interre-gional effects of differential royalty rates, itis difficult to draw conclusions concerningthe impact of these differentials on coalmarkets.

Severance taxes* imposed by States alsoadd to the mine-mouth cost of coal. In theWestern States severance taxes range fromzero in Utah to 30 percent in Montana. A com-parison of severance taxes on surface minedcoal in the West shows that cost per millionBtu is roughly the same in Colorado, NewMexico, North Dakota, and Wyoming (gener-ally 3 to 5 cents/million Btu).13 Severance taxcosts in Montana run three to four times

*See ch. 12 of this report for a description of State coalseverance taxes.

‘ ‘Colorado Energy Research Institute, Mineral SeveranceTuxes in the Western Stutes: A Comparison (Golden, CO1O.:”CERI, 1979].

higher. Severance taxes and royalty ratesadd to the cost of coal, but increases at-tributable to these sources are relativelysmall compared to the cost of mining andtransporting the coal. Consequently, such dif-ference may cause shifts in the location of thecoal production between Western States (ascould be the case in Montana,)* or fromWestern coalfields to other coalfields, but donot have a significant impact on the avail-ability or overall demand for coal.

Industrial Demand

Utah, Colorado, and New Mexico are theonly Western States with significant reservesof metallurgical coal. In 1979 these threeStates supplied only 3 percent of the metal-lurgical coal that was used by the steel in-dustry although they supplied nearly all ofthe metallurgical coal used in the West. Therest was produced and mostly consumed inthe Midwest and Appalachia. Federal leasesin Oklahoma also contain metallurgical coal,and demand for Federal coal from this Statehinges strongly on the needs of the steel in-dustry. Even a dramatic increase in the de-mand for metallurgical coal would not havemuch effect on the total demand for Westerncoal, given its small share of that market.

Industrial coal burning in California pre-sents a significant source of potential in-creased demand for coal from Utah, southernWyoming, New Mexico, and Colorado, but lit-tle realization of this potential is expectedwithin the next 10 years because of the eco-nomic costs of converting boilers from nat-ural gas or oil to coal, combined with thecosts of emission controls. The same is prob-ably generally true of industrial boiler con-version in the Midwest and South-CentralUnited States where Western coal also ex-periences competition from Gulf Coastlignites and Midwestern coal production. Sig-nificant increases in demand for coal be-

*The impact of the Montana severance lax is discussed inmore detail in the section on market advantages and disadvan-tages 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 notlikely to be experienced until after 1990.1’

In 1979, 6 percent of total coal productionin the far Western States (including Arizonaand Washington) was for nonmetallurgicalindustrial uses, most of which was used forlime and cement kilns, metals processing, andsugar processing (table 22, ch. 4). Some in-crease in demand for coal for such industrialuses may occur, but dramatic increases arenot likely, thus the major potential source ofincreased industrial demand for coal will beindustrial boiler conversions.

Synthetic Fuels

A major disadvantage of coal is that it isnot as convenient to use and transport as oiland gas, and is not directly substitutable foruse in the transportation sector, which ac-counted for 25 percent of the total energy usein the United States in 1979. Synthetic gasand liquids can be produced from coal, but ata high cost. Relative costs of oil and gas andcoal-based synthetic fuels are still such thatsynthetic fuels cannot currently compete inthe market place, although some large energycompanies may be willing to commit funds tocommercialization of coal-based syntheticfuels in anticipation of future oil and gasprice rises. Nevertheless, demand for coal toproduce synthetic fuels during the nextdecade is likely to depend to a large extent onGovernment incentives. Coal-derived liquidsmust also compete with oil shale, which pro-duces a synthetic crude oil that can be proc-essed in conventional refineries. At presentthe uncertainties in the cost estimates for thevarious synthetic liquid fuels are larger thanthe estimated difference in the cost of coaland oil shale derived synthetic liquids.

NCA’s long-term forecast for coal produc-tion concludes that coal synfuels productionwill fall short of production goals set by theFederal Government when it created the Syn-thetic Fuels Corp. NCA estimates that coalsynfuels production is not likely to exceed

14 F. Hachman, Market Factors Associated With the Assess-ment of the Development Potential of Federal Coal Leases inUtah, prepared for OTA, 1980.

200,000 barrels per day (bbl/d) of oil equiv-alent by 1990 in contrast to the goals of500,000 bbl/d in 1987 and 2 million bbl/d in1992 established by the Government (ofwhich two-thirds was to have come fromcoal). 15 NCA stated that the goals were unre-alistic considering the economic, technical,environmental, and other regulatory condi-tions in which synfuels plants must be built.

The current status of coal-based synfuelsprojects indicates that most of the demandfor coal for this purpose during the nextdecade is likely to be in the Midwest and Eastrather than the West. A survey by NCA of ex-isting and proposed coal-based synfuel facili-ties found that the largest coal synfuel facili-ties operating in the United States are pilotplants in Kentucky and Texas, and that theonly large commercial synfuel plant underconstruction in 1980 was located in Ten-nessee. l6 According to this survey, of the fourlarge-scale synfuels demonstration plantsthat were expected to start construction in1981, only one, the Great Plains Gasifica-tion Associates’ project in North Dakota, waslocated in the West. The other three arelocated in Kentucky, West Virginia, andIllinois.

On the other hand, DOE assumed in itsfinal 1980 coal production goals that 60 per-cent of the 1990 demand for coal feedstockfor synfuels will be west of the Mississippi,most of which (45 percent of total demand)would be from the six major Western Federalcoal States.17 This assumption was based ontwo major considerations: 1) the technical su-periority of low caking Western coal whenused with first-generation conversion tech-nology and 2) the relative abundance of low-cost strippable Western coal resources. How-ever, the assumed l-million-bbl/d total U.S.production of coal-based synfuels (20 plantswith 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, September1980).

17 U.S. Department of Energy, The Biennial Updute of Nationalund Regiona~ Coal Production Cmds for 1985, 1990 and 1995(Washington, DC.: DOE, January 1981).


nationwide) exceed other estimates of likelylevels of synfuel production by 1990.

Evaluation of this potential for coal-basedsynfuel development in the West by OTA inthe different State assessments generallyagrees with the data in the NCA survey, in-dicating limited development of Western coalto support synfuels plants before 1990, TheOTA Wyoming task force judged only one ofthe three Federal lease blocks in Wyomingthat are associated with synthetic fuels proj-ects to have favorable production prospectsby 1991 and recent developments have in-creased the uncertainty that this project willbe online by then.18 The market analyses pre-pared for the Utah and Colorado task forcesconcluded that the use of coal for synfuels inthose States would be minimal by 1991.19 TheNew Mexico task force projections assumedthat no commercial-scale synthetic fuelplants using New Mexico coal would be inoperation by 1990.20

All of the barriers to beginning full-scaleconstruction of the most advanced commer-

18J. R. Boulding and D. L. Pederson, Development and Produc-tion Potential of Undevelopcd Federal Coal Leases and Prefer-ence Right Lease Applications in the Powder River Basin andother Wyoming Coal Basins, final report (Washington, D. C.:OTA, 1981). The one block with favorable prospects is theRochhelle lease held by Peabody Coat Co., which is committed taPanhandle Eastern’s proposed gasification plant near Douglas.Wyo. This gasification project received a major setback inAugust 1981 when Pacific Gas & Electric and Ruhrgas Akti-engesellschaft of West German~’ announced they were with-drawing from their preliminary partnership agreement for theproject. Consequently, it is uncertain whether any synfuelplants will be producing in the Powder River basin by 1991.The other two blocks associated with synfuel proposals areTexaco’s Lake DeSmet block in the western Powder Riverbasin and Nerco’s Cherakee block in southern Wyoming. Thesewere judged by the Wyoming task force to have uncertain pro-duction praspects by 1991, Subsequent analysis by OTAchanged 1991 production prospects for the DeSmet block fromuncertain to unfavorable. Two other proposed synfuel projectsin Wyoming are still in the early stages of development. TheHampshire project proposed for the eastern Powder Riverbasin is not associated with a specific source of coal, and a coalto gasoline plant proposed by Mobil would involve entirely non-Federal coal in the western Powder River basin.

‘<’See Hachman, op. cit.: and J. E. Martin, Market Factors andProduction Contingencies Determining the Present nnd FutureDemand far Colorado COul (Lakewood, Colo.: Colorado EnergyResearch Institute, December 1980).

-“The Development Praspects for Federal CoaJ Leases in NewMexico 1980-1990 (Washington, D. C.: OTA, November 1980].

cial-scale Western synfuel project in the NCAsurvey have been overcome. Preconstructionactivities began on the Great Plains Gasifica-tion Associates’ coal gasification facility inMercer County, N. Dak,, in August 1980. Thefirst unit of the plant, which would use 4.7million tons per year of lignite, is scheduled tobe in operation in late 1984. The project hadconsiderable difficulty in developing a financ-ing plan that was acceptable to the FederalEnergy Regulatory Commission and consum-ers who would purchase the gas. The originalfinancing plan was revised in January 1981,and received approval in May. Citing possiblecost overruns and the need for a separatepipeline, the project sponsors increased theirloan guarantee request to DOE from $1.8 bil-lion to $2.0 billion. This request was ap-proved by President Reagan in early August1981.

A study prepared for OTA by the ColoradoSchool of Mines Research Institute on thesynfuels potential of Western coal concludedthat significant commercial production ofhigh-Btu gas from coal is unlikely for at least10 years even with Federal incentives.21

Development activities related to medium-and low-Btu gasification facilities are strong-ly dependent on the availability of naturalgas. The Institute’s study concluded that therelative abundance of natural gas, and theprospects for acquiring additional suppliesfrom new foreign and domestic sources havedampened the development of small-scale in-dustrial gasifiers.

This study also concluded that significantcommercial production of coal liquids is un-likely over the next 10 years. Even if substan-tial Government incentives are offered, com-mercial production levels are expected to beless than 100,000 to 200,000 bbl/d of syn-thetic liquid, primarily because of the lead-times for construction and the risks asso-ciated with first generation plants. Becauseof these risks, industry is likely to wait untilprocesses have been demonstrated on a com-

21 Colorado School of Mines Research Institute. Synfuels Po-

tential of Western Coal, Draft Report, prepared for OTA, Oct.31.1980.


mercial scale before committing to build alarge synfuels industry. Because commercialdemonstration is not possible until the late1980’s, 1990 production levels are likely to belimited to the capacity of the first generationpioneer plants.

Foreign Export

Japan, Korea, and Taiwan are expecting tosignificantly increase their imports of coalduring the next 10 years, and have purchasedcoal from several Western States for testburns. Initial shipments of coal have beenmade to Japan from Utah and to Korea fromColorado. Current capacity of port facilitiesto handle coal for foreign export on the westcoast is about 3 million tons, and significantexport of Western coal will require consider-able expansion of existing facilities and con-struction of new facilities to handle coal.NCA estimates that countries in the Far Eastwill import from 153 million to 180 milliontons in 1990.22

Potential competitors to the United Statesfor the coal demand in the Far East are Aus-tralia, Canada, China, the Soviet Union, andSouth Africa. The NCA range of projectedcoal exports for these countries in 1990 is 195million to 240 million tons, which is wellabove the range of import demand in the FarEast (although all export from these countriesis unlikely to go to the Far East). Consequent-ly, the Western coal States will be entering acompetitive market; it is thus difficult topredict what share of this market the UnitedStates is likely to obtain. Australia has a con-siderable competitive advantage over coalproduced in the Western United States, butthe Japanese in particular appear to be plac-ing limited coal commitments elsewhere as ahedge to limit the strength of the Australianposition.23

The Japanese have expressed the greatestinterest in high-Btu bituminous coal with lowash, moisture, and sulfur content, whichgives 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 GreatPlains. The recent expressions of interest bythe Japanese in Powder River basin coal haveresulted in plans to construct a coal exportfacility at Kalama, Wash., that could have anexport capacity of 15 million tons by 1983.Export of subbituminous coals from thePowder River basin will probably depend onthe development of slurry pipelines and tech-nology for drying the coal to upgrade its heatcontent. A recent analysis of the economics ofexport from the west coast did not considerPowder River coal to have significant exportpotential in the near future, primarily be-cause of its lower heat content. 24 The poten-tial for export of Alaskan coal to the PacificRim countries was not examined in this study.

If the Japanese would make firm commit-ments to purchase significant amounts ofWestern coal, port facilities could probablybe constructed to meet the demand for ex-port. However, such firm commitments havenot yet been made, and existing ports thathandle coal on the west coast are reluctant toexpand or construct new facilities untilhigher volumes of coal are assured. In theabsence of firm commitment by Asian coun-tries to purchase Western coal, it is very dif-ficult to predict the level of foreign exports ofWestern coal by 1990, ICF projects exportsfrom the west coast to be 2 million tons in1985 and 14 million tons in 1990.25 The Inter-agency Coal Export Task Force projects anupper limit of 15 million tons in 1990 for westcoast export. 26 DOE final production goalsassume that 12 million to 35 million tons ofcoal in 1990 will be exported from west coastports. 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 ProposedWest 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 “’weare not optimistic about the export potential of Powder RiverBasin 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, environ-mental, and socioeconomic issues examine inmore detail the impacts of various institu-tional constraints on coal production in theWest. There are some specific instanceswhere Federal coal reserves under existinglease cannot be mined because of environ-mental restrictions, but the total reserves in-volved in such restrictions are relativelysmall. * It does not appear that implementa-tion 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 ofWestern States to produce coal. Infrastruc-ture constraints, such as the ability of com-munities to expand services to accommodatepopulation increase because of coal develop-ment and the ability of transportation sys-tems to deliver coal to the areas of demandmay cause constraints on a site-specificbasis. However, such constraints do not ap-pear likely to prevent Western coal Statesfrom meeting the possible ranges of demandsthat are likely during the next 10 years. (Seech. 6 for estimates of production from theWestern Federal coal States.)

Factors Affecting Competition BetweenWestern Coal States

The net result of the various factors andtrends discussed in the previous section isthat conditions favoring rapid increases indemand for coal from the major Federal coalStates are not as favorable for the 1980’s asthey were in the 1970’s, This does not meanthat there will not be substantial increases inWestern coal production—the low cost ofmining Western coal will ensure that—but itdoes mean that the West’s share of coal mar-kets will probably not be as great as has beencommonly anticipated. The major reasons forthis are: 1) reduction in the low sulfur ad-vantage, 2) lower electrical growth rates. and3) higher transportation costs. Offsettingthese trends somewhat is the likelihood thatthe South-Central United States, which is amajor consumer of Western coal, will have ahigh growth rate in coal-fired powerplants toreplace gas-fired plants. Nearly 60 percent(174 million of 301 million tons) of NERC’Sprojected new annual demand for utility coaland lignite from the West between 1979 and1989 will be consumed in the South-Centralregion (ERCOT and SPP regions). Consequent-ly, the overall demand for Western coal willbe highly sensitive to both electrical growthrates and gas to coal conversions in this re-gion. It is more difficult to evaluate the fac-

tors affecting demand for coal in the 1990-2000 time period, but some discussion of thiscan be found later in the Demand for WesternCoal; 1990-2000 section.

This section looks in more detail at therelative market advantages and disadvan-tages that coal producers in each of the majorFederal coal-producing States experiencewith respect to demand for coal in the Westand in other parts of the United States. Theserelative advantages and disadvantages aresummarized in table 29. The next section ex-amines the net effect of these advantages anddisadvantages in the share of total produc-tion and geographic market areas of the dif-ferent States.

North Dakota

In 1979 North Dakota produced 15.0 mil-lion tons of lignite, ranking fifth out of the sixmajor Federal coal States. The key marketdisadvantage of North Dakota lignite is itslow heat content and poor handling charac-teristics for long-distance transport. Lignitetends to combust spontaneously when ex-posed to air, and is difficult to unload fromrail cars in winter because moisture in the

— -.


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 com-bust when exposed to air restricts markets almost entirely tomine-mouth development.

—PSD air quality limitations may restrict the level of mine-mouthdevelopment 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 andSouth-Central United States means transportation costs are ahigh percentage of delivered cost.

—High severance tax (30%).—Low heat content compared to Rocky Mountain coal States,

W y o m i n gPowder 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 su l fur 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 RockyMountain States.

—Long distance to major coal demand centers in the Midwest andSouth-Central United States means transportation costs are ahigh 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 area high percentage of delivered cost.

—Majority of reserves must be underground mined, resulting in rel-atively high mine-mouth costs.

—More distant from demand centers in the west coast than Utahand New Mexico.

–Transportation costs to demand centers in the Midwest andSouth-Central United States are higher compared to Montana andWyoming because most product ion must c ross h igh mounta insand 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 highmine-mouth costs.

—Southern Utah fields distant from transportation networks.—Very far from major demand centers in the Midwest and South-

Central 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 transportationnetworks.

—Some coal in Raton Mesa region must be underground mined withhigher mining costs.

—High ash content of some coals sometimes requires coal clean-ing, thus increasing cost.

-— —


lignite freezes. The low heat content limitscoal sales almost entirely to nearby power-plants (or synfuel facilities) in the State withsome export to the adjacent States of SouthDakota and Minnesota. Air quality thresh-olds, as mentioned previously, are becoming afactor to consider in the use of North Dakotalignite reserves in mine-mouth power andsynfuel plants.

The key market advantages of North Da-kota lignite are that water is readily availablefor onsite development and there are largereserves of surface minable lignite that canbe mined at a relatively low cost, NorthDakota is also located closer to the electricitydemand centers in the upper Midwest thanother Western States, and reserves are well--suited for commercially available gasificationtechnologies.

Montana

In 1979 Montana produced 32.5 milliontons of coal, ranking second among the sixmajor Federal coal States. The major marketadvantages in Montana are large reserves ofsurface minable coal, with generally higherheat content compared to other NorthernPlains States (but relatively low compared tothe Rocky Mountain States). Four counties inthe Montana portion of the Powder Riverbasin contain an estimated 32 billion tons ofstrippable reserves,28 Mine-mouth costs aregenerally half that in the Midwest (see table28) but transportation costs are high, com-prising about one-half to two-thirds the de-livered cost in the Midwest. The Crow andNorthern Cheyenne Tribes have large re-serves of coal that do not depend on Federal,State, or private coal to form minable blocks,

Montana has the highest severance tax inthe United States, Between 1970 and 1975(the year Montana’s severance tax was insti-tuted) growth rates in coal production inMontana and Wyoming were approximatelythe same. Between 1976 and 1979 the growth

2 8 1 3 R , E. ~~iltsorl an[j J. m’. B]umer, Quofit} ond Heserkrf:s f)~

Stripp{lhlc C(NJI Selmtefi Depos i ts , Southmlstern Monttln(l, bul-lelin 91 (Butte, Nlont.: hl(~ntana Bureau of \lines and Cet)l(jgv.December 1973).

rate in coal production in Wyoming wasalmost three times that of Montana (19.3 per-cent compared to 6.5 ). Several published re-ports have concluded that Montana’s sever-ance tax has depressed the growth rate ofcoal production in the State and point to thedifference in growth rate between Montanaand Wyoming as evidence. 29 However the dif-ference in growth rates between the twoStates can also be attributed to other factorsthan the severance tax, such as limits on theavailability of rail lines to areas for proposednew development, and slightly higher produc-tion costs before severance taxes are appliedin either State. It is possible that Montana’shigher severance tax may increase Wyo-ming’s share of production from the PowderRiver basin compared to what it would havebeen without differentials in severancetaxes, but no analysis of Montana’s sever-ance tax to date has established a clear rela-tionship between the tax and changes in Mon-tana coal production,30 Whatever its relativeimpact in Montana and Wyoming, the sever-ance tax remains a small percentage of thedelivered price of electricity generated fromPowder River basin coal, and despite the highseverance tax planned production capacity inMontana during the next 10 years is high (seechs. 6 and 7).

Wyoming

In 1979 Wyoming produced 71,8 milliontons of coal, which was 44 percent of totalcoal production from the six major Federalcoal States and more than twice the produc-tion from Montana, which was the secondranked State of the six. This high level of pro-duction is the result of favorable conditions inthe State’s coalfields in both the PowderRiver basin and southern Wyoming. Wyominghas very large (23 billion tons) reserves ofsurface minable coal in thick coal seams withlow stripping ratios in the Powder River

-“See for example Coal Age, April 1979, p. 39, and HouseCommittee on Interstate and Foreign Commerce, Coal Sev-er[lnce Tf].xes, hearing report 96-173 (Washington. D. C.: U.S.Government Printing Office, 198o).

1“Personal communication, Arnold Silverman, professor (IfEconomic Geology a t the Universi tv of Montana, Nlissoula(phone conversation, Feb. 10, 1981].


basin, and also moderate reserves (3.2 billiontons) of medium-Btu coal (9,500 to 10,500Btu/lb) in southern Wyoming that can be sur-face mined.31

Coal in the Powder River basin of Wyomingis cheaper to mine than anywhere else in theUnited States. The best coal deposits in thePowder River basin are also well located withrespect to rail lines, and are likely to beserved by at least one coal slurry pipeline bythe mid or late 1980's. The major disadvan-tage of coal from the Powder River basin isthat it has a low heat content, and there aresome potential bottlenecks outside of Wyo-ming in transporting coal by rail to markets tothe East and South. Reserves are sufficient tosupport many mine-mouth conversion facili-ties, but the availability of water for onsitedevelopment, plus other siting problems limitsthe likelihood of extensive onsite developmentduring the next 10 years.

The central geographic position of coal-fields in southern Wyoming, combined withtheir close location to the Union PacificRailroad’s main line, facilitates competitionin States to the East and West. Mining condi-tions are generally more difficult in southernWyoming compared to the northern GreatPlains both because dipping coal seams aremore difficult to mine and also because themore arid climate creates more difficult con-ditions for reclaiming mined land. As a conse-quence, mine-mouth prices are higher, evenwhen the higher heat content is taken intoaccount.

Colorado

In 1979 Colorado produced 18.1 milliontons of coal, ranking third among the sixmajor Federal coal States. The main ad-vantage of Colorado coal is high heat contentand low-sulfur content, reserves of surfaceand underground coal that are served by ex-isting transporatation networks, significantreserves of metallurgical coal, and a centralgeographic 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 ofWVoming, 1978).

the Southwest as well as the Midwest andwest coast.

One of the major market disadvantages isthat the majority of reserves in the State mustbe underground mined, resulting in relativelyhigh mine-mouth costs. However, surfacemine production will continue to provide atleast half of Colorado’s coal output throughthe 1980’s. Transportation costs place Col-orado somewhat at a disadvantage in bothWestern and Midwestern market areas com-pared to the other States. Utah is closer towest coast demand centers, and New Mexicois closer to both major demand centers insouthern California and in the South-CentralUnited States. Even though Colorado is closerto the demand centers in the South-CentralUnited States than Montana and Wyoming,transportation costs are relatively higherbecause most production must cross highmountain passes and rail routes are not asdirect. The mountain passes increase trans-portation costs because steep grades necessi-tate more engines and fewer cars than typ-ical unit trains. Also, lines owned by two orthree railroads must be traversed to reachmost destinations in the Midwest and South-Central United States. Because of thesetransportation costs, a significant fraction ofthe coal used by utilities in eastern Coloradocomes from Wyoming.

Utah

In 1979 Utah’s coal production was 11.8million tons. The main advantage of Utah coalis high heat content of steam coal, reserves ofmetallurgical coal, and close location to de-mand centers on the west coast, The majordisadvantages are that virtually all presentproduction is from underground mines, andconsequently mine-mouth costs on the aver-age are the highest of any Western State.Fields in southern Utah have significant sur-face minable reserves, but are distant fromexisting transportation networks. Twenty-four million tons of the Alton field reserves insouthern Utah nearest to Bryce Canyon Na-tional Park have been designated by DOI asunsuitable for mining, Utah is also very farfrom coal demand centers in the Midwest and


South-Central United States with c o n s e q u e n thigh transportation costs, Nevertheless, Utahcoal, because of its high heat content and lowsulfur content has penetrated these markets(see fig. 20).

New Mexico

In 1979 New Mexico produced 15.1 milliontons of coal, slightly more than fifth-rankedNorth Dakota. The major market advantagesof coal in New Mexico are the presence ofmoderate reserves of medium-Btu (9,500 to10,500 Btu/lb) surface minable coal in the SanJuan River region, sufficient to supply high-volume, long-term contracts with utilities.The Raton Mesa coal region has high-Btucoal, but a substantial fraction must be un-

derground mined and thus has a relativelyhigh mine-mouth cost per ton. New Mexico iscloser to coal demand centers in Texas thanother Western coal-producing States and thisrepresents a significant potential market thathas as yet been unrealized because some ofthe existing coal leases are not well served bytransportation networks. Extensive develop-ment of coalfields in the San Juan basindepends on construction of the Star Lake-Bisti Railroad. A significant disadvantage ofsome New Mexico coal is that some of themajor coal deposits in the San Juan Riverregion are quite uniformly high in ash content(generally greater than 14 percent) andcleaning to reduce ash adds to the cost ofusing the coal.

The Market Area of Western Coal StatesThe share that each Western coal State

has in fulfilling the demand for coal dependson the extent to which the advantages in theState outweigh the disadvantages relative tothe other Western States and other coal re-gions. Figure 20 shows all the States to whichthe six major Federal coal-producing Statesshipped coal in 1979, The percentage shownin each Sta te on the map indicates how muche a c h F e d e r a l c o a l S t a t e c o n t r i b u t e d t o t o t a lState use of coal. Coal went to every Statewest of the Mississippi River and to sevenStates east of the Mississippi River. In none ofthe States east of the Mississippi River did thecombined contribution of Western coal ex-ceed 37 percent of total coal use, which in-dicates that Western coal has made substan-tial inroads into the central market areas ofthe Midwest coalfields, but has not achievedmarket dominance* over local coal in theseareas. On the other hand, west of the Missis-sippi River, Western coal contributed morethan 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 torefer to mm] that has a strong cornpeti t ive edge in a certainmarket area. The specific meaning of market dominance ;isused in railroad ra Iemaking is not rneanl.

western coal in these markets. The excep-tions are in Texas, where local lignite has thedominant share of the coal market and inMissouri.

The relative competitive position of the sixWestern coal States can be measured by sev-eral indicators: total coal production, the geo-graphic area where coal is sold, and the per-centage contribution to total State coal use.This information is summarized in table 30.

Wyoming’s market dominance compared tothe other five Western States is evident fromthe data shown on this table. Wyoming hasthe largest level of coal production of anyWestern State producing Federal coal. In ad-dition coal from Wyoming was shipped to thelargest market area (22 States) and in 11 ofthose States Wyoming contributed the largestpercentage of in-State coal use compared tothe other five States. Furthermore, Wyomingcontributed more than half of total in-Statecoal use in eight States, whereas no otherWestern State contributed more than thispercentage in more than one State. Wyomingalso shipped coal to all the Western coal-producing States except Arizona and NewMexico. Wyoming coal’s cost competitiveness

98 . An A

ssessment of D

evelopment and P

roduction Potential of F

ederal Coal Leases

Figure 20.-Market Areas of the Six Major Federal Coal·Producing States

NOTE: Only those States using coal from Montana, New Mexico, North Dakota, Colorado, Utah, and Wyoming are shown. Percentage indicates supplying State's share of user State's coal demand in 1979. Number is in millions of tons and is total State coal uselshipments received.

SOURCE: U.S. Department of Energy, Bituminous and Subbituminous Coal and Lignite Distribution, Calender Year 1979 (Washington, D.C.: U.S. Government Printing Office, April 1980).


Table 30.—Market Relationships Between the Six MajorFederal Coal-Producing States

1979 Market area Contribution to No. majorproduction (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 in-

cluded As of January 1981 none of the proposals listed here was at a stage where production of synthetic fuels was certainCompiled 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. Thenumber for Wyoming Includes a feasibility study being conducted by Rocky Mountain Energy Co. for a synfuel plant todevelop a Federal lease in southern Wyoming and a Utah facility, neither of which is listed in either of the previously citedsources

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 necessarilythe dominant supplier in the State). -


compared to Colorado coal along the FrontRange urban corridor in Colorado, arisingfrom transportation factors, is shown by thefact that Wyoming contributed almost one-quarter of Colorado’s total coal use in 1979.

Montana is the State with the next greatestcompetitive advantage, as measured by totalcoal production. In 1979 Montana producedalmost twice as much coal as Colorado, thenext largest coal producer. However, it is ap-parent that market dominance in terms ofmagnitude of coal production is not neces-sarily accompanied by dominance in terms ofgeographic market area, as can be seen in thecases of Colorado and Utah. Both Statesranked below Montana based on coal produc-tion, but both Colorado and Utah have verylarge geographic market areas compared toMontana, North Dakota, and New Mexico. Infact, Colorado shipped coal to as many Statesas Wyoming. However in only a few Statesdid Colorado or Utah contribute the highestpercentage of total State coal use, and in alarge majority coal shipments representedless than 10 percent of total coal use.

The main reason magnitude of coal produc-tion and the size of market area do not alwayscoincide is that utilities use much largervolumes of coal than industrial users. The lowcost of surface mined coal in the PowderRiver basin, along with large blocks of re-

serves that can sustain high production ratesfor long-term utility contracts have been thekey factors in the market dominance (in termsof magnitude of coal production) enjoyed byWyoming and Montana. The high quality ofcoal in Colorado and Utah (high heat contentand availability of metallurgical coal) allowsa large geographic market area through saleto industrial users, spot market utility sales,and sale for blending with high-sulfur Mid-western coal. However, the high cost of pro-ducing and transporting this coal has signif-icantly limited total production compared toMontana and Wyoming. New Mexico is per-haps the only Western State in which therelationships described here may change sig-nificantly during the next 10 years. At thepresent time New Mexico does not export sig-nificant amounts of coal out-of-State. How-ever, Texas represents a significant potentialmarket that could possibly use 20 million tonsof New Mexico coal by 1990. *

Table 30 also lists the number of large-scale synthetic fuel plants that are in activeplanning stages in each State. All of theseprojects, except one in North Dakota, are stillin early planning stages, and there is no cer-

*The OTA New Mexico Task Force estimated that 20 milliontons or more of coal would he shipped to Texas markets in199o. This seems to be optimistic (see discussion of forecasts ofdemand 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 con-structed. North Dakota has a large number ofpossible plants because the reserves are well--suited for conversion to synthetic gas, andwater needed for cooling and conversionprocesses is more readily available than inother Western coal States. Wyoming has alarge number of proposed projects due pri-marily to the availability of reserves in boththe Powder River basin and southern Wyo-ming to support such facilities, but availabil-ity of water is more of a problem than inNorth Dakota. Projects in the active planningstage in the remaining four States range fromone each in Colorado, New Mexico, and Utahto two in Montana.

The discussion of synthetic fuels earlier inthis chapter indicated that significant levelsof coal production for synthetic fuels wereunlikely before 1990. The capacity in 1990 of

the only two projects that were judged byOTA to have a good chance of being in opera-tion before 1990 (the Great Plains Gasifica-tion Project in North Dakota and PanhandleEastern’s proposed gasification project innortheastern Wyoming) is 12 million tons, butit is uncertain whether either would be pro-ducing at full capacity by 1990.32 Levels ofcoal production for synthetic fuels couldbecome significant after 1990. Coal consump-tion of currently proposed commercial-scalesynthetic fuel plants that would use coal fromthe major Federal coal States would be 95million tons per year at full capacity. Attain-ment of full capacity might be reached in themid 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 certaintythe demand for coal from the major Federalcoal States over the next 10 years, but it ispossible to estimate demand. Numerous esti-mates (usually called forecasts or projec-tions) concerning demand for coal from theWest have been made for the 1985-90 periodthat was the focus of OTA’s analysis of ex-isting Federal leases.

Production and Demand Forecasts andProduction Goals

Coal forecasts fall into two major catego-ries: 1) production projections that are basedon production commitments under existingcontracts and potential production based onindustry plans to open new mines and expandproduction at existing mines, and 2) demandprojections based on computer models thatassume certain conditions in coal marketsand allocate coal production to different coalregions based on varying assumptions aboutfactors such as mining and transportationcosts and electrical growth rates. Production

forecasts are most useful for evaluatingchanges in coal production over the shortterm (up to 5 years or so in the future)whereas demand forecasts are most usefulfor evaluating intermediate and long timeperiods (greater than 5 years). Each ap-proach has its own advantages and limita-tions.

Production Forecasts

These forecasts are more directly relatedto the “real” world because they are basedon contractual commitments and specific in-dustry plans. Production forecasts based onindustry plans for new mine openings andmine expansions are frequently high becausesuch plans are based on individual companyexpectations of the share of market demandthey will be able to capture. Some of the ex-pected market share may be captured byother competitors and consequently actualproduction may be less than productionbased on industry plans. Also, coal contractsusually specify a range of possible delivery

Ch. 5—Markets and Projected Demand for Federal Coal - 101

rates. If electric utilities need less than themaximum amount contracted for, then fore-casts based on contracts will overstate pro-duction. For example, in the Powder Riverbasin of Wyoming, deliveries to utilities in1979 and 1980 averaged about 5 percentlower than would be expected based on con-tractual commitments. ” Production forecastscan change quite rapidly in response tochanged perceptions by the coal industry oflikely demand. For example the projectedcapacity for coal mines in Carbon, Sevier,Wayne, and Emery counties in Utah for theyear 1985 dropped from 45.2 million tons in a1977 survey to 26.5 million tons in a 1979survey .3’ One value of production forecasts isthat they can serve as an indicator of thecapacity of the coal industry to respond tochanges in demand.

Demand Forecasts

Based on computer models, these forecastsare not very reliable for making point fore-casts for a single year because small errorsin assumptions used in making the forecastcan result in large differences in projectedamounts. On the other hand, computer mod-els are very useful in evaluating the sensitiv-ity of demand for coal to changes in condi-tions such as the electrical growth rate and inidentifying possible ranges in demand inresponse to different conditions. The range ofpossible demands generated by computermodels using different assumptions can be sogreat that ultimately identification of a “mostlikely” range of demands must be based onhuman judgments by individuals knowledge-able about current coal market conditionsand an understanding of the impact that ex-isting trends and possible changes in thesetrends will have on future demand. Evalua-tion of forecasts from a number of differentsources allows the development of a range of“most likely” demands in which a higherdegree of confidence can be placed than the

“Personal communication with Gary Glass, Geological Sur-vey of Wyoming, September 1981.

“The 1977 and 1979 Keystone Coal Surveys reported in CoalAge, February 1978; and Coal Age, February 1980, respective-ly.

range of possible demands that may be gen-erated by a single computer model.

An important element in OTA’s evaluationof the production potential from existingFederal coal leases was to identify a mostlikely range of demands for coal from themajor Western coal regions and States withFederal leases. This identification of prob-able ranges in demand generally involved afour step process: 1) review of existing pro-jections from different sources, 2) develop-ment of independent projections by OTAbased on evaluation of market conditions inthe specific regions or States of interest, 3)development of estimates by OTA State taskforces based on review of projections iden-tified in steps 1 and 2 and/or the developmentof new estimates representing the collectivejudgment of task force members, and 4) fur-ther evaluation and modification of task forceestimates by OTA to identify a range of de-mands which could be compared to other esti-mates of production potential from existingFederal leases. *

Production Goals

OTA also paid particular attention to twosets of forecasts that became available aftermost of OTA’s task force meetings had beencompleted: 1) the August 1980 preliminarycoal production goals and the January 1981final production goals developed from DOE’sNational Coal Model36 and 2) refinements tothe National Coal Model forecasts developedby ICF, Inc., using its Coal Electric UtilityModel. 37 DOE’s final production goals were

...——*Special market analyses were prepared for OTAA on the

Powder River basin and southern \\’yoming, Utah, and Col-orado. The Utah, Wyoming. Colorado, and New Mexico taskforces each discussed various ranges of likely demand in theyears 1985 and 1990 ([he bases for these pr[)j(:(t]ons ,] re surl-ma 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 widerrange for purposes of a na] yzing pro(iuc! ion pllten I i,]] from ex-ist in~ Federal leases,

‘ll+-eJirnin(~ry Nfjtionrd and ~e~ion[li CCJ(I/ F’r(j{iu((i{)n (;~MIlsfor 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(Niuclion 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 preliminarygoals (see tables 31 and 32). The final na-tional goals average 16.6, 15.7, and 26.0 per-cent higher than the preliminary goals for theyears 1985, 1990, and 1995 respectively. Thefinalvery(seefinaltonsthan

DOE goal for 1985 (1.118 million tons) isclose to both the ICF and NCA forecaststable 32), but the 1990 and 1995 DOEgoals (1,620 million and 2,214 millionrespectively) are considerably higherrecent Projections from other sources

for the same time periods. The 1990 DOEfinal goal is almost 300 million tons higherthan the highest recent forecast shown intable 32 and the 1995 DOE final goal is almostas high as the high “likely” projection for2000 shown on table 32.

The reason for the increases from the pre-liminary to the final DOE production goals ap-pear to be primarily a clearer conceptualdefinition of the relationship between coalproduction goals and other coal productionforecasts. As the report on the DOE finalgoals says:

The goals developed here are based on na-tional energy needs, existing and emergingnational and international policies and laws

Continued from p. 101liminury AIotionul ond Ilegion(d f.lxJl Production Gools for 1985.1990 ond 1995 (Washington D. C.: ICF, Inc., October 1980). ICForiginally developed the National Coal Model that is used byDOE 10 develop production goals., and has since refined thismodel into the Coal Electric Utility Llodel (CEUM). ICF’S cri-tique of the DOE preliminary goals identified a number ofstructural deficiencies in the model, and deficiencies in dataand assumptions used in the mode]. Examples of structuraldeficiencies include such things as coal production and de-mand regions not coinciding with DOI coal production regionsnecessitating often arbilrary allocation of model outputs be-tween regions, and distortion of transportation cost due tousing average distances between large regions (e. g., transpor-tation costs for southern Wyoming are calculated using anaverage distance from the Powder River basin. ) Examples ofdeficiencies in data and assumptions include out-of-date coalreserve data in several regions, and unrealistically lowassumptions about increases in transportation costs (see foot-note 9). The ICF forecasts correct many of these problems,although ICF emphasizes in its analysis that no modelingforecast can be considered definitive, and that the results offorecasts must be interpreted and used with judgment. Some ofthe deficiencies pointed out by ICF were corrected in preparingthe final goals (i.e., analysis was based on DOI supply regionand higher transportation costs were used) but other changesin assumptions were made that makes comparisons betweenthe ICF base case and DOE final production goals more dif-ficult.

that affect coal demand and supply, andmarket conditions, By comparison, energyforecasts are generally based on expectedmarket conditions and energy laws and regu-lations. Since many of the assumptions un-derlying the production goals are based onpolicy initiatives to expand domestic coalproduction, the goals are likely to exceedcoal production forecasts ., , Such a rela-tionship is entirely appropriate.

The assumptions that were used in setting thepreliminary production goals appeared con-sistent with a forecasting approach ratherthan a production goal approach to modeling.Thus, the difference between the final andpreliminary goals can be attributed mostly toassumptions concerning implementation ofGovernment policies that will increase de-mand for coal. * For example, the final pro-duction goals assume 1 million bbl/d oil equiv-alent of coal-based synfuels production in1990 (in accordance with goals set when theSynthetic Fuels Corp. was established) andstrict enforcement of the 1990 deadline inPIFUA for utility and industrial boiler conver-sions from gas to coal. It does not appear like-ly that these goals will be met by 1990. Thesynfuels assumptions in the final productiongoals substantially exceed those in recentcoal production forecasts (see Synthetic Fuelssection), and section 301(a) (the off gas re-quirement) of PIFUA has been repealed byCongress, although rising prices for naturalgas will serve as as incentive for conversionfrom gas to coal.

The final production goals are listed inmost tables and figures in this chapter toshow their relationship to other productionforecasts, but are not considered in detail inthe evaluation of the likely range of coal de-mand in the major Federal coal States be-cause the assumptions on which the finalgoals were developed probably overstate theimpact of Government policies on increasingoverall demand for coal in the UnitedStates.** However, the preliminary produc-

——. —‘See p. 79 for additional discussion of the conceptual distinc-

tion between Government policies that change the frameworkof the market system and policies that influence the marketsystem directly to increase demand for coal.

**it should be noted that in some instances (Colorado in par-ticular) the final production goals are lower than the pre-


Table 31 .—Comparison of Demand Projections for Major Western Federal Coal Regions and StatesWith 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 177and Wyoming). . . . . . . . . . . . . . 1990 186(206) 275(295) 438(412) 163 226 382 199 to 212

Rocky Mountain coal provinceWyoming (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 25-261990 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 181990 41 (36) 43 (49) 52 (63) 15 27 59 1 8a to 30a to 40a

New Mexico. . . . . . . . . . . . . . 1985 32 (33) 34 (38) 40 (44) 28 30 32 about 301990 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 andCrltique 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. Departmentof 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 CoalProduction and Summary of Coal Contracts (Laramie, Wyo. Wyoming Geological Survey, 1960), and likely high demand taken from J J. Sebesta, Demandfor Wyoming Coal 1980-1991 Based Upon Protected Utility Coal Market (Washington, DC.. Office of Technology Assessment, October 1980) with slightmodifications by the Wyoming Task Force as reported in J. R. Boulding and D. L. Pederson, Development and Production Potential of Undeveloped FederalCoal Leases and Preference Right Lease Applications in the Powder River Basin and Other Wyoming Coal Basins (Washington, D.C. Off Ice of TechnologyAssessment, 1981), Likely high demand for Montana Powder River Basin taken from J. J, Sebesta, Demand for Montana Coal 1980-1991 Based Upon Pro-yected Utility Market (Washington, D C.. Off Ice of Technology Assessment, October 1980). Most likely projections for the whole Powder River Basin derivedby adding Sebesta’s Montana projections to Glass’ Wyoming projections, and likely high demand derived by adding Sebesta’s Wyoming and Montana pro-jectlons Note that the Glass and Sebesta projections for southern Wyomlng in 1985 are the same, so there IS no range shownColorado Estimates by Colorado Task Force, Sept 22-24, 1980, represent minimum production expected from existing contracts, mine plans, and undevel-oped 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 FHachman, Market Factors Associated With the Assessment of Development Potential of Federal Coal Leases in Utah, prepared for the Office of Technol-ogy Assessment, 1980 Total excludes production from Alton Mine or for the Allen-Warner Valley ComplexNew Mexico OTA New Mexico Task Force, Aug. 26-27, 1980 Estimates developed by task force as reported in The Development Prospects for Federal CoalLeases 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 othercoal production forecasts and are analyzed inthis chapter as such.

Table 31 summarizes the DOE, ICF, andOTA task force projections for the Fort Unionand Powder River coal regions, southernWyoming, Colorado, Utah, and New Mex-ico. * Figure 21 compares these projectionsschematically 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 refine-m e n t s i n 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 coalSlates will come from the Powder River region (50 percent or

River regions and southern Wyoming, and fig-ure 22 illustrates these projections for Col-orado, Utah, and New Mexico.

It should be kept in mind when comparingthe DOE, ICF, and OTA task force forecaststhat they were derived by very differentmethods, The model forecasts are based onvarying assumptions concerning factors af-fecting the overall demand for coal in theUnited States: this demand is then allocated

m ( )rc), dcma nd pro j e(’ t i( )ns f[ )r this ii rea k~erc tlllil Ipzcd 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 forthe P{)w(ier Ri\(:r Ix]sin ([in ho foun(i in (’h. 7.

4 . - ‘+ 1 XI - 6 : ,,[ ‘


Table 32.–Demand and Production Forecasts for Coai for the United States: 1985-2000(millions of tons)

1985 1990 1995Low Medium High Low Medium High Low Medium High 2000

EIA production forecasts (1979). . . . 1,129 1,130 1,129 1,305Council on Environmental Quality

(1979) . . . . . . . . . . . . . . . . . . . . . . . – – – –Exxon (1979). . . . . . . . . . . . . . . . . . . . – – – –DOE preliminary production goals

(1980) . . . . . . . . . . . . . . . . . . . . . . 880 963 1,080 1,089ICF CEUM forecasts (1980) . . . . . . . 915 1,016 1,082 1,122Data Resources, Inc. (1980) . . . . . . . – 987 – –National Coal Association (1981) . . 878 1,015 1,131 1,092DOE 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 2,3221,300 1,791 1,380 1,756 2,9761,290 – — 1,617 —1,345 1,540 — — —1,620 1,986 1,519 2,214 2,766

—

899-1850a2,219

——

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 fromthe national average projected in 1990 by Congressional Research Service project Interdependence: U.S. and World Energy Outlook Through 1990, Senate Committeeon Energy and Natural Resources, Pub. No. 95-31 (Washington, D. C.: U.S. Government Printing Office, 1977).

blncluded 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 for1985, 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 fundamentalweakness of all computer models is that theyare least accurate when results are disag-gregate to small geographic regions. Thereason for this is that when modeling complexsystems, simplifying assumptions must bemade. At the aggregate level, simplifyingassumptions that may distort results one wayor another tend to cancel each other out. Atthe specific geographic level, small changesin assumptions may create large shifts in pro-jected demand between regions.38 It must alsobe realized that models reflect the assump-tions, perceptions and biases of the modelmanager. In addition, models tend to seek op-timal (least cost) solutions to fuel procure-ment and the entire system tends to approacha general equilibrium solution. Rarely, ifever, are these conditions totally achieved inreality.

The OTA task force estimates, on the otherhand, were developed based on analysis andjudgments by a group of people familiar withthe effect that specific conditions in the

38 Additional discussion of this problem can be found in theICF report cited previously and also in Energy and Environmen-tal Analysis, Inc., Feasibility of Using Coal Market ProjectionsTo Appraise Potential Production of Federal Coal Leaseholds,draft report prepared for OTA, 1980.

region or State could have for the demand forcoal from that area. The advantage of this ap-proach is that it reflects a sensitivity to localconditions that a computer model cannothave. The disadvantage of this approach isthat events or conditions outside of the Stateor region might affect demand for coal fromthat region in ways not anticipated by thetask force. There is also a possibility that in-dividuals closely associated with develop-ment in a region or State may underestimatethe effects of competition from another regionor State.

The value of looking at both kinds of fore-casts is that the two can be used as a checkagainst each other. If several different fore-casts are in close agreement, then it can beexpected with a reasonably high level of con-fidence that actual production will be close tothe levels forecasted. On the other hand, ifdifferent forecasts of the “most likely” levelof production differ substantially, then acloser look at the forecasts is merited to try tounderstand the reasons for the differences.

Given the inherent uncertainty in fore-casts, it is necessary to identify a range* to

* I t should be noted that this range is distinctly different fromthe 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 thatcannot be predicted, The rest of this sectionexamines more closely the different forecastsin the regions and states shown in figures 21and 22, identifying, where possible, the rea-sons for divergence between the forecasts.

Fort Union Region

Virtually all production from this regioncomes from North Dakota; only 0.5 milliontons were produced in the Montana portion ofthe Fort Union region in 1979, compared to15.0 million tons in North Dakota. The DOEand ICF forecasts are in close agreement in1985 (see fig. 21) but diverge widely in 1990with the ICF high forecast nearly the same asthe DOE low forecast. OTA did not convene atask force for this region, so no projectionsare available for comparison, but OTA’sevaluation of existing leases found that 30million tons would be needed to meet the re-quirements of existing and new coal conver-sion facilities currently planned or under con-struction. Given the leadtime necessary toconstruct these large facilities, it appearsthat demand for Fort Union coal in 1990 islikely to be closer to the ICF forecast than thehigher DOE forecasts.

Powder River Basin

All three forecasts show quite good agree-ment for 1985 (see fig. 21) with the ICF basecase of 169 million tons exactly the same asthe OTA task force most likely productionestimate, and DOE’s medium forecast 10 mil-lion tons lower. However, OTA’s likely highdemand in 1985 is considerably lower thanthe DOE and ICF high forecasts. In 1990 thereis considerable divergence between the three

DOE and ICF forecasts shown in table 31, Tbese ranges are in-dicative of the sensitivity of demand to changes in assump(i(ms(ha I are plugged into the model. but are not necessarily inciica-tive of what is likely to happen in the real world. Even though(he low to high ranges identified bV OTA for analysis of exis[ingh’ederal leases are narrower than the model ranges, it is Iikel}that (iemand for 1985 and 1990 w1lI be within the ran~e. After1990 unrerta inlies and ran~es in forecasts increase r(Jnsider-ablv (see final section of this chapter]; OTA did not allempt todevelop m[)s t likdv ranges of dema n(i for the post- I {)90 period,

forecasts, with OTA’s likely high estimate of212 million tons being 14 million tons lowerthan the ICF base case, and 63 million tonslower than DOE’s medium forecast. The mainreason the DOE forecast is so much higherthan the ICF forecast is that the DOE fore-casts included unrealistically low increasesin transportation costs that were modified inthe ICF forecast. OTA used the DOE mediumforecast as its high-demand scenario foranalysis of production potential of leases,even though it is probably beyond the rangeof “likely” high production levels. (See ch. 7for further discussion of demand for PowderRiver basin coal,)

Southern Wyoming

The OTA task force and ICF projections of38 million tons for southern Wyoming are ex-actly the same in 1985 (see fig. 21 ) and areconsiderably lower than DOE’s midrangeforecast of 50 million tons, In fact, DOE’s mid-range forecast for 1985 is almost the same asthe OTA likely high estimate of 51 million tonsfor 1990. The primary reason for the highDOE numbers is that the DOE model consider-ably understates transportation costs fromsouthern Wyoming because distances in themodel are calculated using a centroid locatedin the Powder River basin, In 1990, DOE’s lowforecast is still higher than ICF’s high fore-cast (for the reason just mentioned) and theOTA range of likely to likely high productionfalls within the midrange to upper range ofthe ICF forecast. For reasons that are notclear, the ICF base forecast drops below its1985 forecast (from 38 million to 36 milliontons) and is thus lower than the OTA taskforce projection.

Colorado

The DOE and ICF forecasts for 1985 arevery close (36 million and 35 million tonsrespectively); the OTA task force estimate inthis case is an estimate of minimum demand.For 1990, the OTA task force estimate of 32million to 38 million tons is comparable to theICF and DOE low forecasts, The ICF baseforecast is considerably higher than the DOE

-. —


400

300

200

100

Figure 21 .—Demand Projections for the Fort Union and Powder River Coal Regionsand 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 milliontons). The OTA task force estimate was con-servative; and although the DOE and ICFmodels may not be sensitive to the especiallydisadvantageous situation in Colorado withrespect to transportation costs, as discussedearlier in this chapter, demand in 1990 maybe closer to the DOE range than the OTArange.

Utah

The forecasted ranges by DOE and ICF donot overlap at all in 1985. The OTA task force

estimated that 1985 production in Utah wouldcome from mines currently in operation orconstruction. In 1980, the State geologicalsurvey estimated planned 1985 productionwould be between 15 million to 18 milliontons. Probably the ICF base of 16 million tonsand the DOE medium forecast of 29 milliontons is a reasonable low to high range. In1990 the ICF base projection and OTA mis-estimate are close (27 million and 30 milliontons respectively) but are considerably lowerthan the DOE midrange forecast of 43 milliontons. The DOE medium forecast is quite closeto the OTA high estimate of 40 million tons.


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

3432 30

‘-J9

1 -44

115

i 1 I I I I I1985

Colorado

aFigures shown are low ranges.bOTA demand estimates for-central Utah onlycFigure represents maximum likely demand.

SOURCE Table 30

New Mexico

The ICF base forecast and the OTA esti-mate in 1985 are exactly the same (30 milliontons) and 4 million tons lower than the DOEforecast, which indicates good agreementamong all three forecasts. In 1990 the DOEand ICF forecasts are very close (57 millionand 58 million tons respectively) but are con-siderably lower than the OTA task force esti-mate of 72 million tons. The OTA task forceestimate was admittedly an optimistic esti-mate, and assumed that in the 1990’s NewMexico would be shipping 20 or more milliontons of coal to Texas markets. A substantialportion of Texas exports would come fromcaptive mines. The OTA task force estimatehas been categorized in table 31 as a poten-

Utahb New Mexico

tial high production level rather than a “mostlikely” level of production. If it is assumedthat New Mexico exports a more modest levelof 10 million tons per year to the South-Cen-tral States in 1990, the OTA estimate woulddrop to 62 million tons, which is close to theDOE and ICF projections.

Comparisons of ForecastsThe comparisons between the three sets of

forecasts for the major Federal coal regionsand States allow a few generalizations. First,compared to the DOE and ICF forecasts, theOTA task force estimates are quite consist-ently lower than, or near the lower of the mid-range forecasts of the two models. Althoughthe specific reasons for this vary, this is prob-


ably generally because the OTA task force es-timates are more sensitive to some of the fac-tors discussed earlier in this chapter thathave weakened the competitive position ofWestern coal. Another reason is that theOTA task forces quite uniformly did not con-sider synthetic fuels or foreign exports to besignificant sources of demand before 1990.Should demand from these sources material-ize to a greater extent than expected by thetask forces, demand might be higher than the“most likely” levels estimated. However, in-clusion of the higher midlevel forecasts fromother sources increases the upper range ofthe “most likely” estimates sufficiently thatpossible demand from these sources is likelyto be adequately accounted for. A secondgeneralization is that the 1990 forecasts fromall sources tend to have wider ranges thanthe 1985 forecasts. This can be attributed tothe higher levels of uncertainty in the factors

affecting demand 10 years from now com-pared to 5 years from now.

Demand for Western Coal: 1990=2000

Forecasts for the demand for Western coalafter 1990 have a much higher level of uncer-tainty than the period from 1980 to 1990, andOTA has not tried to conduct any quantitativeanalysis for the 1990’s. However, a numberof demand forecasts are available for theUnited States through 2000, and these can beused to get a general idea of possible trendsand development through to the end of thiscentury.

Table 32 shows eight forecasts made in thelast few years for total U.S. coal productionin 1985, 1990, 1995, and 2000. Elements ofthese forecasts are compared schematicallyin figure 23. Also shown in figure 23 for 1985

aColorado

Figure 23.– Demand and Production Forecasts for the United States: 1985-2000 andthe 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 AdministrationDRI Data Resources, Inc. ICF ICF Coal Electric Utility ModelDOE Dept. of Energy National Coal Modelc NCA National Coal Association

, Montana. New Mexico, North Dakota, Utah, and Wyomingblntermediate 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 discussionp 100

SOURCE Table 32.


and 1990 are the DOE and ICF forecasts forthe six major Federal coal States combined.From 1990 to 2000 both the range of “mostlikely” forecasts in figure 23 (shaded) and therange of low to high increase greatly, reflect-ing the greater uncertainties inherent in fore-casting over longer periods of time. In fact thelow forecast in 2000 (899 million tons) madeby the Council on Environmental Quality(CEQ), is lower than the lowest medium pro-jection in 1985 (963 million tons by DOE) (seetable 32). The CEQ forecast is based on a low-energy growth scenario in which conserva-tion is the main focus of national energypolicy.

Electrical growth rates after 1990 are gen-

erally projected to be similar to or lower thangrowth projected for the 1980-90 decade. Forexample, Exxon’s projection of 5.3 percentfrom 1978 to 1990 drops to 2,9 percent from1990 to 2000. ICF projects electrical growthrate continuing at 3.0 percent from 1990 to1995. Consequently, according to these pro-jections of electrical growth rate, rates of in-crease in coal demand for utility use can beexpected to be somewhat lower or about thesame in the last decade of this century, al-though conversion of oil and gas to coal may

offset lower overall electrical growth rates.

Significant areas of potential new demandfor western coal after 1990 include: 1) syn-thetic fuels, 2) industrial boilers, and 3) for-eign export. Possible (but not necessarilyprobable) levels of demand for Western coalfor these uses after 1990 could total on theorder of 250 million tons, which is more thanthe total of 231 million tons produced in theWest in 1979. Coal consumption for syntheticfuels plants could be around 100 million tons

(see p. 100), Incremental demand for indus-trial boilers from 1990 to 2000 in the wholeUnited States could be on the order of 100million tons (assuming the 7-percent growthin demand projected by NCA from 1979 to

1990 continues) of which perhaps half mightbe supplied by the West, Foreign exportscould possibly range from 50 million to 100million tons,

Most of the projections shown in table 32are not disaggregated to a level that allows aclose look at trends in forecasted productionfrom the six major Federal coal States, butmost forecasts make a breakdown betweenproduction from the West and East. Sometrends are evident when Western coal pro-duction is translated into percentage of totalU.S. coal production (see table 33). All theforecasts show a steady increase in theWest’s share of total U.S. coal production be-tween 1985 and 2000. A significant part ofthis increase is due to the fact that moreWestern coal must be mined to make a nequivalent contribution to U.S. energy needscompared to Eastern coal. For example, theCEQ forecast did not take this into account,and adjusting their forecast to correct for thelower heat content of Western coal increasedCEQ’s low coal demand scenario in 2000 from782 million to 899 million tons (see footnote,table 32).

A comparison of the different forecasts forany given year in table 33 shows that there isa considerable range in the percentage that isprojected to come from the West. In 1985 theWest’s share of total U.S. production is pro-jected to range from 33 to 43 percent and in1990 f rom 38 to 49 percen t . The Energy In-f o r m a t i o n A d m i n i s t r a t i o n p r o d u c t i o n f o r e -cas ts , which are the lowest for these 2 yearsa g r e e w i t h t h e m o s t r e c e n t f o r e c a s t i n t a b l e33 made by NCA and i t seems l ike ly tha t theg r o w t h r a t e o f W e s t e r n c o a l p r o d u c t i o n w i l li n c r e a s e a t a l o w e r r a t e t h a n t h e v a r i o u smodel forecasts (DOE, ICF, and DRI) indicate.In 1995 the forecasted percentage of West-ern coal product ion begins to converge ( f rom47 to 52 percent) with a mid point of 49.5 per-c e n t a n d i n 2 0 0 0 W e s t e r n c o a l p r o d u c t i o n i sp r o j e c t e d t o e x c e e d s o p e r c e n t o f U . S . p r o -d u c t i o n .

In tab le 33 the numbers in parentheses in-d i c a t e t h e p e r c e n t a g e o f t o t a l U . S . c o a l p r o -d u c t i o n t h a t w o u l d c o m e f r o m t h e s i x m a j o rFederal coal Sta tes . I t i s c lear f r o m t h e s epercentages that these States account formost of the product ion f rom the West , bu t theDOE and ICF forecas ts show product ion f rom

.


Table 33.—Forecasted Changes in Contribution ofWestern Coal to Total U.S. Production

SOURCE. See table 32

t h e m a j o r F e d e r a l c o a l S t a t e s g r o w i n g a t as o m e w h a t s l o w e r r a t e t h a n t o t a l W e s t e r ncoa l p roduc t ion be tween 1985 and 1995 . TheD R I f o r e c a s t s h o w s p r o d u c t i o n f r o m t h em a j o r F e d e r a l c o a l S t a t e s g r o w i n g a t as l i g h t l y f a s t e r r a t e t h a n t o t a l W e s t e r n c o a lp r o d u c t i o n b e t w e e n 1 9 8 5 a n d 1 9 9 5 . I t i s i n -t e r e s t i n g t o n o t e t h a t t h e f i n a l D O E p r o d u c -t i o n g o a l s i n d i c a t e a r e l a t i v e l y s m a l l e r p r o -por t ion of product ion f rom the major Federa lcoal S ta tes compared to the pre l iminary goals(i.e., 32 v. 38 percent in 1990). The final goalsa r e c o n s i d e r a b l y h i g h e r t h a n t h e p r e l i m i n a r yg o a l s , b u t t h e a s s u m e d h i g h e r c o s t i n c r e a s e si n t r a n s p o r t a t i o n a p p e a r t o h a v e r e s t r i c t e dt h e s h a r e t h a t t h e F e d e r a l c o a l S t a t e s o b t a i nof the higher goals.

Summary

The analysis of the various factors affect-i n g d e m a n d f o r c o a l f r o m t h e m a j o r F e d e r a lcoal Sta tes in th is chapter a l lows a few gen-e r a l c o n c l u s i o n s :

1. The demand for coal from the major Fed-era l coal Sta tes wi l l cont inue to grow ata fas ter ra te than the to ta l growth in thedemand for coa l in the Uni ted Sta tes due

3.

pr imar i ly to the low cos t of mining th iscoal compared to the Midwest and A p -palachia, and to the fact that more coalmust be mined to meet equivalent energyneeds because of the lower heat contentof the coal.

2 . However , because of severa l fac tors ( in-c r e a s i n g t r a n s p o r t a t i o n c o s t s a n d p r e s -e n t S O2 e m i s s i o n s t a n d a r d s b e i n g a m o n gthe most impor tant ) the compet i t ive pos i -t ion of Western coal in the Midwest andS o u t h - C e n t r a l U n i t e d S t a t e s ( w h i c h a r et h e m a j o r c e n t e r s o f d e m a n d f o r W e s t -ern coal) wi l l not be as favorable dur ingt h e n e x t 1 0 y e a r s . a s c o m p a r e d t o t h e

previous 10 years. The net effect ofthese factors, combined with downwardr e v i s i o n s i n p r o j e c t e d g r o w t h r a t e s f o re l e c t r i c i t y m e a n s t h a t t h e g r o w t h i n d e -mand for Western coa l wi l l p robably notb e a s g r e a t a s s o m e e a r l i e r f o r e c a s t sh a d p r e d i c t e d .A f t e r 1 9 9 0 W e s t e r n c o a l i s e x p e c t e d t oc o n t i n u e i n c r e a s i n g i t s s h a r e o f t o t a lU . S . c o a l p r o d u c t i o n , b u t t o t a l W e s t e r nc o a l p r o d u c t i o n m a y i n c r e a s e a t as l i g h t l y f a s t e r r a t e t h a n c o a l p r o d u c t i o nfrom the major Federa l coal Sta tes . Off-s e t t i n g s l o w e d g r o w t h i n d e m a n d b e -c a u s e o f p o s s i b l e r e d u c e d e l e c t r i c a lg r o w t h a r e a n u m b e r o f p o s s i b l e n e wmarkets for Western coal for which pre-c ise demands are d i f f icul t to predic t , butwhich could potent ia l ly be la rge consum-e r s o f c o a l . T h e s e p o t e n t i a l m a j o r n e wm a r k e t s f o r W e s t e r n c o a l a f t e r 1 9 9 0 a r es y n t h e t i c f u e l s , i n d u s t r i a l b o i l e r c o n v e r -s ions , and expor ts to Asia .

CHAPTER 6

Development Potential andProduction Prospects of

Federal Coal Leases

ContentsPage

Introduction and Summary of Findings.. . . 113Summary of Findings. . . . . . . . . . . . ........ 114

Development Potential and ProductionProspects of Federal Coal Leases inColorado, New Mexico, and Utah . . . . . . . . 116

Overview. . . . . . . . . . . . . . . . . . . . . . .........116Summary of Production Potential and

Planned Capacity. . . . . . . . . . . . . . . . . . . . . ..118Development Status of Federal Coal Leases

in the Southern Rocky Mountain Region . . . 123Leases With Approved Mine Plans. . ........124Leases in Pending Mine Plans. . . ............127Undeveloped Leases. . . . . . . . . . . . . . . . . . . . .l30

Development Potential and Production . .Prospects of Federal Coal Leases inNorth Dakota, Montana, and Wyoming.. .138

Summary of Production Potential andPlanned Capacity. . . . . . . . . . . . . . . . . . . . . . . 138

Quality of Coal Under Lease . . . . . . . . . . . . . . . 142Production and Consumption of Coal:

Powder River Basin, Southern Wyoming,and the Fort Union Region. . .............142

PageDevelopment Status of Federal Coal Leases

in North Dakota, Montana, and Wyoming. .146Leases With Approved Mine Plans and

Leases in Pending Mine Plans. . ..........147Undeveloped Leases. . . ..................151Diligence ● *************************** 156Diligent Development Analysis. . ...........156Comparison of Production From Federal

Leases and Diligent DevelopmentRequirements. . . . . . . . . . . . . . . . . . . . . . . . . ● 157

Diligent Development in Colorado,New Mexico, and Utah . . . . . . . . . . . . ......157

Diligent Development in North Dakota,Montana, and Wyoming . . . . . . . ..........161

in Oklahoma **** **** * * * * * * * * * * * * * * * 164Status and Production Prospects of Leases in

Approved Mine Plans in Oklahoma. . ......164Status and Development Potential of

Undeveloped Leases and Leases inPending Mine Plans in Oklahoma. . .......164

— —

List of Tables

TabIe No. Page34. Federal Coal Leases in Colorado, New

Mexico, and Utah. . . . . . . . . . . . . . . . . . . . . 11735. Rank ofCoal Under Lease in the

Southern Rocky Mountain Region. ... ...1l936. Total and Federal Production in

Colorado, New Mexico, and UtahSelected Years, 1972-80................120

37. Potential Production From FederalCoal Leases . . . . . . . . . ..... ....... 121

38. Acreage and Reserves Under Leaseby Development Status. . ...............124

39. Summary of Mine Plan and Federal

40

41

Lease Acreage and RecoverableReserves: Approved Mine Plans,Sept 30, 1980. . . . .....................125Mine Capacity and ProjectedProduction: Leases in Approved Mineplans: Colorado, New Mexico, andUtah, Sept 30, 1980.. . . . . . . . . . . . . . . . . .126Summary of Mine Plan, Federal LeaseAcreage-and Recoverable ReservesPending Mine Plans — Colorado, NewMexico, and Utah, Sept. 30, 1980. . . . ....128

42. Mine Capacity and ProjectedProduction: Leases in Pending MinePlans, Colorado, New Mexico, and Utah. .l29

43.Undeveloped Leases in Colorado,

44

45

46

New Mexico, and Utah: Acreage andRecoverable Reserves. . ................131Resource Characteristics ofUndeveloped Leases: Colorado,New Mexico, and Utah. . ...............133Summary of Development Potential ofUndeveloped Leases in Colorado, NewMexico, and Utah. . . . . . . . . . . . . . . . . . . . .134Summary of Potential Production andMine Capacity for Undeveloped LeasesWith Favorable or UncertainDevelopment Prospects in Colorado,New Mexico, and Utah. . ...............135

47. Potential Production From MinesContaining Federal Coal Leases:North Dakota, Montana, and Wyoming. ..l39

48. Acreage and Reserves Under Lease byDevelopment Status . . . . . . . . . . . ........146

49. Summary of Mine Plan and FederalLease Acreage and RecoverableReserves: Approved and Pending MinePlans in North Dakota, Montana,and Wyoming . . . . . . . .................149

50. Federal Mine Capacity and Federal MineProduction Prospects: Approved and

Table No,Pending Mine Plans in North Dakota:Approved Mine Plans in Montanaand Wyoming . . . . . . . .................150

51. Acreage and Reserves of UndevelopedLeases: North Dakota, Montana,and Wyoming , , . . . , . . . . . . . . . . . . . . . . . .151

52. Summary of Development Potential ofUndeveloped Leases: North Dakota,Montana, and Wyoming. . . . . . . . . . . . .

53. Summary of Production Prospects forUndeveloped Leases With Favorableor Uncertain Development Potential:North Dakota, Montana, and Wyoming

54. Analysis of Prospects for MeetingDiligent Development Requirements by1986 or 1991: Federal Leases, MiningUnits, and Recoverable Reserves in

. . 1 5 4

. . 1 5 5

Colorado, New Mexico, and Utah. . ......15855. Diligent Development Summary. . .......16256. Status and Development Potential of

Undeveloped Leases in Oklahoma. ... ... l65

List of Figures

Figure No. Page24. Potential Production From and Planned

Capacity of Federal Mines Summed Overthe Six Major Federal Coal States. ... .... ll5

25. Coal Regions in the Southern RockyMountain States . . . . . . . . . . . ...........116

26. Potential Production Capacity of AllMines With Federal Leases inColorado, New Mexico, and Utah. . ......117

27. Planned Capacity and PotentialProduction of All Mines With FederalLeases in the Powder River Basin,Southern Wyoming, and Fort UnionRegion, . . . . . . . . . . . . . . . . . ... ,... . . . 140

28. Federal Leases in the Hanna Basin,Southern Wyoming. . . . . . . . . . . . . . . . . . . .143

29. Federal Leases in the Powder RiverBasin, North of Gillette, Wyo. ...........144

30. Lessee Projections of Capacity, TotalProduction, and Federal ProductionFrom Mines With Federal Leases:Fort Union Region, Powder River Basin,and Southern Wyoming . . . . . . . .........148

31. Diligent Development Summary for theSouthern Rocky Mountain Region. ... ... l59

32. Diligent Development Summary forFederal Lease Reserves in Colorado,New Mexico, and Utah. . . .. ............160

33. Diligent Development Summary for thePowder River Basin. . .................163

CHAPTER 6

Development Potential and ProductionProspects of Federal Coal Leases

This chapter presents the results of OTA’s the Federal Coal Leasing Amendments Act ofa s s e s s m e n t o f t h e d e v e l o p m e n t p o t e n t i a l a n d l976 (FCLAA): an analys is of a l l mining ac-

p r o d u c t i o n p r o s p e c t s o f F e d e r a l c o a l l e a s e s . t i v i t i e s o n F e d e r a l l e a s e s a n d o f t h e p r e s e n t

T h e s e r e s u l t s c o n s t i t u t e O T A ’ s r e s p o n s e t o a n d p o t e n t i a l v a l u e o f e x i s t i n g F e d e r a l c o a l

t h e f i r s t a n d s e c o n d o f i t s f o u r c h a r g e s i n l e a s e s .

Introduction and Summary of Findings

This chapter presents OTA’s estimate of

t h e a m o u n t o f c o a l t h a t c o u l d b e p r o d u c e dfrom mines wi th Federal leases in the next 10years . The es t imates of the potent ia l produc-t i o n f r o m F e d e r a l l e a s e s m a d e i n t h i s r e p o r ta r e n o t f o r e c a s t s o f t h e c o a l t h a t w o u l d b eproduced a t a g iven pr ice or a g iven demand.They are es t imates of the to ta l amount of coalt h a t c o u l d b e p r o d u c e d f r o m c u r r e n t l y o p e r -a t i n g a n d p r o p o s e d F e d e r a l m i n e s a n d f r o mt h o s e u n d e v e l o p e d F e d e r a l l e a s e s t h a t h a v ec h a r a c t e r i s t i c s c o m p a r a b l e t o o p e r a t i n gm i n e s i n t h e s a m e r e g i o n . C o a l f r o m t h e s eleases would thus be l ike ly to be produced a ta price that is competitive with other mines inthe same area , (Most analyses of coal markett rends in the 1980’s , inc luding those used inO T A ’ s S t a t e t a s k f o r c e s , h a v e p r o j e c t e d t h a tdemand for Western coal wi l l expand s igni f i -c a n t l y w h i l e t h e p r i c e o f c o a l w i l l r e m a i ns t a b l e d u r i n g t h e n e x t d e c a d e w i t h p r i m a r yi n c r e a s e s b e c a u s e o f i n f l a t i o n . ) I f t h e p r o -jected increases in demand fa i l to mater ia l izeor i f holders of exis t ing leases do not capturea p r o p o r t i o n a t e s h a r e o f a n y e x p a n d e d m a r -k e t , t h e n n o t a l l t h e l e a s e s t h a t c o u l d t e c h -nica l ly and economical ly be developed wi l l bebrought in to product ion , Under those c i rcum-s t a n c e s , O T A ’ s p r o d u c t i o n e s t i m a t e s w i l l b eh i g h e r t h a n a c t u a l p r o d u c t i o n f r o m e x i s t i n gl e a s e s .

The years 1986 and 1991 are key years inF e d e r a l c o a l d e v e l o p m e n t . A l l F e d e r a l c o a ll e a s e s i s s u e d b e f o r e t h e p a s s a g e o f F C L A A

m u s t m e e t t h e d i l i g e n t p r o d u c t i o n r e q u i r e -m e n t o f 2 ½ p e r c e n t o f r e c o v e r a b l e r e s e r v e sby June 1 , 1986, under Depar tment of in te r ior( D O I ) r e g u l a t i o n s . F a i l u r e t o m e e t t h i s r e -q u i r e m e n t c o u l d r e s u l t i n c a n c e l l a t i o n o f t h el e a s e . H o w e v e r , t h e d i l i g e n c e p e r i o d m a y b eextended for up to 5 years to June 1, 1991, ifcer ta in condi t ions are met (see ch . 9) .

The product ion es t imates for these two keyy e a r s a r e b a s e d o n r e s o u r c e p o t e n t i a l a n do t h e r f a c t o r s t h a t w i l l a f f e c t o u t p u t , e . g . ,1) the lessees’ plans , f inancial capabi l i ty , andmining exper ience; 2) geologica l condi t ions ont h e l e a s e : 3 ) m i n i n g a n d r e c l a m a t i o n c o n d i -t ions on the lease ; 4) poss ib le envi ronmenta lp e r m i t r e s t r i c t i o n s ; 5 ) a v a i l a b i l i t y o f t r a n s -por ta t ion; 6) soc ioeconomic impacts and l imi-ta t ions ; and 7) potent ia l markets and demandfor Western coal .

Mining p lans are an excel lent source of de-ta i led informat ion for analyz ing potent ia l pro-d u c t i o n a n d a s s e s s i n g s p e c i f i c p r o b l e m s c o n -c e r n i n g t h e d e v e l o p m e n t o f F e d e r a l c o a lleases , The submiss ion of a mining and rec la-mation plan to the U.S. Office of Surface Min-i n g ( O S M ) a n d t h e U . S . G e o l o g i c a l S u r v e y(USGS)* is a necessary s tep in the process ofm i n e d e v e l o p m e n t a n d c o a l p r o d u c t i o n , A sthe first step in its analysis, OTA has groupedl e a s e s i n t h r e e c a t e g o r i e s : 1 ) t h o s e w i t happroved mine plans; 2) those with m i n eplans submitted and pending approval; a n d

*Both surface and underground mines must submit mineplans to thc Office of Surface Mining,

113


3) those with no submitted mine plan, whichare referred to as “undeveloped leases” i nth is repor t .

O T A e x a m i n e d e a c h m i n e p l a n t o d e t e r -mine: 1) major geologica l , mining, and rec la-m a t i o n c o n d i t i o n s a s s o c i a t e d w i t h t h e o p e r a -t ion; 2) the lessee’s mine design capaci ty andprojec ted annual product ion over the next 10years ; and 3) l ike l ihood of the mine’s produc-t i o n m e e t i n g d i l i g e n c e r e q u i r e m e n t s , M i n ed e s i g n c a p a c i t y i s t h e m a x i m u m a n n u a l p r o -duct ion of coal that a l l fac i l i t ies located a t amine can suppor t .

O T A a n a l y z e d u n d e v e l o p e d l e a s e s , ( t h o s ew i t h o u t m i n e p l a n s ) d i f f e r e n t l y . T h e s e l e a s e sw e r e g r o u p e d i n b l o c k s o f a d j o i n i n g l e a s e sheld by the same lessee , Based on geologica la n d t e c h n i c a l c h a r a c t e r i s t i c s o f t h e b l o c k s ,e a c h l e a s e b l o c k w a s a s s i g n e d f a v o r a b l e , u n -certain, or unfavorable d e v e l o p m e n t p o t e n -tial. These assignments were made in part bycompar ing the reserves , coal qual i ty , and them i n i n g a n d r e c l a m a t i o n c o n d i t i o n s o f u n d e -veloped leases wi th s imi lar mines in the area ,L e a s e s t h a t h a d q u e s t i o n a b l e d e v e l o p m e n tp o t e n t i a l b a s e d o n t h e c r i t e r i a w e r e f u r t h e re v a l u a t e d f o r t h e i r p o t e n t i a l t o b e i n t e g r a t e dinto an adjoining mine or to be combined witho t h e r u n d e v e l o p e d r e s e r v e s .

T h o s e l e a s e s w i t h f a v o r a b l e o r u n c e r t a i nd e v e l o p m e n t p o t e n t i a l w e r e a n a l y z e d b l o c kby block to assess the factors that could affectt h e i r r a t e a n d l e v e l o f d e v e l o p m e n t . F a c t o r se x a m i n e d i n c l u d e d c o a l m a r k e t s a n d d e m a n d .Product ion es t imates were then developed foreach lease block.

A more de ta i led descr ip t ion of the method-o l o g y f o r e v a l u a t i n g d e v e l o p m e n t p o t e n t i a land es t imat ing product ion i s g iven in chapter2.

Summary of Findings

As of late 1980, there were 502 Federalcoal leases in the six Western States of Col-o r a d o , M o n t a n a , N e w M e x i c o , N o r t h D a k o t a ,

Utah, and Wyoming. * These 502 leases, 89percent of the 565 existing Federal coall e a s e s , c o n t a i n 1 6 . 3 b i l l i o n t o n s o f r e c o v e r -able reserves , over 98 percent of the to ta l of1 6 . 5 b i l l i o n t o n s o f F e d e r a l c o a l c u r r e n t l yunder lease ; they account for over 99) percentof Federa l coal product ion.**

T h e 5 0 2 F e d e r a l c o a l l e a s e s i n t h e s e s i xSta tes are grouped as fo l lows:***

1.

2 .

3 .

182 leases with 7.3 billion tons of recov-e r a b l e reserves (# percent of the to ta lleased reserves) are in a p p r o v e d m i n eplans.117 leases with 2.5 billion tons of recov-erable reserves (15 percent) are in p e n d -ing mine plans. ****203 leases with 6.4 billion tons of recov-e r a b l e reserves (39 percent) are not inm i n e p l a n s . ( T h e s e l e a s e s , p l u s f i v eleases in pending mine plans in Wyomingare called undeveloped leases. )

Of these 208 undeveloped leases ( 2 0 3leases with no mine plans and the five Wyo-ming leases in pending mine p lans) , 80 leasesconta in ing 4 .1 b i l l ion tons of recoverable re -serves have favorable prospects for develop-

*The leases issued in f;t~rlv 1981 under the new Federal coalma nagemen I program are not included in I }1 is I 01 a I and werenot considered in this study. See also p. 164 of this chapter, fora discussion of the 46 Federa ] leases i n Oklahoma.

* *C(ml from h’df;ral coiil leases is referred 10 [Is Feder;]lcoal. A mine that includes a F’edera 1 lease is G) ]led a Federalmine. Sornel imes, for the sake of efficiency of recoverv or econ-omy of opera t ions, in Iervening Sla [e or private coal is minedwith Federal lease(s) in [he same m inc. This practice is I he rulein southern Wyoming and North [)ak{)ta, for example. “1’hus,many Federal mines produce Ix)lh F’edera I and non-h’ederalcoal. A mine which (:[)n la ins no Federal C(NII is called a non-Federal mine, Totai C(M1 production” in a State or regi(m is thusthe sum of: 1 ) Federal C(MI production from Federal mines plus2) non-Federal coal production from Federal mines, plus 3) non-Federal coal production from n(m-Federal mines.

** *Five small leases, isolated from principal c(ml-producingregions, 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 areundeveloped leases with lit tle likelihood of heing devel(~ped.one is a pr(xiuring lease. ‘1’hese leases do not appear in thetables in this chapter,

****Five leases in pending mine plans in Wyoming are in-rluded in this total. Because of the preliminary nature of themine 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 major i ty of these reservesa r e c o n c e n t r a t e d i n t h e W y o m i n g p o r t i o n o fthe Powder River basin (3.2 billion tons of sur-f a c e - m i n a b l e r e s e r v e s ) a n d i n t h e U i n t a r e -g ion of Utah (0 .4 b i l l ion tons of undergroundreserves) . In a lmost a l l cases , the lessees areact ively developing these leases .

A n o t h e r 6 5 l e a s e s c o n t a i n i n g 2 . 3 b i l l i o ntons of recoverable reserves have u n c e r t a i nprospects for development by 1991. The largemajority of these reserves (about 90 percent]are about evenly d iv ided among the Kaiparo-w i t s P l a t e a u c o a l f i e l d o f s o u t h w e s t e r n U t a h ,t h e G r e e n R i v e r r e g i o n o f C o l o r a d o a n d t h eWyoming por t ion of the Powder River bas in .D e v e l o p m e n t d e p e n d s o n f a c t o r s s u c h a sp a c e a n d s c a l e o f c o n s t r u c t i o n o f a s s o c i a t e dp o w e r p l a n t s o r s y n f u e l p r o j e c t s , d e v e l o p m e n to f i n s i t u g a s i f i c a t i o n , a v a i l a b i l i t y o f a d d i -t i o n a l F e d e r a l r e s e r v e s f r o m p e n d i n g p r e f -e r e n c e r i g h t l e a s i n g a p p l i c a t i o n s ( P R L A s ] o rf r o m n e w l e a s e s a l e s , c o n s t r u c t i o n o f t r a n s -p o r t a t i o n s y s t e m s a n d l e s s e e d e v e l o p m e n tp r i o r i t i e s .

F i n a l l y , 6 3 l e a s e s w i t h a p p r o x i m a t e l y 0 . 5b i l l i o n t o n s o f r e c o v e r a b l e r e s e r v e s a r e u n -likely to be developed. Most of these leaseslack sufficient minable reserves of market-a b l e q u a l i t y t o b e d e v e l o p e d a s n e w m i n e s .M a n y a l s o h a v e d i f f i c u l t m i n i n g c o n d i t i o n st h a t w o u l d m a k e t h e m e x p e n s i v e t o d e v e l o p ,a n d s o m e a r e l o c a t e d o u t s i d e a c t i v e m i n i n ga r e a s a n d l a c k a d e q u a t e t r a n s p o r t a t i o n . B e -cause they are unl ikely to be developed, anyproduct ion i s unl ike ly f rom these leases .

P r o d u c t i o n f r o m e x i s t i n g F e d e r a l c o a lleases i s l ikely to increase substant ia l ly overthe next 10 years , P lanned product ion capac-i ty for 1986 for Federa l mines i s 400 mi l l iontons per year; for 1991, over 535 million tonsper year (see fig, 24). OTA estimates that pro-d u c t i o n f r o m F e d e r a l m i n e s c o u l d r a n g e b e -t w e e n 4 1 0 m i l l i o n a n d 5 0 0 m i l l i o n t o n s p e ryear in 1991 depending on marke ts , synfue lsd e v e l o p m e n t , a n d r a i l c o n s t r u c t i o n . A c c o r d -ing to the plans of lessees, about 65 percent of1 9 9 1 u p p e r l i m i t p r o j e c t e d p r o d u c t i o n ( 3 2 5m i l l i o n t o n s ) i s e x p e c t e d t o b e m i n e d f r o mF e d e r a l m i n e s w i t h c u r r e n t l y a p p r o v e d m i n e

Figure 24.— Potential Production From and PlannedCapacity of Federal Mines Summed Over the

Six Major Federal Coal Statesa

600Likely 1990 demand range for all coal from thesix 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 fromFederal mines in currently approved mine plansonly

B Lessees’ planned annual production fromFederal mines in currently approved and pendingmine plans

C The sum of E?, above, plus estimates of potentialproduction from presently undeveloped Federal leases

aWyoming, Montana, Colorado, Utah, New Mexico, and North DakotabPlanned 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 verystrong market for coal) In many cases (e g currently approved mines In thePowder 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 fallshort of using planned capacity to the full Some mines, particularly newermines 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 1991were used in deriving fig. 24, above, not the higher numbers for planned max-imum capaci t ies in the post 1991 per iod For most Federa l mines in theSouthern Rockies the planned productions for 1986 and 1991 are close to theplanned capacities for those years

Explanation of rangesC. 92 million ton per year range in 199165 mty = Dominant uncertainty iS the development of markets for the coal22 mty Dominant uncertainty IS the construction of two railroads one to the

Kaiparowits Plateau in Utah (14 mty) and one to the Star Lake Bistiarea of New Mexico (8 mty)

5 mty Dominant uncertainty IS the schedule of synfuels developmentD: 22 million ton per year range in 1991

D o m i n a n t u n c e r t a i n t y IS the construct ion of the two rai l roads ment ionedabove under C


plans. About 14 percent would come fromF e d e r a l mines wi th cur ren t ly pending mineplans (69 million tons). The remaining 22 per-c e n t ( 1 0 9 m i l l i o n t o n s ) i s p r o j e c t e d t o c o m ef r o m p r e s e n t l y u n d e v e l o p e d l e a s e s . A c t u a l


p r o d u c t i o n in 1991 could fa l l be low th is Dur ing the 1990 ' s , demand for coa l in gen-r a n g e , h o w e v e r , b e c a u s e o f c o m p e t i t i o n w i t h e r a l a n d W e s t e r n a n d F e d e r a l c o a l i n p a r t i c -n o n - F e d e r a l m i n e s a n d n e w F e d e r a l l e a s e s i n ular might grow rapid ly , par t icular ly i f coal -t h e W e s t a n d f r o m o t h e r c o a l - p r o d u c i n g r e - b a s e d s y n f u e l s a n d e x p o r t s t o f o r e i g n c o u n -gions of the count ry and because overa l l de- t r i e s b e c o m e i m p o r t a n t .mand for coa l may not grow suf f ic ien t ly dur-i n g t h e n e x t d e c a d e t o s u p p o r t t h i s l e v e l o fproduct ion f rom Federa l mines .

Development Potential and Production Prospects ofFederal Coal Leases in Colorado, New Mexico, and Utah

Overview

Colorado, New Mexico, and Utah comprisewhat is referred to in this report as the South-ern Rocky Mounta in reg ion . * This three-Sta tea r e a e m b r a c e s f i v e m a j o r W e s t e r n c o a l - p r o -d u c i n g r e g i o n s — t h e U i n t a r e g i o n , t h e S a nJuan River region, the Denver-Raton Mesa re-g i o n , S o u t h w e s t e r n U t a h , a n d t h e C o l o r a d opor t ion of the Green River-Hams Fork region(see f ig , 25) . The 360 Federal coal leases int h e s e S t a t e s c o v e r o v e r 4 5 1 , 0 0 0 a c r e s a n dc o n t a i n o v e r 5 . 9 b i l l i o n t o n s o f r e c o v e r a b l ec o a l r e s e r v e s ( s e e t a b l e 3 4 ) , T h e s e S t a t e sh a v e 6 4 p e r c e n t o f t h e t o t a l F e d e r a l l e a s e s ,o v e r 5 5 p e r c e n t o f t h e a c r e a g e u n d e r l e a s e ,a n d o v e r 3 5 p e r c e n t o f t h e r e s e r v e s u n d e rlease . Roughly one- th i rd of the leases in theSouthern Rockies a re in approved mine p lans ,another th i rd are in proposed mine p lans , andt h e r e m a i n i n g t h i r d a r e u n d e v e l o p e d . T o t a lproduct ion f rom Federa l coal reserves in Col-orado, New Mexico, and Utah was 20 mi l l iontons in 1979 or about 45 percent of the to ta l

—*’I’he Southern Rockv Mounltiin and the Northern Great

Plains regions-as used in this report-should not be confusedwith I he Northern Grca t Plains and Rocky Mountain coal prov-in(x;s. The Rocky hlountain coal province is H geologic andphysit)graphic designiition that includes rxmlfields west of them)nt inental (iivide and the Denver basin and Ra ton hfesa coalregions of (;olorado and New Mexico. The Rocky hlountain coalprovince runs from the Big Horn basin of northwestern Wy[)-m ing to coalficlds in southern New Mex ice. The Great Plainscoal province includes the Powder River basin and Fort Unionregion of Wyoming, hlontana, and North Dakota. Geologic prov-ince designi+ tions are made on the basis of the geologic cha rac-teristi(’s and age of the real deposits. (Arizona, which is alsopart of the R(mky N!ounti+in C(MI provinre, hi)s l i t t le Federal(’l)al Ii)ll(l illl(l no ~EXICri]l (X)al leases. )

Figure 25.–Coal Regions in the Southern RockyMountain States

Green River

gion

su

region


production of 45 million tons in the threeS t a t e s . I n 1 9 8 0 , p r o d u c t i o n f r o m F e d e r a lr e s e r v e s w a s 2 4 . 4 m i l l i o n t o n s o u t o f t o t a lp r o d u c t i o n i n t h e S o u t h e r n R o c k y M o u n t a i na r e a o f o v e r 4 9 m i l l i o n t o n s . T h e s e t h r e eS t a t e s c o n t r i b u t e d a b o u t 3 3 p e r c e n t o f t h et o t a l p r o d u c t i o n f r o m a l l F e d e r a l l e a s e s i n1979 and 35 percent of the 1980 production.

Summary of Production Potential andPlanned Capacity

Production f r o m m i n e s w i t h e x i s t i n gF e d e r a l l e a s e s i n t h e S o u t h e r n R o c k y M o u n -

—— —

Ch. 6—Development Potential and ProductIon Prospects of Federal Coal Leases ● 117

Table 34.— Federal Coal Leases in Colorado,New Mexico, and Utah

Total Totalnumber of recoverable

Total plans or Total reservesnumber of lease Federal (millions

State/region leases blocks acres of tons)

Colorado— .

Green River 57 34 53,254 1,363Uinta 63 27 69,793 803San Juan ., 1 1 160 1,6Denver-Raton Mesa 6 4 3,686 66

T o t a l 127 6 6 - 126,893 2,234

New MexicoSan Juan . . 26 12 44,560 447Denver-Raton Mesa 3 3 200 0.5

Total . . . . . 29 15 44,760 447

UtahUinta, . . . . . . 108 42 128,930 1,503Southwestern 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 Inde-pendent rounding


ta in area is expected to r i se substant ia l ly i nthe next decade as existing and plannedmines reach full operation and new mines areopened on undeveloped leases. By 1986, ac-cording to current mine plan schedules, pro-duction from Federal mines could reach over76 million tons- more than double 1979 pro-duction. By 1991, depending on the rate atwhich Federal leases are developed, produc-tion from Federal mines could total between110 million and 146 million tons— potentiallydoubling the 1986 output and at least triplingthe 1979 level. Figure 26 shows projected in-creases in production from Federal leases inColorado, New Mexico, and Utah. The per-centage of total regional production comingfrom Federal leases will also increase signif-icantly from about 44 percent in 1980 to over60 percent by 1991.

Most of the projected increases in produc-tion will come from new mines that will notachieve their full design capacity until themid-l990’s. The estimated 1991 productionrange of 110 million to 146 million tons is lessthan the total maximum annual capacity ofover 200 million tons per year that could besupported by mines on existing Federalleases in the mid-l990”s, In the late 1990’s

Figure 26.— Potential Production Capacity ofAll Mines With Federal Leases in Colorado,

New Mexico, and UtahMillion tonsper year Colorado

40 —

30 “A

20 —

I 1 1 I i 1 1 1 1 1 1 I 11979 1986 1991

Million tonsper year New Mexico

I30 —

B20 —

A

I 1 I I I I I I 1 1 I1979 1986 1991

Million tonsper year Utah

B

A

I I 1 1 1 I i I I 1 1 1 11979 1986 1991

A. Lessees’ planned annual production capacity for Federal minesin currently approved mine plans only

B. The sum of A, above, plus estimates of production capacity forFederal mines in pending mine plans and for presentlyundeveloped Federal leases


however, as many of the mines that are nowoperating exhaust their reserves, the totalcapacity supported by existing leases willbegin to decline slowly.

The maximum annual capacity of the 35mines with 113 Federal leases that currentlyhave approved mine plans is about 74 milliontons per year at full operation, Proposed mine


plans have been submitted for 25 new mineswith 108 Federal leases that would add over71 million tons of annual capacity. (When thecapacity of existing mines is referred to, itmeans capacity at full-scale operation, notcurrent installed capacity. ) Nearly half of theexisting and planned capacity (about 64million tons per year) is in underground minesin the Uinta region of Utah and Colorado.About 40 percent of the capacity (nearly 30million tons) in pending mine plans is fromproposed mines in Southwestern Utah.

Production in the Southern Rockies willgenerally be less than capacity until the mid-1990’s, however, overcapacity is not ex-pected to be as significant in this region as inthe Northern Great Plains. Many of the largermines in the Southern Rockies have opened inthe past 4 years and are still under construc-tion. These new mines will not reach full com-mercial operation for several more years.Other existing and proposed mines havescheduled production to fuel new electricpowerplants when they begin operations.Several of the mines with pending mine planswill not begin producing until after 1986 andwill reach full-scale production by the early1990’s.

Many of the 139 currently undevelopedleases could, according to OTA’s analysis,support new mines and at least 13 undevel-oped lease blocks with 27 leases are alreadyin mine plan preparation stages. By 1986, fewundeveloped leases will be producing. By1991, they could contribute between 17 mil-lion and 32 million tons of production. If all ofthe undeveloped leases with favorable or un-certain development potential go into produc-tion, they could add 34 million to 57 milliontons of new annual capacity. Most of this newcapacity (between 23 million and 45 milliontons per year) would come from mines in Utahand in the Green River region of Colorado.Besides market uncertainties, the major dif-ficulty affecting production from undevel-oped leases is construction of coal trans-portation systems in Utah and New Mexico.

Quality of Coal Under LeaseThe Southern Rocky Mountain States have

a wide variety of coal resources and miningconditions. The coal quality ranges fromlignite deposits in the Denver basin to high-grade metallurgical bituminous coals in theUinta region of Colorado and Utah and in theRaton Mesa fields of New Mexico and Col-orado. The three-State region has supportedan active coal mining industry for over a cen-tury. Mines currently in operation in theregion range from small underground minesproducing several thousand tons per year tolarge surface mines producing over 5 milliontons per year. Several of the undergroundmining operations will reach productionlevels of 4 million to 6 million tons per year bythe early 1990’s, and several new surfaceand underground mines are planned that willachieve annual production levels in excess of10 million tons per year.

Generally the active mining areas havegood quality minable coal reserves, however,they do not have the extensive shallow, verythick seams that give a cost advantage to sur-face mines in areas of the Powder Riverbasin. The higher heat content of SouthernRocky Mountain coals, however, partially off-sets the lower mining costs in the NorthernGreat Plains, especially, when coals areshipped great distances. In some fields in theSouthern Rockies, the location and quality ofthe coals make them strong competitors forcoal from other areas. In northwest Colorado,for example, minable surface reserves canreach an aggregate seam thickness of 60 ftwith overburden depths between zero and400 ft.

Underground mining conditions in the coal-fields vary, but generally, these regions arecharacterized by thick minable seams of 5 to12 ft. Some underground seams are 25 f tthick or more, however, current mining meth-ods have limited recovery to only 12 to 14 ft ofcoal. Newer techniques, such as multiple-liftlongwall, promise improvements in recoveryrates; 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 min-ing conditions and seam thicknesses are oftenmore favorable than those encountered insome Eastern and Midwestern coalfields.

Most of the reserves under lease in theSouthern Rocky Mountain region are subbi-tuminous to bituminous in rank. They includehigh-quality coal reserves with heat contentsranging from 9,000 to over 14,000 Btu/lb.Most have relatively low sulfur contents of1.5 percent or less, making them suitable forcompliance quality coal. * The ash contentalso averages less than 15 percent. Somecoals in the San Juan basin of New Mexicoand the Denver basin of Colorado are an ex-ception with relatively lower Btu values, (as

*As discussed in chs. 4 and 5, one strategy of complying withClean Air Act requirements before the 1977 amendments andimplementing regulations was to blend low-sulfur “compli-ance” coals with higher sulfur local coals so that average sul-fur content would be low enough so that pollution control equip-ment costs were minimized while meeting Clean Air Act re-quirements. The 1977 changes requiring sulfur reduction forall coals removed what had been an advantage for Westerncoals.

low as 7,800 Btu/lb in the San Juan basin) andrelatively higher average ash contents of upto 29 percent at the mine. These coals arenevertheless considered marketable for theirarea because the coal can be washed to re-duce ash contents to between 16 to 17 per-cent.

Table 35 shows the rank of coal underlease in each of the major coal production re-gions in the three States and the amount of re-coverable reserves of each type by mine planstatus. Federal lease reserves in approvedmine plans contain about 1.2 billion tons of bi-tuminous coal and 0.3 billion tons of subbi-tuminous coal. There are about 1.4 billiontons of bituminous reserves and about 0.5 bil-lion tons of subbituminous reserves on leasesin pending mine plans. Undeveloped Federallease reserves include over 2 billion tons ofbituminous coal and nearly 0.3 billion tons ofsubbituminous coal. Only about 49 milliontons of leased reserves in the three States areclassified as lignite.

Table 35.—Rank of Coal Under Lease in the Southern Rocky Mountain RegionReserves and Mine Plan Status (all reserves in millions of tons)

Approved mine plans - Pending mine plans Leases without mine plans— —

Sub- Sub. - Sub-Bituminous bituminous Bituminous bituminous Bituminous bituminous Lignite

State/regionLignite

HvAb HvBb HvCb SbA Sbc HvAb HvBb HvCb SbA SbC HvAb HvBb HvCb SbA SbB SbC A

ColoradoGreen River 146 160 29 185 487 43 88 18Uinta 63 164 8 92 165 110S a n J u a n

1 31 7 1302

Denver-Raton Mesa 17 01 49

T o t a l 63 166 154 -160 92 165 139 18 217 494 43 218 18 49

New MexicoSan Juan 34 135 38 56 89 94 1Denver-Raton Mesa 0.1 04

T o t a l 34 1-35 38 – 56 89 01 94 04 1

UtahUinta 2 676 114 16 141 108S o u t h w e s t e r n U t a h

83 359 0.3671 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 dataColumn 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

.


Production and Consumption of Coal FromColorado, New Mexico, and Utah

The Rocky Mountain region coals servemany markets. Most of the coal produced inthe three States is consumed in the region orin the west coast markets (see fig. 20, ch. 5.)Under existing long-term contracts, however,a significant amount is shipped to the Southand Midwest. Coal from Utah is shipped toMississippi utilities, and coal from Coloradois burned by Indiana utilities. Coals from Col-orado and Utah have been sold under con-tract for export to consumers in Korea andJapan.

Colorado, New Mexico, and Utah also havedeposits of metallurgical coal. Although someof this coal is not of as premium a quality assome metallurgical coals in the East, theseWestern reserves have supplied the Westernsteel industry for decades and also showsome promise for expanding export markets.Over the next decade, production of metal-lurgical coal in the Rocky Mountain States isexpected to continue at current annual levelsof about 3 million tons a year because of con-ditions in the domestic steel industry.

In the past decade, Colorado, Utah, andNew Mexico have seen an increase in coalproduction and planned mining activities,Many Federal leases have recently gone intoproduction and new mine plans have beenproposed for others. Table 36 shows the in-creases in total and Federal production inthese States for selected years since 1972,Federal coal production in these States has

risen from 4.6 million tons in 1972 to over 24million tons in 1980, while total annual pro-duction for the region has risen from 19.4million tons in 1972 to approximately 49 mil-lion tons in 1980. Federal leases thus havecontributed an even larger share of total pro-duction, growing from about 25 percent in1972 to approximately 50 percent in 1980.The Federal share of total regional produc-tion is expected to increase substantially overthe next decade. Coal producers in thesethree States have shared in the generally in-creased level of coal development activities inthe West and hold the optimistic expectationthat the coal production from these Stateswill be competitive and capture its share ofthe expanding market.

In 1979, Federal mines in the SouthernRockies produced 34.7 million tons of coal,with about 20 million tons mined from Fed-eral reserves. If all existing and proposedmines on Federal leases are developed andproduce at their expected rates, the 1986 pro-duction from mines with Federal leases couldmore than double the 1979 levels (see table37). By 1991, production from Federal minescould be more than three times the 1979 level.The increases in production would be mostdramatic in Utah, rising from 10 million tonsin 1979 to as much as 74 million tons in 1991.In general, the OTA potential productionfrom Federal mines compares favorably withthe State task force production estimates andwith the Department of Energy’s (DOE) final1985 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 F e d e r a l T o t a l F e d e r a l T o t a l F e d e r a l T o t a l F e d e r a l T o t a l F e d e r a l T o t a 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

U t a h . 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 1980U S Geological Survey, Federal and Indian Lands Coal, Phosphate, Potash, Sodiurn, and Other Minerals Production, Royalty Income and Related StatisticsCalendar year 1960, June 1981Bureau 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


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 leasesProduct ion in approved in pending without in approved

State/reglonin pending without

in 1979 mine plansa mine plansa mine plansb Total mine plansa mine plansa mine plansb Total

ColoradoGreen R iver . . .Uinta . . . . . .San Juan .. . . . .Denver-RatonMesa . . . . . . . . .

Total ., ., ... . .New MexicoS a n J u a nDenver-RatonMesa ., . .

11.24.70.08

19.05.60.07

1.32.80

0.600

20.9 20.08.4 5.80.07 0

1.8 6.4 28.17.4 1.3 14.50 0 0

0 0.5 0.5

9.3 8.2 43.1

0 0 0 0 016,0 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 0Total . . . . . ., 8.4 10.0 6.6 0.2 16.8 10.5 7.5-10.5 1.7-8.0 19.7 -29.0

UtahUinta . . . . . . . . . 10.4 24 5.6 0 29.6 29.0 11.3 7.0-8.6 47.3-48.9Southwestern

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 47.3-74.3Grand 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


described in chapter 5 of this report (seetable 31).

In 1986, production from all mines on Fed-eral leases, including currently undevelopedleases, could reach 76.4 million tons withabout 29 million tons coming from Coloradomines, 17 million tons from New Mexico, andover 29 million tons from Utah. Estimated pro-duction from mines on Federal leases in theColorado portion of the Green River-HamsFork region is 20.9 million tons in 1986 withabout 15.7 million tons from surface mines.Total production from Federal mines in theUinta region in 1986 is expected to be about36 million tons (8.4 million tons in Coloradoand 29.6 million tons in Utah). Almost all ofthis production will come from undergroundmines. Production from mines with Federalleases in the San Juan region is estimated toreach 16.8 million tons in 1986 with most of itcoming from large surface mines in NewMexico,

For both Colorado and New Mexico, theDOE 1985 production goals are higher thanthe potential production from Federal leases,

however, the difference is in large part offsetby production from existing and planned non-Federal mines and from new mines on Fed-eral PRLAs. In Utah, OTA’s potential produc-tion from Federal mines of 30 million tonsmatches the DOE medium production goal,but both estimates are higher than the esti-mate of 15 million to 18 million tons used bythe OTA Utah task force.

For 1991, production from mines with Fed-eral leases is projected to increase to be-tween 110 million and 146 million tons de-pending on the rate of mine construction. Fed-eral mines in Colorado would account for 43million tons, New Mexico mines for up to 30million tons and production from Utah mineswould add between 47 million to 74 milliontons. About 28 million tons could come fromFederal mines in the Green River region. Be-tween 59 million and 61 million tons could beproduced from Federal mines in the Uinta re-gion (14.5 million tons in Colorado and 44.8million to 46.4 million tons in Utah). Between19.7 million and 29 million tons is expected tobe produced from Federal mines in the San


Juan region in New Mexico. Production fromFederal leases in Southwestern Utah is un-certain and ranges from no production at allto as high as 25 million tons by 1991.

The 1990 DOE production goals for Col-orado range from a low of 28 million tons to ahigh of 43 million tons; 35 million tons is themidlevel goal. (These goals were reducedslightly from the preliminary DOE goals pub-lished in August 1980. ) Potential productionof 37 million to 43 million tons from Federalmines and undeveloped leases could meet orexceed the DOE goals and the State task force1991 minimum production estimate of 32 mil-lion to 38 million tons. Even though non-Fed-eral mines are expected to contribute asmaller relative share of State production bythe late 1980’s, the large production capacityof existing Federal leases is apparent. How-ever, at least a portion of this capacity couldbe used to replace existing mines that willshut down in the mid-1990’s. Potential Fed-eral mine production of 47 million to 74million tons in Utah in 1991 could also exceedthe DOE high production goal of 63 milliontons and the State task force estimate of 30million tons. However, when the likelihood oflittle, if any, production from SouthwesternUtah is considered, the lower estimate of 47million tons in 1991 is comparable to the DOEmedium goal of 49 million tons. Both the DOE1990 New Mexico production goals (56 mil-lion to 67 million tons) and the OTA task force1991 maximum production estimate of 72 mil-lion tons are substantially higher than Fed-eral mine production of 20 million to 29 mil-lion tons. When planned production fromIndian and non-Federal mines is added toFederal mine production, the total is around67 million tons, the DOE goal, but still lessthan the OTA task force estimate. Thus,while there is a substantial variety in esti-mates of coal demand and production for theSouthern Rocky Mountain States, in mostcases, OTA’s estimated potential productionfrom Federal mines falls within the ranges ofproduction that would be absorbed under thevarious forecasts.

By the early 1990’s, several currently oper-ating mines on Federal leases will depletetheir existing lease reserves. Replacementcapacity for at least three of these mines willcome from new mines on other existing Fed-eral leases. Replacement capacity amounts tobetween 5 million and 10 million tons of totalnew annual production capacity.

OTA’s production estimates include someuncertainties that are reflected as ranges ofpotential production and capacity. If allleases meet current mine plan schedules anddemand for coal from these States increasesas expected, production from Federal minescould reach 110 million tons in 1991. Produc-tion of an additional 36 million tons of coal in1991 is possible, but subject to large uncer-tainties as a result of factors that could delayor prevent development. About 10 milliontons of estimated 1991 output comes from ex-isting or proposed captive mines that may notreach planned full production levels becauseof changes in internal coal requirements orproduction schedules. Between 4 million and8 million tons of 1991 production could beused in proposed synthetic fuel projects.However, according to the lessees, delays inthese projects are not expected to affectplanned production in 1991 since the coalproduced could be used to meet existingcontracts.

The greatest uncertainty involves the esti-mated 25 million tons of production, and 36million to 45 million tons of annual capacityfrom mines in Southwestern Utah. Except forthe Alton Mine, none of the existing leasesthere have even tentative commitments forpotential production. Furthermore, the Altonand Kaiparowits Plateau fields are not con-nected to existing transportation networks. Aslurry system and rail line have been pro-posed to link these fields to potential markets,primarily in Nevada and California. How-ever, according to most estimates, at least 30million tons of annual coal production wouldbe needed to support construction of theneeded transportation system. OTA’s anal-

Ch. 6—Development Potential and Production Prospects of Federal Coal Leases “ 123

ysis indicates that Federal leases on the Kai-parowits Plateau could support that level ofproduction, however, it is unlikely that thelessees would begin producing without assur-ances that the transportation system wouldbe built. Mine-mouth powerplants that wereonce proposed for Southern Utah, have beenabandoned because of high capital costs andwater availability and air pollution problems.The Alton Mine and slurry project is opposedby environmental groups because of potentialimpacts on Bryce Canyon and Zion NationalParks and on regional water supplies and airquality.

The rate of development for about 10 mil-lion tons of capacity in the central San Juanbasin of New Mexico is also in question be-cause of delays in the original constructionschedule and final right-of-way approvals forthe proposed Star Lake Railroad. In addition,two proposed mines there are linked to pend-ing PRLAs and sustaining full production ca-pacity depends on the availability of PRLAreserves. Several of the lessees could, how-ever, begin small-scale production on existingleases before 1986 in order to meet diligencerequirements and could delay expansion untilthe rail line is completed. Thus, delays are notexpected to affect lease development exceptin the rate of construction and production.

The factors affecting development and pro-duction from Federal leases in Colorado, NewMexico, and Utah are discussed in more de-tail in the State appendixes to this report andin the OTA task force reports.

Development Status of Federal CoalLeases in the Southern Rocky

Mountain Region

Over 60 percent of the 360 coal leases inthe Southern Rocky Mountain region werecovered by approved or pending mine plansas of September 30, 1980. About 30 percent,113 leases, are part of 35 operating mineswith approved mining plans. During fiscalyear 1980, coal was actually produced from57 of these leases in approved mine plans.(The number of leases in approved mine plans

that are actively being mined varies ac-cording to the lessees’ production schedulesand mine configurations. ) Another 108 leasesare included in 25 proposed new mines forwhich mine plans have been submitted toDOI. The remaining 139 leases, 38 percent ofthe leases in the region, have not yet reachedthe mine plan stage of development. The 139undeveloped leases are divided into 77 differ-ent blocks of contiguous leases in commonownership. (Table 38 summarizes the acre-age and reserves under lease by mine planstatus. )

While many existing leases are in histor-ically active mining areas, some are locatedin areas that have not been mined extensive-ly. Two such areas— the southern San Juanbasin and Southwestern Utah—are largelyrural and have supported little past coal min-ing activity. Proposed large-scale coal devel-opment in these two fields with substantiallyuntapped coal resources raises potentiallydifficult conflicts with other resource valuesand land uses. Several of the active miningareas face major expansions of coal mining atthe same time that they are already beingaffected by development of other energysources—oil shale, oil and gas, uranium, andtar sands. If all these development activitiesproceed, they could change the predominant-ly rural character and economic base of theseregions which primarily have depended onmining, agricultural, recreational, and nonin-dustrial activities.

Federal coal production in the SouthernRocky Mountain region has more than quad-rupled in the past decade and it will continueto grow during the 1980’s as new mines openand existing mines expand capacity. By 1991according to OTA’s analysis, total productionfrom mines operating on existing Federalleases in the region could reach as much as146 million tons. Total mine capacity couldeventually reach more than 216 million tonsper year in the mid-1990’s if all plannedmines and leases with favorable and uncer-tain development prospects go into pro-duction.


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 Numberable

reserves Number Number reserves Number Number reservesof of (mi l l ions o f of (mi l l ions o f of (millions

leases plans Acres of tons) leases plans Acres of tons) leases blocks Acres of tons)

State/BLM coal regionColoradoGreen River . . . . . . . . . . 31 10 25,687 519 3a 3 3,150 a 28 a 23 21 24,417 816Uinta . . . . . . . . . . . . . 22b

8 1 6 , 2 3 9b 2 0 3b 18c 8 34,704c 427 C 23 11 18,850San Juan . . . . . . . . . . . . 1

1731 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 MexicoSan Juan . . . . . . . . . . . 9d

2 18,828 169d 9 3 21,098 183 8 7 4,634 95Denver-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 -

UtahUinta . . . . . . . . . . . . . . . 50 14 55,540 792 14e

8 25,711 e 264 e 44 20 47,679 447Southwestern 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 roundingaLease 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 countingbApproved 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 dou-

ble 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 Includ-

ed in a minor modification to the San Juan surface mine.eTotal 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


Leases With Approved Mine Plans

There are 113 leases in 35 active mineswith approved mine plans in the SouthernRocky Mountain region. They cover a total ofover 116,000 acres of Federal land and con-tain more than 1.6 billion tons of recoverableFederal coal reserves. Nine mines are sur-face operations (seven in Colorado, two inNew Mexico) and 26 are underground mines(12 in Colorado, 14 in Utah). Over the nextdecade, two of the active surface mine opera-tions are planning to shift to undergroundoperations to recover deeper reserves (one inColorado, one in New Mexico). Table 39 sum-marizes the acreage and reserves for mineswith Federal leases in Colorado, New Mexico,and Utah. Table 40 shows the total capacityand estimated 1979, 1986 and 1991 produc-

tion for mines with approved mine plans onFederal leases.

The 26 underground mines range in sizefrom two small mines producing less than100,000 tons per year (one in Colorado, one inUtah) to large mine complexes producing over1 million tons annually. Three of the existingunderground mines propose to expand an-nual production capacity to 5 million tons peryear or more by 1986. The nine active surfacemines on Federal leases range in size fromone small operation producing just over100,000 tons annually to several large sur-face mines producing over 5 million tons peryear. Most of the surface mines produce be-tween 1 million and 3 million tons annually.Surface mining activity on existing leases iscurrently limited to the Green River region of


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)

TotalTotal Federal Total Total mine plan Total Federal lease

Number Number mine mine Federal reserves reservesof of mine plan plan lease Under- Sur- Under- Sur-

State/region leases plans acres acres acres ground face Total ground face Total

ColoradoGreen River . . . . . . . . 31 10 40,300 25,687 25,687 113 303 416 199 320 519Uinta 22 8 24,104a 16,239a 16,239a 208 0 208 203 0 203San Juan 1 1 1 160 160 160 0.7 0 0.7 1.6 0 1.6Denver-Raton Mesa — — — — — — — — — — —

Total . . . . . . . . . . . . 54 19 64,564 42,086 42,086 322 303 625 404 320 724

New MexicoSan Juan . . . . . . . . . . 9 2 13,622b 14,972b 18,828 0 194 194 0 169 169Denver-Raton Mesa . — — — — — — — — — — —

Total. . . . . . . . . . . . 9 2 13,622 14,972 18,828 0 194 194 0 169 169

UtahUinta . . . . . . . . . . . 50 14 85,260C 54,523C 55,540C 630 0 630 792C O 792c

Southwestern Utah. . — — — — — — — — — — —

Total . . . . . . . . 50 14 85,260 54,523 55,540 630 0 630 792 0 792aTotal 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,

1960cAll 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 basinof New Mexico, although two surface mineoperations are proposed for Federal leases inUtah.

Total capacity of the active mines withFederal leases is 74.3 million tons per year atfull production. The surface mines in Col-orado and New Mexico account for about 26million tons of annual capacity. The remain-ing 48 million tons of capacity is in under-ground mines. Many of the active mines havebeen opened within the last 5 years and willnot produce at full capacity until about 1986.

Most of the approved mining operationsinclude both Federal and non-Federal coal re-serves. Total estimated production fromthese mines in 1979 was 34.7 million tons.About 20 million tons of this production camefrom the more than 55 Federal leases in ap-proved mine plans that were actually mined.About 20 million tons of the total 1979 Fed-eral mine production came from surfacemines and 14 million tons was from under-ground mines.

By 1986, production from mines with ap-proved mine plans could total 58.7 milliontons. About 26 million tons of this will comefrom surface mines. By 1991 production fromcurrently active mines is projected to be 65.3million tons. Over the next decade at leasttwo of the mines with approved plans are ex-pected to exhaust their reserves and the op-erators will shift to proposed new mines onother Federal leases.

Colorado.—There are 19 mines with ap-proved mine plans operating on Federalleases in Colorado. The 54 leases in thesemines cover over 42,000 acres and contain anestimated 724 million tons of recoverablereserves. Seven of the approved operationsare surface mines located in the Green Riverregion of northwest Colorado. The remaining12 mines are underground mines. Three ofthe underground mines are in the Green Riverregion, eight are found in the Uinta regionand one in the San Juan River region. Thereare no active mines on Federal leases in theDenver-Raton Mesa region of Colorado.

— — ——


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 Actualof mine of annual productionplans Federal capacity from mineswith leases in of all with

Federal these proposed FederalState/basin leases plans mines leases

1986

Maximum Projectedmine production

capacity from minesof with

producing Federalmines leases

1991

Maximum Projectedmine production

capacity from minesof with

producing Federalmines 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

UtahUinta . . . . . . . . . . . . . 14 50 32.2 10.4 32.2 24.0 32.1g 29.0Southwestern 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 65.3aEmpire Energy Eagle #5 and #9 Mines exhaust existing lease reserves; possibility Of extending mine life with new lease reserves not known.bcanadian 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.gTrail 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,


At full operation, the total production ca-pacity of the active mines on Federal leases is31.6 million tons per year. These mines in-clude large surface mines producing over 3.4million tons annually, medium to large under-ground mines yielding from 200,000 to over 1million tons annually, and several small oper-ations serving local or spot markets. Severalof the underground mines are expandingtheir capacity by constructing new portalsthat will allow mining of several overlyingseams at the same time. These enlarged un-derground mines will be capable of producingover 4 million tons annually—thus matchingthe capacity of large surface mines in thesame area. By the early 1990’s, several largesurface mines in the Green River area are ex-

pected to exhaust their current mine planreserves and will have to either shut down orshift to underground recovery if additionalstrip reserves are not available. At least oneunderground mine will require additionalunleased Federal reserves to maintain theplanned level of production.

Total 1979 production from the 19 mineswith Federal leases in Colorado was morethan 16 million tons; 7.7 million tons wasmined from 39 of the Federal leases. Accord-ing to current mine plan projections, produc-tion from currently active mines on Federalleases is expected to reach 24.7 million tonsby 1986 and by 1991 their total output willrise 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 arediscussed more fully in the Coloradoappendix.

New Mexico. —The two currently operatingmines on Federal lands in New Mexico in-clude nine Federal leases with over 18,000acres and 169 million tons of Federal re-serves. Both mines are located in the SanJuan basin in northwestern New Mexico. TheMcKinley Mine, near Gallup operates on Fed-eral, Navajo and private lands; the San JuanMine near Farmington operates mostly onFederal land. The total annual productioncapacity of these two surface mines is cur-rently 10.5 million tons. The San Juan Minewill replace about 2 million tons of surfacecapacity with underground capacity as itmoves to deeper seams.

In 1979, the two mines produced a total of8.4 million tons with 5.4 million tons comingfrom Federal reserves. According to currentmine plans and information from lessees,total production will increase to 10 milliontons by 1986. Capacity and production fromthe two mines are projected to remain ataround 10 million tons per year through 1991.Production from both mines is used primarilyat powerplants in the Southwest. See theNew Mexico appendix for additional informa-tion on these mines.

Utah.—There are currently 14 active un-derground mines with Federal coal leases inthe Uinta coal region in central Utah. These14 approved mine plans include 50 leasescovering a total of more than 55,000 leasedacres and containing about 792 million tonsof recoverable coal reserves. At full opera-tion, the total capacity for these mines will be32.2 million tons per year, or roughly threetimes greater than the 1979 productionlevels.

Total coal production in Utah in 1979 was11.8 million tons. About 10.4 million tons ofthis was produced by the mines with Federalleases, with 6.9 million tons mined from Fed-eral reserves. The Utah State Geological Sur-vey estimates that up to 2 million tons of coalwere stockpiled by several Utah mines in

1979 because of low demand. This overca-pacity is expected to be short-lived. With theopening of the new Emery and IntermountainPower Project electric generating stations, in-State use will expand significantly. Spot mar-ket sales and long-term contracts for exportsto Japan and Korea are being negotiated. Ac-cording to several coal operators in the re-gion, all current excess capacity in Utah wasunder contract by early 1981.

By 1986, production from mines with ap-proved plans on Federal leases in Utah is ex-pected to rise to about 24 million tons. Two ofthe currently producing mines are scheduledto be depleted in the early 1990’s. However,this loss in capacity will be offset as neweroperations reach full production levels in thelate 1980’s. By 1991, total production fromthe currently approved mining operations isprojected to increase to about 29 million tons.A significant portion of this total is captiveproduction for steel and utility companies.See the Utah appendix for additional infor-mation on active mines on Federal leases inUtah.

Leases in Pending Mine Plans

As of September 30, 1980, 25 mine planswith 108 Federal leases were under reviewby DOI. These new mines include a total of108 Federal leases with over 177,000 acresand 1.9 billion tons of recoverable reserves.Most of the proposed mines include both Fed-eral and non-Federal coal reserves. The mineplans cover more than 221,000 acres withFederal leased acreage making up about 75percent of the total. The 25 pending mineplans vary widely in completeness and so-phistication, ranging from multivolume, tech-nically complete proposals in the final stagesof permit review, to more general “con-ceptual” descriptions of the lessee’s 1ong-range plans. Many of the conceptual mineplans were submitted in 1976-78 in responseto DOI requests for information on diligentdevelopment or for inclusion in regional coalstatements and have not been updated to in-clude information for permit approval under


the Surface Mining Control and ReclamationAct of 1977 (SMCRA). Table 41 summarizesthe acreage and reserves for these proposedmines, and table 42 shows the estimated ca-pacity and production.

The 25 pending mine plans include 4 newsurface mines (2 in New Mexico, 2 in Utah)and 21 new underground mines (11 in Col-orado, 9 in Utah, and 1 in New Mexico). Thetwo Utah surface mines also include someunderground operations. The total annualproduction capacity of these proposed minesat full operation is 71.6 million tons. About 25million tons is surface mine capacity and 47million tons is underground mine capacity.Most of these mines will not reach full capac-ity until the 1990’s. The proposed under-ground mines range in size from some withannual capacity between 100,000 and500,000 tons per year to several new, largemines capable of producing over 1 milliontons per year. Several of the largest proposedunderground mines would produce over 10

million tons annually. The proposed new sur-face mines range in size from 1.6 million tomore than 11 million tons of annual produc-tion capacity. Two of the proposed surfacemines are in areas where there is currentlyno large-scale surface coal mining activity—the Alton Field of Southwestern Utah and thecentral San Juan basin of New Mexico.

All of the proposed mines are scheduled tobegin production over the next decade. Themore technically complete and active mineplan proposals will probably receive the nec-essary permits and begin construction in thenext few years. Some of these will be produc-ing by 1986. Initiation of production fromseveral mines with inactive mine plans is lesscertain. According to mine plan estimates,about 16.9 million tons will be produced fromproposed mines with Federal leases in theSouthern Rocky Mountain States in 1986. By1991, production from proposed mines withFederal leases is expected to be between 28.1million tons and 49.1 million tons. The range

Table 41.—Summary of Mine Plan, Federal Lease Acreage and Recoverable Reserves PendingMine Plans—Colorado, New Mexico, and Utah, Sept. 30,1980 (all reserves shown in millions of tons)

State/region

ColoradoGreen River . . . . . . . .Uinta . . . . . . . . . . . . .San Juan . . . . . . . . . .Denver-Raton Mesa

Total. . . . . . . . . . . .

TotalTotal Federal Total Total mine plan Total Federal lease

Number Number mine mine Federal reserves reservesof of mine plan plan lease Under- Sur- Under- Sur-

leases plans acres acres acres ground face Total ground face Total

3 a

3 3,150a 3,150a 3,150a 3 1b 0 3 1b 2 8b 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 MexicoSan Juan . . . . . . . . . . 9 3 29,580 14,979 21,098 42 352 394 56 127 183Denver-Raton Mesa — — — — — — — — — — —

Total. . . . . . . . . . . . 9 3 29,580 14,979 21,098 42 352 394 56 127 183

UtahUinta . . . . . . . . . . . . . 14d

8 33,020 19,902 25,711 300 15 315 247 17 264Southwestern 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 1,270aExcludes 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 reservescAcreage totals include leased area in approved Bear Mine that is also Part Of proposed Mt Gunnison MinedExcludes three leases in the proposed O’Connor Mine that are also partly covered by the approved Skyline and Belina mines Acreage and re-

serves 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.


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 Projectedmine plans Federal maximum capacity production capacity production

with leases in capacity of mines from mines of mines from minesFederal these in pending producing with Federal producing with Federal

State/basin leases plans mine plans in 1986 leases in 1991 leases

ColoradoGreen River . . . . . . . . . . . . . . 3 4a 2.3 2.3 1.3 2.3 1.8Uinta . . . . . . . . . . . . . . . . . . . 8 18 11.1 8.7 2.8 11.1 7.4San Juan . . . . . . . . . . . . . . . . 0 0 0 0 0 0 0Denver-Raton Mesa . . . . . . . 0 0 0 0 0 0 0

Total . . . . . . . . . . . . . . . . . . 11 22 13.4 11.0 4.1 13.4 9.3New Mexico

San Juan . . . . . . . . . . . . . . . . 3 9 15.3 15.3 6.6 15.3 7.5-10.5Denver-Raton Mesa . . . . . . . 0 0 0 0 0 0 0

Total . . . . . . . . . . . . . . . . . . 3 9 15.3 15.3 6.6 15.3 7.5-10.5Utah

Uinta . . . . . . . . . . . . . . . . . . . 8 17b 13.1 11.9 5.6 13.1 11.3Southwestern 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 -49.1aIncludes one lease also in an approved planbIncludes 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 levelsProduct Ion and capacity columns may not add to totals because of Independent rounding

SOURCE’ Off Ice of Technology Assessment

in production reflects uncertainties about thepace and scale of planned mine construction.

At least seven of the new mines with pend-ing plans will not begin production until after1986. There are several reasons for this:1) some new mines are replacement capacityfor existing operations and will not open untilthe active mines shut down or reduce produc-tion; 2) other mines are being developedunder difficult mining conditions, and thus re-quire longer periods for construction, and3) several mines are intended to supply newpowerplants that have been delayed or de-ferred. The planned production dates showthat some operators clearly intend to openmines according to their own schedules andmarket situations rather than to acceleratedevelopment or project early starts to meet1986 diligence requirements. All of the oper-ators expect to qualify for extensions or modi-fication of the diligence requirements undercurrent guidelines,

Despite the optimism reflected in pendingmine plans, OTA’s analysis indicates thatproduction from some of these mines is uncer-tain. In several instances, the mine plans ap-pear to be inactive and the lessee has not pro-ceeded with development according to theoriginal plan schedule. Moreover, because ofthe substantial difficulties facing developersin Southwestern Utah, it is likely that the pro-posed mines there will not open in the late1980’s as originally announced, if at all.

Colorado.—Proposed mine plans for 11new mines on Federal leases in Coloradohave been filed for review by DOI. The plansinclude 21 leases with a total acreage of over37,000 acres and with estimated recoverablereserves in excess of 450 million tons. All ofthe proposed new mines are underground op-erations, All but three of the pending mineplans are in the Uinta region. The productioncapacity of the pending mine plans at full op-eration is over 13 million tons per year.


For 1986, these mines are projected to pro-duce about 4 million tons. By 1991, produc-tion is estimated to increase to around 9.3million tons. Several of the mines are expan-sions or replacements of existing capacity.Many of the pending Colorado mine planswere recently submitted or updated. Al-though markets for some mines are still un-known, at least two of the new mines havecontracts or letters of intent to supply exist-ing or planned powerplants. See the Coloradoappendix for additional information on pend-ing mine plans in Colorado.

New Mexico.— Mine plans were recentlysubmitted for three new mines on Federalleases in the San Juan basin of New Mexico.The plans include nine Federal leases cover-ing over 21,000 acres and 183 million tons ofrecoverable reserves. The proposals includetwo new large surface mines in the Star Lake-Bisti area and one underground mine thatwill produce coal for industrial use. Totalproduction capacity for these mines is 15.3million tons per year. By 1986, OTA estimatesthat production could approach 6.6 milliontons, or about 43 percent of full capacity. Theproduction estimates for 1991 are more vari-able, and range between 7.5 million and 10.5million tons depending on the rate of mineconstruction of the proposed surface mines.

Portions of two Federal leases in the pro-posed Bisti Mine are under review for ex-change for unleased Federal coal. The ex-change is not expected to delay mine con-struction. Production from the Bisti Mine willsupply the San Juan Power Plant and the as-yet-unsited New Mexico Generating Station.The Star Lake Mine is associated with pend-ing PRLAs; the attainment of full commercialproduction at Star Lake Mine is contingent onthe availability of PRLA reserves and on con-struction of the Star Lake Railroad for accessto out-of-State markets. See the New Mexicoappendix for additional information on thesemines.

Utah.—Eleven new mines on Federal leasesin Utah have been proposed. The mines con-tain 78 Federal leases and over 118,000 acres

of Federal land with nearly 1.3 billion tons ofrecoverable coal reserves. The mine planscover almost 150,000 acres, and the totalmine plan reserves, which include both Fed-eral and non-Federal coal, are over 1.2 billiontons. (Total mine plan reserves are less thanthe total lease reserves because plans cur-rently do not cover all of the leased land.)Eight of the mines are located in central Utahand three are in Southwestern Utah. The pro-posed mine plans include nine new under-ground mines and two new surface mines—the first strip mines on Federal leases inUtah.

The total annual capacity of these pro-posed mines at full production is 42.9 mil-lion tons. The smallest of the mines willproduce 220,000 tons per year at full capac-ity; the largest mine will have an annual ca-pacity of 12 million tons. The three minesin Southwestern Utah have a total pro-posed capacity of 29.8 million tons peryear. Several mines will not reach full pro-duction levels on current schedules untilthe late 1980’s or early 1990’s. Markets forseveral of the new mines in Utah are as yetunknown, although at least 4,2 million tonsof capacity can be considered captive pro-duction.

According to the pending mine plans,total production could reach 6.2 milliontons by 1986. As the new mines near full-scale operations in 1991, total productionis expected to be between 11.3 million and29.3 million tons, depending on whetherthe three mines in Southwestern Utah openas planned. The rate of production fromseveral mines in central Utah could be lessthan current ly pro jec ted because ofchanges in construction plans for asso-ciated projects. See the Utah appendix foradditional information on the uncertaintiesin the potential production from pendingmine plans.

Undeveloped Leases

In the three Southern Rocky MountainStates there are 139 Federal coal leases


classified as undeveloped (without mineplans). Table 43 shows the acreage and re-serves for undeveloped leases in Colorado,New Mexico, and Utah. These 139 leases aredivided into 77 lease blocks and contain over2.3 billion tons of reserves. OTA’s review ofthe reserves and mining conditions on theleases found that 96 leases in 37 minableblocks with 95 percent of the undevelopedlease reserves could support new mining op-erations. OTA’s analysis further showed thatmost, but not all of these 96 leases, could bedeveloped over the next decade. In addition,there are a smal l number of leases that couldb e m i n e d a s p a r t o f a d j o i n i n g o p e r a t i o n s o nexis t ing or new base t rac ts .

OTA ident i f ied 42 leases wi th 599 mi l l iont o n s o f r e s e r v e s t h a t a c t u a l l y h a v e f a v o r a b l eprospec ts for deve lopment by 1991. An addi -t ional 54 leases wi th over 1 .5 b i l l ion tons ofr e s e r v e s h a v e u n c e r t a i n p r o s p e c t s f o r d e v e l -o p m e n t . F o r t y - t h r e e l e a s e s w i t h 2 1 9 m i l l i o ntons of reserves were found to have unfavor-a b l e d e v e l o p m e n t p o t e n t i a l . O v e r 7 0 p e r c e n tof the lease reserves wi th favorable develop-m e n t p o t e n t i a l a r e f o u n d i n t h e U i n t a r e g i o no f c e n t r a l U t a h . A l m o s t a l l o f t h e r e s e r v e sw i t h u n c e r t a i n d e v e l o p m e n t p o t e n t i a l a r e l o -

Table 43.—Undeveloped Leases in Colorado,New Mexico, and Utah: Acreage and

Recoverable Reserves

TotalTotal recoverable

Total number of Total reservesnumber of lease Federal (millions

State/region leases blocks acres of tons)

ColoradoGreen River . . . . . 23Uinta. . . . . . . . . . . . 23San Juan . . . . . . . . 0Denver-Raton Mesa 6

Total . . . . . . . . . . . 52

New MexicoSan Juan . . . . . . . . 8Denver-Raton Mesa 3

21 24,417 81611 18,850 1730 0 04 3,686 66

36 46,953 1,055

7 4,634 953 200 0.5

Total . . . . . . . . . 11 10 4,834 95

UtahUinta. . . . . . . . . . 44 20 47,679 447Southwestern 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 roundingSOURCE. Office of Technology Assessment.

c a t e d in the Green River region of Coloradoa n d i n S o u t h w e s t e r n U t a h . T h e m a j o r u n c e r -t a i n t i e s a s s o c i a t e d w i t h l e a s e d e v e l o p m e n ta r e : 1 ) m a r k e t s ; 2 ) c o n s t r u c t i o n o f p r o p o s e dt r a n s p o r t a t i o n s y s t e m s ; a n d 3 ) a v a i l a b i l i t y o fa d d i t i o n a l r e s e r v e s . M o s t o f t h e l e a s e s t h a twere found to have unfavorable potent ia l ford e v e l o p m e n t a r e s m a l l i s o l a t e d l e a s e t r a c t swi th l imi ted reserves .

P o t e n t i a l p r o d u c t i o n f r o m u n d e v e l o p e dl e a s e s t h a t w e r e r a t e d a s f a v o r a b l e o r u n c e r -ta in development prospects i s es t imated to beonly about 800 ,000 tons by 1986 , however by1 9 9 1 , p o t e n t i a l p r o d u c t i o n f r o m t h e s e l e a s e sc o u l d r a n g e b e t w e e n 1 6 . 8 m i l l i o n a n d 3 2 . 2m i l l i o n t o n s d e p e n d i n g o n t h e r a t e o f m i n ec o n s t r u c t i o n a n d r e s o l u t i o n o f v a r i o u s u n c e r -t a i n t i e s . T h e u n d e v e l o p e d l e a s e s c o u l d c o n -tribute between 32 million and 55 million tonsof new annual capacity and 2.6 million tons ofr e p l a c e m e n t c a p a c i t y ,

Summary of Undeveloped Lease Statistics

Of the 3 6 0 Federal leases in the region, 39p e r c e n t a r e c l a s s i f i e d a s u n d e v e l o p e d . T h e yc o v e r m o r e t h a n 1 5 7 , 0 0 0 a c r e s , o r a b o u t 3 5p e r c e n t o f l a n d u n d e r l e a s e i n t h e t h r e eStates, and include over 2.3 billion tons of re-coverable reserves , or over 39 percent of thel e a s e d r e s e r v e s i n t h e s e S t a t e s . O f a l l l e a s e sident i f ied as undeveloped by OTA, 56 percentare located in this region.

U t a h , w i t h 7 6 u n d e v e l o p e d l e a s e s , h a sm o r e t h a n h a l f o f t h e r e g i o n ’ s u n d e v e l o p e dl e a s e s ; t h e r e a r e 5 2 u n d e v e l o p e d l e a s e s i n

C o l o r a d o a n d 1 1 i n N e w M e x i c o . U t a h a n dColorado each have slightly over 1 billion tonso f u n d e v e l o p e d l e a s e r e s e r v e s . N e a r l y a l l o fN e w M e x i c o ’ s u n d e v e l o p e d r e s e r v e s a r e s u r -f a c e m i n a b l e ; i n c o n t r a s t , m o s t o f t h e u n d e -v e l o p e d l e a s e r e s e r v e s i n U t a h m u s t b e d e e pmined . S l ight ly more than ha l f of Colorado’su n d e v e l o p e d l e a s e r e s e r v e s a r e a c c e s s i b l e b yu n d e r g r o u n d m e t h o d s ; t h e r e s t c a n b e s u r -face mined.

T h e u n d e v e l o p e d l e a s e s i n t h e S o u t h e r nR o c k y M o u n t a i n r e g i o n v a r y w i d e l y i n c h a r -acter. 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 plansare nearly completed. Another 13 blocks with17 leases are small tracts of less than 100acres that formerly sustained small under-ground mines serving local markets. Thesemines closed for various reasons: 1) inabilityt o m e e t i n c r e a s e d h e a l t h a n d s a f e t y r e -q u i r e m e n t s ; 2 ) d i f f i c u l t m i n i n g c o n d i t i o n s ;3) deple ted reserves ; or 4) a decl ine in localmarkets . Many of these smal ler leases are lo-ca ted in the i so la ted mounta inous areas . Sev-e r a l l a r g e m u l t i l e a s e b l o c k s i n r e m o t e a r e a sa r e a l s o i s o l a t e d f r o m p o t e n t i a l m a r k e t sbecause of lack of ra i l service . Two of thesel e a s e a r e a s — S o u t h w e s t e r n U t a h a n d t h eStar Lake-Bis t i area of the San Juan basin inN e w M e x i c o — a l s o p r e s e n t p o s s i b l e e n v i r o n -m e n t a l c o n f l i c t s f o r l a r g e - s c a l e c o a l d e v e l -opers because of potent ia l impacts on nearbyn a t i o n a l p a r k s , m o n u m e n t s a n d o t h e r s c e n i ca n d a r c h e o l o g i c a l r e s o u r c e s .

OTA has grouped the 139 undevelopedleases in the Southern Rocky Mountain regioninto 77 blocks of contiguous leases that areowned by the same lessee(s). Each block willprobably be mined as one operation if de-veloped. The blocks range from single leasesof 40 acres to multilease blocks with as manyas 10 leases and a total of more than 25,000acres.

Colorado has the largest number of leaseblocks, 36, of which 31 are single lease blocksand 5 are multilease blocks. New Mexico’s 11undeveloped leases are divided into 1 0blocks. Seven of these are single lease blocksof less than 160 acres, one is a two leaseblock of 160 acres, and two are large leases,each with enough reserves to sustain a newlarge mine.

Utah’s 76 leases are divided into 31 leaseblocks—20 blocks in central Utah and 11blocks in Southwestern Utah. These blocks in-clude 12 multilease blocks and 19 single leaseblocks. The single lease blocks in Utah rangein size from 40 acres to 1,908 acres.

The Colorado, New Mexico, and Utah sec-tions of the appendix to this report describethe lease blocks in more detail.

Assessing the Development Potential ofUndeveloped Leases (in Colorado,New Mexico, and Utah)

OTA’s analysis of undeveloped leases in-cluded an assessment of each lease block todetermine which blocks could potentially sup-port a new mine. OTA compared the resourcecharacteristics of each block with those of ac-tive or proposed mines in the same region.Both large and small mines were included inthe regional mine profiles. * The followingcriteria were used:

1. Approximate mining unit. Is the lease blockcompact, contiguous, and under singleownership to allow for orderly develop-ment as a mining unit?

2. Coal reserves. Are the recoverable coal re-serves within the lease block sufficient tosupport a competitively sized new mine,i.e., large mines producing 0.5 million to 1.0million tons per year; small mines produc-ing 50,000 tons per year?

3. Coal quality. Do the coal reserves meetminimum Btu, sulfur, and ash qualitystandards for the expected end use, e.g.,steam coal, industrial use, synthetic fuels?

4. Geological characteristics. Do the geo-logical conditions of the coal reserve suchas depth of overburden, seam thicknessand dip, and surface topography permit ef-ficient mine design and economic coal re-covery comparable to other operatingmines in the area?

When the quality and quantity of the re-serves and the potential mining conditions onthe lease blocks are considered, 37 blockswith a total of 96 leases were found to havesufficient minable reserves to sustain a newmine without additional Federal or non-Fed-eral reserves. Of these 37 blocks, 10 leaseblocks could support new small mines. It isfrom these 96 Federal leases with sufficientamounts of good quality minable reservesthat most, if not all, of the new production

*These profiles and the results of OTA’s evaluation of prop-erty characteristics are discussed in detail in the State taskforce reports.

Ch. 6—Development Potential and Production Prospects of Federal Coal Leases - 133

from existing Federal leases will come. Seetable 44 for the results of OTA’s review of theresource characteristics of undevelopedleases.

In addition to the resource characteristics,OTA’s analysis of the development potentialof leases without mine plans also included anevaluation of other factors, such as marketconditions, transportation availability, andenvironmental requirements, that will influ-ence whether a lease will go into production,For the Southern Rocky Mountain region,OTA found that the undeveloped leases di-vide almost evenly among three categories:favorable, uncertain, and unfavorable devel-opment prospects. The leases, acreage andreserves in these categories are summarizedin table 45. Forty-two leases (13 blocks) wererated as favorable prospects for developmentby 1991; 54 leases (28 blocks) were rated asuncertain; and 43 leases (36 blocks] wererated as unfavorable. Only 9 percent of theundeveloped lease reserves are included inblocks with unfavorable development poten-tial. Roughly 65 percent of the undevelopedreserves, 1.5 billion tons, fell into the uncer-tain category and 599 million tons, or 25 per-cent of the undeveloped reserves in the regionreceived a favorable rating. As a result of the

analysis of the prospects for development ofexisting leases, several lease blocks with min-able reserves that could support new mineswere found to have little chance of actuallygoing into production in the next decade. Asmall number of leases that could not inde-pendently support viable mining operationswere found to have some potential for devel-opment in association with adjacent Federalor non-Federal reserves.

At least 17 leases (5 blocks) with favorableratings are part of proposed mining projectswith mine plans in preparation and potentialcustomers for future production. The leaseblocks with favorable prospects for develop-ment also include several large tracts of ex-cellent reserves for which current develop-ment plans are unknown. The undevelopedleases with unfavorable development poten-tial include many single lease tracts withsmall reserves as well as several largertracts in areas that are not likely to be linkedto an adequate coal transportation systemwithin the next 10 years. Some of the leasesreceiving uncertain development prospectratings face resolvable development prob-lems such as potentially adverse environ-mental impacts, uncertainties about con-struction 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 havequality minable reserves to support a new enough good quality minable reserves to

mine support a new mine

Number Number Number Numberof of R e c o v e r a b l e 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 38Green River . . . . . . . . . . . . . . 16 14 22,970 792 7 7 1,447 24Uinta . . . . . . . . . . . . . . . . . . . . 18 6 17,658 159 5 5 1,192 14Denver-Raton Mesa. . . . . . . . 5 3 3,646 66 1 1 40 0.1

New Mexico . . . . . . . . . . . . . . . . 2 2 3,954 94 9 8 880 1.5San Juan . . . . . . . . . . . . . . . . 2 2 3,954 94 6 5 680 1.0Denver-Raton Mesa. . . . . . . . 0 0 0 0 3 3 200 0.5

Utah . . . . . . . . . . . . . . . . . . . . . . 55 12 99,274 1,119 21 19 5,942 67Uinta . . . . . . . . . . . . . . . . . . . . 30 8 44,658 417 14 12 3,021 25Southwestern 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


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- Recover-able able

Number Numberable

reserves Number Number reserves Number Number reservesof of (mil l ions of of (mil l ions of

State/regionof (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


or difficulties in marketing coal competitivelyin the current era of overcapacity.

OTA’s analysis identified 96 leases in theSouthern Rocky Mountain region that havefavorable or uncertain prospects for develop-ment in the next decade. These leases containover 2. I billion tons of reserves—over 90 per-cent of the undeveloped Federal lease re-serves in the three States. While a clas-sification of favorable or uncertain does notmean that OTA has found that the lease willdefinitely go into production by 1991, it isprobable that many of these leases will infact be mined because they include very goodreserves and the market situations for thosestates show at least limited opportunities forexpanded coal production.

Production Prospects forUndeveloped Leases

The potential production and mine capac-ity for Federal leases with favorable oruncertain development prospects are sum-marized in table 46. OTA’s production andcapacity projections represent a rough es-timate of the production and capacity thatcould be supported by each block based onconsideration of the amount and type of re-

serves and expected mining conditions foreach block.

OTA identified only two undevelopedleases, one in the Green River region of Col-orado, and one in the San Juan basin of NewMexico, which are expected to be in produc-tion by 1986. Together they could yield 0.8million tons in 1986. One of the leases isalready committed to supply an existing pow-erplant; the other is associated with a pro-posed mine on adjacent non-Federal landserving a local powerplant.

By 1991, 23 blocks including 77 leases (55percent of the total undeveloped leases in theSouthern Rockies) could be in production. Ifall 22 mines on these leases were developed,they could produce between 16.8 million and32.2 million tons of coal in 1991. If a verystrong coal market develops, however, pro-duction could approach the total maximumcapacity of 57.7 million tons that these leasescould support. Twelve of the 23 lease blockswhich might be in production in 1991 have fa-vorable development prospects. The remain-ing 11 blocks have uncertain prospects for avariety of reasons including lack of trans-portation, uncertain markets, and the needfor additional reserves. Despite these current


Table 46.—Summary of Potential Production and Mine Capacity for Undeveloped Leases With Favorable orUncertain 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 Maximumdevelopment 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 JuanFavorable. . . . 2 2 1 1 2.0 0.2 2 2 4.0-12.0 1.7-8.0Uncertain . . . . 3 2 0 0 0 0 0 0 0 0

Denver-Raton-MesaFavorable. . . 0 0 0 0 0 0 0 0 0 0Uncertain . . . . 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

UintaFavorable. . . . 30 8 0 0 0 0 28 7 12.0 7.0-8,6Uncertain . . . . 3 3 0 0 0 0 0 0 0 0

Southwestern UtahFavorable, . . 0 0 0 0 0 0 0 0 0 0Uncertain . . . . 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, theestimated Federal production would be very small and thus, neither those leases nor the possible production are shown in the production and capacity estimatesabove.

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 inplace 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


problems, the lessees of 13 blocks are plan-ning for development and the outlook for re-solving their problems is good enough to sup-port a forecast of some coal production fromtheir leases by 1991.

According to OTA’s analysis, a total of 77of the 96 undeveloped leases with favorableor uncertain development potential are likelyto be in production within the next decade.The remaining leases, 17 of which receiveduncertain development prospect ratings andtwo of which received favorable developmentprospect ratings, either are not as likely toovercome the probable obstacles to develop-

ment by 1991 or will contribute only verysmall production.

Colorado.—Colorado has 52 undevelopedleases with a total of over 1 billion tons of re-coverable reserves. The Green River regionhas 23 undeveloped leases and 77 percent ofthe undeveloped lease reserves in the State.

Ten Colorado leases in three lease blockswith a total of 78 million tons of recoverablereserves were classified as favorable devel-opment prospects. All of the leases are lo-cated in western Colorado and all are part ofnew mine projects that have not yet sub-

84-141 0 - 81 - 10 : 2! 3


mitted mine plans. One of the leases is ex-pected to be producing at it’s planned capac-ity of 600,000 tons per year by 1986; the othertwo blocks could produce 1.8 million tons in1991 out of a total planned capacity of 2 mil-lion tons (see table 45).

Twenty-one leases were classified as un-certain prospects for development. Over 90percent of the 817 million tons of leasereserves rated as uncertain are found in theGreen River region of northwest Colorado.Several very large tracts of underground andsurface recoverable reserves are included inthis category. The uncertain rankings werebased on a variety of considerations thatwere different for each lease block, includingcoal quality, the availability of additionalreserves from PRLAs or new Federal leases,transportation problems, and uncertain coaldemand due to the slow pace of constructionof planned powerplants and coal-based syn-thetic fuel projects. Almost all of theselessees are proceeding with mine plan devel-opment. By 1991, these leases with uncertaindevelopment prospects could produce up to5.8 million tons with an eventual capacity ofbetween 9.6 million and 15.1 million tons peryear depending on the mine design.

Colorado has more leases and reservesrated as unfavorable development prospectsthan New Mexico and Utah combined. Evenso, only 15 percent of the undeveloped leasereserves in Colorado were found to be unlike-ly to be developed. Twenty-one leases in 16blocks with 154 million tons of reserves wereclassified as unfavorable development pros-pects. Most of the unfavorable lease blockswere single lease tracts with small amountsof reserves. Two blocks in the Tongue MesaField with a significant amount of good qual-ity minable reserves were rated as unfavor-able because the area is not served by ade-quate coal transportation. These two blockswere the only large blocks in the three-Stateregion that were found to have little potentialfor development in the next 10 years. See theColorado appendix for additional informationon potential production from undevelopedleases in the State.

New Mexico.—There are 11 undevelopedleases with 95 million tons of recoverablereserves in New Mexico; 8 of these leases andover 99 percent of the reserves are located inthe San Juan basin of northwest New Mexico.The Raton Mesa region in the northeast hasthree scattered Federal leases that once sup-ported small mines.

Two large leases in the San Juan basinwere found to have favorable potential for de-velopment. These two leases cover 82 percentof the acreage of undeveloped leases and con-tain nearly all of the undeveloped reserves.These leases could produce 200,000 tons in1986 and from 1.7 million to 8 million tons in1991 depending on the rate of mine expan-sion.

One block is located in the northern part ofthe basin near Farmington and is associatedwith the proposed La Plata Mine on adjacentnon-Federal land. Production from this leasewill probably be sold to the San Juan power-plant. The other lease is located at BlackLake in the Star Lake-Bisti area of the south-central part of the basin, and is associatedwith several pending PRLAs At least a por-tion of the production will reportedly be usedin the proposed Texas Eastern Synfuels coalgasification project. Coal from the minewould be shipped on the Star Lake Railroad.Both leases would be surface mined. Mineplans were submitted to the State surfacemine agency after OTA’s analysis was com-pleted.

Five leases were rated as having uncertaindevelopment prospects including three leasesin the San Juan basin and two leases in theRaton Mesa region. All of the leases are lessthan 160 acres and contain a total of about 1million tons of reserves. These leases couldbe developed only in association with adja-cent properties. It is unknown whether oper-ating agreements or assignments for such de-velopment have been negotiated. The amountof production from these leases would be verysmall. The four remaining leases were foundto have unfavorable development prospects.See the New Mexico appendix for additionalinformation on these leases,


Utah.—There are 76 leases without mineplans in Utah. These leases are divided into31 lease blocks containing about 1.2 billiontons of recoverable reserves, nearly all ofwhich are accessible by underground mining.Thirty-two leases with over 63 percent of theundeveloped lease reserves are found insouthwestern Utah, which currently has noactive coal mining operations. Several hun-dred million tons of reserves are contained inlarge multilease blocks on the rugged and iso-lated Kaiparowits Plateau.

OTA identified 301 eases in 8 1ease blocksin central Utah that have favorable prospectsfor development in the next decade. Theseleases cover some of the best quality unde-veloped coal reserves currently under lease.Several of the blocks contain metallurgicalcoal reserves. Most of the reserves would bedeep mined, but portions of one block couldprobably be strip mined. These 30 leases in-clude over 70 percent of the undevelopedlease reserves with favorable developmentpotential in the entire Southern Rocky Moun-tain region. These leases could produce up to8.6 million tons in 1991 with maximum minecapacity reaching 9 million to 12 million tonsper year in the mid-1990’s.

Twenty-eight leases in seven lease blockswere found to have uncertain prospects fordevelopment. Three small leases in centralUtah have uncertain development prospectsbecause the lessees reportedly intend to minethe leases in conjunction with adjacent ornearby operations. The amount of reservesand annual production are small. Over 702million of the 705 million tons of reservesrated as uncertain for development are con-tained in 25 leases located in four blocks onthe Kaiparowits Plateau in southwesternUtah. Production from these leases is highly

uncertain because of their distance from railservice, lack of established communities, dif-ficult underground mining conditions, andpotential environmental conflicts resultingfrom development. These lease reservescould support mines with an eventual annualcapacity of between 6.5 million and 16 milliontons per year depending on the mine size.OTA estimates that these mines could pro-duce between zero and 7,4 million tons in1991.

Utah’s undeveloped leases with favorableand uncertain development potential couldadd as many as 11 new Federal mines by1991 with a total capacity of 18.5 million to28 million tons. The production capability ofthe individual mines ranges from less thanI00,000 tons to more than 6.0 million tons peryear.

The remaining 18 leases in Utah werefound to have unfavorable prospects for de-velopment. These 16 blocks with 64 milliontons of reserves consist of small, scatteredlease tracts, many of which once supportedsmall mines. None of the lease tracts haveenough good quality reserves remaining tosupport even a new small mine. Several unde-veloped leases in central Utah are adjacent toUtah Power & Light’s Deer Creek-WilbergMine complex and to several proposed newlease tracts. These unfavorable leases couldconceivably be combined with adjacent oper-ations. However, as of May 1980, when OTAcompleted its review of these leases, no suchaction had been taken. Only 29 percent of theundeveloped reserves in the region with unfa-vorable development ratings are located inUtah. The Utah appendix discusses the loca-tion, production potential, and developmentuncertainties of leases without mine plans incentral and southwestern Utah.


Development Potential and Production Prospectsof Federal Coal Leases in North Dakota,

Montana, and Wyoming

The areascoal province

of the Northern Great Plainsand the northern portion of the

Rocky Mountain coal province which containleased Federal coal are located in Montana,North Dakota, and Wyoming (see fig. 2 inch. I). The Fort Union lignite region ofwestern North Dakota and east-central Mon-tana, and the Powder River basin of south-eastern Montana and northeastern Wyomingare located in the Northern Great Plains coalprovince. In southern Wyoming, which islocated in the northern portion of the RockyMountain province, the Hanna Field, the RockSprings Field, and the Kemmerer Field con-tain significant amounts of leased Federalcoal (see fig. 3 in ch. 1). *

There are 137 existing Federal coal leasesin these three regions covering nearly273,000 acres and containing 10.3 billion tonsof recoverable reserves.** These regions have24 percent of the total Federal leases, 34 per-cent of the acreage under lease, and 62 per-cent of the reserves under lease. Sixty-eightof the leases in this three-state area are in ap-proved mine plans; only nine are in pendingmine plans; the remaining 60 leases are not inmine plans, and are referred to as undevel-oped leases in this report. Coal productionfrom mines with Federal leases in NorthDakota, Montana, and Wyoming was 109 mil-lion tons in 1979 or over 90 percent of thetotal production of 119 million tons in thesethree States and over 75 percent of the total

*PPL’s Cherokee lease block is technically part of the LittleSnake River Field in southern Wyoming, but is included in theRock Springs Field in the numerical analysis in this chapter.

**By confining the discussion in this section to the FortUnion region, the Powder River basin and the Hanna, RockSprings, and Kemmerer fields of southern Wyoming, threesmall leases in Montana in the Yellowstone and Bull Mountainregion, and two small leases in Wyoming in the Big Horn basinare omitted. Four of these leases have unfavorable develop-ment potential. The fifth, in Montana, is currently producing.

production of all mines with Federal leases inthe West. *

Summary of Production Potential andPlanned Capacity

Table 47 summarizes the production poten-tial of all mines with Federal coal leases inNorth Dakota, Montana, and Wyoming. Oper-ating mines with Federal leases in these threeStates produced 109 million tons of coal in1979. According to the lessees’ plans, Federalmines in currently approved mine plans arescheduled to produce 232 million tons in 1986and 260 million tons in 1991. OTA estimatesthat under favorable market conditions mineswith Federal leases in pending mine plansand undeveloped Federal leases located inthis three-State area will contribute an addi-tional 32 million tons of coal production in1986 and 97 million tons in 1991, If theseOTA estimates and the lessees’ plans arerealized, total production from mines withFederal coal leases in North Dakota, Mon-tana, and Wyoming will be 264 million tons in1986 and 357 million tons in 1991.

In the Powder River basin of Wyoming andMontana, Federal mines accounted for 88percent of total coal mine capacity in 1980.This percentage is projected to remain rela-tively constant throughout the decade. How-ever, production from Federal leases them-

*Coal from Federal coal leases is referred to as Federalcoal. A mine that includes a Federal lease is called a Federalmine. Sometimes, for the sake of efficiency of recovery or econ-omy of operations, intervening state or private coal is minedwith Federal lease(s) in the same mine. This practice is the rulein Southern Wyoming and North Dakota. for example. Thus,many Federal mines produce both Federal and non-Federalcoal. A mine that contains no Federal coal is called a non-Federal mine. Total coal production in a State or region is thusthe sum of: 1 ) Federal coal product from from Federal mines plus2) non-Federal coal production from Federal mines plus 3) non-Federal coal production from non-Federal mines.


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 minesFederal in pending Federal in pendingmines in mine plans mines in mine plansapproved and leases approved and leases

Production mine not in mine not inState/region in 1979 plans a mine plansb Total plans a mine plansb Total

North DakotaFort Union . . . . . . . . . . . 14.1 C 12 15 27 12 20 32

Subtotals. . . . . . . . . . 14.1 12 15 27 12 20 32

MontanaFort Union . . . . . . . . . . . 0.3 0.3 0.0 0.3 0.3 0.0 0.3Powder 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

WyomingPowder River basin . . . 44.5 144 5.6 to 9.5 150 to 154 170 17 to 56 186 to 225Hanna Field . . . . . . . . . 10.7 10 0.4 to 0.6 10 to 11 8 0.3 to 0.6 8 to 9Rock Springs Field . . . . 7.2 13 1.3 to 2.0 14 to 15 15 1.1 to 7.0 16 to 22Kemmerer 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 357aWith 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 plansclncludes 56 million tons of production from mines with Federal leases in currently pending mine plans.


selves is projected to increase from less than40 percent of total coal production in thebasin in 1979 to approximately 80 percent in1991. In southern Wyoming, essentially allcoal production is from Federal mines withabout one-third of the production from theFederal leases, This pattern is expected tocontinue with the contribution from Federalreserves rising to perhaps 40 percent by1991. In 1979, Federal mines in the NorthDakota portion of the Fort Union region ac-counted for over 90 percent of the State’scoal production; the amount produced fromFederal reserves was less than 7 percent.This situation is expected to continue, withhowever, production from Federal reservesrising to perhaps 20 percent by 1991.

Figure 27 summarizes the potential pro-duction and planned capacity of all mineswith Federal leases (including undevelopedleases) in the Fort Union region of NorthDakota and Montana, the Powder River basinof Montana and Wyoming, and the coalfieldsof southern Wyoming. The upper capacity

lines (lines D) in this figureestimate of the maximum

represent OTA’scoal production

from Federal mines that could be achieved inthese three regions under strong market con-ditions.

Several features of figure 27 should benoted:

1.

2 .

The Powder River basin will continue toincrease in importance as a coal-produc-ing region, By 1991, Federal mine pro-duction in the Powder River basin couldaccount for about 80 percent of Federalmine production in these three States. *All estimated Federal mine productionfor 1991 for the Powder River basincomes from currently approved minesand from undeveloped leases with favor-able development potential. (Undevel-oped leases with uncertain develop-

*Because of the importance of the Powder River basin inFederal coal production, the development potential and pro-duction prospects of all Federal Coal leases in this region areexamined in more detail in ch. 7.


Figure 27.-Planned Capacity and Potential Production of All Mines With Federal Leases in thePowder River Basin, Southern Wyoming, and Fort Union Region

Million tonsper year

40Fort Union D

region c30 -

20 -

● & I 11979 1966 1991

Year


50

40

30

20

10

Southern Wyoming

.

.

I 9 1 I I I 1 1 I t t I I1979 1966 1991

. .Mil l ion tonsper year

350

Powder River basin

300

250

200

150

100

50

t1 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 presentlyundeveloped Federal leases

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

SOURCE. Office of Technology Assessment.

ment potential contribute no production 3. By 1991, the capacity of Federal minesthrough 1991. ) The large range in esti- in the Powder River basin could be asmated production from undeveloped high as 310 million tons per year. Ac-leases arises from demand uncertainty. cording to the lessees’ plans, the overca-However, several undeveloped leases in pacity in presently operating Federalthe basin have contracts for delivery of mines in the Powder River basin, whichcoal before 1990. was greater than 75 million tons per


4.

5,

year in 1979, will diminish to nearly zeroby 1991,The maintenance of total capacity ofFederal mines in southern Wyoming de-pends on the development of new mines,Although capacity of presently oper-ating mines is projected to decrease overthe next 10 years, their production willprobably not decline, Most of the rangein production arises from uncertainty inthe pace of a synfuels project.The potential increase in production andcapacity of Federal mines in the FortUnion region will occur largely frommines in North Dakota with leases incurrently pending mine plans. Undevel-oped leases are not likely to contributemore than 1 million tons per year by1991. Federal mine production in theMontana portion of the region is likely toremain constant at 0.3 million tons peryear.

The following subsections summarize thedata presented in table 47 by State.

North Dakota.—Production from Federalmines with approved mine plans in the FortUnion region of North Dakota was 8,5 mil-lion tons in 1979. In 1986, these mines areprojected to produce 12 million tons, a levelof production that should remain constantthrough 1991. Production from Federal mineswith mine plans pending was almost 6 milliontons in 1979 and is expected to increase to 15million tons in 1986 and to 20 million tons in1991. Production of perhaps 1 million tonscan be expected from undeveloped leases inNorth Dakota by 1991. Total production fromFederal mines in North Dakota could reach32 million tons by 1991,

Montana.—Production from mines withFederal leases in Montana in 1979 was 27.4million tons, Virtually all of this production(27.1 million tons) came from the PowderRiver basin; production from a small Federalmine in the Fort Union region of Montana ac-counted for the balance. According to the les-sees’ plans, 47 million tons of coal will be pro-duced in 1986 from mines with Federal leases

already developed in the Montana PowderRiver basin. Production from the Montanaleases in the Fort Union region is scheduled toremain at 0.3 million tons through 1991.

OTA estimates that 1.6 million tons of coalcould be produced in 1986 and close to 9million tons in 1991 from undeveloped Fed-eral coal leases in the Montana portion of thePowder River basin. Lessee plans call for pro-duction of 49 million tons in 1991 from Fed-eral mines in approved mine plans. If theseestimates and plans are realized, productionfrom Federal mines in Montana would reach58 million tons per year in 1991. There are noleases with pending mine plans in Montana.

Wyoming.—Coal production from mineswith Federal leases in the four regions ofWyoming— the Powder River basin, HannaField, Rock Springs Field, and KemmererField—totaled 67.5 million tons of coal in1979. Two-thirds of this production (44.5 mil-lion tons) came from the Wyoming portion ofthe Powder River basin. By 1986, accordingto the lessees’ plans, production in this basinfrom Federal mines that now have approvedmine plans will increase to 144 million tons.OTA estimates that an additional 10 milliontons could be produced from undevelopedleases in the basin in 1986, giving plannedand estimated production of 154 million tonsin 1986. By 1991, production could increaseto 225 million tons with 170 million tons com-ing from Federal mines that now have ap-proved mine plans and 56 million tons fromundeveloped leases.

Twenty-three million tons of coal was pro-duced from mines with Federal leases insouthern Wyoming in 1979. The lessees planthat production from currently operatingmines will increase to 29 million tons in 1986and remain constant through 1991. OTA esti-mates that production from currently unde-veloped leases and leases in pending mineplans in this region could reach 6 million tonsby 1986 and 12 million tons by 1991, for totalsouthern Wyoming Federal mine productionof 35 million tons in 1986 and 41 million tonsin 1991.


Quality of Coal Under Lease

Of the 9 billion tons of recoverable coal re-serves under lease in the Powder River basin,7 million tons are subbituminous C, and 1.3billion tons are subbituminous B.* There aresmall reserves of subbituminous A in theMontana portion of the Powder River basin.There are also Federal lignite reserves underlease in the Powder River basin. Several Fed-eral mines and leases in southern Wyominghave reserves of bituminous coal, howevermost of the Federal reserves in southernWyoming, including most of the reserves onundeveloped leases, are subbituminous. AllFederal reserves in the Fort Union region arelignite.

Most of the Federal coal in the PowderRiver basin and the coalfields of southernWyoming is low sulfur (i.e., less than 0.5 per-cent sulfur). Only one Federal mine in thePowder River basin produces coal with a sul-fur 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 typi-cally range from 25 to 120 ft in thickness.Because of the thick seams which lie fairlyclose to the surface, all mines in the PowderRiver basin are surface mines. Large quan-tities of coal can be extracted at low costfrom these mines. On a Btu basis, PowderRiver basin coal mine-mouth prices are thelowest of all coals, ranging from $0.42 to$0.65 per million Btu (see table 28). In addi-tion, the mines in the Powder River basin arelarge. The Belle Ayr Mine in Wyoming is pres-ently the largest coal mine in the UnitedStates; it produced 15 million tons in 1980.Four other mines in the basin are scheduledto reach a design capacity of 20 million tonsper year or more by the end of the decade.

*The following Btu ranges are associated with different coalquality: 1 - Bituminous-high volatile A (greater than 14,000Btu), B (14,000 to 13,000 Btu), C (13,000 to 12,000 Btu): 2- Subbituminous—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 arecommon in southern Wyoming where the re-coverable reserves are usually much smallerand the stripping ratios higher than in thePowder River basin. Also, unlike the PowderRiver basin, underground mining has a longcontinuous history in southern Wyoming. Twounderground mining operations in southernWyoming, the Vanguard No. 2 and CarbonNo. 1 mines, currently include Federal coaldeposits. ** Longwall mining techniques are

being used or will be used to increase coalrecovery at both of these mines to about 75percent of minable reserves.

Surface mining in southern Wyoming ismore complex and more costly than in thePowder River basin because of the steeplypitching and multiple coal seams. At somemines, such as the Elkol-Sorensen Mine whichincludes Federal reserves, combinations ofdraglines, truck/shovel operations, and doz-er/scraper teams are used to develop largemultiple open pits with depths that may reach1500 ft. Up to 12 seams are mined at Elkol-Sorenson with an aggregate coal thickness of300 ft and dips of 170 to 220. Another Federalmine in southern Wyoming, the Black ButteMine, contains 13 coal seams ranging inthickness from 3 to 35 ft. Eleven pits willeventually be developed at Black Butte.

In the Wyoming portion of the PowderRiver basin, most Federal mines are compactunits with little, if any non-Federal coal inter-spersed with the Federal reserves. Conse-quently, mining operations in this area in-volve predominantly Federal reserves. Theoccasional sections of State and fee coal aredeveloped with the Federal reserves. By1986, the Federal portion of coal productionfrom these mines is expected to increase towell over 90 percent from the 1979 level of 49percent. In southern Wyoming and in thearea around Colstrip, Mont., on the otherhand, most leased areas of Federal coal arechecker-boarded with non-Federal coal andall LMUs include both Federal and non-Fed-

**Another underground Federal coal mine in this area, theStansbury Mine, closed in early 1981 but is expected to reopenlater in the decade.

—

Ch. 6—Development Potential and Product/on Prospects of Federal Coal Leases . 143

eral reserves. Orderly and efficient miningcan be difficult where only part of the Fed-eral coal reserves within the extended mineplan area are leased. These two patterns ofreserve development are shown in figure 28,which illustrates patterns of Federal lease-holdings in southern Wyoming, and in figure29, which illustrates patterns of Federalleaseholdings in the Wyoming portion of thePowder River basin.

Approximately 25 billion to 35 billion tons,about two-thirds of the Nation’s l igni tereserves, are found in the Fort Union regionof North Dakota. The coal seams in thisregion seldom dip more than a few degrees.Typically, the North Dakota lignite operationsare surface mines designed to produce 2 mil-lion or more tons of lignite per year. Althougha few specialized or older smaller mines re-main in operation, the trend recently hasbeen toward large-scale operations.

Reclamation and environmental issues areexpected to affect Federal coal developmentin the Powder River basin, southern Wyo-ming, and the Fort Union region, For example,at Colstr ip, Mont. , fugitive dust levelspresently exceed ambient air standards andfuture mine expansion will have to addressand minimize air quality impacts. In southernWyoming, where the climate is more arid,fugitive dust problems may have to be ad-dressed at some mines, However, air qualityconcerns are not likely to deter Federal coalproduction significantly over the next 10years in either the Powder River basin orsouthern Wyoming. Air quality is an impor-tant issue in the Fort Union region of NorthDakota where the possible lack of sulfur diox-ide (S02) increments may delay developmentof some leased Federal coal. These issues arediscussed in more detail in chapter 10,

The availability of water and the impact ofmining operations on water quality have not

Figure 28.— Federal Leases in the Hanna Basin, Southern Wyoming

SOURCE Off Ice of Technology Assessment.

- -


Figure 29.—Federal Leases in the Powder River Basin, North of Gillette, Wyo.


generally been a major factor affecting coalmine development in the Powder River basin.However, such considerations could becomeimportant if onsite powerplants or syntheticfuels projects are extensively developed.Scarcity of water in the Gillette area of thePowder River basin, for example, justified theexpense of constructing the first dry coolingtower in the United States at the WyodakPower Plant. Competition for limited watersupplies may ultimately affect the extent ofcoal mining in portions of southern Wyoming.In this area, mines need water for dust con-trol and use in mining facilities and also forthe irrigation of reclaimed lands.

Substantial quantities of topsoil, adequaterainfall, and a relatively flat terrain enhancethe potential for successful reclamation inNorth Dakota. Nevertheless, reclamation ef-

forts have not been uniformly successful inNorth Dakota. Mining in environmentally sen-sitive woody draws in the west-central regionof the State has been delayed pending devel-opment of satisfactory reclamation plans,Reclamation efforts in North Dakota mustalso take into account sodic soil problems.

At present, Federal coal development insouthern Wyoming and the Fort Union regionaffects no alluvial valley floors. In the PowderRiver basin, however, Federal coal produc-tion or expansion of Federal mine capacitycould be affected in some cases if it is deter-mined that adequate reclamation plans can-not be developed for alluvial valley floors, Ofthe 9.2 billion tons of Federal recoverablereserves under lease in the Powder Riverbasin, approximately 700 million tons couldbe affected to some extent by alluvial valley


floor considerations; less than 100 milliontons of these may be prohibited from mining,however.

Although alluvial valley floors are not animportant constraint on mine development inNorth Dakota, they are given careful consid-eration in mine permitting. Mining can becomplicated in the Fort Union region becauseof large amounts of water that can seep intothe mine pit. In cases where this seepage oc-curs through the highwall, there have beenproblems of instability and spoil pile slumpingwhich cause inefficient and potentially dan-gerous mining conditions.

Concern about the protection of wildlifehabitat has resulted in minimal prohibition tomining and production of Federal coal. Insouthern Wyoming, protect ion of raptorhabitat has resulted in some changes in min-ing plans and has contributed to the loss of 5million tons of reserves at one mine. Unlessendangered species are found to reside on aproposed mine site, it is unlikely that signifi-cant amounts of recoverable reserves will belost because of wildlife concerns.

Because most mines in the Powder Riverbasin have large surface reserves, thick coalseams, and a low stripping ratio, PowderRiver basin coal is the cheapest coal to minein the country. The capacity of a typical minein the Powder River basin is larger than thecapacity of most other surface mines locatedin the West and in other regions of the coun-try, This high volume production and low pro-duction costs are well suited to long-termutility contracts. However, the heat contentof Powder River basin coal is relatively lowcompared to coal produced in the RockyMountain coal province.

Electricity generation is the largest marketfor coal mined in Wyoming and Montana,with the main areas of demand in the South-Central and Midwest regions of the country.Demand for coal produced in Wyoming andMontana is expected to increase as demandfor electricity increases in these regions. Con-versions to coal-fired utility burners, par-ticularly in the South-Central region, may fur-

ther increase the demand for coal producedin the Powder River basin. Industrial demandfor coal mined in the Powder River basin isexpected to be relatively small over the next10 years.

The availability, cost, and reliability of railtransportation to the Midwest and South-Cen-tral regions of the country are important fac-tors in coal mine development in Wyomingand Montana. Transportation costs are al-ready an important component of the de-livered price of Wyoming and Montana coal,running as high as 70 percent in the Midwest(see table 28). Transportation costs are ex-pected to rise still further over the nextdecade.

In general, leases in southern Wyomingand the Wyoming portion of the Powder Riverbasin are closer to rail lines than leases in theMontana portion of the Powder River basin.Rail costs to the Midwest are lower for south-ern Wyoming coal than for Powder Riverbasin coal; total delivered price on a per-Btubasis for southern Wyoming coal is competi-tive with Powder River basin coal in someareas, despite the higher mine-mouth cost ofthe southern Wyoming coal (see table 28).

Coal slurry pipelines could become an op-tion for transporting coal from the PowderRiver basin over the next 10 years but de-velopment of slurry pipelines may be con-strained by restrictions on water export. Oneslurry pipeline company, the Energy Trans-portation Systems, Inc. (ETSI) has obtainedpermission from Wyoming to export water.This pipeline is planned to have a capacity of25 million tons per year. However, the Stateof Montana has decided that use of water forslurry pipelines is specifically not a benefi-cial use of water.

Lignite, which is mined in the Fort Unionregion, has a low-Btu value, high moisturecontent, and large concentrations of impuri-ties. Consequently, the Federal coal mined inthis region will generally be used close to themine site. The characteristics of the ligniterender its transportation both difficult andcostly, requiring special hopper cars and spe-

.—. .— —.


cial facilities for loading and unloading.Despite its poor quality, however, lignite hasproved to be an acceptable fuel when used inproperly designed, coal fired units. All pow-erplants currently planned or under con-struction in North Dakota will use ligniteonsite.

Development Status of Federal CoalLeases in North Dakota, Montana,

and Wyoming

There are 68 leases in 33 approved mineplans in the Federal coal regions of NorthDakota, Montana, and Wyoming (table 48).These leases cover about 149,000 acres andcontain 5.7 bi l l ion tons of recoverablereserves. Nearly 70 percent of the leases incurrently approved mine plans in this three-State area (47 leases in 23 mine plans) arelocated in Wyoming. These Wyoming leasescover about 110,000 acres and include 4.7

billion tons of recoverable reserves. ThePowder River basin of Wyoming contains 24of these 47 leases in 12 mine plans on about56,000 acres with 4.4 billion tons of recover-able reserves. Twelve leases in five approvedmine plans are located in the Montana por-tion of the Powder River basin. These 12leases cover over 29,000 acres and contain0.8 billion tons of recoverable reserves.

Nine Leases are included in six pendingmine plans in North Dakota and Wyoming. Noleases are in pending mine plans in Montana.The five Wyoming leases in three pendingmine plans will be analyzed with undevelopedleases.

Sixty leases not in mine plans are locatedin North Dakota, Montana, and Wyoming.The large majority of these undevelopedleases (47 leases, 26 blocks) are located inWyoming. These Wyoming leases cover near-ly 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 Recover-Of of able of of able of of

leasesable

plans Acres reserves a leases plans Acres reserves a leases blocks Acres reserves a

North DakotaFort 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 smallaln billions of tons.bTHREE SMALL LEASES IN THE BULL MOUNTAIN/YELLOWSTONE AREA ARE NOT LISTED IN THIS TABLE. THE LEASES COVER 240 ACRES AND HAVE VERYSMALL RESERVES. ONE LEASE IS IN A PRODUCING MINE. THE OTHER TWO ARE UNDEVELOPED LEASES.

CTWO SMALL LEASES IN THE BIGHORN BASIN ARE NOT LISTED IN THIS TABLE. THE LEASES COVER 200 ACRES, AND HAVE VERY SMALL RESERVES. BOTH AREUNDEVELOPED.



recoverable reserves. Two-thirds of theseleases (30 leases, 16 blocks) with 3.4 billiontons of recoverable reserves are located inthe Powder River basin.

Leases With Approved Mine Plans andLeases in Pending Mine Plans*

Figure 30 shows the lessees’ plans for ca-pacity, total production, and production ofFederal reserves from mines with Federalleases in North Dakota, Montana, and Wyo-ming. The dominance of the Powder Riverbasin is apparent. Although coal productionfrom Federal mines in each of these regions isexpected to increase in the coming decade,the greatest increase is expected in thePowder River basin where, in 1986 total ca-pacity and production of mines with Federalleases may be six times the total capacity andproduction of mines with Federal leases insouthern Wyoming. Production of Federal re-serves from these mines in the Powder Riverbasin could be over 14 times that from Fed-eral reserves in southern Wyoming in 1986.In 1991, the Powder River basin will continueto account for the largest capacity and pro-duction of coal from Federal mines in thesethree States and in all the Federal coalStates.

Table 49 shows the acreage and recover-able reserves of Federal coal leases in ap-proved mine plans in North Dakota, Montana,and Wyoming and pending mine plans inNorth Dakota. (The five leases in pendingmine plans in Wyoming are not included inthis table, because they are analyzed withundeveloped leases, below. ) Total mine planacres in this table refer to the total area per-mitted for mining as of early 1981. These datainclude Federal, State, and private surfaceareas used fo r min ing ac t iv i t i e s andassociated disturbances such as stockpiles,plant facilities, and buffer zones. Total mineplan acreage will change as mining oper-ations expand to realize future production

*Five leases in three pending mine plans in Wyoming areomitted from this section and are discussed in the sectionUndeveloped Leases, below.

goals. The total mine plan acreage figures intable 49 do not include proposed amend-ments. However, amendments have alreadybeen submitted to the Office of Surface Min-ing for the expansion of mining activities atapproximately 20 percent of the mines withFederal leases in Wyoming.

Federal lease acres refers to the surfaceacreage under which Federal coal is located.However, the Federal Government does notnecessarily own all (or any) of the surfaceunder which Federal coal lies. Thus, it is pos-sible (and is indeed the case at the CaballoMine in the Powder River basin) that the Fed-eral Government could own no surface acre-age in a mine plan even though most of thecoal produced at the mine is extracted fromFederal reserves. Moreover, not all the acre-age of a Federal lease will necessarily be in-cluded in a mine plan.

Table 50 identifies the current and pro-jected capacity and production, as reportedby the lessees, for mines with Federal leasesin North Dakota, Montana, and Wyoming.The portion of production that is expectedfrom Federal reserves at these mines in thenext 10 years is also included in table 50.

As tables 49 and 50 illustrate, the PowderRiver basin has the most Federal coal produc-tion, the greatest potential capacity, the mostleased and permitted mine plan acreage, andthe largest reserves of any of the major Fed-eral coal regions studied in this report.

Powder River Basin

Twenty-four of the 36 leases in 12 of 17 ap-proved mine plans in the Powder River basinare located in Wyoming; the remaining 12leases in five approved mine plans are lo-cated in Montana. The large majority of re-serves (over 80 percent) are located in theWyoming portion of the Powder River basinas is the largest amount of recent and poten-tial production. Production of coal from mineswith Federal leases in the Wyoming section ofthe basin is expected to become more impor-tant during the next 10 years. The total ca-pacity 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 WithFederal 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

1aFive 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


Powder River basin is currently 3.7 times thatof Federal mines in southern Wyoming and 8times that of Federal mines in the Fort Unionregion.

The capacity of mines with Federal leasesin the Powder River basin has not been fullyused in recent years. In 1979, these minescould have produced 76 million tons morecoal; in 1980, 60 million tons more coal. Minecapacity is expected to increase by nearly 50percent between 1980 and 1986 (i.e., from148 million to 220 million tons) and then re-main relatively constant through 1991. This isbecause of the opening of several new large

mines (e.g., Buckskin, Coal Creek, RojoCaballos) and to the expansion scheduled forexisting mines (e.g., Black Thunder, EagleButte, Rawhide). However, according to theproduction estimates of the lessees, the over-capacity of currently operating and per-mitted Federal mines in the Powder Riverbasin will diminish to 15 percent in 1986 andto 3 percent in 1991.

Annual production from Federal reservesin the Powder River basin is becoming in-creasingly important, particularly in Wyo-ming. Federal reserves accounted for only 42percent of total production from mines with


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 FederalNum- ber Total Total plan reservesb plan reservesb lease reservesb

ber of mine F e d e r a l – - - — – .—

of mine plan lease Under- Under- Under-State/region leases plans acres acres ground c Sur face Total ground c Sur face Total ground c Surface Total

ApprovedNorth DakotaFort Union . . . . . . 8 4 — 8,655 0 0.14 0.14 0 0.06 0.06 0 0.12 0.12

MontanaFort 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

MontanaPowder Riverbasin ., . . . . . . . . 12 5 19,080 29,252 0 0.48 0.48 0 0.40 0.40 0 0.8 0.8

WyomingPowder Riverbasin . . . . . . . . . . 24 12 83,141 55,681 0 4.5 4.5 0 4.2 4.2 0 4.4 4.4

Powder Riverbasin totals. . . . . . 36 17 102,221 84,933 0 5.0 5.0 0 4.6 4.6 0 5.3 5.3

Southern WyomingHanna Field . . . . . 15 6 57,037 23,927 LM <0.2 -0.2 LM LM 0.07 LM LM 0.07Rock SpringsField. ... ... , . . 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 Wyomingtotals . . . . . . . . . . . 23 11 129 ,165 54 ,512 LM <0.7 0.7 LM <0.3 0.3 LM <0.3 0.3

PendingNorth Dakota

Fort Union . . . . . . . 4 3 – 5,283 Small 0.07 0.07 Small 0.02 0.02 Small 0.10 0.10aTHERE 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 EX-PECTED ON THESE PRELIMINARY REVIEWS UNTIL 1982 BECAUSE OF THE EARLY STAGES OF DEVELOPMENT OF THESE THREE MINE PLANS, DATA FOR THISTABLE WERE UNAVAILABLE THESE LEASES ARE CONSIDERED IN THE FOLLOWING SECTION ON UNDEVELOPED LEASES

bln 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 TheStansbury 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 inFederal reserves will account

1979. By 1991,for 92 percent

of production from Federal mines averagedover the Powder River basin and almost 100percent of production from Federal mines inthe Wyoming section of the basin.

Southern Wyoming

Twenty-three Federal leases in eleven ap-proved mine plans are located in southernWyoming. These mine plans include over129,000 permitted acres and contain 0.7 bil-lion tons of recoverable reserves, of which

only 0.3 billion are Federal. Recoverablereserves at three mines, Vanguard No. Z, Car-bon No. 1 and Stansbury,* are suitable forunderground mining. The capacity of mineswith Federal leases in southern Wyoming isexpected to decrease 12 percent by the end ofthe decade, although production is expectedto increase by 26 percent during this period.Utilization of capacity is expected to increasefrom 58 percent in 1979 to 83 percent in1991. Federal reserves are expected to ac-

*Slansbury closed early in 1981 but is expected 10 reopenlater this decade.

-. . . -- — . . — —


Table 50.—Federal Mine Capacity and Federal Mine Production Prospects: Approved and Pending Mine Plansin North Dakota; Approved Mine Plans in Montana and Wyominga

1979 b 1980b 1986b1991 b

Number Numberof mine of Actual Actual Projected Projected e

plans Federal Federal Federal Estimate Projected Federal Projected eProjected Federal Projected e

with leases in Federal mine Federal Federal mine of Federal mine Federal Federal mine FederalFederal these mine produc- production mine produc- Federal mine produc- produc- mine produc- produc-Ieases plans capacity tion only capacity tion production capacity tion tion capacity tion tion

North DakotaFor t Un ion(A) c 4 8 10 8.5 1.0 10 8.9 0.6 13 12 3 13 12 3FortUnion(P) d 3 4 7 5.6 0 7 7.0 0 17 15 2 23 20 3

MontanaFort 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 Uniontotals 8 13 18 14 1.3 18 16 0.9 30 27 ~ 6 35 32 ~ 6

MontanaPowder RiverBasin 5 12 36 27 8 36 25 10

Wyoming52 46 29 52 49 31

Powder RiverBasin 12 24 112 45 22 112 63 —f 169 144 142 175 170 170

Powder RiverBas in t o ta l s 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 8Rock Springs

3

Field 3 5 19 7.2 4 19 10.4 — 18 13 7Kemmerer

19 15 7

Field 2 3 7 5.1 0.1 7 5.7 – 7 6 1 7 6 2

SouthernWyoming 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 INTABLE 53. THERE ARE NO PENDING MINE PLANS IN MONTANA. ONE SMALL MINE IN THE BULL MOUNTAIN/YELLOWSTONE REGION OF MONTANA IS NOT IN-CLUDED IN THIS TABLE.

bALL PRODUCTION AND CAPACITY ESTlMATES IN MILLIONS OF TONS PER YEAR; TOTALS MAY NOT ADD BECAUSE OF ROUNDING. SEE SECOND FOOTNOTE ONP. 114 FOR DISTINCTION BETWEEN FEDERAL MINE AND FEDERAL PRODUCTION. FEDERAL MINE PRODUCTION INCLUDES FEDERAL PRODUCTION.

cApproved mine plans.dpending 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 productionthrough 1991 in the Hanna Field; approx-imately 50 percent in the Rock Springs Field;and about 15 to 30 percent in the KemmererField.

Fort Union Region

Nine leases in five approved mine plansare located in the Fort Union region of NorthDakota and Montana. Eight of these leases infour approved mine plans located in NorthDakota contain 0.12 billion tons of recover-able reserves. The one lease in an approvedmine plan in Montana has small recoverablereserves.

In 1979, mine capacity for the NorthDakota leases in approved and pending mine

plans was 17 million tons per year; for theone Montana lease, only 300,000 tons peryear. Annual production from these mines in1979 was 14 million tons per year, of whichabout 1.3 million tons was from Federalreserves.

The contribution of Federal reserves tototal production from mines with Federalleases in North Dakota is small because usu-ally the Federal coal was leased in order to“fill out” a logical mining unit containinglarge amounts of non-Federal coal. Only 25percent of the coal reserves in North Dakotaare owned by the Federal Government—thelowest percentage of federally owned coal inthe 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 beingmined out,

Most of the increase in total productionand Federal production from Federal minesin North Dakota over the next decade is ex-pected from mines currently in pendingplans. By 1991 the capacity of mines withFederal leases in the Fort Union region is esti-mated at about 35 million tons per year. Totalproduction could increase to 32 million tonsper year, but production of Federal reserveswill be a comparatively small proportion ofthis total (about 6 million tons).

Undeveloped Leases

Table 51 presents acreage and reserves in-formation for the undeveloped leases in NorthDakota, Montana, and Wyoming. The Wyo-ming portion of the Powder River basin con-tains 65 percent (nearly 77,000 acres) of thetotal acreage and contains over 85 percent(3,9 billion tons) of the recoverable reservesfor the undeveloped leases located in theseStates. There are only about 80 million tons of

underground recoverable reserves on unde-veloped leases in these three States; all arelocated in southern Wyoming.

Assessing the Development Potential ofUndeveloped Leases in North Dakota,Montana and Wyoming: Review ofProperty Characteristics

Environmental, transportation, and marketfactors were reviewed to assess the devel-opment potential of undeveloped leases inNorth Dakota, Montana, and Wyoming. How-ever, before considering these factors, OTAreviewed information on the reserves, coalquality, and geologic features of these leases.This section summarizes the property charac-teristics of undeveloped leases in this three-State area. The review of the property char-acteristics of undeveloped leases emphasizedthe following four questions: 1) does the tractform a viable mining unit (i.e., is it compactand contiguous)? 2) does the tract have suf-ficient reserves to support an economicalmine? 3) is the coal of suitable quality for cur-rent or potential markets (i. e., heat content

Table 51 .—Acreage and Reserves of Undeveloped Leases:a

North Dakota, Montana, and Wyoming

T o t a lb

Total Total recoverable T o t a lb T o t a lb

number of Total number Federal underground recoverable recoverableState/region leases of lease blocks acres reserves surface reserves reserves

North Dakota. . . . . . . . . . . . . . . 8 7 4,754 0 0.05 0.05Fort 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)

alNCLUDES FIVE LEASES IN THREE PENDING MINE PLANS IN WYOMING. SEE TABLE 48 FOR THE ACREAGE AND RESERVES OF THESE FIVE LEASES EXCLUDESFOUR SMALL LEASES, TWO IN WYOMING AND TWO IN MONTANA. SEE FOOTNOTES b AND C, TABLE 48.

bln billions of tons.


84-141 0 - 81 - 11 : Qt. 3

— — — — — — .- . . . - . — ..-


not too low, sulfur and ash not too high)? and4) are the coal seams sufficiently thick and,where surface mines are involved, is the ratioof overburden to seam thickness sufficientlylow to be economically minable?

Powder River Basin and Southern Wyoming.—The following technical criteria were usedin OTA’s examination of the property charac-teristics of undeveloped leases in the PowderRiver basin and the coalfields of southernWyoming.

There are three major uses for Westerncoal—offsite electric power generation, on-site electric power generation, and, potential-ly, synfuels production. For export steam coalin the Powder River basin and southern Wyo-ming, a mine needs to produce at least 1million tons a year for a 30-year period. Thus,the minimum reserve requirement for a minedeveloped for export steam coal in theseareas was set at 30 million tons.

Four million tons of annual production aregenerally required for 30 years (120 milliontons of recoverable reserves) to supply an on-site electric generation plant (l,000 MW).Production of at least 6 million tons per yearfor 30 years (180 million tons of recoverablereserves) was set as the minimum require-ment for the development of a mine for onsitesynfuels production.

Because of high transportation costs, coalproduced in these two regions for export out-of-State should have an average heat contentof 8,000 Btu/lb for surface mines and 10,000Btu/lb for underground mines. Coal with alower heat content could be mined for onsitepower generation or synthetic fuels produc-tion, but would be uneconomical to transportover any distance.

The 1970 and 1979 New Source Perform-ance Standards (NSPS) for S02 were used asa basis for evaluating the sulfur content ofcoal in the Powder River basin and southernWyoming. Generally, coal with less than 0.63lb sulfur/million Btu will meet the NSPS with-out scrubbing, assuming 95 percent conver-sion of sulfur to SO2. Sulfur content of less

than 1.0 lb sulfur/million Btu will meet the1979 NSPS requirement with partial scrub-bing. Coal used onsite may have a highersulfur level, but it should not exceed 2.0lbs/million Btu in order to meet Wyoming’semission standard of 0.2 lb of S02 p e rmillion/Btu.

Ash is less critical than sulfur in theassessment of coal quality in Montana andWyoming, but a high ash content can raisethe cost per Btu of transporting coal to otherStates to an uneconomical level. Coal for ex-port in the Powder River basin should have amaximum ash content of 10 percent; in south-ern Wyoming maximum ash content can be12 percent since this coal usually has ahigher heat content. Ash levels greater than12 percent were considered acceptable foronsite conversion.

The seam thickness in existing mines in thePowder River basin ranges from 35 to 110 ft.Twenty ft was considered the minimum seamthickness for a developable property in thePowder River basin. The minimum seamthickness in southern Wyoming was set at 15ft for surface mines and at 5 ft for under-ground mines.

Seam dip is not especially important in thePowder River basin since seams in this regionare relatively flat. However, seam dip is animportant factor in mine development insouthern Wyoming where coal seams dip asmuch as 900. While surface mines can be de-veloped with a seam dip up to 250, 13°, to 15°is considered the maximum seam dip for effi-cient coal recovery in underground mines.

Maximum average overburden thicknessfor coal mined in the Powder River basin isusually less than 130 ft. The maximum strip-ping ratio for this coal is usually 2.5. A max-imum average overburden of 175 ft and amaximum average stripping ratio of 3.5 wasconsidered acceptable for mines that will usecoal onsite.

Fort Union Region.— Federal coal leases inthe Fort Union region are rarely contiguousunits or contiguous with one another. A single


lease in the Fort Union region is often dividedinto several different t racts interspersedwith fee coal. For this reason a companyrarely acquires a Federal lease in NorthDakota when it does not control the miningrights of the intervening coal property orlease sections. In addition, the minimumreserves required for mine development arerarely 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 characteristicssuch as heat content are relatively unimpor-tant in North Dakota because all the coal is ofsuch quality that, in general, only develop-ment for use onsite or at a nearby facility ispractical.

Limitations of Property Characteristics as aMeasure of Development Potential.—Undevel-oped leases with unfavorable property char-acteristics usually were found to have unfa-vorable development potential; similarly,leases with favorable property character-istics usually were found to have either favor-able or uncertain development potential.However, in some cases other factors causeda different classification. Several illustrativeexamples are discussed below.

Lessee plans to incorporate the leaseinto an approved mine plan or existing min-ing operation.— In the Powder River basin,the Phillips Creek (1) lease block in ConverseCounty, Wyo., has coal of low heat contentand high ash content in thin seams. Never-theless, it is adjacent to the Dave JohnstonMine which is scheduled to deplete its re-serves in the late 1990’s. The lease block wasrecently acquired by the Pacific Power &Light Co. (PPL) from SunEDCo and is likely tobe integrated into the Dave Johnston logicalmining unit. However, the Phillips (2) lease,recently acquired by the same lessee, andwith similar poor property characteristics, isunlikely to be developed by itself and isunlikely to be integrated into an establishedmining operation.

Lessee plans to develop a synthetic fuelsfacility or onsite power generation.—Be-

cause of low heat content and high sulfur andash, the Cherokee lease in southern Wyomingwill probably not be developed to export coalto other States. However, the lease has suffi-cient reserves to support either an onsite syn-fuels project or electric generation plant. Thesite may eventually support both operations,since a synfuels project and a powerplanthave been proposed by the lessee. The Chero-kee lease, therefore, has favorable develop-ment potential contingent on the constructionof a facility onsite to use the coal.

Lessee integrates the lease with non-Fed-eral coal.—The two CX Ranch leases in theMontana portion of the Powder River basinboth have small Federal reserves; without ad-ditional coal, neither of these leases would belikely to be developed. However, the leaseheld by Consolidation Coal Co. has been in-tegrated with State and private fee coalalready held by the company, and Consolida-tion is proposing an exchange of Indian coalfor unleased Federal coal adjacent to thearea. The transfer may be completed by theend of 1984. Because of these additional re-serves, the lease has favorable developmentpotential.

The other lease, held by Peter Kiewit Sons,Inc., also has been integrated with good qual-ity fee coal and also has favorable develop-ment potential.

Other considerations.— Some undevelopedleases have unfavorable development poten-tial even though they have excellent qualitycoal. For example, the Deadman lease in-cludes some of the highest quality coal in theState of Wyoming; it has high heat content,low sulfur and ash, and adequate seam thick-ness. However, the Deadman lease lacks thereserve base needed to develop an eco-nomical new mining operation and is locatedin an area isolated from adequate trans-portation. Furthermore, underground miningoperations required to develop this leasewould be difficult because the seams on thelease dip as much as 250. For these reasons,the development potential of this lease is un-favorable despite high coal quality.

.— .--— - .


Results of Analysis of DevelopmentPotential

Table 52 summarizes the development po-tential of the 65 undeveloped leases (40blocks) in North Dakota, Montana, and Wyo-ming. This total includes the 5 leases in pend-ing mine plans in Wyoming which were ana-lyzed as undeveloped leases. Thirty-eightleases (18 blocks) in this three-State areahave favorable development potential. Theseleases contain 3.5 billion tons of recoverablereserves and cover over 69,000 acres. Elevenleases (eight blocks) in these States have un-certain development potential. These leasesaccount for over 760 million tons of recover-able reserves and cover over 37,000 acres.Finally, 16 leases (14 blocks) in these States,covering over 11,000 acres have unfavorabledevelopment potential. However, the 310 mil-lion tons of recoverable reserves associatedwith these leases are less than 10 percent ofthe recoverable reserves contained on the 38leases with favorable development prospects.

The Wyoming portion of the Powder Riverbasin has the most reserves on undeveloped

Table 52.—Summary of Development

Federal coal leases in this area. The 3.9billion tons of undeveloped recoverable Fed-eral reserves in the Wyoming portion of thebasin is nearly seven times larger than thecombined undeveloped Federal reserves ofsouthern Wyoming and the Fort Union regionand about 40 times larger than the undevel-oped Federal reserves in the Montana portionof the basin. Furthermore, less than 1 percentof the undeveloped reserves in the Wyomingportion of the Powder River basin have unfa-vorable development potential and over 80percent have favorable development poten-tial. The leases with unfavorable develop-ment potential in the Wyoming portion of thePowder River basin have poor property char-acteristics and little chance of being inte-grated with another coal property. The own-ers of the leases have given no indication thatthey will be developed. Two of the leases areauthorized for trade under provisions of Pub-lic Law 95-554. * The undeveloped reserves inthe 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 potentialNumber Number

Number of R e c o v e r - N u m b e r o f Recover-Of 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 LMFort Union . . . . . . . 1 1 320 s 3 2 3,912 LM

Unfavorable development potential a

NumberNumber of Recover-

Of lease ableleases blocks Acres reserves c

4 4 522 s4 4 522 s

Totals. . . . . . . . . . . . . 38 18 69,145 3.5 11 8 37,878 0.76 16 14 11,446 0.31aTWO 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 UN-FAVORABLE 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)bFIVE 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 OFTHESE LEASES.

Cln bllions of tons


. . .-


basin represent a substantial pool of newcoal production for the 1980’s.

The three coalfields with Federal coalleases in southern Wyoming have 18 unde-veloped leases (11 blocks), covering 30,000acres and containing nearly 300 million tonsof recoverable reserves. Less than 10 percentof these reserves, in six small leases withpoor property characteristics, have unfavor-able development potential.

Ten undeveloped leases are located in theFort Union region. These leases cover 9,850acres and contain over 0.3 billion tons of re-coverable reserves. Two leases with unfavor-able development potential in the Montanaportion of the Fort Union region contain mostof these reserves. Of the four leases with un-favorable development prospects in the NorthDakota portion of the region, two were minedout before passage of the Surface MiningControl and Reclamation Act of 1977. Sinceno mine plan was submitted to the Office ofSurface Mining they were classified as unde-veloped. The lease with favorable develop-

ment potential (located in the North Dakotaportion of the Fort Union region) has verysmall reserves of leonardite, an oxidized formof lignite. Development of two of the threeleases with uncertain development potentialhinges on the availability of adequate trans-portation (see ch. 8).

Production Prospects for UndevelopedLeases With Favorable and UncertainDevelopment Potential

Table 53 summarizes the production pros-pects of undeveloped leases with favorable oruncertain development potential in NorthDakota, Montana and Wyoming. Productionfrom leases with unfavorable developmentpotential is assumed to be zero through 1991.

Under favorable* market conditions, cur-rently undeveloped leases in Wyoming, Mon-tana, and North Dakota could produce nearly78 million tons of coal in 1991. Nearly 65 mil-lion 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 Riverbasin. Under weak market conditions, pro-duction from currently undeveloped leases inthe three-State area is likely to be only about21 million tons in 1991, with about 17 milliontons (81 percent) coming from the PowderRiver basin.

The wide range of 17 million to 65 milliontons in estimated production from PowderRiver basin undeveloped leases in 1991 iscaused by demand uncertainty. Delivery of 17million tons of coal in 1991 from presentlyundeveloped leases in the Powder River basinhas been contracted for; markets would haveto be developed for the rest. All leases withuncertain development potential in the Pow-der River basin have unfavorable productionprospects for 1986 and 1991 (see ch. 7).

In southern Wyoming, production from 12presently undeveloped leases is estimated torange between 4 million and 12 million tonsby 1991. The lower production could beachieved by 1986; much of the remainder de-pends on the pace of development of aplanned synfuels facility. Presently undevel-oped leases will be the only source of newFederal mine capacity in southern Wyoming.

A Federal mine containing a small leonar-dite lease in North Dakota may be producing50,000 tons per year by 1991, and one leaseblock in North Dakota with uncertain devel-opment potential because of transportationuncertainties may be producing up to 1 mil-lion tons per year by 1991.

Diligence

Diligent Development Analysis

The Mineral Leasing Act of 1920 providesthat each Federal coal lease is held subject tothe conditions of diligent development andcontinuous operation. In 1976, DOI issuedregulations defining diligent development forFederal coal leases as actual production ofcoal in commercial quantities from the leaseor from the logical mining unit (LMU) of whichthe lease is a part by June 1, 1986 or withinten years after the lease is issued, whicheveris later. Leases that do not meet this minimumproduction requirement can be canceled.Under certain conditions, the period for pro-ducing the minimum amount for achievementof diligence can be extended for up to 5 yearsto June 1, 1991, for leases issued beforepassage of FCLAA.

Enforcement of DOI's diligent developmentrequirements for pre-FCLAA leases is an im-portant issue in the management of existingleases, not only because of the controversy in-

volving the applicability of the regulations,but also because of the potential administra-tive requirements on DOI in handling re-quests for extensions or approvals of en-larged LMUS, and cancellations. Moreover,after 1986, new Federal leases cannot beissued to any lessee, including a pre-FCLAAlessee, who is holding a lease from which hehas not produced coal in commercial quan-tities during the previous 10 years,

OTA made a rough comparison of its esti-mates of future production from Federalleases with DOI’s diligent production require-ments to determine: 1) how many leases arelikely to meet diligence by 1986, and 2) assum-ing that extensions were granted in manycases under the existing guidelines, the likeli-hood for other leases meeting diligence by1991. The following sections summarizebriefly the results of OTA’s diligence analy-sis. See chapter 9 for a description of theissues related to current diligent developmentregulations.


Comparison of Production FromFederal Leases and DiligentDevelopment Requirements

OTA compared the planned and estimatedproduction from existing Federal leases withthe minimum production requirements set bythe 1976 DOI regulations defining diligent de-velopment for pre-FCLAA leases. The anal-ysis covered the 502 leases in the SouthernRocky Mountain and Northern Great Plainsregions including about 30 post-FCLAAleases issued as production maintenance,hardship, or bypass leases associated withactive mines. * Almost all of these post-FCLAA leases will meet diligence as part ofthe larger mining operations,

OTA used mine plan data and informationfrom mine operators and Government agen-cies. Each approved or pending mine plan oreach undeveloped lease block was consideredto be an approximate logical mining opera-tion. (The term approximate logical miningoperation was used so as not to confuse mineplan and lease block units with designated orapproved LMUS as defined by DOI regula-tions.) In assessing a lessee’s prospects formeeting diligence, OTA used the Federalmine production estimates presented earlier,In deriving these production estimates, OTAconsidered many variables that could, inturn, affect the lessee’s ability to meet dili-gence, such as the amount and quality of re-serves, mine type, transportation availability,and present and projected coal demand (seech. 2 of this report for further discussion ofthe methodology used in reaching productionestimates).

In conducting this analysis, OTA made thefollowing assumptions:

1. The mining operations will meet themine plan production schedules or, if nomine plan is available, the mining opera-tions will meet OTA’s estimated produc-tion schedule. OTA estimated the earli-est feasible year for commercial produc-tion for leases without plans.

*See the Oklahoma section at the end of this chapter for adiscussion of diligence prospects for Oklahoma leases.

2.

3.

The reserves and production from theapproximate logical mining operations(either the total mine plan area or theFederal lease block) were used in assess-ing prospects for meeting diligence.Mines were presumed to meet diligencefor all Federal leases in the unit if theyproduced at least 2½ percent of thetotal mine plan reserves by 1986 or1991. (Without detailed information onthe mining sequence and geometry foreach mine, OTA was not able to cal-culate compliance on a lease by leasebasis).All leases with planned production andthose undeveloped leases with favorableor uncertain development prospects thatare likely to start producing in 10 yearswere assumed to receive extensions ofthe diligence period to 1991 if they didnot produce enough to meet diligence by1986. Under current diligence guide-lines, some mines, particularly small-and medium-sized underground oper-ations producing under 2 million tonsper year, might have difficulty qualifyingfor extensions. Nevertheless, it wasassumed for purposes of this analysisthat they would be able to negotiate anextension. OTA estimates that the num-ber of new mines and leases that arelikely to be producing by 1991 and thatcould not qualify for an extension undera broad interpretation of the diligenceguidelines is very small,

The results of OTA’s analysis for leases inthe six major Western Federal coal Statesare described in the following sections.

Diligent Development in Colorado,New Mexico, and Utah

Southern Rocky Mountain region States(Colorado, New Mexico, and Utah) have 360Federal coal leases. Over 60 percent (221leases) of the leases in this region are in-cluded in currently approved or pending mineplans. Of the remaining 139 leases withoutmine plans, OTA’s analysis identified 96leases that potentially could be producing by

- —- . - --- - . -- .— -— - - . . _ -_ . - — - —


1991. The results of OTA’s diligence analysisare summarized in table 54 and figure 31.The analysis shows that by 1986, all 113 ofthe leases in approved mine plans, 22 leasesin pending mine plans and one undevelopedlease will probably have satisfied the produc-tion requirements for diligence. By 1991another 110 leases could possibly meet dil-igence, assuming that the lessees receive ex-tensions to the diligence period. A total of 246leases, (68 percent of the leases) with 73 per-cent of the Federal lease reserves in theSouthern Rocky Mountain region could meet,or surpass, the production requirements fordiligence by 1991.

The percentages of leases and reserves ineach diligence category are relatively evenlydistributed for the region as a whole (see fig.31), however, there is much less correspond-ence between reserves and leases meetingdiligence when these percentages are calcu-lated on a State basis, as shown in figure 32.

In Colorado, about 80 percent of the leasesand 93 percent of the lease reserves couldpossibly meet diligence; however, half of thereserves contained in only 26 percent of theleases are uncertain to meet diligence be-

cause of uncertainties in the pace and scaleof proposed development. The 19 percent ofthe leases in Colorado that are unlikely tomeet diligence contain only 7 percent of theFederal lease reserves.

In New Mexico, nine leases, 31 percent ofthe leases in the State, are unlikely to meetdiligence. These leases, however, contain lessthan 1 percent of the Federal lease reserves.Thus, in New Mexico, 69 percent of the leaseswith over 99 percent of Federal reservesunder lease are expected to meet diligence.

In Utah, about 40 percent of the leases inthe State and 44 percent of the lease reservesare unlikely to meet diligence by 1991. Mostof the lease reserves (1.4 billion tons) in Utahthat will not meet diligence are contained in61 leases on the Kaiparowits Plateau thatcould be producing by 1991 but which are un-likely to do so and, in any event, will not haveproduced enough to meet diligence by 1991.Most of the leases and reserves in active, pro-posed, or potential new mines in central Utah(95 leases—roughly 46 percent of leases andreserves in the State) will probably achievediligence 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 achievediligence by 1986 diligence by 1991 diligence by 1991 diligence by 1991

Number Number Number Number NumberNumber o f Recov- Number of Recov- Number of Recov- Number of Recov- Number of Recov-

Of m i n i n g e r a b l e o f m i n i n g e r a b l e o f m i n i n g e r a b l e o f m i n i n g e r a b l e o f mining erableState leases units reserves leases units reserves units reserves leases units reserves leases units reserves

———.


Figure 31 .— Diligent Development Summary forthe Southern Rocky Mountain Region

(percent of reserves)

Numberof

leases

136

15

95

114

Percentof

leases

36

4

26

32

Reserves a

2.0

0.3

2.0

1.6

Percentof

reserves

34

5

34

27


Leases That Are Likely To MeetDiligence by 1986

In the Southern Rocky Mountain States,136 leases with a total of 2 billion tons of Fed-eral reserves— about 34 percent of the Fed-eral reserves under lease in the region— arelikely to have met diligence by 1986. All of themines are expected to meet continuous opera-tions requirements and to be mined out within40 years at planned production rates.

According to projected production sched-ules contained in the mine plans, all of the113 leases included or associated with the 35mines with approved mining plans will havemet diligence for the total mine plan reservesby June 1, 1986. Many, if not most, of these

mines have already produced this amountand many of the individual leases have, infact, already produced enough to meet dili-gence. In those cases where leases have notproduced the minimum amounts by 1986, thelessees could either request extensions or ap-proval of enlarged LMUs combining both cur-rently producing and nonproducing mineareas so that aggregate production can beused to meet the diligence requirement.

Another 22 leases in 10 pending mine plansare also likely to achieve diligence by 1986according to mine plan production schedules.One currently undeveloped lease in Coloradois expected to begin production before 1986and thus, will meet diligence. It is possiblethat other undeveloped leases could achievediligence by 1986 by inclusion with DOI ap-proval in adjacent active mining units ownedby other lessees through assignment or oper-ating agreements. This would involve fewerthan 10 leases in the Southern Rocky Moun-tain region because of the requirement thatal l areas in an approved LMU must becontiguous.

Leases That Are Likely To MeetDiligence by 1991

By 1991, 15 more leases in eight mines witha total of 315 million tons of Federal leasereserves are expected to meet diligence re-quirements. These eight mines, including sixleases in Colorado, one in New Mexico, andeight in Utah, represent 4 percent of theleases and 5 percent of Federal coal reservesin the region. All of these leases are in pro-posed mine plans currently under review. Atleast three mines are not scheduled to begincommercial production until 1986 or later.The eight mines include two small mines thatare being reopened on previously minedleases, one new, large surface mine, and onemine that would combine surface and under-ground recovery methods. Another mine is acaptive operation that would supply a newpowerplant that has been delayed, and stillone other has been suggested by proponentsas one of the suppliers for a proposed coalgasification plant in Utah. The remaining two

— — — ——. . - —--— - — -— - — -- . -—


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.


mines are underground operations that willsell to utilities and industrial users.

Leases That Are Uncertain To MeetDiligence by 1991

OTA found that 95 leases in 35 approx-imate logical mining operations with about 2billion tons of recoverable Federal reservesmay not meet diligence requirements by 1991.Roughly 26 percent of the leases and 34 per-cent of the leased reserves in the SouthernRocky Mountain region could possiblyachieve diligence by 1991; however, OTAfound that these leases face some uncertain-ties regarding the pace or scale of proposedmining activities or in defining the LMUreserves. There are several reasons whysome of these leases might not meet diligence:The date of initial production for some minesis uncertain because of delays in constructionof associated electric powerplants or trans-portation systems. For several lease tracts

with very large underground reserves inmultiple seams, it is difficult to predict howmany seams will eventually be included in theLMU reserves, since that determination will,in part, depend on the sequence of mining.Perhaps the greatest uncertainty is that thedevelopment plans of several lessees withlarge tracts of good quality minable reserveshave not yet been announced. Productionfrom captive mines that are planned as re-placement capacity for existing operations isdependent on exhaustion of the economicallyrecoverable reserves in existing mines. Insome cases, the new captive mines are notcontiguous with the existing operations, sothey could not be combined with producingmines to meet diligence under current law.

Utah has 60 leases that are uncertain tomeet diligence by 1991 including 28 leases inthe proposed Alton surface mine with over200 million tons of recoverable Federal re-serves. 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 thereserves that are uncertain to meet diligencein the three-State area. The difficulties inAlton’s proposed development plans are dis-cussed earlier in the chapter and in the Utahappendix.

Colorado has 33 leases in 18 units thatmight not meet diligence, including two pend-ing mine plans. One of these, Arco’s Mt. Gun-nison Mine, has a large amount of recover-able reserves in multiple seams, It is possiblethat the logical mining unit reserves could bedefined by the U.S. Geological Survey as lessthan the total reserves by including only theseams commonly mined in the region. If so,the mine could meet diligence by 1991, andperhaps, even by 1986, since at least onelease in the mine has already produced coal,

Leases That Are Unlikely To MeetDiligence by 1991

Nearly one-third of the leases in theSouthern Rocky Mountain States, 114 leases,with 1.6 billion tons of Federal reserves in 60mining units, are unlikely to achieve diligentdevelopment. These include 37 leases thatare in three proposed new mine plans—onesmall mine in Colorado and two mine com-plexes on the Kaiparowits Plateau in South-western Utah. Sixty-eight leases that areunlikely to meet diligence by 1991 are locatedin southwestern Utah. A total of 61 Kai-parowits leases in six blocks with 1.4 billiontons of reserves have some potential for de-velopment according to OTA’s analysis, Buteven if the lessees began production by 1987(probably the earliest feasible date), it isunlikely that they would be able to produceenough to meet diligence by 1991 because ofthe large amount of reserves involved. More-over, it is unlikely that a new coal transpor-tation system connecting Southwestern Utahwith potential markets will be operational by1991. The remaining 53 leases in the three-State region are unlikely to meet diligencebecause they are unlikely to be mined in thenext decade. These nonproducing leases in-clude many abandoned small mines and otherleases that do not have enough good quality

minable reserves to sustain viable independ-ent mining operations and are not located ad-jacent to other active mines.

Diligent Development in North Dakota,Montana, and Wyoming

The results of the analysis on diligentdevelopment are summarized in table 55 forthe coal regions of Wyoming, Montana, andNorth Dakota. Figure 33 summarizes the re-sults for the Powder River basin, The firstdiligence requirement (production of 21/z per-cent of LMU recoverable reserves by 1986/1991) is the only one summarized in the table;with few exceptions, LMUs which are likelyto meet this requirement appear likely tomeet the additional requirement of contin-uous operation and appear likely to be minedout in 40 years.

The di l igent development analysis forWyoming, Montana, and North Dakota hasreached the following conclusions:

1, Over 60 percent of the leases containingnearly 70 percent of the reserves underFederal lease in these three States arelikely to either meet diligence in 1986 orin 1991,

2. For the Powder River basin, demand forcoal is the dominant factor in whetherleases containing about 1.2 billion tonsof recoverable reserves will meet dili-gence by 1991.

3. Over 90 percent of the 1.5 billion tons of

4

recoverable reserves contained in leasesunlikely to achieve diligence by 1991 inthe Powder River basin are suitable onlyfor onsite synfuels development; andnearly 40 percent (0.6 billion tons) aresuitable only for in situ gasification, as-suming that technology is developed.For southern Wyoming, leases contain-ing most of the reserves should meet dili-gence by 1986 under expected marketconditions, The principal uncertainty inwhether leases containing essentially allof the reserves will meet diligence by1991 is the pace of development of a syn-fuels project.

— ——— .-. . -. -.— -.—


Table 55.—Diligent Development Summary

Unlikely to achieve diligence byUncertain 1991

Total Total Federal Likely to Likely to whether will Favorable ornumber of lease recover- achieve achieve achieve uncertain Unfavorable

Ieases/ able reserves diligence diligence diligence development developmentState/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)

aThese 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.Cln 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 metdiligence 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)



5. In the Fort Union region, all leases in ap-proved and pending mine plans (withabout 40 percent of the Federal reservesunder lease in the region) are likely tomeet diligence by 1986. However, onlyone very small undeveloped lease is like-ly to meet diligence even by 1991. Ade-quate transportation constitutes an un-certainty in whether two other leaseswill meet diligence by 1991.

Powder River BasinAs table 55 and figure 33 indicate, there

are 73 leases in 38 lease blocks in the PowderRiver basin of Wyoming and Montana. Fed-eral reserves under lease total 9.2 billion tonsin the Powder River basin, of which 10 per-cent, or 900 million tons, are in the Montanaportion. Seventy percent of the recoverablereserves under lease in the Powder Riverbasin, or 6.5 billion tons, are likely to meet

-- . - . . _


Figure 33.— Diligent Development Summary for thePowder River Basin

The Powder River basin Montana portion of the73 Leases Powder River basin

38 Lease blocks I 1 5 L e a s e s

9.2 Billion tons of recoverable I 8 Lease blocksreserves under Federal lease ! 0.9 Billion tons

I /I /

Wyoming por t ion o f thePowder River basin

58 Leases30 Lease blocks8.3 Bi l l ion tons

KeyPercent

Rese rves a of reserves

5 2 %1.7 18%

diligence by 1991: 1.2 1 3 %1 6 %

aBillions of tons.


diligence by 1986 or 1991. Thirteen percent,or 1.2 billion tons, are uncertain to achievediligence by 1991 and 16 percent, or 1.5 bil-lion tons, are unlikely to achieve diligence by1991,

With two exceptions, the 18 lease blocks inthe Powder River basin likely to achieve dili-gence by 1986 are associated with producingmines or are in approved mine plans. Withone exception, all these lease blocks pres-ently have contracts to deliver coal by 1986or earlier. * Of the four lease blocks** likely

*PPL is conductng a feasibility study to determine whetheror not its Philllps Creek ( 1 ) leases should be integrated with theDave Johnston Mine. According to a company spokesman, theleases are likely to be added to the mine, in which case, eventhough the leases themselves are unlikely to be mined until1991 or later, they would meet diligence as part of the logicalmining unit. North Antelope Coal Co, ’s North Antelope leasedoes not yet have an approved mine plan but has a contract for1984 delivery of coal.

* *South Rawhide, Rochelle, Antelope, Rojo Caballos. In thecase 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 havecontracts for coal delivery before 1991. (Con-tracts are one of the criteria for granting dili-gence extensions).

The six lease blocks*** which are uncer-tain to achieve diligence by 1991 are all unde-veloped; none of them presently has contractsfor 1991. However, all the lease blocks havefavorable development potential, and thelessees are working to develop their proper-ties. Applications for extensions to diligenceare expected to be filed for all of these blocks.Five of the six lease blocks are being plannedas large surface mines, with capacities of 5million tons per year or more, and would thusprobably qualify for a diligence extensionunder the second (large mine) extension cri-terion. The sixth has a planned capacity of 4million tons per year. However, the level ofdemand for Powder River basin coal is an im-portant factor in their achieving diligence. Ifdemand in 1991 is at the OTA high demandscenario level of 275 million tons per year, allof these lease blocks would likely meet dili-gence by 1991. However, if demand in 1991 isat the OTA low demand scenario level of 163million tons per year, it is possible that noneof these lease blocks will even go into pro-duction by 1991. (See ch. 7 for a descriptionof the OTA high and low demand scenariosfor Powder River basin coal.)

Six undeveloped lease blocks are unlikelyto achieve diligence by 1991 even though theydo not have unfavorable development poten-t ial . Production on four of these (LakedeSmet, Bass Trust, Belco, Gulf [l&z)) is con-tingent on synfuels development; for three ofthe four, production is contingent on in situgasification development. Although little de-velopment activity has occurred on the fifth

output from the existing Rawhide and Caballo Mines, reducingproduction at these two mines, if contracts cannot be obtainedfor South Rawhide itself. Diligence could then be achieved forall three mines: for Rawhide and Caballo by 1986: for SouthRawhide by 1991.

***Dry Fork, East Gillette Federal, N. Rochelle, CX Ranch(Consol), CX Ranch (PKS), Wildcat.

. . . .


(East Wyodak), the lessee (Peabody) hasstrongly stated its intent to develop the prop-erty. The sixth lease, Pearl, is in Montana.The lessee, Shell, spent considerable sums ondevelopment, including the preparation of anenvironmental impact statement, before sus-pending activity. Shell declares it will resumedevelopment once markets strengthen. All sixare expected to file for diligence extensions.Finally, four undeveloped lease blocks withunfavorable developmentlikely to meet diligence.

Development

potential are un-

Potential and

Southern Wyoming

As table 55 states, there are a total of 41leases in 22 lease blocks in the three coal-fields of southern Wyoming. These leasescontain over 500 million tons of recoverablereserves. Leases containing over 300 milliontons of reserves are likely to achieve diligenceby 1986 and several mines are likely to meetdiligence by 1991. The lease block whoseachievement of diligence is uncertain for1991 is being planned for synfuels.

Production Prospects ofFederal Coal Leases in Oklahoma

There are 46 Federal coal leases located inthe Oklahoma portion of the Western Interiorcoal region; the region also includes theStates of Arkansas, Kansas, Missouri, andIowa. There are no Federal coal leases in thelatter four States. Total coal production inOklahoma in 1979 was 5 million tons, or 40percent of total Western Interior productionand over three times the total production ofthe State a decade ago. However, Federal re-serves accounted for only 0.3 million tons ofOklahoma production in 1979.

Approximately 80 percent of the leasedFederal coal in Oklahoma is of high metal-lurgical quality that is used primarily to pro-duce coke for domestic steel production. Vir-tually all of the increase in Oklahoma coalproduction over the last 10 years has beennoncoking coal. Although metallurgical gradecoal can be blended with steam coal to gener-ate electricity, it is unlikely that any newmines with Federal leases in Oklahoma willbe developed to sell metallurgical quality coalprimarily for blending for steam-electric gen-eration. Weak demand is expected for metal-lurgical quality coal over the next 10 years.Captive mining operations, where the parentcompany produces steel or cement, and salesto foreign buyers appear to be the mainsource for Federal coal development in Okla-homa throughout the 1980’s.

Status and Production Prospects ofLeases in Approved Mine Plans

in Oklahoma

There are seven leases in five approvedmine plans in Oklahoma (see table 56). One ofthe seven leases was relinquished in 1980 be-cause of the increase in royalty at the time ofreadjustment. Production on another leasehas been interrupted because of labor dis-putes. The reserves remaining on this leasecan support less than 5 years of commercialproduction. The remaining five leases in ap-proved mine plans or associated with oper-ating mines are currently producing coal orare scheduled to produce coal in the nearfuture. However, only two of these leases inone mine plan are expected to produce coalcontinuously over the next 10 years. Thesetwo leases are likely to meet diligence by1986 or 1991. Of the remaining three leasesin approved mine plans, the reserves on oneare expected to be depleted by 1984, and thereserves on the other two by 1986.

Status and Development Potential ofUndeveloped Leases and Leases inPending Mine Plans in Oklahoma

Thirty-eight leases (20 blocks) of the 46leases 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 ofUndeveloped Leases in Oklahoma

Status of leasesApproved mine plans:

7 leases5 mine plans8,668 acres6 million tons recoverable reserves

Underground: 5.4 million tonsSurface: 0.6 million tons

Pending mine plans:1 lease1 mine plan680 acresSmall underground recoverable reserves

No mine plans:38 leases20 lease blocks64,698 acres179 million tons recoverable reserves

Underground: 169 million tonsSurface: 10 million tons

Development prospects: undeveloped leasesUncertain development prospects:

23 leases7 lease blocks38,334 acres104 million tons recoverable reserves

Unfavorable development prospects:15 leases13 lease blocks26,360 acres75 million tons recoverable reserves—

SOURCE. Office of Technology Assessment,

plans (table 56). None of these leases are ex-pected to be brought into commercial produc-tion by 1991. The production prospects forthe one lease included in a pending mine planare also unfavorable during this period,although the owner of Federal and fee coalnow being mined near this property has ex-pressed interest in acquiring this lease.

Over 90 percent of the recoverable re-serves on undeveloped leases are under-ground reserves. Twenty-five of these leases(8 blocks) have uncertain development poten-tial for 1991; the remaining undevelopedleases have unfavorable development poten-tial for 1991. There are three main reasonsfor the unfavorable production prospects ofthese leases: 1) a depressed metallurgicalcoal market, 2) difficult and costly under-ground mining conditions, and 3) a high Fed-eral royalty relative to royalties charged forfee 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, thePowder River basin of Wyoming and Mon-tana contains the largest pool of undevelopedleased Federal coal reserves with favorabledevelopment potential in the United States.Furthermore, the production of Federalreserves from the Powder River basin nowaccounts for about half of all Federal coalproduction in the country. Because of the im-portant role of this region in Federal coal pro-duction, this chapter examines the PowderRiver basin in more detail, The chapter in-cludes a mine-by-mine examination of the

Federal reserves scheduled to be producedover the next 10 years from currently oper-ating or permitted mines, an analysis of theproduction prospects of each undevelopedlease and preference right lease application(PRLA) in this region, a discussion of the roleof non-Federal mines in Powder River basincoal production, a consideration of demandfor Powder River basin coal in the post-1990period, and an examination of the differentpoints of view on the large-scale new leasingof Federal coal scheduled for the PowderRiver basin in 1982.

Two Demand Scenarios for the Powder River Basin

In order to evaluate the production pros-pects of Federal leases in the Powder Riverbasin, it is necessary to identify the likely de-mand for Powder River basin coal over thenext 10 years. In this analysis, OTA used ahigh demand scenario and a low demand sce-nario developed for the Powder River basincase study. This section considers a range ofdemand forecasts for Powder River basincoal, arrives at a “most likely range” of de-mand for 1985 and 1990, and examines theassumptions about high and low demand usedin the analysis of Federal coal productionprospects in this chapter.

Figure 34 summarizes several recent de-mand forecasts for Powder River basin coalfor 1985 and 1990.1 The Department of En-ergy (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 De-portment of Energy’s August 7, 1980 Report EntitIed: “Pre-liminary National and Regional Coal Production Goals for1985, 1990, and 1995. prepared for the Rocky MountainEnergy Co. (Washington. D. C.: ICF Inc., October 1980).

2. DOE: The 1980 Biennia] Update of National and Regionalcoal Production Goals for 1985, 1990, and 1995 (Washing-ton D. C.: DOE, ]anuarv 1981.)

tric Utility Model) use basically the same com-puter model but vary a number of input as-sumptions (e.g., the overall growth rate ofelectricity demand in the United States) to ar-rive at three projections each for 1985 and1990: low, midlevel (or base), and high. TheSilverman forecasts (made for 1990 but notfor 1985) are computer projections based ona series of different assumptions about elec-tric demand in the market area for NorthernGreat Plains coal, the share of that demand tobe met by coal, and the fraction of that shareto be met by Northern Great Plains coal. TheSebesta and Glass projections are each basedon a detailed examination of utility plans and

3. ICF CEUM: Forecasts and Sensitivity Analyses of WesternCoal Production, prepared for Rocky Mountain Energy Co.(Washington, D. C.: ICF, Inc., November 1980).

4. Sebesta: Demand for Wyoming Coal 1980-1991 Based UponProjected Utility Coal Market and Demand for MontanaCoall 1980-1991 Based Upon Projected Utility Market(Washington, D. C.: OTA, October 1980).

5. Wyoming task force: Result of deliberations of the OTAWyoming task force: Cheyenne, Wyo., October 1980).

6. Glass: Wyoming Coal Production and Summary of CoalContracts (Laramie, Wyo.: Wyoming Geological Survey,1980).

7. Silverman: Preliminary Results from A. Silverman. Uni-versity of Montana, Missoula. Private communication toOTA. Work is funded by OSM.

169

— ------ — . . . . . —


Figure 34.—Powder River Basin Demand Projectionsa

500

400

300

200

100

aseebCalccCalc‘For

synf

0

footnote onulated byulated by1965 all prouels and

.

Final Preliminaryiminsty

~ 2 2 3

193

159

129

iCFCEUM

194

169

136

Other

.

Demand projections d

1985

(173)

(169

(OTA)Wyomingforce (OTGlass c

of

p. 169 for citations.adding Sebesta’s figureadding Sebeata’s figurejections assume zero dforeign export demand.

for thefor 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 marketarea. The Wyoming task force estimate wasreached after a review of the DOE, Sebesta,and Glass projections. Figure 34 also shows

the DOE final production goals. The DOE finalproduction goals and their relation to thepreliminary DOE projections and to other de-mand 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 from129 million tons per year (the DOE low) to 223million tons per year (the DOE high). ICF pro-jections range from 138 million tons per yearto 194 million tons per year; these figuresassume that there will be zero demand forPowder River basin coal for synfuels or forexport to foreign countries.

Although the demand projections for 1985span a wide range, they cluster in a muchnarrower range. The range of 138 milliontons per year to 177 million tons per year in-cludes the ICF low, the DOE preliminary andICF mid, and the Glass, Sebesta, and Wyo-ming task force projections. This range ex-cludes only the ICF and DOE preliminary lowand high projections and the DOE final pro-duction goals.

Two other projections, not shown on figure34, were also examined: the National ElectricReliability Council (NERC)2 projections fortotal U.S. utility* coal requirements and thelong-term forecast of the National Coal Asso-ciation (NCA).3 NERC arrives at an electricaldemand growth rate of 3.7 percent annuallyand a total domestic steam coal requirementof 684 million tons in 1985. NCA assumes anelectrical demand growth rate of 3.5 percentannually and projects total domestic steamcoal demand in 1985 of 727 million tons in itsmidlevel projection. By comparison, ICFassumes an electrical demand growth rate of3.5 percent annually; its midlevel projectionis for 717 million tons of total domestic steamcoal demand in 1985.

‘Electric Power Supply and Demand, 1981-1990 for the Re-gional Rehubiiity Councils of NERC: National Electric Reliability yCouncil: July 1981. The NERC figures do not explicitly projectdemand for Powder River basin coal and must be interpretedusing assumptions about the extent of the Powder River basinmarket area and the market share of Powder River basin coalwithin the assumed market area. Therefore, NERC projectionsare not shown in figure 34.

‘Because 95 percent of Powder River basin coal is pur-chased by utilities, total utility demand is a good measure of de-mand 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 anticipateddemand in 1985 for Western steam coal (ex-cluding lignite) in the market area for PowderRiver basin coal is about 205 million tons.However, other coal competes in this marketarea (see fig. 20). Assuming that the PowderRiver basin share of this market in 1985 is thesame as in 1979, i.e., 65 percent, and that 95percent of the Powder River basin coal willcontinue to go to the utility market, the NERCfigures lead to a demand estimate of 140 mil-lion tons in 1985 for Powder River basin coal,However, Powder River basin coal could cap-ture a larger share of Western steam coal de-mand in its market area in 1985 than in 1979,

OTA High and Low DemandScenarios: 1985

OTA selected the Sebesta projection of 177million tons per year for its high demand sce-nario for 1985. The Sebesta projection ex-ceeds both the DOE preliminary and ICF mid-level projections, the NERC projections as in-terpreted above, and the projections of theWyoming State Geological Survey (Glass,1980). The Wyoming task force estimated1985 demand to be between the Glass andSebesta estimates.

OTA selected the ICF low projection of 138million tons per year for its low demand sce-nario for 1985, This figure is lower than pres-ently contracted Powder River basin produc-tion for 1985 (about 160 million tons per year)and allows analysis of the implications of a“worst case” scenario on development anddiligence.

Demand Projections for 1990

For 1990, the projections shown in figure34 vary widely, and the clustering of projec-tions, although marked, offers less reliableguidance than for 1985. Projections rangefrom 163 million tons per year (the ICF low) to438 million tons per year (the DOE prelim-inary high), but the range of 163 million tonsper year to 275 million tons per year includes

— . .- . — —— — --- -


all but the DOE preliminary and ICF high pro-jections and the DOE mid and high final pro-duction goals.

For 1990, the projections of Sebesta andSilverman in figure 34 include only demandfor steam coal. However, the ICF, DOE, andWyoming task force projections include de-mand for coal for synfuel, for export toforeign countries, and for industrial use.The ICF midlevel projection includes an esti-mate of about 10 million tons for synfuelsfrom Montana and Wyoming and a total de-mand of 8 million tons of subbituminous lowsulfur coal for foreign export; it is unclearfrom the ICF report, however, how much ofthis 8 million tons is projected to come fromthe Powder River basin. The DOE midlevelpreliminary forecast assumes about 30 mil-lion tons of coal from Montana and Wyomingfor synfuels in 1990, and the DOE final pro-duction goals assume about 45 million tons ofcoal from these two States for synfuels. Forcomparison, the ICF base (midlevel) projec-tion estimates a total demand throughout thecountry of less than 50 million tons of coal forsynfuels in 1990; the NCA “most likely” pro-jection is 38 million tons. The DOE midlevelpreliminary forecast estimates that about100 million tons of coal will be used for syn-fuels production in the United States in 1990;the DOE final production goals assume about200 million tons.

The Wyoming task force rated one synfuelsproperty in the Powder River basin as havingfavorable production prospects for 1991—the Rochelle leaseblock with production pro-jected at 6 million tons per year for 1991. *Other synfuels properties in the PowderRiver basin were judged by the task force asunlikely to be producing by 1991. This projec-tion is in agreement with the ICF projection of10 million tons per year from all of Wyomingand Montana, as another property, Cherokee,may come into production for synfuels insouthern Wyoming.

*The 1991 production prospects of the Rochelle lease blockhave become less favorable since the Wyoming task force meet-ing in October 1980, because of the withdrawal of two of thepartners in the Panhandle Eastern Wycoal Gas Project, towhich Rochelle’s coal is contracted.

NERC projections, which include only esti-mates of electric utility demand for coal, arenot shown in figure 34 for reasons explainedin footnote 2 on p. 171. The NERC figure of881 million tons for total U.S. utility coal de-mand in 1990 is comparable to the ICF mid-level number of 862 million tons, but is lowerthan the DOE preliminary midlevel number of906 million tons, NCA’s most likely projectionof 935 million tons, and the DOE final mid-level production goal of 994 million tons. Ifthe Powder River basin captures the sameshare of the market for Western steam coalin 1990 as in 1979, (i. e., 65 percent, ) NERCfigures translate to a demand of approx-imately 180 million tons for steam coal. Usingthe NERC estimated demand for all coal in thePowder River basin market area as the base,not just demand for Western coal, demandfor Powder River basin steam coal in 1990(assuming a 37 percent market share) wouldbe about 170 million tons. Adding demand forindustrial coal, synfuels, and foreign export,NERC projections translate to demand forPowder River basin coal in 1990 of about ZO O

million tons, assuming the Powder Riverbasin market share of Western coal and of allcoal remains the same in 1990 as in 1979.

The Powder River basin share of the steamcoal market may expand over the next dec-ade. Assuming all new Western steam coaldemand is for Powder River basin coal in thePowder River basin market area, but that theold demand for Western steam coal retainsits 1979 split between Powder River basinand non-Powder River basin coal, NERC pro-jections translate to a demand estimate forPowder River basin coal in 1990 of approx-imately 255 million tons for all uses. * * NERCprojections, interpreted as described above,give a range of demand for Powder Riverbasin coal in 1990 of about 200 million toabout 255 million tons; these calculations sug-gest that the DOE preliminary midlevel goalsare high. * * *

* *Including demand for industrial uses (5 percent additionto utility demand), synfuels and foreign export (about 10 mil-lion tons per year).

* * *The same calculations using NERC’s projections for util-ity Western coal demand published 1 year earlier, in July 1980,lead to a demand range of 235 million to 305 million Ions for


OTA High and Low DemandScenarios: 1990

For 1990, OTA selected the DOE prelim-inary midlevel forecast of 275 million tons peryear for its high demand scenario, and theICF projection of 163 million tons per year forits low demand scenario. The Wyoming taskforce projection of 206 million tons per year,representing the estimate of informed re-gional opinion, falls slightly below the aver-age of these two demand levels. The high sce-nario level of 275 million tons per year is 33percent above the Wyoming task force esti-mate, and the low scenario level of 163 mil-lion tons per year is 79 percent of the Wyo-ming task force estimate. OTA’s selected lowprojection is lower than present contracts for1990 delivery of Powder River basin coal (186million tons per year) and thus allows anal-ysis of a “worst case” for development anddiligence,

Production Under OTA's TwoDemand Scenarios

The next two sections examine the produc-tion prospects of all Federal coal leases in thePowder River basin for 1986 and 1991. Thefirst of these sections focuses on the leases in-cluded in producing mines or approved mineplans; the second on undeveloped leases. Thissection describes the approach used by OTAto allocate production under the high and lowdemand scenarios.

In its two demand scenarios, OTA allo-cated potential production among:

1. operating and permitted Federal mines;2. leases with no mine plans* (undeveloped

leases) but with favorable developmentpotential; and

3. non-Federal mines.

— .. —-Powder River basin coal in 1990. The difference between thedemands derived from NERC 1980 and 1981 projections iscaused by the fact that in 1981 NERC projected 50 million Ionsless 1990 demand for Western coal than it did in 1980.

*There are two mines in preliminary permit review in thePowder River basin (South Rawhide and Antelope). Because ofthe early stages of development of these mine plans, theseleases were analyzed with the undeveloped leases.

Under the high demand scenario, demand forPowder River basin coal in 1985 and 1990 isabove present contracts for those years.Thus, for all three categories of coal produc-tion, present contracts for 1985 and 1990 areassumed to be met in full under the high de-mand scenario. Under the low demand sce-nario, demand for Powder River basin coal in1985 is about 85 percent of present contractsfor 1985, and about 90 percent of presentcontracts for 1990. Thus, under the high de-mand scenario, all Federal and non-Federalmines and all undeveloped leases with con-tracts are assumed to be producing at orabove the current contract level for thoseyears; under the low demand scenario, theyare assumed to be producing at about 85 to 90percent of the current contract level for thoseyears.

For both 1985 and 1990, OTA selected theICF low demand projections for its low de-mand scenarios. For each of these years,under the low demand scenario, no undevel-oped leases without current contracts go intoproduction. With the exception of three leaseblocks (Antelope, North Antelope, and Ro-chelle), the undeveloped leases in the PowderRiver basin do not yet have contracts. Underthe high demand scenario, many undevelopedleases would likely go into production by 1990because demand under this scenario requiresconsiderably more production than the sumof current contracts for future delivery ofcoal. The difference between demand andcon t rac t s i s a l loca ted among cur ren t lyoperating and permitted Federal mines, non-Federal mines, and undeveloped leases withfavorable production prospects. No produc-tion is allocated to leases that, for technicalor economic reasons, are unlikely to bebrought into production by 1990.

A share of the demand increase is assignedby formula to each Federal mine or undevel-oped lease block likely to be producing in1985 or 1990, with only its projected capacityand its contracts (if any) entering the calcula-tion, Allocation by formula is arbitrary. Somelessees will be more successful than others incompeting for new coal contracts. Productionwill be higher from some mines than OTA es-

— . — — . . -— — — — — .


timates indicate, and lower from others. In al mines plans under the high and low de-the following section, OTA’s estimates of pro- mand scenarios are compared with the les-duction from operating and permitted Feder- sees’ own estimates.

Federal Leases in Approved Mine Plans andOperating Mines in the Powder River Basin

This section assesses the production pros-pects for Federal coal leases in approvedmine plans and operating mines in the Pow-der River basin. Tables 57 and 58 summarizetechnical and production data for each oper-ating or permitted mine with Federal coalreserves in the Powder River basin. Together,these tables provide an overview of recentFederal mine capacity and production in thebasin and expected developments in the com-ing decade.

Table 57 presents the following informa-tion for each mine in the Powder River basinwith 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

AcreageTotal

permittedNumber of Federala mine Federal Cumulative

Federal lease plan lease First coal production Production RemainingMine name Lessee c 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 ResourcesCabal 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.

51141

(billion tons)

HMLM

LHM

L

6,1982,3513,0163,1374,378

8,2274,3072,3474,9619,410

(million tons) (million tons)

1920’s 41.3 11.7 40 years1969 9.3 2.5 38 years1980 0.0 0.0 25 years1972 55.7 7.1 21 years1978 5.9 5.9 27 plus years

12 0.8 19,080

1,4677,3934,3043,240

10,0406,2805,8158,2329,5454,9597,560

29,252

6005,6973,5201,8805,3602,4013,9596,5605,8064,3525,864

19811977197819221979197319831976198119781977

112

0.07.24.06.31.4

53.80.09.80.06.5

10.3

27.2

0.0 16 years3.6 26 years3.7 37 years2.4 43 years1.3 44 years

15.0 19 years0.0 27 years3.8 26 years0.0 35 years4.7 22 years6.2 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 71.7aNon-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)


SOURCE: Office of Technology Assessment,

— —- — .


Table 58.—Powder River Basin Federal Mine Production, Capacity, and Contracts(millions of tons per year)

1980 1986 OTA estimated 1991 OTA estimatedmine mine production-1986 Contracts Lessees’

designmine production-1991 Contracts Lessees’

Production design demand scenario for estimates of design demand scenario forMine name

estimates ofcapacity 1980 capacity H L 1986 p r o d u c t i o n - 1 9 8 6 c a p a c i t y H L 1991 production-1991

MontanaR o s e b u d 14.2 10.4 19.6 19.5 16.3 19.4 19.4 19.8 19.8 17.5B i g S k y . 4.6 3.0 4.6 4.6 3.9 4,6 4.6 4.6 4.6 4.1S p r i n g C r e e k 0.2 01 10.0 7.6 5.9 7.0 7.6 10 9.2 6,2W e s t D e c k e r 10,4 5.6 10,4 7.5 5.6 6.7 8.0 10.4 9 4 5 9East 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

WyomingBuckskin ., 0 0 6.2 6.2 5.2 6.2 6,2 6.2 6.2 5.5Rawhide andCaballo . . . 12+4 6.4 24+ 12 20.4 13.5 16.0 31.0 24+ 12 30.7 14.2

Eagle Butte andBelle 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 4.0R O jo Caballos 0 0 9 4.5 2.7 2.6 9.0 15 12.5 5.0Cordero ... . . 24 6.5 24 13,9 9.3 11.0 16.0 24 20.5 9,7Coal Creek. . 0 0 12 6.4 4,0 4.8 9.8 12 101 4.2Jacobs Ranch 16 8.2 16 13.6 11.1 13.2 15.6 16 15.3 11.7B l a c k T h u n d e r . 1 4 10.5 20.5 17.4 13.9 16.5 17.0 20.5 19,4 14.6Dave Johnston 3.8 3.8 3.8 3.7 3.1 3,7 3.7 3.6 3.6 3 3

198 19.84.6 4 67.0 10,16 7 8.06.7 6 6

45 49

6.2 6.2

16.0 360

33.0 3204,5 4 55.6 15.0

11.0 24.04.8 12

13.2 15616.5 20.537 3 7

Wyomingtotals 112 62.5 169 123 93 110 144 175 159 101 115 170

Powder Riverbas in to ta ls . 148 87.2 220 169 130 154 191 226 209 141 159 219

aThis capacity estimate based on remaining reserves.


• recent production levels; and● remaining mine life.

Table 58 summarizes information on capac-ity, production, and contracts for this decade.Mine design capacity and production are pre-sented for 1980. Capacity figures for 1986and 1991 are then followed by estimated pro-duction for each of these years under the highand low demand scenarios discussed in thepreceding section, The amount of coal al-ready contracted for 1986 and 1991 is listednext, along with the production estimated byeach lessee. Contract information and com-pany estimates of production are taken fromlessee mine plans submitted to the Office ofSurface Mining (OSM) or from communi-cations with the lessees.

Size of Federal Mines in thePowder River Basin

Acreage: There are over 100,000 per-mitted mine plan acres for mines with Fed-eral leases in the Powder River basin; 85,000of these acres contain Federal reserves.Eighty percent of the permitted acreage is lo-

cated in the Wyoming section of the basin,Not all of the Federal lease acreage asso-ciated with Federal mines is necessarily in-cluded in the permitted mine plan. In theMontana portion of the Powder River basin,for example, the five Federal leases asso-ciated with the Rosebud Mine cover 8,227acres but only 75 percent of this acreage ispermitted in the mine plan; the total acreagepermitted in the mine plan at the East DeckerMine is less than 4,400 acres although thefour Federal leases associated with this minecover approximately 9,400 acres,

Lease acreage is important for gaging po-tential environmental impacts, but it is notalways a good indicator of mine capacity orproduction potential. The Dave JohnstonMine, for example, has a small capacity (3.8million tons per year) compared to othermines in the basin even though it includes thelargest total Federal lease acres (9,662) andthe greatest number of mine plan acres(14,305) in the basin. This mine has been inproduction since 1958. At present, mining islimited to two seams, which average about 45ft in thickness and are captive to a power-


plant that can use only 3.8 million tons peryear.

Reserves: About 90 percent of the nearly 6billion tons of recoverable reserves asso-ciated with approved mine plans or operatingmines with Federal leases in the PowderRiver basin are Federal reserves. As table 57shows, the Federal lease reserves associatedwith these approved mine plans and miningoperations are generally large (over 180 mil-lion tons). Only three of these mines have Fed-eral lease reserves of less than 100 milliontons.

Mine Life: Mines with Federal leases in thePowder River basin have substantial produc-tion potential manifested by the mine life re-maining for these properties. Estimates forremaining mine life in table 57 are taken fromthe lessees’ mine plans. Mine life estimationsare calculated by dividing the remaining re-coverable reserves by the lessees’ long termannual production plans. Should productionfall below the lessees’ estimates, then minelife would be extended. This could happen ina number of cases if demand for PowderRiver basin coal in 1990 turns out to be closeto the estimates made by the Wyoming taskforce (see fig. 34) and does not subsequentlyincrease rapidly in the 1990’s. Mine life couldalso be extended if a lessee obtains additionalreserves.

Most of the mines with Federal leases inthe Powder River basin that opened in thelate 1970’s, or are still under construction,are expected to remain in production for atleast 25 years. Only two mines (East Deckerin Montana and Buckskin in Wyoming) willhave a capacity of less than 10 million tonsper year by 1991. The two mines that openedin the 1920’s, Rosebud in Montana and Wyo-dal in Wyoming, are scheduled to remain inproduction for another 40 years. The DaveJohnston Mine, which opened in the late1950’s, has 16 years expected mine life (3.8million tons per year capacity); the Big SkyMine, which opened in 1969, has 38 years ofmine life remaining (4.6 million tons per yearcapacity).

Trends in Mine Capacity andProduction

Most of the 17 mines with Federal leases inthe Powder River basin are currently oper-ating below capacity. These mines produced87 million tons in 1980, 61 million tons lessthan their combined design capacity of 148million tons. The design capacity of thesemines is expected to increase by 50 percent inthis decade from 148 million tons per year in1980 to 226 million tons per year in 1991. Themagnitude of this increase in capacity is illus-trated by a comparison of the Belle Ayr Minein Wyoming with several of the newer minesin the basin. Belle Ayr has achieved the high-est annual production of coal in the UnitedStates since 1977. However, Belle Ayr’s cur-rent capacity (21 million tons per year) isscheduled to be surpassed by three newmines in the basin by 1986: Eagle Butte (25million tons per year), Rawhide (24 milliontons per year), and Cordero (24 million tonsper year). Production at Belle Ayr is expectedto decrease from its present high level.

Demand will dictate whether or not thedesign capacity of mines with Federal leasesin the Powder River basin will be fully usedover the next 10 years. Under OTA’s low de-mand scenario, substantial overcapacity ofthese mines will continue and capacity utili-zation will not move much beyond 60 percentin either 1986 or 1991. * Under OTA’s high de-mand scenario, production at these mineswould reach 77 percent of capacity in 1986and 92 percent of capacity in 1991. Accord-ing to the lessees’ estimates of production,capacity utilization will be 87 percent in 1986and 97 percentsecured for 701986 and 1991.

in 1991. Contracts have beenpercent of capacity for both

*I! is possible that not all of this capacity would be developedif markets for Powder River basin coal were weak. The poten-tial for continued overcapacity in the Powder River basin is in-creased when the undeveloped lease blocks are considered inthe next section,


Expansion of New Federal Minesin the Powder River Basin

Of the 17 mines with Federal leases in thePowder River basin, 11 are relatively new,i.e., have opened since 1976 or will open earlyin this decade. These new mines now accountfor over 90 million tons of capacity and arescheduled to reach a total capacity of over165 million tons per year by 1986, and over170 million tons per year by 1991.

New mines with Federal leases in the Pow-der River basin have generally followed thesame development pattern, reaching a largecapacity and high levels of production withina decade after they open. By 1986, accordingto the lessees’ production plans, most of the11 new Federal mines in the Powder Riverbasin will be producing at least 75 percent ofcapacity. By 1991, according to the lessees’production plans, nearly all of these newmines will be producing at, or nearly at, fullcapacity. Each of these new mines has a con-tractual commitment for production through1991. In some cases these contracts repre-sent a substantial amount of capacity.

Several of these new Federal mines illus-trate the rapid expansion of Federal mine ca-pacity and production in the Powder Riverbasin. For example, the Eagle Butte Mine inCampbell County, produced 3.7 million tons in1979 after opening in 1978. By 1986, EagleButte is likely to be the largest coal mine withFederal leases in the United States with a ca-pacity of 25 million tons per year and produc-tion of 23.8 million tons per year needed to fillits contract obligations. Only Federal re-serves will be mined at Eagle Butte after1985. AMAX has contracts for 90 percent ofthe reserves planned for production at bothits Eagle Butte and Belle Ayr mines. Coalfrom these mines is marketed jointly.

The Black Thunder Mine in CampbellCounty, Wyo., is another example of rapid ex-pansion of Federal mine capacity and produc-tion in the Powder River basin. This mine,which opened in 1977, is scheduled to achievea capacity of 20.5 million tons per year bylate 1981. Production of Federal reserves

should begin at Black Thunder in 1981 and,by 1984, Federal reserves will account for allproduction. Black Thunder has approximate-ly 80 percent of capacity contracted through1991.

The Rawhide Mine in Campbell County,which also opened in 1977, showed low cumu-lative production (7.2 million tons per year) inthe 1976-79 period. However, the lessee ex-pects to be producing at full capacity at arate of 24 million tons per year by 1986, al-though new contracts to achieve this levelhave yet to be signed. This capacity should beavailable in 1985, 8 years after the first coalwas shipped from the mine. The lessee, Car-ter Mining Co., markets coal jointly from itsRawhide and Caballo mines and has con-tracts for 16 million tons per year beginningin 1984. Only Federal reserves will be pro-duced at these mines.

Importance of Federal Reserves

Over the next 10 years, the proportion ofFederal reserves that will be recovered atthese mines will increase substantially. Ofthe 11 new Federal mines in the Powder Riverbasin, three (Rawhide, Eagle Butte, andCaballo) were producing no Federal reservesin 1979. However, by 1986, each of thesethree new mines will produce only from Fed-eral reserves.

The growing importance of Federal re-serves in the Powder River basin is illustratedin table 59. In 1979, Federal reserves ac-counted for 42 percent of the total productionof coal from mines with Federal leases in thePowder River basin. By 1986, according tolessee mine plans, 90 percent of the coal pro-duced from these mines will be from Federalreserves. This percentage is expected to holdfor 1991. *

*Note that the estimated percentage of Federal productiondiffers little between 1986 and 1991 and among the three pro-duction estimates. However, the production of non-Federal re-serves will decrease substantially in the early 1980’s, from 42million tons per year in 1979 to 20 million tons per year in1986 (according to lessee estimates) while, at the same time,the production of Federal reserves will be increasing substan-tially.

- —- ..—. . . - . - — . . — -.. .


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

F e d e r a l : 3 0 OTA low demand scenarioc Total: 130 Total: 141% Federal: 89% 0/0 Federal: 89°/0

Federal: 116 Federal: 1250/0 Federal: 42°/0 Lessee estimatesb,c Total: 191 Total: 219

% Federal: 90% 0/ 0 Federal : %? O /O

Federal: 171 Federal: 201

aFederal mines in currently approved mine plans only.bLessee estimates are taken from the mine plans.CFor 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.


Nonfederal Mines in thePowder River Basin

Five mines with no Federal reserves in thePowder River basin (two in Montana andthree in Wyoming) were responsible for 11.7million tons of coal production in 1980. Thesefive mines had a combined capacity of nearly20 million tons per year compared to 148million tons per year of total Federal minecapacity in the basin. Table 60 compares thecapacity of currently operating and per-mitted Federal mines with non-Federal minesthat have favorable production prospects.Scheduled capacity for these mines is pre-sented for 1986 and 1991. The total non-Fed-

Table 60.—Capacity in the Powder River Basin:Federal and Non-Federal Mines

1980 1986a 1991a

(million (million (milliontons per tons per tons per

year) year) year)

MontanaFederal mines . . . . . . . . 36 52 52Non-Federal mines . . . . 11 13 30

Total . . . . . . . . . . . . . . 47 65 81

WyomingFederal mines . . . . . . . . 112 169 175Non-Federal mines , . . . 9 16 14

Total . . . . . . . . . . . . . . 121 184 189

Powder River basin totalsFederal mines . . . . . . . . 148 220 226Non-Federal mines , . . . 20 29 44

Total , ... , . . . . . . . . . 188 249 270aDoes not include potential capacity from undeveloped Federal leases. See

table 63

eral share of capacity in the basin is unlikelyto go beyond 12 percent in 1986 and 16 per-cent in 1991.

Table 61 presents information on the ca-pacity and contracts for non-Federal mines inthe Powder River basin that are likely to be inproduction by either 1986 or 1991. While thecombined capacity of 12 non-Federal minesin the Powder River basin could increasesubstantially during this decade—to 29 mil-lion tons per year in 1986 and 44 million tonsper year in 1991—only three of these mines

Table 61.— Non-Federal Mine Development in thePowder 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.


now have contracts for a total of 10.1 milliontons per year for 1991.

Estimated Cumulative ProductionUnder OTA’s High and Low Demand

Scenarios for the Powder River Basin1976=91

Table 62 presents information on the cu-mulative production of mines with Federalleases under OTA’s high and low demandscenarios. Cumulative production from thesemines in the basin from 1980-91 under thehigh demand scenario (1,916 million tons) is30 percent more than that projected underthe low demand scenario (1,480 million tons).

In the 1976-79 period, the cumulative pro-duction of mines with Federal leases in theWyoming and Montana sections of the Pow-der River basin were almost identical. How-ever, mines with Federal leases in the Wyo-ming section of the basin, with their largerreserves, will dominate coal production inthis decade. Most of this new production willcome from the nine new mines discussedabove. The Eagle Butte Mine, for example,shipped its first coal in 1978 and producedonly 4 million tons between 1976-79; how-ever, under OTA’s high demand scenario,this mine would produce 95 million tons be-tween 1980-86, and 110 million tons between1987-91. The Cordero Mine, which opened in

Table 62.—OTA Estimated Cumulative Productiona

Under High and Low Demand Scenarios for thePowder River Basin: 1976-91

(millions of tons)

Estimated Estimated EstimatedCumulative cumulative cumulative cumulativeproduction production production production

1976-79 1980-86 1987-91 1980-91

Montana portionof the Powder H -272 H -243 H - 514River basin. . . . . 112 L -232 L -194 L - 425

Wyoming portionof the Powder H -677 H -726 H -1402River basin. . . . . 112 L -561 L -493 L -1054

Total Powder H -948 H -968 H -1916River basin . . . . . 225 L -793 L -687 L -1480

aFor operating and permltted mines with Federal leases. See table 57, powder

River Basin Federal Mine Statistics. Potential production from undevelopedleases IS not Included in these tables

1976, also has the potential for high cumula-tive growth from 1980 to 1991; from 9.8 mil-lion tons in the 1976-79 period to 61,4 milliontons in 1980-86 and 72.4 million tons in1987-91. Similar increases could occur at theother new mines in the basin. Some increasedproduction will also come from the expansionof older mines.

Lessee Production Plans and OTAHigh= Low Demand Scenario

Projections: A Summary Comparison

Figures 35 and 36 present a graphic com-parison of the production estimates of thelessees with those under OTA’s high and lowdemand scenarios presented in table 58. Thelessees’ estimated production for 1986 is 23percent (36 million tons) more than produc-tion 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 -


+. , . .

.- ,t’

.,[ { Key

,,;k .

,$

-.- Contracted production-“

1979 1980 1986 1991

Year

SOURCE: Office of Technology Assessment.SOURCE: Office of Technology Assessment

— — . — — — — —— — — . .-— —.


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 per-cent (60 million tons) more than coal cur-rently under contract for 1991.

OTA’s estimates of production under thehigh demand scenario in 1991 are only 10 mil-lion tons less than the production estimates ofthe lessees, however, OTA’s production esti-mates under the low demand scenario aresubstantially lower than those of the lessees.For 1991, the difference between the two pro-jections is 78 million tons. OTA’s estimatesunder the low demand scenario closely par-allel production already under contract.

1979 1980 1986 1991

YearSOURCE: Office of Technology Assessment.

Development Potential and Production Prospects ofUndeveloped Leases in the Powder River Basin

The preceding section examined the pro-duction prospects of operating and permittedmines with Federal leases in the PowderRiver basin for 1986 and 1991. The discus-sion focused on the design capacity, total pro-duction, and production of Federal reservesfrom these mines over the next 10 years. Thissection examines the production prospects ofthe 21 undeveloped lease blocks (37 leases) inthe Powder River basin under OTA’s high andlow demand scenarios. The production esti-mates for each of these leases are based onOTA’s review of their development potential,the plans of the lessees, and other considera-tions likely to affect production,

The potential capacity that these leasescould add to the Powder River basin is signifi-cant, totaling 81 million tons per year by theend of this decade. Under OTA’s high demandscenario these leases could produce 11 mil-lion tons in 1986; under the low demand sce-nario, 5.6 million tons. In 1991, under the highdemand scenario, these leases could produce65 million tons per year; their productionwould only be 17 million tons in 1991 underthe low demand scenario. However, as table63 shows, 11 undeveloped lease blocks (20leases) of the 21 undeveloped lease blocks (36leases) in the Powder River basin have unfa-vorable 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

Capac i t y 2 R e s e r v e sNumber of L o c a t i o n (mi l l ion (bi l l ion Product ion prospects ’

D e v e l o p m e n t p o t e n t i a l L e s s e e4 Leases by county’ Ac res tons) tons) 1986 1991

Leases with favorabledevelopment potential

AntelopeN. AntelopeSouth RawhideRochelleDry ForkE. Gilette Fed.(h)N. RochelleCX RanchCX RanchWildcatLake DeSmet(e)Phillips Creek (l)(c)

Resource Development Co.N. Antelope CoalCarter Min ingPeabody CoalCities ServiceKerr-McGee Co.Shell Oil Co.Consol idat ion CoalPeter Kiewit Sons, Inc.

Gulf Oil Co.T e x a c oP P L

311233111154

Favorable(a)Favorable(a)Favorable(b)UnfavorableUncertainUncertainUncertainUncertainUnfavorableUnfavorableUnfavorableUnfavorable

FavorableFavorableFavorableFavorable(e)UncertainUncertainUncertainUncertainUncertainUncertain(e,g)Unfavorable(e,g)Unfavorable

Totals 26 44,888 81 (120) 3.3

Leases with uncertaindevelopment potential

Bass Trust(f) R.D. Bass Trust Estate 1 Sheridan 2 0 , 7 0 1 – L U n f a v o r a b l e U n f a v o r a b l eBelco( f ,h) Belco Petro leum 1 J o h n s o n 4 , 5 5 1 — L U n f a v o r a b l e U n f a v o r a b l eGulf (1) & (2)(f) Gulf Oil Corp. 3 Sheridan 4 , 3 6 6 — H M U n f a v o r a b l e U n f a v o r a b l eEast Wyodak(d) Peabody Coal 1 C a m p b e l l 2 , 5 6 0 — (7.0) LM Unfavorab le Unfavorab le(e,g)Pearl Shell Oil Corp. 1 Big Horn, Mt 541 – (2.0) LM U n f a v o r a b l e U n f a v o r a b l e

Totals 7 32,719 – (9.0) 0.7

Leases with unfavorabledevelopment potential

Armstrong(h) Big Horn Coal 1 Sheridan 80 – s U n f a v o r a b l e U n f a v o r a b l eBlue Diamond Wyodak Resources 1 C a m p b e l l 40 — s Unfavorable UnfavorableGulf (3)(h) Gulf Oil Corp. 1 C a m p b e l l 7 5 6 – s U n f a v o r a b l e U n f a v o r a b l ePhillips Creek (2) PPL 1 Converse 40 – s Unfavorable Unfavorable

Totals 4 9 1 6 – <0.01

‘Counties are in Wyoming unless otherwise noted‘Numbers without parentheses show capacities for 1991, numbers in parentheses indicate capacities after 19913Where footnote appears under “development potential” it IS relevant to the development of the lease. Footnotes under “productIon prospects” are relevant to produc-tion 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


10 years even under favorable market condi-tions.

Undeveloped Leases With FavorableDevelopment Potential

Four undeveloped lease blocks (7 leases)—Antelope, North Antelope, South Rawhideand Rochelle—in the Powder River basinwith favorable development potential havefavorable production prospects for 1991.These lease blocks cover 18,740 acres; threecontain relatively large reserves.

Only one of these lease blocks, Rochelle, isnot likely to be producing under OTA’s lowdemand scenario in 1986. Production at theRochelle lease is contingent on the pace of de-velopment at the Panhandle Eastern Gasifica-tion plant in Douglas, to which 500 milliontons of Rochelle’s reserves have been com-mitted. Panhandle’s plans called for produc-tion in 1986, using coal at a rate of about 6million tons per year with an additional 1 mil-lion to 2 million tons per year possibly going toan associated steam/electric plant. DOE hasfunded a feasibility study on the Panhandle

— . . . . . . -- — — . .


Eastern project but production prospects forthe Rochelle lease are unfavorable for 1986because of the time required for the develop-ment of a synthetic fuels project. However, by1991 the Rochelle lease is assumed to pro-duce 6 million tons of coal under both the highand low demand scenarios. *

The South Rawhide lease, although withoutcontracts, would begin production in 1985and expand to 9 million tons per year by 1991under the high demand scenario. If no con-tracts are obtained for this property, thelessee (Carter Mining Co.) may mine coal atSouth Rawhide to blend with the coal pro-duced at the company’s Rawhide and Caballomines for which contracts have already beensecured. If this occurs, production at theRawhide and Caballo mines would be re-duced proportionately.

Coal from the North Antelope lease will beshipped to Middle South Utilities in Arkansas,a group of several utilities scheduled to beginoperation in 1984. Using company projectionsfor this lease, OTA has estimated that ap-proximately 4.5 million tons per year will beproduced under the low demand scenario and5 million tons per year under the high demandscenario in 1991 unless construction of theplants is delayed. Mining operations at NorthAntelope will include reserves from theRochelle lease.

All planned production from the Antelopelease is also contracted through 1991; thus,production prospects for both 1986 and 1991for this lease are favorable. The lessee plansto produce 5.6 million tons per year by 1990and increase production to 12 million tons peryear by 1993.

Four lease blocks (eight leases) with favor-able development potential, covering 10,696acres, have uncertain production prospectsfor both 1986 and 1991. Thus, under OTA’shigh demand scenario these lease blockscould be producing by 1991; however, their

*The 1991 production prospects of the Rochelle lease blockhave become less favorable recently because of the with-drawal of two of the partners in the Panhandle EasternWyCoal Gas Project.

prospects for production are unfavorablethrough 1991 under the low demand sce-nario. Three of these lease blocks—Dry Fork,East Gillette Federal, and North Rochelle—have substantial reserves and favorableproperty characterist ics. The CX Ranchlease, held by Consolidation Coal Co., hassmall Federal reserves with otherwise favor-able property characteristics and is asso-ciated with significant amounts of non-Fed-eral coal.

The Dry Fork lease block, held by CitiesService Co., could produce 0.4 million tonsper year by 1986 and 5.9 million tons per yearby 1991 under the high demand scenario. Sixhundred forty acres of State coal could possi-bly be included in mining operations. Thereare no contracts for coal from the lease atthis time.

According to the Western Coal PlanningAssistance Project, coal produced on the EastGillette Federal lease block (which could pro-duce 11 million tons in 1991 under the OTAhigh demand scenario) will be delivered tofour utilities in Arkansas, Louisiana, andOklahoma. Parts of two of the three leases atEast Gillette Federal are included in ex-change negotiations authorized under PublicLaw 95-554, but the exchanges would not af-fect the viability of the mining operation. (Seech. 9 for a discussion of exchanges. )

North Rochelle’s production could reach5.9 million tons per year by 1991 under thehigh demand scenario. The lessee, Shell OilCo., plans to apply for a mining permit by1984 and is currently conducting mine feasi-bility and environmental studies. It appearslikely that sales of the coal on the lease willbe directed to steam/electric use, at least inthe near term, though none of the coal has yetbeen sold. Another option for Shell is to usethe coal to meet contract obligations atShell’s Buckskin Mine, where the status ofsome recoverable reserves is uncertain be-cause of alluvial valley floor considerations.Development for synfuels is also a possibilityfor the 1990’s.

Consolidation Coal’s CX Ranch could beginproduction before 1986; capacity could be 8


million tons per year by 1991. Federal coalhas been integrated with State and fee coalalready held by the lessee. Although marketsfor the coal have yet to be identified, thelessee is exploring both steam/electric andsynthetic fuels markets. Environmental stud-ies are underway and the lessee plans to sub-mit a mine permit application in 1981. Underthe high demand scenario, in 1991 Consolida-tion’s CX Ranch lease could produce close to6 million tons per year. *

Both the CX Ranch lease, held by PeterKiewit Sons, Inc., and Gulf Oil’s Wildcatlease have unfavorable production prospectsfor 1986. Either lease could be producing by1991 under the high demand scenario butneither is likely to be producing by 1986 evenunder the high demand scenario.

Production from Gulf Oil’s Wildcat leasecould reach 5 million tons per year by 1991with much of this tonnage expected to beused for onsite power generation. The lesseehas developed a preliminary mine plan thatmay be submitted within the next few years,However, development of this lease blockmay be more difficult and costly than the de-velopment of most other leases in CampbellCounty because the geology of the coal seamsis very complex. The CX Ranch lease couldhave a capacity of 4 million tons per year andproduce close to 3 million tons per year by1991; however, none of the coal on the leasehas yet been sold.

Two lease blocks (9 leases) with favorabledevelopment potential—one contingent onsynfuels, (Lake DeSmet) the other contingenton integration into an existing mine (PhillipsCreek (l))—have unfavorable productionprospects for both 1986 and 1991. Thus,these leases are not likely to go into produc-tion by 1991 even under the high demand sce-nario. Lake DeSmet has large reserves, Phil-lips Creek small reserves. The Phillips Creekblock, recently acquired by the Pacific Power& Light Co. is expected to be incorporated in-to the Dave Johnston Mine. Even if this oc-

*See ch. 10 for a discussion of the alluvial valley floor situ-ation at the CX Ranch leases.

curs, mining of the lease would probably nottake place until after 1991,

Although four of the five Lake DeSmetleases are not contiguous, the lessee owns allof the intervening non-Federal coal. Produc-tion from this lease depends on the develop-ment of synfuels. The lessee submitted a jointapplication to DOE for a feasibility study withTranswestern Coal Gasification Co. However,this study was not funded. No commitmentsor contracts for development of the coal haveyet been obtained.

Undeveloped Leases With UncertainDevelopment Potential

Five lease blocks (7 leases) in the PowderRiver basin—Bass Trust, Belco, Gulf (l&2),East Wyodak, and Pearl—have uncertain de-velopment potential. These leases contain32,719 acres and have sizable reserves. Eachlease has unfavorable production prospectsfor both 1986 and 1991. It is unlikely, there-fore, that these leases would go into produc-tion by 1991 even under OTA’s high demandscenario.

The production prospects of the BassTrust, Belco, and Gulf (l&2) lease blocks arecontingent on the development of in situ gas-ification, which is not likely to proceed beforethe 1990s. The Bass Trust lease, the largestFederal coal lease ever issued, has poor coalquality, thin seams and a high stripping ratio.Similarly, the Gulf (l&2) lease block does notappear to be commercially minable by con-ventional techniques because of a high strip-ping ratio. To date, the lessee has not filedapplications to DOE for pilot plant develop-ment, and no other plans for developmentwere identified for the near term. The Belcolease is authorized for trade under the provi-sions of Public Law 95-554.

The reserves on the East Wyodak leasemight support an onsite coal conversion plantif integrated with 640 acres of contiguousState coal held by the lessee, but strippingratios are probably too high to develop a minefor export markets. In addition, the lesseealso holds a block of PRLAs on land adjacent

——— _ -_ — —— - - _- -- -- — - - . -


to East Wyodak. The lessee has expressedserious intention to bring these reserves intoproduction when more favorable market con-ditions prevail.

A final environmental impact statement(EIS) was submitted on the Pearl lease afterthe lessee (Shell Oil Co.) had conducted acomprehensive planning assessment. In spiteof such an investment of time and resources,development of this property has been post-poned. The amount of lease reserves is mar-ginal and the stripping ratios high. Further-more, the lease reserves are located in twoblocks separated by unleased Federal coal.

Undeveloped Leases With UnfavorableDevelopment Potential

Four leases—Armstrong, Blue Diamond,Gulf (3) and Phillips Creek (2)—have unfavor-able development potential and thus unfavor-able production prospects, even under strongmarket conditions. These leases have smallreserves, poor property characteristics, andlittle chance of being integrated with anothercoal property to form a logical mining unit.The owners of these leases have given no indi-cation that they will be developed. The Arm-strong and Gulf (3) leases are authorized fortrade under the provisions of Public Law95-554.

Development Potential and Production Prospects ofPRLAs in the Powder River Basin

There are 58 PRLAs in the Powder Riverbasin covering a total of 95,228 acres and in-cluding recoverable reserves ranging fromless than 30 million tons to over 180 milliontons. Table 64 presents information on thedevelopment potential and production pros-pects of these 58 PRLAs that are grouped into19 blocks using the criteria of contiguity andcommon ownership applied to undevelopedleases. Acreage and reserve ratings are alsopresented for each block. 1994 is the key yearfor which to assess the production prospectsof PRLAs because the stated policy of theDepartment of the Interior (DOI) is to processall outstanding PRLAs by December 1, 1984(43 CFR 3430.3-l(a)). If this schedule is met,diligence requirements for all PRLAs willhave to be met by 1994 at the latest. *

None of the PRLA blocks with large recov-erable reserves appears to have favorabledevelopment potential . The three PRLAblocks with favorable development potentialcannot contribute substantially to the capac-ity of mines with Federal leases in the PowderRiver basin because of their small reserves.

*These leases will he subject to post -FCLAA diligence re-quirements.

The PRLA blocks that might increase Federalmine capacity substantially in the basin—Peabody (P4), and Consol (1) and (2)—haveuncertain development potential and produc-tion prospects.

PRLAs With FavorableDevelopment Potential

Only three PRLA blocks (four PRLAs) of the19 PRLA blocks (58 PRLAs) in the Wyomingportion of the Powder River basin have favor-able development potential. None of theseblocks would add substantially to the capac-ity of Federal mines in the Powder Riverbasin. Because of their small size and smallrecoverable reserves (each with less than 30million tons), these three PRLA blocks wouldnot have favorable development potential iftheir incorporation into producing mines orapproved mine plans did not seem likely by1994.

The Peabody (P2) PRLA, may be incorpo-rated into Carter Mining Co.'s Caballo Minebecause it is located within the boundaries ofthe 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

ReservesNumber of (millions Production

Development prospects Owner/parent company PRLAs County Acreage of tons) prospects (1994)

PRLAs with favorabledevelopment potential:

Peabody (P2)Weld-Jenk~ns (5)North Antelope (1)

Totals

PRLAs with uncertaindevelopment potential

Peabody (P4)Consol (1)Consol (2)North Antelope (2)Arco (1)Arco (2)Peabody (P3)Western Fuels (1)

(Stevens North)Dixie (2)ThunderbirdWeld-Jenkins (l-4)

Totals

PRLAs with unfavorabledevelopment 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 CoalARCOARCOPeabody Coal Co.Western Fuels Assoc.

Dix ie Natura l ResourcesEl Paso Coal Co.Weld-Jenkins

4 840 15

13221243

11213

ConverseCampbellCampbellCampbell & ConverseCampbellCampbellCampbellConverse

ConverseCampbell & JohnsonCampbell & Johnson

8355,6104,5341,240

357240

2,2008,864

2,27623,92828,496

LM (4.0)4

L (7.0)L (8.5)sssLMHM1

LMS 2, L3

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 UnfavorableDixie Natural Resources 1 Converse 800 NSR UnfavorablePeabody Coal Co. 4 Campbell 3,388 S UnfavorablePeabody 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 coalf = possibilities exist for in situ gasification.1Reserves with stripping ratio less than 3.5 are probably small.2Small surface reserves.3Large underground reserves.4Numbers in parentheses indicates potential mine capacity, if lease IS issued.


SunEDCo’s Cordero Mine. The North Ante-lope (1) PRLA will likely be developed withPeabody’s North Antelope lease. Peabody hascontractual commitments on theAntelope lease with System Fuels forlion tons of coal beginning in 1985.

PRLAs With UncertainDevelopment Potential

North180 mil-

Eleven PRLA bocks (44 PRLAs) covering78,580 acres have uncertain development po-tential. Because of their limited reserves, thedevelopment 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 iscontingent on their being integrated withmines already in production. Development ofthe Western Fuels (1) PRLA is contingent onintegration into the Dave Johnston Mine, ThisPRLA block has thin seams, a high strippingratio, and the coal is of low heat content. Pro-cedural irregularities may impede the proc-essing of these PRLAs and their issuance asleases. The Dixie (2) PRLA would have hadunfavorable development potential becauseof small reserves, thin seams, and low heatcontent of the coal but there is evidence ofplans to develop the lease for local industrialuse.

. . . .


The production of coal from the Peabody(P4), Consol (l), and Consol (2) PRLAs is con-tingent on onsite development. The reservesassociated with the Peabody (P4) block couldsupport an onsite steam electric plant but areinsufficient to support a synfuels project.Both the Consol (1) and Consol (2) blocks couldsupport either an onsite steam/electric plantor an onsite synfuels plant. The issuance ofleases on all three blocks maybe impeded byoverlapping mining claims and/or possibleprocedural irregularities. These PRLA blocksmight produce coal if the electrical growthrate and/or demand for synthetic fuels ishigher than suggested by several estimates.Consequently, even if these PRLAs are issuedas leases, their production prospects wouldbe uncertain for 1994.

The Thunderbird and Weld-Jenkins (1-4)PRLA blocks also have uncertain develop-ment potential because their production pros-

pects are contingent on in situ gasification, atechnology that is not likely to be commer-cially viable by 1984. *

PRLAs With UnfavorableDevelopment Potential

Five PRLA blocks (10 PRLAs) have unfavor-able development potential. Four of thesePRLA blocks have small reserves. The fifthblock, Consol (3) PRLA has unfavorable devel-opment potential because it is separated intofour noncontiguous blocks by unleased Fed-eral coal.

* Preference right lease applicants must demonstrate the ex-istence of commercial quantities of coal before a lease can beissued. Technology for in situ gasification would have to ad-vance to the point of reasonably expected commercial viabilityby 1984 (the deadline for processing PRLAs) for coal reservesthat are suitable only for in situ gasification to meet the com-mercial quantities test. This is unlikely, given the current ex-perimental nature of this technology in the United States.

Comparison of Demand and Supply Projections for thePowder River Basin

As shown in figure 37 and discussed ear-lier in this section, most demand projectionsfor Powder River basin coal for 1990 rangebetween 163 million tons per year and 275million tons per year. The Wyoming taskforce projected a demand for 206 million tonsper year by 1990 for coal produced in thePowder River basin. Production projectionsfor Powder River basin coal can also span awide range, from existing contracts with de-veloped mines to full utilization of the minedesign capacity of existing and plannedmines. Figure 37 compares planned produc-tion and capacity for 1990 with demand esti-mates for 1990.

It should be recalled that the estimates ofpotential production developed in this chap-ter are not forecasts of the coal that would beproduced at a given price or a given demand.They are estimates of the total amount of coalthat could be produced from operating Fed-eral mines and from those Federal leases thathave characteristics comparable to operating

mines in the same region. Coal from theseleases would thus be likely to have miningcosts competitive with costs at currently op-erating mines in the same area. If the demandfor Federal coal does not increase to thelevels of potential production, then not all theFederal leases that could technically and eco-nomically be developed will go into produc-tion.

The existing contracts for delivery of Pow-der River basin coal in 1990 from operatingFederal and non-Federal mines total 169 mil-lion tons (see tables 58 and 61). An additional17 million tons has also been contracted for1990 from three undeveloped lease blocks(Antelope, North Antelope, and Rochelle), ofwhich 6 million tons is for synfuels (Rochelle).Thus, there is a total of 186 million tons peryear of Powder River basin coal already con-tracted for 1990.

The planned production of the lessees for1990 is larger than presently contracted pro-


Figure 37.—Comparisons of Powder River Basin Demand Projections WithPlanned 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 goals1990

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 ofWestern 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 UtiIityCoal Market and Demand for Montana Coal 1980.1991 Based Upon Pro-jected 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 andCritique 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 Goalsfor 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 per-mitted Federal mines, the sum of the lessees’planned production for 1990 is about 215 mil-lion tons. (See table 58 for 1991 planned pro-duction.*) At least another 10 million tons ofproduction is planned by non-Federal mineoperators (see table 61). When potential pro-duction from undeveloped leases is added,the figure for planned production in the Pow-der River basin for 1990 increases substan-tially. Ten undeveloped lease blocks in thePowder River basin could produce 55 milliontons per year by 1990.** Of this, 17 milliontons per year is presently contracted for; 6million tons per year of this 17 million tonsper year is committed to synfuels. *** All ofthese lease blocks were ranked as having fa-vorable development potential, with marketdemand being the most important factor fortheir production prospects.

Most of the lessees’ plans call for higherproduction in 1990 than what is under con-tract at present, and planned mine design ca-pacity is, in a number of cases, higher thanplanned production. Planned mine capacityfor operating and permitted Federal minesfor 1990 is 226 million tons per year (see table58). Planned mine capacity for non-Federalmines adds another 44 million tons per year,for a sum of 271 million tons per year (seetable 61). When estimated capacity for the 10undeveloped lease blocks with favorable pro-duction prospects is added, the resulting sumis 348 million tons per year capacity for 1990(see table 63 for capacity of undevelopedleases in 1991).

In summary, OTA finds that existing andproposed mines with favorable developmentpotential in the Powder River basin could sus-tain production of 348 million tons per year in1990, provided the demand existed; only 6million tons per year of this production iscommitted to synfuels development. This

*Note that these tables refer to 1991 production; the num-bers in the text above refer to 1990 production, which is slight-ly less.

* ● Antelope, North Antelope, South Rawhide, Rochelle, DryFork, E. Gillette Federal, N. Rochelle, CX Ranch (Consol), CXRanch (PKS), Wildcat. The 1990 production is 10 million tonsless than potential production in 1991.

** *Peabody Coal Co. ’s Rochelle lease block production iscontracted to the Panhandle Eastern project.

figure is substantially larger than most de-mand projections: over 25-percent higherthan the DOE midlevel projection, over 50-percent higher than the ICF midlevel projec-t ion; nearly 70-percent higher than theWyoming task force projection; and 75-percent higher than the projection of theWyoming Geological Survey.

There are several reasons to suppose thatthe DOE midlevel projection is outside of the“most likely” range. (See discussion sur-rounding fig. 34. ) A more reasonable “likelyhigh” figure is the ICF base case of 226 mil-lion tons per year. Similarly, the ICF low pro-jection of 163 million tons per year, which isless than present contracts for Powder Riverbasin coal, is probably outside of the “mostlikely” range. Assuming that the “most like-ly” demand range is from 199 million tons peryear (Glass; Wyoming Geological Survey) to226 million tons per year (ICF base case), thenpotential mine capacity in the Powder Riverbasin in 1990 may be from 122 million tonsper year (over 50 percent) to 149 million tonsper year (75 percent) above demand.

Potential Coal Mine Capacity in thePowder River Basin in the 1990’s

The earlier sections of this chapter havediscussed capacity, production and demandin the Powder River basin up to 1991. Thissection briefly examines the additional ca-pacity that might be developed in the 1990’s.Only capacity that can be sustained withoutadditional leasing of Federal coal is included.

Table 65 lists all Federal and non-Federalcoal properties that might produce in the1990’s and the capacity levels that their pres-ently held reserves could support. For thosecoal properties likely to be in production by1991, a total of about 26 million tons per yearcapacity over 1991 capacity could be addedin the 1990’s as follows:

●

●

zero from Federal mines in currently ap-proved mine plans (compare with table59);about 7 million tons per year from non-Federal 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 permittedFederal mines and undeveloped Undeveloped leases with

Federal leases with favorable unfavorable production prospectsproduction prospects for 1991 for 1991 and PRLAs Non-Federal mines b

— —.Name Capacity Name Capacity Name Capacity

All operating and permittedFederal mines 226

Undeveloped Federal leasesAntelope 12North Antelope 5South Rawhide 12Rochelle 11Dry Fork 15East Gillette Federal 15North Rochelle 8WildcatC 10CX Ranch (Consol) (Mt) 8CX Ranch (PKS) (Mt) 4

LeasesLake de SmetC

East WyodakC

Pearle

Total (leases)

PRLAsConsol (1)C

Consol (2)C

Peabody (P4)c

Total (PRLAs)

2072

29

78.54

20

With favorable production prospectsfor 1991 51

Likely to come into production after 1991Mobil (Johnson Co.)C 11Whitney d 1Absaloka (II) (Mt) 10Tanner Creekf 24Tongue River II (Mt)g 10Tongue River III (Mt) g 10Dominy (Mt) 8Bear Tooth (Mt) 2

Total 127

Total 326 Total leases plus PRLAs 49asee tables 58, 81, 63, and 84 for 1991 capacities. (Mt) means mine or lease is in Montana.bIn 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 ofFederal coal and that in several other instances listed capacities exceed the sustainable levels of production when the mine reserves are considered. Mines listed hereare only those mines and potential levels of production that could reasonably be expected to occur without new leasing of Federal coal. Capacities listed here weredeveloped 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 herefShell 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) com-plied 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 Devel-opment Morritoring System: A Survey of Coal Mine Capacity in the West, DOE/TIC-10249 (Washington, DC.: DOE, April 1979). Department of Energy, 1981Western Coal Survey A Survey of Coal Minig Capacity in the West, DOE/RA-0045/1 (Washington, D. C.: DOE, January 1981). Western Coal Planning Assist-ance Project, 1979 Fact Book for Western Coal/Energy Development, prepared for Missouri River Basin Commission (Billings, Mont.: Mountain WestResearch, Inc.).

and● about 19 million tons per year from un-

developed leases (compare with table63).

For those coal properties unlikely to be inproduction by 1991, a total of about 125 mil-lion tons per year of capacity could perhapsbe put in place in the 1990’s as follows:

● about 29 million tons per year from threeundeveloped leases (compare with table63);

● about 20 million tons per year from threePRLAs (compare with table 64); and

● about 76 million tons per year from non-Federal mines.

Therefore, an increase of about 150 milliontons per year of mine design capacity over1991 capacity could perhaps become avail-

able in the Powder River basin in the 1990’swithout additional leasing of Federal coal,giving a possible total post-1990 capacity ofabout 500 million tons per year. This amountshould be considered an upper limit ratherthan a likely value of post-1990 capacity with-out additional leasing of Federal coal. About70 million tons would be suitable only for on-site development for synfuels or power gen-eration.

For the post-1990 period, demand projec-tions become very uncertain. The DOE pre-liminary midlevel production goals, the ICFCEUM midlevel production forecast and theDOE midlevel final production goals for 1995for the Powder River basin are 382, 306, and491 million tons per year, respectively. TheDOE final production goal, 491 million tonsper year, reflects several policies about in-

. . . . . . .


creased coal use, notably a very large de-mand for coal for synfuels, that cause thenumber to be higher than other forecasts. Al-though all demand projections past 1990

should be regarded as very uncertain, thelower numbers above are, as of now, morelikely to be realized.

Implications for New Leasing

Because of the predominance of Federalcoal reserves in the West, the decisions ofDOI on the quantity, location, and timing ofcoal leasing are important not only to the Na-tion in terms of energy availability, but to theregion with regard to regional and communitydevelopment, revenues, and environmentaldisturbance, There are two distinct philos-ophies advanced to govern the leasing of Fed-eral coal: 1) a free market approach based onthe theory that demand for leases should reg-ulate the rate of leasing, and that the FederalGovernment should offer leases for develop-ment to the extent the market can absorb;and (z) an approach that emphasizes leasingcoal at a rate that will ensure that coal pro-duction can meet the anticipated demandafter considering possible errors in demandprojections and delays that might occur indeveloping the leased reserves. The objectiveof the second approach is to offer enough coalto meet the projected supply-demand esti-mates, allowing a moderate margin in excessto meet contingencies for delayed develop-ment, underestimates in demand or unfore-seen constraints on production. DOI hasadopted both of these philosophies at varioustimes in the past,

Because of the leadtime required from theacquisition of reserves to full production, thedecisions on the amount, type, and location ofcoal to be offered for leasing must be mademore than a decade in advance. Leasing tar-gets have been based on projected estimatesof coal demand, projected estimates of indus-try’s production capacity, environmental con-siderations, and the potential impacts on thesocial and economic structure of the coal re-gions. Because leasing targets are based onforecasts and projections, which in turn relyon assumptions and estimates of production

factors and projected demands, there are sig-nificant uncertainties in setting the quantitiesand timing of leasing targets. Experience sug-gests that supply-demand forecasts are sub-ject to significant errors when extended be-yond 5 years, and uncertainties become sub-stantial in projections beyond a decade. (Seech. 5, Markets, for a discussion of thesefactors.)

Some of the uncertainties that may influ-ence the supply and demand for Western coalduring this decade are: Will electricity de-mand growth remain at current low levels?How rapidly will foreign exports of Westerncoal grow during next two decades? How rap-idly and to what extent will the conversionfrom oil and gas to coal take place? To whatextent will rising transportation costs restrictthe market areas for Western coal? Will syn-thetic fuels development place substantialdemands on the Western coal region? Towhat extent will the mandatory scrubbing re-quirements of the Clean Air Act restrictdemand for Western coal? Will there be un-foreseen delays in mine development and theattainment of full production capacity?

Both those who advocate large-scale re-newed leasing of Federal coal lands andthose who oppose renewed large-scale leas-ing as being unnecessary at this time use sup-ply-demand projections and the potential ofcurrent leased reserves as arguments to sup-port their respective positions. The disagree-ments between these two groups are basedon:

1. differences in what constitute reason-able projections of demand for Westerncoal;

Z. differences in estimates of the time re-quired for bringing a mine into produc-


tion at full capacity;3. differences over the acceptable levels of

leased reserve inventories needed by anoperator to ensure competiveness; and

4. differences concerning the safety mar-gins in leased reserves needed to meetcontingencies for higher-than-predicteddemands or to meet shortfalls in suppliesfrom other regions.

Many industry representatives discountthe efficacy of leasing targets altogether.They subscribe to the philosophy that publicresources should be freely available to theprivate sector for development in accordancewith the demands of the marketplace. As onespokesman for this philosophy puts it, “thelevel of leasing can be safely left to those whocan be punished economically by errors injudgment and rewarded by sound forwardthinking.<’ However, industry agrees that rea-sonable performance standards and environ-mental protection standards are necessary toprevent irreversible damage to the environ-ment and the socioeconomic structure of thecommunities.

Background

Under the leasing program adopted by theCarter administration, coal leasing targetsare established in a three-part process: DOI,which has primary responsibility for adminis-tering the coal leasing program on Federallands, uses DOE regional coal productiongoals as a point of departure. Preliminaryleasing targets established by DOI are thenreviewed by Regional Coal Teams, which ad-just the target based on public comments andthe position of the affected States repre-sented on the team. The Secretary of the In-terior than approves a specific coal leasingtarget after reviewing the options presentedin a Secretarial Issue Document (SID). TheSecretary may select one of the suggested op-tions or substitute one of his own.

DOI has changed its basis for determiningleasing targets several times with respect toDOE regional coal production goals. DOI orig-inally used the 1987 medium production goalsincreased by 25 percent for contingencies.

Subsequently, DOI adopted DOE’s midlevelproduction goals for 1990 but these werelater supplanted for the powder River basinby the 1990 high production goals. DOI is cur-rently considering deemphasizing the DOE’sproduction goals, and using them as just onefactor in lease sale planning. In place of totalreliance on these production goals, DOI mayadopt an approach that would allow primar-ily the market demand for leases to determinewhen and where and a t what level lease saleswould be held. In order to simplify and ex-pedite the leasing process, consideration isalso being given to revising the planning proc-ess to defer the determination of mining suit-ability and other land use planning functionsuntil after leasing. DOI is considering work-ing towards having an inventory of reservesunder lease that could support levels two tofour times anticipated production, similar tothe customary practices of the industry.

In making the decision to use the 1990 highproduction goals of DOE for the Powder Riverbasin lease sale, DOI acknowledges that cur-rently planned production will exceed de-mand through 1990. The new Federal coalmanagement program was implemented inJune 1979, and will not be fully operationaluntil 1984 at the earliest. one lease sale washeld in January 1981, in the Green River-Hams Fork region. Other regions selected forearly leasing include:

1. the Powder River basin:2. Uinta-Southwestern Utah: and3. Southern Appalachia.

The lease sale in the Powder River basin isscheduled for early 1982. Since the decisionto hold start-up lease sales was announced,some have expressed doubts about the neces-sity of the 1982 sale in the Powder Riverbasin to meet reasonably anticipated demandin the 1990’s given the leases outstanding,available private coal reserves and industry’spresent overcapacity in the Powder Riverbasin.

OTA estimated that presently operatingand proposed new mines in the Powder River

— . . _ - _— - . . — - . - - . — -- .- -- - -- -


basin, both Federal and non-Federal, wouldhave a total mine design capacity of 350 mil-lion tons of coal annually by 1990. (See fig. 37and tables 58, 61, and 63. ) This contrastswith OTA’s “most likely” demand for PowderRiver basin coal, which was estimated to bebetween 200 million tons and 226 million tonsin 1990. (See this chapter, pp. 171-173 and ch.5, pp. 100-108.) DOE’s interim midlevel pro-duction goal for 1990 is 275 million tons peryear—significantly higher than OTA’s “mostlikely” range. DOE’s final midlevel produc-tion goal is even higher—295 million tons.The final high level production goal for 1990,which is the basis for the Powder River basincoal sale, is 412 million tons per year.

On June 25, 1981, DOI announced that ithad selected a coal leasing target of 1.4 bil-lion to 1.5 billion tons of reserves for thePowder River basin to be considered alongwith al ternat ive levels analyzed in theregional EIS. This target was recommendedby the regional coal team; however, at thetime the target was announced, the AssistantSecretary for Land and Water Resourcescommented that:

I am apprehensive about setting a leasingtarget that is too low, that would hinder oper-ation of the market, and that would result inan insufficient amount of coal being leased tosatisfy the demand for reserves in theregion.4

The Secretary of the Interior, at the time hemakes the final determination on the PowderRiver basin lease sale, could decide to leaseup to 2.5 billion tons of reserves in the region.Currently leased coal reserves in the PowderRiver basin total 9.2 billion tons.

Existing leases in the Powder River basininclude over one-half of the 16.5 billion tonsof Federal coal reserves presently leased.With the additional leases scheduled for1982, the Powder River basin has become thefocus for debate over the timing, pace, andextent of Federal coal leasing needed to meetthe 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 forovercapacity in the early 1990’s as the mainreason why large-scale leasing scheduled for1982 should be deferred unti l , perhaps,1985. * But given the necessary leadtime todevelop a large new mine and reach full pro-duction, new leases sold in 1985 could notconfidently be expected to reach full capacityuntil 1995. By 1995, the excess capacity prob-able in the early 1990’s may have been sub-stantially reduced and possibly have disap-peared. Estimates of potential capacity anddemand in the post-1990 period are consider-ably less reliable than similar estimates for1990. An additional 155 million tons per yearof capacity over the 350 million tons per yearof capacity cited above could perhaps be-come available in the post-1990 period fromsome undeveloped Federal leases, PRLAs andnew non-Federal mines (see table 65).

About 70 million tons per year of the addi-tional post-1990 capacity would be suitableonly for onsite development for synfuels orsteam electric use because of low coal quality.Therefore, the 155 million tons per yearshould be considered an upper limit ratherthan a likely value of additional post-1990capacity without additional leasing of Federalcoal. For the post-1990 period, demand pro-jections are very uncertain.

The ICF CEUM5 midlevel production fore-cast, the DOE preliminary midlevel produc-tion goals, and the DOE midlevel final produc-tion goals for 1995 for the Powder River basinare 306, 382, and 491 million tons per year,respectively. The DOE final production goal,491 million tons per year, reflects several pol-icies about increased coal use, e.g., coal forsynfuels, that cause the forecast to be higherthan others. Although all demand projectionspast 1990 should be regarded as very uncer-tain, the lower numbers above are, as of now,more likely to be realized,

*The debate focuses on large-scale leasing. Leasing in spe-cial circumstances, e.g., to maintain production or to avoid by-passing a small area of Federal coal that could not subse-quently be economically mined, engenders far less controversy.

5Coal Electric Utility Model Forecasts and Sensitivity Anal-yses of Western Coal Production, prepared for Rocky MountainEnergy Co. (Washington, D, C.: ICF, Inc., November 1980).


The pros and cons of the proposed Federalleasing schedule are discussed in the follow-ing sections, using the Powder River basin asa case example.

The Case in Support of Large-ScaleLeasing in the Near Future

Proponents of “start-up” leasing and full-scale leasing programs in the near future citefour basic reasons for their position:

1. to be able to compensate for the con-tingencies of increased demand or short-falls in supply;

2. to ensure competition;3. to provide additional reserves for pro-

duction in the post-1990s to accommo-date the 10 year (or longer) leadtimesneeded to achieve full production;* and

4. to allow entry of operators not now ac-tive in the Powder River basin for equityand to stimulate competition.**

Proponents of immediate Federal leasingcontend that leasing targets should be gearedto allow margins for unanticipated increasesin demand or unforseen shortfalls in produc-tion because of the failure of some plannedcapacity to come on line. For example, if only6 out of the 17 undeveloped properties con-tributing to the 350 million tons per year ofcapacity in 1990 should fail to be developed,capacity in that year could be reduced by asmuch as 60 million tons per year, to 290 mil-lion tons per year. Moreover, the “most like-ly” demand range for Powder River basincoal in 1990 of 200 million to 225 million tonsper year implies a midrange estimate basedupon judgments of reasonable expectations.

*Eslimates of the time required after lease sale to achievefull production for a large surface mine range from under 1 0years to more than 15 years. The upper range reflects a con-servative view of the time needed to scale up to full productionafter production has commenced: the lower range arises inpart from the belief that permitting times will become shorteras mine operators and Government regulators alike developmore familiarity y with the permitting process.

**There are 38 lease blocks in the Powder River basin con-taining 73 leases. There are 19 lessees: 11 oil companies. 3utilities, Peabody Holding Co., and four others (see app. B, OTAWorking Lease List),

The 1990 demand for Powder River basincoal could be somewhat higher than OTA's“most likely estimate”’ if several events wereto occur:

if electrical demand grew faster thananticipated;if boiler conversions from oil and gas tocoal occurred more rapidly than ex-pected;if synthetic fuels development came on-line faster than projected;if foreign export of coal grew more rap-idly than anticipated; orif Powder River basin coal captured aneven larger share of the domestic marketthan anticipated.

Leasing proponents claim that underleas-ing would have a substantial impact on thecoal markets and would drive up market-clearing prices and force shifts in productionto other regions. However, opponents of leas-ing consider it improbable that coal demandwill increase significantly beyond the “mostlikely” demand projections. They further holdthat even if demand increased somewhat orsome shortfalls in production developed,these would not be large and the capacity andresources in other regions, including Mid-western coal, could easily make up the dif-ference.

Currently operating Federal and non-Fed-eral mines in the Powder River basin have aplanned capacity of 246 million tons per yearin 1990. (See tables 58 and 61 (including foot-note a) and fig. 37.) Most of the currentlyoperating Federal mines would be operatingin 1991 at or near full design capacity. Anydemand for Powder River basin coal over the246 million tons per year level would have tobe met by presently undeveloped Federalleases and undeveloped non-Federal coalproperties. Some proponents of immediatelyrenewed leasing do not consider the potentialof the undeveloped leased lands as certainenough to provide a secure safety margin ofproduction in 1990 in light of the leadtime re-quired from lease sale to full production,

194 “ An Assessment of Development and Production Potential of Federal Coal Leases

A second consideration advanced in sup-port of additional Federal coal leasing in thepowder River basin is the potential for stimu-lating competition within the coal industry.Both the Department of Justice (DOJ) and theGeneral Accounting Office (GAO), in reportsissued in 1980, criticized the setting of leasetargets as being inefficient and potentiallyanticompetitive because targets attempt tomatch the amount of Federal coal leased tothe amount required to meet given projecteddemand. * DOJ'S report concludes that a tar-get leasing system unduly supplants the mar-ketplace as the allocator of coal resources.The report presents two solutions: 1) abandonthe setting of targets, and begin leasing on de-mand, or 2) set lease targets at a level far inexcess of the more modest leasing targetsused earlier. DOJ has previously contendedthat doubling or tripling the current targetswould be necessary to provide a reasonablemargin for error and to promote competition.DOJ also recommends the reevaluation ofleasing targets to determine whether it wouldbe preferable simply to lease what industrydesires. DOI is currently considering deem-phasizing leasing targets in favor of the freemarket approach as suggested by DOJ. More-over, the adoption by DOI of DOE high pro-duction goals for 1990 for the Powder Riverbasin is consistent with DOJ's second recom-mendation to provide liberal targets muchlarger than the one to one production-demandratios used for lease planning earlier.

However, opponents of near-term large-scale leasing in the Powder River basin con-tend that the excess in potential capacity inthe Powder River basin could ultimately leadto a decrease in competition within the re-gion. Most of the current leaseholders in thePowder River basin are large companies thatcan afford to take short-term losses; smallerleaseholders or new entrants who may nothave large amounts of capital might find itdifficult to compete in this situation. This fac-tor is also a cause of concern to some smaller

——*U.S. Department of Justice, Antitrust Division, Competi-

tion in the Coal Industry, November 1980; U.S. General Ac-counting Office, A Shortfall in Leasing Coal From FederalLands: What Effect on National Energy Goals? EMD 80-87,Aug. 22, 1980.

companies that nevertheless support earlyleasing in the Powder River basin.

DOE has recently analyzed Federal coalleasing activities. One important factor DOEconsidered was the effect of leasing on theconditions for entry into the coal industry. In-sofar as easy entry into the industry affectsprices and output as a result of stimulatingpotential competition from new entrants, it isan important factor in assessing the competi-tiveness of the industry. For regions such asthe Powder River basin, where future miningwill depend in large part on the availability ofFederal coal, the DOE report found that se-vere limitations on the availability of Federalcoal for lease could create an artificially highbarrier to entry as well as shifting substan-tial market power to present industry partici-pants, In general, new leasing is one methodof improving entry conditions, and increasingthe number of producers. However, the ex-tent to which the lease sale scheduled for thePowder River basin is likely to increase thenumber of lessees is unclear because: 1) somepresent lessees might have an advantage overnew entrants in assembling large minabletracts because of their existing leases; 2) otherpresent lessees with large reserves in thePowder River basin might not care to in-crease their holdings; and 3) the number oftracts to be offered for lease is not yet known.

The third factor cited by those advocatingimmediate renewed leasing of Federal coal isthe need for creating a pool of reserves wellin advance of planned production to allow forstrategic planning by the industry and to ac-commodate the 10-year (or longer) leadtimefrom lease sale to full production.

For flexibility, industry prefers to operateon a reserve base that could support two tofour times the anticipated production. Also,industry contends that any leasing targetsshould be geared to meet the maximum possi-ble demand for coal that could occur within a15- to 20-year planning horizon. Leasing op-ponents, on the other hand, believe that suchlong-range planning and reserve pools are notnecessary. They contend that if demand ismonitored closely, then leases can be offeredwhen demand trends suggest the need will de-velop in 10 years or so.


If DOI were to eliminate leasing targets asthe determining factor in its coal lease plan-ning in favor of a market-oriented programfor leasing on demand, the market responsestill may not result in leasing of reserves thatcould support production substantially in ex-cess of demand (“overleasing”). Moreover,proponents of a liberal leasing policy or leas-ing on demand claim that overleasing wouldnot lead to production of coal in excess of de-mand. The proponents reason that if marketsdo not exist, the lands would not be developedand therefore socioeconomic impacts and en-vironmental impacts because of additionalleasing would not occur.

Those opposing the 1982 Powder Riverbasin lease sale admit that demand uncer-tainties must be considered in coal leasingplanning, but they reject many of the pro-jected demand scenarios as being “extremeassumptions, For example, the DOE finalmidlevel production goal of 295 million tonsper year for the Powder River basin in 1990includes about 35 million tons per year forsynfuels feedstock; this is unlikely to beachieved. A more likely number is under 10million tons per year in 1990, To remedy theuncertainties in long-range demand forecastsand attempt to bring targets closer to “rea-sonable” demand expectations, a trackingsystem has been suggested to improve the ac-curacy of demand projections as DOI movescloser to coal leasing target dates. Demandprojections depend on a number of assump-tions concerning electr ical growth rate,transportation costs, and other factors. If in1982 or 1983 the actual electrical growthrate or transportation costs differ signif-icantly from those used to bracket the likelydemand range earlier, then the likely range ofdemand for a given year could be modifiedwith increasing confidence.

The prospect of leasing on demand or usingliberal leasing targets raises the question ofspeculation. Unlike the situation during theprevious era of liberal leasing, actual pro-duction requirements for diligent develop-ment now exist in the Federal Coal Leasing

Amendments Act and regulations. * If the de-mand for Western coal does not increase asrapidly as liberal leasing proponents gen-erally assume, the diligent development re-quirements could act as a damper on acquir-ing leases purely for speculation.

Opponents of a liberalized leasing programclaim that Federal “overleasing” would re-duce the revenues from private, State, and In-dian coal because of the predominance ofFederal coal in the region and the pressuresthat this coal would place on the local mar-kets. They also claim that “overleaping””would depress the bids on new leases to thepoint where the public would not receive afair return for its resources.

The Case for Postponing Leasing

Those opposing renewed Federal coal leas-ing in 1982 in the Powder River basin citethree reasons for deferring the lease sched-ule:

1.

2.

3.

the currently operating Federal and non-Federal mines, plus the good qualityproperties being actively developed andthe PRLAs that may be developed in thefuture will provide substantially morecapacity than will be needed between1990 and 1995:slower leasing is needed to allow suffi-cient time for adequate planning forleasing by DOI; andslower leasing would better match thecapability of ‘the State, regional, andlocal governments to deal with the socio-economic impacts of development,

Regarding existing and planned overcapac-ity, those who favor reconsideration anddelay of the 1982 leasing schedule in thePowder River basin cite the finding that thecapacity of currently operating mines com-bined with potential capacity from undevel-oped Federal and non-Federal properties that

*1)01 is [it)nsidcrlng various prt)p(wlls I(J prcscn I [I) I) OF; (IJlih(?r:ilizc the riiligonm: re[luir(~nlents f[~r lt?i}scs issued prit]r t{)Auxust 1976.


have favorable development potential couldreach 350 million tons per year in 1990. Thiswould be 125 million tons per year more thanOTA’s estimate of the “most likely” 1990 de-mand for Powder River basin coal. Even ifonly 11 out of the 17 undeveloped coal proper-ties were developed, total design capacitywould still be 290 million tons per year. Op-ponents of renewed Federal leasing in 1982point out that this tonnage substantially ex-ceeds OTA’s likely estimate of 200 million to225 million tons per year.

If leasing of Federal coal were deferred un-til 1985, the newly leased properties wouldnot be producing at design capacity untilabout 1995. As discussed above, available de-mand projections for 1995 are highly uncer-tain, and range from 306 million to 491 mil-lion tons per year. At this time, the lower por-tion of this range appears more likely. Leas-ing opponents consider the overcapacity to besufficient to provide adequate coal to meetdemand through 1995 because they believeDOE’s targets reflect unrealizable policy ob-jectives. The difficulty in making sound pro-jections beyond 1990 precludes a definitiveresolution of the disagreement on supply-demand between the perceptions of the pro-ponents and opponents of additional leasingin the Powder River basin in 1982.

The prospects for significant productionfrom the PRLAs in the 1990’s are more specu-lative. Processing PRLAs will not be com-pleted until 1984. * Until the rights of the ap-plicants are determined, there will be little de-finitive information about ownership, quanti-ty of coal or quality of the resource. Althoughthe full extent of reserves within the PRLAs isnot known with certainty, it is estimated thatbetween 35 million and 60 million tons of coalper year may be minable from such landsthroughout the West by 1994 . Al thoughPRLAs may contribute to future production,it is unlikely that they will add much produc-tion within the next 15 years; their contribu-tion to production capacity in the P o w d e rRiver basin will probably be limited to about

*See ch. 9 for a discussion of PRLAs.

20 million tons per year or less. (See tables 64and 65.)

Opponents of the 1982 leasing schedulealso contend that a delay to 1984 or beyondwould allow more time for DOI to prepare en-vironmental baseline studies and permit de-tailed consideration of the unsuitability cri-teria that could possible disqualify some pro-posed lease blocks. However, recent develop-ments within DOI suggest that under pro-posed changes in the Federal coal leasing pro-gram unsuitability criteria would not be con-sidered in processing PRLAs, and a numberof criteria of unsuitability that were appliedin the prelease tract selection stage wouldbe deferred until later in the process, e.g., themine permit stage. Furthermore, it has alsobeen suggested that fewer prelease determin-ations of the resource base and mining condi-tions be made and that other planning fea-tures be dealt with by the lessee after leasingrather than before. However, both the Gener-al Accounting Office6 and the American Min-ing Congress7 have criticized DOI for using in-adequate data for land use planning on leasesales.

Those advocating a delay of the 1982 salealso claim that the transitional sale sched-uled for the Powder River basin was accel-erated to show that coal leasing could resumequickly after the leasing moratorium waslifted and the new Federal coal managementprogram was formulated. Because of this,they suggest, insufficient consideration wasgiven to competitive factors in the selection ofleasing tracts. Citing the DOJ report on com-petition in the coal industry that criticized theleasing program for giving inadequate atten-tion to the pattern of leasing and how existingownership may influence the competitivenessof upcoming lease sales, opponents of im-mediate leasing claim that deferral of the1982 lease sale would permit more time forconsidering the implication of leasing pat-terns on competition,

6Mapping Problems May Undermine Plans for New FederalCoal Leasing, U.S. General Accounting Office, Dec. 12, 1980.

‘Charles F. Cook, Vice President, American Mining Con-gress, “AMC’s Recommendations 10 Secretary Watt on Reformof Interior Regulations,’” memorandum, Feb. 17, 1981.

Ch. 7—The Powder River Basin: A Case Study 197

Opponents to the 1982 lease sale in thePowder River basin also feel that the largesale will bias the land-use planning processtoward mineral development at the expenseof other Federal resources and make it moredifficult for Federal surface managementagencies to apply effectively the principles ofmultiple-use and sustained yield to managepublic resources,

Finally, opponents of the 1982 lease sale inthe Powder River basin claim that by defer-ring the lease sale until 1984, State, county,and local governments could have time tomeet the needs of expanded coal developmentand plan for the socioeconomic impacts thatwill result, Federal coal leasing decisions inthe Powder River basin can have significantimpacts on the local communities and the en-tire region, Many of the socioeconomic im-pacts of Federal resource development mustbe dealt with by State, county, and localgovernments.

Because of the importance of Federal landswithin the basin. the decisions of DOI with

regard to coal development will determine, toa large extent, the future of the region,the character of the economy and lifestyle ofits residents. Whether the economic growthand social change that will accompany devel-opment of Federal coal resources is desirableor undesirable in the context of local andcounty planning objectives, the Federal Gov-ernment, according to those opposing accel-erated leasing, is obligatedand coordinate coal leasingities and objectives of thebasin.

Another factor in Federalin the broader sense is to

to carefully planwith the capabil-residents of the

leasing decisionsensure that the

benefits and negative impacts of resource de-velopment are distributed equitably amongthe various regions of the country. All ofthese reasons, according to those favoringdelay, can be considered and balanced if suf-ficient time is given to planning, analysis, andseeking a balance in approaching Federalcoal leasing among all coal-producing re-gions.

CHAPTER 8

Transportation

List of Tables

Page● ● ● ● * ● .216. . . . . . . . . 2 1 9

CHAPTER 8

Transportation

The existing transportation network in theWest was generally adequate to move coalproduction from Federal leases and privatetracts in 1980, although a number of specificbottlenecks have been identified, It will beasked to carry greatly increased quantities ofcoal in the future. The key link in this net-work is rail haulage, which handled about 61percent of Western coal production in 1979and is likely to originate even more in 1990.Most Federal coal leases are and will beserved by rail. The principal constraint thatmay materialize in moving future productionof leased coal to its markets is the willingnessof the railroads to invest sufficient capital intime to satisfy demand for increased rail serv-ice from all shippers, including Federal coal.The mine-to-market transportation costs ofWestern coal range from about 10 to over 70percent of delivered fuel costs and constitutean important factor in developing future de-mand.

Western coal is mined at a considerabledistance from most of the ultimate demand itserves, usually electric utility demand, and isused in very large quantities at low unit cost.Coal production therefore creates a substan-tial requirement for inexpensive bulk trans-portation services, Western coal now repre-sents perhaps one-third of all the freightmoved in its principal market area.

Utilities are the chief consumers of coal. In1979 they converted 90 percent of all Westerncoal production to electricity (table 66). Newutility projects are subject to long-term plan-ning, ideally for their entire useful lives. Coalsupply, transportation, generating plant sit-ing, and electric transmission are all coor-dinated, arranged, and fixed. The availabilityand cost of different modes of transportationwill influence the final choices, and therebyshape the future market and transportationnetwork for western coal,

The two most important ways of movingWestern coal in 1979 were by rail and wire.

Railroads originated* 61 percent of al lWestern coal production in 1979 (table 66).Most of this coal traveled more than 750miles, and some was delivered to customersby water, Utilities can also choose to burncoal in nearby or mine-mouth generatingplants and distribute the electricity to distantcustomers through high-voltage transmissionwires, In 1979, 36 percent of all western coalproduction was hauled short distances bytruck, tramway, etc. , to local generatingplants (table 66). Some of this power was con-sumed locally, but a substantial amount wastransmitted over hundreds of miles,

Three major long-distance transportationcorridors exist for Federal coal. powder Riverbasin coal flows east by rail to utilities in themiddle and upper Midwest. Some of this coalhas penetrated Indiana, western Kentucky,and Ohio markets via the Ohio River (see ch,5; fig. 26.) A second corridor flows from thebasin south into Arkansas and Texas. Thiscoal has been shipped entirely by rail, al-though a coal slurry pipeline is projected tocarry 25 million tons per year from the basinto Arkansas on completion in the late 1980’s.The third corridor originates in the tri-Statearea of New Mexico, western Colorado, andUtah. It moves west into Nevada and Califor-nia. Coal traffic from the northern Rockieswest to Oregon and Washington is beginningto increase. Another corridor from Coloradoand Utah to southern California may emergeif an export market for Western coal developsin Asia.

Other transport modes wi l l not soonchallenge the railroad’s dominant position inthe transportation of Western coal. Economicand technical considerations restrict thetransmission of electricity over distancesmuch beyond 500 miles. However, higher

* Rail-originated coal includes: 1) coal hauled exclusively byrail; 2) coal that is transferred to river haulage; and 3) coaltransferred for shipment on the Great Lakes.

201

— ——— .---— - . . - - . — — - — — .— . . .


Table 66.—Distribution of Coals (bituminous, subbituminous, and lignite) Produced in the WesternUnited 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 Mexico c Mexico d Wyoming Utah Dakota Washington subtotal total

United StatesElectric utilities . . . . . . . 33,933 14,659 22,582 68,529 7,098 13,361Coke plants . . . . . . . . . .

36,768 196,930 549,774170 3,362 — 943 —

Other industrial . . . . . .— — 4,475 76,971

3,866 1,457 2,265 3,148 2,492 1,531 482 15,241 67,140Retail. . . . . . . . . . . . . . . . 89 66 1 188 182 47 99 672 1,908Miscellaneous . . . . . . . 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-railElectric utilities ... . . . 3,473 10,519 10,745 50,323 2,071 4,951 22,159 104,241 287,950Coke plants . . . . . . . . . . 170 3,362 . 943 –Other industrial . . . . . . .

— — 4,475 46,0331,145 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-riverElectric utilities . . . . . . . 177 — — 4,930 981 – 1,616 7,704 91,100Coke plants . . . . . . . . . . — — —

Other industrial . . . . . . .

— — — — — 18,989183 1 — — 184

Retail sales . . . . . . . . . .

— — — 2,650— — — — — — — — 31

Total . . . . . . . . . . . . . . . 360 1 — 4,930 981 – 1,616 7,888 112,771

Great LakesElectric utilities . . . . . . . — — — 5,413Coke plants . . . . . . . . . .

— — — 5,413— — —

Other industrial . . . . . . .— — — — —

— — — 6 45 51Retail sales . . . . . . . . . .

— —— — — 4 — — — 4

Total . . . . . . . . . . . . . . . — — — 10 — — 5,459 5,469 20,919

Tidewater . . . . . . . . . . . . . — — — — — — — — 4,881

TruckElectric utilities . . . . . . . 9,272 4,140 5,622 5,158 2,186 3,746 30,124 78,005Coke plants . . . . . . . . . .

—— — — —

Other industrial . . . . . . .— — — 3,674

1,278—

109 13 134 758 26 16 2,334 21,862Retail 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 andprivate railroad

Electric utilities . . . . . . . 21,012 — 6,214 8,118 1,860 4,664Coke plants . . . . . . . . . .

7,580 49,448 77,875— — —

Other industrial . . . . . . .— — — —

1,259— 1,081

— — — 206 1,465Retail sales . . . . . . . . . .

— — 1,465— — — — — — — — —

Total . . . . . . . . . . . . . . . 22,271 — 6,214 8,118 1,860 4,870 7,580 50,913 80,422aData may not add because of rounding.bThis province includes all of Kansas, Missouri, Texas, and Oklahoma counties of Coal, Craig, Latimer, Muskagee, Okmulgee, Pitt.sburg, Rogus, Tulsa, and Wagoner.clncludes all of Colorado, and those counties in New Mexico not listed in footnote d.dlncludes 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 Con-

sumer 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 competeeconomic shipping distance of mine-mouth with railroads over some routes but all thepower , and bulk power i s l ike ly 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 produc-tion in 1979 between end uses and means oftransportation is presented in table 66, Elec-tric utilities c o n s u m e d 9O percent of al lWestern coal (197 mill ion tons) . Of thatamount, 104 million tons—or 53 percent ofthe utility-consumed coal—was hauled byrail; 4 percent by river; 3 percent via the GreatLakes; 15 percent by truck; and 25 percent bytramway, conveyor, or private railroad. Mostof the utility-consumed coal that was movedby rail, river, and Great Lakes traveled at least750 miles. The coal described as transportedby water had to travel 500 miles or more byrail to reach a connecting point. The longestall-rail hauls are about 1,800 miles. Coalburned in mine-mouth plants and short-haulcoal is typically moved by conveyor, truck, orprivate railroad. Much of the electricity pro-duced by this locally burned coal is shippedby wire over distances up to several hundredmiles. Coke plants used only 2 percent of theWest’s coal production in 1979, and all of thatwas hauled by rail. Other industrials c o n -sumed about 7 percent of Western coal, al-most three-quarters of which was moved byrail, Fewer than 1 million tons was sold as aretail product or used for miscellaneous pur-poses. Railroads moved 55 percent of West-ern coal output exclusively, and connectedwith water for an additional 6 percent.

Table 67 presents origin and destinationdata for Western coal production in 1979 bydistrict of origin and State of destination. Inthis table, destination means where the coalwas consumed, not where resulting electrici-

ty may have been consumed. Thirty Statesconsumed Western coal in 1979. Table 68 dis-plays dependence on Western coal for each ofthe 30 States. The degree of dependence notsurprisingly was related to the distance fromthe Western coalfields: the further the con-sumer market, the less dependency on West-ern coal. Western coal’s penetration intoOhio, Indiana, and Illinois has been related tosulfur-emission standards, which make West-ern low-sulfur coal attractive despite the dis-tance and the cost. This market should con-tinue for older plants, but new source per-formance standards (1979) may make localcoals more attractive to utilities in theseStates.

Table 69 ranks these 30 States according tohow much Western coal each consumed in1979, Texas was by far the largest consumer;more than half of its consumption was minedlocally and shipped a short distance. How-ever, the powder River basin shipped about11.6 million tons to Texas by rail. Most of the16 million tons that Wyoming consumed wasmined locally, for customers such as mine-mouth plants, All of Illinois’ 15,2 million tonswas shipped by rail, most of it from Wyomingand Montana. Most of Minnesota’s 12.8 mil-lion tons was hauled by rail from Montana.Kansas, Iowa, and Nebraska tapped thepowder River basin via rail for their coal.North Dakota used mostly locally minedcoals. Colorado and Arizona consumed localcoals hauled by rail. Little coal moved west tothe Pacific rim.

. . . . .


Table 67.—Distribution of Coals (bituminous, subbituminous, and lignite) Produced in the Western United Statesin 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

IndianaRailRiver

IllinoisRailRiver

MichiganGreat Lakes

WisconsinRailRiverTruck

MinnesotaRailRiverGreat LakesTruck

IowaRailRiverTruck

MissouriRailTruckTramway, etc.

North DakotaRailTruckTramway, etc.

South DakotaRailTruck

NebraskaRail

KansasRailTruck

FloridaRiver

TennesseeAlabamaMississippi

RailRiver

ArkansasRailRiverTruck

OklahomaRailTruck

TexasRailRiverTruckTramway, etc.

ColoradoRailTruck

5%5,0007.7%1.9%

15,29735.7%

0.1 %4,353

13.4%5,546

31.5%4.8%0.1

12,78677.3%4.6%7.8%0.2%9,38261 %5.7%2.3%9,339

22.9%10.5%4.9%

11,04921.6%34.3 %

44%2,911

94.7%5.3%4,929100%9,63483%17%

330.5%Neg f

Neg f

95733 %

1%1,94084%3.8%9.6%4,83495%4.9%

40,22832.6%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

28,70325,989

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 2.41.9e

Neg0.1

0.4 15.7

13.4

17.5 144.8

0.1

Neg0.2

0.1

3.4

2.3

9.810.54.9

Neg Neg

Neg

4.5 523.8

3.7 1.1 8.3

9.2 684.47.8

Neg

Neg 0.81.8

Neg

Neg 21.634.344

890.2 5.85.3

8.4

3.9

86Neg 5.6

0.1

Neg

6.717

72

0.5

24 9.5Neg1

786.33.89.6

34.9

0.2 92

1.6 Neg 242.30.2

13.851.3

4.4

4332

23 NegNeg


Table 67.—Distribution of Coals (bituminous, subbituminous, and lignite) Produced in the Western United Statesin Calendar Year 1979 by District of Origin and Method of Movement (tonnage in thousands of tons) —Continued

District of origin

UtahRailTruckTramway, etc.

MontanaRailTruckTramway, etc.

IdahoRailTruck

WyomingRailTruckTramway

New MexicoTruckTramway

ArizonaRail

NevadaRailTruck

WashingtonRailTramway, etc.

OregonRail

CaliforniaRail

30-State total

6,797 6,7962 7 . 3 %

45.3%27.4%

3,731 3,73032%

0.3%68%

516 51696%

3.9%16,005 16,005

17%32%51%

8,702 8,70229%71%

12,878 12,878100%

4,303 4,30325%75%

5,664 5,64310.5%89.2%

243 242100%

2,735 2,73099.8%

482,565 216,644

(100%)

(100%)

(100%)

(100%)

(100%)

(100%)

(100%)

(100%)

(100%)

(99.8%)

(45%)

18.3Neg

0.8

2.1

1

4

2

0.3 0.2

2.8 0.8

37.6

2871

0.40.8

3.50.2

81

16.53251

95

Neg75

2.3

89.7

11 51

8.544.527.4

1.2

133.9

0.30.3

1

23

7.7

26.30.1

68

89.2

6.2

a percentage may not add due to rounding, Neg indicates negligible coal tonnage.bThls province includes all of Kansas, Missouri, Texas, and Oklahoma counties of Coal, Craig, Latimer, Muskogee, Okmulgee, Pittsburg, Rogus, Tulsa, and Wagoner.clncludes all of Colorado, and those counties in New Mexico not listed in fotnote d.dIncludes 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.

—— . .— .—


Table 68.—Western Coal Consumed as Percent of Total Coal Usedin 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% I l l i no is . . . . . . . . . 36% lowa .. . .69% Minnesota . . . . . . . 89%Indiana . . . . . . . 1O% Wiscons in . . . . . 36% Arkansas . . . . . . . . 98%Alabama . . . . . . O% Mississippi. . . . . 34% Ok lahoma. . . . . . . . 100%Florida . . . . . . . . 1% Missour i . . . . . . . 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 tonsGeographic div is ion tons/year million tons/year million tons/year million tons/year plus/year

East North Central Ohio . . . . . . .3.8 Wisconsin .. ..5.5 Illinois .. .15.2Indiana. .. ..5.0Michigan .. .4.3

East South Central Alabama . . . . . . Neg. aMississippi. .. .1.0Tennessee. . . . . Neg.a

Florida . . . . . . . .0.01b

West North Central S. Dakota .. ...2.9 Nebraska. .,4.9 lowa . ........9.4 Minnesota .. .12.8Missouri . . . . ..9.3 N. Dakota. .. .11,0

Kansas. . . . . . 9,6West South Central Arkansas .. ...1.9 Oklahoma ..4.8 Texas. .. .40.2Mountain Idaho. ... , .. ..0.5 Montana .. .3.7 Utah . ........6,8 Colorado .. ..13.0 Wyoming .16 .0

Nevada . . . .4.3 New Mexico . . .8.7 Ar izona. . . . . .12.9Washington . . .5.6

Pacific Oregon ., .. ...0.2California .. ...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).

— —


Rail: Capacity Assessment

Railroads carry most leased coal becauserail is the only transportation mode currentlyavailable to move large quantities of coalaway from leases. In most cases, a mine isserved by a single rail line.1 Rail transport isalso an efficient, available way to move thecoal over long distances to major consumers.

Western rail lines are adequate to handlecurrent coal shipments. Car shortages andtraffic bottlenecks were a problem in the past,but the National Coal Association has notheard similar reports for more than a year.2

Railroads are expected to maintain theirdominant position in the transportation ofWestern coal, The ability of Western railroadsto handle increased future production of Fed-eral coal will be influenced by: demand forrail services to transport Federal coal, non-Federal coal, and noncoal commodities; thecapacitities, condition, location, and utiliza-tion of rolling stock, tracks, and loading andunloading facilities; and the management, in-vestment policies, and financial character-istics of rail carriers, shippers, and utilities.

Physical Capacity

Future Western coal traffic may stretch thephysical capacity of the railroads. The Na-tional Energy Transportation Study (NETS)predicted a “, . . potential shortfall in the ca-pacity of the Nation’s railroad system as itnow exists to move the 1990 predicted coal

1The National Coal Association (NCA) estimates that 85 to 90percent of Western coal production is “captive” to a single car-rier. The Association of American Railroads (AAR) claimsthere is no merit in NCA’s assertion. “Such an assessmentoverlooks competition among railroads, among different coal-producing areas—served by competing railroads—and com-petition with other sources of energy, ” according to WilliamH. Dempsey, president of AAR. DOE could not come to anyfirm conclusions regarding possible anticompetitive effects ofrailroad involvement in Western coal, although it warned of“possible” problems if coal is leased to the Burlington North-ern. Department of Energy, Coal Competition: Prospects for the1980s, Draft Report (Washington, DC.: DOE, January 1981),pp. 270-291.

2Telephone interview with Joseph Lema of the National CoalAssociation, March 1981.

traffic particularly in the West.”3 congestionwas projected to occur at almost 50 Westernrail links in 1990, and a smaller number ofcongested links were identified for 1985 atlower coal traffic. The l990 capacity shortfallassumes that Western coal shipments by railincrease from about 97 million tons in 1975 to625 million tons, and that no new rail invest-ment occurs other than that already under-way as of 1979 -1980.4 More recent Depart-ment of Energy (DOE) coal production fore-casts show smaller increases in Western coaltraffic, projecting that the NETS 1985 trafficlevel will not be reached until nearly l990.This would give the railroads much moretime to improve their facilities.

Several problems in the physical plant ofthe Nation’s railroads have been identifiedwhich bear on Western rail capacity. Limitedlocomotive-manufacturing capacity mayprove to be one constraint because expectedlocomotive requirements in 1990 for all railneeds are “substantially in excess of currentfleet size,” according to the ICC.5 A doublingof the current national 28,000 locomotivefleet is estimated to be needed by l990, whichwould require a 15- to 20-percent growth inlocomotive-manufacturing capacity annually,While some excess capacity in locomotivemanufacturing is currently reported to exist,heavy demand for locomotives may tax thecapability of this sector to respond.

The adequacy of the hopper-car fleet maybe another question mark. The Association ofAmerican Railroads (AAR) estimates that285,000 cars, 80 percent of the open-top hop-per fleet, were dedicated exclusively to coal.The fleet averaged 84.5 tons capacity and 25.5

3 U.S. Departments of Energy and Transportation, NationalEnergy Transportation Study: A Preliminary Report to the Presi-dent (Washington, D. C.: DOE/DOT, July 1980), p. iii (herein-after INETS).

4Ibid., pp. 34, 37.5International Commerce Committee, Ex Parte No. 347 West-

ern Coal Investigation-Guidelines for Railroad Rate Structure(Washington, D. C.: ICC, 1979).


trips each in 1979.6 With these figures, AARcalculated the 1979 theoretical capacity of thecoal fleet at 616 million tons, 23 percent in ex-cess of the 500 million tons estimated to havebeen originated on both major and lesser rail-roads. However, the average coal car made 23rather than 25 trips in 1979 (with 45 mainte-nance days), thereby reducing calculated fleetcapacity to about 555 million tons, an excessof 11 percent rather than 23 percent. It is dif-ficult to determine whether the average coalcar made fewer trips than the fleet averagebecause of lack of demand or operational dif-ficulties.

Unit trains haul most Western coal andalmost all Federal coal. These trains typicallyconsist of 100 100-ton hopper cars that shuttleexclusively between a mine and a utility. Agrowing percentage of these cars—now about40 percent—are owned by the utilities them-selves. The amount of rolling stock needed inthe next decade will depend on coal demandand the time needed to complete a unit traincycle—loading, hauling, unloading, andreturn. The shorter the cycle, the fewer carsare needed, other things being equal. Cycletime, which ranges from several days to 14days or more,7 is a function of the efficiencyof the loading and unloading facilities, rollingstock, roadway, and traffic control systems.unit trains typically experience shorter cycletimes than mixed-freight trains—most Bur-lington Northern (BN) unit trains make theirroundtrips in 4 to 7 days8—and their utiliza-tion is generally much higher.9 The coal fleet

6AAR, “Submission to the interagency Coal Export TaskForce,” Oct. 2, 1980, p. 14.

7Data from the Association of American Railroads indicatethat the cycle time of the average coal car was about 14 days in1979. This figure was derived by dividing 365 by 25.5, the aver-age number of trips per year, according to AAR. See AAR,“Submission,” p. 16. The Congressional Research Service cal-culated a 13-day average coal car cycle several years ago, SeeU.S. Senate, Committee on Energy and Natural Resources, andCommittee on Commerce, Science, and Transportation, Na-tional Energy Transportation, Vol. I—Current Systems andMovements (Washington, D. C,: U.S. Congress, 95th Cong., 1stsess., 1977), p. 56.

80TA correspondence with Allan Boyce, Assistant Vice-President of Burlington Northern, Feb. 26, 1981.

9Willard D. Weiss and Ronald Dunn, “Modern Railroad Con-cepts for Transporting Western Coal, ” a paper presented atEngineering Foundation Conference on Transportation ofFuels for Utility Consumption (Henniker, N. H., 1976), p. 3.

could be stretched by future coal traffic if cur-rent overcapacity is-taken as a sign to reducefuture car orders. If demand for another bulkcommodity, e.g., grain, were suddenly to rise,coal cars owned by the railroads might bequickly converted. This kind of situation en-courages utilities to invest the $45,000/car inbuying their own hoppers.

Rail capacity did not present a problem in1980 as the growth in coal demand slowedand improvements were made in rolling stockand roadways. Three years ago, a number ofWestern coal shippers reported problems inobtaining hopper cars for mine loadings de-spite excess capacity on paper. Peabody’s BigSky Mine reported, for example, a shortfallof 200,000 tons—about 9 percent of totalplanned production in 1978—due to carshortages and scheduling diff icult ies.10 Asimilar situation was reported at ARCO’sBlack Thunder Mine. Coal car shortfal lsforced ARCO to ship less coal than requiredby its contracts. The cycle time from ARCO’smines to Southwest Public Services’ Barring-ton Station plant in Amarillo, Tex., jumpedfrom 87.5 hours (as stipulated in its 1977 BNcontract) to 190 hours in 1978, and the utilitywas forced to increase the number of unittrains and purchase coal from other sup-pliers. 11

The recent slower growth in demand forWestern coal has reduced the pressure on theWestern railroads. This breathing spell hasenabled the rail lines and utilities to have newrolling stock delivered before widespreadshortages materialized. The diversification ofhopper-car ownership should also benefitcoal deliveries by creating less pressure onthe rail-owned fleet and by guaranteeing caravailability to large utility consumers. When arailroad controls the hopper cars, it controlstheir distribution and can, if it chooses, favorsome shippers. Utility ownership of hoppercars then provides an insurance for the utilitythat its coal can be shipped.

It does not appear that the reported coalcar shortages of 3 years ago had much to do

l~TA draft report on the Wyoming task force.lllbido


with technology, fleet capacity, or railroadfinances. Since the railroads have argued thattheir capacity has always been adequate—in-deed, in excess–the shortages that have de-veloped may have been caused by railroadpolicies regarding maintenance, traffic co-ordination and the like, and management in-efficiencies with respect to planning and in-vestment. It is reasonable to assume that themore Western coal production strains fleetcapacity in the future, the greater the role thatmanagement policy and management effi-ciency will play,

Two other major rail infrastructure fac-tors—roadway variables and traffic-controlsystems —determine the number of trains thatcan use existing track at any one time. Carry-ing capacity is related to track configuration,the extent of single and double trackage, thenumber of sidings, and their length and spac-ing. Double tracks facilitate fast haulage inboth directions, Sidings on a single trackallow trains to pass in either direction. Themore sidings and the closer their spacing, themore trains can be run on a single track. Thelonger the siding, the longer the train a trackcan handle. Traffic control systems deter-mine how close trains can be operated to eachother. Automated Block Signals (ABS), a man-ual system, is less capable than CentralizedTraffic Control (CTC), a radio and remotecontrol arrangement, Table 70 estimates thenumber of coal unit trains that can be run onthree different track configurations with aCTC signal system. Longer sidings that arecloser together can double the daily train traf-fic on a single track. Double tracking hasthree to five times more capacity than a singletrack.

BN, which originated more than half of thecoal hauled by rail in the West, controls threekey rail corridors from the Powder Riverbasin:

1.

2.

3.

the line east through North Dakota intothe North-Central States;the line east through Nebraska and Iowa;andportions of the line south through Col-orado and Texas.

Table 70.—Estimated Capacity of Alternative TrackConfigurations With Centralized Traffic Control

(CTC) Signal System

Average number ofcoal unit trains

Configuration of rail line per daya

Single track2½ mile sidings, 11 miles apart . . . 20-252½ mile sidings, 7 miles apart. . . . 30-355 mile sidings, 7 miles apart. . . . . . 40-45

Alternating single/double track10 miles double and 30 miles singletrack, with 2½ mile sidings . . . . . . 50-5510 miles double and 10 milessingle track . . . . . . . . . . . . . . . . . . 60-70

Double track . . . . . . . . . . . . . . . . . . . . 70-125a Assurnes a capacity of 10,000 tons per train.

SOURCE: Samir A. Desal and James Anderson, Rail TransportationRequirements for Coal Movements in 1980 (Cambridge, Mass.. InputOutput Computer Services, Inc , 1976), p 2-32.

BN has been upgrading the single trackwith sidings on its Nebraska line (betweenAlliance and Lincoln), which had an esti-mated capacity of 15 to 20 trains per day inthe mid-1970’s, l2 A CTC signal system withdouble track and alternating single and dou-ble tracks are being installed. The UnionPacific (UP) appears to be better able to trans-port Wyoming coal east because it double-tracks and uses heavier gage rail.13 However,the east-west UP line through southern Wyo-ming and Nebraska does not originate coalfrom the Powder River basin, which is servedexclusively by BN. UP track in Wyoming andNebraska is divided about equally betweenCTC and ABS traffic control systems.

Financial Considerations

NETS estimated that all railroads will haveto invest $5 billion to $7 billion between 1978and 1985 in rolling stock to have the capacityto handle all future traffic. 14 Another $4billion to $5 billion will be needed to upgradeexisting track and construct new coal-trans-

12Montana Energy Advisory Council, Montana ‘S Major Ener-gy Transportation Systems: Current Conditions and Future De-velopments (Helena, Mont.: State of Montana, December1976), p. 49.

13 Comment from the Wyoming task force, Wyoming Report,VOl. 1, p. 6 3 .

14 NETS, p. 62.

. .


.

port lines.15 Inasmuch as most additional coalproduction will occur in the West, it can beassumed that at least half of these sums willneed to be invested there by Western rail-roads. Recent coal traffic projections indicatethat this schedule may be stretched out, butthe investment will ultimately be necessary.

Western railroads range from highly profit-able to below-average money makers.16 Table71 presents company performance data for 11railroads, assembled by Forbes, The two larg-est Western coal carriers—Burlington North-ern and Union Pacific—both ranked near thetop of the list in growth, but were very dif-ferent in profitability. BN, the major Westerncoal line, showed below-average profitabilitymeasures, but UP profitability was well aboveaverage for the railroad industry.

‘51 bid., p. 64.16The M ilwaukee 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 thepurchase of Milwaukee track. BN and UP have acquired about500 miles so far. Standard and Poor rated Western roads in1979 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 Mil-waukee (D). A number of mergers are being negotiated thatmay affect coal haulage, including the Union Pacific with theMissouri Pacific, Burlington Northern with the St. Louis-SanFrancisco, and the Santa Fe and Southern Pacific.

A railroad’s ability to borrow capital orraise it through stock sales is closely relatedto its rate of return over a period of time, aswell as expectations of future growth. ManyWestern railroads are subsidiaries of diver-sified companies who must choose wheretheir capital should be invested. In 1977,return on rail assets amounted to 8.6 percentfor the Denver and Rio Grande; 3.3 percent,Burlington Northern; 5.9 percent, Santa Fe;2.3 percent, Southern Pacific; 7.9 percen t ,Union Pacific; 5.8 percent, Missouri Pacific.17

Yet the parent companies of these lines madeat least 10 percent on their other assets(nonrail transport, real estate, forest, andnatural resources). Table 71 shows a similarcomparison between the rail industry and theall-industry medians.

Table 72, which summarizes the coal busi-ness of the major Western railroads, indicatesthat the coal revenues received by the West-ern roads were low in proportion to coal’sshare of their total freight traffic. Coal, for ex-ample, made up 44 percent of BN’s totalfreight in 1978, but accounted for only 24 per-cent of all of BN’s freight revenues,

1 7 NET’s , p . 67.

Table 71 .—Railroads: Yardsticks of Management Performance

Profitability Growth

EarningsReturn on equity Return on total capital Sales per share

Latest Debt/ Latest Net5-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 10.9Union Pacific . . . . . . . . . . . . . . . 13.3 3 15.6 0.3 10.3Southern Railway. . . . . . . . . . . . 12.9 4 14.3 0.6 8.1Norfolk & Western Ry . . . . . . . . 12.6 5 15.1 0.3 9.5

Santa Fe Industries . . . . . . . . . . 10.4 6 13.3 0.3 8.9IC Industries. . . . . . . . . . . . . . . . 9.8 7 10.2 0.7 5.7St Louis-San Fran Ry . . . . . . . 8.0 8 10.3 0.8 6.3Burlington Northern. . . . . . . . . . 7.2 9 10.7 0.5 7.0Southern Pacific . . . . . . . . . . . . 6.9 10 7.1 0.6 4.8CSX . . . . . . . . . . . . . . . . . . . . . (b) (b) (b) (b)

6 6.6% 4.0% 10.8% a

1 11.2 8.0 14.2 a

2 8.9 8.6 19.54 7.4 10.6 10.63 7.4 13.6 5.9

5 7.2 9.0 13.47 6.1 2.7 19.49 5.1 5.3 9.48 5.2 5.5 14.9

10 4.9 5.3 8.7(b) 6.7 9.2a

6 20.8% a 34 18.7 a 51 21.0 27 13.3 9

11 18.9 4

5 14.3 72 13.3 88 14.5 63 25.5 1

10 6.4 109 6 1a

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

aFour year growth.bNot available: not ranked.

SOURCE: Forbes, Jan. 5, 19b1, p. 92


Table 72.—Coal Carried and Revenue Received as Percentage ofTotal Freight for Western Railroads, 1978

Coal originated Total coal revenues

Coal as Coal revenue asTonnage percent of Coal revenues percent of all

Railroad (million tons) all freight (million dollars) freight revenue

Burlington Northern . . . . . 63.0 44 $463.7 24Union Pacific. ... , . . . . . . 17.3 26 167.6 11Denver & Rio Grande . . . . 13.2 69 65.7 31Missouri Pacific . . . . . . . . 9.2 14 63.8 5Milwaukee . . . . . . . . . . . . . 4.9 19 34.0 8Chicago & 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 movingcoal are lower than costs for many other com-modities. Western coal haulage costs are low-ered by the extensive use of dedicated, highlycost-effective unit trains, often owned by theconsumer rather than the carrier. Coal ship-pers, unlike consumers of many other rail-hauled commodities, even build and operatetheir own loading and unloading facilities.Railroads also use a betterment accountingsystem, which tends to show lower earningsthan would depreciation accounting. Thesefactors mitigate what otherwise seems to be agenerally bleak profit picture for coal haulageby Western carriers.

Rail-related capital can be raised in manyways. However, the parent companies ofWestern railroads may be reluctant to investtheir limited capital in new rail capacity ifnonrail investments consistently generategreater returns. Consequently, future rail in-vestment and capacity for Federal coal seemsto be linked more to the investment prioritiesof individual railroads than to questions ofphysical plant, technology, and capital avail-ability. Although sufficient investment hasbeen undertaken to provide adequate capaci-ty for current and future coal traffic over thenext few years, constraint on Western coalproduction could develop by 1990 or 1995 ifthe railroads decide not to make additionalcapital stock investment and roadway im-provements.

This question of capital application wasspelled out in detail by Richard Bressler,

President and Chief Executive Officer of BNto Western utility executives, Bressler said:

One of the first things 1 did at BurlingtonNorthern was to look at where our invest-ments had been made.

Here’s what I found. For many years, Bur-lington Northern has invested more than itscash flow,

. . . and a large part of those investmentshas gone to coal–into our ability to haul coalfrom the Powder River basin to you, the util-ities. . . .

about $1 billion has been intvested in(coal-carrying) capability so far. Our planscall for the investment of another billionover the next several years.

. . . Last year, the railroad made $41 mil-lion before tax, according to our annualreport.

$41 million–that’s a before-tax rate of re-turn of less than 4 percent on what Burling-ton Northern recently invested in coal-haul-ing alone. Less than 4 percent.

I can look at an array of tariffs andfigure out that relatively little of that $41 mil-lion came from hauling coal,

. . . we at Burlington Northern will be verycareful about future investments in coal-hauling capacity—at least until the picture isclear.

Burlington Northern has other good in-vestment opportunities, many solid oppor-tunities.

. . . Burlington Northern is prepared tocontinue investing in coal capacity. We areprepared to continue our commitment, as-suming there is a reasonable return on suchinvestments, (Emphasis in the original. )18

18Richard M. Bressler, “Remarks Before the Western CoalTransportation Association” Denier, Sept. 10, 1980.


The unclear picture of the future to whichBN’s Bressler referred involves future railrates, coal demand, litigation (utilities have 18separate suits against BN related to coal-haul-ing contracts), and slurry pipelines. If an ap-preciable investment is made in pipelines, BNvice-president Allan Boyce said, the railroadwill cut back its coal-related investment.19

If return is not sufficient to cover antici-pated investment, other financing arrange-ments—such as borrowing, shipper or cus-tomer purchase of hopper cars, shipper con-struction of roadway, or public subsidy,among others—will be considered. Such ar-rangements are an increasingly common wayof financing new railroad equipment. Rollingstock is normally financed through eitherleases (often from banks) or equipment trustcertificates, which are, in effect, mortgages.Utilities that have long-term coal contractsnow frequently finance the hopper cars andlocomotives necessary to transport the coal.In some cases, utilities and coal shippers arealso providing money to the railroads for im-proving roadbeds. The Staggers Act of 1980,which partially deregulated the railroads,provides the legal framework for utilities tonegotiate long-term contracts with railroads.Coal industry spokesmen believe that custom-ers and shippers will begin to negotiate suchcontracts because they introduce morepredictability into rate and supply issues.

Western railroads have made major capitalinvestments in recent years to meet expectedcoal traffic. The higher efficiencies that thisinvestment has produced and the slower-than-expected rate of growth for Western coalhas resulted in excess coal-haulage capacitythroughout the Western rail network. Therailroads have argued that the Interstate Com-merce Commission’s (ICC) rates have not pro-duced sufficient return to continue invest-ment at recent levels. Excess capacity is an in-efficient use of capital and tends to inflate railrates. However, if rail rates are not highenough, additional needed investment willnot be made. Rates must cover necessary in-

190TA telephone interview with AlIan Boyce, Assistant Vice-President of Burlington Northern, March 1981,

vestment but not excessive overcapacity.Even though excess capacity is now a com-mon complaint among railroad operators,they have argued that ICC rates have not beenadequate to meet their needs. For example,Thomas J. Lamphier, president of BN’s trans-portation division, recently wrote:

Unit train coal traffic requires a heavy-duty rail system in order to withstand thecontinuous impacts of this heavy tonnage onthe rail and roadbed. It also requires longsidings and automated signaling to allow forfast movement of coal trains together withnon-coal trains, These requirements involveenormous amounts of capital to be generatedfrom internal earnings and from externalsources. Unfortunately, recent ICC andcourt decisions have produced an uncer-tain pricing atmosphere to the point whereit is doubtful that the revenues permit therecovery of full costs involved in the traf-fic, much less recovery of the large in-creases in costs as they arise in today’sinflationary environment. (Emphasis add-ed.)20

Coal-haul rates vary according to distance,tonnage, and other factors. A representativeexample is the $20.42/ton cost—$0.0127/tonmile—of hauling Powder River basin coalfrom Gillette to Smithers Lake, Tex., a dis-tance of 1,607 miles. 21 (Eastern hauls areshorter than Western hauls—generally be-tween 150 and 400 miles—and costlier: therate 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 in-creases for Western coal traffic in recentyears, 20 to 30 percent boosts being commonsince the late 1970’s.

On the other hand, utilities say that the cur-rent t ransportat ion charges, w h i c h c a namount to over 70 percent of the deliveredcost of a ton of Western coal, * are not justi-

20 Correspondence between Thomas J. Lamphier and ArthurIngberman of DOE, Aug. 26, 1980, included in AAR’s “Sub-mission,” p. 23.

21 Rates included in letter from John S. Reed, Chairman andChief Executive Officer of the Atchison, Topeka. & Santa FeRailway Co. to William Dempsey, President and Chief Execu-tive 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, thatever higher rail charges and unreliable serv-ice are forcing them to develop other sourcesof supply and other modes of transportation.Assuming rail transportation costs continueto rise, Western coal customers can be ex-pected to consider shifting part of their pur-chases to closer suppliers. This constitutes aneconomic rationalization that may reduce thegrowth of Federal coal production, or, atleast, geographically reapportion Federal pro-duction. The ICC’s Ex Parte 347 decision onWestern rail rates in November 1980 couldresult in an annual increase in Western coal

rates of from 2 to 10 percent annually.22 T h eStaggers Rail Act of 1980, which deregulatedpart of the rail industry, will have little directeffect on Western coal haulage since ICC re-tains regulatory authority over “market domi-nant” commodities, of which ICC considersWestern coal to be a “classic” example,

22Telephone conversation with John Sado, ICC lawyer whowas involved in Ex Parte 347, January 1981. Sado emphasizedthat 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 fundshas led to the deferment of road maintenance and the delay ofroad capital . . and an increased reliance on debt and leaseobligations. ” (Ex. Parte 347, pp. 4-23).

Rail: Constraint Analysis

The major potential constraints on increas-ing Western coal traffic, other than physicaland financial capacity, can be grouped intotwo categories: socioeconomic problems andenvironmental-safety problems.

In the past, railroads brought economic lifeto the communit ies through which theypassed. Today, increasing coal traffic cancreate serious disruptions in Western com-munities that are bisected by rail lines carry-ing heavy traffic. If the line has been a heavycarrier for many years, communities are like-ly to have adapted or made the necessary in-vestments to resolve delays. Where the in-crease in traffic occurs suddenly, severe dis-ruption and a lack of resources may combineto create public concern. The ICC noted that:

increased unit train operations on these[existing Western] routes may reach a levelwhich may disrupt transportation, land use,and social patterns of the residents. . . . Itshould be noted, however, that unit trainswill not create any new or unique im-pacts, . . . Rather, the same railroad/commu-nity problems that have existed in the pastmay be intensified and what might have his-torically been regarded as a slight annoyancecould potentially develop into a significantcommunity problem.23

23 Ex Parte 347, p. 5-86.

Delay caused by train operation is the majorrai l-related impact whose disruptivenesscould give rise to community opposition andbecome a constraint on Federal coal develop-ment, Heavy unit-train traffic during whichdozens of 100-car trains pass through a townfor a number of hours each day can interferewith normal business, commuting, emergen-cy vehicles, and school schedules. Severalhundred crossings are likely to be affected byincreased Western coal traffic and a some-what smaller number of grade separations arelikely to be needed.

Grade separations and improved signalingsystems are often prohibitively expensive forlocal governments to finance. Western Statesare now surveying their specific needs, NETSdiscussed alternative sources of financingnew highway grade crossings, among whichare railroad financing, State funding, andFederal funding (Highway Trust Fund, gener-al revenues, national coal severance tax, anda carrier tax.)24 NETS did not make a recom-mendation on this matter but concluded:

Blocking of grade crossings may become asignificant problem both to communities andto the movement of coal. , . . In the absenceof solutions, communities may take actionswhich could affect coal traffic, Local or-

24NETS, pp. 70-71.

. . . . .


dinances prohibiting blocking of crossingsmore than a given amount of time per hour,coupled with speed limits, could adverselyaffect the efficiency of coal traffic. Legisla-tion before Congress to limit the length ofunit trains would actually increase conges-tion at grade crossings. 25

Environmental health and safety is a sec-ond potential constraint on rail transport.Fatalities and injuries associated with railhaulage are significant, although OTA esti-mated that a go-percent increase in train traf-fic would yield a 21-percent increase in deathand injuries.26 Exposure to train noise is ahazard whose seriousness depends on factorssuch as the location of the rail lines, pop-ulation density and topographical and archi-tectural configurations. At 50 unit trains perday , OTA es t imates , for example , tha t

25 Ibid., p. 69,26 Office of Technology Assessment, U.S. Congress, A Tech-

nology 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 wouldbe exposed to noise levels exceeding the En-vironmental Protection Agency (EPA) com-munity noise guidelines.27 Air quality is likelyto be reduced somewhat from locomotiveemissions of carbon monoxide, hydrocar-bons, nitrogen oxides, particulate, and otherpollutants associated with diesel-electricengines.28 Each of these problems could be-come a constraint on Federal coal were theyto reach serious proportions in a number ofplaces at about the same time,

Increased use of Western coal by PacificCoast States, or the marketing of Westerncoal abroad, will enlarge the area affected byrail transportation impacts, Socioeconomic,environmental, and safety considerationscould pose particular problems for west coastcommunities which already experience con-gestion 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 whoconvert it to electricity. As indicated by theearlier discussion of table 67, 40 percent ofthe Western coal sold to utilities in 1979 wasdelivered to mine-mouth or nearby generat-ing plants by conveyor, truck, etc., while 60percent was shipped long distances, prin-cipally by rail. Because more than 60 percentof the electric demand supplied by Westerncoal in 1979 was located at long distancesfrom the mines, a large part of the locally gen-erated electricity was shipped by wire toserve that demand. Since the cost and effi-ciency of generating plants is the same re-gardless of whether it is coal or coal-firedelectricity that is being shipped in bulk, a util-ity’s decision between the two often revolveson transportation factors, such as cost and re-liability, and environmental impacts that mayprevent siting of new generating plants andtransmission lines in certain areas.

Electricity moves from generating plantsvia high-voltage wires. Bulk power is sup-plied through lines in excess of 230 kilovolts(kV). * The bulk power is distributed to re-gional power pools, which are utility-estab-lished organizations that regulate the genera-tion and distribution of electricity amongpool members to achieve economic efficien-cies. 29 Once electricity is fed into the grid, thepoint of origin and final destination of anyparticular unit cannot be identified.30

* Utilities also transmit and distribute power. Transmissionlines are between 70 and 230 kV, and distribution lines are 69kV and less.

29 U . S . Senate, Committees on Energy and Natural Re-

sources; and Commerce, Science, and Transportation NationalEnergy Transportation, 95th Cong., 1st sess., publication No.95-15 (1977), pp. 353-354.

30 The Federal Energy Regulatory Commission (FERC) col-lects data on interstate shipments of bulk power from utilitieson FERC Form 412, but does not tabulate this information. TheU.S. Senate report cited above did organize these data for CY1974 (Ibid., p. 372).

Ch. 8—Transportation 215

High-voltage transmission involves lossesin transformers, reactors, and lines that nor-mally consume about 6 percent of the powergenerated at the mine-mouth.31 Transmissionlosses increase with distance, and can be re-duced by raising the voltage. Present voltagespermit efficient power transmission overdistances of several hundred miles. Longerdistances can be achieved by using highervoltages or by “wheeling,” in which a regionimports power to supply a portion of its owndemand and passes on its own generatedsurplus.

Different studies have come to differentconclusions regarding the relative cost effi-ciencies of rail v. wire transportation. A 1975study by the Bureau of Mines compared thetwo using Powder River basin coal and con-sumer destination at 1,000 miles southeastfrom the mine. This study concluded thatunit-train haulage would be about 30 percentless costly.32 DOE’s National Power GridStudy found that a mine-mouth generationplan “. . . may offer a 15-percent cost advan-tage over the local generation plan.”33 High-voltage transmission has a more stable coststructure than rail haulage, which may con-stitute its principal economic advantage inthe 1980’s. Its labor and operating costs areminimal.

Burning coal at mine-mouth plants andshipping by wire is an attractive option formany utilities that own both the generatingplant and distribution system, and, thereby,are not dependent on independent carriers. Italso attracts utilities because of the relativeease of passing along the costs of capital in-vestment compared with the difficulty of ne-gotiating fuel-adjustment increases. Advan-tages of this sort might also be viewed as po-

31 []0 E, Thf, N o ( 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 Coul-f?o$(!d ~~nf!rg}r 10 [ ~s[!rs 1,000 ~liff)s southrosterl~’ From F;ostf)rnl~r~oming C[)ul fJif:l(ls—F’[)ur hlodf:s of F;nergj 7’r(]ns[]cJrtcrtiorlond El(v.tricit} i’f’rsus (;[1s ~J n d the F;n(i [ ‘sf’ I+;nf:rg} F o r m s(W’ashingtorl, 1).(; ,: [ 1,S, (;okernrmcrrt Printing Office, April1975).

~sD(3~;, IN”O tjorl[rl P[)\t[:r (;rid Stu[i!r. ~’of. l], p. 149.

tential anticompetitive, cost-increasing devel-opments for electricity consumers.34

Large future increases in the amount ofFederal coal shipped by wire may be con-strained by several factors. The generatingplants require large amounts of water, whichis used to cool the electricity-generating ap-paratus. 35 An alternative is air-cooling. Scar-city of water in the powder River basin justi-fied the expense of constructing the first dry-cooling tower in the United States at the Wyo-dak Power Plant east of Gillette, Wyo.

Water use by plants may limit other eco-nomic activity, particularly water-intensivefarming. If mine-mouth plants are plannedfor cluster areas together with synthetic fuelplants, air-quality standards could be ex-ceeded, Constructing mine-mouth plants inthe West also presents local communitieswith problems because of intense but short-term population growth associated with theconstruction work force. These problemshave given rise to local opposition in somecases to expansion of mine-mouth generatingfacilities, 36

The transmission lines have also becomeobjects of controversy. Farmers and otherlandowners have objected to losing right-of-way land (15 to 20 acres are required per mileof transmission line). A direct-current linefrom a North Dakota lignite mine to Minne-sota’s Twin Cities was protested by farmerstrying to keep the line off their property.37

Farm opposition is understandable sinceradial-spray irrigation systems cannot beused in fields under transmission lines. 3 8

underground burial of these lines can double

— .34 DO)j, COO] compet i t ion , Supra note 1.35Jy~:TS pp. 8 0 - 8 1 . water-(;ool~~ Stea fll-g[?ll[; l’iit i rl g ~)lil Ilt S IW-

quire 7 to 8 tons of water per ton of coal, compare(l iiith 1 tonof 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~rer-sity of Nlassa(:husetts Press, 1981).

~a~l i[; h a(:) j. ~11] rph ~,, S u s a n n e N! aeder, and J a rnes 1. ~f (: 1 n-

tirw, 11’~)rthf~rn (;rcat Ploins Cool: Conflicts ond ()[)tions in Dwi-slon Nloking ( NI inneapolis, Nf i n n.: Upper h! idwest Council,1 9 7 6 ) , pp. fj-22.

216 ● An Assessment of Development and Production potential of Federal Coal Leases

to sextuple the costs. 39 Citizens have alsoquestioned the environmental safety of theelectr ic and magnetic f ields surroundinghigh-voltage lines. Problems associated withcorona, noise, spark discharge and ozonehave been identified. The long-term biologicaland health implications of high-voltage trans-

39 Montana Department of Natural Resources and conserva-tion, Draft Environmental Impact Statement on Colstrip Gener-ating Units 3 and 4, 500 Kilovolt Transmission Lines, and Asso-ciated 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 in-creasingly difficult for utilities to obtainWestern rights-of-way. Construction of a765-kV system as suggested in figure 38 tohandle mine-mouth power could give rise tosubstantial opposition.

For all these reasons, some industry repre-sentatives and environmentalists have urgedthat it is preferable to site combustion facil-ities near to the markets for their electricity.

SOURCE: National Power Grid Study, p. 133


Truck Haulage: Capacity and Constraints

Trucks hauled almost 33 million tons ofWestern coal in 1979, 30 million of whichutilities consumed. This represented about 15percent of all Western coal production as wellas 15 percent of utility-consumed Westerncoal,

Coal is trucked to consumers both on andoff the public highways. Highway vehiclescarry 15 to 30 tons (occasionally more) whileoff-road trucks can handle up to 150 tons.Trucks are more flexible than other coal-transportation modes. They are a cost-effi-cient mode for short distances and smallquantities of coal, the economical distancevarying according to local conditions. Onecompany looking at transportation systemsfor 5 million tons per year of Texas ligniteconcluded that truck haulage was limited to amaximum of 10 miles and that truck-rail haul-age was cost effective for longer distances.40

Truck haulage is a simple and familiar tech-nology whose application is generally deter-

400TA correspondence with 13. C. Bradley, President ofChaco Energy Co., February 1981.

mined by economic factors, weight limita-tions on local roads, proximity of mine toconsumer, and the like. The physical capacityof truckers to move Federal coal does not ap-pear to represent any constraint on futureproduction.

Truck haulage of coal presents a range ofenvironmental, safety, and socioeconomicproblems, particularly where trucks regularlypass through population centers. Noise, dust,and pollution are common causes of citizencomplaint. Highway damage is frequently ex-tensive from large coal trucks. More thanother coal-transport technologies, trucks arelocal—the technology itself is familiar andsimple; the drivers are local residents whooften own or lease the trucks; the impacts arereadily seen and understood; and effect iseasily related to cause, For such reasons,citizen opposition to extensive truck haulagein a given community may emerge morequickly than opposition to other transporta-tion modes. Even if citizen complaints werenumerous, a constraint on Federal produc-tion is unlikely to result because most newFederal coal will move by rail or wire.

Waterway-Barge: Capacity and Constraints

Almost 8 million tons of Western coal trav-eled by river in 1979 and another 5% milliontons were shipped on the Great Lakes, Almostall of this tonnage was shipped to electricutilities, and all of it originated by rail, Overhalf of this coal went to two States, Ohio andMichigan.

The inland waterway system has been con-structed and maintained by public authority,the Federal Government, with one exception,Locks are operated by the U.S. Army Corps ofEngineers. Lock size is the principal determi-nant of the extent of river and lake traffic, Themain access points for Western coal are: Su-perior, Wis., on Lake Superior; Sioux City,Iowa, on the Missouri River; and in the St,

Louis area on the Mississippi. The Sioux Cityconnection is closest to the Western coal-fields.

Barge haulage is a very inexpensive way ofmoving bulk commodities. Barge service costaverages 6,86 mills/ton-mile compared with26 mills for rail.41 The Reagan administrationhas proposed to increase the fuel tax forbargelines to 30 cents/gal in 1983, which theadministration estimates would add less than4 mills/ton-mile to the operating cost of the

41 Telephone conversation ~v ith IVei ] SC h u stcr, Vice-p rcsid en tof the A rnerican Waterways Operators, I nc,, januar~’ 19 8 1 .Schuster stressed that these cost estimates were for a~’eragerevenue for all commodities, and that the costs for coal wouldbe less for both harge and rail, Cost data were for 1979.

. _


barge companies. This would represent a58-percent increase in average barge servicecost, “Four mills per ton-mile is a phenom-enal jump, an awfully significant increase,when you’re talking six to eight mills to movecoal,” Anthony Kucera, director of the Amer-ican Waterway Operators Association, said.“The impac t would be inc red ib le . ”42 Amanagement consultant recalculated theReagan proposal for an industry newsletterand found that the fuel tax increase would in-crease expenses by 5 to 8 mills.43

Problems have been noted with the capaci-ty of several locks on the Mississippi-OhioRiver systems, which exceed or are close to

42 Northern Coal, Mar. 11, 1981.43 Ibid.

exceeding design capacity.44 NETS found fu-ture congestion to be likely at Dam 26 atAlton, Ill., and the Gallipolis Lock on the OhioRiver unless new facilities are built.45 The ex-tent of any future constraint depends less onthe extent of Western coal movement bybarge and more on how much additionalbarge service is required of other commodi-ties, notably oil products.

44 The ICC states that “a waterway reaches capacity when theaverage 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 EnvironmentalStatement, Vols. I and 2 (Washington, D. C.: Bureau of LandManagement, 1979). The problem locks include: Locks 50-53on the Ohio River; Gallipolis Lock on the Ohio; Locks 26 and27 on the Upper Mississippi; all locks on the Illinois River;Lock No. 3 on the Monongahela River; and the Winfield Lockon the Kanawha River. The ICC says these locks require “long-term structural solutions through the modification or replace-ment of existing locks” (p. 4-27).

45 NETS, p. 74.

Coal Slurry Pipelines: Capacity and Constraints

Coal slurry pipelines have not played asignificant role in coal transportation. Onlyone pipeline is currently operating: the BlackMesa line between Kayenta, Ariz., and south-ern Nevada that has a 4.8-million-tons-per-year capacity and covers 273 miles. This pipe-line handled about 0.6 percent of the coalmined in the United States in 1980.

A number of slurry pipelines have beenplanned or proposed (fig, 39). Nearest to con-struction is the Energy Transportation Sys-tems Inc. (ETSI) line that would ship PowderRiver basin coal to Oklahoma, Louisiana, andArkansas. It would have a capacity of 25 mil-lion tons per year. A recent DOE contractor’sreport forecast that 70 million to 126 milliontons of coal could be pipelined in 1990, whichwould amount to between 5 and 9 percent ofall coal transported.46 This report concludedthat several pipelines were most viable, in-cluding Arizona to Nevada; Wyoming to Illi-nois; Wyoming to Texas; Wyoming to Arkan-sas, Oklahoma, and Louisiana. OTA’s inves-

q~ICF, The Potential Energy and Economic Impacts oj’ coalS1urry Pipelines, Draft Final Report (Washington, D. C.: ICF, De-cember 1979), pp. 1-2.

tigation reported that coal slurry pipelines66 do represent under some specific cir-. . .cumstances the least costly available meansfor transporting coal measured in economicterms.”47 On the other hand, the constructionof a number of Western pipelines would di-rectly affect the investment and capacity deci-sions of competing railroads. Coal slurrypipelines involve much more complex engi-neering than gas or oil pipelines and they arenot without environmental and social costs oftheir own.48 This report also concluded:

, . . the introduction of coal slurry pipelinesis not likely to affect materially the rate ofcoal resource development and use on a na-tional scale. It may, however, affect theregional pattern of coal mining and distribu-tion 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. Thissummary updates an earlier report, A Technology Assessmentof Coal Slurry PipeJines (Washington, D. C.: U,S. GovernmentPrinting Office, March 1978). The array of legal, economic andenvironment issues involved in the slurry pipeline debate arediscussed in full in OTA’S 1978 Assessment and in the 1980 up-date.

qaAn extensive discussion of these tradeoffs is found i n

OTA’s assessment, Coal Slurry Pipelines, chs. V and VI.


Figure 39.—Coal Slurry Pipeline Systems

A

Proposed pipelines . . . . . . . . . . . . ● . ,.,. .,... ● *..

Principalcompany

Plpeline a affiliation

A. Existing1. Black Mesa pipeline (to present) Consolidation Coal Co.2. Ohio pipeline (1957-1963)

B. Planned or proposed3.

4.

5.

6.

7.

8.

9.

10.

Allen-Warner Valley Energy System Nevada Power Co.(Alton pipeline) (1983-19843)Energy Transportation SystemsIncorporated (ETSI pipeline) (1983)Continental Resources (Florida Florida Power Co.pipeline) (1985-1986)Northwest Integrated Coal EnergySystem (Gulf Interstate Snake Riverpipeline)Pacific Bulk Commodity Transporta- Boeing Corp.tion System pipelineSan Marco pipeline (1983)

Texas Eastern (Wytex pipeline)(1985)Vepco pipeline Virginia Electric Power Co.

Total b

●

● Miami

Capacitypotential

Capacity to exportDistance (million (million

Origin Destination (miles) tons/year) tons/year)

Kayenta, Arizona Southern Nevada 273 4.8 NoneCadiz, Ohio Cleveland, Ohio 108 1.3 None

Utah/Arizona Nevada 183-256 11.8 None

Powder River Oklahoma/Louisiana 1,378 25 0.5basin/Wyoming Arkansas

Southern Illinois/West Georgia/Florida 600 – 40-50 10Virginia/Kentucky 1,500Powder River basin Oregon 1,100 25 0.5Wyoming

Emery, Utah Oxnard, Cal if. 645 10 10

Colorado/ Houston, Tex. 900- 15 NoneNew Mexico 1,100Gillette, 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 itsarea of origin.49

The degree to to which pipelines affect railtraffic depends on whether pipeline operatorswin passage of eminent-domain legislationand on the level of rail rates. As rail rates in-crease, the economic attractiveness of pipe-lines increases as well. If Federal pipelinelegislation is enacted, pipeline operators willenjoy a regulatory advantage over railroads.The pipeline industry argues that the absenceof Federal eminent-domain legislation is asignificant constraint on pipeline construc-tion. Such legislation would make construc-tion easier and accelerate the construction ofpipelines, but it does not appear to be essen-

49)T A, Coal Slurry pipelines, Summary, p. 9, September1980.

tial to the construction of any individualpipeline.

The principal environmental constraint onpipeline construction has to do with water.For any particular pipeline, water availabilitymay not be a problem. However, when waterdemand for all possible new energy facilitiesin a western basin, including mine-mouthplants, synthetic-fuel facilities, and pipelinesare totaled, water availability can become animportant constraint on pipeline construc-tion. Moreover, Montana and Colorado pro-hibit export of local water, and Wyoming re-quires legislative approval before export canoccur. Assuming that the legal and environ-mental water issues are resolved, the onlylikely constraint on pipeline developmentarising from the operation of the lines wouldbe citizen objection to spillage from breaks.Federal and State environmental regulationsmay be violated in such accidents.

Port Facilities: Capacity and Constraints

Very little Western coal is being exportedto Asia. If Asian exports are to increase, im-proved port facilities are required. Domesticport facilities at Los Angeles, Long Beach,and Stockton, Calif., are currently capable ofloading only several million tons per year.plans for expansion of these port facilitieshave been announced. The volume of coalthat could be transferred through these portsmay be constrained by area rail system capac-ity. The port at Vancouver, British Columbia,

now has a capacity of 15 million tons peryear, and could handle some Western coal.Seattle plans to expand its coal export facil-ities to 40 million tons per year by 1990, if ex-port sales warrant such an investment. OtherWestern ports may also invest in expansion ifthe coal export market grows.50

50 see Office of Technology Assessment, Coal Exports andPort Development, OTA-TM-O-8 (Washington, D. C.: U.S. Gov-ernment Printing Office, April 1981).

Comments on Regional and StateTransportation Factors

Powder River Basin 72 million tons of this came from mines con-taining Federal leases. About 160 million tons

The Powder River basin is likely to supply are contracted for 1990 from Federal minesan increasing percentage of Federal coal. In alone (see ch. 7). Almost all of this coal will be1979, the Montana-Wyoming Powder River consumed by utilities. Unless coal slurrybasin produced about 80 million tons of coal; pipelines are built, more than 90 percent of


Federal coal will be hauled by rail, If the threepipeline projects mentioned in figure 39 arecompleted by 1990, they would transport 75million tons per year.

Texas and Iowa will be two principal con-sumers of Federal coal from the Powder Riverbasin in 1990. Other States that have con-tracted for large amounts of Powder Riverbasin coal include Montana, Minnesota, Col-orado, Wisconsin, Michigan, Indiana, Ohio,Oklahoma, Wyoming, and Kansas.

A rough idea of the rail traffic these con-tracted tonnages represent can be calculatedon the assumption that it requires one set of100 cars making 100 trips to transport 1 mil-lion tons. Powder River basin contracted out-put from mines including Federal leases willrequire 16,000 unit-train trips. Traffic pastany given point is doubled to take into ac-count the returning trains.

Assuming that the average coal car makes46 trips annually (7-day cycle time plus 45days maintenance), this tonnage would re-quire 348 unit trains with at least 34,800 hop-per cars. The time that a particular communi-ty is disturbed by train traffic depends on theamount of traffic, time of day, and trainspeed. A town through which 25 loaded and25 return trains pass daily will be disturbedfrom 1 to 5 hours depending on train speed. *It should be recalled that other traffic (somenon-Federal coal but principally noncoalcommodities) will also be using this rail sys-tem, thereby increasing the traffic.

BN, which serves the powder River basin,will have to expand its capacity if it is to han-dle 1990 coal traffic. Although most Federalleases lie within 15 miles of existing rail lines,roadway limits down the line from the pointof origin may present bottlenecks in the fu-ture.51 Obtaining sufficient rolling stock is

*This would represent an annual tonnage of 91.25 milliontons. Towns on the BN’s track in Wyoming, Colorado, Nebras-ka, and Iowa can expect this level of traffic. Towns south ofGillette 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 congestedrail links in the coal transportation network nationally. Aboutthree dozen of these bottlenecks were identified in the Westalong transport routes for Powder River basin coal. (NETS, fig.

less of a problem than upgrading and con-structing adequate roadway. As was notedpreviously, likely bottlenecks have been pin-pointed on rail lines running east from thebasin through Nebraska and Iowa to Missouriand south through Colorado and Texas. Traf-fic through the southerly corridor could beeased by operation of two proposed 25-mil-lion-ton-per-year pipelines: the Texas Eastern(Wytex) line from Gillette to Houston; and theETSI line from the basin through Oklahoma,Louisiana, and Arkansas. The Wyoming StateLegislature passed a bill in 1974 specificallyauthorizing export of water through the ETSIline. This line has obtained the necessaryrights-of-way, air-quality permits, and EISclearance. It could become operational in themid-1980’s. Unresolved legislative and water-resource issues have impeded rapid develop-ment of slurry pipelines originating in thebasin. The lack of eminent-domain legislationand a recent decision by the Governor ofWyoming that pipelines should be developedonly if they use nonwater technologies aresignificant constraints.

Managing the transportation of 1990 coalproduction from the basin will require co-operation among Western railroads. The BNand Chicago Northwestern (CNW) recentlyconstructed a line from Gillette to Douglas,Wyo., which greatly improves the basin’scoal-export capacity. But CNW’s coal haulagealso depends on use of UP track that runseast-west through southern Wyoming. BN hasrefused to share a connecting line with CNW,which prevents that carrier from hauling coaleast on the UP track. CNW has proposed tobuild its own connecting track, but has en-countered strong opposition from local resi-d e n t s .52 CNW, however , expresses con-

3-2). However, NETS used 1975 data that did not take into ac-count post-l975 rail investment beyond what was underway inthat year. BN and other major Western rail haulers have sig-nificantly upgraded their mainlines since 1975 to meet heaviercurrent traffic. The BN, for example, originated less than 19million tons of coal in 197o compared with 80 million tons in1980 and 100 million tons forecast for 1981, according to BNpresident Richard Bressler,

52 Powder River Basin Resource Council, “WYOBRASKAKeeps Up the Pressure,” Powder River Breaks, September1981.


fidence that it will be able to realize its plansto haul approximately 45 million tons peryear from the Powder River basin in 1990.53

Other Wyoming Regions

Wyoming will also produce coal from theHanna, Rock Springs, and Kemmerer fieldsin southern Wyoming, At the present time, allof the coal produced in this region comesfrom Federal mines—23 million tons of pro-duction in 1979, Coal production from thisregion will increase during the 1980’s. TheUP serves these coalfields. The UP seems ableto haul expected tonnage without difficultyfrom this area. Because there are more com-munities in southern Wyoming than in andaround the Powder River basin and becauseUP carries other commodities, some commu-nities may be adversely affected despite thecomparatively modest coal traffic increases.

Fort Union Region ofNorth Dakota and Montana

It is not cost effective to transport lignitefar from the mining site. Lignite has the low-est energy value and highest moisture contentof the domestically mined coals, These fac-tors force utilities to burn lignite close to themine site. All of the powerplants currentlyunder construct ion or planned in NorthDakota will burn coal at the mine site.

Only one operating powerplant–the BigStone facility—consumed more than 1 milliontons of lignite annually from mines situatedmore than 100 railroad miles away, ThisSouth Dakota plant designed and built specialcovered hopper cars for hauling lignite fromKnife River Coal Co. ’s Gascoyne Mine 350miles away. The Milwaukee Road (Chicago,Milwaukee, St. Paul, and Pacific Railroad)owns and operates this 350-mile track overwhich two unit-trains pass daily, The Mil-waukee’s bankruptcy may result in cutbacks

53 Remarks of’ Douglas A. C hristensen, Vice president forMarketing of C&NW Transportation Co., at the Coal OutlookConference Charting the Future of Western Coal, June 8-9,1981.

in service. The Milwaukee Road Trustee re-quested a new freight rate, which would in-crease the transport costs of lignite by 65 per-cent. The partners at the Big Stone plant re-jected this because the trustee was unwillingto provide guarantees that any portion of thenew rate would be used to maintain the road-bed between the mine and the powerplants.North and South Dakota have been spendingRailroad Recovery Act funds to maintain thistrack, which is considered to be in worseshape than any other stretch in the Mil-waukee system. Milwaukee applied to itsbankruptcy court and to the ICC in May 1981for permission to abandon this tract. The ICCwill make a recommendation to the court onSeptember 15, at which time a final decisionwill be made.

While Gascoyne production has not beenconstrained by transportation factors up tonow, Knife River’s New Liepzig project hasbeen delayed indefinitely by BN’s unwill-ingness to invest $20 million to $24 million toupgrade the track that would carry about 2million tons per year to a powerplant in Man-dan, N. Dak. Knife River wants to prorate theupgrading costs between itself and BN (whichowns extensive mineral rights along this line),but BN contends that Knife River shouldfinance all the costs. BN stands to gain littlefrom this investment because the expectedtraffic volume is so small. On the other hand,Knife River has no other way to move coalfrom this site.

Colorado

Transportation factors play a major role indetermining the market potential of Coloradocoals. Transportation costs are an importantvariable because Colorado coal from under-ground mines must compete with cheapersurface-mined coal from Wyoming and NewMexico. Moreover, Colorado coal must beshipped over the Rocky Mountains to reachMidwest and South-Central markets, Mineoperators in the Green River region, theState’s largest producing area, complain thatrapidly escalating rail rates are destroying


their competitiveness. The Denver & RioGrande Western (D&RGW), which serveswestern Colorado, argues that its rates arefair considering the high costs of upkeepunder difficult conditions, such as the MofattTunnel that leads to Denver and easterlymarkets. Higher rates also reflect the cost ofnew sidings and the installation of CTCS, therailroad says. The D& RGW’s continued abili-ty to move projected expanded coal outputfrom western Colorado to the front range isopen to question despite the railroad’sassurances. The Green River-Ham’s Forkenvironmental impact statement (EIS) foundthat with 20 million tons of new annual pro-duction from new lease sales, about 75 per-cent of D& RGW’s capacity would be used.One alternative that has been suggested bylocal governments and mine operators to ex-pand coal transportation capacity in north-west Colorado is construction of an extensionof the UP line from Rawlins, Wyo., to Craig,Colo. No such extension of the UP intoD& RGW’s service area has actually been pro-posed.

Other rail capacity questions are apparent.Until the Tongue Mesa Field and the SanJuan coalfield around Durango are served byrail, it is unlikely that significant develop-ment will occur there. The Federal leases inthe Coalmont Field of the North Park regionprobably cannot be developed until the aban-doned UP line from Walden to Hebron is sub-stantially upgraded. This line has sharp turn-ing radii and steep grades. These improve-ments will probably not be made unlessenough coal can be shipped from the areaunder long-term contracts to offset the costs.

Several coal mines in the Green River re-gion truck their coal to railheads at distancesranging from 2 to 30 miles. This has createdadditional expense for the mine operatorsand road damage to certain highways. Con-veyors and rail spurs are being evaluated bysome companies to reduce truck use. Onecoal slurry line originating in Colorado hasbeen discussed—the San Marco line fromWalsenburg to Houston, Tex. However, theColorado legislature has barred exportation

of the State’s water. This policy coupled withother demands on local water resourcesmakes this pipeline an unlikely prospectwithout Federal enabling legislation or legalresolution of water-rights issues,

New Mexico

The OTA New Mexico task force estimatedthat total coal production in the State couldincrease from 14,6 million tons in 1979 to asmuch as 72 million tons by 1990 under favor-able conditions. Of this number, about 55million tons would be exported, mostly toutilities in California and Texas. AlthoughNew Mexico has traditionally exported morethan half its in-State produced electricity toout-of-State customers, the emphasis over thenext decade is likely to be shipping coal byrail.

The construction of the Star Lake Railroadin west-central New Mexico is a major factorin this increased production. This line wouldconnect the Star Lake-Bisti area of the SanJuan basin, which contains one of the largestuntapped strippable coal deposits in theWestern United States, with the Santa Femain line at Prewitt, N. Mex. Five largeundeveloped leases and 28 outstanding pref-erence right lease applications (PRLAs) arefound in this area, as well as large reserves offee, State, and Indian coal. The 114-mile StarLake line could carry almost 17 million tonsper year by 1990, and, if fully developed, thisarea would be able to mine as much as 75 mil-lion tons per year. Production of about 8 mil-lion tons of coal from Federal leases in 1990hinges on construction of this railroad, asdoes an additional 18 million tons from mineson land covered by PRLAs. Construction ofthe Star Lake Railroad has been delayedbecause of difficulties in obtaining all thenecessary rights-of-way. However, progresshas been made; a right-of-way over publiclands has been approved. Several questionsinvolving rights-of-way over public lands andindividual Indian allotment lands remain tobe resolved. About three miles of tribal trustlands and 25 miles of allotment lands are in-volved. 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 wouldbegin within a few years after the right-of-way issues are settled and would be com-pleted within 2 years, according the the SantaFe’s estimates.

Other transportation issues are relevant toother coal development in New Mexico. Mineconstruction on several Federal lease blockswill require upgrading of local roads. A230-kV transmission line would have to beconstructed to link the proposed New MexicoGenerating Station near Bisti with the ex-i s t ing e l ec t r i ca l g r id 209 mi le s to thesoutheast. Another proposed rail connectionfrom mines on the Navajo reservation to theeast-west trunk line at Gallup is also underconsiderat ion. T h e c a r r i e r — t h e S a n t aFe—has acquired right of way to 22 miles andthe remainder is under discussion. This linewould carry between 4 million and 25 milliontons per year if completed.

Utah

Most Federal leases in central Utah arelocated near existing road and rail transporta-tion systems which appear to be adequate tohandle future production. In this area, coalwould be moved by truck, rail, or conveyor tothe powerplant or railhead. Improvementsand repairs to existing systems are underway.Some mines currently have to truck coal 60miles to rail connections, but this does notseem to have been a constraining factor inmine development, This truck haul would bereduced when the planned Castle Valley Rail-road extension is constructed.

Southern Utah, on the other hand, does nothave a well-developed transportation systemserving potential coal mining areas. Two coalslurry pipelines 180 miles long would connectthe Alton Mine to the proposed Allen WarnerValley Power Project. The slurry plan con-

flicts with Utah law restricting transfer ofwater out of State, The Kaiparowits PlateauField is not currently served by rail or majorroads. Coal development there depends onconstruction of a rail or slurry line to movecoal to market, A minimum of 30 million tonsof annual production is required to offset thecost of building a rail line from the plateau.Such a rail line has been under study, but nodate has been proposed for its construction.

Oklahoma

Oklahoma’s coal production, currently atabout 5 million tons per year, is not projectedto increase substantially over the next decade.Utilities in Oklahoma buy coal from otherStates, principally Wyoming, because of itslow-sulfur content. Oklahoma’s high-sulfursteam coal is exported to generating plants inother States that have less restrictive airpollution requirements. Oklahoma’s metal-lurgical coal markets depend on demandrather than supply-side or transportation fac-tors. Much of Oklahoma’s current productionis trucked to rail and barge centers through-out the region. County roads and bridges ad-jacent to Federal coal properties are typicallyin poor condition and some cannot accommo-date heavy commercial traffic. Coal industryspokesmen have expressed a willingness tobuild new roads or repair existing ones. Raillines to major rail and barge connections areill-suited to transport large quantities of coalefficiently, but should prove sufficient to han-dle expected output with some upgrading.One Oklahoma coal operator has stated thatthe “only way that is economically feasible (toexport Oklahoma coal) is by barge; the railrate 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

PageLegal Framework and Policy . . . . . . . . . . . . .227Historical Development of Federal

Land Policies. . . . . . . . . . . . . . . . . . . . . .. ...227Federal Coal Leasing Amendments Act

of 1976 ● **. , **o.*.*.....*.?*****.***** 231Federal Land Policy and Management Act. . .232

1979 Federal Coal Management Program. . .233

Legal Issues Relating to ExistingFederal Leases . . . . . . . . . . . . . . . . . . . . ...238

Diligent Development and Related Concepts. . 238Common Law Diligence. . .................238The 1976 Diligence Regulations. . . .........239Summary of Diligent Development and

Continuous Operations Regulations. .. ....239Logical Mining Units. . ...................241Diligence Extensions. . . . . . . . . . . . . . . . . . . .242Continuous Operations. . . . . . . . . . . . . . . . . . .244Advance Royalties . . . . . . . . . ..............245Cancellation of Leases. . ..................245Application of the 1976 Diligence

Requirements to Existing Leases.. . .......245Legal and Administrative Issues in the

Enforcement of Diligence Requirements. ..247Determination of LMU and LMU Reserves

for Diligence , . . , . O * . . . . ? . . . . . . . . . . . * * 248Relinquishments. . . . . . . . . . . . . . . . . . . . . . . . .252Potential Production From Federal Coal

Leases and Diligence. . ..................252Exchanges . . . . . . . . . . . . . . . . . . . . . ● ........252

Preference Right Lease Applications. .. ....255Potential Production From PRLAs. . . . .. ....255Procedures for Processing PRLAs. .........256Litigation Involving PRLAs. . . . . . . . . . .. ....257Other Legal and Administrative Issues

Related to PRLAs. . ...........9.........260Unsuitability for Mining . . . . . . . . . . . . ......262

PageFootnotes for Chapter9. .. ...............265

List of Tables

Talbe No. Page73. Surface Acreage of Leases and PRLAs

74,

75*

76.

77,

78.

79.

by State and by Surface Ownership:Sept 30, 1980, . . . . . ...................230Federal Coal Leasing Amendments Actof 1976: Summary of Major Provisions. ...232Department of the Interior Division ofFunctions and ResponsibilitiesConcerning Management of Federal CoalBetween the Office of Surface Mining,the U.S. Geological Survey and theBureau of Land Management. ., ........235Changes in Definitions of DiligentDevelopment and Continued Operation,Proposed and Final Regulations . . . . . ....240Changes in Definitions of Logical MiningUnit and Logical Mining Unit ReservesProposed and Final Regulations. . .......243Readjustment Schedule for Pre-FCLAALeases in Colorado, Montana, NewMexico, North Dakota, Utah, andWyoming . . . . . . . . . . . . . . . ● .*..*,. ● .,.. 251Processing Preference Right LeaseApplications . . . . .....................258

List of Figures

Figure No. Page40. Principal Federal Landholdings in the

Conterminous United States . . . . . . . . . . . .22841. Federal Land Grants for Railroads.. .. ...22942. Federal Coal Management Program:

Department of the Interior AgencyInvolvement . . . . . . . . . . . . . . . . . . . . . . . . .234

CHAPTER 9

Federal Coal Lease Management

Legal Framework and Policy

The Federal Government has both propri-etary and sovereign responsibilities for Fed-eral lands. A proprietary responsibility tomanage the publicly owned lands and naturalresources to meet the Nation’s needs forenergy, minerals, timber, agricultural pro-duction, and recreation while ensuring a fairreturn on public resources; and a sovereignresponsibility to encourage and regulate com-merce while at the same time protecting andconserving the natural heritage. The statutesand policies providing the framework of theseFederal responsibilities for the managementof Federal coal resources are reviewedbelow.

Historical Development ofFederal Land Policies

Lands owned by the Federal Governmentare either: 1) public domain lands, acquiredby cession, treaty or purchase from other sov-ereign nations; or 2) acquired lands pur-chased by the Government from private own-ers after the lands were made part of theUnion. By 1867, approximately 1.8 billionacres of land had been added to the public do-main through a series of purchases and trea-ties. Most of these public domain lands werewest of the Mississippi River, Figure 40shows the distribution of federally ownedlands in the conterminous 48 States in 1976.

Federal land policy from the time the Na-tion gained independence through the end ofthe 19th century had five objectives: 1) to pro-duce revenue for the Government; 2) to facili-tate settlement and growth in the various re-gions; 3) to reward war veterans; 4) to pro-mote education and charitable institutions;and 5) to encourage the construction of inter-nal improvements, e.g. , rai lroads, roadsand canals to promote transportation andcommerce.

Federal land policy has historically beenaimed at disposing of Federal land to privateinterests through a number of devices includ-ing sales, military warrants, preemption,homesteading, and direct grants to Statesand railroad companies. Through each ofthese mechanisms, vast areas of the publicdomain were transferred to private owner-ship. Those areas that were less favorable foreconomic use during the period of disposal ofpublic lands were largely retained by the Fed-eral Government, and today constitute themajor part of the lands managed by theBureau of Land Management (BLM).

The intermingled landownership patternsthat are the legacy of earlier public landspolicies in the West have a direct and signifi-cant impact on the management of WesternFederal coal lands today. Two aspects, inparticular, created land ownership problemsfor the development of Federal coal lands:1) checkerboard land grants made to thetranscontinental railroads: and 2) severedestates, the separation of surface ownershipfrom subsurface mineral ownership.

Railroad Land Grants.—Over 94 mil l ionacres of Federal lands were given to the rail-roads directly as railroad land grants. An ad-ditional 37 million acres were granted to theStates for their use to encourage rail develop-ment within their boundaries. Figure 41shows the location of these railroad grants.

Railroad grants were awarded on odd-numbered sections on either side of the pro-posed right-of-way, with even-numbered sec-tions retained in public ownership. This re-sulted in what is called a “checkerboard”ownership pattern and still influences the de-velopment of Western coal, particularly inareas of North Dakota, Montana, Wyoming,and in New Mexico where the transcontinen-tal railroads were granted lands under thePacific Railroad Act. Many railroads sold

227


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 togenerate revenues to finance construction. Asubstantial amount of railroad land grantsunderlain with valuable coal deposits re-mains in railroad ownership today.

Surface Ownership and Mineral lnterests.—The early 20th century policy of retainingFederal ownership of subsurface mineralrights while granting surface ownership toprivate parties subsequently created prob-lems for both parties of interest.’ The valuesto the surface owner are in use of the land forgrazing, agriculture, recreation, timber, orother surface activities. Mining, on the otherhand, frequently involves surface disturb-ance 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 displacedfrom the property for as much as 30 to 40years over the life of the mine. Moreover,even after mining, reclamation may not fullyrestore all of the land’s previous characteris-tics. Under law, mining is considered thedominant land use; the surface owner is com-pensated for any damages to or loss of build-ings and other improvements on the land dis-turbed by mining. Large quantities of Federalcoal may lie below lands whose surface isprivately owned. Achieving an equitablebalance between the interests of the surfaceowner and the interest of the public in makingcoal resources available for development isoften a contentious and difficult administra-tive problem in the Western coal regions. Sec-tion 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 approximatelimits of the areas in which the railroads

I W y o m i n g ]

(n

Acreage grantedu Y

The shaded areas are in proportion to the acreagereceived by the railroads. They do no show theexact location of the granted lands,which in general formed a checkerboard pattern.

SOURCE. Bureau of Land Management.


Reclamation Act of 1977 (SMCRA)2 bars theleasing of Federal coal under certain private-ly held lands unless the surface owner con-sents to the lease. Section 714 does not applyto existing leases and preference right leaseapplicat ions (PRLAs)2 which cover over200,000 acres of privately owned surfaceland. Table 73 shows the surface ownershipof Federal coal leases in Western coal States.

Reforms Under the Mineral Leasing Actof 1920

Before 1920, Federal coal lands were soldunder the authority of the 1873 Coal LandsAct. 3 Sales were limited to 160 acres for indi-viduals and an association could purchase upto 320 acres. The enactment of the MineralLeasing Act converted the policy of sale ofcoal land to a policy of leasing rights to ex-plore, develop, and remove coal and otherfuel and fertilizer minerals.’

Under the 1920 Act, the Secretary of theInterior could issue prospecting permits thatentitled the permittee to the exclusive right toprospect for coal in areas with no known coaldeposits. The permits were converted intopreference right leases if the permitterscould demonstrate the discovery of coal incommercial quantities.

Under the provisions of the 1920 Act, Fed-eral lands containing known commercial coaldeposits were divided into leasing tracts andleases were awarded competitively to thehighest bidder for a cash bonus,

The Mineral Leasing Act provided forleases to be issued for an indeterminateperiod so long as the lessee could demon-strate diligent development and continuousoperation of the lease. Royalties were orig-inally set at not less than 5 cents/ton of coaland annual rentals could not be below 25cents, 50 cents, and $1.00/acre for the first,second through fifth, and sixth through 20thyears, respectively. The leases were subjectto readjustment of terms and rentals and roy-alties at the end of each 20-year period afterissuance.

1971 Moratorium on Coal Leasing

Between 1920 and 1970, Federal coal wasvirtually leased on demand, i.e., whereverand whenever anyone requested a lease saleor permit, In 1970, a study conducted by BLMfound that although the amount of leased Fed-eral coal had increased dramatically in theprevious decade, coal production had signif-icantly declined in comparison to the amountof coal under lease. ’ This study ultimately led

Table 73.—Surface Acreage of Leases and PRLAs by State andby Surface Ownership: Sept. 30, 1980

Number of Total —- Federal lands– NativeState leases acres BLM FS Other American State Private

Colorado . . . . . . . . . . 127 126,875 45,773 22,589 0 0 0 58,498Montana . . . . . . . . . 22 37,445 1,225 80 0 0 0 36,141New Mexico . . . . . . . 29 44,761 20,047 0 0 9,148 7,086 8,478North Dakota. . . . . . . 18 17,504 0 0 0 0 0 17,504Utah . . . . . . . . . . . . . . 204 279,654 187,993 50,102 0 0 28,108 13,450Wyoming . . . . . . . . . . 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 LeaseData System, Sept. 30, 1980.


to an informal moratorium on further leasingof Federal coal in 1971. In 1973 the mora-torium was formalized by secretarial orderbut modifications provided for new leases tomaintain existing mines or to supply near-term production to satisfy existing market de-mands. 6 The Department of the Interior (DOI)immediately began developing an improved,long-term coal leasing program.

Meanwhile, congressional hearings on coalleasing (1972-74) focused on whether Federalcoal leases were being held for speculationand whether enforcement of lease conditionsof diligent development and continued opera-tion were ineffectual. ’ As a result of the hear-ings, legislation amending the 1920 MineralLeasing Act eventually passed over PresidentFord’s veto in August 1976.8 The amendmentsincluded provisions limiting the holding ofFederal leases without production.

Energy Minerals Activity RecommendationSystem (EMARS)

While Congress was considering changesto the Mineral Leasing Act in 1975, DOIannounced a new coal leasing program,EMARS, which involved the industry more di-rectly in the tract selection process.9 Insteadof DOI identifying the areas eligible for leas-ing or offering leases in response to specificsale requests, as was the procedure underthe 1920 Mineral Leasing Act, the EMARSprocedure was an integrated planning proc-ess for lease sales that involved annualnominations for coal leasing areas by the in-dustry and the public, The program was op-posed by the western Governors and agricul-tural interests, and environmental groups. In1975, the Natural Resources Defense Council(NRDC) sued DOI for insufficiently describingthe EMARS program and its potential conse-quences in the environmental impact state-ment (EIS).

Two years later, the District Court for theDistrict of Columbia, in NRDC v. Hughes,found the EMARS programmatic EIS inade-quate under the National EnvironmentalPolicy Act of 1969 (NEPA). The EIS failed toconsider the impacts of a no-action alter-

native of not establishing a new leasing pro-gram, 10 and the proposed leasing system de-scribed in the final EIS differed substantiallyfrom the system described in the draft thatwas circulated for public comment. The courtenjoined DOI from implementing the EMARSprogram and from any new leasing, exceptwhere the proposed lease was necessary tomaintain an existing mining operation ornecessary to provide reserves to meet exist-ing contracts, until DOI fully complied withthe requirements of NEPA,11

The case was settled on June 14, 1978under an agreement permitting additionalleasing and the processing of 20 PRLAs whileDOI developed a revised coal program andEIS. 12 By 1980, leasing under the 1978 settle-ment had resulted in 29 new leases covering20,822 acres containing 212 million tons ofrecoverable reserves.

The task of preparing an adequate EIS andformulating changes to the system of leasingFederal coal reserves fell to the new Carteradministrat ion and the moratorium con-tinued. By April 1979, the EIS process wascomple ted . 13 In July 1979, under the Fed-eral Coal Leasing Amendments Act of 1976(FCLAA), l4 the Federal Land Policy and Man-agement Act of 1976 (FLPMA),15 and the set-tlement of NRDC v, Hughes, DOI promulgatedregulations implementing a new Federal coalleasing program.16 The first lease sales underthe new program were held in January 1981.

Federal Coal Leasing AmendmentsAct of 1976

FCLAA contains several provisions aimedat what were characterized in the hearingsas problems of speculation and nonproduc-tion. The noncompetitive preference rightleasing system was repealed on the basis thatit did not grant the public a “fair return.” Allnew leases are to be issued competitively andno bid can be accepted for less than the fairmarket value of the lease. The amendmentsalso provide for: 1) the consolidation of leasesinto “logical mining units” (LMUS) to assuremaximum economic recovery (MER): 2) dili-

232 ● An Assessment of Development and Production Potent/al of Federal Coal Leases

gent development and continuous operationon each lease, and 3) preparation of a com-prehensive land use plan before coal leasesales. See table 74 summarizing the majorprovisions of FCLAA.

Federal Land Policy andManagement Act

FLPMA is the comprehensive “organic”act for BLM. Before passage of FLPMA, BLMoperated on a series of authorizing acts, reor-ganization plans, and secretarial orderswhich gave little guidance to the overall man-agement of the public lands. Each act ad-dressed a separate problem, but failed to setgoals and objectives for BLM as it attemptedto balance the use and development of West-ern lands under its jurisdiction.

In FLPMA, Congress directed BLM to man-age the public lands (including Federal min-

eral interests under private surface) within aframework of land use plannng. Among theprinciples set out in the legislation are theguidance to manage the lands for “multipleuse” and “sustained yield” and to assure thatthe fair market value is received for the saleor use of public resources. l7 BLM was di-rected to protect areas of critical environ-mental concern, to consider present as wellas future uses of public lands, to provide forcompliance with applicable Federal and Statepollution control laws, and to coordinateplanning activities with those of other Feder-al, State, and local agencies. Section 603 ofFLPMA also directs DOI to inventory andstudy BLM roadless lands for potential con-gressional designation as wilderness areas.The general requirements for management ofpublic lands under FLPMA also govern ac-tivities 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 bidwith 50 percent of lands offered in any year tobe awarded under a system of deferred bonusbidding and a “reasonable number” of tractsare to be reserved for leasing by public bodies.No bid may be accepted for less than the fairmarket value of the tract offered. Minimumlease size is changed from 40 acres to suchsize that “will permit the mining of all coalwhich can be economically extracted”.

The Secretary shall not issue a lease to alessee who has held a lease for ten years (afterpassage of FCLAA) without producing coal incommercial quantities. All lands to be leasedmust be included in a comprehensive land useplan. DOI must consult with State and localgovernments and provide opportunities forpublic hearings if requested in preparing landuse plan. Secretary must consider the social,economic, and other impacts on the com-munities affected and provide an opportunityfor a public hearing before a lease is issued.DOI must obtain consent of Federal surfacemanagement agencies outside DOI before leas-ing lands under their jurisdiction. DOI mustconsult with State Governor before leasing Na-tional Forest lands. Advance notice must begiven of competitive lease sales includingpublication in local newspapers. No mine planfor leased lands may be approved unless it pro-vides for maximum economic recovery of coalwithin the tract. All coal leases are to containprovisions requiring compliance with theFederal Water Pollution Control Act and theClean Air Act.

Sec. 4

Sec. 5

Sec. 6

Repeals, subject to valid existing rights, provi-sion allowing noncompetitive leasing throughissuance of prospecting permits andpreference right leases. Establishes a systemof nonexclusive exploration licenses. Licenseesmust furnish all data acquired to Secretary,however, information is kept confidential untilafter the area is leased.

Repeals, subject to valid existing rights, provi-sion for collective contracts for exploration,development and operations. Substitutes con-cept of Logical Mining Unit (LMU). Allows con-solidation of Federal leases and non-Federallands into single LMU if maximum economicrecovery is served. Lease terms in LMU may bemodified so that requirements imposed onleases are consistent. Pre-FCLAA leases maybe included in LMU with consent of lessee.Aggregate production from LMU may be usedto meet diligence and continued operation re-quirements. Mining plan approved for LMUmust provide for depletion of LMU reserves in40 years. LMU may not be larger than 25,000acres.Amends section 7 of MLA to provide thatleases are for an initial period of 20 years withreadjustments at the end of the initial term andevery 10 years thereafter. Any post-FCLAA leasenot producing in commercial quantities at theend of 10 years shall be terminated. Minimumroyalty for coal mined by surface methods shallbe 12.5 percent; with a lesser royalty as deter-mined by the Secretary for coal recovered byunderground methods. Allows payment of ad-vance royalties (determined by a fixed reserve to


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 acceptedfor more than 10 years during the period of anylease. Requires submittal of a mining andreclamation plan within 3 years after the lease isissued; Federal surface management agencymust consent to DO I approval of mine plan.

Establishes program for comprehensive coalexploration program for Federal lands to sup-port land use planning and leasing operations.Information from coal exploration program, ex-cept for certain proprietary data, is to be madepublic.

Requires annual reports to Congress by theSecretary of the Interior on the management ofFederal coal leases and by the AttorneyGeneral on competition in the coal industry, in-cluding an analysis of whether the antitrustlaws are effective in preserving or promotingcompetition in the coal or energy industry.

Amends the revenue distribution provisions ofsection 35 of the MLA by reducing the amountpaid to the Reclamation Fund from 52½ percentto 40 percent (and raising the amount paidto the States by 12½ percent.) Directs thatStates may spend their share of the revenuesas each State Legislature provides givingpriority to the needs of communities impactedby Federal mineral leasing.

Requires Office of Technology Assessmentstudy of Federal coal leases.

Amends section 27 of the MLA to provide thatno 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 normore than a total of 100,000 acres in the UnitedStates. Lessees controlling more than 100,000acres on passage of FCLAA may continue toown their leases, but may not acquire moreleases until the total acreage controlled is lessthan 100,000 acres. The definition of a lesseeentity is broadened to include a person, associa-tion, or corporation, or any subsidiary, affiliateor persons controlled by or under common con-trol with such person, association or corpora-tion.

Authorizes leases to governmental entities ofacquired lands set aside for military or navalpurposes.

Repeals, subject to valid existing rights,authority to lease an additional 2,560 acres ofcoal lands to a lessee who has exhausted thereserves in the original lease. Substitutes newprovision allowing noncompetitive leasing ofup to 160 acres as a modification to a con-tiguous existing lease.

Amends section 39 of MLA to limit authority ofSecretary to waive suspend or reduce advanceroyalties.

Requires Secretary to consult with AttorneyGeneral before drafting rules and regulationsor before issuing, renewing or readjustingleases as to whether the proposed actionwould create a situation inconsistent with theantitrust laws.


1979 Federal Coal Management Program

Under the 1979 coal management program,all Federal coal leasing is done under BLM’soverall land use planning program estab-lished in section 202 of FLPMA. Figure 42shows the lease planning and sales processunder the July 1979 Federal Coal Manage-ment Program. The land use planning andcoal management programs include a proce-dure for reviewing existing and potentialleases to determine their suitability for min-ing according to a series of “unsuitabilitycriteria. ” Areas are only considered for leas-ing if they have a high to medium coal devel-opment potential and have been classified asa known recoverable coal resource area[KRCRA). DOI’s unsuitability criteria are ap-

plied to these lands and a determinationmade as to whether the lands are suitable forleasing. Federal lands that have been leasedalso are reviewed for their suitability for min-ing during the general land managementplanning process and on mine plan approval.The use of unsuitability criteria for existingleases results in recommendations for mitiga-tion requirements when a mine plan is pro-posed. The impact of the land use planningunsuitability criteria on pre-FCLAA leases isdiscussed more fully in chapter 10.

Several agencies and departments shareresponsibility for management and oversightof coal leases on Federal lands. Table 75


Figure 42.—Federal Coal Management Program: Department of the Interior Agency Involvement

Management of:

a) Existing leasesb) PRLAsc) Emergency leasesd) Exploration Iicensese) Exchanges

Land use plannlng:

a) Identify coai iandsb} Unsuitabiiity findingsc) Resource tradeoffsd) Surface owner consultation

w

Activity pianning:a) Preliminary tract

identificationb) Tract ranking and

proposed tractseiectionschedulingwithin regions

c) Regionai saie EiSs1

1,Sales:

a) Decision by Secretary on selectionand scheduling of tracts for Saie

b) Notice of saiec) Lease saie

Description of action Agency involvement

Regionai productiongoais and

ieasing targets:a) DOE regionai

production goaisb) RCT recommends

regionai leasingtargets based onDOE goais

c) Secretary adoptsregionai ieasingtargets

Planning update — unsuitability criteria BLM; FWSExpressions of interest BLMTract delineation GS; BLMTract site-specific analysis BLM; GS; OSMTract ranking BLM; GS; FWS; OSMTract selection, scheduling, and analysis BLM; GS; FWSRegional EIS BLM; GS; FWS; OSM; HC & RS; BR; BIA; DeptDEIS printing and distribution BLMPublic review period BLM; GS; FWS; OSM; HC & RS; BR; BIAPFEIS, development, and review BLM; GS; FWS; OSM; HC & RS; BR; BIAFEIS printing and distribution BLMDOE review, Governor’s consultation BLMSecretarial review decision on FEIS Secretary’s officePrelease sale activities BLM; GSLease sale begin BLM

Key.BIA Bureau of Indian AffairsBR: Bureau of ReclamationDEIS: draft environmental impact statementFEIS: final environmental impact statementHC & RS: Heritage, Conservation, and Recreation ServicePFEIS: preliminary final environmental impact statementRCT: regional coal team

SOURCE: U.S. Department of the Interior, Bureau of Land Management, June 1980.


Table 75.—Department of the Interior Division of Functions and Responsibilities Concerning Management ofFederal Coal Between the Office of Surface Mining, the U.S. Geological Survey and the Bureau of Land

Management (OSM, USGS, and BLM)

Prime Jo in t In consul ta t ion ConcurrenceF u n c t i o n responsib i l i ty responsib i l i ty w i t h f rom

Preleasing functionsEvaluate coal resources

Petition process fordesignation of Federallands unsuitable for allor certain types of sur-face coal miningoperations

Federal coal landsreview

USGS — — —— —OSM — Receives petitions Sur face Management

— Conducts hear ings Agency and other— Issues dec is ions appropriate State and local

agencies

OSM, USGS and other OSM — Establishessurface managing ground rulesagencies and criteria

for Federalcoal landsreview

BLM — Appl ies cr i ter ia in —

determinat ion ofsui tabi l i ty

Preparation of regional B L M l e a d a g e n c y ( u n l e s s o t h e r —EIS or site-specific pre- agency designated lead agency)lease EIS concerning — Relating to lease tractlease tract selection select ion

OSM, USGS and other —appropr ia te agenciesand State and localin terests

Preparat ion, spec ia l BLM —

lease terms andc o n d i t i o n s

OSM (responsibilities USGS, OSM, and DOE

under SMCRA - toadmin is ter protect ionrequirements of theact), USGS (responsi-

bilities under the MLA)

Act as Secretary’sofficial representativein dealing with leaseapplicants

BLM — — —

BLM (lease tract selectionfunct ion)

Surface owner consent — — —

Post/easing preminingfunctionsPrepare recommenda-tions on applicationsfor use of federallyowned surface overleased coal for rightsnot granted inFederal coal lease

BLM OSM and USGS (BLMreceives applications) - priorto receipt of coal miningplan it is solely USGSresponsibility to reporton surface use application

USGS before mining –plan; OSM after miningplan filed.

Delineation of “permitarea”

None until mining plan filed,Then OSM assumes responsi-bility with concurrence of BLMand USGS

— BLM and USGS—

Review, approval ofmining plans and majormodifications; leadagency for preparationof site specific EA/EISand coordination withother agencies outsideDOI

OSM has lead responsibility (for-merly assigned to USGS, becameessential function of OSM undersec. 201, SMCRA)

BLM and USGS BLM regarding special USGS on productionrequirements relating and recoveryto protection of natural requirementsresources; USGS regard-ing responsibilitiesrelating to development,production and resourcerecovery requirements

OSM —Exploration on leasedcoal lands outside apermit area

USGS receives application andsupervises operations for all ex-ploration outside a permit area

—


Table 75.—Department of the Interior Division of Functions and Responsibilities Concerning Management ofFederal 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 ConcurrenceFunction responsibility responsibility with from

——.Exploration on leasedcoal lands within a per-m it area

Responsibility for allnon-lessee activity onlease land prior tooperations

Responsibility for determining performancebond

Functions and respon-sibilities during miningoperationsAct as Secretary’srepresentative in deal-ing with lessees and/oroperators duringoperations

Take necessary actionin emergency environ-mental situation

Conduct inspectionprior to abandonmentand specify and ap-prove abandonmentprocedures

Release of reclamationbond (permanentprogram)

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 ap-prove abandonment proceduresand approve abandonment ofoperations)

OSM

BLM

OSM and USGS coordinate USGSa data exchange

— —

— —

USGS retains product ion —functions; OSM assumesenvironmental and enforce-ment functions; BLM retainsnonmining functions out-side the permit area, in-cluding rights-of-way andancillary activities relatedto mining. USGS and BLMinspection in connectionwith USGS, BLM functionsare coordinated with OSMinspections (except BLM in-spections outside the per-mit area). USGS makesroyalty audits and othernon field inspections in-dependent of OSM

OSM has primary emergen–cy authority; BLM andUSGS have such authoritywhen OSM inspectors areunable to take action beforesignificant harm or damagewill occur.USGS and BLM retain theirpresent procedures foremergencies involving loss,waste, or damage to coaland other natural resourcesand to other M LA functions

OSM, USGS, BLM - all have Private surface owner inabandonment inspect ion case of private surfaceresponsib i l i ty

USGS

—

—

—

—

BLM concurrence inapproval of com-pliance, special re-quirements: protectionof natural resourcesand post-mining landuse of affected lands.USGS concurrence:compliance with pro-duction and coalresource recovery re-quirements.

— — BLM and USGSconcurrence.

— — OSM and USGSconcurrence.

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 whenrequired 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


shows the division of functions and respon-sibilities among BLM, the U.S. GeologicalSurvey (USGS), and the Office of SurfaceMining (OSM) within DOI for the administra-tion of the Federal coal management pro-gram, BLM is the lead agency for implementi-ng DOI’s preleasing and leasing functions;OSM is responsible for processing designa-tion petitions and coordinating mine planreview; and USGS is responsible for evaluat-ing the coal resource and enforcing MineralLeasing Act requirements and collectinglease revenues from production. The Fish andWildlife Service is consulted on matters in-volving wildlife and potential impacts onrefuges. The Forest Service of the Depart-ment of Agriculture becomes involved as thesurface management agency for lands in na-tional forests. In addition, the Department ofEnergy (DOE) shares responsibility with DOIfor setting production levels, bidding systemsand diligence requirements on Federal en-ergy mineral leases.18

As part of the coal management programcooperative Federal-State regional coal man-agement teams were formed which institu-tionalize the requirements in FCLAA for con-sultation with State and local governmentsbefore leasing. The regional coal teams in-clude representatives of the Western Gover-nors who make specific recommendations tothe Secretary of the Interior on where, howmuch, and when coal should be leased onFederal lands.

DOI and DOE were given collateral respon-sibilities for establishing regional coal pro-duction goals and leasing targets. DOE peri-odically issues national and regional produc-tion goals. These goals in turn are consideredby DOI in establishing regional leasing tar-

gets. These production goals and leasing tar-gets are used by the regional coal manage-ment teams in the “activity planning process”which advises the Secretary on the tractselection, ranking and scheduling proposedlease sales in the regions.

Establishing regional production goals andleasing targets is done in two stages: 1) tractdelineation and industry expressions of in-terest in each land-use planning area; and2] tract ranking, selection and scheduling,considered over the entire coal region. Indelineating tracts, BLM considers the in-terests of the industry, technical data pro-vided by USGS and the States, MER estimatesof USGS, potential LMUs, surface ownership,and regional leasing targets.

Final regional tract ranking, selection andscheduling of lease sales is based on two de-terminations: 1) a site-specific environmentalanalysis of the proposed tracts and 2) the re-gional coal team recommended ranking of thetracts (high, medium, or low) considering geo-logical and economic factors and potentialenvironmental and socioeconomic impacts ofmining. At every stage in the overall leasingprogram, public participation is encouragedthrough open meetings of regional coal teams,public hearings, opportunities for commentand review during the leasing target and EISprocesses. Most of this public participationand consultation with State and local govern-ments is required by FCLAA, After the plan-ning, target setting, tract selection and rank-ing are completed, the tracts are offered forsale by competitive bid. The first sale underthe new program was held in early 1981 in theGreen River-Hams Fork region and includedone small tract under a special small businessset aside arrangement.


Legal Issues Relating to ExistingFederal Leases

Of the 565 Federal leases in effect onSeptember 30, 1980, 535 leases containingnearly all of the Federal coal reserves underlease were i s sued be fore enac tment o fFCLAA, and are thus subject in part to dif-ferent legal requirements than leases issuedafter FCLAA.

This section examines some of the majorlegal issues related to the development andmanagement of existing Federal leases andPRLAs including:

●

●

●

●

diligent development, and the relatedconcepts of continued operation, LMUS,advance royalties, maximum economicrecovery and cancellation;exchanges of reserves under existingleases and PRLAs for unleased Federalreserves;processing and va l id i ty o f pend ingPRLAs; anddesignation of areas on existing leasesthat are unsuitable for surface mining un-der section 522 of SMCRA.

Diligent Development andRelated Concepts

The concept of “diligent development” ofFederal coal leases evolved over a period oftime. A number of legal uncertainties stillsurround its practical application to existingleases. There are several other importantconcepts that are either directly or indirectlyrelated to diligent development: 1) require-ments in the 1920 Mineral Leasing Act forcontinued operation of a lease once diligentdevelopment is achieved, 2) definition ofLMUs and logical mining unit reserves towhich diligent development and continued op-eration requirements apply, and 3) advancepayment of royalties either to encouragediligent development, or in lieu of require-ments for continued operation.

Common Law Diligence

Diligent development as an implied cov-enant of mineral leases originated in commonlaw. Under the Mineral Leasing Act, diligentdevelopment is an express condition of everyFederal lease. The condition of diligent devel-opment imposes an obligation on the lessee toproduce the mineral so that the lessor re-ceives the agreed royalty to fulfill the lessor’sinterest in the contract.

As applied to private mineral leases undercommon law, the courts have generally de-fined diligence as requiring the lessee to “dowhatever under the circumstances would bereasonably expected of a prudent operator ofa particular lease, having a rightful regard forthe interests of both the lessor and thelessee." 19 Market considerations can be takeninto account, however, absence of a market isnot grounds for indefinite deferral of produc-tion. Each case is decided on its specific cir-cumstances. Lease provisions can providemore specific diligence standards such as re-quiring production to commence within a def-inite time period or allowing the lessee to payadvance royalties instead of producing.

Compensation for the rights to explore anddevelop mineral resources is often paid in atwo-part process. The initial rights to enter,explore, and develop a leasehold are grantedto lessees in exchange for payment of a fee(bonus) generally made at the time the lease isexecuted. The second payment is a continu-ous periodic payment of royalties, usuallybased on a percentage of the value of theproduct. To ensure that the lessor receivedsome periodic payment even in the absence ofproduction, annual rentals are sometimesnego t i a t ed tha t a re based on min imalpayments for holding the lease,

The size of the bonus payment is generallyproportional to the probability of finding andproducing minerals at a profit. If the prob-


ability of discovering commercial high-graderesources is high, the bonus payment will belarge. If the probability of commercial dis-covery and economic production is highly un-certain, the bonus payment will be low.

Since royalties are not received until pro-duction begins, and production must continueor the royalties will cease; a condition (stipu-lation) requiring continued operation is oftenincluded in a lease agreement to ensure thatproduction and income continue. Failure topursue diligent development of the leaseholdand to continue production constitutes abreach of the lease contract. The most viableremedy available to a lessor harmed as theresult of a contractual breach is cancellationof the lease, and if the lessor choses, resaleof the lease to one who will develop theleasehold.

The 1976 Diligence Regulations

Although all pre-FCLAA coal leases bystatute must contain both the conditions ofdiligent development and continued produc-tion, enforcement of these provisions wererare until 1976 when the terms and meaningof the provisions were defined by rulemaking.Between 1920 and 1976, various lease termshad imposed minimum investment and pro-duction requirements and advance royalties,but these provisions were not applied univer-sally to all leases.20

In response to an unprecedented period ofgreatly expanded leasing during a time ofdecreasing Federal coal production, DOIbegan grappling with the problem of diligencein lease development in 1970. Its initial ef-forts concentrated on policies aimed at apply-ing economic leverage on lessees to ensureproduction, e.g., such as gradually increasingadvance payment royalties, which would re-quire front-end payments that would be offsetagainst future production. Congress, how-ever, preferred the establishment of specifictime limits for development, therefore, in1974-1975 DOI proposed regulations thatdefined diligent development and set timelimits for performance, but also retained the

option for advanced royalty payments (seetable 76 summarizing proposed and final reg-ulations on diligent development). Final reg-ulations were promulgated by DOI in May1976 shortly before passage of FCLAA, 21

With the approval of the 1976 FCLAA, a dualsystem governing diligent development wasestablished, The legal effect was to createtwo similar, but not identical diligence stand-ards, one applying to leases issued before toAugust 4, 1976 (pre-FCLAA), and the secondapplying to leases issued after that date (post-FCLAA). These regulations have remainedlargely unchanged since repromulgation inDecember 1976 to include FCLAA require-ments. 22 The Department of Energy Organiza-tion Act of 1977 transferred the Secretary ofthe Interior’s authority to issue regulations ondiligence for Federal leases to the Secretaryof Energy.’ ) The Secretary of the Interior re-tains the responsibility for enforcement, buthe cannot change these regulations.

Summary of Diligent Development andContinuous Operations Regulations

Section 7 of the Mineral Leasing Act of1920 requires that all Federal coal leases aresubject to diligent development and con-tinuous operations. Lessees failing to meetthese conditions can lose their Federal coalleases. Moreover, under section 3 of FCLAA,after August 4, 1986, with few exceptions,lessees who have held a nonproducing leasefor 10 years or more cannot obtain any newFederal coal leases.24

In 1976, DOI issued regulations definingdiligent development for Federal coal leasesas timely preparation for and actual produc-tion of coal in commercial quantities from thelease, or from the LMU of which the lease is apart, by June 1, 1986 or within 10 years afterthe lease is issued, whichever is later.

These regulations established two sepa-rate standards for diligent development ofFederal leases by defining commercial quan-tities differently for pre-FCLAA and post-FCLAA leases. Commercial quantities forpre-FCLAA leases are defined as “production


Table 76.—Changes in Definitions of Diligent Development and Continued Operation,Proposed and Final Regulations (1974-79)

Source Diligent development Continued operation

Federal RegisterDec. 11, 1974(Proposed)39 F.R. 43229

Diligent development means: preparing to extractcoal from an LMU in a manner and at a rate consist-ent with a mining plan approved by the miningsupervisor. Qualifying activities and expendituresinc lude env i ronmenta l moni tor ing and basel ine

Continuous operations defined as: extraction, processing,and marketing of coal in commercial quantities from theLMU without interruptions totaling more than 6 months inany calendar year except as provided in 30 U.S.C. 207and in the lease.

studies, geological and geophysical studies,engineering feasibility studies, mine developmentand construction work, and contracts for purchaseor lease of equipment undertaken for the purpose ofobtaining production from the LMU.Lessee must report on activities in support ofdiligent development to mining supervisor every 2years and indicate plans for continuing diligentdevelopment for following 2-year period.

Federal RegisterDec. 31, 1975(Reproposed)40 F.R. 60070

Federal RegisterMay 28, 1976(Final)41 F.R. 21779

Diligent development means timely preparation forand initiation of production from the LMU of whichthe lease is a part so that one-fortieth of the LMUreserves associated with the lease are extractedwithin 10 years from the effective date of the regu-lation or issuance of the lease, whichever is later.Additional time for meeting diligence may begranted for a period equal to the time during whichdiligent development was significantly impaired by:

1. a strike, the elements or casualties not at-tributable to the lessee;

2. an administrative delay in the DOI not causedby the lessee’s action; or

3. extraordinary circumstances not attributable tothe lessee and not foreseeable by a reasonablyprudent opera tor (ex t raord inary c i rcumstancesdo not include: conditions arising out of normal-ly foreseeable business risks such as fluctua-tions in prices, sales, or costs, includingforeseeable costs of environmental protectionrequirements; commonly experienced delays indelivery of supplies or equipment; or inability toobtain sufficient sales).

Diligent development defined as: timely preparationfor and initiation of production from the LMU ofwhich the lease is a part so that one-fortieth of theLMU reserves associated with the lease are ex-tracted within a period of 10 years from the effecteddate of the regulations (i.e., by June 1, 1986) or fromthe issuance of the lease, whichever is later.Extensions may be granted for time during whichdiligent development is substantially imparied by:

1. a strike, the elements or casualties not at-tributable to the lessee;

2. an administrative delay in the DOI not causedby the lessee’s action; or

3. extraordinary circumstances not attributable tothe lessee and not foreseeable by a reasonablyprudent operator.

An extension may also be granted for up to 5 years(i.e., to June 1, 1991) if the lessee cannot meetdiligence because of:

—time needed for development of an advancedtechnology (e.g. in situ gasification or liquefac-tion processes);

—the large magnitude of the project (ordinarily 2million tons per year for an underground mineand 5 million tons per year for a surface mine);o r

—a contract or equivalent firm commitment forthe sale of the first 2½ percent of the LMU re-serves after the 10-year period.

Continuous operations defined as extraction, processing,and marketing of coal from the LMU after diligent devel-opment has been achieved in an amount of 1 percent ormore of the LMU reserves in each calendar year subjectto the exceptions in 30 U.S.C. 207 and in the lease.

Continuous operations defined as the extraction, process-ing, and marketing of coal in the annual average amountof 1 percent or more of the LMU reserves computed on a3-year basis including the 2 previous years.With approval of the mining supervisor, advance royal-ties may be paid in lieu of continuous operations forleases issued or readjusted after the effective date of theregulations,

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 RegisterOct. 15, 1976(Proposed)41 F.R. 45571

Federal RegisterDec. 29, 1976(Final)41 F.R. 56643

Federal RegisterMar. 19, 1979(Proposed)44 F.R. 16800

Federal RegisterJuly 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 prepara-tion for and initiation of production from the LMUof which the lease is a part so that coal IS actuallyproduced in commercial quantities by June 1, 1986(commercial quantities IS defined as production ofone-fortieth of the LMU reserves associated withthe lease). Extensions may be granted under thesame conditions as in the May 1976 final regula-tions, but the period for meeting diligence cannotbe extended beyond Aug. 4, 1986, or the date thelease IS first subject to readjustment after FCLAA,whichever IS laterFor post- FCLAA leases and all readjusted pre-FCLAA leases, diligent development means timelypreparation for and initiation of production from theLMU of which the lease IS a part so that coal IS ac-tually produced in commercial quantities (defined as1 percent of the LMU reserves) by 10 years after theeffective date of the lease or by June 1, 1986 or bythe date on which the pre-FCLAA lease IS first sub-ject to readjustment after FCLAA, whichever IS later.Extensions granted to pre-FCLAA leases can con-tinue in effect after readjustment, but only until Aug.4, 1986.

For pre-FCLAA leases: Diligent develop-merit means -

timely preparation for and initiation of productionfrom the LMU of which the lease IS a part so thatcoal IS actually produced in commercial quantities(defined as one-fortieth of the LMU reserves) byJune 1, 1986 Extensions may be granted undersame conditions as May 1976 final regulations.For post. FCLAA leases: diligent development meanstimely preparation for and initiation of productionfrom the LMU of which the lease IS a part so thatcoal IS actually produced in commercial quantities(defined as 1 percent of the LMU reserves) within 10years from the effective date of the lease (No provi-sions for any extensions for post-FCLAA leases areincluded in the regulations.)

No substantive changes proposed to Decemberfinal regulations (The authority to promulgaterules relating to diligence and minimum productionrequirements for Federal leases was transferred tothe Secretary of Energy by section 302 of theDepartment of Energy Organization Act )

No substantive changes to December 1976 final -

regulations—relevant sections renumbered as partof new coal management program regulations

erally summarizes the regulations rather than quoting them in full.

Continued operation

‘Continued operation means the extraction, processing, andmarketing of coal in the amount of 1 percent of all theLMU reserves associated with the lease for each of thefirst 2 years of continued operation and in an annual aver-age amount of 1 percent of all the LMU reserves asso-ciated with the lease for all following years The annualaverage amount will be calculated on a 3-year basis withthe 2 preceding years

Continued operation means production of 1 percent ofthe LMU reserves in each of the first 2 years after meet-ing diligence, and production at an annual average rate of1 percent of the LMU reserves thereafter. The annual aver-age rate IS calculated on a 3-year basis with the 2 pre-vious years

No substantive changes proposed to December 1976final regulations

No substantive changes to December 1976 final regula-tions-relevant sections renumbered as part of new coalmanagement program regulations.

Logical Mining Units

The current regulations define diligence

of one fortieth (21/2 percent) of the recov-erable reserves of the LMU of which the leaseis a part. ” For post-FCLAA leases, commer-cial quantities are defined as “production of and continuous operations requirements ac-

one percent of the lease’s LMU reserves cording to LMUS rather than leases. The ba-

within 10 years after lease issuance, ” Under sis of the LMU concept, as generally under-

certain circumstances, the diligence period stood, is that geological and engineering

can be extended for pre-FCLAA leases, characteristics should delineate the bound-


aries of the area that can be leased andmined economically with appropriate envi-ronmental safeguards. In practice, however,the legal right to mine coal often dictates thearea to be developed, which can result in aless than optimal mining unit, especially inareas with scattered and diverse ownership.The concept, with some modification, was in-corporated into the 1976 diligence regula-tions and FCLAA. The regulations currentlydefine an LMU as:

. , . an area of coal land that can be devel-oped and mined in an efficient, economical,and orderly manner with due regard for theconservation of coal reserves and other re-sources. An LMU may consist of one or moreleases and may include intervening or ad-jacent non-Federal lands, but all lands in anLMU must be contiguous, under the effectivecontrol of a single operator, and capable ofbeing developed and operated as a unifiedoperation with complete extraction of theLMU reserves within 40 years from the dateof first approval of a mining plan for thatLMU. No LMU approved after August 4,1976, shall exceed 25,000 acres, includingboth Federal and non-Federal coal deposits.25

Notwithstanding this definition, the rules alsoprovide that “each lease shall automaticallybe considered to constitute an LMU on the ef-fective date of the lease or June 1, 1976,whichever is later. 26 The single lease LMUcan later be modified to add other Federal ornon-Federal coal with the approval of DOI,but the enlarged unit must meet the generalLMU criteria. The single lease LMU was es-tablished in the May 1976 regulations pri-marily for administrative convenience in ap-plying diligent production requirements, how-ever, it was reinforced at least indirectly bysection 5 of FCLAA which requires the les-see’s consent before pre-FCLAA leases canbe consolidated into a designated LMU underthat section. Table 77 summarizes the devel-opment of the LMU concept in DOI reg-ulations.

For pre-FCLAA leases, the LMU is deter-mined by the lease boundaries, and the LMUreserves for diligence and continuous re-quirements are the recoverable reserves of

the lease unless the lessee petitions either tohave the LMU boundaries modified to includeother Federal leases or non-Federal coal or torelinquish portions of the lease reserves thatwill not be mined. If a new LMU is desig-nated, the aggregate production from alllands in the unit can be used to meet diligencefor all producing and nonproducing leases inthe unit.

Diligence Extensions

Extens ions can be approved for pre -FCLAA leases for delays in meeting diligencebecause of conditions that are beyond thecontrol of the lessee. These extensions are re-quired by sections 7 and 39 of the MineralLeasing Act.27 These nondiscretionary exten-sions are granted for a period of time equal tothe time during which diligence is impairedby: strikes, weather conditions, casualties,Government delays, or extraordinary circum-stances that are not the fault of the operator.Regulations on whether and under whatcircumstances nondiscretionary extensionsmight be available to post-FCLAA lesseeshave not yet been promulgated.28

In determining whether such extraordi-nary circumstances exist, the regulationsspecifically exclude “any condition arisingout of normally foreseeable business riskssuch as: fluctuations in prices, sales, or costs,including foreseeable costs of compliancewith requirements for environmental protec-tion; commonly experienced delays in deliv-ery of supplies or equipment; or inability toobtain sufficient sales. ’29

The pre-FCLAA lessee can also apply for asingle extension of up to 5 years, i.e., up toJune 1, 1991, under certain circumstances.These d i scre t ionary ex tens ions may begranted for: 1) additional time for developingnew coal technologies, such as synfuels ornonwater-based coal slurry pipelines; 2) ex-traordinarily large or complex mining opera-tions (generally exceeding 2 million tons peryear for underground mines and 5 milliontons per year for surface mines); or 3) firmcontracts to produce and deliver the first 2½

Ch. 9—Federal Coal Lease Management . 243

Table 77.—Changes in Definitions of Logical Mining Unit and Logical Mining Unit ReservesProposed and Final Regulations (1974.79)

Source

Federal RegisterDec. 11, 1974(Proposed)39 F.R. 43229

Federal RegisterDec. 31, 1975(Reproposed)40 F.R. 60070

Federal RegisterMay 28, 1976(Final)41 F.R. 21779

Logical mining unit

An LMU is a compact area of coal land that can bedeveloped and mined in an efficient, economical,and orderly manner with due regard for conserva-tion of coal reserves and other resources and in ac-cordance with an approved mining plan,The LMU may consist of one or more Federal lease-holds and may Include Intervening or adjacent non-Federal lands insofar as all lands are under the ef-fective control of a single operator. Mining super-visor (MS) authorized to approve or establish anLMU.All leases must be included in an LMU within 2years from effective date of regulations If thelessee IS unable after a good faith effort to form anLMU as defined in the regulations, a single leasewill be treated as an LMU for diligence and report-ing requirements.

An LMU IS an area of coal land that can be devel-oped and mined in an efficient, economical, andorderly manner with due regard to the conservationof the coal reserves and other resources. An LMUmay consist of one or more Federal leases and mayInclude Intervening or adjacent non-Federal lands, ifall lands are under the control of a single operatorand can be developed and operated as a unifiedmine.The MS IS authorized to approved or establishan LMU.Every Federal lease wiII automatically be consid-ered an LMU; the LMU boundaries may later bechanged:

1. at request of lessee with approval of MS withconcurrence 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 devel-oped and mined in an efficient, economical, andorderly manner with due regard to the conservationof the coal reserves and other resources. An LMUmay consist of one or more Federal leases and in-tervening or adjacent non-Federal lands, but alllands in an LMU must be under the effective controlof a single operator and capable of being developedand operated as a unified mineEvery lease wiII automatically be considered byitself an LMU as of the effective date of the lease orthe regulations, whichever IS later,Any LMU other than a single Federal lease wiIIbecome effective only on its approval by the MSwhere it IS requested by the lessee. Boundaries ofLMU may later be changed on application by thelessee and with approval of the MS and after con-sultation 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 of41 F.R. 45571 the coal reserves and other resources. An LMU may

consist of one or more Federal leases and inter-vening or adjacent non-Federal lands, but all landsin the LMU must be contiguous, under the effectivecontrol of a single operator and capable of beingdeveloped and operated as a unified operation withcomplete extraction of the LMU reserves within 40years 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 andnonfederal 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 theLMU, and 2) estimated non-Federal recoverable reservesthat wiII be mined before extraction of all Federal re-serves in the LMU.Federal LMU reserves will be the estimated reserves onthe effective date of regulations—or the date of the lease,whichever is later,Reserves may be adjusted by MS whenever significantnew information becomes available about the amount ofsuch reserves, including the time at which a mining planIS approved for the Federal portion of the LMU.

—.As of a given date, LMU reserves are the sum of 1) esti-mated recoverable Federal reserves under lease in theLMU, and 2) estimated non-Federal recoverable reservesthat wiII be mined before extraction of all the Federal re-serves in the LMU. LMU reserves associated with a Fed-eral lease are the estimated LMU reserves as of effectivedate of approval of LMU.LMU reserves may be modified when MS approves mod-ification of LMU boundaries or whenever significant newinformation becomes available about the amount of recov-erable 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 theMS whenever a modification of the LMU boundariesIS approved, or the lessee surrenders deposits under

lease in the LMU, or whenever additional Informationbecomes available about the amount of such reservesincluding when a mine plan is approved,


Table 77.—Changes in Definitions of Logical Mining Unit and Logical Mining Unit ReservesProposed and Final Regulations (1974-79)—Continued

Source—

Federal RegisterDec. 29, 1976(Final)41 F.R. 56643

Federal RegisterJuly 19, 1979(Final)44 F.R, 42583 now43 CFR 3400.0-5

— — —Logical mining unit— -——

Notwithstanding the above definition, every Federallease will automatically be considered an LMU onthe effective date of the lease or June 1, 1976,whichever is later.An LMU other than a single lease LMU will becomeeffective only at the direction of the MS or by ap-proval of the MS at the request of the lessee.(These designated LMU’s must meet the re-quirements of section 5 of FCLAA.)—-.Unchanged from October 1976 proposed ‘ - -

regulations,

An LMU is an area of coal land that can be devel-oped and mined in a efficient, economical, andorderly manner with due regard for the conservationof coal reserves and other resources. An LMU mayconsist of one or more leases and may includeintervening or adjacent non-Federal lands, but alllands in the LMU must be contiguous (i.e., havingone point in common, including cornering tracts),under the effective control of a single operator, andcapable of being developed and operated as aunified operation with complete extraction of theLMU reserves within 40 years from the date of firstapproval of the LMU mine plan. No LMU approvedafter Aug. 4, 1976 may exceed a total of 25,000acres of Federal and non-Federal lands.Notwithstanding the above definition, every Federallease will automatically be considered an LMU onthe effective date of the lease or June 1, 1976,whichever is later.An LMU, other than a single lease LMU, wiIIbecome effective only on approval by the MS on ap-plication by the lessee, or by direction of the MS, orby designation during the normal tract delineationphase of the coal activity planning process. The MSwill not approve the designation of such an LMUunless maximum economic recovery of all theFederal coal deposits in the LMU will be achieved.

Logical mining unit reserves

Logical mining unit reserves are the sum of 1) estimatedrecoverable Federal reserves under lease in the LMU and2) estimated non-Federal recoverable reserves in the LMU.The LMU reserves associated with the Federal lease arethe estimated recoverable reserves on the effective dateof the LMU.The LMU reserves may be adjusted by the MS wheneverthe LMU is modified, or the lessee surrenders deposits inthe LMU, or whenever significant new informationbecomes available about the amount of such reserves in-cluding when a mine plan is approved.

LMU–reserves mean the sum of 1) estimated recoverablereserves under Federal lease in the LMU, and 2) esti-mated non-Federal recoverable reserves in the LMU. TheFederal lease LMU reserves are estimated as of the datethe LMU becomes effective. The LMU reserves may be ad-justed by the MS whenever the LMU boundaries are modi-fied or when significant new information becomes avail-able 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 avail-able for post-FCLAA leases.

Continuous Operations

After attaining diligence, both pre-FCLAAand post-FCLAA lessees must meet the con-tinuous operations requirements. The regula-tions define continuous operations for allFederal leases as production of an average of1 percent of the LMU reserves annually, with1 percent produced in each of the 2 years im-

mediately following the year in which thelessee meets diligence. With approval of DOI,the lessee can pay advance royalties in lieu ofactual production in order to satisfy contin-uous operations requirements. Such advanceroyalty payments, however, cannot be madein lieu of continued operation for more than10 years during the life of the lease. Con-tinuous operations requirements for pre- andpost-FCLAA leases can be suspended duringperiods when production is interrupted be-cause of conditions beyond the control of thelessee. Minimum annual production require-

Ch. 9—Federal Coal Lease Management “ 245

ments can also be lifted when operations onthe lease are suspended with the approval ofthe mining supervisor to promote conser-vation of coal resources. Table 76 showsthe development of continuous operationsregulations.

Advance Royalties

Advance royalties are commonly used byprivate coal lessors to ensure that mine pro-duction stays on schedule. If production pro-ceeds according to the predetermined sched-ule, the lessee continues to pay the regularroyalty, but if production is lower than sched-uled, advance royalties are collected on thedifference between scheduled and actualproduction. The purpose for using advanceroyalties is to provide a financial incentivefor the lessee to develop the lease.

Advance royalties have been used in sev-eral ways in pre-FCLAA leases: 1) in lieu ofcontinued operation requirements for leasesissued between 1920 and 1971; 2) as an in-centive to begin production for leases issuedduring the moratorium between 1971 and1976 by requiring payment of advance royal-ties beginning in the sixth year after issuanceof the lease based on a predetermined sched-ule (similar to the way advance royalties areused in the private sector); and 3) in lieu ofcontinued operation for up to 10 years duringthe term of the lease as allowed by FCLAA.32

Advance royalties are currently based onan annual production rate that would ex-haust the mine reserves in 40 years (2.5 per-cent per year) .33 This rate is higher than the 1percent rate required to satisfy continuousoperation regulations and thus is an incentiveto produce.

Cancellation of Leases

Under section 31 of the Mineral LeasingAct of 1920 if the lessee fails to comply withthe terms of the lease, a provision of the act,or general regulations issued under the actthat were in force at the date of the lease, theSecretary may ask the Justice Department tosue in Federal court to have the lease for-

feited and canceled.34 For pre-FCLAA lessees,breach of the conditions of diligent devel-opment or continued operation could result incancellation of the lease in court proceedingsif the court decided that the lessee did notmeet diligence because he or she did notsatisfy the minimum production defined in the1976 regulations (or some other standard).35

Section 6 of FCLAA provides that any post-FCLAA lease not producing in commercialquantities 10 years after issuance shall beterminated automatically. Termination is anadministrative proceeding and is subject tojudicial review. The May 1976 DOI regula-tions l imited the circumstances that theSecretary c o u l d c o n s i d e r i n d e c i d i n gwhether to cancel a lease for failure to meetdil igence by generally excluding lack ofmarkets.36 Both pre- and post-FCLAA leasesmust be canceled through court proceedingsbrought under the general provisions of sec-tion 31 for any other breach of the leaseterms or conditions, or for violation of the actor DOI regulations.

Application of the 1976 DiligenceRequirements to Existing Leases

Since 1976, DOI has maintained that the1 9 7 6 d i l i g e n c e r e g u l a t i o n s a r e g e n e r a lregulations implementing the Mineral Leas-ing Act which are applicable to all coal leasesand that the regulations, thus, need not bemade specifically part of individual leasesthrough amendment or readjustment. Thediligence regulations and other aspects of thecoal management program are currentlyunder review by the Reagan administrationand could be modified. Whether or not the1976 regulations are eventually held to begenerally applicable to all leases, under cer-tain circumstances the diligence require-ments can be made part of individual leases:1) by voluntary amendment of the lease termsby mutual agreement between DOI and thelessee; 2) by readjustment at the end of thelease term; 3) by amendment as part of thedesignation of a new LMU under section 5 ofFCLAA; or 4) by operation of existing leaseterms incorporating future regulations. If the


requirements are specifically incorporatedinto a lease, they are clearly applicable andenforceable for that lease.

Voluntary Amendment

At the request of DOI, some lessees havevoluntarily agreed to lease revisions incor-porating the diligent production require-ments. In other instances, DOI could nego-tiate the lessee’s consent to revise the lease toinclude the 1976 regulations as part ofanother transaction involving the lease, suchas a modification or segregation, or in ex-change for DOI’s agreement not to move im-mediately to enforce the minimum productionrequirements contained in some existingleases.37

Readjustment

Pre-FCLAA leases were originally issuedfor indeterminate periods subject to readjust-ment of lease terms, conditions, rentals androyalties at the end of each 20-year periodfollowing issuance. The Secretary of the In-terior has broad discretion in setting newlease terms. Readjustment generally resultsin incorporating any changes in the laws andregulations governing leases that were notapplicable at the time the original lease wasissued. At readjustment, pre-FCLAA dili-gence requirements are expressly made partof the new lease terms. If the new terms areunacceptable, the lessee can either: 1) de-cline extension of the lease; or 2) appeal orprotest the revised terms. Leases readjustedafter August 4, 1976 are to include the 1976diligence requirements that apply to pre-FCLAA leases. About 244 pre-FCLAA leasesare due for readjustment before June 1, 1986.Over 200 pre-FCLAA leases are not due forreadjustment unti l after the init ial 1986diligence “deadline,”

Amendment of Lease Terms onDesignation of a Section 5 LMU

Under section 5(b)(4) of FCLAA, when oneor more leases, including pre-FCLAA leaseswith the consent of the lessee, are con-

solidated into an LMU, the provisions of anyFederal lease in the LMU may be amended sothat mining will be consistent with the re-quirements imposed on that logical miningunit. 38 Although “consistency” is not definedand the Secretary is not required to amendthe lease, the LMU designation may be usedas an opportunity to provide for express ap-plication of diligence regulations to leaseswithin the LMU. However, such revisionwould require the lessee’s consent.

As another result of an LMU designationunder section 5(b)(3) of FCLAA, the Secretarymay (but is not required to) provide, “amongother things, that (i) diligent development,continuous operation, and production on anyFederal lease or non-Federal land in thelogical mining unit shall be construed as oc-curing on all Federal leases in that logicalmining unit . . .“ Since approval of an en-larged LMU is discretionary, the lessee’sconsent to include the 1976 diligence require-ments as a stipulation in the lease might beused as a condition for obtaining an LMUapproval. 39

Existing Lease Terms That IncorporateSubsequent Regulations

Federal coal leases issued or renewedafter 1965 contain a provision in the initialclause of the lease stating that the lease isissued:

. . . pursuant and subject to the terms andprovisions of (the Mineral Leasing Act of1920), and to all reasonable regulations ofthe Secretary now or hereafter in forcewhich are made a part hereof . , .40

By accepting the lease with this provision(referred to as the “hereafter clause”), thelessee has specifically agreed to be bound byfuture “reasonable regulations” made ap-pl icable to exist ing leases without thenecessity of formally amending the leaseterms. As a result of this express agreement,leases with this clause are subject to the 1976diligence regulations by operation of the priorlease term. Violation of the subsequent reg-ulations would, therefore, be a violation of

Ch. 9—Federal Coal Lease Management “ 247

the lease provisions and make the lease sub-ject to cancellation under section 31 of theMineral Leasing Act.41 The reasonableness ofany subsequent regulations would be deter-mined according to general principles of ad-ministrative law if the issue were ever liti-gated. The hereafter clause has been used inthousands of other Federal mineral leases forover 45 years, The meaning of the “hereafterclause” and its impact on the applicability ofthe 1976 diligence regulations on coal leaseshave not yet been judicially construed.

Legal and Administrative Issuesin the Enforcement of Diligence

Requirements

The impact of the 1976 diligence regula-tions on Federal coal leases is uncertain. Theregulations requiring actual production with-in 10 to 15 years were generally opposed bythe coal industry, and the major industrytrade groups. The National Coal Associationand the American Mining Congress, havecontinued to criticize the policy.

While many lessees have accepted the1986 deadline, and many will in fact meetdiligence by then (see ch. 6 of this report),legal challenges are likely if DOI enforces therequirements against those lessees who arenot in compliance. Among the major legal ob-jections which the industry has raised are:I) the regulat ions are arbitrary, unrea-sonable and exceed the Secretary’s authorityunder the Mineral Leasing Act because of thestringent compliance period imposed and thelack of flexibility in measuring diligence asproduction of 2½ percent of the LMU re-serves; 2) the regulations violate the MineralLeasing Act by imposing new terms and con-ditions on the lessee which can only be doneat readjustment; 3) the regulations are ineffec-tive to the extent that they conflict withspecific lease provisions; and 4) the regula-tions abridge the lessee’s contractual rights,thus, violating the constitutional prohibitionagainst deprivation of property without dueprocess of law or just compensation.

The only litigation challenging the applica-tion of the diligence requirements in the 1976regulations to pre-FCLAA leases, Mobil OilCorp. v. Andrus, was settled out of court andthus did not establish any precedent.42 As aresult of the settlement, Mobil received ap-proval of a 5-year extension in the period formeeting diligence for its 1971 lease.

The possible difficulties in enforcing DOI’sdiligence regulations were recognized in theSecretarial Issue Document for the FederalCoal Management Program,” One of the ma-jor uncertainties is the absence of a prior en-forcement history for diligence for Federalcoal leases. Before promulgation of the 1976regulations, DOI had not issued formal rulesdefining diligent development nor had it can-celed any coal lease for failure to meet dili-gence. As an added complication, many leaseforms contain provisions requiring minimumproduction beginning in the sixth year of thelease. Without the adoption of the 1976regulations superseding the lease terms andgiving 10 to 15 years to meet diligence, manynonproducing lessees would already be inviolation of their lease provisions. Ultimately,the issue of the validity and applicability ofthe 1976 regulations may be decided by thecourts. The range of possible results of suchchallenges include:

The 1976 diligent development regula-tions are valid and fully applicable to allleases because all leases are subject tothe conditions of diligence required inthe 1920 Mineral Leasing Act and to thedepartmental regulations implementingthese requirements, (the position of DOIin Mobil. )44The 1976 regulations are invalid and notapplicable to pre-FCLAA leases becausenothing in the 1920 Mineral Leasing Actauthorizes the Secretary to define dili-gence solely as achieving specified pro-duction levels within a definite period oftime. (Note: The Mineral Leasing Actand common law diligence conditionswould still be applicable although theprecise standard to be used would re-main undefined.)

94-141 c1 - 81 - 17 : ‘lIj 3

—


●

●

The 1976 diligence regulations are validbut are applicable to pre-FCLAA leasesonly on readjustment at the end of theircur ren t 20-year l ease t e rms o r byamendment of lease terms with consentof the lessee either in response to DOI’srequest or as a possible precondition ofapproval for designation of a combinedLMU under section 5 of FCLAA or otherdiscretionary administrative action.The 1976 regulations are valid and ap-plicable to pre-FCLAA leases to the ex-tent that they are consistent with thespecific terms and conditions of individ-ual leases issued before the regulationsbecame effective. The regulations wouldapply to leases containing the “here-after clause” which incorporates futureregulations, as well as to any leasesissued before 1965 that include provi-sions which do not establish differentminimum production levels or advanceroyalty payments to satisfy diligenceconditions.

Leases issued after the 1976 FCLAA areclearly subject to the diligent developmentregulations promulgated under that act andmust produce coal in commercial quantitieswithin 10 years after issuance or they will beterminated.

The eventual impact of diligence require-ments on pre-FCLAA leases will depend onthe interaction of many variables besides thelegal precedents that may be established onthe applicability of diligence regulations.These factors include: 1) the extent of volun-tary compliance by lessees; 2) how many ex-tensions are granted to lessees who cannotmeet the 1986 production deadline; 3) howmany existing leases are combined with otherleases or non-Federal coal reserves to meetdiligence by forming a designated LMU undersection 5 of FCLAA; 4) how the logical miningunit reserves are defined for each lease; 5)the extent to which leases are readjusted onschedule; 6) the extent of effective enforce-ment of the 1976 regulations by DOI and theDepartment of Justice; and 7) how many non-producing leases are relinquished.

Determination of LMU and LMUReserves for Diligence

Whether or not some existing leases willmeet diligence depends on the USGS deter-minations of LMU and LMU reserves againstwhich compliance is gaged. There are twokinds of LMUs for the purpose of diligence:1) single lease LMUs and 2) designated LMUsunder section 5 of FCLAA. All existing leasesare single lease LMUs under current regula-tions. Section 5 of FCLAA prohibits consoli-dation of any pre-FCLAA lease into an LMUwithout the lessee’s consent and no section5 LMUs had been approved by USGS as ofearly 1981.

Single lease LMUs are based on the gener-al authority of the Secretary to manage coalleases under the Mineral Leasing Act of 1920and the regulations originally promulgated inMay 1976 before passage of FCLAA. TheseLMUs consist of the reserves in a single leasethat can be mined efficiently and economical-ly with due regard for conservation of thecoal resource and other values. They neednot consist of a separate mine or mine planfor each single lease LMU. Single lease LMUsneed not be contiguous, nor must they bemined out in 40 years. The major difficulty indefining the LMU reserves for single leasesoccurs in determining which seams to includewhen the lease has large multiple-seam re-serves either that would not be mined in thelessee’s normal sequence and method of min-ing or that do not meet the lessee’s coal qual-ity requirements under existing contracts.Each such case will be negotiated separately,depending on the characteristics of eachlease and the lessee’s circumstances. Thus,in some instances, USGS may omit seamsfrom the LMU reserves or permit the lessee torelinquish particular seams or lease areasthat will not be mined.45

If a pre-FCLAA lessee requests designationof a section 5 LMU combining a pre-FCLAAlease with other Federal leases or non-Fed-eral lands, the LMU criteria of section 5 alsobecome applicable to the pre-FCLAA leases.Specifically:


1. the Secretary must find that maximumeconomic recovery of the coal deposits isserved by consolidation;

2. all lands in the LMU must be under theeffective control of a single operator, b eable to be developed and operated as asingle operation, and be contiguous;

3. the total acreage of the LMU must b e25,000 acres or less; and

4. any mining plans approved after theestablishment of a section 5 LMU mustrequire such diligent development, oper-ation, and production that the reservesof the entire unit will be mined in aperiod of not more than 40 years. 46

In addition, the terms of individual Federalleases in the LMU may be amended so thatmining on any lease will be consistent withthe requirements imposed on the entire LMU.LMU designation of a section 5 LMU is oftento the lessee’s advantage because the Sec-retary is authorized to provide that diligentdevelopment, continued operation and pro-duction occuring anywhere in the unit is con-sidered as occurring on all Federal leases inthe unit, thus, allowing a producing lessee tokeep nonproducing Federal leases in the LMUafter the 1986-91 diligence deadlines and tomine such leases in the optimum sequence forthat mine. Designation also allows rental androyalty obligations for all leases in the LMUto be combined and advance royalties can beapplied against the combined royalties due.

Many existing lessees will probably re-quest LMU designations under section 5 inorder to meet diligence; most of the lesseesshould qualify for such approval. Some oper-ating lessees in Colorado and Utah have non-contiguous nonproducing leases that theyintend to mine as part of their existing opera-tions after the diligence date. Unless the re-quirement that all leases in the LMU be con-tiguous is modified or reinterpreted, a section5 LMU could not include these noncontiguousareas and the lessee would probably shiftproduction prematurely to the new area fromother Federal leases.

Still other mines on Federal leases havevery large reserves in multiple seams and

could encounter the same difficulty in defin-ing the LMU reserves for a section 5 LMU asdescribed above for single lease LMUs. Re-serves on some of these potential LMUs areso large that meeting the 2½ percent dili-gence production target could become a prac-tical impossibility if all the lease reserveswere included. These cases too will be ad-dressed individually and could result in someseams being omitted from the LMU reservesor being relinquished.

Maximum Economic Recovery

Prior to enactment of the FCLAA in 1976,USGS conducted an informal monitoring pro-gram to ensure conservation of coal re-sources and prevent waste on Federal coalleases under the general authority of theMineral Leasing Act to protect the public in-terest. Section 3 of FCLAA created a formalrequirement for achieving the “maximumeconomic recovery” (MER) of Federal coal.The concept of MER “means that all portionsof the coal deposits within the lease tractshall be mined that have a private incremen-tal cost of recovery (including reclamation,safety and opportunity costs) less than orequal to the market value of the coal.” 4 7

Beyond this general definition of the termMER, guidelines for determining what is re-quired to meet MER have not been promul-gated. 48

FCLAA requires that MER be consideredat three stages: 1) at the time the lease isissued; 2) when the mine plan is approved;and 3) on approval of a section 5 LMU. At theprelease stage, the USGS mining supervisordetermines the mining method, e.g., surface,deep mining, etc., that is likely to yield thegreatest recovery under given economic con-ditions. The prelease determination is basedon a general examination of the tract andstandard mining practices, and not a detailedseam-by-seam assessment. The premining as-sessment of MER, on the other hand, is ex-pected to require a detailed investigation andthe application of more specific engineeringand economic evaluative criteria and maylead to modifications in the mine plan to en-


sure that MER is achieved. Before the Secre-tary can approve a petition for designation ofa section 5 LMU combining one or more Fed-eral leases with other Federal leases or withnon-Federal reserves, he must find that theconsolidation will serve maximum economicrecovery of the coal resources.

Theoretically, the application of the MERrequirement could lead to the extraction ofmarginal coal that was once left behind. Thepurpose of the MER standard was to preventthe possibility that operators on Federalleases would take only the most economicallyprofitable coal seams and would leave theless profitable or marginal reserves in theground. By requiring the lessee to average thecosts of mining over all the economically re-coverable coal under lease (thus offsettingthe profit from mining high-grade reservesagainst the higher costs of taking marginal re-serves) more coal is extracted, more royaltiesare paid, and less coal is rendered econom-ically unrecoverable, Strict MER guidelinescould result in larger estimates of LMUreserves, and therefore could affect thediligence and continuous development re-quirements for leases. MER determinationscould also result in more complex miningplans, which would have a concomitant effecton the lessee’s ability to comply with the timelimits on diligent development. The nature ofthe MER concept makes it, in effect, a “con-tinuing performance standard” that may re-quire an operator to continue operating aFederal coal lease at marginal costs beyondthe point where a lessee would cease miningin an unregulated operation.

The full extent of the impact of the conceptof MER on Federal leases is unknown, sinceregulations implementing section 3 of theFCLAA have not yet been promulgated, andscope of its applicability to pre-FCLAA leasesis uncertain.

Timeliness of Readjustment

Pre-FCLAA leases were originally subjectto readjustment of lease terms at 20-year in-tervals. Section 6 of FCLAA reduced the

readjustment period to 10 years. Consequent-ly, when pre-FCLAA leases reach the end oftheir current 20-year term, each will be eligi-ble for an extension of only 10 years. At read-justment, new lease provisions, includingterms incorporating the requirements of the1976 diligence regulations, are made part ofthe lease and the rentals and royalties arechanged to conform to FCLAA. Current DOIpractice is to set the new rental rate at$3 .00/acre and the roya l ty ra te a t thestatutory minimum of 12.5 percent of thesales price per ton for coal mined by surfacemethods, and at a lower discretionary rate of8 percent for coal mined underground. Forproducing leases, the major impact of read-justment is financial—an increase in theroyalty paid from (for example) $0.15/ton toperhaps $1.60/ton (assuming $20.00/tonfor underground coal at eight percent). Forundeveloped leases or leases in pending mineplans, if the diligence requirements are onlyeffective on readjustment, the result wouldbe differing diligence standards for pre-FCLAA leases. If diligence requirements forinitiating production within 10 years aremade effective only on readjustment, somelessees would still have to meet the 1986deadline, while others, conceivably, wouldnot have to produce until after the year 2000.

As a further complication, during the1970’s, many lease readjustments were de-layed because of DOI personnel shortagesand confusion over the applicability of vari-ous regulations due to litigation, legislation,and changes in the coal management pro-gram. At the end of fiscal year 1980, most ofthe backlog had been reduced and readjust-ments were pending for 40 pre-FCLAAleases. 49 A number of completed readjust-ments have been appealed to the DOI Boardof Land Appeals and to the courts. BetweenJanuary 1, 1981, and June 1, 1986, nearly 200pre-FCLAA leases in the six Western Federalcoal States are due for readjustment; another191 of these leases are to be readjusted byJune 1, 1991. At least 39 more pre-FCLAAleases will not be readjusted until after the1991 diligence deadline (see table 78).

—


Table 78.—Readjustment Schedule for Pre-FCLAA Leases in Colorado, Montana,New Mexico, North Dakota, Utah, and Wyoming

Readjustments Readjustmentsbetween between Readjustments

Aug. 4, 1976 and June 1, 1986 and afterState June 1, 1986 June 1, 1991 June 1, 1991

Colorado. . . . . . . . . . . . 59 46 10Montana. , . . . . . . . . . . 9 7 2New Mexico. . . . . . . . . 18 9 1North Dakota. . . . . . . . 7 9 1Utah . . . . . . . . . . . . . . . 105 76 17Wyoming . . . . . . . . . . . 46 44 8

Total 244 191 39

Note Dates of readjustment obtained from Automated Coal Lease Data System. October 1980 The total readjustments do notinclude second readjustments of leases due to be readjusted after FCLAA (Aug. 4, 1976) or first readjustments of newleases issued after FCLAA

Because of these delays, some lessees havechallenged DOI’s r ight to readjust theirleases. The lessees have argued that becauseDOI did not notify them of its intention toreadjust their leases in a timely fashionbefore the expiration of the previous leaseterm, that DOI implicitly waived its oppor-tunity to readjust their leases and that theleases continue for an additional term underthe previous royalties and lease provisions. Insome cases, this position may prevail depend-ing on the specific facts, the anniversary dateand the Department’s actions relating to at-tempted readjustment. DOI has maintainedthat it has the authority to adjust leases evenwhen the lessee was not notified on or beforethe 20-year anniversary date and to adjustleases with anniversary dates occurringbefore the passage of FCLAA to conform tothe minimum royalties required by FCLAA.At least two Federal district courts haveruled against DOI on the issue; both caseshave been appealed.50 In the 1979 rulemakingfor the new coal management program, theregulations governing readjustments weremodified in response to industry comments.The regulations now provide that for leaseswhich are subject to readjustment after June1, 1980, if DOI does not notify the lesseebefore expiration of its present lease term ofits intent to revise the lease, DOI will havewaived its right to readjust the lease for thenext lease term.51

Enforcement

The extent that diligence regulations areenforced will also influence their impact,Before promulgation of the regulations in1976, DOI had not canceled any nonproduc-ing leases. Before 1960 there had been littleneed for enforcing diligent development asmost leases eventually went into production.However, in the 1960’s, as coal productionlagged while leased areage increased, the po-tential for using diligence requirements tostimulate development increased.

Before a pre-FCLAA lease is forfeited fornot meeting diligence, a judgment must be ob-tained against the lessee. To do this, theDepartment of Justice must sue the lessee inFederal court at the request of the Secretaryof the Interior. The decision to request en-forcement action by the Justice Department isdiscretionary with the Interior Secretary,however, the final decision on whether or notto initiate a lawsuit is made by the AttorneyGeneral. It is likely that if DOI adopted an ag-gressive enforcement policy, the cases wouldbe carefully chosen to establish a strongprecedent, thus many weak or questionablecases could be deferred.

Under the Secretary’s general discre-tionary authority to administer leases in thepublic interest, DOI can also waive violationsof the Mineral Leasing Act and regulations

—


either on its own initiative or through negotia-tions with the lessees. Generally, such waiv-ers are not binding on DOI or the Governmentunless they are: 1) express, 2) written, and3) executed by the appropriate official.52

Relinquishments

Some leases can be expected to relinquishtheir nonproducing leases voluntarily if theycannot meet diligence rather than go throughcourt proceedings. Relinquishments must befound to be in the public interest.53

A significant factor affecting productionpotential from existing leases and the leasesthat are unlikely to meet diligence by 1986 issection 3 of the FCLAA that prohibits the is-suance of new leases to lessees that have notproduced commercial quantities from any ex-isting leases they have held for 10 years byAugust 4, 1986.54 This amendment to the Min-eral Leasing Act creates a strong incentive torelinquish nonproducing leases if the lesseewishes to lease addit ional Federal coalreserves.

Potential Production From Federal CoalLeases and Diligence

In chapter 5 of this report, OTA presentedthe results of its comparison of the expectedproduction from existing Federal leases withthe minimum production levels required fordiligence. This analysis, which assumed thatthe diligence requirements are fully appli-cable to existing leases, provides some indica-tion of the situations that might arise.

By 1991, over 70 percent of the 502 leasesin the six major Western Federal coal Statescould meet the existing diligence require-ments.

●

●

●

216 leases with 7.4 bi l l ion tons ofreserves are likely to meet diligence by1986;29 leases with 2.1 billion tons of reservesare likely to meet diligence by 1991 withextensions; and112 leases with 3.4 bi l l ion tons ofreserves are uncertain to meet diligenceby 1991 with major uncertainties tied to

delays in powerplant and transportationsystem construction, fluctuations in cap-tive coal needs, and difficulties in defin-ing the logical mining unit for leases withvery large reserves in multiple seams.

Thirty percent of the Western Federalleases are unlikely to meet diligence by 1991even with extensions:

●

●

●

Production for 61 leases in the Kai-parowits Plateau with 1.4 billion tons ofreserves is dependent on construction ofa coal transportation system.Development of 10 leases in the PowderRiver basin with 1.4 billion tons of re-serves are contingent on commercial-ization of synfuels technologies, such asin situ gasification, that can use lowerquality reserves at the mine site.The remaining 74 leases are primarilysmall, scattered leases with poor qualityreserves and are unlikely to be devel-oped by 1991 even with extensions.

Most leases with potential for productionby 1991 could qualify for extensions underexisting guidelines. The exceptions are small-to medium-sized mines that are intended toserve spot markets and several undergroundmines opening in areas with difficult miningcond i t ions r equ i r ing longer const ruct ionperiods that do not fit clearly into any of thecurrent guidelines.55

The 502 leases are divided into a total of217 mine plans or blocks of contiguous leases;of these, 146 units could be producing by1991 and many of these can be expected torequest a section 5 LMU designation so thataggregate mine production can be used tomeet diligence and with some exceptionsshould qualify as LMUs under current guide-lines.

Exchanges

Exchange can be used to shift coal develop-ment on Federal or non-Federal lands awayfrom areas where mining conflicts with otherresource values or uses to more acceptableareas. Exchanges, thus can offset potentiallosses in coal production from environmental


or land-use restrictions. Because of the re-quirement in section 2 of FCLAA that all newleases be awarded by competitive bidding,DOI has only a limited authority to offerunleased Federal coal in exchange for relin-quishment of exist ing Federal leases orPRLAs in areas where mining poses environ-mental or other problems.

However, under general provisions of theMineral Leasing Act, the Secretary can issuea noncoal mineral lease of comparable value,coal bidding rights, or modifications of up to160 acres each to other coal leases in ex-change for relinquishment of an existing coallease or PRLA.56

Special legislation has been enacted spe-cifically authorizing several proposed “leaseswaps” involving existing Federal leases andPRLAs in Wyoming, Utah, and New Mexicoand contested Indian leases and permits inMontana. Other existing Federal leases couldqualify under the special alluvial valley floorexchange provisions in SMCRA.

Exchanges of Federal coal reserves forprivate coal lands have also been suggested.Under section 206 of FLPMA, DOI has theauthority to exchange interests in Federallands, including mineral rights, for interestsin non-Federal lands of equal value if the ex-change is determined to be in the public in-terest. Section 510(b)(5) of SMCRA directsthe Secretary to establish a program of ex-changes of non-Federal lands that cannot bemined because of alluvial valley floor restric-tions for available Federal coal lands undersection 206 of FLPMA.

According to information from OTA’s Statetask forces, as much as 1.7 billion tons ofFederal coal reserves are involved in variousexchange proposals.57 It is now apparent thatnot all of these exchanges will be completed,however, a significant portion of reservesthat cannot be mined without substantialadverse social or environmental conse-quences could be replaced through the ex-change mechanisms described below.

Special Exchange Legislation

Under special exchange legislation en-acted by Congress, the Secretary of the In-terior has been authorized to approve ex-change relinquishments of certain existingleases and PRLAs and contested Indianleases and permits for new noncompetitiveFederal coal leases. Generally, the Secretarymust find that the exchange is in the publicinterest and that the value of the rights to betraded are approximately equal,

Public Law 95-554—Federal Coal LeasingAmendments Act of 1978

In the 95th Congress, DOI requested legis-lation giving it generic authority to exchangeor condemn leases and PRLAs where miningposes environmental or other problems. In-stead, Congress passed the Federal CoalLeasing Amendments Act of 1978 makingminor amendments to the Mineral LeasingAct and specifically authorizing exchangesfor all or part of nine leases underlying Inter-state 90 and State highways near Gillette innortheastern Wyoming, and for eight PRLAson the Kaiparowits Plateau in southwesternUtah. 58 The 1978 act also requested a feasibil-ity study on the possible acquisition of privatelands surrounding the Lake DeSmet Reser-voir near Buffalo, Wyo., in exchange for Fed-eral coal lands. The rights to be exchangedmust be of approximately equal value, how-ever, a cash settlement of up to 25 percent ofthe difference in value would be allowed.

DOI has completed the exchange studiesunder Public Law 95-554. In September 1979,it recommended against the Lake DeSmet ex-change . 59 In June 1981, the Utah Power &Light exchange was rejected because thePRLAs to be exchanged were determined tobe not of approximately equal value to thenew lease tracts requested. 60 The Wyominghighway exchanges are proceeding and nego-tiations with the lessees are continuing on theleased areas to be relinquished in return forother Federal coal reserves.61


New Mexico Lease Exchange

Public Law 96-475 62 directs the Secretaryof the Interior to issue leases for coal on otherFederal land in exchange for all or portions oftwo Federal leases in the Bisti area of NewMexico. The exchange is to be completedwithin 30 months, i.e., by April 1983, or as ex-peditiously as possible. The Bisti lease areacovers about 1,360 acres of the Bisti wilder-ness study area, as well as other areas withunusual paleontological, archaeological andrecreational values. 63 The legislation spe-cifically describes the unleased Federal coallands that are to be offered in the exchange.

The exchange is to be made pursuant to theexisting land use policies and leasing pro-cedures established by the Secretary. Theleases issued must contain the same termsand conditions as leases surrendered. Thetwo leases are due to be readjusted beforethe exchange date and would thus be subjectto post-FCLAA requirements.

The exchange involves two leases in theplanned Bisti Mine. The lessee, Western CoalCo. had sought the exchange and agreed todefer exploration and mine construction ac-tivities in the areas pending administrativeand legislative action. Processing of the ex-change is not expected to delay developmenton the other Federal leases in the mine area.

Northern Cheyenne Indian ReservationLease Exchange

Public Law 96-401 authorizes the Secre-tary of the Interior to negotiate for thecancellation of seven leases and 11 prospect-ing permits on Indian lands on the NorthernCheyenne Reservation in Montana.64 T h etribe has been contesting the BIA’s issuanceof these coal development rights coveringover half of the tribal reservation. Develop-ment of the leases and permits was sus-pended by the Secretary of the Interior inresponse to the tribe’s petition. The act wouldallow the Secretary to negotiate with thelessees and permit holders for cancellation oftheir rights in exchange for bypass leases onFederal coal adjacent to their active mines

and for Federal coal bidding rights equal tothe amounts that they have invested in the In-dian coal rights. The act does not provide fora ton-for-ton or acre-for-acre exchange ofFederal coal lands for the disputed tribal coallands, but rather establishes a framework forthe parties to negotiate a settlement and forthe coal companies to recover their out-of-pocket expenses. The settlement authority inthe act does not affect any legal rights thatthe parties may have. If they are unable toreach an agreement, the issues could still belitigated. 65

Alluvial Valley Floor Exchanges

Section 510(b)(5) of the Surface MiningControl and Reclamation Act of 1977 requiresthat reserves on certain nonproducing Fed-eral leases and private lands in alluvial valleyfloors with agricultural potential that cannotbe mined, can be exchanged for Federal coalif the lessee made substantial legal or finan-cial commitments to developing a mine beforeJanuary, 1, 1977.66 It is not yet known howmuch, if any, coal in alluvial valley floors willbe exchanged under this provision intendedto compensate mine owners and lessees whodo not qualify for permit approval under thegrandfather provisions of section 510(b)(5). Ingeneral, relatively small amounts of Federallease reserves are likely to be affected by theprohibition on mining agriculturally impor-tant alluvial valley floors and the Federalreserves that would be eligible for exchangewould be even smaller. (See the discussion ofalluvial valley floors in ch. 10 of this report.)

Section 510(b)(5) also directs the Secretaryto establish an exchange program under sec-tion 206 of FLPMA to trade title to availableFederal coal lands for title to private landsthat cannot be mined because of alluvialvalley floors. This exchange of private landsfor Federal reserves is mandatory and notsubject to the requirement of previous sub-stantial legal and financial investment. 6 7

There are a number of mines in the PowderRiver basin, with substantial reserves of non-Federal coal under alluvial valley floors thatmight qualify for these mandatory exchanges.


If significant amounts of reserves from thesemines qualify, the net result could be a de-crease in available unleased Federal re-serves because of the transfers of Federalcoal to non-Federal ownership in exchangefor unminable non-Federal reserves in allu-vial valley floors.

Other Exchanges

Under section 206 of FLPMA, DOI can ex-change interests in Federal lands, includingmineral rights, for interests in non-Federallands of equal value if the public interest iswell served by the exchange.68 Cash settle-ment of up to 25 percent of the difference invalue of the tracts exchanged is authorized.The alluvial valley floor coal exchanges are tobe evaluated under this provision. Several ex-changes of non-Federal coal lands for Federalcoal lands have been suggested to preserveimportant wildlife habitat from mining, or toallow “blocking up” of checkerboard lands orother areas of dispersed mineral ownershipso that both the Federal Government and theprivate owner receive title to contiguousLMUs as a result.69 Exchanges of lands foundunsuitable for mining under SMCRA have

also been suggested; however, exchange ofany Federal lease areas could only be accom-plished by specific legislation.

DOI’s limited experience with trying to im-plement the authorized exchanges discussedearlier has revealed technical and adminis-trative difficulties involved in working out anexchange agreement acceptable to both par-ties. The difficulties in determining an ap-propriate value for the rights to be exchangedhave been particularly troublesome in Utahand Wyoming where the reserves to be relin-quished are of lower present economic valuethan the reserves sought in exchange. Evenso, other leaseholders with reserves that can-not be mined can be expected to press for ex-changes through administrative, legislativeand judicial channels. Although all the coalreserves under existing leases may not bemined, the eventual result of exchanges couldbe little net change in the total amount of Fed-eral coal reserves developed. The location ofmining may change compared to present pat-terns of Federal lease ownership, but theamount of Federal reserves committed bypast leasing practices could remain essential-ly the same.

Preference Right Lease Applications

Under section 2(b) of the 1920 MineralLands Leasing Act, prospecting permits couldbe issued for areas where commercial de-posits of coal were unknown. The purpose ofthis provision, similar to prospecting permitprovisions for other leasable minerals and tothe location patent system under the mininglaw, was to encourage the exploration anddevelopment of mineral resources on publiclands. 70 A successful prospector, upon show-ing discovery of a valuable deposit during theterm of the permit, was entitled to a non-competitive preference right lease. Abouthalf of the existing Federal coal leases wereissued through the preference right leasemechanism .7’ Section 4 of the FCLAA re-pealed the authority to issue preference right

leases except for PRLAs and prospecting per-mits pending on the date of its enactment.72

Potential Production From PRLAs

As of March 1981, there were 171 activelypending PRLAs covering over 395,000 acresand containing over 5,7 billion tons of recov-erable reserves. OTA estimates that thepotential production from these PRLAs is be-tween 35 million and 60 million tons per yeardepending on how the various legal and envi-ronmental problems affecting certain PRLAsare resolved.73 About 10 million tons of thisannual production is associated with newmines on existing Federal leases in Coloradoand New Mexico. This estimate is lower than


the earlier DOI estimates of 186 million to 248million tons per year used in development ofthe new coal management program and re-flects: 1) a reduction in DOI’s estimates of in-place reserves; and 2) OTA’s analysis of theproduction potential of PRLAs in Wyoming,Colorado, and New Mexico. Even the lowerproduction estimates for PRLAs indicate asignificant potential for contributing to coalsupply in 1990-95.74

The potential impact of the various legal,planning, and environmental restrictions onPRLA issuance and hence production wasprobably overestimated in the DOI review.OTA’s examination of the data used inpreparation of the working paper disclosedthat most of the environmental restrictionswere related to wildlife concerns and wouldprobably result in special lease stipulationson impact mitigation rather than in deletionof reserves from the PRLA. The legal prob-lems include some, such as incomplete appli-cations, that are curable during the adjudica-tion process under regulations allowing theapplicant an opportunity to submit additionaldata.75 Other legal problems such as failure tosubmit any information about the quantityand quality of reserves discovered probablywould result in rejection, however, only a fewapplications did not contain this information,so the probable impact is small.76

The true potential production from PRLAswill not be known until after the pending ap-plications have been processed and thosethat meet the legal requirements have beenissued. With few exceptions, processing ofthe pending PRLAs was suspended duringmost of the past decade: first, because of the1971 moratorium; then, to allow for develop-ment of new leasing policies; and, finally, bylitigation. 77 Following promulgation of finalregulations for the new coal managementprogram in July 1979, processing of pendingPRLAs was resumed. Under current policy,all PRLAs should be adjudicated and leasesissued to qualified applicants by 1984.

Many of the legal, administrative, and pro-cedural issues related to the issuance or re-jections of PRLAs have been addressed by

DOI and the courts, however, a number ofnew questions are likely to arise as the ap-plications are processed and these must beresolved before the full production fromPRLAs will be realized.

Procedures for Processing PRLAs

Before its repeal in the 1976 amendments,section 2(b) of the Mineral Leasing Act of1920 provided:

Where prospecting or exploratory work isnecessary to determine the existence orworkability of coal deposits in any un-claimed, undeveloped area, the Secretary ofthe Interior may issue, to applicants qual-ified under this chapter, prospecting permitsfor a term of two years, for not exceedingfive thousand one hundred and twenty acres;and if within said period of two years there-after the permittee shows to the Secretarythat the lands contain coal in commercialquantities, the permittee shall be entitled toa lease under this chapter for all or part ofthe land in his permit.

A prospecting permit could be extended for. -2 years; however, the approval of extensionswas discretionary. In practice, they appear tohave been granted routinely at the request ofthe permittee. In order to qualify for a pref-erence right lease, the prospector had to sub-mit an application accompanied by evidenceshowing the discovery of commercial quanti-ties of coal within the permit area before theexpiration date of the permit. The 1976repeal was subject to valid existing rights,thus any pending permits or applications forpreference right leases were not affected andcould be pursued under pre-FCLAA require-ments. Any leases issued would, however, begoverned by new lease terms imposed byFCLAA.

As a result of an internal review of DOIprocedures and criteria for issuing prospect-ing permits and approving PRLAs, new reg-ulations were issued in May 1976 governingall pending and future PRLAs. 78 The reg-ulations formally defined the standards fordetermining “commercial quantities” underthe Mineral Leasing Act, specified the in-


formation to be submitted, and established atwo-phase adjudication procedure, The inter-nal review had disclosed that, in some in-stances, the less stringent “workability”standard had been used mistakenly to deter-mine whether a PRLA should be issued ratherthan the stricter “prudent person” test.79 T h eregulations formally adopted the “prudentperson” standard applied under the MiningLaw as the appropriate test for determiningdiscovery of commercial quantities of coalunder the Mineral Leasing Act.

The commercial quantities standard re-quires that “the coal deposit discovered. . . shall be of such character and quantitythat a prudent person would be justified infurther expedition of his labor and meanswith a reasonable prospect of success in de-veloping a valuable mine. ” The applicantmust present “sufficient evidence to showthat there is a reasonable expectation that rev-enues from the sale of the coal shall exceedthe cost of developing the mine and extract-ing, removing, transporting, and marketingthe coal. ” Mining costs include expenses forenvironmental protection, reclamation, andcompliance with applicable State and Fed-eral laws and regulations.80

Under the new adjudication procedure, theapplication was to be accompanied by an“initial showing” with reserves estimatesand supporting geologic data, maps, and adescription of the proposed mining operation.Holders of pending PRLAs were notified tosupplement their applications with the re-quired initial showing. (Table 79 shows theadjudication steps in processing PRLAs.) Theapplication and initial showing are firstexamined for completeness and compliancewith other Mineral Leasing Act require-ments. Incomplete or insufficient applicationscan be rejected at this stage, however inmany instances, the applicant will be givenan opportunity to supplement or correct themissing data. If the PRLA is rejected then orlater in the process, the decision can be ap-pealed administratively to the Interior Boardof Land Appeals.81

The ini t ial showing is fol lowed by atechnical examination and environmentalassessment from which proposed lease termsand stipulations are formulated. This reviewwill normally be conducted during the ongo-ing BLM land use planning cycle establishedby each State BLM Office, unless the lesseerequests an accelerated review. The environ-mental assessment includes a site-specificanalysis to evaluate the suitability of the areafor mining and to develop appropriate leasestipulations, consultation with State govern-ment, and preparation of either an environ-mental assessment (EA) document or an EISas required under NEPA. The Geological Sur-vey reviews the adequacy of the initial show-ing and recommends lease terms and condi-tions and bonding, MER, and minimum pro-duction requirements for diligence.

The applicant is then provided with theproposed lease terms and stipulations (in-cluding rentals and royalties), the EA or EIS,and other relevant information and allowed90 days to submit a “final showing” of com-mercial quantities. The final showing must in-clude the applicant’s estimated production,estimated revenues, and mining and reclama-tion costs. The estimates must have a reason-able factual basis and reflect all costs that aprudent person would consider before decid-ing to develop a mine. It must demonstratethat the deposit can be profitably mined andmarketed under the proposed lease terms andapplicable State and Federal laws. If all therequirements of the final showing are satis-factorily met, the applicant is entitled to alease.

Litigation Involving PRLAs

NRDC v. Berklund

In March 1975, the Natural Resources De-fense Council and the Environmental DefenseFund sued DOI seeking: 1) a declaratory judg-ment that the Secretary had the discretionaryauthority to refuse to issue a PRLA on envi-ronmental grounds under the Mineral Leas-ing Act of 1920 and National EnvironmentalPolicy Act of 1969, and that an environmental


Table 79.—Processing Preference Right Lease Applications

Review of application and initial showing1. Review completeness and adequacy of

application.

2. Review completeness of initial showing.

3. Determine whether PRLA conflicts with validmining claims.

4. Request additional information needed forinitial showing and mining claims reviews.

5. Determine adequacy of initial showing.

Technical review and environmental assessment1. Establish priority for review of PRLA in land

use planning process.

2. Conduct environmental analysis includingunsuitability criteria.

3. Review adequacy of EA or EIS; consult withGovernor, Surface Management Agency, otheragencies, and public. Issue final EAIEIS.

4. Set proposed lease terms, conditions, rental,royalties, bonding, MER, and minimumproduction requirements.

5. Request applicant to submit “final showing”of commercial quantities.

Review of final showing1. Determine completeness of final showing.

2. Determine whether applicant meetscommercial 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 MultipleMineral Development Act (1954) and the date prospecting permit wasissued. (Claims must be filed with BLM as required by FLPMA to bepresumed valid); notify applicant of conflict and of procedures forcontesting 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 commercialdevelopment.

Accept initial showing if all requirements are met; refer application fortechnical review and environmental assessment.

Schedule accelerated review on applicant request.

Prepare environmental assessment (EA) or draft environmental impactstatement (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. Requestadditional information needed for final showing.

Has applicant demonstrated discovery of a coal deposit of suchcharacter 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 prospectof success in developing a valuable mine with a reasonableexpectation that the revenues from the sale of the coal will exceedthe costs of developing the mine and extracting, removing,transporting, and marketing the coal? (NOTE: Applicant may deleteareas that are recommended as unsuitable for mining from applicationbefore final showing to exclude costs of mining these areas.)

Accept PRLA and issue lease if applicant meets all requirements andcommercial quantities test.Reject PRLA if applicant does not meet commercial quantities test onfinal showing.Negotiate with applicant for exchange of PRLAs that meetcommercial quantities test but pose environmental or other problemsif developed.

SOURCE. Bureau of Land Management, Instruction Memorandum 79-846 (revised), Solicitor’s Opinion M-36893, as revised, Jan. 8, 1981.


impact statement must be prepared before is-suance of any PRLA that involved a “majorFederal action significantly affecting the en-vironment;" and Z) an injunction barring theissuance of any such leases without comply-ing with the declaratory judgment provisionssought.

In June 1978, the District Court of theDistrict of Columbia held: 1) that the Sec-retary has no discretion to reject a PRLA ifthe applicant successfully meets the commer-cial quantities test and other requirements ofthe Mineral Leasing Act; and 2) that NEPA re-quires the preparation of an EIS before the is-suance of any lease where such action is “amajor Federal action significantly affectingthe environment.”82

In reaching its decision the court furthernoted that NEPA requires the Secretary to“exercise his authority to safeguard societyand prevent irreparable damage to the envi-ronment through a careful and complete for-mulation of lease terms.” 83 The court ob-served that the Secretary has broad powersto establish strict standards for proposedlease terms that could make compliance withthe commercial quantities test difficult or im-possible (i.e., the cost of implementing theseterms would make the mining costs exceedthe market value of the coal). Thus, while DOIcannot deny a PRLA solely for failure to meetenvironmental requirements, the court statedthat “if a permittee does not have the tech-nological capability to comply with (strict en-vironmental) standards, the high cost of com-pliance will outweigh potential coal revenuesand he will fail the commercial quantitiestest, ”84

In preparing an EIS prior to the issuance ofa PRLA, the Berklund court ruled that theSecretary must consider at least three alter-natives: 1 ) exchange of the PRLA for a min-eral lease of comparable value or coal bid-ding rights; 85 2) issuance of the lease withlease terms to protect against irreparabledamage to the environment as required byNEPA, which will determine whether the per-mittee will meet the commercial quantitiestest, which in turn will determine whether the

lease will be issued; and 3) if the applicantwill not agree to an exchange and the leaseterms do not defeat the commercial quantitiesshowing, withdrawing the lands or askingCongress for legislation canceling the leaseon payment of just compensation.86

By clear implication, the decision upheldthe application of the 1976 commercial quan-tities regulations. The decision was affirmedby the U.S. Court of Appeals in November,1979. 87

Utah International Inc. v. Andrus (Utah)88

Utah International, Inc., sued DOI seekinga judgment that the May 1976 PRLA adjudi-cation procedures and commercial quantitiesregulat ions could not be applied to i tssouthern Utah PRLA which was filed beforethey were effective and also seeking to havecourt rule that any lease issued from its PRLAwould have lease terms in effect on date ofapplication rather than post-FCLAA require-ments. The Utah Federal district court heldthat the 1976 regulations were proper andcould be made applicable to pending PRLAs;and that an applicant does not acquire avested right to a lease or to have its applica-tion judged under a particular standard sim-ply by filing an application. The court furtherruled that an applicant could not sue over theapplication of the commercial quantities testto its PRLA until after DOI had made a finaldecision approving or rejecting the applica-tion and the applicant had all exhausted ad-ministrative appeals in DOI.

Utah International Inc. v. Andrus(Colorado) 89

Utah International, Inc., also sued DOIover processing of a PRLA in Colorado—thistime with more success. The Colorado Fed-eral district court decision cited the result inthe Utah case with approval, noting that it iswithin the authority of the Secretary to act tocorrect errors in the administration of pro-grams committed to his discretion, thus it wasproper to issue new regulations for process-ing PRLAs and to establish a corrected com-mercial quantities test fully applicable to


pending applications, The Colorado courtthen distinguished the PRLA in the casebefore it from other PRLAs by finding thatDOI had made a final and binding determina-tion of discovery of commercial quantities onthe PRLA in 1970 before the effective date ofthe new regulations. Having made a finaldecision, DOI could not subsequently reopenthe case to apply its later requirements. DOIwas ordered to process the application. Thecourt further held that the applicant, Utah In-ternational, was not entitled to the leaseterms in effect when its application was ap-proved, but rather the Secretary had fulldiscretion to set the terms and conditions ofthe lease. The case was appealed by both DOIand the plaintiff, Utah International. Its valueas precedent for other PRLAs is limited sincethe decision was based on the specific cir-cumstances of the case.

Other Legal and Administrative IssuesRelated to PRLAs

Unclaimed Land

Under the 1920 Act, prospecting permitsand preference right leases could be issuedonly on “unclaimed, undeveloped” lands. A1977 Solicitor’s Opinion (Solicitor’s OpinionNo. M-36893), interpreting the meaning of“claimed” as any land on which a valid min-ing claim had been filed under the MiningLaw of 1872 and was present at the time theprospecting permit was issued, raised theprospect that many pending PRLAs would beinvalid in those areas in which they over-lapped mining claims.

In response to the Opinion, in August 1977,PRLA holders were asked to submit a “cer-tified abstract of title” within 160 days listingprevious mining claims affecting land withintheir PRLAs.90 A review of the submitted ab-stracts revealed that lands encompassed by20 PRLAs were covered in part or in whole bya total of 465 mining claims that had beenissued prior to the coal prospecting permits.Most of these PRLAs are in Wyoming, where14 out of 72 applications, covering 25,586acres include one or more mining claims.

One application had 239 mining claims. Mostof these claims are for uranium minerals.

On November 19, 1979, the Solicitor issueda Supplemental Opinion on the effect of theAugust 1977 Opinion on the processing ofpending PRLAs. The Supplemental Opinionconcluded that prospecting permits previ-ously issued in “claimed” or “developed”areas are void and clarified the meaning ofthe terms “unclaimed” and “undeveloped”under the Mineral Leasing Act. The term “un-claimed” refers to the absence of valid min-ing claims. The term “undeveloped” meansthe lack of surface mineral activities asso-ciated with the delineation of an ore body ormineral resource which could reasonably beexpected to disclose knowledge of an area’scoal or phosphate potential. The Supplemen-tal Opinion also noted that holders of PRLAs“have an opportunity through private con-tests, submission of evidence of an area’sstatus, or by rebutting a show cause order, toshow that the lands under application were‘unclaimed, undeveloped’ at the time of pros-pecting permit issuance."91

Review of the Solicitor’s Opinion on un-claimed areas resulted in a third opinionissued January 8, 1981. This third opinionconcluded that only claims filed before enact-ment of the Multiple Mineral DevelopmentAct of 1954 could adversely affect PRLAs,The opinion further concluded that it is suffi-cient to only check BLM land office recordsfor evidence of mining claims thus allowingDOI to dispense with the requirement for cer-tified abstracts.

The results of this third Solicitor’s Opinionon the “unclaimed, undeveloped” issue couldmake processing of PRLAs simpler and couldresult in some PRLAs being approved al-though they might contain conflicting miningclaims for other minerals. The Multiple Min-eral Development Act of 1954 provides thatmining claims located after the date of itspassage do not carry with them the right toleasable minerals, including coal.92 Thus, lo-cation of a mining claim after that date doesnot create a claim that is adverse to the rightsof a coal lessee and, in fact, the Government


may lease the coal, phosphate, oil, and gas,and other leasable minerals on these lands.The PRLA records examined by OTA do notindicate when the mining claims that poten-tially conflict with the PRLAs were filed.However, it is likely that many of the uraniumclaims were located after the passage of the1954 Act and thus could not result in a con-flict with any coal prospecting permits.

The elimination of the requirement for sub-mission of certified abstracts makes use ofprovisions of the Federal Land Policy andManagement Act of 1976. Section 314 ofFLPMA requires that holders of unpatentedmining claims file information on the locationof their claim and an affidavit of assessmentwork performed with the BLM by October 21,1979, and annually thereafter. 93 Failure tofile this information is deemed conclusively toconstitute abandonment of the claim. Beforethis provision was enacted, there often wasno feasible procedure available to BLM or theprospector to determine the presence of min-ing claims on lands covered by applicationsfor prospecting permits.

If the third Solicitor’s Opinion is imple-mented, the portions of a PRLA covered byvalid prior claims will be deleted from leaseconsideration. This would reduce the leaseacreage of some PRLAs and perhaps com-pletely disqualify others. In Wyoming, PRLAswith mining claims contain over 600 milliontons of reserves, and 15.5 million tons out of20,5 million tons potential production capac-ity from PRLAs could be affected by theseclaims. Whether issuance of a preferenceright lease is affected by the presence of min-ing claims depends on: 1 ) how much of thePRLA is covered by claims; 2) whether theclaims were filed before 1954; 3) whether theclaims have been kept valid through the re-quired work requirements at least up to thetime the prospecting permit was issued; and4) whether the mining claim holder has madethe required filing with BLM.

Existence and Workability of Coal Deposits

Preference right leases were awarded onlyfor those lands where commercially valuable

coal deposits were not known to occur. Pros-pecting permits were issued under the Min-eral Leasing Act of 1920 where prospectingor exploratory work was necessary to deter-mine the existence or “workability” of coaldeposits. If the permittee could show thatland contained in coal in “commercial quan-tities, ” the permittee was entitled to a pref-erence right lease for the vacant, unappro-priated lands described in the prospectingpermit.

The concept of workability for coal pref-erence right leases is similar to the “valuabledeposit test” that applies to other mineralsand is the same as the commercial quantitiestest in the current coal regulations.{” Toqualify, the land must be found to contain“coal of such quantity and quality as wouldwarrant a prudent coal miner or operator inthe expenditure and labor incident to theopening and operation of a coal mine or mineson a commercial basis.”95 In other words, “apermittee must have found a deposit uponwhich a prudent man would expend his laborand means (a workable deposit) and that tomeet this test, commercial quantities of coalmust be found. ”

In deciding whether a prospecting permitcould be issued, USGS also used a classifica-tion standard of workability that assumedthat the coal deposits were marketable andwhich focused on whether the known phys-ical characteristics of the coal deposits in-dicated that the value of the coal was greaterthan the costs of extraction. This less strin-gent classification standard of workabilitywas for some years mistakenly used to deter-mine whether a permittee was entitled to alease. 96 This misunderstanding was correctedby DOI in the 1976 commercial quantities reg-ulations. This confusion over the correct ap-plication of the workability test raised ques-tions about whether some lands had correctlybeen open to prospecting.

Some environmental groups have arguedthat some prospecting permits in Wyomingwere issued on lands with abandoned under-ground mine workings or surface coal out-crops and that such lands should have been


classified as areas with known coal deposits.Issuance of prospecting permits in such areaswould violate the statutory requirement thatknown deposits must be leased competi-tively. 97 However, in 1979 in rulemaking forthe new coal management program, DOI re-jected a proposal to reexamine PRLAs for er-rors in determining the presence of knowndeposits. 1)01 “will continue to give thesedeterminations a presumption of administra-tive regularity;” however, “if a case file doesnot contain the required conclusion by USGSthat a prospecting permit could be issuedthen the presumption of administrative regu-larity does not apply,” and DOI “will examinein such a case whether the permit was prop-erly granted.”98

Unsuitability for Mining

Pre-FCLAA leases can be affectedways by current requirements anddures relating to the environmental

in twoproce-unsuit-

ability of lands for coal mining: 1) undersections 510 and 516 of the Surface MiningControl and Reclamation Act of 1977, per-formance criteria for mining must be consid-ered before a mine plan is approved, and ifthe impacts cannot be mitigated the plan maybe rejected; 2) mining on a pre-FCLAA leasemay be foreclosed if it is within an area thatis designated unsuitable for mining as aresult of the petition process established insection 522(a) of SMCRA.99

BLM land use plans and coal lease tractselection include the consideration of suit-ability criteria for the medium and highpotential coal lands in each BLM districtplanning area. Lands that are not unsuitableare considered further in the land use plan-ning and coal leasing process. Suitabilitycriteria are also applied by OSM to each non-producing pre-FCLAA lease when a miningand reclamation plan is submitted. Beforepermit approval OSM consults BLM for spe-cial stipulations or recommendations on thesuitability of leased areas for the proposedmining operation. The impact on pre-FCLAAleases has been relatively small, although thestatus of several hundred million tons of re-

serves in the Powder River basin potentiallycould be affected by alluvial valley floorrestrictions (see ch. 10 for further discus-sion). Overall, the impacts of unsuitabilitycriteria and the designation of lands un-suitable for mining are not are not expectedto impair the ability of existing Federal leasesto meet the possible range of demand forWestern coal in the next 10 to 15 years.

Federal lands unsuitability criteria havetwo major sources: First, an order issued byPresident Carter in May 1977 directing theSecretary of the Interior to lease coal only inareas “where mining is environmentally ac-ceptable and compatible with other landuses” and to review existing leases for com-patibility with these standards, and to takethe necessary steps under existing law todeal with nonproducing, environmentally un-satisfactory leases and applications.

Second, the Surface Mining Control andReclamation Act of 1977 (SMCRA) requiresthe Secretary of the Interior to review allFederal lands to identify any areas unsuit-able for surface coal mining operations.Standards of unsuitability in section 522 ofSMCRA focus on environmentally sensitiveareas or areas which are classified for otheruses, such as national parks or wildernessareas. Other Federal statutes impose addi-tional responsibility on the Federal Govern-ment to protect endangered species, historicand culturally significant sites, etc.; thesewere also included in the suitability criteria.The unsuitability review includes a processfor public participation that considers mat-ters of local or State significance and a pro-cedure for private surface owners to withholdconsent for new Federal coal leases.

Under the July 1979 coal management reg-ulations, unsuitability criteria for new coalleases are applied during the land use plan-ning process in order to identify those areasrequiring special stipulations to provide nec-essary protection from adverse impacts ofmining. These criteria apply to all surfaceminable areas and also to underground minesif mining would unduly disturb the surface,cause subsidence or interfere with surface


occupancy. Exceptions to these criteria arepermitted to protect valid existing rights orsubstantial legal and financial commitmentsmade by operators before enactment ofSMCRA. In some instances, the criteria ex-tend to buffer zones around protected areas,such as those listed in the National Registerof Historic Places, endangered species habi-tats and lands with National Resource Wa-ters on site. Section 522 criteria also apply tomine plans; if sufficient data are not avail-able to determine the minability at the time ofleasing, the issue will be resolved at the mineplan approval stage.

Designation of Lands Unsuitable for Min-ing: Section 522(a) of SMCRA establishes aprocedure for petitions to designate lands un-suitable for mining. An unsuitability designa-tion is mandatory if required reclamation isnot technically or economically feasible.SMRCA also provides for Federal or Stateagencies to designate land unsuitable for min-ing as a matter of discretion based on a re-view of the petition if:

1. mining is incompatible with existingState or local land use plans;

2. mining could result in significant dam-age to important historic, cultural, scien-tific and esthetic values and naturalsystems on fragile or historic lands;

3. mining of renewable resource landsresults in substantial loss or reduction oflong-range productivity of food or fiberproducts and water supply; and

4. mining of natural hazard lands (such asareas subject to frequent flooding andareas of unstable geology) could substan-tially endanger life and property.100

The petition process forces considerationof the cumulative environmental impacts ofsurface mining that may be overlooked or in-adequately analyzed in the application of un-suitability criteria during individual mineplan review. It also allows examination of en-vironmental issues that are not specificallyaddressed in requirements for mine plan re-view, such as the impacts of mining on na-tional parks.

By June 1981, two petitions had been filedin the West to designate lands unsuitable formining; one in the Alton area of southwesternUtah and the other in the Tongue River Valleyof southeastern Montana.

The Alton Petition

On November 28, 1979, the EnvironmentalDefense Fund, Friends of the Earth, SierraClub, and seven residents of the Alton area insouthwestern Utah petitioned the Secretaryof the Interior to designate certain Federallands near Bryce Canyon National Park andDixie National Forest as unsuitable for sur-face coal mining, Approximately 325,200acres, or slightly more than 500 square miles,were affected, including 29 Federal leasescovering over 26,000 acres containing about290 million tons of surface minable coal re-serves, 100 million tons of recoverable un-derground reserves, and two PRLAs covering2,398 acres. The major allegations in the peti-tion dealt with the technological and econom-ic feasibility of reclamation, potential damageto surface and ground water systems and po-tential damage to the unique values of thepark and national forest.

The final EIS on the petition, issued byOSM in November 1980, did not support theclaims that: 1) the Alton land could not bereclaimed; 2) blasting from mining woulddamage geologic formations; 3) wildlife wouldbe threatened; and 4) mining would cause ir-reparable damage to water supplies. It didnote that these issues would be reexaminedas part of the permit approval process andthat appropriate stipulations could be re-quired should additional information revealany such adverse problems. The EIS did findthat mining in part of the area would impairscenic vistas from Bryce Canyon NationalPark and that high noise levels would occur insome areas within the park. In December1980, the Secretary of the Interior declared9,049 acres containing approximately 24 mil-lion tons of coal near Yovimpa Point in BryceCanyon National Park as unsuitable for min-ing because of the adverse impacts on the


park. The decision stated that mining activ-ities would significantly reduce visibility andscenic vistas from the park overlooks andwould raise noise levels thus damaging thevalues for which the park was establishedand diminishing the experiences of the parkvisitors. In support of his decision, SecretaryAndrus also cited his responsibility as thesteward of the national parks “to conserve thescenery and the natural and historic objectsand the wildlife therein and to provide for theenjoyment of the same in such manner and bysuch means as will leave them unimpaired forthe enjoyment of future generations."101

The decision left the two main leaseholdersin the petition area, Utah International andNevada Electric Investment Co. approximate-ly 16,700 acres under lease containing 266million tons of coal to supply the proposedAllen-Warner Valley Energy System or otherprojects.

Utah International challenged the decisionin Federal court alleging that its leasesshould be exempt from unsuitability designa-tion because of substantial legal and finan-cial commitments undertaken by the lesseesbefore SMCRA was enacted. The petitioners,the Environmental Defense Fund (EDF), alsoappealed the decision, alleging that the Sec-retary failed to consider adequately the ef-fects mining would have on the national parkand on the regional water supply. If EDF’ssuit results in expanding the area unsuitablefor mining, there could be a significant im-pact on coal production from the area. Up tonow, however, the potential for coal produc-tion from the leases in the area has not beensignificantly impaired even though 12 of the29 leases in the area are affected, in whole or

in part, by the Secretary’s decision. The im-pact of the decision is probably limited to itsunique circumstances since few, if any, otherexisting leases border on national parks. 102

The Tongue River Petition

In November 1980, the Northern PlainsResource Council and three of its affiliates,the Tri-County Ranchers Association, theRosebud Protect ive Associat ion and theTongue River Agricultural Protective Asso-ciation filed a petition with the MontanaDepartment of State Land and OSM to desig-nate approximately 100 thousand acres of in-termingled Federal, private, and State landsin the Tongue River Valley in southeasternMontana unsuitable for surface mining. Themajor allegations in the petition are that thintopsoils and indigenous sal ts make rec-lamation technologically and economicallyunfeasible, and that s tr ip mining coulddamage water supplies and the long-termproductivity of farmlands. The area in thepetition includes an estimated 10 billion tonsof strippable coal and includes the proposednon-Federal Montco Mine that has a pro-jected production capacity of 12 million tonsper year by 1990. Substantial amounts ofFederal coal are located in the area, butthere is no currently leased Federal coal inthe area, so the petition will not have anysignificant impact on the development of ex-isting Federal leases in Montana. The petitionwas found to be complete and the allegationsare now under review by the State of Mon-tana and DOI,103 Final decision on non-Feder-al lands rests with the State; the decision ofFederal lands suitability will be made by DOI.A decision on the petition will be made by De-cember 29, 1981.


Footnotes for Chapter 9

1For a description of the public land disposal laws and theorigin of split ownership problems in the West, see Manage-ment of Fuel and Nonfuel Minerals in Federal Lands, Office ofTechnology Assessment (OTA-M-88), April 1979, p. 86,

230 U.S.C. 1304, SMCRA narrowly defines the surface own-ers to which the consent requirement applies. A ‘‘qualified sur-face owner” is a natural person (or a corporation controlled bya natural person) who: 1) owns legal or equitable title to theland surface, and 2) either lives on the land or personally farmsthe land or derives a substantial portion of his income fromsuch farming or ranching operation, and 3) has met the pre-vious conditions for 3 years before granting consent.

3See discussion of Coal Lands Act in Management of Fueland 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 1970than there was in 1960. See chs. 3 and 13 of this report for his-tory 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 IndianCoal Leasing in the West [New York: Council on Economic Pri-orities, 1974), and U.S. General Accounting Office, Improve-ments Needed in Administration of Federal Coal Leasing Pro-gram, 1972.

8Federal Coal Leasing Amendments Act of 1976, Public Law94-377, 90 Stat. 1083, Aug. 4, 1976. In 1976, the House of Rep-resentatives approved S. 39 I by a vote of 344-51, and theSenate accepted the House amendments by unanimous vote.President Ford vetoed the bill on July 3, 1976. [Weekly Compila-tion of Presidential Documents, vol. 12, July 3, 1976. ) The Cong-ress overrode the President’s veto. The Senate vote was 76-17,122 Cong. Rec. 25198, at 25465 (Aug. 3, 1976); the House ofRepresentatives was 315-86, 122 Cong. Rec. H831O-H832O(Aug. 4, 1976).

9The Draft Environmental Impact Statement on the ProposedFederal Coal Leasing Program issued by DOI in 1974 proposedan “Energy Minerals Allocation Recommendation System” inwhich leasing would be based on a Federal coal allocationmodel. The Final Environmental Statement on the ProposedFederal Coal Leasing Program issued in 1975 described a dif-ferent system, the “Energy Minerals Activity RecommendationSystem, ” described above. Since both systems have the sameacronym, they have sometimes been referred to as “EMARS I“and "EMARS II. ”

10NRDC v. Hughes, 437 F. Supp, 981 (D.D.C. 1977]; ordermodified, 454 F. Supp. 149, 1978,

11See 437 F. Supp. 981,993.12Specifically the settlement authorized leasing in four cir-

cumstances: “bypass,” i.e., leases in which Federal coal mightotherwise be lost if not developed by an existing mine; hardship(involving seven named lease applications); employment (leasesissued to maintain production and employment in mines exist-ing on Sept. 29, 1977); and leases for certain experimental DOEprojects (i.e., projects authorized under sec. 908 of SMCRA 30,USC 1328 to conduct and promote research, experiments anddemonstration projects relating to alternative coal mining tech-nologies). Exchanges of Federal leases in alluvial valley floorsunder sec. 510(b)(5) (30 U.S. C. 1260(b)(5]) of SMCRA were alsoallowed. The Order expired before the PRLAs were processedand adjudication of these applications is being conductedunder 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 CoalManagement Program was issued for review in December1978; 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 needsfor both renewable and nonrenewable resources, land produc-tivity, environmental values, and economic return (43 U.S,C,1702(c)). “Sustained yield”’ means the achievement and main-tenance of high output of public lands natural resources con-sistent 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 con-tinued operation are traditional in mineral leases and undercommon law the meaning of diligent development evolved withslightly different meanings for different minerals. Much of thecommon law which defined diligent development resulted fromoil and gas leases in which conditions and expectations for dili-gent development are quite different from coal leases becausethe existence of commercially producible oil and gas is usuallynot known. The discussion of diligent development here focuseson the concept as it applies to coal leases. A recent Texas caseinvolving private leases with an indefinite lease term held thata coal lessee has a duty to develop the leased lands within areasonable period of time unless the lease specifically sets outthe scope of the lessee's duties—such as initiation of produc-tion within a specific period of years. See Cleghorn vs. DallasPower & 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 acceptadvance royalty payments in lieu of requirements for continuedoperation. The DOI issued coal leases permitting payment ofroyalties in lieu of continued operations, but until 1973 had ef-fectively nullified the minimum royalty requirements by settingthe minimum royalty equal to the annual rental (i. e., no addi-tional payments beyond the normal rental rates were re-quired). There are a few leases that were issued between 1973and passage of the 1976 FCLAA that require payment of ad-vance royalties based on a predetermined rate of productionfor the sixth and succeeding years of the lease (Office of Tech-nology Assessment, Management of Fuel and Nonfuel Mineralsin Federal Land: Current Status and Issues, Washington, D. C.:OTA, 1979).

21 See 41 F.R. 21779, May 28, 1976, In considering passage ofFCLAA, Congress was aware of the diligence requirements forproduction on existing leases within 10 years in the proposedand final regulations. Among the reasons cited for vetoingFCLAA, President Ford said that the May 1976 regulationsmade many of the provisions of the Bill unnecessary. See State-ment of Representative Mink at 122 Cong. Rec. H8311, atH8312 (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 astrict interpretation, would bar the issuance of any new leases


for coal or for oil, natural gas, or other minerals under the Min-eral Leasing Act to any coal lessee who continues to hold alease for 10 or more years without producing coal in commer-cial quantities. The section provides that “The restriction doesnot apply if production on the lease has been suspended under30 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 sub-

ject to the conditions of diligent development and continuousoperations except when operations are interrupted because ofstrikes, the elements, or casualties not attributable to thelessee. However, the final sentence in the subsection providesthat nothing in this subsection (207(b)) shall be construed to af-fect the requirement in subsection (a) that leases not producingat the end of 10 years shall be terminated. This proviso hasbeen interpreted to mean that no extensions of any kind areavailable for post-FCLAA lessees. However, FCLAA did not re-strict the Secretary’s authority in sec. 39 of the Mineral Leas-ing Act (30 U.S. C. 209) to suspend the operation of any lease inits entirety in the interests of conservation. The Secretarycould suspend the term of a lease, and the diligence obligation,under the general authority of sec. 39. Thus, providing somedelay in the running of the diligence clock for post-FCLAAlessees. (Sec. 14 of FCLAA did amend sec. 39 slightly, by limit-ing the Secretary’s authority to waive, suspend, or reduce ad-vance 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 onthe Federal Coed Management Program, app. I at p. I-26, 1979.

30See 43 CFR 3475.4(b)(2). On Feb. 1, 1980, proposed guide-lines for deciding on applications for discretionary extensionsunder this regulation were published for comment. 45 F.R.7138. In January 1981 final guidelines were approved by UnderSecretary Josephs of the Carter administration. As of May1981, the Reagan administration had not yet decided whetherto adopt these guidelines.

3143 CFR 3473.4(d).32Advance royalties were required of all leases on adjust-

ment under 1976 pre-FCLAA regulations (since rescinded). Thepre-FCLAA advance royalty regulations might have had a sig-nificant effect on lease development. Had these regulations re-mained in force, the schedule for advance royalty payments in1990 for 249 currently undeveloped leases with no mine plans,assuming that none of these leases were producing, could havebeen over $200 million. This is more than 9 times the $24.6 mil-lion paid in coal royalties in 1979. This estimate assumes thatall leases would be readjusted and uses an average royalty rateof $1.25/ton ( 12.5 percent royalty per ton paid on an averageprice per ton of $ 10.00). The annual production schedule forapplying advance royalties to the 249 undeveloped leaseswould be $165 million tons (6.6 million tons of recoverable re-serves divided by 40 years resulting in annual payments of$206 million. This amount would probably have been signif-icantly higher than the royalties paid on actual productionto meet the l-percent annual production rate for continuousoperations,

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 althoughit is not necessarily controlling. The lessee can also raise var-ious defenses to the action and to the application of DOI’s dili-gence standard to his lease. Thus, even if the lessee does notmeet 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 estab-

lish standards such as these for lease cancellation. The stand-ard described in 3523.2-1 clarifies those conditions that wouldnot be considered when a lessee applies for an extension toavoid lease cancellation.” 41 F.R. 21780, May 28, 1976. Thecurrent regulations on cancellation of leases (43 CFR 3452.2-1(c)) list a number of adverse circumstances that will not beconsidered in deciding whether to cancel a lease. The circum-stances listed are essentially the same as those listed in 43 CFR3475.4(b)(l) as conditions that are not extraordinary, andhence do not qualify for extensions of diligent developmentdeadlines. These conditions include: 1) normally forseeablebusiness risks such as fluctuation in prices, sales, or costs, in-cluding foreseeable costs of complying with requirements forenvironmental protection; 2) commonly experienced delays indelivery of supplies or equipment; or 3) inability to obtain suffi-cient sales. The preamble to the Dec. 29, 1976 final regulationsstates that these provisions limit the DOI’s discretion to decideagainst cancellation. In its discussion of the reason for settingminimum production levels for continued operation a 1 percentrather than 2½ percent annually the preamble says: “If thelessee produces less than the rate specified in the mining plan,the DOI may cancel the lease for failure to comply with theplan; however, if the lessee fails to produce 1 percent annually,the DOI's discretion to decide against cancellation would besubstantially limited as set forth in 43 CFR 3523.2 -l(b)(1)(i) (re-modified as 3452.2-l(c), This ability to elect whether or not tocancel a lease if annual production is between 1 percent andthe higher rate specified in the mining plan provides the DOIwith leverage to pressure those in arrears to increase produc-tion and to cancel leases when there is not a good faith effort tocomply with the mining plan” (41 F.R. 56,646, Dec. 29, 1976).

37 Secretarial Issue Document on Federal Coal ManagementProgram, Department of the Interior, March 1979, issue paperNo. 14. In the preamble to the May 1976 regulations, it was ob-served that: “It should be understood that, while the DOI hasprovided a definition of diligent development for the future, itreserves the right to sue for cancellation of existing leaseswhere lessees have not made a reasonable effort heretofore todevelop 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 dili-gent development, operation, and production so that the re-serves of the entire unit will be mined within a period estab-lished by the Secretary which shall not be more than 40 years."While not requiring amendment of lease terms to incorporatethe diligence requirements, these conditions on a mine plan ap-proval could result in production exceeding requirements ofthe 1976 regulations for diligent development and continuedoperations which allow a pre-FCLAA lessee to mine his leasefor 97½ years after meeting diligence,

40See for example, the lease form reprinted in Hearings onFederal Coal Leasing Before the Subcommittee on Mines andMining of the House Committee on Interior and Insular Affairs.94th Cong., 1st sess. (1975), at p. 41.

41A lease provision incorporating subsequent regulationsmakes viola lion of these regulations grounds for cancellationunder sec. 31 of the Mineral Leasing Act which provides thatleases may be canceled for breach of general regulations thatwere in effect a t the date the lease was issued. If, however, the1976 diligence regulations are determined to be only interpre-tive regulations (i.e., those advising lessees and the public ofthe DOI’s view of diligence under the act], then the limitation onregulations in effect at the date of issuance is not applicable


since the cancellation would be for violation of the act as inter-preted by DOI. Departmental interpretations of matters com-mitted to their discretion are generally followed by the courtseven though alternative reasonable interpretations be made.Over time, departmental interpretations of law can becomebinding 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 chal-lenging the Secretary’s authority to impose diligent de-velopment regulations on its Rojo Caballo lease in CampbellCounty, Wyo. The settlement provided that: 1) Mobil agreed todismissal of the lawsuit with prejudice: 2) Mobil would take allsteps necessary after mine plan approval so that a minecapable of producing coal in amounts to meet diligence wouldbe in place not later than June 1, 1989: and 3) The extension isapplicable to Mobil only and cannot pass with any assignmentof more than 49 percent of the interest in the lease to anyoneother than a Mobil affiliate. On Apr. 23, 1980, Secretary of In-terior Cecil Andrus signed a letter approving Mobil’s applica-tion for an extension of the diligent development deadline toJune 1, 1991. The extension approval was based on informationsubmitted by Mobil that it had contracts demonstrating that itcould market the necessary 2½ percent of the LMU reservesafter 1986.

43U.S. Department of the Interior, Secretarial Issue Docu-ment on the Federal Coal Management Program, Issue PaperNo. 14, July 1979.

44See defendant’s Brief in Support of Its Cross-Motion forSummary Judgment, Mobil Oil Corp. v. Andrus, No. C79-110B(D. W Y 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 pub-

lished on May 19, 1980 (45 F.R. 321 15). In spring of 1981, DOIannounced that substantially revised proposals for MER anddiligence regulations were under consideration with publica-tion 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 CoalManagement Program, 44 F.R. 42601, July 19, 1979, and 43CFR 3451.1(d), 1980. The effect of this presumptive waiver ofreadjustment on the applicability of regulations issued afterthe prior lease date and of FCLAA provisions to the lease is notspecified. However, since DOI has previously maintained thatreadjustment is not necessary to make general regulations ap-plicable to the lease, DOI probably would argue that waiverwould have little effect because the regulations were ap-plicable 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 innortheast Wyoming: over 300 million tons of PRLA reserves insouthwestern Utah; and up to 60 million tons on leases in theBisti area of New Mexico. Additionally. as much as 400 milliontons of reserves in the Lake DeSmet lease blocks might qualifyfor exchange under SMCRA and over 130 million tons of Fed-

eral bypass lease reserves could be involved in the NorthernCheyenne 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 re-moved during construction of a right-of-way did not have to beleased competitively and provided that higher minimum royaltyrates did not apply to modified leases until expiration of theircurrent terms.

59Bureau of Land Management, Lake DeSmet E x c h a n g eStudy, Wyoming State Office, Johnson County, Wyo., July 1979.Texaco is the major holder of private land and mineral rightsand only holder of Federal leases in the Lake DeSmet area. Theacquired lands would have been used for recreation purposes.Even though the exchange was not approved, Texaco feels thatreserves on several Federal leases in the block may qualify forexchange under sec. 510(b)(5) of SMCRA (letter from R.T.Carter, Vice President, Coal and Energy Resources Depart-ment, Texaco. to OTA, dated Dec. 19, 1980).

60Energy Daily, June 17, 1981, p. 3. The rejection followednegative recommendations by the U.S.G.S. economic evaluationunit on the value of the PRLAs because the PRLAs are locatedfar from existing coal transportation networks. (Personal com-munication to OTA, U.S.G.S. Conservation Division, Denver,Colo., Dec. 15, 1980. ) GAO also circulated a draft report on theexchange questioning the validity of the PRLAs because the ap-plicant did not have an approved prospecting permit when ex-ploratory drilling was conducted on two PRLAs: and the lack ofdata on the coal reserves required for making the “equal valuedetermination”: and expressing concern over the competitiveeffect of giving Utah Power & Light highly desirable coal landsin central Utah. Letter of Apr. 2, 1981 from J. Dexter Peach. Di-rector, Energy and Minerals Division. GAO, to James G. Watt,Secretary of the Interior. The Utah Power & Light exchange isdiscussed in the final environmental statement on the Uinta-Southwestern Utah Lease Sale, Bureau of Land Management.1981.

61 Several of the Wyoming leases under consideration for ex-change were reviewed by the OTA Wyoming task force and arediscussed in ch. 6 of this report. The Interstate Highway ex-change proposal includes parts of the existing Wyodak Mineand two lease blocks with favorable production prospects by1986 (Kerr McGee’s East Gillette Federal and Carter’s SouthRawhide Mines). Two other leases—Armstrong and Gulf (No.3) were given unfavorable development prospects. The finallease, Belco, has uncertain development prospects-contingenton in situ gasification— with unfavorable production prospectsin 1986 and 1991. Gulf Oil Co. has requested that the Gulf (No.3) lease be exchanged for a corridor of unleased Federal coalthat 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 obtainedat the OTA Wyoming task force, up to 1 billion tons of coal iscovered by these leases and permits. Peabody Coal Co., holderof the seven leases and three permits, is seeking rights to 130million tons of Federal bypass coal in return for cancellation ofits 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 min-ing act regulations. The AVF exchange regulations were re-manded to DOI to include provisions implementing the man-datory exchange program for non-Federal lands. See con-


ference report on H.R. 2, House Report 95-493, July 12, 1977,pp. 104-105:

The Senate amendment also provided authority for the Se-cretary of Interior to lease Federal coal deposits as an exchangerelinquishment of a Federal coal lease for coal affected by thisalluvial valley floor constraint. Such an “exchange” would belimited to those operators who had made a “substantial legal andfinancial” commitment to mine such coal prior to Jan. 1, 1977.

Similar exchange authority under sec. 206 of the Federal LandPolicy and Management Act of 1976 was granted the Secretarywith respect to “fee” coal owned in alluvial valley floors. Both ofthese authorities were discretionary on the part of the Secretary.

The conferees also stipulated that the Secretary develop andcarry out a coal exchange program for fee coal located in alluvialvalley floors under the provisions of sec. 206 of the Federal LandPolicy and Management Act of 1976.

The language added by the conferees to the “Wallop Amend-ment” of the Senate version is designed to make it clear that theSecretary should actively implement the coal exchange program.This program would apply to all those private coal deposits, re-gardless of any previous financial or legal commitments, which theSecretary determines cannot be mined because of the provisions ofsec. 510( b](5]. The program would not apply to privately ownedcoal which might have been mined in the same operation but whichcan still be mined.*43 U.S.C. 1716, Regulations implementing sec. 206 have

been promulgated but are under review by the Reagan adminis-tration.

‘ qExchanges of checkerboarded lands covering criticalwinter range for big game species in the Atlantic Rim area nearRawlins, Wyo, have been suggested. See also, R. C. Andersonand A, Silverstein, Management of Federal Cod Properties inAreas of Fragmented Resource Ownership (Washington, D. C.:Environmental Law Institute, 1980) for discussion of ex-changes for unitization of coal reserves.

“’See Management of Fuel and A!on~uel Minerals in FederalLand, Office of Technology Assessment, April 1979, ch. 3, fordiscussion of various provisions for obtaining developmentrights 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. Thenumber of PRLAs has dropped as some applications were re-jected and now fluctuates between 171 and 178 depending onthe results of various appeals of rejected applications. All pros-pecting permits have since expired. As of March 1981 thenumber of PRLAs had dropped to 171 as a result of: 1) additionof two new applications because of litigation challenging theDOI’s denial of extensions of prospecting permits for which noapplications had been filed at the time the 1976 FCLAA wasenacted; and 2) the withdrawal of seven applications.

“The Summary Paper on Management of Preference RightLease Applications (Office of Coal Leasing Planning and Coor-dination, SecreturiaJ Issue Paper: Formulation of Proposal forCoal Programmatic Environmenkd Impact Statement (Washing-ton, D. C.: U.S. Department of the Interior, June 23, 1978, Tab I)estimated maximum potential production from pending PRLAsto range from 186 million tons/year (if legal, probable andpossible planning and environmental restrictions are applied)to 248 million tons (no restrictions applied). This was based on40-year mine life on estimated recoverable reserves of 9.9billion tons. The estimated reserves under PRLAs have beensubsequently reduced to 5,7 billion tons (due primarily toelimination of an estimated 3.6 billion tons of subbituminousunderground reserves in the Wyoming Powder River basin). Ifthe lower reserve figures are substituted for those in theSecretarial issue paper, the range of potential productiondrops to between 108 million and 144 million tons, OTA’S anal-ysis of PRLAs in Wyoming indicates that approximately 40 mil-

lion tons of potential production capacity in this revised num-ber have unfavorable development prospects (see ch. 6 andOTA’S Wyoming task force report). When OTA’S estimates ofpotential production capacity of PRLAs in Wyoming with favor-able or uncertain development prospects (20.5 mil l iontons/year) are substituted for the revised numbers for Wyo-ming in the Secretarial issue paper, the range of total produc-tion potential becomes 69,5 million to 102.5 million tons/year.OTA’S analysis of production potential of PRLAs in the 1990’sis based on the following modifications of DOI’S production es-timates: Colorado, 9 million to 17 million tons; Montana, zero to7.7 million tons; New Mexico, 7,5 million to 9.5 million tons;Oklahoma, zero to 0.4 million tons; Utah, zero to 6.5 milliontons; Wyoming, 20 million tons. OTA’S adjusted annual produc-tion totals yield a range of 35 million to 60 million tons includingabout 10 million tons of production capacity associated withexisting leases and reflected elsewhere in this report as Fed-eral mine production. Total new annual production potential ofPRLAs would thus be between 25 million and 50 million tons.Some PRLA reserves in eastern Colorado and Wyoming werefound to have some potential for use as a feedstock in syntheticfuels processes, but substantial production from these PRLAsis likely only if there is greatly expanded demand for such coalin the 1990’s.

741nitial production from most PRLAs can be expected in1988-94 assuming that it takes about 6 years for mine develop-ment from the date of lease issuance. Several groups of PRLAswill be issued during 1981 to 1982 under an accelerated proc-essing schedule: these PRLAs include four in Colorado and theArch Mineral PRLAs in New Mexico.

75105 of 172 applications submitted to BLM did not containinformation proving that commercial quantities had been dis-covered, but rather stated that the requisite data had been pro-vided to the U.S. Geological Survey, Seventy-five PRLAs werefiled without the required qualifications statement describingthe applicant, and 70 PRLAs were filed without precise de-scriptions of the acreage covered by the application. In addi-tion, 25 PRLAs did not file initial showings in a timely mannerrequired 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 theapplicant to correct the application by supplying the requiredinformation, If the applicant does not respond with the re-quested 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 didnot properly indicate the existence of recoverable reserves andfour PRLAs that were not filed before the expiration date of theprospecting permit. Several of these PRLAs have subsequentlybeen rejected.

“Preference right leases were issued in 1974, 1975, 1976,and 1977 in accordance with short-term leasing criteria in ef-fect at that time. The four leases (one issued in each of thoseyears) range in size from 175 to 14,902 acres.

“See 41 F.R. 18845, May 7, 1976 (final rules); see also pro-posed rules published at 41 F.R. 2648, Jan. 19, 1976.

“According to the Preamble to the Proposed Rules, use of theworkability standard for classification resulted in a determina-tion of commercial quantities “based solely on the physcialcharacteristics of the mineral without regard to costs such astransportation and reclamation, ” The use of this standard wasrejected. 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).‘3458 F. %pp. 937.

“458 F. Supp. 937.“The ability of DOI to exchange leases or PRLAs for un-

leased Federal coal without specific congressional approval isrelatively limited, but 43 CFR 3435.1 allows PRLAs to be relin-quished in exchange for other rights, including: I) the issuanceof coal lease bidding rights of equal value; 2) a mineral leaseother 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 thequestion of whether such withdrawal would constitute a takingsince, under 43 U.S.C. 1701, withdrawals are subject to validexisting rights.

“’NRDC v. Berklund, 609 F. 2d 553 (D.C. Cir. 1979).“448 F. SUPP. 962 (D. Ut. 1979)‘9448 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 didnot respond and five PRLA holders were not contacted becauseof 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, 526and 527.

‘“43 U.s.c. 1744.‘“43 CFR 3430.1-2


“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 Federa-tion to Frank Gregg, Director, Bureau of Land Management (re:comments on Bureau of Land Management Proposed CoalLeasing Management Regulations: PRLAs, May 18, 1979). In1975, the Environmental Defense Fund and Natural ResourcesDefense Council concluded that a number of PRLAs in the Pow-der River basin, Wyoming could be challenged on this basis,but decided that litigation challenging such PRLAs would needto be done on a case-by-case basis when (or if) the leases wereactually 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 lo-

cated within a few miles of Chaco Canyon National Monumentand its “outliers”. Chaco Canyon was established primarily topreserve the Indian archeological sites there: it is likely thatany protective stipulations on mining in the area would bedirected at minimizing any harmful effects of mining on thearcheological sites and not at preserving scenic vistas.

“’iSee notice at 46 F.R. 30202, June 5, 1981.

CHAPTER 10

Implications-of Environmentaland Reclamation Issues for the

Development of Federal Coal

[Page Omitted]

This page was originally printed on a gray background.The scanned version of the page is almost entirely black and is unusable.

It has been intentionally omitted.If a replacement page image of higher quality

becomes available, it will be posted within the copy of this report

found on one of the OTA websites.

http://www.wws.princeton.edu/~ota/

CHAPTER 10

Implications of Environmentaland Reclamation Issues for the

Development of Federal Coal

This chapter considers the extent to whichenvironmental and reclamation concernsmay affect the production of Federal coal.Primary emphasis is placed on documenta-tion of those cases where mining of recover-able coal reserves has been delayed or pre-vented. A brief discussion is also included onthe effect that environmental and reclama-tion concerns have on the cost of mining Fed-

eral coal. The chapter is not an analysis ofthe effects of coal mining on the environment,although those issues are briefly discussed inorder to provide a context for the chapter.Background information is also provided onthe environmental characteristics of Westerncoal regions and the existing framework forcoal mine regulation.

Environmental Overview of Coal= Producing Regions

The United States can be divided into 12major coal-producing regions (fig. 43). Fed-eral coal accounts for a large portion of thecoal reserves of the six westernmost regions.In addition, Federal coal reserves are signifi-cant in the extreme southern portion of theWestern Interior region in Oklahoma. * Thissection reviews the important environmentalcharacteristics of these seven coal regions,pointing out regional similarities as well asnoting differences. Emphasis is placed on dis-cussion of those characteristics that are ofmost importance to the mining of Federal coalreserves, and on the potential for success inreclaiming mined lands. This section servesas background to the discussion of reclama-tion and environmental issues later in thischapter.

Because Federal coal reserves are concen-trated in the Western United States, the en-

*Alaska has substantial coal resources on Federal lands, andthere are also scattered areas of federally owned coal reservesin the eastern regions and in Texas. These coal regions are notconsidered in this report because of the relatively minoramounts of Federal coal there currently under lease comparedto leased reserves in the seven States of Colorado, Montana,New Mexico, North Dakota, Oklahoma, Utah, and Wyoming.

vironmental characteristics of mining andreclamation of Federal coal differ from themining of the other coal reserves of the Na-tion. Only the Federal coal reserves of Okla-homa in the Western Interior region have en-vironmental characteristics similar to thecharacteristics of the privately held reservesof the Midwest and Eastern United States.

The Western United States is notably dis-tinct from the rest of the country in its overalllack of available water, its shallow soils, andits high erosion rates. These factors combineto make reclamation more difficult than inother parts of the country. Annual mean pre-cipitation in the West is low, ranging from 4inches or less per year in some of the hotdeserts to over 20 inches in the higher moun-tains. Droughts are common in the West, andprecipitation is more commonly below aver-age than above. Particularly during periodsof drought, precipitation may occur in short,intense storms that have the potential tocause severe erosion. Temperatures in theWest fluctuate widely, and high summer day-time temperatures can quickly dry out soiland seeds.

273

.— —


Figure 43.—Tweive Coai Suppiy Regions of the United States

u vSOURCE: 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 andarid West. Rocks weather slowly, and or-ganic matter accumulates slowly. The result-ing soil profile is loose and undifferentiatedand has little capacity for holding moisture.In much of the West, rates of erosion areamong the highest in the country, and soil canbe lost because of flash flooding and hillslopeerosion.

Vegetative succession is a slow process inthe West because of climatic severity. A dis-turbed site in the Eastern United States mayrevegetate itself in 5 to 10 years, but decadesor centuries maybe needed for natural reveg-etation in the West. Thus, natural revegeta-

tion cannot be relied on to rehabilitate dis-turbed sites, and careful planning is needed.’

Tables 80, 81, and 82 summarize the envi-ronmental characteristics of the seven coal-producing regions with major reserves ofFederal coal. The information is separatedinto three categories: physical characteris-tics (table 80), environmental resources (table81), and social characteristics (table 82).

‘Previous three paragraphs adapted from National Academyof 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 Climate c

Western Interior: Central Lowlands Division Gently sloping hills Mollisols Evaporation: 64-80"/lyr.Oklahoma Upper Missouri Basin Subdivision Inceptisols Mild temperatures: 400 winter

>800 summerPrecipitation: 32-48’’/yr.Winds: 11-14 mphDust 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 continentalNorth 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 “Fareas. Precipitation: 12-16’’/yr.

thunderstorms frequentWinds: 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 continentalWyoming some areas. Entisols Mean annual temperature:

45“FPrecipitation: 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 Mounta in Div is ion Complex mountains and basins, Aridisols Evaporation: 48’’/yr.Colorado (Wyoming - Big Horn Basin generally a series of parallel Mollisols Semiarid continentalWyoming Subdivision) ranges. Mean annual temperature:

Local relief up 2,000 ft, but 37-46 “Fgenerally 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 pat-canyons. terns in the mountains

High plateaus of stratified rock (some of which maintaincut by deep canyons in year round snow cover)southwestern Utah. Precipitation: 30% of area

receives 0-8"/yr., rest ofarea (except mountains):8-16’’/yr.mountains: > 20”/yr.

San Juan River: Colorado Plateau Basins with mesas, rolling Entisols SemiaridColorado Division and Subdivision plains, and badlands Aridisols Mean annual temperatures:New Mexico 48-52 ‘FUtah Mean annual precipitation:

less than 10” to 20”Summer thunderstorms.Evapotranspiration exceeds

precipitation by a factor of6:1

Denver-Raton Mesa: Southern Rocky Eastern portion: gentle plains Alfisols Evaporation: 64-80’’/yr.Colorado Mountain Division Western portion: Steep slopesNew Mexico Rocky Mountain, Piedmont and

Semiarid continentaland footh i l ls Mean annual temp.: 48-520 F

Southern Rocky Mounta ins Precipitation: 13-18’’/yr., lowSubdiv is ion humidity, l ight rainfall,

per iod ic droughtsWinds: 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 aperiod 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 Irrtgatlonis 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 andtemperature. 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 andmany 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 plantgrowth 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 generallymoist, these soils tend to dry out in the warm seasonscEvaporatlon figures are for mean annual evaporation.SOURCE: Class A pan-National Atlas.

—— .—— . . -


Table 81.—Environmental Resources of Coal-Producing Regions

CarryingAgriculture 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, timbermoderate 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: 6birds, 3 mam-mals.

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, wheatreals, 200 southernquantities 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 Principalbirds, 3 mam- crops: wheatreals. and grain.

Powder River Overall quality: Annual surface water run-off: less Wyoming: Prairie Similar to Fort Grazing and 15.5generally 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, andarea for TSP. Major streams: Yellowstone, Big ponderosa pine.

Horn, Powder, Tongue, BelleFourche, 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. andparts of Sweet-water, Colo., andWyoming are non-attainment forTSP.

Eastern half: .1-2” sagebrush. species. sheep ranch- A.U.M.Quality good in mountains and Salt brush biome: Large numbers of ing, limitedpoor in basins. greasewood, moun- big game farming.Major streams: Green, Yampa, tain shrub, animals. Cropland: 4°/0Sweetwaters , Shoshone, Greybu l l . evergreen fo res ts , Varied game and Range: 70°/0

broadleaf forests . non-game f ish Forests: 270/ospecies.Wild horse herds.Federally pro-tected species: 1fish, 3 birds, 2mammals.

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- woodlandduring 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°/0sagebrush. phibians

Federally pro-tected species: 3fish, 3 birds, 2mammals.

San Juan River Overall quality Annual runoff: 0.1-O.5’’/yr.generally good ex-cept around in-dustrial areas.High SO2 levelsnear powerplants.

Major streams: San Juan, Colorado,and Little Colorado.San Juan River is the only perennialstream in Federal lease block area.Ground waters are generally good,but levels are dropping.

Generally sparsevegetation.Lower elevations:grassland shruband grasslands.Upper elevations:Pinyon, juniper andconiferous forests.

Habitat supports:100 speciesmammals, 116species birds, 28species amphib-ians.Several areunique to region.Federally pro-tected species: 1fish, 4 birds, 1mammal.

Cattle and 22 acres/sheep ranch- A.U.M.ing.Range: 50%Forests: 45%Limited crops:corn, hay,wheat, cotton,and sugar-beets.

Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal ● 277

Table 81.—Environmental Resources of Coal-Producing Regions—Continued

CarryingAgriculture

Air qualitycapacity

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, sugarbeetstional 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: 1fish, 3 birds, 1mammal.

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

1975Major 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 5.4tified archeological value. A few Grasslandareas have large sites and/or high ● Theodore Roosevelt Nationalsite density. There is a high prob- Memorial Parkability of disturbance to sites in ● Custer National ForestCuster 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 4.6bance to sites in Rosebud, Bighorn ● 65 Sites eligible for, or currentlyand Powder River Co’s., Mont, and enrolled on the National Registerin Johnson and Campbel Co’s., Wyo. of Historic sites.Remainder of region considered to • Thunder Basin Nationalhave some archeological value. Grassland

● Custer National Forest

Green River- The region has some identified ● Flaming Gorge National Recrea- 126,938 2.6Hams 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 Can-sites in Emery, Kane and Garfield yon National ParksCo’s., in Utah. Remainder of region ● Cedar Breaks National Monumentconsidered 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 7.2having both great archeological ● 6 National Monumentsand historical value. There is a highprobability of disturbance to sitesin the Chaco Canyon National Monu-ment area.

Denver-Raton Mesa This region has some identified ● Comanche National Grasslands 1,854,205 77.5archeological 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.



Physical Characteristics. Table 80 con-tains information on physiographic subdivi-sions, topography, soil orders, and climate.The topography of the Federal lease areas isvaried. The Western Interior region is typi-fied by a gently undulating prairie landscape.The northern regions (Fort Union and PowderRiver) are also generally characterized bylow overall relief and an undulating grass-land, but selected areas include badlands,ponderosa pine forests, and rocky cliffs andoutcrops. The central western regions (GreenRiver-Hams Fork and Uinta-SouthwesternUtah) are located in mountainous terrain. TheSan Juan River region is characterized bymesas and badlands. Topography in the Den-ver-Raton Mesa region varies from gentleplains to rugged slopes and foothills. As notedearlier, the Western areas tend to be eithersemiarid or arid in climate. There are someexceptions in the mountainous areas, whichtend to create localized weather patterns ofhigher precipitation. In all the Western re-gions, evaporation exceeds precipitation. Theratio of evapotranspiration* to precipitationranges from 2 to 1 in the Fort Union region to6 to 1 in the San Juan River region. The evapo-ration rates in the region range from 48 to 64inches in a year in the northern coal regionsand generally increase to a high of 80 to 96inches a year in the southern San Juan Riverregion, Low rainfall and high evaporationcreates moisture stress throughout the coallease areas. The moisture stress generally in-creases from north to south for similar eleva-tions. Soil types reflect the topography, geol-ogy, and climate of the regions. Most of thesoils have a low moisture content, but usuallyhold enough water to sustain plant growth for3 months of the year.

Environmental Resources. Table 81 sum-marizes air quality, water resources, vegeta-tion, wildlife, agriculture and land use, andlivestock carrying capacity of the coal leaseregions. Overall, the air quality of all theregions is good to very good, although atmos-

*Evapotranspiration means loss of water from the soil bothby evaporation and by transpiration from the plants growing inthe soil.

pheric inversions are common in all the areasfor parts of the day in both summer and win-ter. The exceptions to good air quality are inareas with extensive urban or industrial de-velopment. Areas with air quality problemsinclude Billings and Colstrip, Mont.; portionsof Sweetwater County, Wyo.; Craig, Colo.;areas around powerplant generating stationsin the San Juan River region; and in the urbanColorado Front Range corridor.

Annual surface water runoff ranges from0.5 to 2 inches for most of the coal leaseregions, with most areas falling within thelower part of the range. The major exceptionis in the mountainous areas of the GreenRiver-Hams Fork and Uinta-SouthwesternUtah regions. Water availability in all regionsis greatest in the major river valleys. Thewater quality of the regions’ streams is dif-ficult to generalize and ranges from variableto good. High sediment loads are common.

The coal regions are characterized bysparse growth in the lower elevations. Prairiegrasses and sagebrush are the predominantspecies. The mountainous forests are gen-erally characterized by coniferous treespecies. Large mammals—antelope and muledeer—range throughout the regions, with theGreen River-Hams Fork and Uinta-Southwest-ern Utah regions containing the largest num-ber of big game animals. The San Juan Riverarea contains a number of animal speciesthat are unique to only that region. The num-ber of federally protected fish, bird, andmammal species varies from four to nine ineach region.

Except for the fertile Western Interiorregion, the predominant land use is grazing.The semiarid conditions of the West limitcroplands to areas with above-average rain-fall or to irrigated or subirrigated areasgenerally found in stream valleys. Table 81indicates the percent of land devoted to bothfarming and grazing use. In addition, table 81summarizes the average regional carrying ca-pacities for livestock, which range from 2.6acres per animal unit month in Oklahoma, to22 acres per animal unit month in the SanJuan River region.

Ch. 10—implications of Environmental and Reclamation Issues for the Development of Federal Coal . 279

Social Characteristics. Table 82 containsinformation on population, population den-sity, and features of archeological signif-icance in the coal lease areas. In general, thepopulation density of the Western regions islow, except in the Denver-Raton Mesa regionwhich reflects the significant growth that hasoccurred in the Denver region.

The archeological history of most of theWestern region dates back to the Paleo-

Indian big game hunting tradition of thepre-8000 B.C. period, and to the Desert Cul-ture of the period from 9000-4000 B.C. Theregions also contain remains of early Indiancultures, the most significant of which is theAnasazi people and the remains of their mul-tistoried pueblos in the Southwest that dateback to 1000 A.D. Although all of the regionsare considered to have some archeologicalsignificance, the San Juan River region hasthe greatest archeological value.

Regulatory Framework

Federal regulation of the environmentaleffects of surface coal mining operations,including the surface effects of undergroundmining, was initiated on August 3, 1977 whenPresident Carter signed into law the SurfaceMining C o n t r o l a n d R e c l a m a t i o n A c t(SMCRA) (Public Law 95-87 ).2

In brief, the Surface Mining Act estab-lishes a detailed national program for ad-dressing environmental effects of coal min-ing. Of particular importance is the act’sestablishment of environmental protectionperformance standards (sec. 515) and provi-sions for designation of lands as unsuitablefor coal mining (sec. 522). The performancestandards of section 515 are minimum stand-ards applicable to various aspects of the min-ing and reclamation process. Under SMCRA,the States may, if they choose, impose stand-ards that are more stringent. Among otherthings, the standards require:

●

●

●

●

●

maximum utilization and conservation ofthe coal being recovered;restoration of disturbed land to originalor better conditions;restoration of the approximate originalcontour of the land surface;stabilization and protection of all sur-face areas;protection of prime farmlands throughspecific reclamation techniques;

291 Stat. 445, 30 U.S,C. 1201 et. seq.

84-141 ? - 81 - 19 : u 1, 3

● minimization of disturbances to the ex-isting hydrologic balance; and

● limitation of mining on steep slopes.

Section 522 of the act establishes a pro-cedure to designate lands as unsuitable forall or certain types of coal mining operations.The Secretary of the Interior determines un-suitability for Federal lands, while Stateshave authority over non-Federal lands. Areasmay be designated unsuitable if, upon peti-tion, it is determined that reclamation of dis-turbed lands is not economically or techno-logically feasible. Areas may also be desig-nated unsuitable if mining operations will:

● be incompatible with existing land useplans;

● significantly affect important fragile orhistoric lands;

● result in substantial loss or reduction inthe productivity of renewable resourcelands which produce food or fiber; or

● substantially endanger life and propertyin natural hazard lands.

The act requires that the Department ofthe Interior (DOI) obtain the consent of cer-tain private surface owners before Federalcoal underlying their lands can be leased.The act restricts mining activities affectingalluvial valley floors. Section 510(b)(5) of theact allows the Secretary of the Interior totrade unleased Federal coal reserves for ex-isting leases or non-Federal lands that cannotbe mined because of alluvial valley floor des-


ignations provided that coal is not yet beingproduced from the mine and the operator hadmade a substantial legal or financial commit-ment to develop a mine before January 1,1977. The act also requires the Secretary toexchange non-Federal coal lands in alluvialvalley floors that cannot be mined for avail-able Federal coal lands of comparable value;these exchanges are not subject to the re-quirement of substantial legal and financialinvestments.

The act also created the Office of SurfaceMining Reclamation and Control (OSM) with-in DOI to implement the statute’s various pro-grams. The act mandates compliance with de-tailed technical performance standards byoperators on private as well as on Federaland State lands. The act originally providedfor slightly less than 3 years of Federal en-forcement of State-issued operating permitsimplementing the most stringent of the act’sperformance standards (known as the “in-terim regulatory program”) followed by im-plementation of the remaining standards(known as the “permanant regulatory pro-gram”). At the end of 3 years (June 3, 1980),primary regulatory responsibility for the pro-gram was to have shifted to those States whohad their proposed program for assumingregulatory primacy approved by DOI. Inthose States in which primacy was notachieved, a Federal program was to havebeen implemented and administered by OSM.Three and one-half years after enactment ofthe statute, all mining operations were tohave been in compliance with permits issuedin accordance with the full range of regu-latory requirements, as administered byeither the States or OSM.

Litigation brought in the District Court forthe District of Columbia by several of themajor coal companies and trade associations,as well as by several States, has resulted insignificant changes to this schedule. Theresult of these changes has shifted the latestdate for transfer of primacy or implementa-tion of a Federal program from June 3, 1980to January 3, 1981, and on-the-ground com-pliance from February 3, 1980 to September

3, 1981. Litigation pending in eight States(Pennsylvania, Virginia, Ohio, Tennessee,Kentucky, Alabama, Indiana, and Illinois) en-joining implementation of a Federal programin those States that did not gain primacy ac-cording to the schedule, has further delayedthe implementation schedule. Although thefull surface mining regulatory program wasto have gone into effect on Federal lands 1year after enactment of the statute (i.e., Aug.3, 1978), the Secretary of the Interior, exer-cising his discretion, shifted the effectivedate of the permanent program requirementsto coincide with the date on which primacy istransferred to a State or a Federal regulatoryprogram is implemented for the State (Jan. 3,1981).

Several other environmental statutes alsoaffect the manner and method of mining coalon Federal leases. The most significant ofthese are the Clean Air Act and the CleanWater Act. Others, such as the EndangeredSpecies Act of 1973, Bald Eagle ProtectionAct of 1969, as amended, Migratory BirdTreaty Act of 1918, as amended, the NationalForest Management Act of 1976, and the Na-tional Historic Preservation Act of 1966, asamended, may act to prevent mining in cer-tain locations at the mine plan approvalstage. These acts are discussed separatelylater in this chapter. The DOI, in implement-ing the coal leasing process in accordancewith the Federal Lands Policy and Manage-ment Act of 1976, has applied most of thesestatutory requirements to the process ofselecting tracts for leasing during the landplanning process, i.e., at the earliest stage inthe lease development process. Because ofthe preliminary nature of the data availableat this early point in the development process,decisions on certain criteria cannot be madeconcerning the suitability of a given tract forleasing, and these decisions are considered inthe actual mine plan approval process.

In the West, because much of the coalreserve underlies Federal lands, OSM hashad direct responsibility not only for enforc-ing the act’s regulatory requirements, butalso 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 min-ing activities on Federal lands is shared bythe U.S. Geological Survey (USGS), the Bu-reau of Land Management (BLM), and theU.S. Forest Service as well as with thoseWestern States with Federal lands withintheir boundaries that have gained regulatoryprimacy and have signed cooperative agree-ments with DOI. USGS has jurisdiction overexploration on Federal lands outside minepermit areas, as well as responsibility forresource conservation, diligence, and royal-ties under the Mineral Leasing Act as dis-cussed in greater detail in chapter 9 of thisreport, BLM is the leading agency for Federalminerals and, under a variety of Federal stat-utes, is responsible for the management andprotection of surface resources on Federallands. BLM can set postmining land use per-formance bond limits to assure protection ofthese resources. The Forest Service performsa similar role for National Forest Systemlands. Thus, USGS, BLM, and the Forest Serv-ice, together with OSM, submit recommen-dations to the Secretary of the Interior con-cerning the approval or disapproval of mineplan applications. The U.S. Department ofAgriculture, acting through the U.S. ForestService, must concur in the issuance of mineplan approvals for mines within the bound-aries of any national forest. Applicable Fed-eral, State, and local agencies retain similarauthority with respect to mines that mightadversely affect any public park or site in-cluded in the National Register of HistoricSites.

Each of the Western States with significantcoal reserves had enacted surface mining leg-islation in the 1970’s prior to passage of theSurface Mining Act. The stringency of theState programs varied significantly, withWyoming and Montana generally recognizedas having had the most stringent programs,and Utah and New Mexico the least stringent.All of the Western States have received ap-proval of their permanent regulatory pro-grams and have qualified for assumptionof primary regulatory jurisdiction underSMCRA. Thus, the States have assumed pri-mary responsibility for mine plan compliance

and enforcement with the act’s requirements.Those States with approved permanent plansthat have entered into a cooperative agree-ment with the Secretary of the Interior ac-quire the authority to regulate mining on Fed-eral lands within their boundaries. The Sec-retary of the Interior, however, retains theauthority to approve or disapprove miningplans on Federal lands and to designate Fed-eral lands unsuitable for mining.

The OSM regulatory program is in theprocess of undergoing changes. Secretary ofthe Interior James Watt has ordered majororganizational and staff revisions for OSM.Proposed budgetary cuts for fiscal year 1982decrease funding for oversight inspections ofmines. Extensive review of existing regula-tions is expected to result in a significantdecrease in the extent of current regulationsand is expected to increase the use of guid-ance documents and handbooks to clarifySMCRA. Reliance on State enforcement pro-grams is expected to increase significantly. Inannouncing a plan to reorganize the numberof OSM offices outside of Washington, Secre-tary Watt said:

As the States move closer to achieving pri-mary responsibility for enforcing the SurfaceMining Control and Reclamation Act of 1977,the role of the Office of Surface Mining isshifting to one of assistance, advice and re-view of state efforts to assure that the envi-ronmental protection standards of the Actare met. 3

The reorganization plan and regulatory re-view has been critized by conservation andsome agricultural groups and supported bythe coal industry, The ultimate effect of thesechanges in the OSM regulatory program isuncertain at this time,

Selected Environmental Issue Areasand Their Relationship to theDevelopment of Federal Coal

The following sections discuss several en-vironmental issue areas: air resources,

‘U.S. Department of the Interior Press Release, May 21,1981.


water resources, alluvial valley floors, topsoil concerns, and discusses the likely effect ofand spoil handling, revegetation, wildlife, and these concerns on coal production. Emphasiscultural resources, and analyze how the en- is placed on limitations to recovery of coalforcement of statutory controls may affect reserves or on the rate of recovery. The gen-the production of Federal coal. Each section eral effect of environmental controls on min-reviews the specific statutes important to ing costs is considered in the last section ofthat issue area, outlines the environmental this chapter.

Air Resources

Laws and regulations protecting air qual-ity affect coal mining activities in three ways.First, mines must comply with national airstandards as established by the Clean Air Actand various State implementation programs.Second, undeveloped leaseblocks whose de-velopment is contingent on mine-mouth*power generation or synthetic fuels develop-ment are affected if those facilities cannotcomply with applicable local air qualitystandards. Lastly, changes in requirementsfor controlling sulfur emissions at power-plants in the market area for Western coalmay affect the competitive cost advantages oflow sulfur Western coal.** Issues related todirect emissions from mining activities arefocused on fugitive dust and its effect on totalsuspended particulate (TSP). No other emis-sion from coal mines is important to nationalor State air standards. Standards for sulfurdioxide (S0 2) and nitrogen dioxide (NO2), aswell as for TSP affect emissions from power-plants or synthetic fuel plants.

To date, air quality concerns related todirect mine emissions have had only a minoreffect on Western coal mine development. Inportions of the Powder River coal basin, fugi-tive dust emissions have exceeded or arenearing national ambient air standards, andmining activities in these areas may have toadopt better dust control measures. How-ever, the level of production in this region isnot expected to be constrained by air stand-ards.

*Mine-mouth powerplant is a term that refers toa coal-firedelectrical generating facility located at or near the supplyingcoal mine.

**This issue is examined in ch. 5.

Some mine-mouth powerplants may experi-ence difficulty in receiving permits becauseof their inability to meet air quality regula-tions. Expanded development of some Federalmines in North Dakota may be delayed be-cause of the projected impacts of new power-plants and synfuels projects on the pristineair of the Theodore Roosevelt National Me-morial Park, a Class I clean air area. Simi-larly, powerplants or synthetic fuel plantsmay have difficulty meeting air standards inparts of the Powder River basin and in south-ern Utah. In some cases, notably in NorthDakota, the quality of the coal that would firethe mine-mouth plants is too low to transportany distance. Thus, failure to gain air permitsfor major facilities could preclude develop-ment of some coal reserves. However, a finaldecision on permitting the proposed facilitiesin North Dakota has not yet been made.

The potential impact of changes in nationalsulfur emission standards on the developmentof Western coal is discussed in chapter 5,Markets. Generally, the requirement to con-trol emissions regardless of the sulfur con-tent of the coal decreases the competitive-ness of low sulfur Western coal in marketareas where local high sulfur coal is alsoavailable.

Statutory Control

Surface Mining Control andReclamation Act

SMCRA requires that an operator: “stabi-lize and protect all surface areas includingspoil piles affected by the surface coal mining


and reclamation operation to effectively con-trol erosion and attendant air . . . pollution”(sec. 515(b)(4)). Regulations adopted by OSMpursuant to this section required that an op-erator “plan and employ dust control meas-ures as an integral part of site preparation,coal mining, and reclamation operations” (30CFR 816.95(a) and 817.95(a)). These regula-tions listed 19 different control measures thatmight be employed by an operator to achievethe best available control of fugitive dust.However, these regulations were remandedto OSM by the decision of Judge Flannery ofthe district court of the District of Columbia.4

The regulations, as promulgated, were said tobe too encompassing and beyond statutorymandate. OSM has not proposed a revision ofthese performance standards and at this timeis deferring to State regulatory agencies deci-sions about coal mine fugitive dust emissions.No date is available for reissuance of theseOSM regulations.

Subsequent to this decision, each WesternState except Montana remanded its State reg-ulations that had mirrored the Federal reg-ulations (30 CFR 816.95, 817.95). In each ofthese States, air resource issues are beinghandled by the State agency responsible forState implementation of the Clean Air ActAmendments and not by the mine reclamationagency. In Montana, coal mine related airresource issues are being handled jointly bythe State reclamation agency and the Stateair quality agency. Even in Montana, wheresurface mine regulations are the strictest inthe West, the standards of the Clean Air Actstill take precedence. Thus, State implemen-tation and enforcement of the Clean Air Actis the foundation of regulation of air impactsof coal mining.

Clean Air Act

The Clean Air Act establishes a nationalsystem of air quality regulation. Regulationsand standards under this act are imple-mented at the Federal level by EPA and atState levels in conjunction with additional

4In re Surface Mining Litigation, civil action No. 79-1144(District of Columbia).

regulations and standards imposed by indi-vidual States. The following discussion high-lights provisions of the act of significance tocoal mining. Brief mention is also made ofprovisions of importance to mine-mouthfacilities.

National Ambient Air Quality Standards(NAAQS)5

Regulation under the act focuses on six cri-teria pollutants: particulate, sulfur dioxide(S0 2), carbon monoxide (CO), nitrogen oxides(NOX), ozone (O3), and lead. Two types of am-bient air quality standards are designated:primary standards, which were designed toprotect human health; and secondary stand-ards, which were designed to safeguardaspects of public welfare, including plant andanimal life, visibility, and buildings. The Na-tion is divided into 247 air quality controlregions (AQCRs) so that pollution control pro-grams can be locally managed. Each AQCR isclassified as to whether it meets the nationalstandards.

The classification of an area with respectto ambient air quality has important conse-quences. Regions that are found by EPA to bein nonattainment status are subject to a par-ticular set of restrictions under the act. Onthe other hand, nondegradation regions,where air is cleaner than the standards, aresubject to a different set of regulations,which are intended for “prevention of signifi-cant deterioration” (PSD). Regardless of anarea’s classification, almost every new majorsource of emissions is required to undergo apreconstruction review. (A major source ofemission is defined for PSD purpose at 40CFR 52.2.l(b)(l)(i).)

To achieve air quality goals, areas with aircleaner than NAAQS were divided intoclasses I, II, and III. Certain national parks,

5The following discussion draws heavily from An Assess-ment of 011 Shale Technologies, OTA-M-1 18, June 1980, Seealso Final Rules on Requirement for State Implementation PJansfor Prevention of Significant Deterioration, 45 F.R. 52676, Aug.7, 1980. The rules implement major changes in Clean Air Actregulations 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).

.— —


wilderness areas, and monuments that ex-isted when the act was passed were immedi-ately designated as class I areas where airquality is to remain virtually unchanged. Allother clean air areas were designated classII—areas in which some additional air pollu-tion and moderate industrial growth wereallowed. Individual States or Indian Tribalgoverning bodies can redesignate some classII areas to class III areas in which major in-dustrial development is foreseen and airpollution up to one-half the level of the sec-ondary standards would be permitted. TheStates or Indian Tribes can also redesignateclass II areas as class 1. Either type of redes-ignation is subject to hearings and consulta-tions with the managers of affected Federallands, or States in the case of Indian action.

State Implementation Plan (SIP)Each State must submit an implementation

plan for complying with primary and second-ary standards. A State can decide how muchto reduce existing pollution to allow for newindustry and development. State plans mustalso include an enforceable permit programfor regulating construction or operation ofany new major stationary source in nonat-tainment areas, or significant modification toan existing facility. New processing plantsand power stations must also satisfy emission

standards set forth in the State implementa-tion plan.

Each of the Western States has adopted itsown ambient air quality standards (table 83).For particulate, Colorado has the stricteststandards. For sulfur, important for power-plant emissions, Montana, North Dakota, andNew Mexico have the strictest standards.

The Prevention of Significant Deterioration

All SIPS must specify emission limitationsand other standards to prevent significant airquality deterioration in each region that hasair quality better than primary or secondaryNAAQS or cannot be classified with regard tocompliance with primary standards becauseof insufficient information.

Under these PSD standards, maximum al-lowable increases in concentration of S 02

and particulate are specified for each class(table 84). For the other criteria pollut-ants, maximum allowable concentrations fora specified period of exposure must not ex-ceed the respective primary or secondaryNAAQS, whichever is stricter.

A State can redesignate a class I or II cleanair area with respect to PSD to allow greaterincreases in emissions under procedures set

Table 83.—Federal and State Ambient Air Quality Standards Pertinent to Coal Mineand Related Facility Development

Concentration in micrograms per cubic meter

Federal FederalPollutant (primary) (secondary) Colorado Montana New Mexico North Dakota Utah Wyoming

Particulate:Annual geometric mean . 7524-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 75150 150 200

100 100 100600(3 hr

standard)

53267

—

60150

100200(24 hr

standard)

75 601% 260 150

100 100 100200(1 hr

standard)a Standards for oxidants, CO, lead, and nonmethane hydrocarbons omitted.

SOURCE: Off Ice of Technology Assessment.


Table 84.—National Standards for Prevention ofSignificant 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 assessmentof the impacts of the redesignation, publicnotice and hearings on such a redesignation,and approval by EPA. However, certain Fed-eral areas cannot be redesignated.

If a facility’s construction began afterJanuary 1, 1975, a special preconstructionreview must be undertaken if it is located in anondegradation area. To obtain a permit forsuch a facility, an applicant must demon-strate that it will not cause air pollution in ex-cess of NAAQS or PSD standards more thanonce per year in any AQCR. Best availablecontrol technology (BACT) must be used forall pollutants regulated by the act, and the ef-fects of the emissions from the facility on theambient air quality in the areas of interestmust be predicted. Impacts on air quality thatcould result from any growth associated withthe facility must also be analyzed.

Although coal mines are not subject to PSDreview under Federal regulation, State PSDpermits are required for most coal mines inNorth Dakota and Montana. Under proposedState rules, PSD permits for coal mines inWyoming may be required, but final adminis-trative action has not yet been taken.

Implications of the Clean Air Act forFederal Coal Development

Fugitive dust emissions are the only type ofcoal mine emission that has the potential forviolating national or State ambient air qualitystandards. Annual mean TSP concentrationshave 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 TSPat Colstrip was 92µg/ms, the next highest con-centration was 48.1µg/ms, at Ekalaka in east-ern Montana, A 120-mi 2 area surroundingColstrip was designated as a nonattainmentarea in 1978 (fig. 44). Surface mining ac-tivities surrounding the town are consideredthe primary source of fugitive dust.

Ambient air quality standards have not yetbeen violated at Gillette, Wyo. However, theWyoming standard for maximum 24-hourTSP concentration is reportedly being ex-ceeded at some mines.6

Roads are the major source of fugitive dustfrom surface coal mining operations and gen-erally are responsible for twice as manyemissions as the next most important source.Other sources of fugitive dust include unittrains, coal storage and processing facilities,spoil piles, and reclamation areas. Options

‘Personal communication with the Wyoming Department ofAir Quality, Sheridan Office.

Figure 44.—Colstrip TSP Nonattainment Area

R. 40 E I fi R. 41 E I R.42E

N

t

Iia I T. 2 N.

i~Bur l ing ton

Northern

SOURCE: U.S. Geological Survey and Montana Department of State Lands,Draft Environmental Statement for Proposed Expansion of Miningand Reclamation Plan, Big Sky Mine, 1978, fig, 11-11


for controlling fugitive dust emissions in-clude:

I. periodic watering of unpaved roads;2. chemical stabilization of unpaved roads;3. paving of roads;4. enclosing, covering, watering, or other-

wise treating haul trucks and railroadcars;

5. substituting conveyor systems for haultrucks;

6. minimizing the area of disturbed land;7. prompt revegetation of regraded lands;

and8. covering coal storage areas.

Some of these options are employed at eachsurface mine in the West. Most mines inCampbell County, Wyo. pave their haulroads. Closed conveyor systems replace truckhaulage at Gulf’s McKinley Mine near Gallup,N. Mex., and at AMAX Coal’s Belle Ayr Minesouth of Gillette. All mines water haul roadsand revegetate topsoil s tockpiles . Manymines now enclose their coal storage areas.

Operations in Nonattainment Areas

The Colstrip, Mont. area has been desig-nated a nonattainment area for TSP. In De-cember 1979, Western Energy filed a petitionagainst the nonattainment designation withthe Montana Department of Health and Envi-ronmental Sciences and EPA. Monitoringdata indicate that the TSP problem existsonly in the immediate vicinity of Colstrip andnot in the entire 120-mi2 area. However, noredesignation has yet been made. T Criteria forapproval of new facilities in nonattainmentareas are subject to careful regulatory review.Sources of fugitive dust, most notably West-ern Energy’s Rosebud Mine, must developplans to limit emissions so that TSP concen-trations will eventually meet standards. Also,no new facilities may be approved unless itcan be shown that the new facility will notadd to emissions in the area.

7Montana Department of State Lands, Final EnvironmentalImpact Statement, Western Energy Company’s Rosebud Mine,Area B Extension, 1980.

Western Energy has initiated measures toreduce emissions, including seeding of lawnsin the town, paving of some roads, and chem-ical treatment of some haul roads. However,construction of two new powerplants in thetown makes future compliance with TSPstandards uncertain. As long as nei therPeabody Coal, which operates the Big SkyMine, also in the nonattainment area, norWestern Energy proposes increasing theircurrent capacities, their future applicationsfor extending their mines will probably not beaffected. However, increasing capacities andconstruction of new facilities cannot be ap-proved under SIP unless Western Energy candemonstrate reduction of other emissionssuch that emissions from expanded produc-tion will not increase total area emissions,Because Western Energy plans on extendingcapacity by 5 million tons per year in 1984,the company will have to either achieve otheremission reductions by that time or gain afavorable decision on redesignation of thenonattainment area.

Operations in the Wyoming Portion ofthe Powder River Coal Basin

As noted, TSP levels in portions of thePowder River coal basin in Wyoming are ap-proaching the limits set by State ambientstandards. Already, mines are installing con-trols, including paving of many roads. How-ever, the magnitude and concentration ofmines make compliance difficult (fig. 45). Inparticular, north of Gillette, where the Buck-skin, Rawhide, and Eagle Butte Mines are ad-jacent to one another, as well as to the unde-veloped South Rawhide, Dry Fork, and EastGillette leaseholds, compliance with TSPstandards at higher than existing productionrates is of increasing concern. South ofGillette, the Caballo, Belle Ayr, Rojo Caballos,and Cordero Mines are adjacent to oneanother. Total 1979 production at these fourmines was 20.1 million tons, but may expandto about 30 million tons in 1985 (see ch. 7).Although modeling of TSP concentrationshas indicated compliance with standards atpermitted 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 ofGillette, Wyo.

105 037’30”44 “30’

44 000’

43°30’

lckskin

4

North Rawhide *I

i=3Eagle Butte1

d

Fort Union 31 3.r

ISouth Rawhide ~ ~(proposed) -g

% !G~Eaet Giliette@ropoeed) “ !

I

- Belie Aw .0

105 037’30” 105 000’

SOURCE’ U S. Office of Surface Mining, Draft Environmental Statement Pro-posed Mining and Reclaimation Plan, RO jO Caballos Mine, 1980,fig. 1-1.

ming Air Quality officials have expresseduncertainty about the accuracy of thesemodelling projections.8 Expansion of miningat the Jacobs Ranch and Black ThunderMines in southern Campbell County may in-crease local TSP concentrations in that area,as well.

‘Personal communication to OTA, Wyoming Air QualityBureau Staff, Sheridan.

If air quality standards are not met, por-tions of Campbell County could be designatednonattainment areas, despite prior issuanceof air qual i ty permits . Such designationwould require development of mitigation pro-grams and reevaluation of each operation’sfugitive dust control plan. Although produc-tion rates would probably not be affected, ad-ditional control measures might be required.

Some new mines in Campbell County havenot obtained approval of their proposed max-imum production rate. For example, the BlackThunder Mine received a permit for a max-imum production level of 20.5 million tons peryear although it applied for a 30 million tonsper year maximum rate. Modeling had indi-cated that production greater than 20.5 mil-lion tons per year would have resulted inemissions exceeding TSP standards. BlackThunder’s planned production for 1991 is20.5 million tons per year; it currently has tosupply contracts 16.5 million tons per year in1991. (See ch. 7.)

To date, Wyoming has issued permits forexisting and proposed mines in Campbell andConverse counties that could accommodateover 250 million tons per year (table 85), Thisis three times total production from the entirePowder River basin in 1979 and is higherthan OTA’s high scenario estimate for coalproduction from all Federal mines in the en-tire Powder River basin, including the Mon-tana portion, in 1991. Only three undevelopedFederal lease blocks in these two countiesconsidered by OTA to have favorable produc-tion prospects for 1991 have not yet gainedair permits (table 85). Each of these leases isexpected to receive a permit for some level ofproduction. Six Federal lease blocks have airpermits in excess of their expected 1991 ca-pacity and three lease blocks will have 1991capacities in excess of air permits (table 85).

Under OTA’s low demand scenario for thePowder River basin, only the Rochelle andAntelope lease blocks would need to acquireair permits to meet projected productionlevels. Permits are expected to be issued forboth lease blocks. Under OTA’s high demandscenario, the Buckskin, North Rochelle, South


Table 85.—Air Permits and Production Scenarios for Mines in Campbell andConverse Counties, Powder River Basin, Wyo.

1991 OTA 1991 OTAhigh demand low demand

Approved 1991 scenarioMine

scenarioair permit capacity production production

Developed-FederalBuckskin . . . . . . . . . . . . . . . . . . . . . . . . . 6Rawhide . . . . . . . . . . . . . . . . . . . . . . . . . . 24Eagle Butte . . . . . . . . . . . . . . . . . . . . . . . 29Wyodak . . . . . . . . . . . . . . . . . . . . . . . . . . 5Caballo . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Belle Ayr. . . . . . . . . . . . . . . . . . . . . . . . . . 25

Rojo Caballos . . . . . . . . . . . . . . . . . . . . . 20Cordero . . . . . . . . . . . . . . . . . . . . . . . . . . 24Coal Creek . . . . . . . . . . . . . . . . . . . . . . . . 18Jacobs Ranch . . . . . . . . . . . . . . . . . . . . . 16Black Thunder. . . . . . . . . . . . . . . . . . . . . 20.5Dave Johnston. . . . . . . . . . . . . . . . . . . . . a

Developed—non-FederalFort Union . . . . . . . . . . . . . . . . . . . . . . . . 1.2Clovis Polnt . . . . . . . . . . . . . . . . . . . . . . . 4.0

Undeveloped-favorabledevelopment prospectsFederalNorth Rochelle . . . . . . . . . . . . . . . . . . . . —Wildcat . . . . . . . . . . . . . . . . . . . . . . . . . . . 10South Rawhide . . . . . . . . . . . . . . . . . . . . 7Dry Fork . . . . . . . . . . . . . . . . . . . . . . . . . . 15East Gillette . . . . . . . . . . . . . . . . . . . . . . . 11Rochelle . . . . . . . . . . . . . . . . . . . . . . . . . . —North Antelope . . . . . . . . . . . . . . . . . . . . 5Antelope . . . . . . . . . . . . . . . . . . . . . . . . . . 12b

6.224255

12

11

1524121620.5

3.8

05.0

6.2 5.530.7 14.235.2 29.2

4.9 4.0included in Rawhideestimatesincluded in EagleButte estimates12.5 5.020.5 9.710.1 4.215.3 11.719.4 14.63.8 3.3

— —— —

000005.34.47

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 Bureaurecords. 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 areexpected to need air permits to accommodatehigher production; between them, Buckskinand South Rawhide would need permits for2.0 million tons per year of additional produc-tion under the OTA high demand scenario.Permits for capacities in excess of the ex-pected capacity of 22 million tons per year atNorth Rochelle, Rochelle, and Antelope areexpected to be issued.

implications for Onsite Powerplantsand Synfuels Facilities

Lignite in North Dakota will be mined forconsumption by local powerplants or syn-thetic fuel plants. Because of its low heat con-tent and tendency to combust during trans-port, lignite is, with one exception, notshipped long distances. Future expansion oflignite mining in North Dakota is contingent

on continued development of mine-mouthpowerplants and synthetic fuel plants.

However, the prevention of significant de-terioration (PSD) provisions of the Clean AirAct may delay or limit the future developmentof new power or synthetic fuels facilities i nwestern North Dakota. Although there are nononattainment areas in the State, the Lost-wood Wilderness Area and the TheodoreRoosevelt National Memorial Park are man-datory Federal class I areas.

Air quality monitoring and modeling con-ducted by the North Dakota State Depart-ment of Health suggests that available airquality increments o f S 02 a t T h e o d o r eRoosevelt National Park may be exceeded ifadditional powerplants or synfuels facilitiesare permitted in west-central North Dakota.In 1978, using a model developed by EPA, theDepartment of Health obtained results that


indicated that the operation of seven coalconversion units under review at that timewould result in S02 concentrations that wouldexceed allowable standards for the nationalpark.

These permit applications included UnitedPower Association’s Coal Creek units 1 and 2,Montana Dakota Utilities’ Coyote No. 1 facil-ity, Great Plains Gasification Associates’ coalgasification plants, phase I and II, and BasinElectric’s Antelope Valley Station units 1 and2 (fig. 46). Because Basin Electric was the lastorganization to file a building permit applica-tion, the company had to redesign its plants to

reduce S0 2 emissions. Basin Electric resub-mitted its application and was subsequentlygranted permission to build. According to themodel, the Basin Electric project left no roomfor additional concentrations of S0 2 at thepark.

Based on the results of their modeling, theNorth Dakota State Department of Health hasnot granted any additional permits, beyondthe seven listed above, for construction ofnew coal conversion facilities east of thepark. Although powerplant operators havemaintained that the EPA model used to esti-mate remaining SO2 increments at Theodore

Figure 46.—Relationship of Recently Permitted (1979) Sources to the Theodore Roosevelt National Park(wind flow vectors indicated)

, - - .I1

.

SOURCE: U.S Bureau of Land Management, Final West-Central North Dakota Regional Environmental Impact Statement on Energy Development, 1978.


Roosevelt National Park is not rel iablebeyond distances of 50 to 70 kilometers, no al-ternative modeling data has yet been foundacceptable by the State. Most of the develop-ment in Mercer and Oliver Counties is takingplace more than 150 kilometers from thepark. Work on improving modeling tech-niques is currently underway at the NorthDakota Department of Health.

The coal industry must also compete withexpansion of oil and gas production for airquality increments. Because North Dakota’sWestern oil and natural gas resource areasoverlap the Fort Union lignite region, gasextraction and refining facilities located nearTheodore Roosevelt National Park wouldcompete directly with coal development forany available sulfur dioxide increments. Ingeneral , oi l and natural gas productionwould not involve major air quality consid-erations; however, much of the gas in thisarea is sour (i.e., contains up to 24 percenthydrogen sulfide) and presents potential airquality problems when flared or treated insweetening plants. If additional class I incre-ments at Theodore Roosevelt National Parkbecome available, some could be assigned tothe expansion of the natural gas industry.

At some point, additional lignite develop-ment may be dependent on the ability of lig-nite consumers to design and site facilitiesthat do not affect the air quality of class Iareas. If increments remain unavailable, po-tential developers of new coal conversionfacilities will have two choices—either obtainoffsets from existing facilities or obtain Gov-ernment-issued variances. The first of thesetwo options is unlikely to be successful.Most of the existing and permitted facilitiesare new and thus have already been fittedwith advanced sulfur dioxide control tech-niques. In the case of the second alternative,the State so far has appeared unwilling to ex-ercise its authority allowing waiver of PSDrequirements under certain circumstances topermit degradation of the air quality ofTheodore Roosevelt National Park. Pro-posed facilities affected by the situation arelisted in table 86, However, the situation re-

Table 86.—North Dakota Department of HealthPending Air Emissions Permits

Company Operation Type Capacity

Nakota

Basin ElectricBasin ElectricWarren

Petroleum

AMOCO

MinnesotaPower & Light

Unnamed Coal tomethanol 96,000 bbl/d

AVS Ill Powerplant 500 MWSunrise Powerplant 1,000 MW

Sour gastreatment 30 MCF/d

Sour gastreatment 100 MCF/d

Powerplant 1,000 MW


mains unresolved. Considerable uncertaintystems from the fact that five permitted fa-cilities have not yet been built and thereforetheir effect on air quali ty can only beestimated.

In Wyoming, class I designations and Statesulfur standards may also affect onsite facil-ities construction. Class I areas have beenproposed both for the Cloud Peak PrimitiveArea in the Bighorn Mountains west of theWyoming portion of the Powder River basinand for Devils Tower to the east. State gov-ernments and Tribal governing bodies aresolely responsible for making such a redesig-nation determination. Air quality considera-tions may constrain the eventual level of syn-fuels development in the Powder River basinand southern Wyoming, but probably not dur-ing the next 10 years. However, Wyoming’ssulfur dioxide emission standard, which ismore stringent than the national standard(table 83) could create difficulties for onsitedevelopment of coal reserves with high levelsof sulfur. Two undeveloped Federal leasetracts (the Belco tract in the western PowderRiver basin and the Cherokee tract in south-ern Wyoming) that have reserves sufficient tosupply a power or synfuels plant would re-quire more than 95 percent sulfur reductionto meet the State standard. * Sulfur removalefficiencies exceeding 95 percent could beachieved, but would be expensive.

*The Belco tract is expected to be traded for other Federalcoal 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 SMCRAUnsuitability Petition Process

Under the SMCRA unsuitability petitionprocess, areas may be designated unsuitablefor coal mining if it can be shown that min-ing operations will “affect fragile . . . landswith significant damage to important. . .aesthetic values or natural systems” (30CFR 762.11(b)(2)). In the Alton coalfield ofsouthern Utah, an area including 28 undevel-oped Federal leases covering 26,693 acres(fig. 47), several petitioners, including locallandowners and three national conservationgroups, alleged, among other things, thatthe visibility and air quality values from andwithin Bryce Canyon National Park wouldbe threatened by coal mining. (The park is amandatory class I attainment area under theClean Air Act. ) The OSM’s analysis of theseallegations used PSD standards as an evalu-

ative benchmark. 9 OSM found that 24-hourPSD class I increments could be exceededone or two times a year in a small portion ofthe park. OSM also found that visibilitywould be locally reduced by dust plumesfrom mining and coal trucks. There was con-flicting data from other sources that PSD in-crements would not be exceeded. The finaldecision by the Secretary of the Interior todesignate 9,049 Federal lease acres of theproposed petition area as unsuitable wasbased on the finding that mining in part ofthe area would impair scenic vistas visiblefrom the park and that high noise levelswould occur in some areas within the park,thus damaging the values for which the parkwas established.

“See U.S. Department of the Interior, Statement of ReasonsSupporting Secretarial Decision on Petition to Designate Cer-tain Federal Lands in Southern Utah Unsuitable for SurfaceCoal Mining operation, Jan. 13, 1981, OSM ref. No, 79-5-001,pp. 13-14.

— —— -— —- . - — .- . . . .


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”

32T.33s.

34

35

36

37

36

39

40

41

42

T.43s.

37“T,41N.

40

T.39N.

Provo

UTAH Price

Milford/’

Dixie National Forest

f

Index map showing location of the petition areaJ d

!Ea*il%?&#aw .A

. . .

aKnown recoverable coal

Eresource area (KRCRA)

Known recoverable coairesource area (KRCRA)

Boundary ofPetition area

I ~ Area east of dashed ilne in-L –n - / w \ dlcates portion designated

unsuitable for mlnln~

\\

#“ I KanabCoal leasesExisting leases on Federal lands

Preference right lease application(PRLA) on Federal lands

Existing leases on State lands

Coal slurry line, Nevada ElectricInvestment Co., et al., to WarnerValley and Harry Allen generatingstations

Proposed Union Pacific Railroad iMilford, Utah

m ForestDixie National PR4 f%oposed Union Pacific Railroad 1

Cedar City, UtahR. 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.


Water Resources

Water is a scarce and valuable commodityin the West and concern for the water re-source is indicated in detailed Federal andState regulations. Ground and surface waterhydrology data required of proposed coalmine operators is more extensive than anyother type of data.

Several aspects of the water resourceissue could affect Federal coal development.However, none has yet resulted in disap-proval of a mine plan. Potential for selectedprohibitions exists in cases where water sup-ply diminution or degradation becomes un-avoidable, and alternative supplies cannot beidentified. Conflicts with other water usersexist in virtually every coal region; this studyhas not attempted to analyze these conflictsin any detail.

Water resource concerns could result inthe prohibition of mining in some areasunder the unsuitability petition process.These concerns were part of the Alton coal-field petition but were not critical to the finalsecretarial decision, because insufficient in-formation was available on which to make adetermination. The decision noted that thehydrological impacts of proposed miningoperations would be reviewed when a mineplan was submitted for approval underSMCRA.10 Water resource concerns are cen-tral to a recently filed petition for a part ofthe Tongue River drainage basin in south-eastern Montana (see also ch. 9).

The availability of water for use by mines,particularly where irrigation is necessary forreclamation in the Green River-Hams Forkand San Juan River regions may ultimatelyconstrain coal development. However, OTAdid not identify any areas where such a con-straint was imminent.

10 Ibid, The Alton lessees submitted a mine plan for the Proj-ect before SMCRA regulations were implemented. The mineplan has not been updated to incorporate additional surfacemining permit requirements.

The extent of regulatory control overwater resource issues has been the subject ofcriticism from the coal mining industry.These criticisms are identified and sum-marized in this section; however, a detailedstudy of increased costs and time delays at-tributed to these regulations is beyond thescope of this report.

General Impact of Coal Mining onWater Resources

Coal mining activities affect water bothdirect ly through disturbance by mining,indirectly through powerplant facility devel-opment, and potentially through transpor-tation by coal slurry pipelines. Primary at-tention has centered on the direct impact ofsurface mining, particularly on disruption ofground water flow and quality. Recently, re-search has begun on the impacts of under-ground mining and related subsidence onwater resources.

The opening of a pit for surface miningaffects the level and flow of ground waters.The mine pit will intercept all ground watersthat are found above the pit floor. Directionsof ground water movement may change andeven reverse as water surrounding the pit inall directions flows toward the pit. As waterflows into the pit, water levels in surround-ing areas, as evidenced in wells, will fall. Ulti-mately, an equilibrium condition is estab-lished based on the characteristics of thewater-transmitting rocks (aquifers) and thelength of time the pits are open. Monitoringstudies have measured the offsite extent ofdrawdown, as the lowering of the groundwater level is termed, 2 miles from an activepit.11

Water qua l i ty can a l so be a f fec ted .Ground water moving through backfilled

11Van Voast and Hedges, Hydrologic Aspects of Existing andProposed Strip Coal Mines Near Decker, Southeastern Mon-tana: Montana Bureau of Mines and Geology Bulletin 97.1975.


surface mines is known to have substantiallyincreased concentrations of total dissolvedsolids and other constituents. Generally, theaverage concentration of dissolved solids istwo to three times greater in spoil watersthan in the waters in undisturbed coalaquifers.

The overall potential changes are suchthat Congress, OSM, and the various Stateshave developed comprehensive requirementsfor the prediction and monitoring of groundwater impacts from surface mines.

Impacts of sedimentation and pollution onsurface waters are more easily understoodand monitored. The primary impact , in-creased sediment loads in streams caused byerosion of mine and reclamation areas, caneffectively be controlled by construction ofsedimentat ion ponds at drainage outletsfrom mines. Surface waters can also be af-fected by seepage of polluted ground watersinto receiving streams. Although not ob-served to date, this possibility is the basis ofthe Northern Plains Resource Council un-suitability petititon for the Tongue Riverarea. The petition is partly based on a pub-l ished modeling study predict ing thisi m p a c t .

Subsidence from underground coal mininghas been documented to impact water re-sources and the subject is receiving increas-ing study. Subsidence cracks have caused in-terception of spring flow, ground water flow,and stream flow at locations in the Uinta-Southwestern Utah coal region.13 Since sub-sidence is an expected aspect of all under-ground mining, regulatory concern overassociated environmental impacts is grow-ing. Subsidence monitoring has been re-quired at several underground mines as acondition of permit approval.

12Woessner, Osborne, Heffern, Whitman. Spotted Elk, andMorales-Brink, Hydro~ogic lrnpacts from Potentiul COOI SfripMining, Northern Cheyenne Reservation. report 10 the EPA In-dustrial Environmental Research L[iboratory, Cincinnati, Ohio,1980.

13‘Dunrud, Some Engineering Geologic Factors (lmtroliing(lx]] Mine Subsidence in U(ah und (ldormh), USGS ProfessionalPaper 969, 1976.

Powerplants and synthetic fuel plants areaffected by Clean Water Act provisions re-lat ing to discharge l imitat ions. Effluentstandards are not a significant impedimentto construction of these facilities, however.The availability of water and restrictions onwater usage under interstate water use com-pacts and State law have affected the con-struction of coal slurry pipelines and, tosome extent, the construction of power-plants,

Statutory Control

Major regulatory review of the waterresource impacts of mining proposals is con-ducted under the mandate of the SMCRAand the Clean Water Act. Water resourcedata is a major component of a mine permitapplication and compliance with severalwater resource performance standards mustbe demonstrated before an application canbe approved. Mines must also obtain a per-mit to discharge effluents from an operationunder provisions of the Clean Water Act.Thus, the agencies most responsible forreview of water resource impacts are OSMand companion State reclamation agenciesand EPA and companion State water qualityagencies. The following section reviews someFederal statutes and regulations over waterresources. Implementation in each of theWestern States varies slightly and may bemore stringent than outlined here. No Statehas less stringent provisions.

The SMCRA establishes conditions forpermit approval or denial:

No permit or revision application shall beapproved unless the application affirma-tively demonstrates and the regulatoryauthority finds in writing , . . that:

(3) the assessment of the probable cumula-tive impact of all anticipated miningin the area on the hydrologic bal-ance . . . has been made by the regula-tory authority and the proposed oper-ation thereof has been designed to pre-vent material damage to hydrologicbalance 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 establishesperformance standards related to water re-source impacts. A permit application mustdemonstrate, among other things, that thesestandards can be complied with before ap-proval is obtained:

General performance standards shall beapplicable to all coal mining and reclamationoperations and shall require the operation,as a

(2)

(4)

(8)

(lo)

minimum to—restore the land affected to a conditioncapable of supporting the uses which itwas capable of supporting prior to anymining, or higher or better uses ofwhich there is reasonable likelihood, solong as such use or uses do not . . . poseany actual or probable threat of waterdimunition or pollution . . . .stabilize and protect all surface areasincluding spoil piles affected by the sur-face mining and reclamation operationto effectively control erosion and at-tendant . . . water pollution , . .create, if authorized in the approvedmining and reclamation plan and per-mit, permanent impoundments of wateron mining sites as part of reclamationactivities , . .minimize the disturbances to the prevail-ing hydrologic balance at the mine-siteand in associated offsite areas and to thequality and quantity of water in surfaceand ground water systems both duringand after surface coal mining operationsand during reclamation by—(A) avoiding acid or other toxic mine

drainage . . .(B)(i) conducting surface coal mining

operations so as to prevent, to theextent possible using the besttechnology currently available,additional contributions of sus-pended solids to streamflow, orrunoff outside the permit area,but in no event shall contributionsbe in excess of requirements setby applicable State or Federallaw;

(ii) constructing any siltation struc-tures . . . prior to commencementof surface coal mining opera-tions . . .

(c)

(D)

(E)

(G)

cleaning out and removing tem-porary or large settling ponds orother siltation structures fromdrainways after disturbed areasare revegetated and stabilized;and depositing the silt and debrisat a site and in a manner ap-proved by the regulatory author-ity;restoring recharge capacity of themined area to approximate pre-mining conditions;avoiding channel deepening orenlargement in operations requir-ing the discharge of water frommines , . .such other actions as the reg-ulatory authority may pre-scribe . . .

The purpose of these requirements is to en-sure that long- and short- term adversechanges in the hydrologic regime that mightbe caused by coal mining and reclamation ac-tivities will be prevented or minimized.

OSM promulgated comprehensive regula-tions pursuant to these statutory provisions.The major subject areas of the regulations ofconcern to Western mining are:

● water quali ty standards and effluentlimitations,

● diversions, sediment control, and sedi-mentation ponds,

● impoundments,● protection of ground water and ground

water recharge capacity,● monitoring,• water rights, and• stream buffer zones.

Additional regulations concern alluvial val-ley floors; these provisions are discussed in alater section.

Water Quality Standards andEffluent Limitations

Control of discharges from mining andreclamation activities is jointly controlled byOSM and the agency responsible for imple-mentation of the Clean Water Act in eachState. Under sections 301, 304, and 401 of

— —— . .


the Clean Water Act, mining operationsmust obtain discharge permits and complywith EPA, or State effluent, limitations forpoint source discharges of pollutants to sur-face waters. However, the Clean Water Actpermit system applies only during the activephase of mining; it does not extend to recla-mation, nor does it cover nonpoint pollutionsources, nor does it consider discharges toground water. However, under SMCRA allwater discharged as a result of coal miningand reclamation act ivi t ies which couldmaterially damage the hydrologic system isregulated. Thus, coal mines must obtain apermit to discharge from EPA, or adminis-tering State water quality agency, for allpoint source discharges. These dischargesinclude effluents from plant facilities anddischarge of ground waters intercepted in amine pit. OSM, or State reclamation agency,review also considers other types of dis-charges such as those from reclamationareas, as well as providing input in thereview of point source discharges.

Effluent limitations established by OSMare generally similar to those adopted byEPA (table 87). In each State, any stricterstandards supersede these Western regionalstandards. For instance, the Montana Stateimplementation program of the Clean WaterAct includes a provision that no dischargemay degrade the quality of receiving waters,regardless of conformance with specific ef-fluent limitations. At most Montana coalmines, the necessity to meet this criterion isa stricter one than are the direct effluent lim-itations.

Table 87.—Effluent Limitations for Western CoalMines in Milligrams per Liter (mg/l)a

Average of dailyvalues for 3 0

Max imum consecut iveEff luent character ist ics allowable discharge days

Iron, total . . . . . . . . . . . . . . . . 7.0 3.5Manganese, total . . . . . . . . . 4.0 2.0Total suspended solids . . . . 45.0 30.0aEPA 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, andSedimentation Ponds

Sedimentation ponds in conjunction withother sediment control measures, are con-sidered by OSM to be the “best technologycurrently available” to prevent offsite sedi-ment increases, as required by SMCRA.Generally, OSM and State reclamation agen-cies require that ponds be constructed ondrainages below all mining and reclamationdisturbance areas. Regulations establishmany of the design characteristics of theseponds, including their sediment storage vol-ume, detention time, dewatering devices,methods to prevent short circuits, * spillwaydesign, sediment removal, freeboard,** andengineering characteristics of the retainingdam.

In conjunction with sedimentation ponds,OSM regulations require sediment controlmeasures within and around disturbed areas.These measures include:

• disturbing the smallest area practicableat 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 diver-sions are also outlined in regulation.

Impoundments

Regulations also establish minimum stand-ards for permanent and temporary impound-ments. These impoundments include anylakes or ponds proposed to become part of areclamation landscape. Section 515(b)(8) ofSMCRA establishes that permanent impound-ments may only be constructed if six criteriaare met:

● that the impoundment size is adequatefor its intended purpose;

*Short circuiting: a process which transports sedimentthrough a pond in less than the detention time necessary forthe sediment to settle out.

**Freeboard: the height above the water surface level whenthe spillway is operating at design capacity.


●

●

●

●

●

that the impoundment dam is designedto achieve necessary stability;that the quality of impounded waterwill be adequate for its intended use;that the impoundment water level willbe reasonably stable;that water users will be provided ade-quate safety and access; andthat adjacent landowners will not be ad-versely-affected by the impoundment.

Adopted regulations establish design cri-teria for impoundments and dams, and re-quire inspections, maintenance, and initialcertification.

Protection of Ground Water and GroundWater Recharge Capacity

SMCRA requires that the ground waterportion of the hydrologic system be pro-tected along with the surface water portion.Regulations have been adopted which gener-ally require that backfilling and alinement ofexcavations be conducted so as to protectground water outside the permit area.

SMCRA also requires that the rechargecapacity of the mined area be restored to theapproximate premining condition. Concep-tually, recharge capacity is the ability of thesoil and rock materials to receive water,store it for a period of time, and slowlyrelease it, either to a topographically lowerstream or lake, or to a well. Primarily, themovement of precipitation and surface waterinto the soil or rock materials is controlled bythe infiltration capacity of those materials.Mining and reclamation have the potential ofchanging infi l t rat ion capacity, primari lythrough compaction.

Monitoring

Operators are required under SMCRA tomonitor ground water and surface waterquantity and quality on the permit area andin the surrounding area before, during, andafter mining. The extent of the requiredmonitoring varies, but must be sufficient todescribe the premining environment and toprovide enough data for evaluating the ef-

fects of mining and reclamation activities.Monitoring is required of all ground or sur-face waters which may be disrupted or de-graded by mining.

Water Rights

Water rights issues are considered in thecontext of the State laws applicable in eachState. OSM had developed regulations onthe water rights issue; however, these wereremanded in the Flannery decision (see p.283), Generally, in each State, coal miningoperations must replace any water suppliesexpected to be degraded or diminished bythose activities.

Stream Buffer Zones

Disturbance of a perennial stream must bespecifically approved under SMCRA. Theregulatory authori ty must f ind that thestream channel will be restored and that un-disturbed portions of the channel will not beaffected.

Implications of Water Resource Issuesfor Federal Coal Development

Although no mine has yet been prohibitedfrom operating because of conflicts withother water users, the potential for conflictswith municipal, domestic or agriculturalwater users exists. Conflicts may be acute inthe Uinta-Southwestern Utah region. In allWestern States, water supplies diminished ordegraded by mining are required to be re-placed by the operator. In many cases, mineschoose to redrill nearby wells to deeperaquifers if impacts from mining are expected.The following discussion gives several il-lustrative examples of existing or potentialconflicts.

Municipal and Domestic Impacts

Surface and ground water originating inthe Wasatch Plateau of central Utah is usedby several municipalities. Local water usersare concerned that these waters may be in-tercepted or contaminated by underground


coal mining along the eastern edge of theplateau. For instance, the town of Hunting-ton, located near an active mining area, usesspring flow for its water supply. This springflow may be affected by nearby undergroundcoal mining. In the nearby Emery coal field,the town of Emery uses ground water thatcould be affected by Consolidation Coal’sEmery underground mine and proposed sur-face mine. The effects of this mining arebeing studied by the company and USGS.14

If mining were demonstrated to adverselyaffect municipal water supplies, mining com-panies would be required to replace thesesupplies or limit their mining areas.

In North Dakota, some lignite seams aresignificant aquifers. The Falkirk Mine ismining such a seam, which is also the watersource for the nearby town of Underwood.Little data are yet available on the impacts ofcontinued mining; however, the operator hasmade a commitment to provide alternativesupplies should disruption occur.

Agricultural Impacts

The North Fork Gunnison River Valley ofwest-central Colorado is an area where un-derground coal mining may affect the avail-ability of water for agricultural irrigation.Projected subsidence at the proposed Mt.Gunnison Mine may divert enough surfaceand ground water flow to adversely affectdownstream water users. 15 The State recla-mation agency and OSM are advising the op-erator that if this occurs, the company willhave to purchase or replace the affectedsenior water rights in the valley. Otherwise,the mining company may have to leave recov-erable coal in place in order to avoid subsid-ence and undesired water loss. Other minesin the Somerset coal field may face similarsituations if projections of subsidence indi-cate diversion of significant surface flow.

l+ Morri~sey, Lines, and Ba rtholoma, Three-Dim ensionui Di-gital-Computer Model of the Ferron Sandstone Aquifer nearEmery, Utah, USGS open file report.

l~personal Communication to OTA, Technical Analysis Divi-sion, Regional Director, Region V, OSM, 1981.

Concern about the effect of undergroundmine-induced subsidence on springs is wide-spread in the Wasatch Plateau. A landownerabove Utah Power & Light’s Deer Creek Minehas expressed concern about subsidence ef-fects on his springs, and the company has in-stituted a subsidence monitoring program toevaluate impacts. All operating or proposedmines in this area are developing monitoringprograms to measure subsidence and impactsto springs and surface waters.

At the non-Federal Absaloka Mine insoutheastern Montana in the Powder Riverbasin, controversy about the projected de-struction by surface mining of several seepsand springs has caused the operator, West-moreland Coal, to delay proposing mining ofthe presumed source area of most of thesprings. The State reclamation agency hopesthat continued monitoring will result in abetter understanding of the hydrologic sys-tem before mining is proposed for the re-charge area itself.

Throughout the Fort Union region andPowder River coal basin, numerous domesticand stock wells obtain water from shallowaquifers. For example, 60 to 70 percent ofwestern North Dakota’s domestic and stockwells tap shallow lignite aquifers. Each ofthese water sources, if destroyed, dimin-ished, or degraded by mining activities, is re-quired to be replaced.

Empire Energy Co. is proposing to mineseveral seams below the Yampa River innorthwestern Colorado in the Green River-Hams Fork coal region. Regulatory review isfocused on the projected effect of mine-induced subsidence on the river, both interms of environmental , and health andsafety impacts.

Water Resource Issues and the SMCRAUnsuitability Petition Process

The effects of projected mining on wateravailability were part of the Alton coalfieldunsuitability petition. The petitioners al-leged that water development necessary tomine and transport coal, and to help reestab-


lish vegetation, would result in the drying ofsprings and stream recharge cri t ical toagricultural water users in the same area.OSM found that “present users of . . . water. . . would be adversely affected.’’ ]’ ] In mak-ing his final decision on the petition, how-ever, the Secretary of the Interior found thatinsufficient information was available onthis issue on which to exclude areas frommining and that the issue would be reex-amined at the time of mine plan permitreview.

The Northern Plains Resource Counciland several affiliates have filed a petition fordesignation of lands unsuitable for miningfor a portion of the Tongue River drainagebasin in southeastern Montana. UnleasedFederal coal, as well as fee and State coalreserves, are affected by the petition. Inpart, the petitioners claim that large-scalemining would have significant regional im-pacts on water resources. They claim thatlarge-scale mining would have long-termdegrading effects on the stream, adverselyaffecting stock and irrigation water uses.Because the effects would be experiencedover a long time period, they fear that signif-icant degradation could take place and notbe identified until it was too late to initiateremedial measures. The petition is presentlyunder review and a decision is expected bythe State of Montana in late 1981.17

Other Water Resource Issues

Most of the water resource issues outlinedin the discussion on statutory control havehad no effect on the amount of Federal coalpermitted for mining. Although some of theprovisions have received substantial criti-cism from industry as being needlessly de-tailed and requiring unnecessary environ-mental protection, no Federal reserves havebeen prohibited from recovery because ofthese regulations. The issues of cost and

16U.S. Office of Surface Mining, Southern Utah Petition Eval-ua tion Document, Document Nos. OShf-PE-l and OSM-EIS-4,1980.

“Northern Plains Resource Council, Petitian far Designationaf Certain Lands Unsuitable for Mining, 1980.

time delay in collecting required informationare briefly considered at the end of thischapter, although a detailed examination ofthese issues was not undertaken in thisreport.

Water quality standards and effluent limi-tations have not had an effect on the out-come of the permitting process. EPA andOSM limitations are able to be met at allWestern mines. Some controversy has con-tinued over the standard for total suspendedsolids, which industry has claimed to be toostringent. These standards are being revisedto control total settleable solids, but the newstandards have not yet been released. In-dustry has criticized the number and size ofsedimentation ponds required of coal mines.These criticisms center around issues of in-creased costs. Construction of these ponds,particularly in steep canyons of the Uinta-Southwestern Utah region, has caused ex-tensive disturbance at some areas.

To date, no permanent impoundment hasbeen proposed under OSM regulatory pro-gram in the West. This may be because ofregulatory constraints or because no im-poundment has been needed for reclamation.The requirement to reestablish rechargecapacity has not caused any regulatorydenials; however, permit approval has beendelayed in some cases because the data sub-mitted was found to be insufficient. Monitor-ing requirements have been criticized asbeing overly demanding. However, in gen-eral, companies have apparently been able tobear these costs. The impact of these re-quirements on small operators is discussedin the final part of this chapter, Mining nearperennial s treams is general ly approvedunder special conditions. Mining of perennialstreams themselves has not generally beenapproved.

Water Availability: Primary andSecondary Impacts

Limited water supplies, and competitionfor those supplies, may ultimately affect theextent of coal mining development in por-

—


tions of the Green River-Hams Fork regionand in the San Juan River region. In thesewater-deficit areas, mines need water notonly for dust control and use in the facilities,but also for irrigation of vegetation on re-claimed areas. Irrigation is presently used atsome mines in the Green River-Hams Forkregion and all mines in the San Juan Riverregion. Recent studies in southern Wyomingof expanded coal leasing indicate that watershortages are possible as mines, growingmunicipalities, and agriculture compete forthe same water sources.18

Expansion of mining in the San Juan Riverregion may also be affected by limited wateravailability. Essentially, surface water isnonexistent in this area and wells must sup-ply all water needs. However, the Fruitlandformation aquifer is expected to be the pri-mary water supply for the uranium mining in-dustry in the area, as well as for municipal-ities. According to the OTA New Mexico taskforce, if both industries expand in the 1980’s,available water supplies may not be able tomeet demands.

Water availability may also affect coaldevelopment where coal development is de-pendent on onsite powerplants, synthetic fuelplants, or slurry pipelines. See table 88 for

18 U.S. Bureau of Land Management. Final Green River-HamsFork Regional Coal Environmental Impact Statement, 1980.

Table 88.—Total Water Requirements for VariousMajor Facilities, Northern Great Plains

Water needFacility (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- 8,000Slurry pipeline (35 million tons per year). . . 13,000-20,000


water requirements for these facilities. Scar-city of water in the Gillette area of thePowder River basin justified the expense ofconstructing the first dry-cooling tower in theUnited States at the Wyodak Power Planteast of Gillette. Proposed sources of water forslurry pipelines have been the Madison Lime-stone aquifer and the Little Bighorn River.Controversy surrounds the use of eithersource. Although Energy Transportation Sys-tems, Inc. (ETSI) has a permit from the Stateof Wyoming to withdraw about 20,000 acre-ft/yr from the Madison for its pipeline, theState of South Dakota is considering bringingsuit against such a water use, claiming ad-verse impact to its existing uses of the sameaquifer. The State of Montana has decidedthat use of water for slurry pipelines is spe-cifically not a beneficial use of water andwate r use pe rmi t s therefore cannot begranted for use of Montana water in coalslurry pipelines.

Alluvial Valley Floors

Under provisions of SMCRA, alluvial and regulating Government agencies. Indus-valley floors in the Western United States try has claimed that the alluvial valley floorare given special protection because of their provisions are overly complex, lead to signif-agricultural and hydrologic importance. The icant delays in processing permits, and maymore important alluvial valley floors are pro- ultimately lead to significant loss of recover-tected from coal mining and its associated able reserves.disturbance. The less important al luvialvalleys may be mined, but standards for rec-lamation are higher than for other types of 1.mined areas. The impact of the alluvialvalley floor statutory provisions, adoptedregulations, and guidelines have been thesubject of continued debate among industry

Analysis by OTA has found that:

To date, for Federal mines, only onestream valley in the West (SquirrelCreek Valley in Montana) has been iden-tified as having the characteristics thatwill probably lead to absolute prohibi-


2.

3.

4.

5.

6.

tion of mining activities in a portion ofthe valley. The affected companies haveasked tha t t h i s dec i s ion be r econ-sidered.Numerous stream valleys in the PowderRiver coal basin have been, or are likelyto be, identified as having characteris-tics that will allow mining, but understringent alluvial valley floor reclama-tion standards.Neither OSM, nor any State reclama-tion authority, has approved a proposedreclamation plan for an alluvial valleyfloor under the permanent regulatoryprogram. Thus, no regulatory decisionshave yet been made on which to analyzethe detail and expense that reclamationof alluvial valley floors will necessitate.The general perception of both industryand Government officials is that mostalluvial valley floors are reclaimableunder existing technologies. Subirri-gated alluvial valley floors pose thegreatest difficulties for reclamation.Alluvial valley floors have been iden-tified under formal regulatory processesin the Powder River coal basin, andmost leaseblocks in that basin are ex-pected to include some areas of desig-nated alluvial valley floor, Alluvialvalley floors are also important in theFort Union coal region. In the GreenRiver-Hams Fork coal region and theUinta-Southwest Utah coal region fewalluvial valley floors have been iden-tified,The alluvial valley floor issue has thepotential to affect more tonnage ofrecoverable coal than any other en-vironmental factor. However, in rela-tion to the total Federal recoverablecoal base under lease, and the marketsupply relationships anticipated to ex-ist until 1991, no adverse production ef-fects are expected in the next 10 years.Alluvial valley floor issues are likely toaffect non-Federal coal reserves to agreater degree than Federal reservesbecause of the concentration of non-Federal coal in major river valleys, the

sites of initialWest.

Background and

homesteading in the

Statutory Control

As a general description, alluvial valleyf loor s a re those s t r eam va l l eys in thewestern United States which: 1) are under-lain by unconsolidated gravel, sand, silt, andclay; 2) have a stream flowing through them;3) have a generally flat valley floor topo-graphic surface; and 4) have an agriculturalimportance (fig. 48). The relative importanceof these valleys is a function of the watersupplies available in the specific valley area.The agricultural activities generally includeirrigated or subirrigated hay lands, devel-oped pasture lands, critically importantgrazing areas, or lands that could be devel-oped for any of these purposes.

Alluvial valley floors were one of the morecontroversial portions of SMRCA, and wereextensively debated in Congress prior topassage of the act in 1977. The special rolethat alluvial valley floors play in Westernagriculture was central to the debate:

Of special importance in the arid andsemiarid coal mining areas are allu-vial valley floors, which are the produc-tive lands that form the backbone of theagricultural and cattle ranching economy inthese areas, For instance, in the PowderRiver basin of eastern Montana and Wyo-ming, agricultural and ranching operationswhich form the basis of the existing eco-nomic system of the region could not survivewithout hay production from the naturallysubirrigated and flood-irrigated meadowslocated on the alluvial valley floors.19

The provisions passed in the act includedspecific prohibition from mining certainalluvial valley floors, and stringent reclama-tion standards for those alluvial valley floorsthat could be mined. The prohibitions tomining are outlined in section 510(b)(5) of the

19 U. S. House of Representatives, Committee on Interior andInsular Affairs, Report Accompanying H.R. 2, the Surface Min-ing Control and Reclamation Act of 1977, House Report 95-218,95th Cong,, 1st sess., 1977, p, 116.


Figure 48.—Stylized Diagram of an Alluvial Valley Floor

Subirrigatedalluvium

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 nocoal mining operation may “interrupt, dis-continue, or preclude farming” on alluvialvalley floors, unless the lands that would bedisturbed are “of such small acreage as to beof negligible impact on the farm’s agricul-tural production. ” Alluvial valley floors usedas “undeveloped range lands” are not pro-hibited from mining.

Section 510(b)(5)(B) also states that coalmining must be prohibited if it would “mate-rially damage the quantity or quality ofwater in surface or underground water sys-tems” that supply those important alluvialvalley floors that are prohibited from min-ing. Thus, mining in areas near importantalluvial valley floors would be prohibited ifmaterial damage were projected.

For those alluvial valley floors not ex-cluded from mining under the provisions ofsection 510(b)(5), reclamation standards areestablished under section 515(b)(10)(F). Thissection states that a coal mine must “mini-mize the disturbances to the prevail inghydrologic balance . . . by . . . preservingthroughout the mining and reclamation proc-ess the essential hydrologic functions of

alluvial valley floors. ” This requirement to“preserve” both during and after mining “theessential hydrologic functions” is a regula-tion unique to alluvial valley floors.

Regional Studies of Alluvial ValleyFloor Occurrences and TheirRelationship to Recoverable

Coal Reserves

The first studies of the regional pattern ofalluvial valley floor occurrence were con-ducted prior to passage of the act. 20 T h eresults of these studies are summarized intable 89. Generally, these studies concludedthat less than 5 percent of the recoverablecoal reserves of the West would be affectedby alluvial valley floor provisions. Reexami-nation of these studies indicates that about 1percent of the reserves studied in the aboveinvestigations would likely be affected by thep roh ib i t i on p rov i s ions o f s ec t ion 510(b)(5), BLM, in 1980, estimated that almost 60percent of the available unleased Federalcoal in the Gillette, Wyo. area was overlain

20 Malde and Boyles, 1976; Schmidt, 1977; Hardaway, et al.,1977. See table 89 for full citations.


Table 89.—Alluvial Valley Floor Studies

Study areaunderlain by

strippable Amount orcoal or area of

amount of strippablestrippable coal coal overlain

Study Study area considered by AVF

Malde and Southeastern Montana 392,000 acres 10,500 acresBoyles, 1976

Schmidt, East-central Montana1977

Burns Creek- 2,640 mt 39.2 mtThirteenmile CreekKCLAWeldon-Timber Creek 657 mt 15.9 mtdepositRedwater River 582 mt 46.4 mt

Hardaway, Existing and proposed 914,000 acres 27,000 acreset al., 1977 mines, Western United

States

SOURCES Jack Schmidt. “Alluvial Valley Floors in East-Central Montanaand their relatlon to strippable coal reserves, ” Denver, Environ-mental 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 7½ 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, JackSchmidt and Larry Erickson. "Sub-lrrigated Alluvial Valley floors –A reconnaissance of their properties and occurrence on coalresource lands in the Interior Western United States: Louisville, ”Proceedings of Natoinal Coal Association/Bituminous CoalResearch Symposium, 1977, p. 61-135,

by potential alluvial valley floors. BLM madeno attempt to distinguish between areas likelyto be prohibited from mining and areas wherespecial reclamation standards would be re-quired. Examinations of this study by OSM in-dicate that BLM has also identified areas thatwill not be classified as alluvial valleyfloors. 21 Thus, the BLM study almost certainlygreatly overestimates alluvial valley flooroccurrence.

OSM identified alluvial valley floors in theAlton, Utah coalf ield.22 No a t t empt wasmade to distinguish between areas likely tobe prohibited from mining and areas wheremining would be allowed. Of the 325,000-acre area considered under the Alton un-suitability petition, less than 5 percent of thearea was designated as alluvial valley floorof either type.

“Personal communication: OSM Region V, Chief, Branch ofEarth Sciences and Geot echnics.

zzu .s. Office of Surface Mining, Southern Utah Petition Evac-uation Document, 1980.

Determinations Made by Federal andState Reclamation Agencies in the

Powder River Coal Basin

The Montana Department of State Lands,with the concurrence of OSM, has deter-mined that Squirrel Creek valley in Big HornCounty is an alluvial valley floor, portions ofwhich are being actively farmed and are sig-nificant to agriculture. The stream is a inter-mittent tributary of the Tongue River andcrosses portions of Federal coal leases heldby the Rosebud Coal Sales Co. (lease No.M-061686) and the Consolidation Coal Co.(lease No. M-46292). Areas with significantfarming activities total about 250 acres;however, the total alluvial valley floor, whichcontains Federal and non-Federal coal re-serves, is more than 1,250 acres. Alluvialvalley floors, although not necessarily signif-icant to farming activities, cover about 35percent of the Consolidation Coal proposedmine plan area and over 40 percent of theRosebud Coal Sales proposed mine planarea. 23

At this time, it is not known what effectthe alluvial valley floor determination willhave on mining in this area. Areas consid-ered significant to farming cannot be mined,even if they are reclaimable. On the onehand, it is possible that no mining of eitherlease will take place, particularly if the Mon-tana DSL determines that mining of adja-cent areas would result in “material damageto the Squirrel Creek Valley. ” On the otherhand, mining might still be able to take placeon the surrounding uplands. ConsolidationCoal intends to submit a proposed mine planfor nonalluvial valley floor areas in early1982. The companies have estimated that atotal of 100 million tons of Federal and non-Federal coal under both leases would be af-fected by the alluvial valley floor decision.24

State regulatory authorities, with the con-currence of OSM, have identified alluvialvalley floors that are considered not to be

24Nimick, personal communication, Montana Department ofStale Lands hydrologist, 1981.

“Ibid.

—


.—

significant to farming at the Buckskin, Raw-hide, Eagle Butte, and Coal Creek mines, alllocated in the Powder River coal basin ofWyoming (see table 90). The Coal Creek mine,operated by the Thunder Basin Coal Co. (asubsidiary of Atlantic Richfield Co.), ob-tained approval for its mine in early 1979and began coal shipments in late 1981. Regu-latory authorities designated 846 acres ofthe total proposed mine plan area, or about 9percent, as alluvial valley floors. Althoughinitial approval was obtained for the first 5years of mining, the regulatory agencieshave stated that Thunder basin coal mustdemonstrate compliance with section 515(b)(l0)(F) of the act before any additionalmining wil l be approved. As discussed

earlier, section 515(b)(10)(F) requires anoperator to demonstrate that the “essentialhydrologic funct ions” of the designatedalluvial valley floors will be protected byminimizing offsite impacts and restoring thealluvial valley floors proposed to be mined.

Although only 9 percent of the total mineplan area has been designated as alluvialvalley floors, Thunder Basin Coal would beseriously constrained in mining the CoalCreek if the company could not demonstratecompliance with section 515(b)(60)(F).25 EastFork Coal Creek crosses the middle of themine plan area. The company maintains that

25Smith personal communication, President, Thunder Basin

Coal, 1980.

Table 90.—AlluviaI Valley Floor (AVF) Summary TableDeveloped Coal Reserves in the Powder River Basin

Acres of streamAcres of designated Acres of designated valley under

Federal lease AVF significant AVF not significant study asMine area (acres) to farming to farming potential AVF

Rosebud. . . . . . . . . . . . . . . . . . . 8,226 —a — 386Big Sky (g)b . . . . . . . . . . . . . . . . . 4,307 0 c 0 0

— — 275Spring Creek . . . . . . . . . . . . . . . . 2,347 0 0 0

— — 257West Decker (g) . . . . . . . . . . . . . . 4,961 0 0 0East Decker (g) . . . . . . . . . . . . . . 9,410 — — 386Buckskin . . . . . . . . . . . . . . . . . . 599 — 358 0

— — oRawhide(g) . . . . . . . . . . . . . . . . . 5,697 0 143 0

0 52 0Eagle Butte (g) . . . . . . . . . . . . . . . 3,520 0 126 0

— — 10Wyodak (g) . . . . . . . . . . . . . . . . . . 1,880 — — 240Caballo. . . . . . . . . . . . . . . . . . . . . 5,360 0 0 0

Belle Ayr (g) . . . . . . . . . . . . . . . . . 2,401 0 0 365Rojo Caballos . . . . . . . . . . . . . . 3,959 0 0 0Cordero (g) . . . . . . . . . . . . . . . . . . 6,560 — — 640

non-FederalCoal Creek . . . . . . . . . . . . . . . . . . 5,806 0 116 0

0 616 00 70 00 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 CreekEmile (Coal bank)L & Miller CouleeLee CouleeSpring CreekSouth Fork Spring CreekSpring & Pearson CreekDeer CreekRawhide CreekSpring DrawRawhide CreekLittle Rawhide CreekLittle Rawhide CreekDry Fork Powder RiverDonkey CreekTisdale Creek andGold Mine DrawCabal lo CreekClabaugh and Desmet DrawBelle Fourche River

Coal CreekE. Fork Coal Creek and TributaryMiddle Fork Coal CreekDry Creek Tributary

Little Thunder CreekBurning Coal DrawN. Prong Little Thunder Creekand Little Thunder Creek—

Totals:Federal lease acres . . . . . . . . 84,931 0 1,525 2,704Federal recoverable reserves

(million tons) . . . . . . . . . . . . 5,300 0 97 299a

—: Indicates no determination made.b

g: Refers to So-called "grandfathered mines;” that is, those mines which were operating prior to passage Of SMCRA.co: 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 CoalCreek would render the entire operation un-economic. The entire mine area containsseveral hundred million tons of recoverablereserves. Despite the uncertainty of thefuture regulatory decision, Thunder BasinCoal has proceeded with its development,and anticipates that mining approval will beobtained. Even if approval were not obtainedfor mining the stream valleys, examinationof mine plan maps suggests that the ulti-mate economic impact of a regulatory prohi-bition could be less than predicted by thecompany, Individual pits might be devel-oped on either side of the main stream: how-ever, at least 30 million tons underlying thestream would be lost.

Several regulatory decisions concerningalluvial valley floors are pending, and haveaffected the orderly development of mineplans. Alluvial valley floor studies are under-way, with decisions pending, at 10 mines inthe Powder River coal basin. OSM does notanticipate that any of the stream valleys inquestion will be designated significant tofarming, and thus be subject to prohibitionfrom mining.26 At those mines operatingprior to passage of the act, mine planninghas proceeded under the assumption thatmining of alluvial valley floors will be ap-proved. However, formal regulatory ap-proval has not yet been obtained. Plans formining and reclamation of valleys were sub-mitted by each mine in January 1981, as partof each mine’s permanent regulatory pro-gram submittal. As of late March 1981,review was proceeding but no State agencyhad had sufficient time to approve theseplans.

At two mines approved after passage ofthe act, Spring Creek and Buckskin, uncer-tainty about alluvial valley floor status andreclaimability has led each operator to avoidproposing the mining of areas of uncertainal luvial val ley f loor s tatus. Studies areunderway in each case that may show thatthe streams can be reclaimed. However, atleast temporarily, 59 million tons at Spring

26Kimball, personal communication, OSM, 1981.

Creek and 36 million tons at Buckskin arenot proposed for mining.

The position that State and Federal regu-latory agencies take toward compliance withsection 515(b)(10)(F) will have a significanteffect on the quantity of coal reserves af-fected by alluvial valley floor provisions. Ifindustry is able to demonstrate that the es-sential hydrologic functions can be protectedor restored during or after mining, then onlythose alluvial valley floors with significantagricultural activities on them will be pro-hibited from mining. In that case, it is likelythat only the Consolidation Coal and Rose-bud Coal Sales leases referred to above, af-fecting about 100 million tons of Federal andnon-Federal reserves, will ultimately be pro-hibited from mining,

Table 91 summarizes potential alluvial val-ley floor occurrences on all undeveloped Fed-eral leaseblocks in the Powder River coalbasin. Total estimated area of potential allu-vial valley floors is about 2,800 acres, whichmay include about 219 million tons of Federalrecoverable reserves. Thus, about 5 percentof the Federal recoverable reserve base ofundeveloped lease blocks in the Powder Riverbasin is overlain by potential alluvial floors.Another 2 percent of Federal recoverable re-serves in undeveloped lease blocks in thePowder River basin could be prohibited frommining because of the significant to farmingprovisions. Although the potential for affect-ing additional reserves through inability todevelop orderly mine plans might increasethe affected reserves somewhat, the increaseis not expected to be substantial.

The impact of alluvial valley floor designa-tions, and the likelihood of identifying areassignificant to farming, is of greater concernto private coal owners in the Powder Riverbasin than to Federal lessees. This situationresults from the fact that private coal owner-ship is often concentrated in major streamvalleys where significant farming operationsare found. This pattern of ownership existsbecause the earliest homesteaded lands inthe West obtained mineral as well as surfaceownership rights upon compliance with the


Table 91.—Alluvial Valley Floor (AVF) Summary TableUndeveloped Coal Leases

Acres of streamLease block Acres of designated Acres of designated valley under

area AVF significant AVF not significantLease 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

52454180

20.701

—400

200

Little Youngs CreekNoneClear CreekPowder RiverDeadman Creekseveral tributariesPowder RiverRobinson DrawWild Horse CreekNorth Prong Wild Horse

CreekBoxelder Creek and TributaryNegio and Dry CreekJamison Prong andSoukup DrawNoneDry Fork Little Powder River

Prairie CreekDry Fork Little Powder River

TributaryLittle Rawhide CreekDonkey CreekDry Fork Little Powder River

TributaryNoneLee DrawSchool Creek TributaryPorcupine Creek and

TributaryHolmes CreekWest Fork Creek TributariesNoneAntelope CreekLogan DrawSpring CreekPhillips CreekDry Fork Cheyenne River

—0 b

o

Arvada. . . . . . . . . . . . . . . . . . . . 4,366 0 0 750

1OC

240120

Lake DeSmet . . . . . . . . . . . . . .Belco. . . . . . . . . . . . . . . . . . . . .Wildcat . . . . . . . . . . . . . . . . . . .

9,4174,5511,571

00

00

— —

Blue Diamond. . . . . . . . . . . . . .Dry Fork . . . . . . . . . . . . . . . . . .

403,580

0300

——

——

South Rawhide. . . . . . . . . . . . . 4,782 180— —

East Gillette . . . . . . . . . . . . . . .Federal

4,343 160120

——

——

Gulf (3) . . . . . . . . . . . . . . . . . . . .East Wyodak . . . . . . . . . . . . . .North Rochelle . . . . . . . . . . . . .Rochelle . . . . . . . . . . . . . . . . . .

7562,5602,0008,821

————

————

—2518

North Antelope. . . . . . . . . . . . .Antelope . . . . . . . . . . . . . . . . . .

3204,817

——

——

Phillips Creek (1) & (2) . . . . . . . 4,079 60— —

Totals:Federal Lease Acres:. , . . . . 78,523 245 300 2,823Federal Recoverable

reserves: (million, tons)d . 4,000 < I00e e 219

a—: Indicates no determination made.bo: 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 re-

serves 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


homestead standards. The earliest settlers without transferring mineral ownership. Forwere 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 Kiewitreserves located along those major stream Sons’ Whitney Benefits Mine, north of Sher-valleys with the longest history of agricul- idan, Wyo., both on or near the Tonguetural land use are owned by private entities. River, face substantial issues related toOnly later did the Federal Government begin farming activities on alluvial valley floors.the practice of transferring surface ownership


Alluvial Valley Floor Occurrencein Other States

Alluvial valley floors occur in each of theother Western coal regions. By definition,alluvial valley floors do not occur in Okla-homa or other areas east of the 100th merid-ian. In Western coal regions outside thePowder River basin, less work has been doneon defining alluvial valley floors; however,based on the work that has been done, alluv-ial valley floors probably occur infrequentlyin most areas. While only Alderin Creek atthe Glenharold Mine in North Dakota isbeing reviewed for alluvial valley floor statusin the Fort Union region, studies by Schmidt(1977) and Hardaway, et al. (1977) indicatethat up to 10 percent of the reserve base ofthat region might be affected by alluvialvalley floor concerns.27 However, the amountof reserves that will be prohibited from min-ing will probably be much less because mostvalleys in mine areas are not being activelyfarmed.

27 see table 89 for full citations.

In the Green River-Hams Fork region, al-luvial valley floors may occur in southwest-ern Wyoming and in northwestern Colorado.Three blocks in the Kemmerer Field have po-tential alluvial valley floors covering lessthan 200 acres. No alluvial valley floors areexpected to be designated in the RockSprings or Hanna fields. In northwesternColorado, Empire Energy is proposing min-ing under the Yampa River, in an alluvialvalley floor. The impact of other alluvialvalley floor areas on mine production is un-evaluated at present.

In the Uinta-Southwestern Utah region,alluvial valley floor determinations may af-fect mine development in the Alton Field asdiscussed earlier. Elsewhere, effects are ex-pected to be minimal because undergroundmining generally is not occurring understream valleys. Alluvial valley floors are notexpected to be a significant issue in the SanJuan River region because of the generalabsence of surface water.

Topsoil, Spoil Handling, and Recontouring

OTA has identified one mine where recov-erable coal reserves have been rendered un-recoverable by regulatory decision in thisissue area. That mine, in the Green River-Hams Fork region in Wyoming, estimatedthat it lost 5 million tons* due to a limitationon the area where spoils** could be disposed.Additional reserves may be affected in theGreen River-Hams Fork region at mines withcharacteristics similar to the mine discussedhere. Regulations on this issue have also af-fected the cost of mining. These increasedcosts are discussed under the economic im-pacts section of this chapter.

*OTA estimates that 15 million tons may ultimately beremoved from mining a t I his mine if the State continues its pat-tern of interpretation of these regulations.

* *Spoil is overburden material removed by mining opera-tions in the course of exposing coal seams.

The Mining Process

The first step in developing a mine pit isthe removal of topsoil. Topsoil is eitherstored in stockpiles or replaced on regradedspoils elsewhere in the mine. Decisions con-cerning the depth of topsoil to be salvaged atany location prior to mining are based on asoil survey for the mining area. Agreementbetween the operator and the regulatoryagency is reached on how much of each soiltype must be salvaged.

Overburden is the rock strata between theground surface and the target coal seam andbetween the target seams. (Rock strata inthe latter case may also be called inter-burden. ) Spoil may be removed by dragline,truck and shovel combination, or scraperand dozer combination. Depending on thegeology of the coal seams, an open pit, area,

_ . .


or terrace pit mine may be developed (ch. 11).Spoil disposal at each type of mine is slightlydifferent. In open pit mines, spoil is storedoutside the pit since the entire pit is neededfor mining operations. In area or terrace pitmines spoil is disposed in inactive parts ofthe pit from which coal has already been re-moved. Requirements to limit out-of-pit spoildisposal or to selectively bury toxic over-burden may necessitate different techniquesof overburden removal and spoil disposal.

Statutory Control

SMCRA requires that certain standardsbe adhered to in the handling of topsoil andspoil. Topsoil must be removed prior to min-ing operations and either stockpiled or im-mediately placed on a regraded area (sec.515(b)(5)). If stockpiled, the topsoil must bevegetated in order to protect it from erosion.All mined and regraded areas must be cov-ered with topsoil or “the best available sub-soil which is best able to support vegeta-tion” (sec. 515(b)(6)). Since some spoil materi-al may be high in concentration of elementsdetrimental to vegetation or livestock or maycontribute to ground water pollution, spoilmust be placed in such a manner as to reducethese effects (sec. 515(b)(10)(A)(19)). The re-claimed land surface must resemble “the ap-proximate original contour of the land.” Spe-cial exceptions to this requirement are madefor areas of very thick and very thin overbur-den. In those cases, the operator is required toattain the “lowest practicable grade, ” to pro-vide drainage, to cover toxic forming materi-als, and to ensure land surface stability (sec.515(b)(3)).

SMCRA regulations for topsoil removalrequire that an operator remove topsoil orother approved plant-growth medium beforebeginning mining operations, save it in amanner conducive to protecting the primaryroot medium from contamination and ero-sion, and redistribute it in a manner that willenhance its productivity. Regulations gov-erning removal and redistribution are de-fined in 30 CFR 816.21 to 816.24. Removal re-quirements define the timing for removal as

being after vegetation is removed and prior tosurface disturbances caused by drilling, min-ing, blasting, or other such activities. Regula-tions define which unconsolidated subsoilsshould also be removed. Certain overburdenmaterials may be used in lieu of, or as a sup-plement to, topsoil if those materials are ap-proved by the regulatory authority.

Once topsoil is removed, it is desirable tomove it only once, placing it where the soilwill be permanently part of a new reclama-tion landscape. When temporary storage oftopsoil is necessary, 30 CFR 816.23 definesthe procedures to protect the soil from windand water erosion, and to maintain its physi-cal and chemical composition. Regulationsalso establish standards to be achieved inreplacing topsoil in regraded areas (30 CFR816.24(b)). Soil tests performed in accordancewith regulatory standards are required to de-termine whether soil nutrients and amend-ments are necessary for the replaced soil tosupport the proposed revegetation.

Requirements for backfilling and gradingof areas disturbed by surface coal mining arefound at 30 CFR 816.101 to 816.105. Thefocus of these regulations is to “insure theprompt restoration of the disturbed lands tominimize additional damage to the environ-ment, and to return the land to a productiveuse” (sec. 515(b)(3)). General backfilling andgrading requirements consider:

1.

2.

3.

4.

the timing of these activities, subse-quent to the removal of coal,the contour of the land which must berestored in the final grading process;the procedures to be used when the finalthickness is less than 0.8 of the initialthickness* (thin overburden situations);andthe procedures to be used when the finalthickness is greater than 1.2 of the ini-tial thickness (thick overburden situa-tions).

*InitiaI thickness is the sum of the overburden and coalthicknesses prior 10 the removal of the coal. Final thickness isthe product of the initial overburden thickness, prior to coal re-moval, times a bulking factor,


In order to prevent environmental degra-dation caused by acid and toxic formingmaterials, 30 CFR 816.103 requires that “aminimum of four feet of the best availablenontoxic and noncombustible material (beplaced upon) all exposed coal seams and allacid-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 inthe loss of about 5 million tons of recoverablereserves at the Black Butte Mine in Wyoming,following a regulatory decision limiting thearea outside the mine pit where spoil can bedisposed. Mining methods employed at thismine involve development of several distinctpits, many of which require out-of-pit spoil*disposal areas. OSM, in its technical reviewof the Black Butte Mine plan, determined thatthe originally proposed out-of-pit spoil areasconflicted with four regulatory standards:1) the requirement to minimize the overall dis-turbed area; 2) the requirement to achievethe approximate original contour of the land-scape; 3) the requirement to limit disturbanceto wildlife habitat; and 4) the requirement tolimit disturbance in stream channels. OSMthen limited the out-of-pit spoil disposal area,necessitating mine plan changes that resultedin the loss of recoverable coal28

Although no other mine in Wyoming or Col-orado in the Green River-Hams Fork regionhas experienced such a limitation to date, thesimilarity of the mining method used by BlackButte with that of other mines in the region

*Out-of-pit spoils are those spoils removed in the course ofmining that are not backfilled in the mine pit but rather are lefton the natural ground surface.

ZIJU. S. Office of Surface Mining, Technical Analysis, BlackButte Coal CO. amendment to spoil handling procedures in AreaD, 1979,

suggests that some other mines in the region,most of which use out-of-pit spoils disposalmethods as part of their mining operations,may experience regulatory decisions similarto Black Butte. Other mines where out-of-pitspoils and approximate original contour con-siderations may result in loss of recoverablereserves include Rosebud Coal Sales, Sem-inoe No. 2, Medicine Bow, Colowyo, and theundeveloped South Haystack lease. However,SMCRA allows out-of-pit disposal as part ofthe special regulations specific to open pitmining in the Kemmerer, Wyo, area (specialbituminous coal mine regulations).

P roposed mine m e t h o d s h a v e b e e nchanged because of spoil disposal and spoilhandling requirements. These requirementshave included limitations on placement ofexcess spoil (East Decker Mine, Montana),the need to bury spoil high in sodium concen-trations (Spring Creek Mine, Montana), andthe need to bury spoil high in selected ele-ments (Big Sky Mine, Montana; severalmines in the Powder River coal basin, Wyo-ming). At some of these mines, companiesclaimed that the regulatory changes in min-ing method resulted in increased costs whichare now being passed to the consumer. Theseincreased costs are examined in the final sec-tion of this chapter.

Approximate original contour considera-tions may have effects in areas of steeptopography even where coal seams are flatlying. For example, at the Spring Creek Minein the Powder River basin, recoverable coalunderlies a steeply sloping area of sandstonebluffs. The operator is uncertain whether theapproximate original contour can be re-stored. The effect of this concern is unclearat this time. At the nearby West Deckermine, the Montana State reclamation agen-cy has requested the company to mine intothe bluff in order to achieve erosion controlat the highwall. Thus, the impact of approx-imate original contour regulations is stilluncertain.


Publicstringent

Revegetation

Law 95-87 establishes a uniformstandard for revegetation of mined

lands that is particularly challenging in theWest. Section 515(b)(19) requires the estab-lishment of a “diverse, effective and perma-nent vegetative cover of the same seasonalvariety that is native to the area of land to beaffected and capable of self-regenerationand plant succession at least equal in extentof cover to the natural vegetation of thearea. ” The standard also makes allowancesfor use of introduced species where desirableand necessary to achieve the approved postmining land use plan. The use of introducedspecies in the West generally requires moreintensive management to maintain optimumlevels of productivity compared to restora-tion of native vegetation. This is generallynot feasible in most areas of the West thatwill be surface mined because the addedcosts of intensive management usually donot increase productivity sufficiently to payoff. Consequently, most reclamation in theWest involves reestablishment of native eco-systems.

Revegetation of surface mined lands hasbeen the subject of considerable controversyin the West primarily because the arid andsemiarid climate makes the establishmentand maintenance of vegetation more difficultthan in the humid East. A study by the Na-tional Academy of Sciences29 concluded thatareas receiving 10 inches or more of annualprecipitation can usually be reclaimed* pro-vided that evapotranspirat ion is not ex-cessive, landscapes are properly shaped, andtechniques demonstrated to be successful inrehabilitating d i s tu rbed range lands a reused. However, the NAS committee con-cluded that in drier areas receiving less than10 inches of precipitation, revegetation will

29National Academy of Sciences, Rehahilitation Potential ofWestern Coal Lends (Cambridge, Mass.. Ballinger Publishingco., 1974).

*The NAS Committee used the term “rehabilitation’” ratherthan “reclamation,” but in current usage, the two terms areusually used interchangeably.

be much more difficult and can probablyaccomplished only with major sustained

bein-

puts of water, fertilizer and management.The committee used slightly less stringentcriteria than in SMCRA for defining suc-cessful reclamation, and emphasized that itsconclusions were not based on long-term ex-tensive controlled experiments in revegeta-tion.

More recent studies that have evaluatedrevegetation practices in the West 30 h a v enoted short term success in revegetation,but have concluded that the long term suc-cess of revegetation through periods of ex-tended drought have yet to be demon-strated, and that revegetation techniques re-main essentially experimental in nature,

There is no dispute about whether vegeta-tion can be established on mine land in theWest. This has been accomplished throughthe use of irrigation and intensive manage-ment even in the driest areas such as the SanJuan River basin and southern Wyoming,and high levels of productivity have beenmeasured at several reclaimed sites in theNorthern Plains that have used fertilizationand introduced species. However, disagree-ment exists as to whether native ecosystemswith s imilar levels of productivi ty andresilience to the stress of drought can beestablished. Of particular concern is whethera suitable mix of native species can beestablished that provides good year-roundpasture for livestock in the Northern Plainswithout requiring continued intensive man-agement and whether desert and foothills-shrub vegetation associations that providecritical winter range for large game in theRocky Mountain coal areas can be estab-lished. Another area of concern is the revege-tation of spoils high in sodium concentra-t ions, a problem in the Fort Union andPowder River regions.

30F. X. Murray (cd.), Where We Agree: Report of fhe NationalCfNI) 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),


Reclamation experts differ in the degree ofoptimism or pessimism with which they viewthe likelihood of success in reclaiming nativeecosystems in the West, but there is generalagreement that it will be a number of yearsbefore the question is resolved. It has been 7years since Montana passed the first recla-mation law in the West that had stringentstandards for revegetation, and as yet noland reclaimed under that statute has devel-oped a vegetative cover that qualifies forbond release, 31 A recent study by the Com-mittee on Soil as a Resource in Relation toSurface Mining for Coal of the NationalAcademy of Sciences concluded that the 10-year time period specified in SMCRA forbond liability after reclamation is completedmay not be long enough to demonstrate suc-cess of revegetation in the arid areas of theWest. 32

The issue of revegetation has not had asignificant impact on the availability fordevelopment of Federal coal under existingleases. The main reason for this is that whileregulatory authorities recognize that uncer-—

‘1’(’rso[l;]l ((~nlml]l]i(;lll(}[] u I(h []ru( t; I liI;(l(?I), A(imlllis-Ir: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(jso{ 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-termsuccess of current revegetation practices,they do not feel that the probabilility ofserious failure is high enough to justifyrejecting a permit application on the basis ofdifficult conditions for revegetation. Thisjudgment is evident in DOI’s decision on thepeti t ion to designate the Alton area insouthern Utah as unsuitable for mining. Oneof the arguments made in the petition wasthat conditions in the area were too difficultfor successful reclamation because of thenature of the soil and the arid climate.However, DOI concluded that revegetationwould be successful.33

Unless there are dramatic failures in re-vegetation involving state-of-the-art recla-mation practices in the next 10 years, it isunlikely that difficult conditions for revege-tation will prevent any existing Federal coalleases from being developed, However, con-cern over revegetation has required, and canbe expected in the future to require modifica-tion of mining plans. For example, OSM hasconcluded that the Black Butte Mine insouthern Wyoming has very difficult condi-tions for revegetation and has required theuse of a sprinkler irrigation system.

Wildlife Concerns

Concern about the protection of wildlifehabitat has resulted in minimal prohibitionof mining and production of Federal coal, Insouthern Wyoming, in the Green River-Hams Fork region, protect ion of raptorhabitat along outcrop areas has resulted insome changes to mining plans, includingcontributing to the loss of 5 million tons atthe Black Butte Mine (previously discussedin the Topsoil, Spoil Handling, and Recon-touring section). The inability of a NorthDakota operation to demonstrate reclama-tion of wooded draws that are importantwildlife habitat has led to delay in approvalof a mine plan. Despite conflicts between

proposed mineswinter range forplace in southerngered species areposed mine site, it

and designated cri t icalgame, leasing has takenWyoming. Unless endan-found to reside on a pro-is unlikely that significant

amounts of recoverable reserves will be lostbecause of concerns about adverse effects onwildlife.

Statutory Control

Jurisdiction under SMCRA for protectionof fish and wildlife is based on a provisionwhich states that an operation must:


. . . to the extent possible using the besttechnology currently available, minimize dis-turbances and adverse impacts of the opera-tion on fish, wildlife, and related environ-mental values, and achieve enhancement ofsuch resources where practicable (sec.515(b)(24)).

OSM, in developing its final regulations (30CFR 816.97), interpreted the term “relatedenvironmental values” to mean habitat forfish and wildlife. Operators are required to:1) design electric powerlines and other trans-mission facilities so as to minimize the po-tential for electrocution of raptors; 2) locateand fence roads in order to minimize im-pacts; 3) exclude wildlife from hazardouswaste areas; 4) protect or restore riparianareas; and 5) refrain from using persistentpesticides. Where fish and wildlife habitat isto be a primary or secondary postminingland use, an operator must select plantspecies on reclaimed areas based on theirnutritional value and their value as cover,and must distribute these species to op-timize habitat. Where cropland is to be es-tablished after mining, such as in NorthDakota, fields are to be interspersed with“trees, hedges, or fence rows. ”

Three important Federal wildlife acts alsoaffect coal mines: the Bald Eagle ProtectionAct, the Endangered Species Act, and theMigratory Bird Treaty Act. Each of theseacts is primarily enforced by the U.S. Fishand Wildlife Service (FWS). The Bald EagleProtection Act requires, among other things,that bald eagles’ and golden eagles’ nestingareas not be disturbed. Since many Westerncoal mines have eagle nests located on them,conflicts with this act have occurred. FWShas permitted the moving of eagle nests in afew selected instances.

The Endangered Species Act requires thata determination be made of the occurrence ofendangered species on any proposed minesite. If adverse impacts from mining ac-t ivi t ies are projected, an operator mustmitigate or avoid those impacts. To date, noendangered species, such as the black-footedferret or the peregrine falcon, have beenfound to be resident on any proposed mine

site. The Migratory Bird Act requires en-hancement and prevention of loss of migra-tory bird habitats. This act, though consid-ered in the mine review process, has not af-fected mining planning to date. Potential ef-fects include possible requirements to protectwetland habitat used by migratory species inNorth Dakota.

Implications of Wildlife Concernsfor Federal Coal Development

Generally, wildlife concerns have not hada significant effect on the ability to producecoal. However, in selected instances, wildlifeconcerns are limiting recoverability of re-serves and the manner in which coal ismined. Particularly in southern Wyoming,mine plans have had to be adapted for theprotection of raptor habitat, especially thatrelated to nesting areas for eagles. In NorthDakota, mining is being restricted in woodeddraws, a scarce wildlife habitat in the State.In northwestern Colorado, surface miningareas conflict with elk habitat; however,mitigation strategies are being studied so thatrecoverable coal is not lost.

Green River-Hams Fork Region

Topography in southern Wyoming is morediverse than in the Powder River coal basinor the Fort Union region. Southern Wyo-ming is characterized by intricate drainagefeatures, expanses of rock outcrop, develop-ment of long ridges, and other topographicirregularities that serve as good wildlifehabitat. Also, big game migration patternsvary from winter to summer, and certainareas of southern Wyoming serve as criticalwinter habitat for game. Without such crit-ical winter habitat, game populations woulddecrease substantially.

Eagles and other raptors favor rock out-crops or dead trees along drainages fornests. Eagle populations, particularly goldeneagles, are high in southern Wyoming. Coalmine operators generally begin mine pitexcavations at or near the coal outcrop. Inmany 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 habitaton these outcrops, mining methods wouldgenerally use draglines to open the initialcuts near the outcrop. The boxcut spoilwould be cast over the adjoining outcrop.Such spoiling would cover the original out-crop and thus would cover or destroy raptorhabitat. State and Federal reclamation agen-cies have prohibited this kind of miningmethod. For example, at the Black Butteand South Clock mines, requirements to pro-tect outcrop areas have resulted in the open-ing of cuts further away from t he ou tc ropthan originally planned. Relocation of theopening pits has also necessitated somerehandling of spoils.

In the Hanna Field, at the Seminoe No. 1

Mine, concern about raptor habitat may re-sult in decreased reclamation costs to thecompany. An eagle established a nest in anabandoned highwall prior to the highwall’sscheduled slope reduction. As a conse-quence, the highwall may not have to bereduced.

Although not a significant deterrent tolease development in southern Wyoming todate, wildlife values may conflict with futuredevelopment of Federal coal. With the excep-tion of the Jim Bridger Mine, which is most-ly covered by critical habitat for antelopeand mule deer, most mine development insouthern Wyoming has not been located inareas designated as critical habitat by theWyoming Game and Fish Department, How-ever, a number of new proposals for the de-velopment of coal mining in southern Wyo-ming could conflict with the preservation ofwildlife values, and the Wyoming Game andFish Department has expressed its opposi-tion to some of these mines. The Red Rimtract, recently leased, includes over 2 , 0 0 0acres of critical winter range for antelope inWyoming. Several other proposed mines,such as Red Desert and Atlantic Rim, havesignificant areas of critical wildlife range,and a competitive lease application by IdahoPower Co. in southern Carbon County, Wyo.,was rejected several years ago because ofwildlife considerations.

Critics of the Wyoming Game and FishDepartment’s opposition to these mine de-velopment proposals in southern Wyominghave argued that data are insufficient todetermine the critical winter range for largegame. OTA was not able to evaluate thiscriticism on a site-specific basis, but did com-pare areas identif ied as cri t ical by theWyoming Game and Fish Department (1979)with data on wildlife presented in the South-central and Southwest Wyoming Environ-mental Impact Statements (BLM, 1 9 7 8 ) .This comparison suggests that the Depart-ment is rather conservative in identifyingareas of concern for large game. For exam-ple, the EIS’s iden t i f i ed seven l eases(Seminoe No. 1, Black Butte, Hanna South,Cherokee, Long Canyon, Twin Creek, andSouth Haystack) as being partly or com-pletely covered by antelope, elk or mule deerwinter range. However, current areas ofcritical winter range mapped by the Wyo-ming Game and Fish Department showwinter range only on the Long Canyon lease.

Mining may affect wildlife values otherthan big game herds. Eight developed leasesin the Powder River basin and 5 developedleases in southern Wyoming are completelyor partly covered by critical habitat forupland game birds. Several black-footed fer-ret skulls have been found on or near theSouth Haystack and Rosebud Mines insouthern Wyoming. Rare plant species havebeen found within or adjacent to leaseboundar ies a t the Lake DeSmet Block(Brownish sedge), Nor th Block (Abieslasiocarpa-pinus contorta community), andthe South Haystack lease block (malt sage-brush and stemless wild buckwheat).34

North Dakota

To date, mining activities have not beenaffected by the presence of any of the en-dangered wildlife species that exist in theState. The destruction of woody plants indraws, a scarce woodland resource found inthe l ignite region of North Dakota, hasbecome 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 ofthese areas is mandated by State, ratherthan Federal, statutes. The woody draws,dominated by green ash, box elder, andAmerican elm, are found throughout theGlenharold site in draws, valleys, and alongthe north- and east-facing slopes of the proj-ect area. The understory, consisting of amixture of shrub species provide habitat fordeer and other wildlife. Consolidation Coal’splans to mine across these draws have re-sulted in opposition from the State PublicService Commission and have delayed ap-proval of Consolidation Coal’s mining permitapplication. Consolidation Coal must demon-strate the ability to successfully reclaimthese draws before it can gain regulatory ap-proval for mining these areas. With the ex-ception of the Glenharold Mine, other coalmining operations in the state either containno woodland areas or have managed to avoidmining these areas.

Other Regions

In northwestern Colorado, surface minesconflict with elk migration and calving areas.At the Energy Fuels Mine, a calving area isbeing mined. The company, in conjunctionwith OSM and the Colorado Division of Wild-life, is experimenting with “habitat manipu-lation.” The company is attempting to recre-ate offsite the type of calving habitat that isbeing lost due to mining. To date, wildlife con-cerns in this area are not expected to affectrecoverability of coal because of the exten-sive mitigation strategies available to oper-ators.

Seven of the eight new leasing tracts of theWasatch Plateau in Utah have critical winterrange for big game, Since the tracts involveunderground mining, the potential impactsare substantially less than those associatedwith surface mining,

Cultural Resources

Throughout the Western United States,archeological and historical sites are fre-quently encountered. Under current statutesand regulations, a comprehensive surveymust be undertaken before disturbance. If asite has significant scientific value, it isstudied and the artifacts are generally sal-vaged, Only at sites with significant architec-tural or recreational value would a site be pre-served and prohibited from mining.

However, according to the OSM staff, cul-tural resource issues are perceived as a“ tho rn in the s ide” by industry. Mineoperators are frustrated by the rejection ofcultural resource surveys determined incom-plete by OSM and the subsequent delays inpermitting. OSM staff claim that industryhas had d i f f i cu l ty t ak ing the cu l tu ra lresource issue seriously. Often, companieshave contracted with firms or universitieswhose work has been found inadequate by

OSM.35 Future problems may be alleviated ifthe OSM promulgates guidelines for ade-quate surveys.

The San Juan basin area has the greatestpotential for future conflicts between cul-tural resources and mining of Federal coal.The Anasazi cultural features of the regionare generally recognized by archeologists tohave great significance and value. Architec-tural sites abound and several areas are pro-tected by the National Park Service, Con-flicts are likely in the Star Lake-Bisti regionwhere it is likely that coal reserves are foundbeneath remnant “outlier” communities toChaco Canyon. Expansion of the Chaco Can-yon National Monument to include some ofthese communities might also affect coalrecovery. No attempt has yet been made toquantify these conflicts.—

35Shafer, OSM staff ~rche(]logist, personal communication,1980.


Statutory Control

Federal requirements for the protection ofarcheological and historic resources arederived from SMCRA, OSM’s authority toprotect these resources comes from otherFederal laws directed at protecting arche-ological and h i s to r i c resources. Theseinclude:

1,

2.

3.

4.

5.

6.

7.

8,9.

The

The Antiquities Act of 1906 (Public Law59-209, 34 Stat. 225; 16 U.S.C. 431-433);The Historic Sites Act of 1935 (PublicLaw 74-292, 49 Stat. 666; 16 U.S.C.461-467);The Reservoir Salvage Act of 1960(Public Law 86-523, 74 Stat. 220; 16U.S.C. 469-469 c);The Historic Preservation Act of 1966(Public Law 89-665, 80 Stat, 915; 16U,S,C. 470);The National Environmental Policy Actof 1969 (Public Law 91-190, 31 Stat.852; 42 U.S.C. 4321-4347);Executive Order 11593 (May 13, 1971, 36F.R. 8921);Archaeological Conservation Act of1974 (Public Law 93-291, 88 Stat, 174);The Tax Reform Act of 1976; andArchaeological Resources ProtectionAct of 1979 (Public Law 96-95, 93 Stat.721: 16 U.S.C. 470).

more important laws are briefly dis-cussed below. -

Under the Historic Preservation Act of1966, the historic value of any site in the Na-tional Register, or eligible for listing in theNational Register, must be taken into con-sideration when any project utilizing Federalfunds or under Federal permit might ad-versely affect such a site. Detailed surveysof proposed mine sites must be undertakento ensure that all eligible sites are identifiedprior to mining.

The National Environmental Policy Act of1969 declares that it is the policy of the

Federal Government to use all practicalmeans, consistent with other essential con-siderations of national policy, to—amongother things—improve and coordinate Fed-eral plans, functions, programs, and re-sources with the objective of preserving na-tionally important historic, cultural, andnatural aspects of our heritage. It directs thatthe policies, regulations, and public laws ofthe United States shall be interpreted and ad-ministered, to the fullest extent possible, inaccordance with the act. Further, it directsall agencies to use a systematic interdisci-plinary approach that will ensure the inte-grated use of the natural and social sciencesand the environmental design arts in plan-ning and decisionmaking which may have animpact on man’s environment, It further re-quires that, on all federally sponsored orlicensed projects which significantly affectthe environment, the responsible official sub-mit an environmental impact statement thatassesses the impact of the proposed actionand any unavoidable adverse environmentaleffects (this has been consistently interpretedto include impacts to archeological and his-toric resources), sets forth the alternatives tothe project, identifies the long- and short-termresults, and identifies any irreversible andirretrievable commitment of resources re-quired by the project.

The Archaeological Conservation Act of1974 specifically provides for the preserva-tion of historical and archeological data(including relics and specimens) that mightotherwise be irreparably lost or destroyed asa result of alteration of the terrain caused byany Federal construction project or federallylicensed activity or program.

Together, these acts require that OSM en-sure that all potential archeological or his-toric sites are identified and salvaged beforemining. Actual preservation of sites will prob-ably only be required where significant struc-tures exist.


Economic Impacts ofFederal

Environmental regulations may have aneconomic impact on Federal coal productionin two major ways: 1) income foregone by theleaseholder in terms of profits, and by theFederal Government in terms of royalties, asa result of leaving coal in the ground thatwould otherwise be recovered if environ-mental concerns were not considered; and 2)increased mining costs because of changes inmining methods necessitated by environ-mental regulations.

Losses of reserves at tr ibutable to en-vironmental regulations can be quantifiedand OTA’s evaluation of existing Federalleases has found that most mines currentlyproducing Federal coal have not had to leavereserves in the ground as a result of en-vironmental requirements. Furthermore,losses of reserves at those mines at which en-vironmental requirements have, or will, pre-vent mining of reserves usually involvesmall tonnages in comparison to the totalreserves in a mine block. In the PowderRiver basin, 700 million tons of Federalreserves under lease are likely to be underalluvial valley floors, but only a small por-tion of these Federal reserves (less than 100million tons) appear to be subject to clearprohibition against mining. Delays of mineplan development at two mines because of al-luvial valley floor issues (Buckskin, SpringCreek) have affected another 95 million tonsof the potential 700 million tons. Most re-serves under alluvial valley floors can bemined if adequate reclamation can be demon-strated; such demonstrations are expected.Regulatory decisions that have resulted inprohibitions have affected a total of 29 mil-lion tons (see table 92), and the recovery ofperhaps another 200 million tons of Federalreserves may be delayed or otherwise af-fected by regulatory decisions. In comparisonto total leased Federal reserves (16.5 billiontons), these reserves are small.

Environmental Regulations onCoal Production

Analysis of the impact of environmentalregulations on the cost of mining coal is dif-ficult because of both conceptual and prac-tical problems in quantifying the impact ofsuch regulations. A recent study that ana-lyzed the economics of reclamation has iden-tified a number of the difficulties involved inquantifying the cost impacts of environmen-tal regulations as follows:36

1.

2.

3.

4.

A conceptual problem with cost-benefitanalysis of reclamation is that costs arerelatively easy to consider in monetaryterms (i.e., costs imposed on coal opera-tors and consumers of coal), but costs ofnot reclaiming mine sites (i. e., the bene-fits of reclamation) are often difficult, ifnot impossible, to measure in monetaryterms.Reclamation costs are highly site-speci-fic. For example, earth-moving costs as-sociated with reclamation may vary bya factor of 3 or 4, and since these costsmay be as much as 90 percent of recla-mation costs, such variations signif-icantly affect total cost at a site.Inflation and questions of cost alloca-tion, such as the extent to which earth-moving costs should be considered min-ing or reclamation costs, make precisemeasurement of reclamation costs dif-ficult.Coal operators are generally unwillingto disclose the detailed costs of miningand reclamation for business reasons,so most cost data available is based onhypothetical information from engineer-ing studies, or publicly financed experi-mental projects which often do not cre-ate optimum conditions for achievingthe least cost in production.

36National Research Council, Surface Mining: Soil, Coal andSociety (Washington, D. C.: National Academy Press, 1981).


Table 92.—Summary of Impacts to Federal Recoverable Reserves FromEnvironmental and Reclamation Considerations

Federalreservesaffected

Location of (millionsIssue 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 benonattainment area Colstrip, Mont. after 1985 to limit production

or about rate, not prohibit30 mt of any mining areasreserve

Permitting of additional powerplants West-central <100 U , improved airnear class I area where S02 levels for ex- North Dakota quality modelingisting and permitted but not constructed techniques beingfacilities are currently predicted to be at developedmaximum PSD level. The additionalpowerplants would be fueled by lignitemines in the vicinity.

Lands unsuitable Impacts of coal mining will damage Alton Coalfield, 24 Ap -on portion offor mining important esthetic values of Bryce southern Utah proposed mine area

Canyon National Park designated asunsuitable; restof leaseholdunaffected.

Water resources Subsidence of mine will divert surfaceand ground water and adversely affectother uses

Alluvial valley floor (AVF) in areassignificant to farming

Developed mines with stream valleysunder study as potential AVF wheremine plan development has beendelayed

Designated AVF in developed mines.Valleys not significant to farming. Mineplan development affected

Potential alluvial valley floors which ex-isted in developed mines prior topassage of SMCRA. Reclamation plansmust still be approved

Potential AVFS in undeveloped coallease areas

Mt. Gunnison Mine,west-central Colorado

CX Ranch leases Mon-tana portion of thePowder River basin

Powder River basinBuckskin and SpringCreek mines

Powder River basinEagle Butte, Rawhide,Coal Creek mines

Powder River basinBig Sky, East Decker,Eagle Butte, Wyodak,Belle Ayr, JacobsRanch and BlackThunder mines

Powder River Basin

23 U, approval likely ifmine will buy orreplace seniorwater rightsaffected.

<100 Ap uncertain

95 D, mining of valleysexpected

61 U, mining of valleyexpected

240 U, mining of valleysexpected

219 U, mining of mostvalleys expected

Spoil handling Limitation on out-of-pit spoil area Black Butte Mine 5 Apand protection Green River-Hams Forkof 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 Dwoody 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 HealthVleclslon 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 significantto 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


Table 93 summarizes “typical” reclama-tion cost estimates in 1978 dollars in theWest, Midwest, and Appalachia, showingcosts before and after passage of SMCRA. Itis evident that both on a per-ton and a per-acre basis, reclamation costs are signifi-cantly less in the West than in the Midwestand Appalachia, The largest part of the costinc reases in the Wes t a t t r ibu tab le toSMCRA is the 35 cents/ton fee for the aban-doned mine reclamation program, which isnot strictly an increase in production costs,but rather is a tax to pay for rectifying theenvironmental costs of past mining prac-tices. When this reclamation fee is sub-tracted from the estimated total reclamationcosts in table 93 to reflect cost increases at-tributable to changes in mining method,“typical” reclamation costs in the Midwestare 8 times higher than in the West and morethan 20 times higher in Appalachia than inthe West. The main reason for this large dif-ference in cost is that much thicker coalseams are mined in the West, and the largesize of many mining operations allows con-

Table 93.—Summary of “Typical Reclamation CostEstimates (in 1978 dollars)a

$/ton $/Acre

Mid- b Mid- b

Range point Range point

1. Pre-Public Law95-87 (SMCRA)a. Appalachia. . . . . . $3.23-7.16 $ 5.19 $2,676-14,915 $9,460b. Midwest (rowcrop) 1.40-2.73 2.07 7,000-10,000 8,500c. West . . . . . . . . . . . 0.08-0.39 0.24 1,899- 8,186 5,043

2. Incremental costwith Public Law95-87 (SMCRA)a. Appalachia. . . . . . — 5.24 — —

b. Midwest (rowcrop) – 1.80 — —c. West . . . . . . . . . . . — 0.57 – —

3. Estimated total re-clamation costswith Public Law95-87 (1 +2)a. Appalachia. . . . . . — 10.33 – —

b. Midwest (rowcrop) — 3.87 – —

c. West . . . . . . . . . . . — 0.81 – —

aThls table presents cost estimates developed by the NAS Committee on Soilas a Resource in Relation to Surface Mining for Coal, based on a synthesis ofall studies available as of 1980. However, until more experience is gained withthe reclamation provisions of Public Law 95-87, cost estimates will remainuncertain. The NAS report notes that these cost estimates are probably higherthan costs will be in the long run.

bThe midpoint values for $/ton and $/acre were derived independently from thetwo 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 rea-sons incremental costs in Appalachia andthe Midwest are greater with Public Law95-87 compared to the West is that waterpollution control is much more difficult inAppalachia and in the Midwest. Also, primefarmland reconstruction requirements re-quire a larger relative change in materialshandling than in the West.

On a site-specific basis, Federal coal mayexperience significant cost increases be-cause of environmental regulations, but suchsituations appear to be the exception ratherthan the rule. Two areas where such impactsmay be significant on a site-specific basis arethe extensive hydrologic data collection andanalysis that is required in Public Law 95-87for permit applications, and requirementsnecessitating changes in spoil handling pro-cedures. The effects of these extensive hydro-logic data collection and analysis require-ments are greatest on small operators or com-panies with l imited f inancial backing.Although OSM’s Small Operator AssistanceProgram offsets costs for the smallest size op-erations, somewhat larger mines may havedifficulty conducting the required studies.However, comparison of the detail of mineplan data submittals to OSM indicates thatconsiderable variation exists in the detail ofhydrologic information considered accept-able. Mine operations in the Northern GreatPlains are required to submit more compre-hensive data than mines in other areas.

There are several examples of the impactsof requirements under SMCRA concerningspoil handling. The Decker Coal Co, hasclaimed that the change in mining methodsnecessitated by prohibition of placing spoilin an intermittent stream valley adjacent totheir East Decker mining area increased thecost of mining by several dollars per ton.These costs were passed on to the consumerin the form of increased coal prices. At pres-ent, the city of Austin, Tex., is suing theDecker Coal Co., challenging the validity ofthe increased prices. The case has not beenresolved. At the Black Butte Mine in south-ern Wyoming, restrictions on placement ofout-of-pit spoils has required significant


modifications of the original mining plan,but these modifications apparently have notjeopardized the viability of the mining opera-tion,

In summary, OTA has identified a numberof examples on existing Federal coal leaseswhere there are demonstrable economic im-pacts on mining because of environmentalregulations, both in terms of revenues fore-gone because of the necessity to leave coal inthe ground, and through increases in miningcosts. However, to date, and in the foresee-able future, total reserves lost through suchrequirements appear to be relatively small,and OTA has not identified any situationswhere the overall viability of a mining opera-tion has been jeopardized because of in-creased costs attributable to environmentalrequirements. Significant modification ofmining plans to accommodate environmen-tal concerns is not uncommon.

The primary reason that environmentalregulations appear to have had a relativelysmall impact on Federal coal production isthat costs resulting from these regulationsare small when compared to other majorcoal-producing regions. Current require-ments concerning out-of-pit disposal ofspoils have the greatest relative impact onmining costs in southern Wyoming, andnorthwest Colorado, where the mining ofdipping multiple coal seams creates difficultconditions for surface mining. Improvedspoil handling methods through the reorien-tation of pits and expanded use of truck-shovel combinations rather than draglinesmay lead to resolution of many of these prob-lems, but at the present time it appears thatSMCRA has reduced the competitive posi-tion of coal mined in southern Wyomingcompared to coal from the Powder Riverbasin, although this change is difficult toquantify.

CHAPTER 11

Mining Technology

\

. . . . —

Contents

PageIntroduction and Overview. . . . . . . . . . . . . .323

Review of Coal Mining TechnologiesCurrently Used at Federal Mines. . ......325

Surface Mining Techniques. . .....,........325Underground Mining Techniques, ,... .. ...328

Analysis of Mining Technology Problems. .333Recovery Ratio. . . . , , , , . . . . . , . , , , . . . . . . . .333Production and Productivity, ,,. . ..,......,334Environmental . . . . . . . . . . . . . . . . ..........335Roof Support. . . . . . . . . . . . . . . . . . . . . , . . . , , .335

Review of Technology Developments inEurope and the Western United States. ...336

Comparison of Mining Conditions in Europeand the Western United States. . ..........336

New Equipment Developments. . . . ..,......337

Considerations for Using ImprovedLongwall Mining Techniques on FederalCoal Leases . . . . . . . . . . . . .............339

PageCapital . . . . . . . . . ........................339Labor . . . . . . . . . . ........................341Production and Productivity. . . . . ....,.....342Environmental . . . . . . . . ..................343Health and Safety. . . . . . . . . . . . . . . . . , . , , , . .343

List of Figures

Figure No, Page49. Western Strip Mining. ....,.,, . .....,..32750. Truck and Shovel Terrace Pit Mine With

Two Overburden Benches and TwoCoal Seams. . . . . . . . . . . . . . . . . .........328

51. Room-and-Pillar Underground Mining. ..33052. Longwall Mining System . . . . . . . . . . . . . . .332

—

CHAPTER 11

Mining Technology

The Federal Coal Leasing Amendments Actof 1976 charged OTA to assess the feasibilityof the use of deep-mining technology onleased areas. With the passage of the Sur-face Mining Control and Reclamation Act of1977 congressional interest in the study ofdeep underground mining technology shiftedits principal focus from a concern for the pro-tection of surface resources to a concern formaximum economic recovery and the conser-vation of the resource. Lessees are requiredto mine all coal that can be extracted eco-nomically and within the limits of safety andtechnology so that coal reserves are not left inthe ground where they can deteriorate andnot later be retrieved. Underground miningmethods usually leave a significant portion ofthe coal reserve in the ground, Some under-

ground mines recover only 30 to 50 percent ofthe minable resource, although, averagedover all underground mines in the UnitedStates, the recovery ratio is 63 percent. Sur-face mines, on the other hand, typically re-cover from 70 to 90 percent of the minableresource.

Introduction and Overview

This chapter summarizes OTA’S review ofthe mining technologies currently in use onFederal leases and the potential for commer-cial mining technologies to extract Federalcoal reserves from deep underground seams.The chapter discusses:

●

●

●

●

three surface mining techniques that areused in the West: 1) area strip, 2) openpit, and 3) terrace pit;two methods of underground mining inthe West: 1) room and pillar with contin-uous miners, and 2) longwall mining;recent underground mining technologydevelopments in Europe and the West-ern United States that could affect theproduction of coal from Federal leases;andfactors affecting the choice of these un-derground coal mining technologies inthe West, including: 1) capital require-ments, 2) resource recovery, 3) labor,4) production and productivity, 5) envi-

ronmental impacts, and 6) health andsafety.

A number of technological innovationshave been developed recently for under-ground coal mining, but the greatest near-term commercial promise for the expansionof underground coal mining in the WesternUnited States appears to be the implementa-tion of longwall mining techniques developedin Europe. Although longwall mining is usedvirtually exclusively to produce coal from un-derground mines in Europe, it accounts foronly 5 percent of annual underground coalproduction in the United States. Longwall sys-tems have been used in several Europeancountries to extract most of the reserves in30-ft thick seams at depths of 3,000 ft. In theUnited States, on the other hand, such recov-ery of thick, deep underground seams is stillin the development stage,

Some of the largest underground mines inthe West, including several that produce Fed-

323


eral coal, have recently converted to longwallmining. Longwall mining is also scheduled tobe installed at other large underground oper-ations in the West. For these reasons, muchof this chapter compares longwall miningwith the dominant underground mining tech-nology in the West—room-and-pillar miningwith continuous miners.

Federal coal reserves in the Rocky Moun-tain province provide the greatest near-termpotential for the application of longwall min-ing. The first successful longwall operation inthe West was the York Canyon Mine of Kai-ser Steel located near Raton, N. Mex. Al-though the York Canyon Mine is not locatedon Federal leases, New Mexico provides op-portunities for the implementation of longwallmining on Federal land.

Longwall systems have also been intro-duced in several mines with Federal leases inthe Book Cliffs Field of central Utah. Newconcepts are now being implemented andtested to extract coal from thick seams and tomine steeply dipping seams at two mineswith Federal leases in Colorado—the Coal Ba-sin Complex of Midcontinent Resources andthe Snowmass Mine of Snowmass Coal Co.These projects are likely to encourage the useof longwall mining to extract other thick orsteeply pitching coal seams in the area.

Longwall systems are also scheduled to beimplemented at two mines with Federal re-serves in the Hanna basin of southern Wyo-ming. In 1981 a longwall system will be in-troduced at Carbon No. 1 Mine. This systemwill be the highest longwall unit (14 ft) in theWest. Much of the area overlying this opera-tion has already been surface mined. In 1984Energy Development Co. plans to use a long-wall unit at the Vanguard No. 2 Mine.

In the Powder River basin of Wyoming andMontana, where coal is mined inexpensivelyfrom large surface mines, it may be techni-cally possible to extract thick undergroundseams. However, the resource information ondeep underground coal deposits in this areais inadequate to assess the economic feasibil-ity of this. The comparatively low-Btu value of

coal in the Powder River basin and the verylarge, inexpensively minable surface depositsin the basin are economic barriers to under-ground mining in this region at least through-out this decade.

A potential method for recovering energyfrom coal is through in situ gasification ofdeep coal seams that cannot be mined by sur-face mining methods. The thick coal seams inthe Powder River basin are considered at-tractive in their potential for in situ gasifica-tion, and two separate small-scale test siteshave been developed in Campbell County,Wyo., one by the Department of Energy (HoeCreek Site) and another by ARCO Coal Co. Insitu gasification in this country is still in earlyexperimental stages. A major disadvantagewith in situ gasification is that it does not pro-duce pipeline quality gas. Thus, unless thereare industries nearby that could use low- ormedium-Btu gas, a surface facility must beconstructed to upgrade the gas to pipelinequality or perhaps to convert it to methanol.The National Coal Policy Project concludedthat even if in situ gasification experiments inthe Powder River basin are successful, thedistance of the region from centers of de-mand is likely to limit application of the tech-nology. 2 Considering the present state of de-velopment of the technology, in situ gasifi-cation is not likely to be used commercially inthe Powder River basin until the mid-1990’sat the earliest.

To date, the experience with longwall min-ing both in Europe and the Western UnitedStates points to significant potential advan-tages in terms of increased resource recov-ery, higher production and productivity, re-duction in the cost of labor and frequently inthe overall costs per ton of coal, the control ofdifferential subsidence on the surface, and areduction in the number of unintentional rooffalls at the face. One should not conclude,however, that longwall mining will realizethese advantages in all underground miningenvironments or that longwall mining can be

2F. X. Murray (cd.), Where We Agree: Report of the NationalCoal Policy Project (Boulder, Colo.: Westview Press, 1978).

Ch.. 11—Mining Technology ● 325

used profitably and efficiently in all of thedeep Federal coal seams in the West. The de-cision to implement a particular undergroundmining technology at a particular site can bemade rationally only after the completion ofcomprehensive sit e-specific geological,engineering, economic, and environmental as-sessments,

In spite of the positive experience withlongwall mining both in Europe and theUnited States, many underground coal pro-ducers in the West will be reluctant to installthis mining technology because of its high ini-tial capital cost. The cost of a typical longwall

installation is $9 million; total capital cost ofthe technology per ton of coal mined over thelife of a system is about $1,50. This comparesto a capital cost of $0.40/ton of coal minedover the life of the system for the typicalroom-and-pillar operation in the West, usingcontinuous miners. In many cases, the sav-ings in labor and the other advantages ofusing longwall mining may not be sufficient tooffset this cost differential. Nevertheless,longwall systems are likely to figure prom-inently in mining underground Federal coalreserves in several areas of New Mexico,Utah, Colorado, and Wyoming.

Review of Coal Mining Technologies Currently Usedat Federal Mines

Although underground mining was, at onetime, the principal mining method in parts ofColorado, Montana, Wyoming, and NorthDakota, and continues to be so in Utah, sur-face coal mining now predominates in mostareas of the West. Because coal seams aregenerally thicker and nearer the surface inmost Western States, compared to the East,they are more amenable to recovery by sur-face mining techniques. Surface miningoperations are usually well-suited to themany areas of the West that have not yet ex-perienced the extensive development oftowns, cities, highways, and railroads char-acteristic of the Midwest and the East.

Surface Mining Techniques

Surface mining of coal is characterized bythe use of large, capital-intensive and effi-cient mining equipment. First, the overlyingsoil and rock layers (overburden) are re-moved. The coal is then fractured with explo-sives or machines, and loaded onto vehi-cles for haulage from the mine site. Finally,the disturbed land must be fully reclaimed.Principal considerations in the selection ofsurface mining and reclamation techniquesand equipment include the thickness and

character of the overburden, the dip of theseam, the thickness and number of recov-erable seams, and the physical and chemicalcharacteristics of the coal. The three surfacemining techniques most widely used in theWest are area strip, open pit, and terrace pit.

Area Strip

Area strip is the principal surface miningtechnique used in the United States. The tech-nique was perfected in the coalfields ofIllinois, Indiana, Kentucky, and Ohio. Thecapacity of a dragline, the machine used toremove the overburden in strip mining, variesin size from 10 to over 200 cubic yards. ManyEastern mines use stripping shovels insteadof draglines; and stripping shovels currentlyare being used successfully at several stripmines in the West such as the Rosebud Minein the Montana portion of the Powder Riverbasin which produces Federal coal.

Area strip mining proceeds by first makinga box cut into the earth to uncover the initialstrip of coal that is to be mined. The strip ofcoal uncovered will vary from 100 to 200 ft inwidth and from one-quarter to several milesin length. The actual size of the cut will be de-termined by the thickness of both the over-


burden and the coal and the designed produc-tion rate of the mine. After the coal has beenmined from the bottom of the box cut, theoverburden covering the next strip of coal isremoved and placed in the void left by themining of the preceding strip of coal. Miningproceeds with succeeding parallel strippingcuts until the property limits of the miningarea are reached (see fig, 49).

Even the largest draglines have limits onhow much overburden they can remove froma given operating location. A single draglinecan generally remove overburden to depths of100 ft. However, it is possible to extend thestripping limits to as deep as 200 ft by team-ing the principal stripping dragline with addi-tional equipment such as another dragline, astripping shovel, a bucket-wheel excavator,or fleets of trucks and shovels or scrapers.This additional equipment will increase thetotal overburden removal costs and can bejustified only by significant increases in theamount or quality of the additional coal thatcan be recovered.

Open Pit

The open pit mining technique currentlyused in the Western United States was ini-tially developed in the metal mining industry.An open pit mine is characterized by a seriesof benches, the number of which increases asthe mine is deepened. Each one of thesebenches is 40 to 50 ft in height, and excava-tion can proceed to depths of hundreds orthousands of feet.

The use of an open pit for overburden re-moval is justified only where there is an ex-ceptionally thick seam or a series of seamsthat can be mined in sequence, The singleseam mines can be found in the brown coal-fields of Germany, but only the multiseammines are found in the Western UnitedStates. The best example of the latter type isFMC’s Skull Point Mine located on Federalleases in southwestern Wyoming.

Equipment used for overburden removal inan open pit coal mine is currently limited totruck and shovels or scrapers. The truck and

shovel or scraper approach typically pro-vides the most flexibility in the developmentof a bench system and the mining of coalseams. However, lower overburden removalcosts might be achieved if rail or conveyorhaulage systems, similar to those used in thecopper mines of the Southwestern UnitedStates, could be implemented in open pit coalmines,

Terrace Pit

The terrace pit system for surface coalmining has come into use only during the last5 years (see fig. 50). This method, which es-sentially combines the area strip and open pittechniques, is used in the thicker coal bedsof northeastern Wyoming and southeasternMontana. In these two areas, the removal ofoverburden thickness in excess of the 100-ftstripping limit of a dragline is justified eco-nomically by the mining of exceptionally thickcoal seams.

Terrace pit mines have a system ofbenches similar to those designed for open pitmining. However, the overburden depths thatcan be removed economically by the terracepit method are currently limited to between200 and 300 ft. so that the maximum numberof benches will be about seven, Also, unlikethe open pit system, the terrace pit systemdoes not remain in the same location butrather moves across the property in a mannersimilar to area strip mining. The overburdenthat is removed from one side of the pit ishauled to the other side of the pit and dumpedwhere the coal has already been mined. As aresult, the overburden removal operation ofthe terrace pit moves constantly in a spec-ified direction, usually down dip during theinitial years of mining. The removed over-burden is replaced behind the mining opera-tion at a distance determined by the numberand size of the benches.

Equipment used for overburden removaland coal extraction in the terrace pit systemtypically consists of trucks and shovels, al-though draglines are used at several suchmines in the West, including the Rawhide

Ch. 11—Mining Technology ● 327

F igu re 49 .—Wes te rn S t r i p M in ing

.

. “

. ’ “! .


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 inthe Wyoming portion of the Powder Riverbasin. A maximum of two to three shovels willtypically be assigned to each overburdenbench together with a sufficient number oftrucks to haul the material excavated by theshovels to the other side of the pit, The num-ber of shovels used in this operation is deter-mined by the length and the rate of devel-opment of the pit. As in open pit mining,other forms of excavation and haulage equip-ment, such as bucket-wheel excavators andconveyors, are being considered for terracepit mining. However, the dynamic aspect ofterrace pit mining makes it more difficult touse equipment that does not have the mobilitycharacteristic of trucks and shovels,

Underground Mining Techniques

Surface mining is generally preferred bymine operators over underground mining.The reasons for this preference includehigher percentage of coal recovery, higherlabor productivity, lower operating costs, andfewer safety and health hazards. Also, someenvironmental impacts of underground min-ing, such as subsidence, acid mine drainage,and the interruption of aquifers can begreater than those of surface mining, All ofthese factors are important and will be dis-cussed in more detail later in this chapter. Incases where coal seams are too deeply buriedto be recovered economically using surfacemining techniques, it is likely that the coal

Ch. 11—Mining Technology “ 329

will be mined using one of the two under-ground mining techniques discussed below,Furthermore, several companies mining Fed-eral coal in the West have had to shift fromsurface to underground mining as their sur-face minable reserves became exhausted.

Access to underground mine workings willbe by one of three methods. If the coal seamoutcrops at the surface it is possible to minedirectly into the seam from the surface; thistype of mine is referred to as a drift mine.Most underground mines in the West aredrift mines. If the minable seam is locatedunder shallow cover then it may be possibleto reach the coal bed through the use of an in-clined drift (slope); this type of mine is re-ferred to as a slope mine. If neither of theseforms of access is possible, then it is neces-sary to sink a vertical shaft from the surfaceto the minable seam; this type of mine is re-ferred to as a shaft mine.

The initial capital cost for developing aslope mine may be slightly more than that fordeveloping a shaft mine because, for thesame overburden thickness, a slope is ap-proximately three times longer than the depthof a corresponding vertical shaft. However,over the long term, a slope mine has loweroperating costs because of the relatively lowcost to move men and materials into the mineand coal out. A slope mine is typically moreeconomical when the overburden is less than500 ft; a shaft mine when it is over 1,000 ft. Inthe 500- to 1,000ft range a site-specific eco-nomic evaluation is usually necessary to de-t e rmine wha t type o f mine shou ld bedeveloped.

Room and Pillar

In the room-and-pillar method, the voidsleft by removed coal form the rooms and theunmined coal forms the pillars (see fig. 51).The pillars are left in place to support theweight of the overlying strata. The principalfactors determining the percentage of coalthat can be removed from a seam are thethickness of the seam, the strength of the

seam and the confining rock strata, the pres-ence of faults or fractures, and the depth ofthe seam. The deeper the seam, the greaterthe weight of overlying rock that must be sup-ported; thus the size of the pillars generallywill be greater for deeper mines.

The extraction of the coal in a room-and-pillar mine is accomplished using eitherconventional mining or continuous miners.

Conventional mining declined in popularityduring the 1960’s and most of the 1970’s butcontinues to account for 35 to 40 percent ofthe underground coal product ion in theUnited States. The first step in conventionalmining, which is more labor-intensive thancontinuous mining, is to cut a slot into theseam with a machine that looks like a largechain saw mounted on a large, rubber-tiredvehicle (see fig. 51), Holes are then drilledinto the face and loaded with explosives.After blasting, the coal is fragmented andallowed to drop on the floor of the mine. Aroof-bolting machine is used to drill verticalholes into the roof and install bolts for roofsupport. A loading machine is then used togather up the coal and to load it into rubber-tired shuttle cars which haul the coal fromthe loader to a conveyor belt for transport outof the mine. In a few instances, a series ofbridge conveyors are used in place of theshuttle cars.

Continuous miners are equipped with a ro-tating head with cutting bits that is used tobreak coal from the face (see fig. 51). The de-sign of the cutting head and the form of rota-tion will vary with the manufacturer, but allcontinuous miners typically break the coalfrom the face and load it directly into shuttlecars or onto conveyors. As in conventionalmining, a roof-bolter is used to install boltsfor roof support. The labor requirement forcontinuous miners is at least 10 percent lessthan that of conventional mining systems.While continuous miners generally are moreefficient, conventional mining can be morereadily adapted to certain difficult miningconditions and to large inclusions in thecoalbed.

—.—


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)



Longwall Mining

The basic longwall system consists of a setof supports that are located parallel to themining face, a conveyor system that runsalong the base of the face, and a machine thatmoves back and forth along the face, cuttingthe coal and loading it onto the face conveyorfor transport out of the face area (see fig. 52),In addition, continuous miners are requiredfor the development of longwall panels. Thelength of the mining face will depend on anumber of factors (discussed in more detaillater in the chapter), but will generally rangefrom 400 to 650 ft, with 500 ft being typical.

The basic longwall support system consistsof hydraulic rams positioned vertically to sup-port the roof when they are extended. De-pending on the size of the mining operation,the rams are arranged into one or more pairslocated in the plane perpendicular to theface, When more than one pair of hydraulicrams are used, they will be structurally con-nected to one or more other pairs to ensurelateral stability. The exact configuration ofthe rams and the method of interconnectingthem will vary according to model or man-ufacturer. For additional support, a shieldsupport system may be employed. This systemuses a protective canopy as a structural partof the support mechanism to protect minersworking along the face from roof falls.

The longwall chain conveyor system ismounted on the mine floor in front of the baseplate used for the roof support rams or onseparate supports, In either case, the con-veyor assembly must be flexible to allow forbending as the supports are advanced oneafter another to keep pace with the advanc-

ing face. As the supports are advanced, theroof is allowed to collapse behind them. Thetypical conveyor mechanism used on a long-wall chain conveyor system has a series ofhorizontal bars or flights that are locatedperpendicular to the longitudinal axis of theconveyor, These flights are spaced approx-imately 1 ft apart and are fastened togetherwith chains connected to their ends or cen-ters, The chain-connected flights move alongthe top and bottom surfaces of the chain con-veyor system through the force of a gearmechanism which engages the chain. Side-boards are mounted along the top surface ofthe system so that coal falling into the troughformed by the sideboards will be pulled alongby the chain-driven flights.

The machine used to cut the coal from theface and load it on the face conveyor iseither a plow or a shearer. Plows are favoredin West Germany because of the thin coalseams and soft coal deposits in that country.The cutting action of a plow is just as thename indicates. The height and the depth ofthe cut will be limited by the amount of pull-ing force that can be applied to the plow. Inthe case of shearers, however, the cuttingforce comes from a rotating drum with cut-ting bits mounted on it. The diameter of thedrum will typically be somewhat greater thanone half the face height so that two passes ofthe drum will be required to mine the fullheight of the face. The top half of the face ismined first. Since a shearer drum is designedto operate only in one direction, a double-ended shearer makes it possible to cut the up-per and lower portions of the face withouthaving to return the shearer to the same endof the face to begin each cut.

——.


Figure 52.—Longwall Mining System

Elevation view

Overburden

Mining Conveyormachine

Plan view

Conveyor

Suppo

Slumpedoverburden

I Miningrts machine

Tunnel

L Air Main tunnel


Ch. 11-Mining Technology ● 333

Analysis of Mining Technology Problems

The preceding descriptions of surface andunderground mining techniques currently inuse on Federal coal leases are very general.They are intended to introduce the reader tothe basic differences between surface andunderground coal mining. This section willdiscuss in more detail the problems that areencountered in using these coal mining tech-nologies. These problems will be illustratedwith examples from mines currently operat-ing on Federal coal leases.

Recovery Ratio

Recovery ratio is the percent of minablecoal recovered from the seam. Generally, therecovery ratio for surface mining will behigher than that for underground mining be-cause some coal must be left in place in un-derground mines to support the roof and limitsurface subsidence. According to the Bureauof Mines, the average recovery ratio from allsurface mines in the United States is 83 per-cent; for underground mining the nationalaverage is 63 percent.

Thick single-seam surface mines often haverecovery ratios in excess of 90 percent. Forexample, the thick-seam mines of the PowderRiver basin of Wyoming are achieving recov-ery ratios of 95 percent. The reason for this isthat the coal lost at the seam boundaries in athick seam is a small fraction of the total coalbeing mined. The operator often does not re-cover 6 to 12 inches of coal at the upper andlower seam boundaries, because this coalusually contains significantly more mineralmatter than the remainder of the seam, Theproportionate amount of the seam thicknesslost is much less for a 50- or 100-ft thick seamthan it is for a 5- or 10-ft thick seam.

A multiseam surface operation will oftenhave a lower recovery ratio than a single-seam mine because a certain thickness ofcoal is lost for each boundary between a coalseam and the surrounding material. Hence,even though the cumulative thickness of theseams in a multiseam mine approaches or ex-

ceeds the seam thickness in many single-seammines, the percentage of coal not recoveredwill be greater.

Recovery ratios in surface coal mines alsocan be adversely affected by such factors asextreme seam dip, faults, and characteristicsof the overburden material that interferewith stripping operations. Such problems arecommon in the surface mines of northwesternColorado and southwestern Wyoming. How-ever, mines such as the Colowyo and theTrapper mines encounter a combination ofthese problems but still achieve recoveryratios in excess of 80 percent. Seam dip at theCanadian Strip Mine in north-central Colora-do is so steep that it has been necessary to im-plement what is essentially a contour stripoperation. Here a bench is cut into the hill-side and all of the coal in the bench area ismined. Even though the ratio of waste materi-al removed to coal mined is on the order of15 or 20 to 1, only a small percentage of thecoal is not recovered.

The recovery ratio for underground miningwill usually be less than for surface mining asa certain amount of the coal must be left inplace around access facilities such as shafts,slopes, drifts, main entries, and submain en-tries. Additional coal is also lost that is left inboundary pillars around the perimeter of theproperty and in pillars in the mined out areasto support the roof and prevent or lessen sub-sidence of the surface.

Recovery ratios for room-and-pillar mineswill vary from a low of 20 percent to a high of80 depending on the completeness of the sec-ondary recovery of pillars from the miningpanels. The average recovery ratio for allroom-and-pillar mines in the country is 62percent. Several equally important factorsdetermine the recovery ratio of these minesincluding the dip of the seam, the presence ofigneous or other intrusions in the seam, faults(vertical displacements in the seam), and thedepth of the seam. The depth of the seam isimportant in the West where many mines are

—


2,000 to 3,000 ft deep. The greater the depthof the seam, the more overlying rock stratathat must be supported by pillars left aroundaccess facilities and in the mining areas. Toavoid failure of these support pillars due toexcessive loading, they must have largercross-sectional areas, I f the p i l l a r s a relarger, then the amount of coal that can be re-covered will be correspondingly less. Supportproblems caused by the depth of the seam canbe aggravated by the presence of faults, poorcompetency of the rock strata forming thefloor and roof of the mine, and excessivewater. Several of these conditions are foundat mines with Federal coal leases in westernColorado. Conditions became so severe atU.S. Steel’s Somerset Mine that one of themining levels had to be abandoned, Stressesinduced in support pillars at this mine causedthe pillars to fail explosively, However, ac-cording to a spokesman for the Bureau ofMines, this problem has been brought undercontrol at Midcontinent’s Coal Basin complexin Colorado,

Recovery ratios for longwall mining rangefrom a low of 50 percent to a high of 80. Theaverage recovery ratio for all longwall minesin the country is 75 percent. * Longwall min-ing generally results in higher recovery ratiosthan those achieved in room-and-pillar min-ing when the latter does not include full ex-traction of the pillars. A good example of therecovery ratio increases which can be ex-pected from longwall mining when comparedto room-and-pillar mining is found in the DeerCreek-Wilberg mine complex of Utah Power &Light in central Utah. These mines hadopera ted as room-and-pillar mines withrecovery 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 m i n i n g i n t h eUnited Stales is even higher [84 percent). As in longwall min-i 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 {hec(N]1 ;+nd haul[~ge is done bv shut tlc (:[~r rather I han with a con-tinuous (xlnvey(]r. Shurtwall mining may he used in the futurein the 14’es t in ciiscs where :) 600-fl fi~(’e is not ava il[lble. Per-S( ~n;{ I (Jomm un ir:i t ion t( ) ()’I’A from I):\ n iel J. Sn\’der, 111, Pres i-dent. (I()]{)rild~J-Wcs tnlf)rt; ltlrl(i. In(’., June 15. 1981.

pany has already installed one longwallsystem and plans to install a second. Therecovery ratio for the longwall system at thismine is approximately 80 percent.

Production and Productivity

Although there is no hard and fast relation-ship between the production rate for a mineand its rate of labor productivity, it is oftentrue that those mines with high productionrates also will have relatively high rates oflabor productivity, The reason for this is thatboth surface and underground mines withhigh production rates generally have trainingprograms and equipment that will generatehigher labor productivity y.

The large surface mines of the WesternUnited States have long been characterizedby high rates of labor productivity. The pro-ductivity of some of these mines is as high as30 to 35 tons per worker per day. The aver-age productivity rate for all surface coalmines in the United States is approximately15 tons per worker per day, Since labor is oneof the major costs for any mining operation,productivities on the order of 30 or more tonsper worker per day translate into signifi-cantly reduced unit operating costs. How-ever, high rates of productivity are typicallyachieved as the result of greater investmentsin equipment, so that the reduction in unit op-erating costs will be partially offset by in-creases in the unit capital costs. Further-more, capital costs for initial infrastructuredevelopment and interest charges are themost significant costs in coal mining.

Because there are fewer operating con-straints, surface mining will generally pre-sent fewer problems with respect to achiev-ing high production rates and concomitantlyhigh labor productivity rates. The achieve-ment of these goals in underground coal min-ing, however, requires good mining conditionsas well as good management and a willing-ness to invest in the appropriate equipment.A good example of the high level of productiv-ity that can be achieved in underground min-ing is the Soldier Canyon Mine of California

.


Portland Cement Co. in central Utah. Using alongwall system, this mine is achieving alabor productivity of 23.5 tons per worker perday and an annual production rate of over 1million tons. This productivity rate is not onlymuch higher than the national average of 8.6tons per worker per day for underground coalmining but also exceeds that achieved bymost surface coal mines,

It is generally accepted that longwallmining represents a better opportunity forachieving higher production rates, higherlabor productivity rates, and better safety inunderground mining. A room-and-pillar oper-ation using continuous miners can readilyachieve shift production rates of 350 to 400tons. Rates in excess of 700 tons per shift areexceptional, In the case of longwall mining,shift production rates in excess of 1,000 tonsare common in the West and rates of 1,500 to2,000 tons per shift have been achieved at anumber of longwall operations.

Environmental

Environmental problems resulting fromcoal mining operations in the arid West aremore likely to be associated with surface min-ing than underground mining. Environmentalissues are discussed in detail in chapter 10.Although the siting of surface facilities forunderground mining operations will generallyhave limited environmental impacts, a poten-tially greater problem associated with in-creased underground mining on Federal coalleases is surface subsidence. * The impactfrom subsidence depends on the location ofthe mine and is greatest in highly built-up ur-ban areas. This problem is most often asso-ciated with cities and towns in the EasternUnited States but has also occurred in West-ern towns such as Rock Springs, Wyo., wherebuildings and other facilities located inseveral areas of the city have been endan-gered.

*Acid mine drainage, which can be an acute problem inmany mining areas in the East, is not a significant problem inmost arid regions of the West.

Surface subsidence can also be a problemin rural and unpopulated areas. Differentialsubsidence can break through to the surfacein the form of fractures and sinkholes. Moretypically, subsidence will manifest itself inthe form of a generally lowered surface ele-vation, This will not be a problem unless itoccurs under a stream, railroad, highway,building, or dam. Even then, the adverse ef-fects of subsidence can be minimized if themine is properly planned. In several Euro-pean countries, especially West Germany,where the art of deploying planned subsid-ence is well developed, entire towns havebeen lowered as a result of underground min-ing without adverse effects.

It is becoming apparent that longwall min-ing is usually preferred to room-and-pillarmining where surface subsidence may be aproblem. The reason for this is that longwallmining is more likely to produce more uniformand predictable subsidence. Concern aboutthe potential impact of surface subsidence onsprings and ground water hydrology has beenexpressed by local residents in mining areasin Utah and Colorado. Subsidence tends to bedifferential in room-and-pillar mining andmay not occur until years after mining opera-tions have been completed. It may then occurwithout warning and with potentially catas-trophic results. However, full recovery of thepillars will usually result in the more uniformsubsidence comparable to that achieved withlongwall mining.

Roof Support

Deeper mines require that larger supportstructures be left in place in the undergroundworkings. Greater support can be accom-plished by leaving the coal in place or by re-placing it with substitute support structures,For longwall mining there is increasing evi-dence that control led subsidence of themined areas reduces support stresses onboundary pillars that are left in place alongmain and submain entries. In some longwall

-.


mines it has been necessary to install supple- much less than that required to support thementary 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 theWestern United States

This section reviews mining technology de-velopments in Europe and the United Statesand discusses possible solutions of the miningtechnology problems described in the preced-ing section.

Because surface mining techniques andequipment in the United States are relativelyadvanced compared to underground coalmining technology in the United States, onlynew underground technology developmentswill be discussed in this section. As thenumber of underground mining operations in-creases in the West, improvements in under-ground mining technology can lead to signifi-cant improvements in coal production, recov-ery ratios, productivity rates, and safety.

Comparison of Mining Conditions inEurope and the Western United States

Mining conditions on Federal coal leasesvary from nearly ideal to some of the mostdifficult conditions anywhere in the world.For example, in certain locations in north-western Colorado and in northwestern NewMexico the minable seams are a few hundredfeet deep and from 6 to 30 ft thick, the dips ofthe seams range from the horizontal to a fewdegrees, there are few faults, and the floorand roof rocks are nearly ideal for support. Incontrast, the conditions found at some exist-ing mines with Federal leases in western Col-orado and central Utah include depths ofcover that are over 3,000 ft, seams that rangefrom 4 to over 40 ft in thickness, seam dipsthat approach 350, extreme fracturing andfaulting of both the coal seams and the confin-ing rock strata, and floor and roof rocks ofvery poor competency. Many mines in Colo-

rado and Utah extract coal from seams thatare over 1,000 ft deep.

Mining conditions vary in other areaswhere there are substantial Federal lease-holdings. For example, in the Powder Riverbasin of northeastern Wyoming the depth ofcoal seams ranges from a few hundred feet toan undesirable 2,000 to 3,000 ft. However,most other mining conditions are good in thisarea. Difficult mining conditions in the StarLake-Bisti area of New Mexico include seamdips up to zoo and faults. In Oklahoma,high concentrations of methane gas and un-dulating, thin seams cause extremely difficultmining conditions on most Federal leases.

Direct comparisons of coal mining in Euro-pean countries with coal mining in the West-ern United States can be misleading becausemany mining conditions are different in thesetwo areas. The principal coal mining coun-tr ies of Europe—France, Great Brit ian,Czechoslovakia, the Soviet Union, Poland, andWest Germany— are currently mining coalfrom seams that would be considered unmin-able in the United States. A condition which ispresent in all of these countries, but whichhas not been observed in the Western UnitedStates, is extreme folding of the coal seams.In the case of folding, it is necessary to dealnot only with steeply dipping seams but ver-tically oriented seams as well. Most of thecoal mined in England is extracted fromseams that are deeply buried, thin, folded,and faulted. Both France and Poland are cur-rently operating deep mines with almost fullextraction of coal seams 20 to 30 ft thick.However, even though many mining condi-tions in Europe differ from those in theWestern United States, the use of longwall

Ch. 11-Mining Technology ● 337

mining in Europe to extract deep, thick seamsis relevant to assessing the technical poten-tial for extracting deep, thick seams in theWestern United States.

New Equipment Developments

The equipment developments discussed be-low include both refinements to existing un-derground mining technology and new equip-ment concepts that are still in the prototypeand testing stage. New equipment and con-cepts could solve many of the problems de-scribed in the section on mining technologyproblems.

Longwall Mining Improvements

Modern longwal l mining technologyemerged in its present form in Germany, theSoviet Union, and Great Britain during thelatter part of the 1950’s after more than 20years of continuous development in thesecountries. Refinement and improvement oflongwall equipment and techniques havesince continued in these countr ies . TheUnited States has been a late entrant into theuse of longwall mining, and the equipmentmanufacturers in this country have made rel-atively few contributions to the technologyduring the past 10 years.

Many of the recent developments in long-wall technology have dealt with improve-ments in reliability and production capability,although there also has been considerable ef-fort to improve safety conditions associatedwith longwall mining. The discussion of theseimprovements of longwall mining technologywill be organized according to the three prin-cipal components of a longwall system; roofsupport, the face conveyor, and coal cuttingand loading.

Principal improvements in the longwallsupport system have included increases inthe load-carrying capability of the hydraulicrams, increased maneuverability of the sup-ports, better stability, and refinements in thecontrols. Most manufacturers of longwallsupports now offer units that have maximumyield loads of 1,000 tons or more, The in-

creases in the maximum yield loads also havebeen accompanied by the development ofshields and chock-shields that offer greaterstability and more protection to the miner.Advancement and alinement of the supportsnow can be done remotely which not only re-duces the time required for advancing thesupport system, but also allows locating min-ers away from the moving support and out ofthe way of falling material caused by move-ment of the support.

The transport of the cut coal away fromthe longwall face by the face conveyor stillremains a major potential bottleneck in thelongwall mining system. A breakdown in theconveyor can result from broken fl ightchains; minor delays also are caused by over-sized lumps of coal becoming stuck in con-veyor transfer points. The broken flight chainproblem has been partially solved by the useof a “twin-inboard” chain at the center of theflight which reduces stress on the flightchains as the flight conveyor bends aroundcurves. The need for a transfer point at theheadgate where the face conveyor meets thepanel belt conveyor in the headgate entry hasbeen eliminated by the recent innovation ofthe roller curve in West Germany. The rollercurve allows the face conveyor to turn the900 corner at the headgate and to dump coaldirectly onto the panel gate conveyor or into afeeder-breaker which reduces the size ofoversize lumps and then feeds the coal ontothe panel belt conveyor.

The majority of the longwall cutter-loadersinstalled in the United States are shearersrather than plows. Two major hazards asso-ciated with the use of shearers have beenhigh coal dust concentrations created by thecutting action of the rotating shearer drumsand the danger from a break in the chain thatis used to pull the shearer back and forthalong the face. Significant reduction of dustconcentrations has been reported through theuse of a “Shearer-Clearer” water spray sys-tem which was developed by Foster-MillerAssociates in conjunction with the U.S. Bu-reau of Mines. This system partitions the air-flow around the shearer into a clean split


through the use of water sprays. The coaldust cloud is confined to the vicinity of thecoal face while the shearer operators remainin the clean split on the support side of thecutting machine.

The broken chain hazard has been solvedby equipment manufacturers in Great Brit-ain, West Germany, and the United Stateswhich now offer chainless drives, These drivesystems are all based on a variation of therack and pinion gear system. Initial indica-t ions a re tha t t hese cha in le s s sys t emsalready have gained wide acceptance by theoperators.

One additional development in longwalltechnology is a system designed specificallyfor steeply dipping seams. The system iscalled the “Troika” and is offered by Hem-scheidt America Corp. It is designed for usein seams that dip up to 750 and is scheduledto be used to extract Federal coal from aseam pitching 330 at the Snowmass Mine inColorado. It consists of three shields con-nected to a central structural beam by adouble-acting ram assembly. The beam is con-nected mechanically to the center shield andto the outer shields by the rams. The centershield, which has no double-acting ram, ismoved by the outer shields with the ramsthrough the beam. The outer shields followthis beam during movement.

The new equipment developments for long-wall mining are potentially important, butbetter use of available equipment is an equal-ly important aspect of technology develop-ment for this system. An example of the latteris the use of available longwall technology toextract the maximum thickness possible fromseams that are thicker than the approximately12-ft seams currently being mined with con-ventional longwall systems.

One approach to thick seam extraction inunderground mining is the double lift long-wall method currently being developed tomine Federal reserves at the Coal Basin Com-plex of Midcontinent Resources under a cost-sharing contract with the Department ofEnergy. With this system, the coal seam is ex-

tracted by taking two successive passes ofthe longwall. Total thickness of the coal seamis 25 ft; by taking two 10- to 12-ft lifts, all but5 ft of the seam will be recovered. Althoughthis is less than the total seam thickness atCoal Basin, it is a significant improvementover the extraction of 8 to 10 ft of coalachieved with the single lift approach. Con-ceptually, this method could be extended toextract the full coal seam, using three ormore lifts.

Another approach to thick-seam miningusing a longwall system, developed in France,uses a single-lift longwall operation under thebottom of the sea. The roof supports on thissystem have been modified to allow the por-tions of the seam located above the longwallto cave in behind the supports under the over-lying broken roof rock. The broken coal isthen collected on a conveyor belt running be-hind the supports.

Room-and= Pillar Mining Improvements

For some time there has been an aware-ness that the cutting action used by existingcontinuous miners is less efficient and pro-duces more dust than alternative cutting ac-tions. Tests of the linear-cutting miner experi-mental concept developed by the U.S. Bureauof Mines have indicated that deeper cuts atconstant depth in the coal face can be mademore efficiently, while reducing the respir-able dust that is normally generated by con-tinuous miners. It is estimated that this newcutting concept would produce three timesthe amount of coal with one-third of the dustand would use one-third to two-thirds lesselectrical power, depending on the cuttingdepth. However, the development of the com-mercial machine is not likely for another 20years.

A concept for extracting more coal frompillars during secondary recovery operationsis the underground auger miner developed byFMC under contract to the U.S. Departmentof Energy. In addition to the recovery of coalin pillars, the system shows a potential formining out prepared panels of coal at signifi-cantly lower cost than conventional methods.

Ch. 11l—Mining Technology 339

The system consists of an undergroundaugering machine, a two-stage coal conveyor,and auxiliary ventilation and rock-dustingequipment. The auger miner excavates coalby drilling a series of large holes side by sideinto [he coal seam. The conveyor carries thecoal to the mine’s face haulage system, Thein-hole ventilation and rock-dusting equip-ment is used to dilute methane gas and coaldust to nonexplosive concentrations,

The availability of efficient and reliablehaulage systems has long been one of thegoals of underground mining technology de-velopment. Existing rubber-belt conveyor sys-tems have gone a long way to satisfy this re-quirement, but major deficiencies remain atthe face. The principal need is for a contin-uous haulage system which is sufficientlyflexible to adapt to the multitude of configu-rations experienced during the developmentand product ion from a coal panel. Besides theneed for flexible components, there is also aneed for an efficient method for transferringcoal from one component to another, e.g.,from shuttle cars to panel belt conveyors. *

* This need is also eveident for panel development in longwallmining

Long-Airdox has introduced a continuoushaulage concept that is based on the use ofmobile bridge carriers and piggyback bridgeconveyors. A piggyback bridge is atttacheddirectly to the boom of the continuous minerat one end and is supported by a dolly at theother end. This dolly is designed to move free-ly along rails mounted on top of the sides of aseparate mobile bridge. Coal flows from theminer to a piggyback bridge to a mobilebridge to a piggyback bridge, and so on, untilit reaches the last piggyback bridge’s dollyand is dumped onto the panel belt. Fourstandard mobile conveyors (each 30 ft) cou-pled with five standard piggyback conveyors(each 3 to 41 ft) can provide an effectivereach of over 300 ft in a seven-entry miningprojection.

Other concepts of continuous haulage thathave been tested include the use of air andwater as the carrying media for crushed coalin pipelines. Although this approach offerssome advantages, it is still more difficult toimplement than are concepts based on theuse of conveyor belts. A slurry pipeline sys-tem has been installed in one Eastern mine,however,

Considerations for Using Improved Longwall MiningTechniques on Federal Coal Leases

The preceding sections of this chapterhave provided an overview of mining systemscurrently in use on Federal coal leases andhave considered several of the technologyproblems associated with the use of these sys-tems. This section will address: 1 ) the cost incapital and labor and the time needed to im-plement longwall mining and 2) the compara-tive production advantages and some of thephysical, environmental, and social conse-quences of using this technology.

Capital

During the 20-year period that reliablelongwall mining systems have been on the

market, an important reason for the reluc-tance of coal producers to use this technologyhas been the initial cost of installation. Theinstallation of a complete longwall miningsystem, not including the cost of developmentworkings and other mine infrastructure, re-quires the expenditure of a single large lumpsum of capital, usually $1.5 million per 100 ftof face length. This cost includes: 1 ) the facesupport subsystem, 2) the face conveyor sub-system, and 3) the coal cutting-loading sub-system. The total installed cost of the threelongwall subsystems will vary significantlyfrom mine to mine. The more important var-iables which determine the cost of a specificlongwall system include the length of the

——. . . —


face, the height of the coal to be cut, the geo-logical conditions of the seam, the thicknessand quality of the roof rocks (which deter-mine the capacity of the face support subsys-tem required), and the rated capacity of thesystem.

The typical longwall system now being in-stalled in the Western United States has a de-signed face length of 600 ft and a rated pro-duction capacity of 1,250 tons of coal pershift. However, the actual production capac-ity obtained varies from 700 to 1,500 tons pershift because of variations in mining condi-tions and in the ability of producers to op-erate longwall systems. This compares with anational average of 400 tons per shift forlongwall systems in 1980.

The cost of this typical longwall installationin 1980 dollars is estimated at approximately$9 million. Assuming that the mine operates250 days per year and two shifts per day, therated annual production capacity of the typ-ical longwall system will be 625,000 tons. * Ifthe longwall system is assumed to have a pro-ductive life of 10 years, which is not unreal-istic if the system is adequately maintainedand there is selective replacement of themore expendable system components, thenthe total production capacity over the 10-yearlife will be 6,250,000 tons of coal. Hence, thetotal installed capital cost of the longwallsystem over the life of the system will be ap-proximately $1.50/ton of coal mined.

The significance of capital cost for long-wall mining can be illustrated by the follow-ing example. Utah Power & Light installed alongwall system in its Deer Creek mine nearHuntington, Utah, in April 1979. The systemwas designed for a 480-ft face and a 10-ftthick seam. The initial production capacity ofthe system was 1,500 tons per shift. However,after only 3 months of operation longwall pro-duction reached an average of 2,500 tons pershift, 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[emis 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 pro-duction of 2,200 tons per shift.

The impact of the success of this initiallongwall system on the entire Deer Creek op-eration is dramatic. Prior to the installationof the longwall unit, daily production ca-pacity at the mine was 7,000 tons. To achievethis production rate it was necessary to useas many as 10 continuous miner sections.With the implementation of the longwallsystem the daily production has increased toin excess of 10,000 tons and the monthly pro-duction to 220,000 tons. Of this 220,000 tons,a total of 115,000 tons is produced by thesingle longwall unit and the balance by eightcontinuous miner sections. With the instal-lation of a second longwall, the company ex-pects the requirement for continuous minersto drop to four sections. Two of these sectionswill be used for longwall panel developmentand two to extract pillars from sections of themine which have already been mined usingthe room-and-pillar technique.

Prior to the installation of the first longwallunit the Deer Creek Mine was producing 1.75million tons of coal per year, This rate wasachieved through the use of 10 continuousminer sections. Assuming an average invest-ment of $700,000 per section, the total invest-ment in mining equipment was $7 million.Based on a 10-year life for the continuousminers and auxillary equipment, the totalcapital cost per ton of coal mined over the 10-year period was $0.40. Assuming an installedcost of $9 million per longwall unit, a similarcalculation for the 2-longwall and 4-contin-uous miner production system now producing2.64 million tons of coal per year results in acapital investment of $0.80/ton of coal pro-duced over a lo-year period, assuming thelongwall units and the continuous minershave productive lives of 10 years. Consider-ing the cost of money at 20 percent and totalfinancing of the equipment, the all continuousminer system cost becomes $0.85/ton and thecost for the mixed system $1,65/ton.

Although the capital cost per ton of coalproduced is higher for the longwall system,labor costs are reduced. Assuming that the

Ch. 11—Mining Technology 341

longwall and the continuous miner sectionsboth require 10-person crews for their opera-tion and that the size of the maintenance sup-port staff is the same for both the all contin-uous miner mine and the combined longwalland continuous miner mine, the combined op-eration will require 80 fewer hourly employ-ees to operate on a two shift per day basis.Based on a direct hourly rate of $9/hour and afringe benefit rate of 35 percent, each ofthese 80 employees costs approximately$25,000 per year. Therefore, the total savingsin labor costs for the mine configuration usingthe combined systems is $2 million per year,This sum is 14 percent of the difference incapital cost between the combined operation($21 million) and the all continuous mineroperation ($7 million). When the fact that thecombined operation produces 900,000 addi-tional tons of coal per year is factored in,then the payback period becomes of the orderof 2 years.

There a re a number o f ex i s t ing andplanned underground mines on Federal coalleases that could use development strategiessimilar to that of the Deer Creek Mine. TheSkyline Mine of Coastal States Energy Co.,which is located near Price, Utah, is sched-uled to open in 1982 with an initial productionrate of 437,000 tons per year, This rate ul-timately will be increased to 5.4 million tonsper year. Over 40 percent of this production,2.3 million tons, is scheduled for three long-wall units ranging in capacity from 702,000to 864,000 tons per year. Because of extremevariations in seam thickness and the pres-ence of faulting on the property, problemswhich do not exist at the Deer Creek Mine,the balance of the annual production will bemined with continuous miners. It is estimatedthat 14 continuous miners will be required toproduce their 3. l-million-ton share of the an-nual production.

Labor

As the above section shows, increased cap-ital costs for longwall mining can be offset byreduced labor costs and increased produc-tion, Because the costs of capital and labor

will be the major inputs into any mining sys-tem, both surface and underground, therealways will be some tradeoff between thetwo, which will vary from mining system tomining system. However, several aspects oflabor requirements for longwall systems dif-fer from the labor requirements for room-and-pillar systems. These differences cannotbe readily quantified in terms of direct cost.

Western coal mines usually recruit theirminers from the general labor force. Someworkers may come to the industry with abackground in construction or some other re-lated occupation, but few have any mining ex-perience. Therefore, if a mine using longwallmining hires a new employee, there is fre-quently no need to retrain an individual re-cruited from room-and-pillar operations. Thisability of the Western coal miner to adaptreadily to the longwall mining environmenthas been noted by a number of companies. Asindicated above in the discussion of the DeerCreek Mine, the production rate from its new-ly installed longwall face increased from1,500 tons per shift to 2,500 tons per shift inlittle more than 3 months of operation. Theonly experiences longwall miners at the timethe longwall unit was installed were the threeshift foremen. The Coal Basin Mine longwalloperation in western Colorado and the Sun-nyside Mine in central Utah also have hadgood experiences with the installation of theirfirst longwall units. Like Deer Creek, thesemines have achieved production rates muchhigher than those obtained at many of thelongwall units located in Eastern coal mines.

Another benefit of longwall mining fromthe point of view of the mine operator is thereduced labor requirement when comparedto room-and-pillar systems. This factor is anadvantage both with respect to f indingenough qualified employees to staff an opera-tion and in reducing the amount of infra-structure needed where a mine is remotelylocated and requires development of a sup-porting community infrastructure to serveemployees, Since minable coal deposits in theWest often are located in sparsely populatedareas, the availability and the housing of


employees are two major considerations. Inthe case of a mine such as Skyline, which islocated in a large rural area of Utah thatalready has seen the expansion and develop-ment of a number of large mines, attractingskilled labor becomes a problem. Thus, reduc-tion in the total number of operating employ-ees required from 480 for a mine using allcontinuous miners to 340 for a mine using acombination of continuous miners and long-wall units is significant,

There are other advantages to the mine op-erator of reduced overall manpower require-ments. These include the reduced potentialfor personnel turnover, less need for em-ployee training, and an overall reduction inpersonnel support costs. Operating with asmaller labor force also means that fewerpeople will be exposed to the hazards of un-derground coal mining per ton of coal pro-duced. This will be discussed in greater detailin the section on health and safety,

Production and Productivity

As has been discussed in preceding sec-tions of this chapter, production and pro-ductivity are related but separate opera-tional considerations. An increased produc-tion rate is of interest to the operator who hasthe reserves to support large market commit-ments but who is not able to produce the coalrequired of these commitments because of de-ficiencies in the production system. In con-trast, productivity is of interest to all mine op-erators, Productivity is usually discussed interms of coal output in tons per unit of laborexpended, but is equally applicable in termsof coal output per unit of machine time ex-pended. Whether stated in terms of labor pro-ductivity or equipment productivity, the ob-jective is to maximize coal production perunit of resource used.

The question of improved productivity andlongwall mining has been addressed. In thediscussion of the capital cost of longwall min-ing, the potential for improving labor produc-tivity through the installation of longwallequipment was illustrated by two examples.It was also shown that even though the im-

proved labor productivi ty was achievedthrough the use of longwall equipment whichwas more expensive than the continuousminers it replaced, the overall effect was areduction in the total cost per ton of coalmined.

The underground coal mining industry inthe United States has undergone significantchange in the past 10 years. A 500,000-ton-per-year mine, formerly considered a largemine, is now considered of small to averagesize. With this change, production equipmentand the scheduling of equipment have becomemore complex. Whereas a 50(),0()0-ton minecould operate with two to three continuousminers on a two shift-per-day schedule, minessuch as the Skyline Mine discussed abovewould require 24 continuous miners to sus-tain its 5,4-million-ton-per-year productionrate, Coping with the production schedulingin a mine where there are 24 operating sec-tions which require the assignment of man-power, equipment, maintenance, and trans-portation is an extensive and demanding task.The Skyline operation is not unique in this re-spect. Other existing and planned under-ground mines on Federal leases that even-tually will be producing in the 5-million-ton-per-year range include the Price River CoalCo. mine (formerly Braztah) in Utah and theLoma Complex in Colorado. In the 2-million-to 3-million-ton-per-year range there will beSUFCo in Utah, Mt. Gunnison in Colorado,Energy Development in Colorado, and poten-tially La Ventana in New Mexico, The minesin the l-million- to 2-million-ton-per-yearrange are even more numerous.

Nearly all of these mines will install long-wall units, One of the major considerations inarriving at the decision to use longwall min-ing at these mines has been the need toachieve high production rates. A single long-wall unit can produce 750,000 tons of coalper year. The longwalls at the Deer CreekMine are producing in excess of 1 million tonsper year per unit, The Wilberg Mine, a sistermine of Deer Creek, is installing a longwallunit that is rated at 3,000 tons per shift. Thistranslates into 1.5 million tons per year,

Ch. 1 l—Mining Technology ● 343

Coastal States Energy Co. is currentlystudying the feasibility of using longwall min-ing at its SUFCo Mine which is located onFederal leases near Salina, Utah. The minableseam, the Hiawatha, varies from 6 to 15 ft inthickness. However, the average thickness is12 ft and with the exception of thinning onone part, the lease tends to maintain this aver-age over extensive areas. There is little dip tothe seam and little noticeable faulting. Insum, these conditions suggest that installa-tion of at least one longwall unit to replacesome of the existing 10 continuous minerunits would simplify the operation and mightreduce the cost of mining.

In summary, Western underground minesneed to continue to pursue methods for in-creasing their production rates and improv-ing their productivity. These combined goalswill lower their unit mining costs and therebyenable them to compete more effectively withthe coal mines in the Eastern United Statesand the large surface mines in the West.Other than reduced mining costs, an addi-tional advantage of the increased productionrates could be the ability to use unit-traintransportation to move coal to markets andthereby recover some of the transportationcost penalty associated with supplying coal toMidwestern and Eastern markets.

Environmental

In the arid West, the impact of under-ground coal mining on the environment is gen-erally less than that resulting from surfacecoal mining. Longwall mining can furtherreduce the environmental impacts normallyresulting from room-and-pillar operations.

Subsidence from underground mining cantake the form of either a wide-area loweringof the ground surface or sinkholes and frac-tures that break through to the surface. Theresults of several studies, conducted both inthe United States* and Europe, indicate that

longwall mining is most likely to result inwide-area subsidence and to cause little dif-ferential subsidence that can result in breaksin the ground surface. These studies alsohave indicated that surface subsidence isgenerally limited to an amount equal to one-half the thickness of the coal being extracted,although it can exceed 50 percent and can goas high as 90 percent of the seam thickness.For the thicker seam longwall operations, thiswould generally mean a subsidence of about6 ft. A lowering of the surface elevation ofthis magnitude could be a problem in theWestern United States and would have to behandled on a case-by-case basis. However,the areawide form of subsidence likely toresult from longwall operations is preferableto the differential subsidence that is morelikely to result from room-and-pillar opera-tions,

Health and Safety

Regardless of the type of mine, under-ground coal mining takes place in a hazar-dous environment. Fewer workers will be ex-posed to these hazards in a longwall opera-tion than in other underground coal produc-tion met hods for a given level of production.

Because of the fundamental differences be-tween room-and-pillar and longwall miningsystems it is difficult to make a direct com-parison as to which provides a healthier orsafer environment for the worker. The basichazards—coal dust, methane gas, sponta-neous combustion, roof falls, bumps, andmoving machinery in confined spaces—arepresent in both types of mining. In some casesthere are tradeoffs in hazards, The control ofexcessive coal dust at the longwall face is aproblem that must be solved, although thereare some potential breakthroughs. On theother hand, however, the protection from rooffall hazards provided by longwall supportsis superior to that available to the continuousminer operator.

Equipment advances that improve the un-derground mining environment with respect


to worker health and safety will continue. tivity and a concomitant reduction in theHowever, the most direct results will be ob- number of workers that must be exposed totained through increases in labor produc- the dangers of underground coal mining.

CHAPTER 12

Revenues andSocioeconomic Impacts

Contents

PageIntroduction ● . . . . . . . . . . . . . . . . . . . . . . . . . . 347Background. . . . . . . . . . . . . . . . . . . . . . .......347

Potential Federal Coal Leasing Revenues. ..348OTA Estimates of Potential Revenues From

Federal Coal Leases. . ...................349Bonuses . . . . . . . . . .......................349Rentals . . . . . . . . . . . . . . . ..................350Royalties . . . . . . . . . . . . . . . . . . . . . . . ........350

State Allocation of Federal .MineralLeasing Revenues. . . . . . . . . . . . . . . . . . . . .352

Colorado . . . . . . . . . . . . . . .................352Wyoming, . . . . .. ., $ .....................353Utah . . . . . . . . . . . . .......................353Other Western States . . . . . . . . . . . . . ........354

Federal Programs To AssistEnergy-I m p a c t e d C o m m u n i t i e s . . . .............354

Loans Against Future Leasing Revenues. ....354Payment in Lieu of Taxes (PILT). . ..........354Abandoned Mine Reclamation Funds. ......355“601” Program . . . . . . . . ..................355Other Federal Programs. . .................355

S t a t e P r o g r a m s . . . . . . . . . . . . . . . . . . . . . . . . . 3 5 6Severance Taxes . . . . . . . . . . . ..............356State Energy Facility Siting Programs. .. ....359

Effects of Expanded Federal CoalProduction . . . . . . . .**..*** ● ..*.*.* . . . 360

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 361Utah . . . . . . . . . . . . .......................363New Mexico . . . . . . . . . . ..................364Wyoming and Montana . . . . . . . . ...........365North Dakota . . . . . . . . . . ..................367Oklahoma . . . . . . . . . . . . . . . . . . . . . . ........368

List of Tables

Table No. Page94. Federal Coal Production and Royalty

Revenues, by State: Fiscal Years 1979and 1980.. . . . . . . . . . . . . . . . . . . . . .. ....348

95.

96.

97.

98.

99.

100,

101.

102.103.104.

105.

106.

List

PageCompetitive Coal Lease Sales on PublicLands Fiscal Years 1954-1980..........350Estimated Rental Payments for FederalLeases in 1986 and 1991. . .............3501986 and 1991 Competitive Mine-MouthPrices by Federal Coal ProductionRegions . . . . . . . . . . ..................351Federal Royalties and StateDistributions From Potential CoalProduction on Federal Leases 1980and 1986, 1991... . ....................352Colorado Allocation of FederalCoal Royalties . . . . . . . . . ..............352Wyoming Allocation of Federal MineralLease Revenues. . . . . . . . . . . . . . . . . . . . . .353Utah Allocation of Federal MineralLease Revenues. . . . . . . . . . . . . . . . . . . . . .353Payments in Lieu of Taxes by State. .....354Coal Severance Taxes. . ...............357Allocation of Coal Severance TaxRevenues . . . . . . .....................358Demographic Characteristics ofSelected Counties in Colorado, Utah,and New Mexico. . . . . . . . . . . . . . . . . . . . .362Demographic Characteristics ofSelected Counties in North Dakota,Wyoming, and Montana. . .............366

of Figures

Figure No. Page53. Total Severance Tax Revenues. . . , .. ....35754. Counties of the Rocky Mountain

Study Area. . . . . . . . . . . ................36155. Counties of the Great Plains Study Area. ..365

CHAPTER 12

Revenues and Socioeconomic Impacts

Introduction

This chapter responds to the third ofOTA’s tasks under Public Law 94-377: cal-culation of potential Federal revenues fromexisting leases, It provides an estimate ofrevenues from rentals and royalties based onOTA’s analysis of lease development and pro-duction prospects. The chapter also de-scribes the various methods used by theWestern coal States to distribute their shareof mineral leasing revenues and discussesFederal and State programs for amelioratingthe adverse impacts of energy development.Areas that potentially will be affected by ex-panded Federal coal development are iden-tified.

Background

Rapid growth and its consequent socialdisruption have been characteristic of muchenergy development in the Northern GreatPlains and Rocky Mountain regions. Large in-fluxes of people, associated with the con-struction and operation of energy projects,have come to rural towns. Prior to this, manyof the communities had stable or decliningpopulations and economies based on serviceto agriculture.

With the sudden increases in population,loca l soc ia l s t ruc tu res have been ha rdpressed to meet the needs of the residents.Both public and private sectors have faceddifficulties. Among the consequences of rapidgrowth have been:

● acute housing shortages with rapid costescalations;

inability of the public sector to provideservices, such as sewer and water, in atimely way;dislocations in the private sector, suchas business failures and labor short-ages;manifestations of inc reased soc ia lstress, such as crime, truancy, and sui-cide;accompanying pressure on health, wel-fare, public safety, and mental healthservices;discontent expressed by both old andnew residents; andhigh turnover rates and declines in pro-ductivity among employees of energy in-dustries.

Financial shortfalls during the early stagesof rapid growth have been particularly acute.These are called front-end financing diffi-culties. New public works, such as water orsewer systems, cannot be built quickly andthey are expensive. In some instances, localvoters have been reluctant to approve bondissues for public works, fearing that after theboom they will be left with a large debt. Inother cases, towns have been limited by Statestatutes in the amount of debt they can incur.

As a result, most Great Plains and WesternStates have devised mechanisms to assistlocal governments in meeting both their front-end financing requirements and the otherneeds arising from rapid growth. Federalmineral leasing revenue payments are an im-portant source of funds for impact assist-ance. A variety of types’ of other Federal aidalso are available.

347


Potential Federal Coal Leasing Revenues

Under section 35 of the Mineral LeasingAct of 1920, each State receives a share ofthe revenues derived from sales, bonuses,rentals and royalties from mineral activitieson public lands within its borders.1 Original-ly, a State’s share was 37.5 percent; it was tobe spent by the State legislature “for the con-struction and maintenance of public roads orfor the support of public schools or other pub-lic educational institutions.’” Of the remain-ing revenues, 52.5 percent went to the Recla-mation 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 billionwas distributed to the Western States forpublic roads and schools. There was no re-quirement that the areas most affected bymineral development on Federal lands re-ceive priority in the allocation of the States’share.

In 1976, section 35 was amended to in-crease a State’s portion of the revenues from

130 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 per-

cent of the Federal mineral leasing revenues generated withinthe State since it does not participate in the Reclamation Fund.See 30 U.S.C. 191. The Reclamation Fund was established bythe Act of June 17, 1902, c. 1093, 32 Stat. 388, now codified at43 U.S.C. 391, as amended. Moneys in the Fund are to be usedfor the reclamation of arid and semiarid lands through con-struction of dams, reservoirs, and irrigation projects, and forother specified purposes for the benefit of 17 Western States.

37.5 to 50 percent. The amount paid into theReclamation Fund was reduced to 40 percent.In addition, purposes for which the State dis-tributions could be spent were broadened. ’Each State legislature can now allocate min-eral leasing revenues “giving priority to thosesubdivisions of the State socially or economi-cally impacted by the development of miner-als leased under this chapter for 1) planning,2) construction and maintenance of public fa-cilities, and 3) provision of public service.”5

This language established for the first time aspecific priority for use of the revenues forimpact assistance,

According to the Congressional Budget Of-fice (CBO), a total of $210 million in Federalmineral royalty payments were distributed tothe States in fiscal year 1979,’) Most of thesepayments came from oil and gas leases; only$14 million (about 7 percent) came from coalleases on Federal lands in the West, ac-cording to CBO. Table 94 shows the total Fed-eral coal production and total coal royaltiesreported by the Department of the Interior

4The major amendments to sec. 35 (raising the Stale’s shareand broadening the purposes) were made by sec. 9 of the Fed-eral 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 FY1980coal production royalty revenues coal production royalty revenues

State (tons) ($) (tons) ($)

Alabama . . . . . .Colorado. . . . . .Kentucky. . . . . .Montana . . . . . .New Mexico . . .North Dakota . .Oklahoma . . . . .Utah . . . . . . . . . .Washington . . .Wyoming. . . . . .

1,7777,401,530

59,6377,964,3164,660,225

589,079333,773

6,778,615215,662

31,136,664

1,9163,852,839

62,3851,298,3251,048,550

134,622789,681

1,476,61243,124

7,411,170

27,7808,562,862

9,21910,345,2556,546,2241,418,129

299,5998,616,415

036,130,862

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; theStates received one-half of these receipts,

Royalties are expected to increase sub-stantially in the next decade, although themagnitude of the increase depends on theassumptions of the forecaster. CBO estimatesthat total payments from all types of mineralleases will reach $450 million to $500 millionby fiscal year 1985. State shares of revenuefrom coal, CBO projects, will grow from $14.1million in fiscal year 1979 to $65 million to$85 million by fiscal year 1985.

Budget figures prepared by DOI for fiscalyear 1982 show an expected increase in totalcoal royalties from existing and new leases inall States from $24,6 million in fiscal year1980 to $131 million in fiscal 1985, and to$792 million in fiscal 1990 (again the Stateswould get half these revenues).7 OTA’s esti-mates of potential revenues from coal produc-tion on existing Federal leases also show asignificant rise in payments (see below).

The increases can be attributed to severalfactors: the anticipated expansion of Federalcoal production, the scheduled readjustmentsof existing leases to, and the issuance of newleases at the higher minimum royalty rate of12.5 percent for surface mines required un-der the Federal Coal Leasing AmendmentsAct of 1976 (FCLAA).

OTA Estimates of Potential RevenuesFrom Federal Coal Leases

Section 10 of FCLAA directed OTA to pro-vide an estimate of the “receipts to the Fed-eral Government” from existing Federalleases. OTA calculated the potential rentalsand royalties for 1986 and 1991 based onOTA’s estimates of the production prospectsfor Federal leases presented in chapter 6 ofthis report. The estimates include increasedroyalty rates on all leases that are due forreadjustment over the next decade.

‘Personal communication, U.S. Geological Survey, Conserva-tion Division, Royalty Accounting Section, February 1981.

According to OTA’s analysis, total Federalroyalty revenues from existing leases in thesix Western coal States should increase from$31.5 million in 1980 to $193 million to $215million in 1986, and to as much as $336 mil-lion to $544 million in 1991 (depending on therate of development of existing leases). TheStates will receive half these revenues. In thepast, the amounts received as the States’shares of bonuses and rentals have beensmall compared to the front-end costs ofmeeting the impacts of coal development.Only when royalty payments started withcommercial production have the States re-ceived significant benefits from coal leaserevenues.

Bonuses

When Federal coal leases are offered com-petitively, the successful bidder pays a lumpsum or “bonus” for acquisition of the lease aswell as an annual rental and percentage roy-alty on production. Under the current biddingsystem, DOI establishes the rental and royaltybefo re the l ease sa le and the l ease i sawarded to whoever offers the highest bonusbid. FCLAA requires that half of the leasesfor sale in any year be offered on a system ofdeferred bonus bidding, which allows lesseesto pay the bonus in installments. No bid canbe accepted for less than the fair market valueof the coal, which is established before thesale by the U.S. Geological Survey (USGS).

No bonus is paid for the acquisition of anoncompetitive preference right lease. Abouthalf of the exist ing leases were issuedthrough the preference right system and themore than 170 pending preference right leaseapplications (PRLAs) could result in new ad-ditional noncompetitive leases. When newleases are offered, the States receive half ofthe bonuses paid.

Table 95 shows the bonus payments re-ceived for Federal coal leases between 1954and 1980. Since 1954 over $15 million hasbeen received in bonuses for competitiveleases. Of this amount, $1.4 million was paidafter the 1976 amendments raising the State

-.

350 ● An Assessment of Development and Production Potential of Federal Coal Leases—

Table 95.—Competitive Coal Lease Sales onPublic Lands Fiscal Years 1954-1980

(acreage, bonus payments, average bonus per acre)

.

Fiscal year

1954 .: . . . .1 9 5 5 . . .1 9 5 6 . . . . ,1957 .1958 .1959 . . . . .1960 . . . . . . . . .1961 . . . . . . . . . .1962 . . . .1 9 6 31964 .1965 . .1966 . . . . . . . . . .1967 . . . . . . . . . . .1968 . . . . . . . .1969 . . . . . . . . . . . .1970 . . . . . . . . .1971 . . . . . . . . . .1972 . . . . . . . . . . . .1973 . . . . . . . .1974 . . . . .1975 . . . . . . . . .1976 . . . . . . . . . . . .1977 . . . .1978 ,.,.,.1979 . . . . . . . . .1980 . .

Total . . . . . . . . .

Total acres

4000

4,3163,863

15,3758,8054,358

12,73338,97620,78010,76823,26444,89443,88588,037

018,49328,386

00

3,989000

5746,3957,817

385.408

$ 4200

4,3176,064

19,176224,179

9,05520,531

202,404143,02339.532

146,258753,727721,294

3,077,7360

370,3957,618,634

00

390,776000

31,380803,408582,369

$15.164.678

$ 1.05.

1.001.571.25

25.462.081.615.196.883.666.15

16.7916.4434.96

020.03

268.3900

97.96000

54.69125.6274.50

$ 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 aslow as $O.25/acre to hundreds of dollars peracre depending on when the sale was heldand on the location and quality of the re-serves.

Rentals

Estimated rentals from Federal leases areshown in table 96. The rentals are small com-

pared to the revenues received from royal-ties. However, for States with large amountsof Federal lands under lease but with smallamounts of production, rentals can be a sig-nificant component of their Federal revenue.Before passage of FCLAA, the amount of an-nual rental paid was subtracted from the roy-alties due. New leases and leases readjustedafter August 4, 1976 do not allow rentals tobe subtracted from royalties and require pay-ment of annual rentals as well as productionroyalties. The amount of rental charged is setby the Secretary of the Interior before thelease sale and at readjustment. Most pre-FCLAA leases have rentals of $1.00/acre;minimum rentals for post-FCLAA and pre-FCLAA leases at readjustment are currentlyset at $3.00/acre, although some leases haverentals as high as $7.0()/acre.

Royalties

Federal coal royalties are based on either astraight fee per ton, generally between $0.15and $0.22/ton for many pre-FCLAA leases, ora percentage royalty of the sale price per tonof coal produced with a statutory minimumof 12.5 percent for surface mined coal, The1979 annual Federal coal management reportnoted the following about the percentage advalorem royalty provision:

The amount of money collected under a cents-per-ton royalty does not increase as the value ofthe coal production increases. During the 1970’s,the Department shifted to percentage ad valoremroyalties which provide that royalty payments tothe Government will increase as the value of thecoal increases. Conversely, the Government willshare the risk with the lessee, receiving in ab-

Table 96.—Estimated Rental Payments for Federal Leases in 1986 and 1991

Number of 1986a 1991aState leases Total acres total rentals total rentals

Colorado . . . . . . . . . . 127 124,091 $253,886 $373,748Montana ... , . . . . . . . 21 37,327 73,992 111,858New Mexico . . . . . . . . 29 44,760 119,772 133,596North Dakota . . . . . . . 20 18,048 46,684 57,556Utah . . . . . . . . . . . . . . 204 279,416 650,721 855,186Wyoming . . . . . . . . , . 101 217,067 548,072 660,734

Total . . . . . . . . . . . . 502 720.709 $1,693,129 $2,192,678a Rentals not reduced for portion of rentals credited to royalties due for unadjusted leases


—

Ch. 12—Revenues and Socioeconomic Impacts ● 351

solute terms, less royalty money should the futureprice of coal decrease.

In calculating the potential royalty pay-ments, OTA used the production estimatesderived from the OTA analysis of the develop-ment prospects of Federal leases (ch, 6 ) ,These production estimates are expressed inranges of production that reflect uncertain-ties based on markets, transportation avail-ability, and the rate of mine construction.Consequently, royalty estimates reflect simi-lar uncertainties, Because detailed long-termcontract information and individual mine costdata were not available, OTA used a regionalcompetitive mine-mouth price of coal in calcu-lating future royalty payments. The actualmine-mouth sales price may be higher orlower than the regional figures used. Thecompetitive mine-mouth prices were derivedfrom an economic analysis done for OTA andare based on projections of the potential de-mand for Western coal. For the Hanna basinand Denver-Raton Mesa coal fields, whichwere not included in the economic analysis,OTA substituted an estimated mine-mouthprice based on a review of DOE’s nationalcoal model supply curves and on OTA con-tractor surveys of mine operators, Table 97shows the competitive mine-mouth pricesused in the royalty calculations.

The estimates for all leases that are duefor readjustment before 1991 reflect higherrental and royalty rates—$3.()()/acre rentaland 12.5 percent surface and 8.0 percent un-derground royalties, Pre-FCLAA lease rent-als were generally set at $1.()()/acre and royal-ties at $0.15/ton. The increases in royaltypayments from readjustments will be sub-stantial. For example, for underground coalmined at $20.0()/ton, the current royalty maybe as low as $().15/ton; on readjustment, itwould be raised to 8 percent of $l.60/ton—more than 10 times the previous level, Forsurface mined coal, the increase will also besubstantial. To ta l Federa l coa l roya l typayments in calendar year 1980 were about$32 million on total production of 69 milliontons, Table 98 shows the potential Federalcoal production, total royalty revenues, andState distributions estimated for 1986 and1991.

Some existing underground mines have re-quested royalty reductions from the currentminimum of 8 to 5 percent or lower under theprovisions of section 39 of the Mineral Leas-ing Act and current regulations, H There is nostatutory minimum royalty for underground

’30 U.S.C. 207

Table 97.—1986 and 1991 Competitive Mine-Mouth Prices by Federal CoalProduction Regions (1979 dollars per ton)

1986 1991Region Btu/lb dollars/ton dollars/ton

Fort Union . . . . . . . . . . . . . . . . . . 6,000 6.00 Surface 6.00 SurfacePowder River basin . . . . . . . . . . 8,500 7.40 Surface 7.40 SurfaceHanna 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 UndergroundColorado . . . . . . . . . . . . . . . . . 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 Surface24.00 Underground 24.20 Underground

San Juan . . . . . . . . . . . . . . . . . . . 10,000 15.10 Surface and 15.30 Surface andunderground underground

NOTE All prices are for steam coal



Table 98.—Federal Royalties and State Distributions From Potential Coal Production on Federal Leases1980 (actual) and 1986, 1991 (estimated) (1986 and 1991 royalties are in constant 1979.1980 dollars)

1980a 1986b 1991b

Federal lease Royalty State Federal lease Federal leaseproduction 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 95-108 245-405 336-544 168-277Details 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 Produc-tion, 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 asareas where underground mining costs are Colorado and Utah where underground pro-high, the royalty paid for underground mined duction is significant. But in return, since thecoal can be higher per ton than that charged royalty reduction is intended to allow thefor surface mined coal. It is possible that, if mine to be operated at a profit, it assures con-many underground operations receive under- tinued production, employment, and otherground royalty rate reductions, total royalty revenues.

State Allocation of Federal Mineral Leasing Revenues

In response to the 1976 amendments and tolocal priorities for impact assistance, eachWestern State has established its own for-mula for spending Federal revenues. As theincome from Federal production grows andlocal needs change, the States can alter thesedisbursement formulas. Current State prac-tices (surveyed by OTA in 1980) are de-scribed in the following section.

Colorado

Colorado distributes its Federal mineralrevenues in four different ways (table 99).The Mineral Impact Fund is dispensed by theExecutive Director of the Department of Lo-cal Affairs, after a recommendation proce-dure involving local, regional and State en-tities. (State severance tax receipts are han-dled in the same way.) The Fund is used forplanning, construction and maintenance ofpublic facilities and for the provision of

Table 99.—Colorado Allocation ofFederal 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 “politicalsubdivisions socially or economically im-pacted by the development, processing, orenergy conversion of minerals” from landsleased from the Federal Government or sub-ject to State severance taxes.9

A limitation of $200,000 per year on thedirect county allotment means that majorenergy-producing counties receive much less

9 Co1o. Rev. Stat, 1973, §§34-63-102 and 39-29-110 (1979Supp.).


than 50 percent of the revenues. The excessgoes into the public school fund, In fiscal year1980, for example, Rio Blanco County gener-ated $5.86 million and Moffat County $1.07million of the $20.3 million that came back tothe State. The $200,000 that each receivedamounted to 3.4 and 18.6 percent of therespective royalty revenues they generated.Six Colorado counties reached the $200,000limitation; the spillover was $7.7 million (38percent of the amount the State received),which raised the school revenues to $12.7million (63 percent of the total receipts).

The original $200,000 per county limitationwas enacted at a time when total minerallease revenues were low and some Coloradocounties were receiving far greater oil andgas revenues than their sparse populationscould justify. These conditions have changeddramatically with substantial growth fromcoal development and expected change fromproposed oil shale processing; as a result,legislation to raise the maximum has recentlybeen proposed.

Wyoming

In Wyoming, revenues from the Federalmineral royalties are assigned according to acomplex formula (table 100). About 19% per-cent is available for local assistance, in-cluding 21A percent for roads, 71/2 percentfor public facilities, and 9¾ percent for com-munities.

The Wyoming Farm Loan Board allocatesgrants from the Impact Assistance Accountand has the authority under the Joint PowersAct10 to issue $60 million in loans to energyimpacted jurisdictions. (See discussion onseverance taxes, below, for a description ofadditional Wyoming mitigation programs. )

Utah

In Utah, 32% percent of the mineral leas-ing revenues are dedicated to a CommunityImpact Account (table 101). Established in1977, it is a revolving fund for loans and

10 Wyo. Stat. §§9-1-l 29 through 136.

Table 100.—Wyoming Allocation of Federal MineralLease Revenues

State Highway Fund for construction and main-tenance of permanent roads and highways inimpacted counties . . . . . . . . . . . . . . . . . . . . . . . . .Public School Foundation Fund. . . . . . . . . . . . . .State Highway Fund ., . . . . . . . . . . . . . . . . . . . . .University of Wyoming (pledged to bondissues). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Incorporated cities and towns for planning, con-struction or maintenance of public facilities orproviding public services ($10,000 plusformula). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Wyoming Government Royalty Impact Assist-ance Account (Farm Loan Board) . . . . . . . . . . . .

(a) For impacted incorporated cities andtowns, counties, joint powers boards withoutexisting revenue sources; and(b) To fund planning, construction and main-tenance of public facilities, provisions of pub-lic services or equipment purchases.

School District Capital Construction Account. .

2.25%37.5026.25

6.75

7.50

9.75

10100%


Table 101 .—Utah Allocation of Federal MineralLease 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 pol i t ical subdivis ions that aresocially or economically impacted by mineralresource development. 11 The account is par-ticularly important since Utah is the onlyWestern coal-producing State without a coalseverance tax. For the 1978-79 period, Utahreceived $13 mil l ion in mineral leasingmoneys of which $4,2 million was allocated tothe Community Impact Account. However, im-pacted communities requested more than $11million. Most of the funds have been used forwater and sewer projects in communitieswith critical growth problems.

The State requires that a majority of thefunds given to the Board of Regents for highereducation be spent for research, educational,

11 Utah Code Ann. 1953, §§53-7-l and 2: 65-1-64 and 65; and65-1-1 15( 1979 Supp. ).


and service programs to benefit communities provements. How much of this money ends upeconomically or socially affected by mineral in energy impacted communities is difficult toleasing activities. determine. New Mexico designates virtually

all of its Federal mineral revenues to theOther Western States General Permanent Fund for the public

school textbook fundThe other Western States distribute funds North Dakota similarly

by a variety of formulas. Montana currently in the general fund forprovides 62.5 percent of its Federal royalties schools.for schools and 37.5 percent for highway im-

and other purposes.places all its royaltiesdistribution to public

Federal Programs To AssistEnergy-Impacted Communities

Loans Against FutureLeasing Revenues

Section 317(c) of the Federal Land Policyand Management Act of 197612 authorizes theSecretary of the Interior to make loans toStates against their share of anticipatedmineral leasing receipts for any prospective10-year period. The loans, intended to ad-dress front-end financing problems, are to bemade specifically for relieving the socio-economic impacts associated with Federalmineral development activities. The programhas 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 ofgovernment as compensation for taxes thatthey cannot levy on the tax exempt Federallands within their boundaries. With regard tocoal development, annual payments are madeto local jurisdictions that contain land ad-ministered by the Bureau of Land Manage-ment (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 Programmet with initial objections from the executive branch becauseof the low interest rates provided, In 1978, the act was amend-ed to allow higher rates, thus removing the major objection. Atotal loan level of $212 million was authorized through fiscalyear 1982, although no funds have been appropriated, and $40million of the authorization expired in fiscal year 1979. SeePublic Law 95-352, sec. l(c), 92 Stat. 515, Aug. 20, 1978.

“Public Law 94-565.

PILT funds are allocated under a formulabased on acreage, population, and revenueproducing programs on public lands such astimber, grazing and mineral development.Although not so designated, the funds areoften used for energy impact assistance. ’sTotal (coal and other) payments under PILT in1979 were $105 million and in 1980 amountedto approximately $108 million (table 102).

An important feature of PILT is that thepayments given to local governments are re-duced by the amount of Federal mineral leaserevenues redistributed to these jurisdictionsby the States. That is, any lease revenues thatflow directly to local areas are deducted fromthe per-acre PILT payments. This arrange-ment serves as an incentive for States to usemineral royalties for purposes other thanreturning them directly to impacted jurisdic-tions. But it makes no difference to the local

15 P1LT payments are made almost exclusively to county gov-

ernments, since cities and towns generally do not contain BLMor Forest Service lands.

Table 102.—Payments in Lieu of Taxes by State

State FY1980 payment

Colorado . . . . . . . . . . . . . . . $7,507,361Montana. . . . . . . . . . . . . . . . 8,078,067New Mexico . . . . . . . . . . . . . 9,589,751North Dakota . . . . . . . . . . . . 571,552Utah . . . . . . . . . . . . . . . . . . . 8,146,654Wyoming . . . . . . . . . . . . . . . 6,550,736

SOURCE: Department of the Interior.


governments, since they receive equal sums,either from Federal PILT payments or fromthe State’s share of mineral lease receipts.

Abandoned Mine Reclamation Funds

The Surface Mining Control and Reclama-tion Act of 197716 provides for annual grantsto States to help develop, administer, and en-force statewide reclamation programs. Theprograms are for Federal and non-Federallands disturbed by coal mining. The act alsoestablishes Federal and State abandonedmine reclamation funds, financed primarilyby revenue derived from a reclamation fee of$0.35/ton of surface-mined coal and $0.15/tonof underground-mined coal, or 10 percent ofthe gross value of the coal, whichever is less.

Fifty percent of the reclamation fees col-lected annually in any State must be allo-cated to the State’s abandoned mine reclama-tion fund. This in turn must be used to reclaimany land mined for coal and abandoned (orotherwise left in an inadequate reclamationstatus) prior to 1977. If all such land in aState has been reclaimed, the State may useits 50 percent of the fees for construction ofpublic facilities in communities impacted bycoal development. 17 The State must certify,and the Secretary of the Interior agree, thatthere is a need for such facilities and that themoneys available under the Mineral LeasingAct or the PILT payments are inadequate forsuch construction.

Since the Western States until recentlyhave had little large-scale coal mining, theyhave fewer abandoned, unreclaimed coalmines than the Eastern States. Thereforethey are more likely to qualify to use their 50percent for public facilities in coal impactedcommunities, This could be a major source offunds for Western States with approvedreclamation programs.

16Public Law 95-87, 91 Stat. 445, 30 U.S.C. 1201 et seq. Title4 of the act established the Reclamation Fund.

’730 U.S.C. 1233(g)(1).

"601" Program

A Federal program for energy impactedareas was established by section 601 of thePowerplant and Industrial Fuel Use Act of1978.18 Administered by the Farmer’s HomeAdministration in the Department of Agricul-ture, it provides funds for planning assist-ance and acquisition of land for housing andpublic facilities in communities affected bycoal or uranium development. IndividualStates have not received much assistancefrom section 601 programs because of the rel-atively small appropriation ($20 million in1979 and $50 million in 1980), the statutorylimitations on the use of the money, and thelarge number of States that have applied forassistance.

Other Federal Programs

BLM is supporting a project on the socialeffects of the Federal coal management pro-gram in the West.19 The project will develop aguide for social impact assessment to help fillexisting data gaps and remove some theoreti-cal uncertainties about community disrup-tion. Because it is designed to improve the ge-neric process, the project should, in the longrun, significantly improve the social and eco-nomic mitigation aspects of Federal leasingefforts.

A variety of other programs, not directedat energy or mineral development, is alsoavailable to State and local governments;however, only a few deal with socioeconomicproblems. According to various authors, from30 to 165 programs have been useful to boom-town 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 im-

pacted communities:An Assessment of Oil Shale Technologies (ch. 10), OTA, GPO

stock No. 052-00340759-2 (Washington, D. C.: GovernmentPrinting Office, 1980).

Energy Development in the Western United States—Impacton Rural Areas, Murdock and Leistritz (New York: PraegerPublishing,1979).

Report to the President-Energy Impact Assistance, EnergyImpact Assistance Steering Group (Washington, D. C.:


State Programs

Each State has developed ways of provid-ing technical and financial assistance toenergy impacted areas. In addition to tradi-tional revenue sources such as sales, income,and excise taxes used to support general pro-grams, Western States have relied on threespecific sources for energy impact mitigation.These are Federal mineral royalties, Stateseverance taxes, and bonding authority. Inmost States, severance tax revenues con-tribute the most aid.

Severance Taxes

A severance tax maybe broadly defined asa special levy assessed at flat or graduatedrates on the extraction of natural resources.Severance taxes are distinguished from othertaxes by their imposition on the removal ofthe natural resource rather than on the re-source itself. Legally, severance taxes aregenerally held to be excise rather than prop-erty taxes and, as such, are not subject to theconstitutional requirements placed on prop-erty taxes of uniformity and equality. Therehas been much controversy on the nature,level, and distribution of severance taxes.

Some of the arguments cited in support ofseverance taxes include:

●

●

Natural heritage.— A State’s natural re-sources are an irreplaceable heritage ofthe people of the State. A severance taxis compensation for a portion of the irre-trievable loss of this wealth.Conservation of natural resources.—If atax is high enough, the increased priceof the extracted mineral should slow therate of resource exploitation and stimu-


DOE/IR-0009, 1978).Mitigating Adverse Socioeconomic Impacts of Energy Devel-

opment, 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 Of-fice, 1979).

●

●

●

late the substitution of alternative tech-nologies and/or renewable resources.Internalization of socioeconomic costs,—The significant public costs associatedwith large-sale mineral development canbe internalized by levying a severancetax. If the tax is shifted to consumers, aprice for the resource can be establishedthat reflects a truer cost of production,both public and private.Capture of economic rent.—Accordingto the concept of economic rent, the fi-nite nature of natural resources resultsin a market price that includes a portionrepresenting pure surplus that can betaxed away without affecting consumerprice, production levels, or allocation ofresources. For example, in passing theMontana Coal Severance Tax Act, theMontana Leg i s l a tu re dec la red tha t“coal in Montana, when subbituminousand recoverable by strip mining, is insufficient demand that at least one-thirdof the price it consumes at the mine maygo to the economic rents of royalties andproduction taxes.”S ta tewide sha r ing o f t ax benef i t s .—Since mineral development often - oc-curs in less populated rural areas, morepopulous regions sometimes feel they de-serve a larger share of the benefits fromthis development. In addition, areasaway from the immediate energy-pro-ducing regions can be affected by energydevelopment. For example, between1975 and 1978, approximately 75 per-cent of Colorado’s growth in miningemployment occurred not in the outlyingresource areas but in the Denver metro-politan area. A severance tax can helpspread benefits throughout the State.

State Income From Severance Taxes

Colorado, Montana, New Mexico, NorthDakota, and Wyoming impose severancetaxes. Of the coal-producing States, only Utahdoes not; however, Utah does impose a mining

Ch. 12—Revenues and Socioeconomic Impacts . 357— — - - . - — - - - - —

occuaption tax on various minerals (exclud-ing coal). Figure 53 shows severance tax in-come from all minerals, not just coal, and theportion of total State revenues contributed byseverance taxes. Wyoming ranks highest inpercentage (25 percent) of State revenuederived from severance taxes. New Mexicoreceived the largest amount ($159 million infiscal year 1979), although only 13 percentwas from coal. A common trend is the in-crease over the pastI 5 years in funds avail-able to the States through these taxes.

In general, coal severance taxes are calcu-lated either as a flat rate of production or asa percentage of net or gross value of the coalproduced. Table 103 shows the differentbases currently used for assessing severancetaxes. The 30-percent rate in Montana is thehighest of the Western States and its consti-

Figure 53.— Total Severance Tax Revenues(all minerals)

Thousands of dollars Percent of State revenues

1975 1976 1977 1978 1979

Fiscal years


Table 103.—Coal Severance Taxes

ColoradoCoal—Surface $0.63/ton

Underground $0.315/tonAdjusted by wholesale price index.

MontanaHeatingquality Surface

(Btu/pound) mining

Under 7,000 $0.12 or 20% of value7,000-8,000 $0.22 or 30% of value8,000-9,000 $0.34 or 30% of valueover 9,000 $0.40 or 30% of value

Undergroundmining

$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 productif in excess of $5,000.

New MexicoCoal—Steam coal $0.57/tonAdjusted by consumer price index escalator (in 1981total tax is $0.73 per ton)

North DakotaCoal—Steam coal $0.50/ton

Adjusted quarterly based on wholesale price index.

WyomingCoal 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 StateRevenue Agencies, January 1981

tutionality has been challenged by miningcompanies and coal consumers. On July 2,1981. the U.S. Supreme Court ruled that Mon-tana could impose a severance tax this highwithout violating either the Commerce Clauseor the Supremacy Clause of the United StatesConsitution. 21

Allocation of Severance Taxes Revenues

Table 104 summarizes the distribution ofcoal severance tax revenues. New Mexicodoes not follow a specific allocation formula;instead, all its revenues are placed in theSeverance Tax Bonding Fund. Each year thelegislature authorizes the issuance of bondsfor a variety of projects, including impactassistance. Any portion of the fund that is notpledged to the principal and interest onoutstanding bonds is deposited in the Sever-ance Tax Permanent Fund. The CommunityAssistance Authority makes recommenda-tions for the issuance of bonds for projects inareas affected by mineral and energy develop-

21Commonwealth Edison Co. v. Montana, No. 80-581, July 2,1981 (slip opinion).


Table 104.—Allocation of Coal Severance Tax Revenues

Category Colorado Montana New Mexicoa North Dakota Utah b 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 1 9 . 0 %e

Other . . . . . . . . . . . . . . . . . . . . . . . 22.25% f 20% g 38.1 ‘/Oh

a Reallocated annually by legislature

b Utah has no severance taxC15 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 energyimpact assistant advisory committee.

d The Coal Development Impact Fund is administered by Coal Development Impact Office that makes discretionary grants to impacted communitiese 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 Countyh 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 govern-

ment facilities, school buildings, and community colleges.

ment, and $10 million is allocated annuallyfor the specific purpose of making grants toimpacted communities.

Colorado gives energy developers a creditagainst their severance taxes for certain ap-proved contributions made to local commu-nities to assist with preventive efforts beforea project begins operation.

Colorado, Montana, North Dakota, andWyoming place a percentage of their coalseverance tax revenues in trust funds. Thesefunds are intended to compensate future gen-erations for depletion of nonrenewable re-sources. The purposes of the funds are statedin general terms; the most common areas forinvestment are the reestablishment and di-versification of the economic base in anticipa-tion of the day when the mines are exhausted.The funds also can be used to redress anylong-term environmental consequences ofprolonged coal mining, They are in part a re-sponse to the boom and bust cycles that havehistorically characterized mineral develop-ment in the West.

Four of the seven Western coal-producingStates—Wyoming, Montana, New Mexico,and North Dakota—have passed constitu-tional amendments establishing permanentmineral trust funds. The term “permanent”’means that a three-fourths vote of both

houses of the legislature is necessary beforethe principal can be disbursed for any pur-pose. Such precautions are designed topreserve the integrity of the principal. Col-orado has a permanent trust fund establishedby statute that has no restriction on paymentsfrom its principal; however, the State has notyet spent any of the principal. In most States,the income from investment of the permanenttrust funds is either deposited directly in thegeneral fund or otherwise made available forlegislative appropriation. Thus, these perma-nent trust funds, unlike the remainder of theseverance tax revenues, do not contribute alarge proportion to impact assistance.

Table 104 also shows the percentage ofseverance taxes placed in the State generalfunds. These percentages are relatively low(30 percent in North Dakota is the highest).The allocations to local governments repre-sent direct distributions to communities, anddo not include any remaining percentages in-directly available to these jurisdictions. InMontana, for example, impacted towns aredirectly allocated only 8.75 percent of rev-enues, but they could also receive indirectbenefits from general fund disbursements,such as county planning appropriations, orcultural and historic site moneys.

In addition to mechanisms to dispense reve-nues, Wyoming has created several govern-


mental agencies to help mitigate the socioeco-nomic impacts. In 1974, the legislaturepassed the Joint Powers Act22 to encouragevarious levels of government to cooperate inthe financing of public facilities. Local gov-ernments (e.g., cities, counties, school dis-tricts) can join together to become eligible forJoint Powers Loans.

In 1975 the l eg i s l a tu re c rea ted theWyoming Community Development Authority(WCDA) to help alleviate housing shortages.’{

It is designed to compensate for the lack offunds in the private mortage lending market.WCDA is authorized to issue up to $250 mil-lion in bonds that provide assistance throughprivate lending institutions and through pur-chase of mortgages in areas of capital short-age. The program became fully operational in1979 and more than $200 million in WCDAbonds were committed as of the end of 1979.

Several other programs are valuable tojurisdictions with rapid growth. For instance,if a school district is nearing the limit of itsbonded indebtedness and faces expenses be-yond its financial capacity, it may apply tothe Farm Loan Board for emergency con-struction funds, A $2 million account withinthe Permanent Trust Fund is reserved for thispurpose. In addition, the legislature hasgranted counties the authority to institute anadditional l-percent sales tax.24 This tax mustbe distributed on the basis of population; as aresult, cities and towns with increased pop-ulation get a greater proportion of the reve-nue than counties.

State Energy Facility Siting Programs

While most States analyze the physical en-vironmental effects of siting major energy fa-cilities, only a few have developed programs

to deal directly with the socioeconomic as-pects of this siting. Montana and Wyomingare two that have mechanisms specificallyaddressing such impacts. The primary aim ofthese programs is to ensure that industry par-ticipates in appropriate mitigation efforts.

The Wyoming Industrial Development In-formation and Siting Act was passed in 1975largely in response to the social and econom-ic conditions in boomtowns such as RockSprings and Gillette. ” The act requires that,prior to construction, major energy develop-ers predict likely social and economic im-pacts and commit themselves to a number ofmonitoring and mitigation strategies. An In-dustrial Siting Council has broad latitude todetermine compliance with an elaborate setof criteria. The council must approve all proj-ects with a total cost of over $63 million andcertain other projects with the potential forsubstantial community or environmental im-pact.

The Montana Major Facility Siting Act26)has a checklist of socioeconomic criteria re-quiring an applicant to give consideration toimpacts on the population already in thearea, on the population attracted by con-struction and operation of the facility, and onpublic services and facilities. Coal mines pro-ducing more than 500,000 tons per year, mostelectric generating facilities, and synfuelsplants must obtain a siting certificate.

The Montana Board of Natural Resourcesand Conservation has discretion to place con-ditions on the siting certificate. For instance,in the case of the application for generatingunits 3 and 4 at Colstrip, the Board askedMontana Power to set up a training programfor Northern Cheyenne Indians wishing em-ployment in the construction and operationwork 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


Effects of Expanded Federal Coal Production

Industrial development in sparsely popu-lated rural regions inevitably brings changesin t he e s t ab l i shed soc i a l pa t t e rns . Thesechanges are seen as mixed blessings. On theone hand, a larger tax base, the expansion ofretail services, and an improvement in publicservices are viewed as positive. On the other,housing shortages, crowding of facilities suchas schools, and locally high inflation are seenas negative impacts. Residents respond in avariety of ways. Some welcome the changesas indicat ions of prosperi ty; others lamentthem for the loss they bring to the earl ierways of life.

Whether communities are able to adapt torapid growth depends on a complex set of ele-ments , many of them si te-specif ic . In anycase, the combined efforts of private entities,especially the energy developers, and publicagencies, particularly local and State govern-m e n t s , a r e n e c e s s a r y t o d e a l w i t h t h echanges.

The effects of expanded Federal coal leas-ing will depend on the interaction of manyfactors. These include:

●

●

●

Magnitude of the growth.—The directand indirect population influx from alarge energy project may double o rquadruple the size of a small rural c o m -munity.Pace of the development. — Energy-re-lated growth occurs suddenly and pro-gresses rapidly, frequently with majorimpacts in the first few years of the d e -velopment. Rural communities often areill-prepared for this surge.Fluctuating nature of the growth.—Dur-ing the construction period there may belarge increases and decreases in popula-t i on . The pe rmanen t ope ra t i ng fo r ceoften is s ignif icant ly smaller than theconstruction one. Communities must pre-pare for large temporary populat ions ,especially in the case of powerplant con-struct ion.

●

●

●

●

●

Uncertainty. —The t iming of developm e n t i s o f t e n u n c e r t a i n b e c a u s e o fchanges i n p ro j ec t e conomics and f i -nancing, shifts in State and Federal pol-icy, and the risks associated with largeenergy projects . The unpredictable fu-ture of development makes initial invest-ment in community facilities and serv-ices risky and difficult.Condition of existing municipal servicesand facilities, —Exist ing faci l i t ies havelittle excess capacity or elasticity. In ad-di t ion, they may require extensive up-grading. The condition of many servicesand faci l i t ies is such that replacementmay be required; and an isolated loca-t ion usual ly means higher construct ioncosts.Availability of fiscal and other a id .—Im-provement of public services and facil-ities must occur during the early stagesof industrial expansion; this takes placebefore an enlarged tax base is estab-lished. The front-end financing problemis usually one of timing rather than along-term shortfall, since the increase inpublic revenues may ul t imately exceedthe total cost of municipal expansion.That the problem is one of timing ratherthan net loss in the long term, however,does not make it less severe.jurisdictional problems.—A new energyfaci l i ty and the increased tax base i tgenerates are frequently located in onepoli t ical subdivision while the popula-tion settles in another. For example, en-ergy facilities may be located in the unin-corporated port ions of counties (whichderive revenues from the project), whilethe majority of new workers settle in ad-jacent towns (which legally cannot sharein these revenues).P r iva t e s e c t o r [ c o m m e r c i a l ) i n f r a s t r u c -

tu re .—As in the public sphere, privatesector services often require expansion;small towns general ly have only basicc o m m e r c i a l e s t a b l i s h m e n t s . L a c k o f


capital. absence of experienced entre-preneurs , and competi t ion with energyindustries for labor and supplies can allcontribute to delay in the expansion oflocal businesses.

• Characterstics of the region. —Someareas have experienced past booms andbusts and are accustomed to their dis-ruptive effects; others have not and theresidents may be unprepared for boom-town problems.

● C o n c u r r e n t e x p a n s i o n o f o t h e r i n d u s -tries in the same location.—Many of themost severe problems have been asso-ciated not with coal mining, but with ma-jor powerplant construction. Althoughmajor disruptions in sparsely populatedand homogeneous communities couldoccur from the number of mines and an-cillary activities necessary to supportlarge-scale coal production, the biggestproblems will come from total energy de-velopment. Thus, the greatest potentialfor major socioeconomic dislocations ex-ists where more than one energy-relateddevelopment is expected.

The remainder of this chapter examinesthe potential for adverse social and economicconsequences in the coal development re-gions studied by OTA. The State task force re-ports, from which the following discussionsare drawn, include consideration of how so-cioeconomic conditions could influence Fed-eral coal development. The task forces con-cluded that socioeconomic and communityconditions would not be a significant con-straint on the development of existing leases.This is because industry is concerned withproblems such as labor turnover, and Stateand local governments have experiencedsome adverse consequences of coal-relatedgrowth. As a result, prospective developersand impacted communities will probably takeappropriate steps to deal with any emergingproblems,

Colorado

To handle the negative effects of energy de-velopment, Colorado has adopted an impact

mitigation strategy involving local citizens,regional Councils of Governments, and astatewide office to coordinate efforts. Thestrategy has been successful in developingboth public and private solutions to growthproblems. Nevertheless, some communitieshave already experienced negative conse-quences from coal development, and the po-tential for future difficulties exists. OTA’s es-timates of potential production (see ch. 6) in-dicate that areas already experiencing prob-lems are the most likely to face future diffi-culties.

The northwest and west-central are suchregions (fig. 54 and table 105). For example,all eight of the proposed new lease tracts inColorado are within 25 miles of Craig. Theerection of two new coal-fired units at theCraig station, possible building of a syntheticfuels plant, and construction of major re-gional reservoirs in the next 10 years could

Figure 54.—Counties of the Rocky Mountain StudyArea

I h !, f.\

. “, . . I I 1

. . v > . . . .,.. ,,,. ,.,

., .?’.

. .

I.-.<,/

m .“ ..,. , . “ . ., . . . . (’. .,.4 ,,.

. . . ,.!., . . ,

~. .

“.. ,.

.,, . ,,

I .,.SOURCE: Office of Technology Assessment.


Table 105.—Demographic Characteristics of Selected Counties in Colorado, Utah, and New Mexico

Colorado

Percent Total acreage AverageTotal change Percent of land in Percent

population asize 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

UtahCarbon. . . . . 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 MexicoColfax . . . . . 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 devel-opment.

Craig has been handling growth for sometime (the population of Moffat County hasdoubled since 1970) with the help of State im-pact assistance funds and professional citymanagement. However, the amount of moneythat is returned to Craig from Federal roy-alties and State severance taxes is small com-pared to the revenues generated, and this dis-parity is a sore point with local leaders,

new coal miners and construction workers tosettle there, the town expanded its water-works. But the growth failed to materialize,and now Hayden residents are having troublepaying the debt from this expansion. Similar-ly in Craig, the population dropped from lay-offs a t mines and from completion of unit 2 atthe powerplant, but the voters have had todecide on a referendum for a $7 million bondissue to double the current capacity of thewater system.

Nearby, at Hayden, the problem of fluctu- Meeker illustrates the difficulties of plan-ating 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 from2,200 to 3,600 people per facility; includingfamilies and secondarily induced service per-sonnel, over 10,000 people could conceivablymove to the town. If the oil shale endeavorsproceed according to some plans, the areacould experience a 400- to 600-percent in-crease in population by 1985.27 The uncertain-ties associated with oil shale development,however, make it difficult to prepare for thisgrowth, Concurrent expansion of coal pro-duction would add to these difficulties,

Rangely illustrates the problem of jurisdic-tional mismatches. This town, already thecenter for oil and gas development, is readyto absorb some new residents. Workers willcome from the Federal oil shale tracts in Col-orado once a road is completed. They are alsoapt to come from coal and oil shale develop-ments in Utah, since Rangely is closer to thesesites than Vernal, Utah. In this case, Rangelywill bear the costs of accommodating theworkers without the benefit of tax revenuesfrom the properties.

Rio Blanco County has recently completedan agreement with Western Fuels Associatesfor impact mitigation. The company's pro-posed Deserado mine near Rangely will sup-ply coal for a powerplant at Bonanza, Utah.Under the agreement, support will be pro-vided for expansion of water and sewer facil-ities, schools, highways, and both municipaland county services (planning, medical, fireprotection, recreation, and other services).The arrangements are based on the expectedarrival of 1,500 new residents in the Rangelyarea. About $15 million will go for mitigation;this is 5 percent of the projected $300 millioncost of the development,

In recognition of the fact that unpleasantliving conditions lead to low productivity andhigh worker turnover, many energy devel-opers have taken the initiative to help commu-nities. Industry has contributed to the pro-vision or upgrading of facilities and services,has assisted with housing development forworkers, has prepaid taxes, and has taken

“Meeker’s population was 1,597 in 1970 and 2,356 in 1980.

other s teps such as offer ing t raining pro-grams for local workers. For example, earlyin 1981, Northern Coal Co. announced it hadarranged to bui ld 18 apartments in Meekeras temporary housing for its employees. Ap-proval has been given for a 104-lot develop-ment, sponsored by industry, for permanenthousing. In addition, Northern Coal has pre-paid $318,500 in severance taxes to help fundmunicipal improvements.

Utah

Utah has two major coal regions with Fed-eral leases— the Uinta region including Car-bon, Emery, and Sevier Counties in the cen-tral part; and the Southwestern region en-compassing Garfield and Kane Counties insouthern Utah (fig. 54 and table 105).

The central area has historically been acoal producing region. Mining and relatedconstruction have been, and remain, the ma-jor economic activities, In the past, conditionsin the coal market have had a direct effect onthese counties. From 1950101970, during de-pressed market times, they experienced de-clining populations. Since 1970, with an im-proved market, they have had significantgrowth: for instance, mining employment in-creased over 200 percent in Emery County inthe first half of the 1970’s.

There is disagreement over whether or notincreased coal development will cause socio-economic problems in central Utah. For ex-ample, in preparation of the DOI final envi-ronmental impact statement for coal develop-ment, the most extensive criticisms revolvedaround the social impact analysis.

The disagreements were also reflected inthe OTA task force for Utah that reviewedthe data for this assessment, The task forcegenerally assumed that impacts could bedealt with adequately and community re-quirements would not be a factor discour-aging mine development. However , county

commissioners and other local residents in-terviewed by OTA staff expressed concernabout the capability of the area to absorb andsupport development without major disrup-


tion of existing communities and displace-ment of their ways of life; they cited loss of ir-rigated cropland and higher real estate as-sessments among their concerns.

The State government has adopted a policyto promote dispersed development. The inten-tion is to spread the benefits and impacts ofcoal development more evenly and thus avoidthe adverse consequences of more concen-trated growth.

Development of coal leases in the Alton andKaiparowits coalf ields in southern Utahwould require new or expanded facilities.The area is sparsely populated and rural,without large communities. Agriculture andtourism are the principal industries. A signifi-cant portion of the work force needed to oper-ate coal mines would have to be brought intothe area; new communities would have to beconstructed to provide for the miners, sup-port personnel, and their families.

One of the greatest concerns about coal de-velopment in Utah is the potential for changein the character of the communities. Manybelieve the entry of new residents would alterthe generally homogeneous religious andcultural composition of the present socialfabric. This perception of “outsiders” is arelatively recent development, and may stemin part from the residents’ greater recogni-tion of the magnitude of the development be-ing proposed. The view residents have of ac-tivities elsewhere may also be contributing totheir concern. In southern Utah the impres-sion of the Price area (in the central part ofthe State) is that of a boomtown, similar toRock Springs, Wyo. Many southern Utah resi-dents feel that substantial changes in Price’scharacter have taken place and they wishto avoid similar alterations. The possiblechanges in community composition or way oflife are also a predominant concern behindmuch of the local opposition to the proposedMX missile system.

In sum, the potential for socioeconomicchanges appears high in Utah, assuming thatplanned coal development proceeds. At thesame time, there is widespread disagreement

as to whether these would be undesirablechanges. Central Utah has been an historiccoal mining area; booms and busts are not un-known to these towns. Southern Utah issparsely populated and coal developmentwould require establishing a different socialand economic infrastructure to meet theneeds of a larger and more , diverse pop-ulation.

New Mexico

Like Utah, New Mexico has the potentialfor extensive socioeconomic changes, and theprobability of these changes being negativeappears high. The State recognizes the possi-ble effects of industrial expansion on localgovernment and has funded studies and proj-ects in preparation for energy development.Large-scale expansion of coal mining andconstruction of powerplants or synthetic fuelprojects in the San Juan basin could severelystrain existing social and economic institu-tions. The problems would be particularly se-vere in remote coal regions where there arenow few or no community facilities and serv-ices (table 105; fig. 54),

OTA’s analysis (see ch. 6) indicates coalproduction could double or triple in the StarLake-Bisti region (assuming the completion ofthe railroad). The towns of Cuba, Grants, andMilan would be most affected by the newmines and the construction, operation, andmaintenance of the proposed Star Lake Rail-road. Uranium and oil and gas developmentare also planned, and considerable publicconcern about the impact of uranium miningon the community of Grants has been ex-pressed.

The town of Cuba is located near severalnew Federal coal developments; it is the clos-est community to the proposed La Ventana,Star Lake, and Black Lake mines. Cuba lacksthe capability to provide the services neededto handle the expected growth. For example,water quality in this region is poor and itsavailability for domestic use is limited. Trans-porting water to Cuba from other parts of theState has been under study. The town is cur-


rently burdened with financial obligations, in-cluding $651,000 in outstanding bonds, thatlimit its ability to underwrite new projects.

The Farmington, Bloomfield, and Aztecareas expect a construction boom that is pro-jected to peak in 1985-86. A State Commissionhas established as high priority the repairand construction of new roads from theFarmington area to Cuba needed to handlethe expected increase in coal traffic. In Farm-ington a housing shortage exists and waterfor residential use is not plentiful.

Because of the landownership patterns inNew Mexico, off-reservation Indian landsand communities will be affected by the de-velopment of existing Federal leases. Mitiga-tion efforts will require, in addition to Stategovernment participation, involvement of Tri-bal governments and local Indian pueblocouncils, as well as consultation with DOI’SBureau of Indian Affairs.

Wyoming and Montana

OTA focused on two regions in Wyomingand Montana: the Powder River basin, andsouthern Wyoming. A map of these areas andthe nearby communities is found in figure 55;demographic indices are in table 106.

An early study of the socioeconomic im-pacts of increased coal development in theNorthern Great Plains28 reached the followingconclusions:

●

●

●

Population increases attributable to coaldevelopment will be large, and attendantproblems will be compounded becausesuch increases will be both rapid andunevenly distributed.Most communities in the Northern GreatPlains are not prepared to deal with themagnitude of change attending regionalcoal development.The rapid influx of population will causea proportionally greater increase in de-

28Northern Great Plains Resource Program, 1974. This exten-

sive study covered the five States of Montana, Nebraska, NorthDakota, South Dakota, and Wyoming; it was funded in largepart by the Department of the Interior.

SOURCE” Off Ice of Technology Assessment.

mand for services because newcomersoften have higher expectations for serv-ices than native residents.Public service requirements will in-crease at a much faster rate than rev-enue collection, especially in the earlyyears of development. The service areasof part icular concern are housing,health care, and education.

These expectations were confirmed by sub-sequent experiences in the region. For exam-ple, Rock Springs, located in SweetwaterCounty in southwestern Wyoming, was thesubject of a classic study of boomtown phe-nomena. 29 The population increased from

18,931 to 36,900 from 1970 to 1974. The abili-ty to provide municipal and other local serv-ices declined markedly. The ratio of doctors

4

29 John S. Gilmore, and Mary K. Duff, Boom town Growth Man-agement: A Case Study of Rock Springs—Green River, Wyo.(Boulder, Colo.: Westview Press, 1975).


Table 106.—Demographic Characteristics of Selected Counties in North Dakota, Wyoming, and Montana

North Dakota

Percent Total acreage AverageTotal change Percent of land in Percent size of

population 1970 to Land areab People b 65 years farms b of all land farms b

County 1970 1980 1980a (mi2) per mi2 and 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 944Oliver . . . . . . 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 8,798a

1980 census of population and Housing: Advance Reports, U.S. Bureau of the Census, March 1981 (PCH80-V)b1975 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 to1:3,700 in 1974 (in contrast to an averagestatewide ratio of 1:1,100). In 1974, countyschools were short an estimated 128 school-rooms; approximately 1,397 homesites had nomunicipal services; and 4,599 mobile-homespaces were needed. Caseloads in mental-health clinics increased eightfold. Crimerates increased by 60 percent between 1972and 1973 alone, while police services re-mained relatively constant.

Other towns affected by nearby coal min-ing include Forsyth and Colstrip, Mont.; andSheridan, Gillette, and Douglas, Wyo. Someof them have been better able to handle theimpacts than others; and the mining company

mitigation efforts have been different in eachcommunity.

Colstrip was originally developed by theMontana Power Co., for its workers at theRosebud Mine and the Colstrip Power Plants.Workers at Peabody’s nearby Big Sky Minehad to commute daily from Forsyth, about 40miles away. In the last few years, MontanaPower has begun to transfer ownership of thetown of Colstrip, and Big Sky Mine workersare purchasing houses there.

Sheridan, Wyo., has grown from mining de-velopments around Decker, Mont. Workers atthe East and West Decker and Spring Creekmines live in Sheridan although they work in


Montana. Sheridan has taken this growth instride, although the county has difficulty ob-taining sufficient funds for its general budgetto meet operating expenses.30 Increased hous-ing costs, in large part from energy develop-ment, have created hardships for elderly res-idents on fixed incomes.31

Gillette, too, has had difficulty. During anoil boom in the 1960’s, the adverse psycho-logical effects of rapid growth were so pro-nounced that they came to be known as the“Gillette syndrome.” Now, with coal devel-opment, careful planning appears to be con-trolling some of the problems seen in theearlier period. A new town, built to h o u s eworkers at mines south of Gillette, was ableto accommodate a population of 1,400 within3 years after construction began.32

Douglas, Wyo., which already has experi-enced rapid growth, will have substantial ad-ditional impacts with the development of newprojects, and Rock Springs continues to showboomtown symptoms, Workers for the JimBridger, Black Butte, and Stansbury mineslive there. The Wyoming Industrial SitingCouncil has asked industry to reevaluate theimpacts of the Jim Bridger Mine and PowerPlant on Rock Springs. The community is seenas an undesirable place to live and turnoveris growing at the mines. The development of abetter environment in Rock Springs “is a mat-ter of good business, ” according to industrys o u r c e s .33

In summary, W y o m i n g h a s e x p e r i e n c e dsome of the most extensive social and eco-nomic changes from energy development, Dif-ferent communit ies have responded in dif-ferent ways; some have become boomtowns,others have coped with rapid growth withoutexcessive disruption. The State has devel-oped a wide array of mitigation strategies toassist the affected counties and communities.

30 D. Pernula, “But What Happens When Coal’s in Montanaand Growth’s in Wyoming?" The Western Planner 1(7):9 Sep-tember 1980.

“P. Primack, “Expanding Energy Town Narrows Life forElderly, ” High Country News, 11(19]:1 Oct. 5, 1979.

“R. E, Huff, “Wright’s Success Reflects Commitment and Co-opera tion, ” The Western Planner 1(7):15 (1980).

“Persona] communication from J. Larsen, 1980.

The greatest potential for additional coalproduction from existing leases is in theWyoming portion of the Powder River basin(see ch. 7), Campbell and Converse Counties,therefore, are the most likely to experienceadditional growth, and possible disruptionfrom Federal coal development.

North Dakota

Coal mining on Federal land in NorthDakota occurs in the Fort Union region in thewestern portion of the State. Most of the ma-jor mining operations are located in the fourwest-central counties of McLean, Mercer,Oliver, and Ward (see fig. 55). In recentyears, Federal, State, and local governmentshave been major employers (28 percent of thepopulation in 1975), with agriculture next (25percent), Large farms and ranches, produc-ing wheat and cattle, are characteristic. Thelargest urban area is Bismarck; small townswith stable populations are found throughoutthis part of the State (see table 106).

Rapid growth has already come to thetowns of Beulah and Hazen, Energy devel-opers in the Beulah area have pooled re-sources to provide housing for incomingworkers, and Bismarck and nearby Mandan(within an hour’s drive of the major lignite de-velopments) have absorbed some of the newpopulation,

There generally has been little local op-position to industry expansion in those areaswhere lignite mining and powerplant con-struction have already taken place (e. g.,Oliver and Mercer Counties). This may bebecause much local income comes from thenearby mining operations. Negative publicreaction has been pronounced in Dunn Coun-ty, however. The combination of public op-position to the siting of Natural Gas PipelineCo. ’s (NGPL) planned gasification facility inthe Dunn Center area and the lack of avail-able air quali ty increments at TheodoreRoosevelt Park led to NGPL’s decision toabandon the project. To date, no large coalrelated facilities have been located in the im-mediate vicinity. The opposition of Dunn


County residents is shared by some NativeAmericans on the Fort Berthold Indian Reser-vation directly to the north of NGPL’s pro-posed site.

Almost all of the existing Federal leasesare in already developed areas (Mercer andOliver Counties), Social and economic im-pacts are not likely, therefore, to affect thefurther development of Federal coal re-sources. This situation would change with theleasing of new tracts in previously undevel-oped parts of the State. For example, thewestern edge of the State is an area wheresocial and economic impacts from severalventures could accumulate. Oil and gas ex-plorat ion is taking place here now, andalthough the operations are well removedfrom existing Federal lease areas, the poten-tial exists for future problems.

Oklahoma

Federal coal leases are located in fourcounties in the east-central region of Okla-homa. Economic conditions are poor in thispart of the State. A continuing decline in coalproduction since 1950 combined with afailure of other industries to flourish in thisregion has led to economic stagnation. Mostcivic leaders and many residents would wel-come a rejuvenation of the coal industry .34

However, as discussed in chapter 6, the pros-pects are not encouraging for extensive de-velopment of coal on Federal land in Okla-homa during the 1980’s.

Development of the Federal leases couldrequire underground mining in many in-stances. However, surface mining has dom-inated the Oklahoma industry for the pasttwo decades, and few local miners have hadextensive underground experience. Conse-quently, the initiation of mining by the com-panies holding Federal leases would probablyrequire the recruitment of workers from out-side the State.

Four mines are currently operating onFederal leases, Any increase in populationthat might result if additional Federal leaseswere developed over the next 10 years wouldnot impose an unmanageable burden on com-munity services. The population of manytowns is still smaller than when coal miningwas more extensive. Most elementary andhigh schools could increase their enrollmentswithout building new facilities or hiring newteachers, and health and recreational facil-ities are adequate. However, in several com-munities that have been hard hit by economicrecession, commercial and residential build-ings have deteriorated and would require ex-tens ive repa i r o r r ep lacement . -

34This is documented in BLM’s public participation file andwas supported by individuals in private industry and in Federaland State agencies contacted during OTA's survey of the Okla-homa coal industry.

CHAPTER 13

Patterns and Trends inOwnership of Federal CoalLeases and PRLAs 1950=80

———.—

ContentsPage

ownership by Business Activity Category. .372Electric Utilities . . . . . ● . . . . . . . . . . . . . . . . . . ● 376Energy Companies. . . . . . . . . . . . . . . . . . . . . .377Peabody Coal Co . . . , . . . . . . . . . . . . . . . . . . 3 7 7Steel Companies . . . . . . .. ... ... .. ...377Independent Coal Companies . . . . . . . . .. ....378Oil and Gas Companies (Minor). . ..........378Unincorporated Individuals . . . . . . . ........378Natural Gas Pipeline Companies. . ..........379Nonresource-Related Diversified Companies .379Kemmerer Coal Co.. . . . . . . . . . . . . . . . .. ....379Metals and Mining Companies .. ... ,. ...379Landholding Companies. ...., .., ... ... .. 38O“Other” Lessees . . . . . . . . . .. .. .. ... ... ...38O

Federal Coal Production by BusinessCategory 4******** ● ********* ● ***.**** 380

The Business Organization of Coal Leaseand PRLA Owners. . . . . . . . . . . . . . . . . . . . 381

Unincorporated Individuals . . . . . . .....,...382Independent Corporations. ............,..382Subsidiary Corporations. ,.. . .............382Multicorporate Entities . . . . . . . . . .~..... 383

Implications of Lease and PRLA‘ Ownership Patterns and Trends. ... .....384C o n c e n t r a t i o n . . . . . . . . . . . . . . . . . . , . . . . . . . . 3 8 4Diversif ication. . . . . . . . . . . . . . . . . 0 . 0 03 $ 4Leasing Policies . . . . . . . . . ........... 386

List of Tables

Table No. Page107. Number of Acres and Percent of Total

Leased Land Held by BusinessActivity Category . . . . . . . . . . ..........373

Table No. Page108. Changes in Federal Coal Lease

Own&shin Because of Recent Major

109.

110.

111.

112.

Corporate-Ownership Changes. .. .....373Number of Acres and Percent of LandUnder PRLAs Held by BusinessActivity Category . . . . . . . . . ...........375Federal Leaseholdings and Productionby Business Category. . ...............376Number of Acres Under Lease by Typeof Business Organization 1950-1980 andPercent of Total Leased Land by Typeof Business Organization. . ............381Acres and Percent of Total Acres UnderPRLAs Held by Business OrganizationCategory . . . . . . . . ..........9..-......382

of FiguresList

Figure No. Page56.

57 0

58.

59.

60.

Total Acres of Federal Coal Under -

Lease 1950-80 . . . . . . . . . . . . . . . . . . . . . . . .371Number of Federal Coal Acres UnderLease by Business Activity Category,1950-80. . . . . . . . . . . . . . . . . . . . . . . . . .. ...3741980 Coal Leaseholdings by BusinessActivity Category . . . . . . . . . ............3751980 PRLA Holdings by BusinessActivity Category . . . . . . . . . . ...........376Number of Federal Coal Acres UnderLease by Type of Business Organization,1950-80 ...,..* . . . . . . . . ● . * * . . * * .. ... 382

CHAPTER 13

Patterns and Trends in Ownership ofFederal Coal Leases and PRLAs 1950-801

The Federal coal leasing program makesFederal coal land available for mining by theprivate sector. Hence, the amount and loca-tion of leased land helps define the extent ofthe coal reserve base of the industry. Figure56 shows the total number of acres underFederal coal lease from 1950 to 1980, Theregions with leased coal lands in the West areshown in figure 17 and discussed in chapter4.

This chapter summarizes the results of astudy of the ownership histories of each ofthe 538 Federal coal leases and 176 pref-erence right lease applications (PRLAs) in ex-istence as of September 30, 1979. * Thechapter identifies the participants in the coalleasing program between 1950 and 1980 andexamines the changing ownership patterns ofFederal coal leased to the private sector. Theownership histories of companies, groupedaccording to similar business activities orbusiness organizational structures, are con-sidered separately.

The principal data used for this chapterwere case histories of the legal ownership ofthe titles to each Federal lease and PRLA. **

1For further information on this subject, see the OTA ‘I’erh-nical hlcm(jrandum, P(I t ferns und Trends in Fwicrd Coal Lewsrou’ncrshi~) 1950-80, () I’A-’I’hf-hl-7. klarrh 1981. The TerhnicalNlemorandurn i s a v a i l a b l e f r o m the Superintendent ofDocuments, [J. S. Government Printing office, Washington, D.C.20052, at $4.00 per copy. I ts GPO stock number is052-003-00799-1.

*In its ownership work, 0’I’A did not analyze leases orPRLAs that were relinquished prior to Sept. 30.1979 or the fem.leases issued in Iatr 1979 or in 1980. Thus, the coal leaseacreage tf)ta 1s in this chapter and I he tota 1 number of leasesconsidered in this chaJjtf!r differ slightly from the totals in therest of the report, whirh include a 11 lmises in existence (m Sept.30, 1980. A (I(]mplete prf?scntation of the methodology and find-ings of the ownership study is contained in the OTA ‘1’e(:hni{{ilhlemorandurn referenced above.

**(ITA examined the (~wners of record of leases and PRLAs.It did not stud}’ companies participating in the le:ising programin other c:]parit ies such as “’rtcsi~nated operators’” of mineswork 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

6 0 0 , 0 0 0

500,000

400,000

300,000

200,000

100,000

1950-80

I I I I I I1950 1955 1960 1965 1970 1 9 7 5 1 9 8 0

Year


This information was collected from primarysources, principally serial books and casefi les maintained by State off ices of theBureau of Land Management. From this data,lists of all owners of leases and PRLAs ateach of seven analysis dates were developedand the holdings of each owner tabulated.The analysis dates were January 2 of theyears 1950, 1955, 1960, 1965, 1970, 1975,and 1980. Next, each present and past owner

371


of Federal coal during this period was clas-sif ied according to i ts pr incipal l ine ofbusiness activity (if an individual or an inde-pendent corporation] or by the business ac-tivity of its controlling interest or interests (ifa wholly owned subsidiary or a joint venture).In addition, all present and past owners werecategorized according to their type of busi-ness organization structures. Detailed andseparate analyses were then done for anybusiness act ivi ty category and businessorganization structure that controlled at least5 percent of all land under lease or PRLA atone of the dates listed above. Individualanalyses were also done for any companythat did not clearly fall into an identifiablebusiness category but nonetheless controlled5 percent of leased land or land under PRLAat one of the dates selected for analysis. Re-maining owners were grouped in an othercategory.

Thirteen categories of business activitygroups holding leases and 10 categories ofPRLA owners were identified and studied.Also, four types of business organizationcategories were identified for both lease andPRLA owners. The business activity cat-

egories for leaseowners and PRLA holdersare as follows:

Business Activity Categories Defined by OTALeaseholders*Electric utilitiesEnergy companiesPeabody Coal Co.Steel companiesIndependent coal companiesOil and gas (minor)

companiesUnincorporated individualsNatural gas pipelinecompanies

Nonresource-relateddiversified companies

Kemmerer Coal Co.**Metals and miningcompanies

Landholding companies“Other” lessees

PRLA holdersUnincorporatedindividuals

Energy companiesNatural gas pipelinecompanies

Kemmerer Coal Co.**Metals and miningcompanies

Electric utilitiesOil and gas (minor)

companiesLandholding companiesInternationalGeomarine and CoalConversion Co,

“Other” lessees

*The categories include 10 industries, two individual com-panies that were classified as distinct business categories forvarious reasons and an other category for the remaininglessees, Each of the 13 business categories controlled or con-trols at least 5 percent of all land under lease al some time be-tween 1950 and 1980.

**In March, 1981 Kemmerer Coal Co. was purchased byGulf Oil Corp.

Ownership by Business Activity Category

Tables 107 and 108 and figure 57 sum-marize data on the relative and absolutegrowth and decline in leaseholdings by the 13business activities defined and studied byOTA. Table 109 provides similar informationfor the 10 categories of PRLA owners. These •tables and the figure show that:

●

●

The electric utilities, major energy com-panies, oil and gas (minor) companies,natural gas pipeline companies, and ●

nonresource-related diversified com-panies have all increased their Federalcoal landholdings significantly since1965 both in absolute and relative terms.Independent coal companies and unin-corporated individuals dominated coalleasing in the 1950’s and the first half of

the 1960’s but their leaseholdings, ex-pressed as a fraction of the total landunder lease, have steadily declined since1950. Individuals are still the dominantclass of PRLA holder.Peabody Coal Co. and Kemmerer CoalCo. have played important and longstanding roles as large individual leasingparties.Steel and metals and mining companieswere early leasing part icipants, butsteel industry influence has declinedsteadily in relative terms since 1955,although the acreage held by the steel in-dustry has s teadily increased since1950. Metals and mining company lease-holdings 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 Landheld leased held leased held leased held leased held leased held leased held leased(#) (%) (#) (%) (#) (%) (#) (%) (#) (%) ( % )(#) (#) (%)

Electric utilities. . . . . . . . . 0 0 2,000 3% 8 , 2 6 3 6% 45,363 15% 132,038 18% 142,077 19% 163,259 21%Energy companies . . . . . . 0Peabody Coal Co. . . . . . . . 0Steel companies . . . . 4,993Independent coal

companies . . . . . . . . . . 14,584Oil and gas (minor)

companies . . . 0Unincorporated

individuals . . . . . . . . . . . 11,129Natural gas pipeline

companies . , . . . 0Nonresource-related

diversified companies 0Kemmerer Coal Co. a. . . . . 475Metals and mining

companies . . . . . . . . . . 5,009Landholding companies. 1,360“Other” lessees. . . . . . . 2,907

00

12

00

14,817

00

19

00

19,888

00

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

155,024 206 2 , 0 0 9 86 0 , 0 1 5 8

5 5 , 4 1 0 7

4 5 , 9 2 6 6

4 3 , 2 1 5 5

3 6 , 3 1 7 5

3 5 , 6 7 5 532,191 4

1 7 , 6 2 0 24,661 ‹1

77,861 10

58.83735 25,022 33 41,557 29 77,273 25 78.297 11 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 32,5220 0 0 0 0 0 4

01

01,752

02

06,849

05

4,61018,504

16

10,01533,793

15

12,58033,988

24

1237

5,0094,5763,240

764

9,26611,50418,288

68

13

17,70813,41139,134

64

13

107,50443,581

41,153

1566

118,30026,22537,051

1535

NOTE Uncategorized lessees hold less than 2 percent of land under lease at any analysis dateNumbers might not add to 100 percent because of the holdings of uncategorized lesseesNumbers 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 2643Lessees 2% 3 % 2 % 2 % < 1 %

6,8481%

1 8 4 5< 1 %

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


Table 108.—Changes in Federal Coal Lease Ownership Because of RecentMajor Corporate Ownership Changes

Corporate—

Number of.

Number of Change in Change inownership of leases of acres business activity business organ-

c h a n g ea involved involved category izatlon category—

Kemmerer Coal Co. 26 37,191 From Kemmerer Coal No changepurchased by Gulf Oil Corp. Co. to energy

companies

St. Joe Minerals Corp. 1 280 From metals and No changepurchased by Fluor Corp.b mining companies to

nonresource-relateddiversified companies

Energy Fuels Corp. 5 4,521 From independent coal From independentpurchased by Getty Oil companies to energy corporations toCorp. c

companies subsidiariesBelden Enterprises 1 42 From independent coal From independentpurchased first by Grand companies to “other” corporations toMesa Coal Co., which was and natural gas pipe- multicorporatebought by Eastern Gas and Iine companies entitlesFuel Associates jointly withNicor, Inc.CONOCO, Inc. purchased 31 43,442 From energy No changeby E I du Pent de Nemours companies to non-& co resource-related diver-

Sum: (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 COc Getty now holds the leases by a subsidiary, Getty Mining Co.d The leases involved are held by Consolitdation Coal CO



Acres

800,000

700,000

600,000

500,000

400,000

200,000

100,000

Figure 57.— Number of Federal Coal Acres Under Lease byBusiness Activity Category, 1950-80

Other lessees

oYear

sOURCE: Off Ice of Technology Assessment


Table 109.—Number of Acres and Percent of LandUnder PRLAs Held by Business Activity Category

1955-65 1970 1975 1980

Unincorporated UP to 5,890 147,022 115,317 80,559individuals ( loo%) (46%) (28%) (20%)

Energy 22,008 30,738 65,784companies — (7%) (7%) (16%)

Kemmerer Coal 33,190 39,160 39,160Co. a . (10%) (9%) (10%)

Metals and mining 17,278 39,461 36,514companies . (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.


to the 1977 sale of Peabody Coal Co. byKennecott Copper Corp.

● Independent land companies played asignificant role in leasing in the 1950’sand 1960’s, but they have largely liq-uidated their holdings over the pastdecade.

Table 107 and figure 57 also summarizethe absolute changes in leaseholdings thathave occurred over the past 30 years. Theyshow the steady increase in acreage held bythe steel companies, independent coal compa-nies, and unincorporated individuals through1970, followed by the slow decline in theholdings of the latter two groups since then.Table 107 and figure 57 also illustrate howthe significant but relatively modest in-creases in the holdings of these three groupsduring the 1960’s compare to the more sub-stantial acquisitions of some new entrants toleasing in that period, (Table 108 summarizesthe major changes in corporate ownershipthat have occurred since early 1980 that af-

fect the acreages held by the major coalleaseholding categories shown in table 107.)

Figure 58 shows that the leaseholdings ofthe 13 major business activities ranged, in1980, from 21 percent of all land under heldby the electric utilities, to less than 1 percent,held by independent land companies. Themajor energy companies hold 20 percent ofleased acreage. With the exception of theutilities and the major energy companies, allthe categories hold less than 10 percent ofleased coal acreage.

Eight business activity groups currentlyhold at least 5 percent of all land included inPRLAs. A ninth holds over 1 percent (see fig.59). Each group also appears on the list ofmajor leaseholding categories, although thereare differences in the rank ordering of thegroups in the two cases. Individuals hold alarger share of land under PRLAs (20 per-cent) than any other category. Individuals arefollowed by major energy companies andnatural gas companies and then by four in-dustries each of which holds between 8 and10 percent of land under PRLAs.

Two companies, International GeomarineCorp. and Coal Conversion Corp. held, at dif-ferent times, PRLAs covering more than 10percent of all land under permit. (See table

Figure 58.— 1980 Coal Leaseholdings by BusinessActivity Category (percent of total leased acreage)

SOURCE: Off Ice of Technology Assessment,

—


Figure 59.— 1980 PRLA Holdings by BusinessActivity Category (percent of total acres under permit)

from leased land in fiscal year 1979, moreFederal coal than mined by any other busi-ness activity category (see table 110). (Nation-wide, all utility coal production accounted for11 percent of the coal industry’s total produc-tion in 1979).

More than any other industry group ex-amined in this survey, utilities have under-gone complicated internal restructuring re-lated to coal lease management. Several utili-ties now hold leases or PRLAs in the name ofone or more subsidiaries, e.g., coal miningsubsidiary, resource development subsidiary,landholding subsidiary, or legal entity with-out employees or business activities. Also,


109.) They do not appear on the list of currentPRLA holding groups because they have as-signed all of their PRLAs to other parties.

The future disposition of PRLAs has sev-eral uncertainties. * The current Departmentof the Interior leasing policy calls for theprocessing of PRLAs in sequence between1981 and 1984, but it is unclear how manywill be converted to leases or what restric-tions on development will be included amongthe terms of leases that are granted. It wouldthus be speculative to add lease and PRLAholdings into grand totals, and OTA has notdone so. The following pages discuss brieflyboth types of holdings by each business activ-ity category in order of decreasing size ofholdings.**

Electric Utilities

Electric utilities currently hold more Feder-al coal land under lease than any other busi-ness category identified by OTA; they ranksixth in PRLA holdings. Seventeen utilitiesand one utility fuel acquisition associationnow control 21 percent of leased acreage and9 percent of land under PRLAs. These compa-nies mined 30 percent of all coal produced

* see chs. 3, 6, 7, and 9 for more information about the statusof PRLAs.

* *The only exception is the other category that is discussedat the end.

Table 110.—Federal Leaseholdings and Productionby Business Category

Fiscal year1972 1979coal coal

production production1970 from 1980 from

Business activity leased Federal leased Federalcategory 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 landholdings listed as acres. All production listed in million tons of coal.

a Peabody 1970 land holdings and 1972 productions totaled In metals and min-ing category.

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


Ch. 13—Patterns and Trends in Ownership of Federal Coal Leases and PRLAs 1950-80 . 377

utilities have been active in several joint ven-ture leasing and multicorporate developmentprojects, One utility currently holds differentleases in the name of five subsidiaries and isinvolved in three multicorporate lease devel-opment projects. The internal restructuringof utilities and their involvement in multicor-porate leasing ventures appears to indicate apolicy decision by some utility managementsthat coal leasing and mining activities shouldbe separate from electrical generation activ-ities because of the different managementskills that these activities require. Further-more, this division enables utilities, as a regu-lated industry, to clearly distinguish amongtotally regulated, partially regulated, and un-regulated business activities.

Utilities made their most significant leaseacquisition gains in the mid to late 1960’s atthe same time as the energy companies andthe smaller oil and gas companies, but beforethe entry of the natural gas pipeline compa-nies. Most utility-mined coal is used inpowerplants owned by the leaseholding com-pany (captive production), although increas-ing amounts of utility-mined coal are beingsold on the open market. Utilities play aunique role in the coal industry as both an im-portant producer of coal and the major con-sumer of coal. Utilities burned 77 percent ofall domestically used coal in 1979.

Energy Companies

Energy companies in this survey includethe 18 largest privately owned oil companiesbased on worldwide petroleum production.Eleven of these companies now own leases orPRLAs. They rank second in both categories,holding 20 percent of leased land and 16 per-cent of land under PRLAs. Energy companiesproduced 16 percent of the coal mined fromleased land in fiscal year 1979.

The late 1960's marked the period ofgreatest growth in Federal coal landholdingsby energy companies, well before the Arab oilembargo and the energy shortage conscious1970’s. Most of the leases obtained by thesecompanies were acquired through lease as-

signments or by the purchase of a companythat held leases among its assets. * Only 16 of110 leases acquired by energy majors wereobtained by de novo leasing directly from theFederal Government. Similarly, only 7 of 27PRLAs now owned by energy majors were ob-tained de novo. Energy companies appear tobe continuing to acquire land through assign-ment and corporate mergers. In 1980, threeleaseholding companies were purchased byenergy companies and several lease assign-ments to energy companies were made. (Seealso table 108. )

Peabody Coal Co.

Peabody Coal Co. owns leases coveringmore Federal coal land than any other com-pany or individual. Its leases cover 8 percentof all land under lease. In addition, Peabodycontrols 17 PRLAs, all located in Wyoming.Peabody accounted for 4 percent of Federalcoal production in fiscal year 1979.

Peabody operated as an independent coalcompany from its founding until 1968 when itwas purchased by Kennecott Copper Corp.The acquisition was challenged by the Fed-eral Trade Commission on anticompetitiongrounds and a divestiture order was issued in1973. In 1977, Kennecott sold the company tothe Peabody Holding Co., the ownership ofwhich is shared by six companies with busi-ness interests as diverse as aerospace,mineral extraction, and life insurance. Be-cause of its unique ownership structure andbecause of its large holdings, Peabody wastreated in the OTA survey as a separate busi-ness activity after 1977.

Steel Companies

Steel companies were among the earliestparticipants in Federal coal leasing, owning12 percent of all land under lease in 1950.The industry is still well represented (fivecompanies control 8 percent of leased land)but its importance in Federal coal lease-holding has declined because of the entry of

*See chapter 3 for a discussion of methods used to acquirecoal leases,


many companies from other industries. Steelcompanies currently do not own any PRLAs.

Steel companies produced 2 percent of allFederal coal mined in fiscal year 1979. Mostof this production was for captive use as araw material for coke ovens at steel mills.Hence, the industry has focused its attentionon leasing in the coal fields of Oklahoma, Col-orado, and Utah that contain metallurgicalgrade coal.

Independent Coal Companies

In 1950, 18 independents constituted thelargest leaseholding business group, control-ling 35 percent of all land under lease. Todaythey control just 7 percent. Only one PRLA isheld by an independent coal company. His-torically, changes in ownership patterns byindependents have occurred at a rapid pace.Over 60 independents have held leases, butnone of the current 21 independent lesseeswas among the original 18 in 1950. Risingmining costs, the preference of utilities forlarge supply contracts from single producers,and a slow growth in local domestic or in-dustrial coal use restrict the business op-portunities of independent coal companies.As a result, many leaseholding independentshave assigned their leases to principally non-coal companies or have been acquired as sub-sidiaries. At least 10 leaseholding companiesthat are now wholly owned coal mining sub-sidiaries once operated as independent coalproducers.

In spite of these trends, independents re-main the fifth largest leaseholding businesscategory. Furthermore, several present les-sees, notably Garland Coal and Mining Co.and North American Coal Corp., have builtsubstantial coal reserve bases through theleasing program. Also, several other in-dependents have entered the Western coalfields for the first time in the last decade. In-dependent coal companies accounted for 7percent of Federal coal production in fiscalyear 1979.

Oil and Gas Companies (Minor)

Eight oil and gas companies (those com-panies not large enough to appear among theenergy majors and which do not operate largenatural gas pipelines) now control about 6percent of all land under lease and 8 percentof land under PRLAs. They rank sixth andseventh in total holdings respectively. Oil andgas companies entered coal leasing in themid-1960’s and their holdings have grownslowly but steadily ever since.

Lessees and PRLA owners in this categoryrange from small oil wildcatters to large com-panies such as Kerr-McGee Corp. and QuakerState Oil Refining Corp. These companies ac-counted for about 9 percent of the total pro-duction of Federal coal in fiscal year 1979.

Unincorporated Individuals

The role of unincorporated individuals inthe leasing program, at one time second onlyto the independent coal companies, has great-ly declined in relative importance. On theother hand, although their holdings of PRLAshave also declined, individuals still have thelargest share of land under PRLAs of anybusiness category.

In 1950, unincorporated individuals consti-tuted the second largest leaseholding groupand held 27 percent of all acreage underlease. Their share of leased acreage hasdeclined to 5 percent today. Many leases heldby individuals include mines that have beenclosed for years and exhibit little potentialfor reopening. One percent of fiscal year1979 Federal coal production occurred onleased land held by individuals.

In 1970, unincorporated individuals held46 percent of all land included in PRLAs.Over the past decade, many of these PRLAshave been assigned to corporations and theshare held by individuals has dropped to 20percent. Although unincorporated individ-uals are still the major PRLA owners, thedecline in the number of PRLAs held by indi-viduals 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 byindividuals reflects a decreasing use of the“sole proprietorship” business organizationby small mining firms in favor of some form ofincorporated business s tructure. Anotherreason for this decline is the abolition of thepreference right leasing program, a popularand low cost lease acquisition route for indi-viduals, including land agents operatingunder contract to corporations and individu-al land speculators. Finally, the leasing mora-torium of the 1970’s, which increased theassignment value of exist ing leases andPRLAs, and the diligent development require-ments defined in the 1976 coal leasing regula-tions may have been incentives for individ-uals to sell leases that they could not mine.

Natural Gas Pipeline Companies

Natural gas pipeline companies are theeighth largest leaseholding business groupand the third largest group holding PRLAs.Six of these companies hold 5 percent ofleased land and 12 percent of land underPRLAs. They mined 4 percent of all Federalcoal produced in fiscal year 1979.

All leases and PRLAs now owned bynatural gas pipeline companies have been ac-quired since 1971 during a period when op-portunities to acquire leases de novo werelimited. Twenty-five of 27 leases and 27 of 29PRLAs were obtained by assignment or segre-gation from existing leases or PRLAs ratherthan directly from the Government,

Nonresource-Related DiversifiedCompanies

The nonresource-related diversified busi-ness category includes companies with prin-cipal lines of business activity that are notenergy or mineral related, but which comple-ment or could be integrated with resourcedevelopment. It includes, for example, sev-eral chemical companies, which might usecoal as a chemical feedstock or might developsynfuel technologies, and companies such as

General Electric and General Dynamics thatsell electrical generation equipment.

The companies in this category are late-comers to Western leasing, Their leasehold-ings have increased from 1 percent in 1965 to5 percent in 1980. They form the ninth largestleaseholding category, In addition, such com-panies hold three PRLAs. They produced 2percent of all Federal coal mined in fiscalyear 1979, The most significant increase inholdings by companies in this category oc-curred in 1976 when General Electric pur-chased Utah International, which controllednearly 25,000 acres of leased land. Utah Inter-national was an independent metals and min-ing company prior to its acquisition by Gener-al Electric.

Kemmerer Coal Co.

Kemmerer Coal Co, is one of the oldestWestern coal producers, dating back to thelate 19th century. Since 1926 Kemmerer hasbeen owned by the Lincoln Corp., a holdingcompany of Kemmerer family interests. * InSeptember 1980, the family announced its in-tention to sell Kemmerer Coal. Its recent saleto Gulf Oil Corp. marks a major shift in leaseand PRLA ownership.

Kemmerer now owns 4 percent of all landunder lease and 10 percent of all land underPRLAs. Kemmerer produced less than 1 per-cent of Federal coal mined in fiscal year1979. The company ranks as the 10th largestleaseholding category and the fourth largestholder of PRLAs,

Metals and Mining Companies

Metals and mining companies enteredWestern coal leasing early, Although recentcorporate acquisitions have sharply reducedtheir leaseholdings, these companies con-tinue to account for significant Federal coalproduction.

* Kemmerer was studied separately by OTA rather than asan indepenedent coal company because of its ownership byLincoln Corp., which includes noncoal business among itsi n t e r e s t s .


Metals and mining companies held 12 per-cent of all land under lease in 1950 and 15percent in 1975. This total has dropped to 2percent over the past 5 years, principallybecause of the divestiture of Peabody Coal byKennecott Copper Corp. and the purchase ofUtah International by General Electric. Bothactions resulted in the removal of largeacreages from the totals of the metals andmining category. In spite of these devel-opments, metals and mining companies pro-duced about 16 percent of all coal mined fromFederal land in fiscal year 1979.

Amax, Inc., a company grouped in themetals and mining category, currently holds 9percent of the land under PRLAs. These hold-ings alone rank fifth among the business cate-gories studied by OTA. *

Landholding Companies

Independent land companies, like indi-vidual land agents, featured prominently inthe early history of the leasing program. Theyacquired large blocks of coal bearing land foreventual resale to coal developers or other in-vestors. Their role peaked in 1960 when they

*Amax has been placed in the metals and mining categoryinstead of being listed separately because of its identifiablebusiness activity and because prior to 1980 other companies inthis category held PRLAs.

held 8 percent of all land under lease. In1980, seven landholding companies ownedleases covering less than 1 percent of theacreage under lease and PRLAs covering 1percent of the land under PRLAs. They ac-count for no Federal coal production.

The reasons for the liquidation of theholdings of most independent land companiesare s imilar to those for individual landagents: the abolition of preference right leas-ing, the diligent production requirements,and the impact of the moratorium on the re-sale value of leases and PRLAs.

“Other” Lessees

This last category includes lessees that donot fit into one of the business categoriesestablished during the survey and which, ontheir own, do not control more than 5 percentof the land under lease or permit. Such com-panies presently hold about 10 percent of allleased land and about 15 percent of all landunder PRLAs. This other category includeslessees with an amazing diversity of in-terests. For example, it includes a railroadholding company, a heavy construction com-pany, a cement company, two banks, threeconglomerates, and a religious institution.About 9 percent of all coal produced onFederal land comes from leases held bylessees in the other category.

Federal Coal Production by Business Category

Ownership of leases covering Federal landis only one measure of involvement of com-panies and individuals in the leasing pro-gram. The amount of coal production fromleased land is another measure. Based onlimited information available for past Federalcoal production on a lease-by-lease basis,OTA has compared acreage holdings of busi-ness activity categories in 1970 and 1980with Federal coal production by these cat-

During the 1970’s the total number of acresleased by the 12 business categories* thatnow mine coal increased 14 percent from687,094 acres to 784,522 acres. Between1972 and 1979, on the other hand, total coalproduction summed over all these categoriesjumped nearly sixfold, from 10.3 million tonsto 59.5 million tons. In terms of percentage oftotal production, the share of production con-

egories in 1972 and fiscal year - 1979. (See *In fiscal year 1979 no production was contributed by inde-table 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 30percent and the share of independent coalcompanies dropped from 20 to 7 percent. Inboth cases, absolute production increasedsubstantially, by nearly a factor of four forthe utilities and by over a factor of two for theindependent coal companies. During thesame period, the shares of production of theenergy companies increased from 5 to 16 per-cent. Production by natural gas companies,metals and mining companies, and oil and gascompanies also increased sharply, Produc-tion by unincorporated individuals also rosenearly threefold, although declining from 3 to1 percent of total Federal coal production.

Electric utilities, metals and mining com-panies, and oil and gas companies are all pro-ducing Federal coal at levels greater thantheir share of leased acres would suggest.The level of production of the metals and min-ing companies is particularly high relative totheir share of leased acres. Present produc-tion by energy companies, Peabody and Kem-merer Coal, steel companies, nonresource-related diversified companies, and individ-uals is below the share suggested by theircurrent acreage holdings. *

*Many currently nonproducing leases arc being activelv de-veloped. See ch. 6.

The Business Organization of Coal Leaseand PRLA Owners

OTA also examined the changes in theorganizational structures of coal lease andPRLA owners, Four types of business organi-zation structures were defined and analyzed.They are:

●

●

●

●

Unincorporated individuals — persons,including sole proprietorships, partner-ships, and estates.Independent corporations — companiesnot wholly owned by one or more othercompanies.Subsidiary corporations — companieswholly owned by a single other company.Multicorporate entities — companieswholly owned by two or more companies(such as joint ventures) or two or morecompanies holding shares in leases orPRLAs.

Table 111 and figure 60 trace the history oflease ownership by the four organizationcategories. They show that the relative im-portance of unincorporated individuals inleasing has been sharply reduced since the1950’s. They reveal the dominant role of in-dependent corporations in the 1950’s and1960’s and their recent decline in relative im-portance. They show that the subsidiaries

category has grown in importance over theyears. Finally, they show that muIticorporateentities are the newest type of businessorganization to attain significance in West-ern leasing,

The role of the four business organizationsas owners of PRLAs between 1970 and 1980

Table 111 .—Number of Acres Under Lease by Typeof Business Organization 1950-1980

and Percent of Total Leased Land by Type ofBusiness Organizat ion

Unincorpo-rated Independent Subsidiary

indivduals corporations corporations

11,129 18,504 10,8241950. , 2 7 % 4 5 % 2 6 %

17,618 40,495 15,9211955. . 2 3 % 5 3 % 2 1 %

Multi- Uncategor.corporate izedentities companies

1,0350 % 2 %

1,9150 % 3 %

25,678 79,717 36,058 2,4531960. . 18% 55% 25% 0% 2%

41,475 169,402 91,690 640 5,1471965. . 13% 55% 30% <1 % 2 %

78,995 319,847 271,329 60,504 2,6431970. . 1 1 % 4 4 % 3 7 % 8 % < 1 %

66,515 257,637 321,576 112,418 6,8481975. . 9 % 3 4 % 4 2 % 1 5 % 1 %

43,215 204,612 343,865 197,491 1,8451980. . 5 % 26% 43% 25% <1 %`

SOURCE. Off Ice of Technology Assessment


Figure 60.— Number of Federal Coal Acres UnderLease 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 UnderPRLAs Held by Business Organization Category

19551960 &1965 1970 1975 1980

Unincorporated 160-5,890 147,022 115,317 80,559individuals 100% 46% 28% 20%

1950 1955 1960 1965 1970 1975 1980

Year


is summarized in table 112. The patterns andtrends are very similar to those observed forleaseholders with exceptions that unincor-porated individuals play a larger role amongholders of PRLAs and independent corpora-tions have a smaller share of PRLA land thanleased land.

Unincorporated Individuals

The relative importance of individuals inthe leasing program has declined significant-ly both in terms of leases and PRLAs. Unin-corporated individuals control just 5 percentof all land under lease, down from 27 percentin 1950; they hold 20 percent of all land under

I ndependen t co rpo ra - — 107,558 89,345 47,480tions — 33 % 22% 12%

S u b s i d i a r i e s – — 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 160-5,890 322,725 415,619 403,8001 00% 100% 100% 100%. . —

PRLAs, down from 46 percent in 1970. In-dividuals today hold fewer leased acres thanany of the four business organizations ex-amined and rank third in PRLA holdings. In-corporation provides increased legal andfinancial protection over the sole proprietor-ship form of business. This advantage pro-vides one of many reasons for the decliningrole of individuals . Other reasons werepresented in the individuals “business activi-ty category” earlier in this chapter.

Independent Corporations

From 1950 to 1970, independent corpora-tions held the largest share of leased land ofthe four organizational categories. Since1970, their role has declined and they nowhold 26 percent of leased land and 12 percentof land under PRLAs. Independent corpora-tions are the second largest leaseholdinggroup and the smallest PRLA holding groupamong the four organizational categories.

Subsidiary Corporations

OTA has defined a subsidiary corporationas a company wholly owned by one othercompany. Subsidiary companies currentlyown more leases and PRLAs than the otherthree organizational groups. The leasehold-ings of subsidiaries have grown steadily from21 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 in-creased from 21 percent in 1970 to 44 per-cent in 1980.

Subsidiaries have used four differentmethods to increase their lease and PRLAholdings, First, subsidiaries have acquired anincreasing share of leases and permits issuedde novo by the Government. Secondly, manyleases and permits held by individuals or in-dependent corporations have been obtainedby subsidiary companies through assignment.Thirdly, some independent companies haveundergone internal reorganization or formednew subsidiaries, resulting in the transfers oftitle to leases or PRLAs to a subsidiary withinthe corporation. Finally, dozens of independ-ent corporations have been purchased byother companies thereby changing theirstatus from independent to subsidiary com-panies. Title to leaseholdings was frequentlyretained by the formerly independent com-pany rather being transferred to the purchas-ing company,

The present large holdings of subsidiariesis particularly prevalent in two business ac-tivity categories examined by OTA, coal min-ing and landholding,

In 1950, 18 independent coal companiescomprised the largest leaseholding categorywhile only three coal subsidiaries of noncoalparent companies held leases, By 1980, 36wholly owned coal mining subsidiaries held36 percent of land under lease, while theshare held by independent coal companieshad dropped to 7 percent, Similarly, only onePRLA is held by an independent coal com-pany today, while 33 are owned by coal sub-sidiaries.

In many cases, there is a direct link be-tween the decline of independent coal com-panies and the growth of subsidiaries, Atleast 10 of the wholly owned coal mining sub-sidiaries holding leases today previouslyoperated as independent companies. A largernumber of independent coal companies wentout of business after selling their assets—in-cluding coal leases— to noncoal companies

that subsequently organized coal mining sub-sidiaries to which the leases were assigned.

Landholding companies provide anotherexample of the trend towards 1easing by sub-sidiary rather than independent companies.In 1960, 8 percent of all land under lease wascontrolled by independent landholding com-panies that hoped to profit from the eventualassignment of their leases to coal develop-ment companies. Today the independent land-holding companies hold less than 1 percent ofall land under lease. On the other hand, start-ing in the early 1960’s, leaseholdings by land-holding companies that are subsidiaries ofcompanies with principal business activitiesother than coal mining has increased steadily.Today nine landholding subsidiaries controlmore acreage than the independents ever did.Similarly, only two PRLAs are owned by in-dependent land companies while 30 areowned by land subsidiaries.

The two leasing trends among landholdingcompanies appear to be unrelated. Most inde-pendent landholding companies acquiredleases as speculators and they have gradual-ly liquidated their holdings over the pastdecade. Many of the companies now holdingleases—most notably the energy companiesand utilities—have formed landholding sub-sidiaries to which leases have been assigned.These subsidiary landholding companies arelegal entities through which large corpora-tions hold land, usually for future develop-ment.

Multicorporate Entities

OTA has defined multicorporate entities ascompanies wholly owned by two or more com-panies (such as joint ventures) or two or morecompanies sharing ownership of leases.

Over the past decade there has been a sub-stantial increase in lease and PRLA holdingsby various types of multicorporate businessorganizations. They represent the newestform of business organization to gain a sig-nificant share of the Federal coal leasing pro-gram. Since 1970, leaseholdings by such en-tities have increased from 8 to 25 percent and


PRLA holdings have increased from zero to24 percent. Multicorporate entities are nowthe third largest leaseholding business or-ganization studied by OTA and the secondlargest PRLA holding group.

Three types of business arrangements areincluded in the multicorporate entity cat-egory. The first includes two or more cor-porations holding shares in leases or PRLAs.For example, 10 leases are held jointly byConsolidation Coal Co. and Kemmerer CoalCo. and 10 PRLAs are co-owned by FanninSquare Corp. and Eastern Associated Proper-ties Corp. Secondly, this category includes

companies that represent legal joint venturesof two or more companies formed to developspecific business interests. These includecompanies such as Colowyo Coal Co., a jointventure of W. R. Grace & Co. and Hanna Min-ing Co., and Cumberland Coal Co., a joint ven-ture of subsidiaries of Peter Kiewit Sons andUnion Pacific Corp. Finally, this category in-cludes Peabody Coal Co., (which is owned bysix companies through participation in thePeabody Holding Co.), and Ark Land Co.(which is owned by Ashland Oil and two Huntbusiness enterprises).

Implications of Lease and PRLA Ownership Patternsand Trends

The OTA analysis of the historical roles ofdifferent business activity and organizationalstructures in coal leasing suggests severalobservations.

Concentration

The data obtained in this study reveal littleevidence of a concentration of lease or PRLAholdings among fewer companies. The num-ber of participants in leasing nearly doubledfrom 1950 to 1980, from 84 to over 160. Thefour largest leaseholders in 1950 controlled32 percent of all land under lease while thetop eight controlled 34 percent in 1980.Hence the number of participants has in-creased and the concentration of ownershipamong the top companies has remained near-ly unchanged. The number of PRLA holdershas increased from 37 in 1970 to 47 in 1980.

Other evidence suggesting the absence ofconcentration is provided by the entry oflease and PRLA holders from an increasinglywide assortment of businesses. In 1950, onlyfour business activity categories were iden-tified in this survey as holding at least 5 per-cent of all land under lease. By 1980, ninesuch categories were identified. Also, whilesix business categories contributed 5 percent

or more of the total production from Federalland in 1972, seven categories provided atleast that level of output in fiscal year 1979.In both 1970 and 1980, six business activitycategories held at least 5 percent of allacreage under PRLAs.

While the above data suggest that concen-tration has not occurred, other data showthat leaseholding entities typically hold larg-er blocks of Federal coal land and more Fed-eral coal leases than in earlier years. Duringthe 30-year period when the number of leas-ing participants nearly doubled, the totalnumber of acres under lease increased 18fold and the number of leases increased six-fold. On the average, a lessee held 3.38 leasesand 4,975 acres under lease in 1980, 10 timesmore than the 493 acres held, on the average,and three times the 1.04 leases held, on theaverage, by lessees in 1950. Little change isnoted for average number of acres held byPRLA holders. For PRLAs, the average num-ber of acres held was 8,722 in 1970 and 8,591in 1980.

Diversification

The increased involvement in the Federalcoal leasing program by widely different


types of businesses is complemented by atrend toward increased diversification ofbusiness interests within the lease and PRLAholding companies. Three patterns withinthis trend are noteworthy.

First, there is a growing involvement in theleasing program of horizontally integratedcompanies. The energy companies, naturalgas pipeline companies, and smaller oil andgas companies together hold 31 percent of theland under lease, In 1965, the companies inthese three categories combined held only 4percent of Federal coal acreage under lease.These companies also control 36 percent ofall land under PRLAs, up from 15 percent in1970. For these companies, involvement incoal leasing appears to be part of a strategyto branch into several energy resource fields.

Growing involvement of companies forwhich coal reserves acquisition represents avertical integration of business activities is asecond trend in lease ownership patterns.Steel companies and electric utilities—whichtogether hold 29 percent of all land underlease today —are the two principal examplesof leasing by vertically integrated companies.Steel companies have for decades mined sig-nificant quantities of coal and have par-ticipated in the leasing program since its in-ception. The growth of utility involvement inWestern leasing since 1965 to its position asthe largest leaseholding business activitycategory in 1980 represents a new and sig-nificant type of vertical integration amonglessees. The Federal coal leasing programhas provided an important avenue for utilityentry into the coal industry. Utilities provided11 percent of the Nation’s coal output in1979. They hold 21 percent of all Federal coalland under lease and produced 30 percent ofall coal mined on Federal land. Approximate-ly one-fourth of all utility “captive” coal pro-duction was mined from leased Federalreserves.

A third trend reflects the growing involve-ment of large, already diversified companiesin coal leasing. These include metals and min-ing companies that are diversifying their

mineral extraction skills to include coal. Theyalso include chemical and high-technologycompanies for which entry into the coal in-dustry represents a diversification related to,but not integrated with, existing business ac-tivities.

The shift in leaseholdings to large, diver-sified and integrated companies in turn sug-gests several observations. First, lease de-velopment decisions are increasingly shapedby priorities that reflect business oppor-tunities and capital availability unrelated tocoal development. Secondly, these ownershipchanges can cause a relocation of final deci-sionmaking authority affecting coal develop-ment from local managers to those sometimesworking hundreds or thousands of miles fromlease sites. Thirdly, the internal business ar-rangements established by large companiesto manage coal leases result in complex deci-sionmaking processes. While all three ofthese trends might contribute to increased ef-ficiency in the coal industry, they make un-derstanding coal industry priorities an in-creasingly difficult task.

Another result of ownership changes is theappearance of more lessees with the finan-cial resources available for coal developmentthat far exceed the resources available to theearlier, smaller coal leasing companies. In-creasing participation by larger and morecomplex corporate entities is not surprisingconsidering the large capital requirementsposed by today’s coal development.

Next, the increasing tendencies of thelarge, diversified companies holding leases toestablish multicorporate development proj-ects could raise competition concerns notposed when leasing was dominated by manysmall independent companies. Multicorpo-rate lease development ventures provide ameans for corporations to distribute the risksinvolved in undertaking large-scale coal de-velopment projects. They also increase thecapital generating capacity of the project asa whole. At the same time, they increase thelevel of intercorporate information exchangeand communication. Finally, joint venturingthrough subsidiaries far removed structur-

.


ally from the parent organization has recent-ly provided indirect entry into coal leasehold-ing by railroads. * (Railroads are prohibitedby the Mineral Leasing Act of 1920 from dir-ect lease ownership.**)

Leasing Policies

Several recent studies have pointed to thepotential importance of Federal coal leasingpolicies as a determining factor in the organi-zation and development of the coal industryover the next several decades. The Harvard

*See ch. II, sec. 6 M, Other Leaseholders, of the OTA Tech-nical Memorandum for further in formation. See reference onp. 371.

**A recent Justice Department report recommends strikingfrom Federal law prohibitions againsl the issuance of Federalcoal leases 10 ra ilr(xads or their a ffilia [es. (Competition in theCoal Industry. Report of the U.S. Department of Justice, /)ur-

swn t to sect;(m 8 f~f the Federf]l C(NII Leasing Arnendrnen (S Acfof 1976 for F“iscxd Year 1 !)79; U.S. Dcpartmen t of Justice An-Iitrust Divisifm: November 1980. )

Business Study, Energy Future, for example,observes that: “competition can be protectedby methods short of horizontal divestiture,such as existing antitrust laws, setting limitson the share of reserves any single firm cancontrol, and innovative leasing policies. Thelast can be especially effective.”***

The present study shows that over the past30 years, ownership patterns on leased pub-lic coal land have generally been similar tothe pattern of industry restructuring typicalfor private land. Indeed, some developmentson Federal coal leases—such as the growingrole of utilities as “captive” coal producers—seem to be leading indicators of the changingcharacter of the American coal industry.

* * *R. Stobaugh and D. Yergin (cd.), Energy Future: Report ofthe Energy Project of the Harvard Business School (New York:Random House, 1979).

Appendixes

APPENDIX A

Development and Production ofFederal Coal Leases in the Southern

Rocky Mountain States

Colorado

Overview

Colorado has Federal leases in four coal re-gions: the Green River, the Uinta, the San Juan,and the Denver Raton Mesa regions, (See table 34in ch, 6 for a summary of acreage and reservesunder lease.) The San Juan and the Denver-RatonMesa regions contain the fewest number of Feder-al leases. There is one Federal lease in an ap-proved mine plan in the San Juan region. Six Fed-eral leases in the Denver-Raton Mesa region arecurrently undeveloped. Most of Colorado’s 127Federal leases and reserves are located within theUinta and Green River regions. In the Green Riverregion, 31 leases are in approved mine plans, 3 arein pending mine plans, and 23 are not in mineplans. In the Uinta region, 22 leases are in ap-proved 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 leasescover more than 126,000 acres of land and containover 2.2 billion tons of recoverable coal reserves.The State thus ranks second to Utah, and beforeNew Mexico in lease acreage and reserves in theSouthern Rocky Mountain region. In 1979, Colo-rado mines with Federal leases produced almost16 million tons of coal, as compared to roughly 10million tons from Federal mines in Utah, andabout 8 million tons from New Mexico Federalmines.

Overall the maximum production capacity forColorado’s existing and proposed Federal mines isalmost 45 million tons per year. production fromthese mines in 1986 could exceed 29 million tons.Production from undeveloped leases in 1986 isonly 0.6 million tons, By 1991, production fromexisting and proposed Federal mines could in-crease to about 35 million tons, and productionfrom currently undeveloped leases could also in-crease substantially, to about 8 million tons,

The Department of Energy (DOE) 1985 produc-tion goals for Colorado of 34 million to 38 milliontons are higher than OTA’s estimate of potential

Figure A-1 .—Coal Mines on Federal Landsin Colorado

MOFFAT

● 6“!RIO BLANCO

Map locations

1- Canadian Strip 15- Somerset2- Colowyo 15- Blue Ribbon3- Eagle Nos. 5, 9 16- Loma Complex4- Trapper 17- Bear5- Deserado 17- Mt. Gunnison6- Meeker Area 18- Coal Basin7- Apex No. 2 19- Hawksnest East & West8- Edna 20- Ohio Creek No. 28- Trout Creek 21- Windjammer No. 19- Energy Fuels Nos. 1, 2 22- Cameo Nos. 1, 2

10- Johnnies 22- Roadside11- Seneca, 2W 23- Coal Canyon12- National King Coal 24- Cottonwood Creek13- Orchard Valley 25- Snowmass14- Red Canyon No. 2 26- Marr


production from Federal mines in 1986 (29.4 mil-lion tons), The difference in large part will prob-ably be offset by production from non-Federalmines and from mines on Federal preference rightlease applications (PRLAs), The OTA Coloradotask force estimated that 1986 minimum State pro-duction would be about 26 million tons from allmines. By 1991, the Colorado task force projectedthat minimum State production would range from

389


32 million to 38 million tons. OTA’s analysisfound that potential production from mines withFederal leases could reach 43 million tons in 1991exceeding the task force projection and almostequaling the DOE high-level 1990 production goalof 43.3 million tons. (The DOE low-level goal is 28million tons and the midlevel goal is 35 milliontons,) By the 1990’s Federal mines are expected tocontribute a larger share of total State production.

Green River Region

Of the four coal regions in Colorado, the GreenRiver region is the most important in terms of itstotal coal reserves, its total mine capacity, and itspast and anticipated coal production. Roughly 60percent of the region’s total Federal lease reservesare not yet included in any mining plans. Only 2.5percent of the region’s lease reserves are con-tained within mine plans pending with the Officeof Surface Mining IOSM), The remaining 38 per-cent of the reserves are included within approvedmining plans. (Additional Federal productioncould come from the first new lease sales underthe Federal coal management program whichwere held in the Green River-Hams Fork region ofColorado and Wyoming. Almost 56 million tonswere leased in the January 1981 sale, and an addi-tional 64 million tons were sold in April 1981).

Approved Mine Plans.—There are 10 mine plansinvolving 31 Federal leases that have been ap-proved in the Green River region. Of these, 8 wereactively in production in 1979 and produced atotal of 11.2 million tons of coal in that year. Twomines were not producing in 1979, Six mines aresurface operations and accounted for 93 percentof the production in 1979. All of the approvedmines in this region are expected to be in produc-tion in 1986; moreover, all are expected to meetDepartment of the Interior’s (DOI) diligent devel-opment requirements by that year. Total operatingcapacity for these mines is estimated at 23.6 mil-lion tons per year, of which 21 percent is under-ground capacity. According to mine plan projec-tions, production for 1986 will reach about 19 mil-lion tons and could increase slightly to almost 20million tons per year by 1991. These productionlevels represent 83 and 88 percent of maximumdesign capacity for existing mines. The totalcapacity of currently approved mines will declineslightly as 2 mines exhaust their existing leasereserves, several other large surface mines in theregion will exhaust their strippable reserves in the1990’s and plan to shift eventually to undergroundoperations to maintain production.

Most of the currently operating Federal minesin the Green River region are large operationswith annual capacities ranging from 1.1 million to4,8 million tons per year. The five largest minesaccount for 80 percent of the operating capacity;the mine with the greatest planned capacity is anunderground mine, the multilease Meeker AreaMine, operated by Northern Minerals. This opera-tion, which produced less than 0.1 million tons in1979, is projected to be in full production by 1991,and will be a four-mine complex with a capacityof 4.8 million tons per year.

Of the approved, operating mines in the GreenRiver region, the two with the greatest currentproduction are surface mines. These are the Trap-per Mine, operated by Utah International, Inc.,and the Energy Nos. l&2 Mines, operated by Ener-gy Fuels Corp. Both of these mines, with 1979 pro-duction of 2.3 million and 3.4 million tons, respec-tively, are producing at roughly 85 percent of theirmaximum capacity.

Pending Mine Plans.—There are three mineplans with a total of four Federal leases in theGreen River region that are currently pending ap-proval, Two mines, Western Fuel’s DeseradoMine, and Gulf Oil’s Trout Creek Mine, are ex-pected to produce a total of 1.3 million tons in1986. The Trout Creek Mine is a separate under-ground mine proposed to operate on a Federallease that is also included in Gulf Oil’s existingEdna Strip Mine. This mine is expected to beoperating at its maximum capacity of 0,5 milliontons per year in both 1986 and 1991. The DeseradoMine in the Lower White River Field will supplythe Moon Lake Electric Co. ’s new powerplant inBonanza, Utah. production from proposed minesin this region is expected to increase from the1986 level as a result of increased production fromthe Deserado Mine. Total projected productionfrom pending mine plans in this region is 1.8million tons per year in 1991. One proposed smallmine on a post-FCLAA lease will probably not gointo production because of financial difficultiescaused by the delay in issuing the lease.

Undeveloped Leases.—The Green River regionhas the greatest amount of undeveloped reservesand the highest estimated future production fromits undeveloped leases of any region in Colorado.

The region has 23 undeveloped leases whichcontain approximately 816 million tons of coalwithin about 24,400 Federal lease acres. Theseleases are relatively large, both in acreage and inreserves, For example, 10 of the leases are greaterthan 1,000 acres in size and contain from 20 mil-lion to 250 million tons of recoverable coal re-serves 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 Riverregion, 16 leases in 14 blocks with 792 million tonsof recoverable reserves are promising new mineproperties. The remaining 7 leases with less than24 million tons of reserves could not support in-dependent viable mining operations, (See table 44in ch. 6.) Two leases have favorable developmentprospects. Seven have unfavorable developmentprospects; most of these leases with poor develop-ment potential have insufficient reserves to sup-port an economically viable mine of minimal size.Based on OTA’s evaluation, the majority of thereserves, 738 million tons contained within 14leases, have uncertain development prospects,

The two leases in this region which have favor-able development prospects are held by PeabodyCoal Co, One lease is located midway betweenPeabody’s existing Seneca and Seneca 2W opera-tions, and is expected to be surface mined at a rateof about 0.6 million tons by 1986. This is the onlyundeveloped lease block that is projected to be inproduction in that year. It will supply the nearbyHayden powerplant under a dedication agree-ment, and will maintain Peabody’s current capaci-ty and production levels, Production from theother favorable lease, which will be an under-ground mine, is projected to begin in 1987 andwill share existing nearby facilities. Maximumproduction capacity for this mine would be 1.0million tons per year.

By 1991, 5 of the 14 leases with uncertain devel-opment potential ratings, are projected to be inproduction, Total production from undevelopedleases in the Green River region is estimated to be6.4 million tons in 1991. Production will be con-centrated in the Yampa, Danforth Hills, and NorthPark coalfields. Actual production may vary fromthese estimates. Current production from theGreen River region goes primarily to utilities.

One of the small leases with anticipated produc-tion for 1991, held by AMCA Coal Leasing, waspreviously mined by underground methods, How-ever, it also contains strippable reserves of bitu-minous rank which could be developed as a smallmine to serve spot market or local needs. It is lo-cated in an active mining area where strip re-serves are gradually being mined out, thus makingits marginal strip reserves more desirable, produc-tion is estimated to be as much as 50,000 tons peryear by 1991.

The 1991 production from the lease held byW. R, Grace & Co. could be as high as 1.4 milliontons per year. Considerable uncertainty surroundsthis projected production since one possibility forthe lease’s development is linked to Grace’s pro-

posed synthetic fuels plant in Moffat County. Re-cently, their initial coal conversion goals werescaled down from 5,000 to 500 tons per day. If thesmaller plant proves to be successful, Grace couldscale up to its original size. Grace could also de-velop this tract as an alternative source of coal formore conventional uses when strippable coal re-serves in northwestern Colorado are expected tobe depleted in the 1990’s.

There are seven large Federal leases in the Dan-forth Hills Field of the Green River region: six areheld by Consolidation Coal Co., and one is held byUtah International, Inc. Production from theseleases is contingent on resolution of uncertaintiesinvolving the issuance of associated PRLAs andnegotiations with surface owners, including a po-tential competitor, W. R. Grace & Co, Productionfrom Consolidation Coal’s lease blocks couldreach 1.3 million tons per year by 1991 with aneventual capacity between 3 million and 6 milliontons per year, The lease held by Utah Interna-tional, although reported to have sufficient re-serves to sustain an average-sized new mine,would probably only be developed if the lessee ob-tained sufficient additional acreage and reservesfrom its PRLA or new lease sales to allow opera-tion of a very large surface mine similar to the ad-jacent Colowyo Mine, If development proceedssmoothly, OTA estimates that product ion fromthis mine could reach 1,3 million tons by 1991 outof a potential annual capacity of 3 million to 6million tons,

The remaining coalfield in the Green Riverregion that may have production by 1991 is theNorth Park Field in Jackson County. Possible pro-duction of 0.5 million tons per year from leasesshared by Kemmerer and Consolidation Coal com-panies is estimated for 1991, however develop-ment is contingent on improvements in coal trans-portation from the area, No production is pro-jected for 13 remaining undeveloped leases in theGreen River region.

Uinta Region

The Uinta region contains 63 leases coveringnearly 70,000 acres with a total of over 800 milliontons of recoverable reserves, Approximately 203million tons of reserves are contained in 22 leasesin approved mine plans, about 427 million tonsare in 18 leases with pending mine plans, and 173million tons of reserves are in 23 leases withoutmine plans. Total maximum capacity is 8 milliontons per year for approved mine plans and over 11million tons per year for Federal leases in pending


plans. potential capacity for leases without plansis estimated at 1.5 million tons.

As displayed in table 37 in ch. 6, projected pro-duction for 1991 is 7.4 million tons per year forpending plans, 5.8 million tons per year for ap-proved plans, and up to 1.3 million tons per yearfor leases without plans.

Approved Mine Plans.— In the Uinta region thereare eight operating mines which include 22 Fed-eral leases. All but one of these mines began pro-ducing in the late 1970’s and all of them reportedproduction for 1979. Furthermore, past and an-ticipated future rates of production indicate thatall of the mines will satisfy DOI’s diligent develop-ment requirements by 1986.

Federal lease reserves total 203 million tons inapproved mine plans. Total mine plan reservesare 208 million tons. All of the reserves are highvolatile bituminous and all are best suited for re-covery by underground mining methods. Severalmines in the region produce high-grade metallur-gical coal.

Total maximum design capacity of these minesis almost 8 million tons per year. The maximumcapacity of individual mines varies widely—from0.1 million tons per year for the small Ohio CreekNo. 2 Mine to 1.4 million tons per year for West-ern Slope Carbon’s Hawksnest complex. WesternSlope’s 1979 production was only 31 percent oftheir design capacity. However, they expect to beoperating at full capacity by 1991, The Coal BasinMine’s multilease operation held by Mid Conti-nent Resources, represents another large incre-ment of capacity for approved mine plans. Theirunderground operation is designed to handle 1.3million tons per year, and their projected produc-tion for both 1986 and 1991 of 0.9 million tons isexpected to account for about 65 percent of thiscapacity,

Two mines, the Bear Mine, operated under asublease from ARCO, and the Roadside Mine,operated by Cambridge Mining, are expected toexhaust their reserves by the end of this decade.The Bear Mine is currently operating at close toits capacity of 0.26 million tons per year and willshut down in the next few years before operationsbegin on ARCO’s larger, Mt. Gunnison mine onthe same lease. The Roadside Mine, which beganproducing in the 1900’s and which has a capacityof 1.2 million tons per year, is reducing its oper-ations and anticipates production of only about0.3 million tons by 1986.

The Orchard Valley Mine operated by ColoradoWestmoreland will exhaust its current lease re-serves by the mid-1980’s at its present production

rate. The mine is expected to continue operationswith the acquisition of new Federal lease reserves.

Pending Mine Plans.—The Uinta region has 18Federal leases in 8 currently pending mine plans.In total, there are about 427 million tons of recov-erable reserves on over 34,700 lease acres. One ofthese proposed mines, the Loma complex of Sheri-dan Enterprises, reported production for 1979.This was the result of development work at themine site.

By 1986 five new mines are projected to pro-duce approximately 2.8 million tons of coal. Atthis rate of production, three of these mines, theBlue Ribbon, Loma complex, and Windjammermines, seem likely to meet DOI’s development re-quirements by 1986. All eight of the proposedmines are expected to be in production by 1991,and all but one seems likely to meet diligencedevelopment requirements by then.

When all mines are brought into production,maximum operating capacity is expected to ex-ceed 11 million tons per year. Given this capacitybase, anticipated 1986 production of 2.8 milliontons will represent approximately 25 percent oftotal mine capacity, and projected production of7.4 million tons for 1991 will represent 67 percentof full capacity. several of the newer mines willprobably not achieve full capacity until after l990.

Operating capacity for individual mines rangesfrom 0,12 million to 5.0 million tons per year. Twomines—the Loma project, operated by SheridanEnterprises, and the Mt. Gunnison Mine, oper-ated by ARCO—account for 70 percent of the totalcapacity for pending mine plans in the Uintaregion.

When completed, the Loma project is expectedto be producing from six underground minesusing both longwall and room-and-pillar methods.Estimated production for 1991 is expected to beabout 56 percent of the 5.0 million tons per yeareventual planned capacity for the Loma Mines.

The Mt. Gunnison Mine is projected to beginproduction in 1983, and to take approximately 10years to reach the estimated operating capacity of2.8 million tons per year. The coal will be re-covered by room and pillar underground miningmethods, The reserves in the Mt. Gunnison leasesare very large. If all seams in the lease, includingseams not currently mined, are made part of thelogical mining unit (LMU) reserves for diligence,Mt. Gunnison might have some difficulty in meet-ing the 2,5 percent production required for dili-gence.

Undeveloped Leases.—The Uinta region has atotal of 173 million tons of recoverable reserves


contained within 23 undeveloped leases. The ma-jority of these reserves are recoverable by under-ground mining only, and their quality ranges fromsubbituminous to bituminous. Based on OTA’s re-view of these leases, 18 leases in 6 blocks coveringabout 17,660 acres and containing approximately159 million tons of reserves could sustain newmining operations. The remaining five leases,containing about 14 million tons of recoverablereserves do not have sufficient good qualityreserves to support viable new mines.

Not all of the 18 viable leases, are likely to be de-veloped. Eight leases were classified as favorabledevelopment prospects, three leases have uncer-thin development prospects, and the remainingseven leases have unfavorable development poten-tial.

None of the Uinta region undeveloped leasesare expected to be in production by 1986. For1991, OTA projects that two lease blocks held byU.S. Steel with a total of nine leases could be pro-ducing up to 1.3 million tons. Of this production,up to 0.75 million tons of high-quality metallurgi-cal coal could be produced from eight U.S. Steelleases in the Coal Basin Field. There is someuncertainty about this production, however, duein part to the lease area’s steeply dipping seams,faulting, and deeply buried seams which willmake underground mining difficult and the factthat U.S. Steel has been purchasing productionfrom the neighboring Coal Basin Mine. U.S. Steelhas no current plans to develop the Coal Basinleases before 19$10. Two other mining companieshave developed or planned development of adjoin-ing mine properties which have similar propertycharacteristics, indicating that the adverse miningconditions can be overcome. The remaining un-certainty concerns the currently depressed mar-ket for metallurgical coal. Three other lease blocksheld by U.S. Steel in the Somerset-Paonia areahave uncertain development prospects based onthe expectation that they would be developed aspart of a company strategy to expand coal oper-ations to steam coal, since the coal on these blocksis not of metallurgical quality. U.S. Steel has anexist ing mine in Somerset that supplies i tsGeneva, Utah steel plants. The OTA Colorado taskforce estimated that, by making use of their ex-isting loading and other facilities, surface miningproduction from the other leases could reach 0.5million tons per year by 1991, Alternatively, theleases might be assigned to an independent oper-ator.

No production is anticipated from the remain-ing 14 leases in the Uinta region including two

blocks with a total of 7 leases held by KemmererCoal Co. in the Tongue Mesa Field. These leaseshave sufficient high-quality reserves to support anew mine, but there is not an adequate coal trans-portation system in place.

Denver-Raton Mesa Region

Currently there are no active Federal mines orany pending mine plans for Federal leases in theDenver-Raton Mesa region of southeastern Colo-rado. The region contains six Federal leases with-out mine plans, which OTA has organized intofour lease blocks. Based on a review of the qualityof leased coal, the size of the reserve base and thelessee’s development capabilities, four of theleases in two blocks are considered to be viablemining properties. Peabody Coal Co. holds thefour favorable lease properties which contain atotal of over 48 million tons of surface recoverablereserves,

These leases have uncertain development pros-pects largely because the coal is lignite. Develop-ment of these tracts will likely require a near siteuse, such as a mine-mouth powerplant or synfuelsfacility, in order to overcome the less favorableeconomics of transporting the lower quality coal.The four leases could be producing up to 0.5 mil-lion tons in 1991, and thus may satisfy the DOI’sdiligent development requirements by that year,although this is still speculative. The other twoleases in the region have unfavorable develop-ment potential. The lease held by CF&I Co., hasunfavorable development prospects for 1991 be-cause the lessee has available more attractive non-Federal reserves than those contained within thissingle lease block composed of small scatteredparcels of Federal coal.

The remaining lease, a 40-acre tract with under-ground reserves, is not considered a viable miningproperty due primarily to its small reserves base.

San Juan River RegionThe San Juan River coal region is located in Col-

orado and New Mexico; the larger portion of theregion lies in New Mexico. There are six activenon-Federal mines operating in the Colorado por-tion. The only Federal lease in the region is in theNational King Coal Mine, a small operation pro-ducing about 70,000 tons per year for sale to localconsumers. Coal was first produced from thelease in 1936 and production is expected to de-crease from 83,000 tons in 1979 to 65,000 tons peryear by 1986. The Federal lease reserves are ex-pected to be mined out by 1991.


Summary of Production Potential

In 1979, the 19 mines with Federal leases pro-duced over 16 million tons of coal with about halfof this production (7.7 million tons) from Federalreserves. By 1986, two of the currently operatingmines are expected to deplete their reserves, how-ever, nine new Federal mines are expected to bein production. Overall, OTA projects that, totalproduction from Federal mines will increase tonearly 30 million tons—almost double the 1979production. The percentage of total productionfrom Federal reserves is also expected to increase.By 1991, 35 mines containing Federal leases areprojected to produce 43.1 million tons of coal,About 8 million tons of this production couldcome from currently undeveloped leases.

New Mexico

Overview

The 29 Federal coal leases in New Mexicocover over 44,000 acres and contain 447 milliontons of recoverable coal. The State has the fewestleases and leased reserves among the threeSouthern Rockies States and fewer leased reservesthan any major coal-producing Western State ex-cept North Dakota. Three of the leases are in theRaton Mesa region of northeast New Mexico andthe other 26 are found in the San Juan basin in thenortheastern part of the State.

Only one large coal mine complex is operatingin the Raton Mesa region, It is located entirely onnon-Federal land, No extensive development is ex-pected to occur in this region on either Federal ornon-Federal land, although an additional minecould be developed in the region. Coal is found insmall scattered deposits throughout the rough andmountainous terrain of this region. Though theRaton Mesa contains high-quality and metallurgi-cal-grade coals with a Btu content averaging14,340 Btu/lb and sulfur levels averaging less thanone percent, the difficult terrain, small reserves,and lack of markets has inhibited development.Other problems facing developers of three smallleases here include limited local rail capacity(although the region itself is served by a main lineof the Santa Fe Railroad), and complicated coalland access problems involving intermingled Fed-eral, railroad, Spanish land grant, and privateland blocks.

The San Juan basin contains 96 percent of theremaining coal resources in New Mexico, includ-ing nearly all of the strippable reserves, A substan-tial portion of the basin’s reserves are controlled

by the Navaho Tribe. Over 80 percent of the 1980coal production of 16.5 million tons in the Statecame from this region and by 1990 it could ac-count for over 95 percent. Typical San Juan coalhas a Btu content of 10,492 Btu/lb and a sulfurcontent of 0.84 percent. It has relatively highaverage ash levels of 13.8 percent, although theash content can be as high as 25 percent in someareas.

Mining currently occurs in two areas within theSan Juan basin, There is at present little or no pro-duction in the central part of the basin (see fig.A-2). Production from the northwest corner, in-cluding the San Juan Mine on Federal land, isused at mine-mouth generating stations. Produc-tion from the McKinley Mine on Federal and In-dian land in the southwest part of the region isshipped by rail mostly to Arizona and otherWestern markets. Most of the San Juan basin coalreserves, including areas with leased Federal coal,are not served presently by rail transportation.This central region of the basin is one of thelargest untapped strippable coal deposits in theWestern United States. The Santa Fe Railroad hasproposed to build a 114-mile line into the area,

Figure A-2.—Coal Mines on Federal Lands inNew Mexico

ISOURCE: Office of Technology Assessment.


called the Star Lake Railroad. The final environ-mental impact statement has been issued. The re-maining uncertainty involves 3 miles of right-of-way that cross land owned by Indian allotmentholders. Rugged terrain makes rerouting acrossother land prohibitively expensive. Negotiationswith the Indian allottees are underway and therailroad has asked the Secretary of Interior towaive the landowner consent requirement. TheBureau of Land Management had deferred grant-ing of the rights-of-way across Federal land untilresolution of the allottee issue, though it has ap-proved use of Federal land for the project. TheStar Lake-Bisti Regional Coal EnvironmentalStatement projected that coal production associ-ated with the railroad could eventually reach 75million tons per year, About 8 million tons ofFederal mine production in 1991 is tied to devel-opment of the Star Lake Railroad,

The 29 New Mexico Federal coal leases can bedivided into 16 lease blocks. Three of these unitsare single leases in the Raton Mesa. The other 13are located in the San Juan region.

Nine leases in two lease blocks are currentlypart of operating mines. These two mines pro-duced 9.7 million tons of coal in 1980, about halfof the State’s total production with about 6.3million tons produced from Federal reserves.Three lease blocks including nine leases are partof proposed mine plans which are now pendingbefore DOI. The remaining 11 leases and 10 leaseblocks are undeveloped and no mine plans todevelop them had been submitted to DOI as ofSeptember 30, 1980.

Approved Mine plans.—The two producingmines which include Federal coal leases are theMcKinley and San Juan Mines. The McKinleyMine includes four Federal leases owned by GulfOil Corp. and Indian and private lands. The SanJuan Mine includes five leases owned by WesternCoal Co., a joint venture of Public Service Co. ofNew Mexico and Tuscon Electric Co. It is operat-ing almost entirely on Federal lands, althoughpossible expansion onto coal lands on the UteMountain Indian Reservation to the north is beingconsidered. Both are surface mines. The approvedmine plans for these projects call for small in-creases in mining on Federal land over the nextdecade. The McKinley Mine is scheduled to in-crease production from 4.6 million to 5.0 milliontons by 1991 and the San Juan Mine is scheduledto increase from 5.1 million to 5,5 million tons.The San Juan Mine will shift a portion of its ca-pacity to underground operations on a new Fed-eral lease acquired in 1980.

Pending Mine Plans.—Like the operating mines,the three lease blocks for which mine plans arepending are located in the San Juan region. Fiveleases are part of the La Ventana Mine project pro-posed by the lessee, Ideal Basic Industries. It is theonly active or proposed mine on Federal leases inNew Mexico that will be solely an undergroundoperation. At least seven inactive leases in the LaVentana area once supported small undergroundmines, but these were closed due to structural andfire hazards, inability to comply with health andsafety regulations, and the decline of the domesticcoal market in New Mexico, The proposed LaVentana Mine plan has been designed to resolvewhat had been difficult safety problems involvingpoor roof conditions and the tendency of La Ven-tana coals for spontaneous combustion, A marketfor at least part of the coal produced exists atIdeal’s cement plant in Albuquerque, The mine isscheduled to produce 1.1 million tons by 1986 and1.5 million tons by 1991; it has an eventual capaci-ty of 3 million tons per year.

The other two pending mine plans with fourFederal leases are located in the area of the SanJuan basin presently without rail service. Develop-ment of these tracts will depend on either the con-struction of the Star Lake Railroad or the con-struction of mine mouth power or synfuels plants,The proposed Bisti Mine includes three leasesowned by Western Coal Co. Public Service Co. ofNew Mexico has proposed building a mine-mouthpowerplant near this mine, but that project is inonly preliminary planning stages and the con-struction schedule is still uncertain. The secondlease block is a single lease owned by PeabodyCoal Co., and Thermal Energy Co. The mine pro-posed for this site, however, is being developed byChaco Energy Co., a subsidiary of Texas Utilities,Inc. The Star Lake Mine, as it is called, will likelysupply powerplants owned by the parent com-pany or serve other utility markets. The Star LakeMine eventually will include reserves from pend-ing PRLAs. The Bisti Mine is scheduled to pro-duce 2.5 million tons by 1986 and 3 million tons by1991. The Star Lake Mine is scheduled to produce3 million tons in 1986 and between 3 million and 6million tons by 1991. Coal from Star Lake wouldbe shipped via the Star Lake Railroad.

Undeveloped Leases.—Eleven leases in ten leaseblocks are inactive and have no mine plans fortheir development pending before DOI, althoughsome planning work is underway on several ofthese. The three small leases in the Raton Mesaregion fall into this category of undevelopedleases, The group also includes six small leases


and two large leases in the San Juan region. Thesetwo large leases are part of proposed mining proj-ects which have not yet reached the completedmine plan stage. Production from these mines islikely before the end of the decade, Some prelimi-nary investigations of mine development on sev-eral of the smaller leases as part of mine devel-opment on adjacent lands has been reported, how-ever, prospects for production before 1991 are un-favorable.

The two leases that might be in production by1991 include 98 percent of all the undevelopedFederal lease reserves in New Mexico. The firstlease is owned by Cimmaron Coal Co. and is partof the proposed LaPlata surface mine in north-west New Mexico. The mine could serve the sup-ply needs of the nearby San Juan powerplant asreserves from the San Juan Mine are mined out.Based on a review of a wide range of factors, in-cluding coal quantity and quality, transportationaccess, environmental issues, engineering prob-lems, and markets among others, OTA found thatthe lease has a favorable development potential.Production is scheduled to total 0.2 million tons in1986 and between 1 million and 2 million tons in1991.

The second large New Mexico lease (1,910acres) is located along the route of the Star LakeRailroad. It is owned jointly by Fannin SquareCorp. (a subsidiary of Texas Eastern TransmissionCorp.) and Eastern Associated Properties Corp. (asubsidiary of Eastern Gas and Fuel Associates).The lease also received a favorable developmentprospect rating by OTA though several uncertain-ties cloud its future. The lessees are likely to needadditional coal reserves adjoining the lease inorder to create an economical mining unit forlarge-scale operat ions. The companies holdPRLAs for much of this land which might be con-verted to lease shortly. Texas Eastern Trans-mission received a DOE grant in 1980 to study thefeasibility of building a major synfuels complexnear 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 de-pendent on the completion of the Star Lake Rail-road. The companies nevertheless are proceedingwith plans for the Black Lake Mine, which if itproceeds, is likely to produce between 0.7 millionand 6 million tons by 1991 depending on the com-panies’ coal needs and the rate of development ofadjoining reserves.

Of the nine small leases in eight lease blocksthat are not likely to be in production before 1991,four blocks received uncertain development pros-

pect ratings by OTA and four were rated as unfa-vorable for development.

Two of the leases with uncertain developmentratings are located in the Raton Mesa region. Thelessees of both are studying mining projects thatinclude the leases, but small reserves, mining andtransportation problems caused by the rough ter-rain earned these leases an uncertain rating atbest. The other two lease blocks receiving uncer-tain ratings adjoin the proposed La Ventana Minesite, Each of these lease tracts once were under-ground mines, but they were closed because firesand explosions made them unsafe and uneco-nomical to mine. If Ideal Basic Industries acquiresthese leases and incorporates their reserves intothe La Ventana Mine plan, these problems couldperhaps be overcome. The leases would probablybe surface mined. In their present status it isunlikely that individual mines on these blockscould ever compete.

The final four lease blocks, one in Raton Mesaand three in the San Juan region, received un-favorable development prospect ratings by OTAand were judged to have minimal production po-tential. All four are isolated tracts with small re-serves. Underground mines serving local marketsonce operated on them, but they have been closedfor at least a decade because of safety, engineer-ing, and economic problems. There is currentlylittle or no effort on the part of the present lesseeto develop new mine plans and no published ex-pressions of interest on the part of outside partiesto acquire the leases.

Production Potential

To summarize the production potential of ex-isting Federal coal leases in New Mexico:

Two mines are currently producing about 9.7million tons of coal per year; and by 1986 thesetwo mines with approved mine plans are sched-uled to produce 10.0 million tons. In addition,three mines which currently have mine planspending at DOI could be producing 6,6 milliontons, and one mine which is now in the premine-plan stage could be producing 0.2 million tons by1986.

By 1991, the six existing and proposed minesare scheduled to produce between 19.0 millionand 23.0 million tons. One other mine is due tobegin production after 1986, and is scheduled toproduce between 0.7 million and 6.0 million tonsby 1991. Total 1986 production from mines on ex-isting leases is projected to be 16.8 million tonsand 1991 production is projected to be between19.7 million and 29.0 million tons.


If these projections hold true, 6 of the 16 leaseblocks covering 79 percent of the leased reserveswill be included in active mining operations in1986. By 1991, 7 lease blocks covering 20 of the 29New Mexico coal leases and over 98 percent ofthe coal reserves under lease are likely to be asso-ciated with active mining projects.

The DOE 1985 production goals of 33 million to44 million tons are higher than OTA’s estimate ofpotential 1986 production from Federal mines of16.8 million tons. The OTA task force estimatedthat 1986 total State production would be 30million tons, and recent New Mexico Energy andMinerals Department estimates have set plannedproduction from all mines in the State for 1985 at47 million tons. Most of any shortfall between theDOE goals and potential Federal mine productionin 1985 to 1986 would probably be absorbed bymines on Indian and non-Federal reserves, whichcurrently provide more than half of New Mexico’sannual coal output.

For 1991, the OTA task force estimated that themaximum production potential of all mines in theState would reach 72 million tons—higher thanboth the DOE 1990 high level goal of 67 milliontons and the recent State government estimate of68 million tons of production in 1990. Accordingto OTA’s analysis, production from mines withexisting Federal leases could reach 20 million to29 million tons in 1991.

Actual production levels could vary from theOTA’s projections. Several obstacles to coal min-ing could lower actual production below theseprojections, while the removal of some barriers todevelopment and a strong coal market couldcause production to increase above these levels.

A key determinant of actual coal productionfrom New Mexico leases will be the level of out-of-State utility coal demand specifically and coalmarket considerations generally. A market studyprepared for OTA concluded that the price com-petitiveness of New Mexico coal in major Easternand Western markets is considerably underesti-mated. ” Actual market demand will depend on awide range of issues including the growth of elec-tric consumption, coal supply decisions of Texasutilities (Texas is the major potential new marketfor New Mexico coal), and the growth or declinein coal use relative to substitute fuels for powergeneration. Within New Mexico, the rate of com-mercialization of synfuels technology and the pos-sible construction of additional powerplants to

See Energy and Environmental Analysis, Inc., Feos]bilit~, of [ ~singCool ,Jlorket Projections To Appruiw Potential Production of FwjmmJCorIl Leaseholds, draft report, May 1980.

serve out-of-State customers are two additionalfactors bearing heavily on demand.

The lack of rail service to the central portion ofthe San Juan basin is the second most significantfactor affecting the growth rate of New Mexicocoal production, As explained above, the pro-posed Star Lake Railroad is in an advanced plan-ning stage, but a right-of-way acquisition problemcould still delay or prevent its construction.

Other major issues and uncertainties that willaffect the future of the New Mexico coal industryinclude environmental impacts, land-use con-flicts, socioeconomic impacts on local commu-nities, and the amount of additional Federal re-serves made available for mining through PRLAsand new lease sales. Mining and associated in-dustrial development such as synfuels plants posepotentially unacceptable and unavoidable airquality impacts in this arid region. Mining in theBisti area conflicts with protection of threewilderness study areas and with potentially im-portant archeological and paleontological sites.An exchange of existing leases for new Federalcoal to avoid some of these conflicts is under con-sideration. (See discussion in ch. 9.) Demand foradequate water supplies for mining, reclamation,synfuels development, and community needs andthe need to protect water supplies from possibledegradation could create conflicts between coaldevelopment and other users. Because of the aridclimate, sparse vegetation, and high susceptibilityto wind and water erosion, reclamation ofsurface-mined lands in the San Juan basin mayprove more difficult than in other areas of theWest, This difficulty is not, however, expected torestrict mine development. Most of the expandedcoal development on Federal leases in New Mex-ico will occur in areas that are relatively isolatedand sparsely populated. Associated population in-creases and demands for community services willimpose additional administrative and financial re-quirements on the existing communities, More-over, because Native Americans own or occupysubstantial acreages throughout the basin, reso-lution of potential conflicts between mining andNative interests will require cooperation withtribal governments and the U.S. Bureau of IndianAffairs. (See ch, 12.)

There are currently twice as many acres underPRLAs than under existing leases in New Mexico.Processing of PRLAs in New Mexico will have asignificant effect on the future of Federal coaldevelopment there. Two proposed Federal minescould be adversely affected by loss of reserves ifadjoining PRLAs are rejected. New leased re-


serves from other PRLAs will compete in the mar-ket with other Federal and non-Federal coal cur-rently available for mining.

Utah

Overview

Utah has the largest number of Federal coalleases of any State. There are 204 leases currentlyoutstanding in Utah covering over 279,000 acresand more than 3.2 billion tons of recoverable coalreserves. Utah also has 25 pending PRLAs totalingover 75,000 acres and containing over 1 billiontons of recoverable reserves. According to U.S.Geological Survey (USGS) estimates, about 82 per-cent of the coal resources in Utah are federallyowned, This high percentage is due, in part, to thefact that most of the coal deposits occur in therugged mountainous terrain and the upland pla-teaus of central and southern Utah—areas thathave largely remained in Federal ownership,while State and private land selections, landgrants, and homesteads were concentrated in thevalleys and flatlands. Most of Utah’s known coalreserves are underground minable.

Utah has two major coal regions: the Uintaregion which includes the Wasatch Plateau, BookCliffs, and Emery coalfields in central Utah; andthe Southwestern Utah coal region, which in-cludes the Alton, Kolob, Kaiparowits Plateau, andHenry Mountain coalfields.* There are 108 Feder-al leases in the Uinta region and 96 leases in theSouthwestern Utah region. The recoverable re-serves are divided almost equally between the tworegions.

Nearly 65 percent of the Federal leases in Utahare part of existing or proposed mines and thustheir development and production plans are in-cluded in mine plans filed with DOI. The 14 mineswith approved mine plans are all located in theUinta region and contain 50 Federal leases with atotal of 792 million tons of reserves, Eleven newmines have been proposed covering another 78leases and 1.3 billion tons of reserves. Over 1billion tons of new mine plan reserves are con-tained in the three proposed new mines in theSouthwestern Utah region. The remaining 76 Fed-eral leases without mine plans include severallarge tracts of good quality minable reserves thatcould be producing by 1990, as well as many

* The BLM coal productlon region Uinta-Southwestern Utah com-bines the Uinta coal region of Utah and Colorado and the SouthwesternUtah coal region into a single region for coal management program andproduction target purposes.

smaller tracts that once supported small minesthat will probably not be reopened. The Uintaregion has 44 undeveloped leases and about 447million tons of undeveloped reserves, The South-western Utah region has 32 undeveloped leaseswith 744 million tons of reserves—most of whichare on the Kaiparowits Plateau.

Production Potential

In 1979, Utah mines produced 11.8 million tonsof coal with 10.4 million tons of this from mineswith Federal leases. Federal production was 6.9million tons in 1979 and came from 27 leases. In1980, total State production increased to 13.1million tons with 8.7 million tons coming fromFederal reserves. All production in the State camefrom underground mines in the Uinta region.Figure A-3 shows the location of active and pro-posed mines with Federal leases in Utah.

Most of the coal produced was used by electricutilities, but a significant portion (about 1 millionto 2 million tons) was used by the steel industry.About 40 to 50 percent of the coal produced in1979 was used in the State; the rest was exportedto consumers in the Southwest, west coast, andMidwest, Up to 2 million tons reportedly wasstockpiled in 1979 because of soft market condi-tions. However, by the end of 1980 most, if not all,of Utah’s excess production had been sold, inpart, because of increased foreign export sales. In1981, at least one Utah Federal mine was shippingcoal under contract to Asian markets,

Coal production and mine capacity in Utah areexpected to increase substantially during the1980’s as new mines are opened and existingmines reach full capacity. Production from mineswith Federal leases will account for most of thegrowth. By 1986, total output from mines withFederal leases is expected to be as much as 30.2million tons with up to 6.2 million tons of thiscoming from proposed new mines. By 1991, pro-duction from mines with Federal leases is ex-pected to reach as high as 47 million to 74 milliontons. About 7 million to 8.6 million tons couldcome from undeveloped leases in central Utah.Up to 25 million tons of coal could come from newmines in Southwestern Utah. The total capacity ofexisting mines on Federal leases at full productionis 32.2 million tons per year, If all the pendingmine plans went into production they would add43 million tons of annual capacity. OTA estimatesthat the undeveloped leases could support an ad-ditional 18.5 million to 28.0 million tons of annualcapacity. Southwestern Utah Federal coal produc-


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-Dove1- B Canyon 10- Wilberg-Deercreek2- Braztah 11. Emery3- C & W No. 1 12- Hiawatha Complex4- Pinnacle (Deadman) 13- Huntington Canyons5- Gordon Creek No. 2 Nos. 4, 56- Sage Point-Dugout 14- Trail Mountain

Canyon 15- Alton6- Soldier Canyon 16- Kaiparowits7- Sunnyside Nos. 1, 2, 3 17- Red and Blue8- Belina No. 1 18- Convulsion Canyon (Sufco)8- O’Connor 19- Skumpah Canyon8- Skyline 20- Ute Nos. 1, 29- Star Point Nos. 1, 2

tion could grow from nothing in 1979 to over 25million tons in 1991, with an estimated total an-nual capacity of 36.3 million to 45.8 million tons.However, it is highly uncertain whether suchlevels of production would be achieved in theSouthwestern Utah region because of the majortransportation, economic, and environmental dis-advantages facing coal development there.

OTA’s estimate of planned production frommines with Federal leases in Utah of 30 milliontons in 1986 agrees with the DOE 1985 midlevelproduction goal of 30,2 million tons, but is con-siderably higher than OTA’s Utah task force esti-

mate of 1985 production of between 15 millionand 18 million tons. At least part of the differencebetween the conservative task force estimates andthe OTA estimates and DOE goals is due to de-ferred powerplant construction. For 1991, OTAfound that potential Federal mine productionranged from 47 million to 74 million tons withabout 25 million tons of production in Southwest-ern Utah classified as uncertain. In comparison,the task force projected that 1990 productionwould range from 18 million to 40 million tons,with a likely level of 30 million tons which ex-cludes any production in Southwestern Utah orfor synfuels development. The DOE 1990 produc-tion goals for Utah range from a low of 36 milliontons to a high of 63 million tons with a midlevelgoal of 49 million tons.

The development and production potential ofFederal leases in Uinta and Southwestern Utahcoal regions are described in more detail in thefollowing sections.

Central Utah

The central Utah portion of the Uinta region in-cludes the Book Cliffs and Wasatch Plateau coal-fields near the town of Price and the Emery coal-field near the town of Emery. The Book Cliffs andWasatch Plateau coalfields are underground min-ing areas. The Emery Field has both surface andunderground minable reserves. The central Utahcoalfields have supported mining operations forover a century. Two active mines in the BookCliffs Field—U.S. Steel’s Geneva Mine and KaiserSteel’s Sunnyside Mine—suppIy metallurgicalcoal to their Western s teel operat ions. TheWasatch Plateau Field is the major producing areain the State. (See figs. A-4 and A-5.)

There are 108 Federal leases outstanding incentral Utah. There is only one pending PRLA inthe region. * Federal leases in central Utah cover128,930 acres and contain an estimated 1.5 billiontons of recoverable coal reserves, including about21 million tons of surface recoverable reserves inthe Emery field, The 50* * leases in the 14 miningoperations with approved plans cover over 55,000acres and more than 792 million tons of recover-able reserves and have a total maximum designcapacity of 32.2 million tons per year. There are

* Possible impacts of issuance and development of this PRLA are ex-amined in the Final [ rin to-!jou I}] wws[ern [ Itoh Cool Enl,ironmentaj Sto tP-ment, Februar}, 1981.

* *Tbrec leases in the C)’ Connor mine area are also partly included inthe approved mine plans for the Belina and Skyline mines,

400 ●

An

Assessm

ent of

Developm

ent and

Production

Potential

of F

ederal C

oal Leases

\

Figure A-4.-Federal Coal Leases, PRLA's and New Lease Tracts Wasatch Plateau and Book Cliffs Fields

SOURCE: U.S. Department of the Interior, Bureau of Land Management, Uinta·Southwestern Utah Final Coal Environmental Impact Statement, February 1981.

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 theEmery Coai Fieid, Utah

TO PRICE

T“o

, \ . .‘. I\ I

..\;d - - \, .

/ ‘ \A

c%

@.fi i “\

1 [/ / .“-”-” \ \ Coastal States ‘. f.+ . I I

.-- SUFCO

— ~ [..> I II Link Flat I

, 1 a

a1>1

1 m a8 1 , n

1 lx 11 1 r

r11

o New lease tract (1981 sale)

SOURCE U.S. Department of the Interior, Bureau of Land Management, Uinta-Southwestern Utah Final Coal EnvironrnentalImpact Statement, February 1981.


also eight proposed new mines in the Uinta regionwith 14 leases that are in pending mine plans. *These leases cover 25,711 acres and contain about264 million tons of recoverable reserves. The pro-posed new mines have a total annual capacity ofover 13 million tons per year.

The remaining 44 leases in central Utah areundeveloped. These leases cover 47,679 acres andmore than 447 million tons of reserves. When thecontiguous leases held by the same owners aregrouped together into minable blocks, the unde-veloped leases in central Utah form 20 leaseblocks with 12 blocks each composed of only 1lease.

The active mines in central Utah range from afew small underground operations producing lessthan 100,000 tons per year to new large mines pro-ducing over 1 million tons per year. Several minesare in the process of expanding their productioncapacities to produce up to 5 million tons per yearor more by 1985, The 14 approved mining opera-tions on Federal leases in central Utah are all un-derground mines and all, but the newly approvedSkyline Mine, were producing in 1980, In 1980,over 8.7 million tons of production from Federalleases were reported to USGS for royalty pur-poses.

By 1986, production from operations with ap-proved mine permits is projected to reach 24million tons, more than double the 1979 produc-tion levels. By 1991, production from these minescould rise to 29 million tons. One small operation,the Trail Mountain Mine is expected to be de-pleted by 1991 unless it acquires additional re-serves to maintain production. Both U.S. Steel’sGeneva Mine and Kaiser Steel’s Sunnyside Mineare expected to be nearing the limit of their eco-nomically recoverable reserves by the late 1980’sand would then begin to shift production to newmines on their other Federal leaseholdings. OTA’smine plan review indicates that about 5 million ofthe 32.2 million tons of capacity on approvedmine plans might not be constructed as plannedbecause of changes in the lessee’s captive coalneeds out-of-State.

Six of the operating mines are captive opera-tions, including two mines operated by steelcompanies, two complexes run by Utah Power &Light, the Soldier Canyon Mine run by CaliforniaPortland Cement, and the Braztah Mine complex

“These leases include two leases that are partially included in twodifferent mines: the newly approved Skyline Mine and the adjacentBelina and O'Connor mines which are dissected by several fault zonesand 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 6.1million tons—over half the total production in theState. By 1986 captive production from Federalmines is expected to total about 13 million tonsmaking a slight decline in its share of total Stateproduction. The captive segment of the Utah coalindustry is expected to maintain it’s position inthe 1980’s and 1990’s since a significant amountof production from new mines on Federal leaseswould supply captive markets.

Pending Mine Plans.—The eight proposed newmines on Federal leases would, if all were devel-oped as scheduled, add more than 13 million tonsof annual production capacity in central Utah by1990. One new mine, Eureka Energy’s 3.2 milliontons per year Sage Point-Dugout Canyon Mine, isintended to supply a new 1,600-MW coal-firedpowerplant to be built by its parent Pacific Gasand Electric Co. U.S. Steel’s new B Canyon Minewould replace the existing Geneva Mine whenthat operation reaches the limits of its economi-cally minable reserves. Mountain States Re-sources’ Ute Nos. l&2 mines near Emery wouldinclude both underground and surface operations.Several of the proposed new mines have been inplanning stages for 5 years or more, however,mine permitting and construction activities havebeen deferred by the lessees because of soft mar-ket conditions and slower than expected electrici-ty demand growth.

If all the proposed new mines meet theirplanned production schedules, six of the eightmines will be operating by 1986 with an estimatedtotal production of 5.6 million tons. By 1991, alleight mines could be producing a total of 11.3 mil-lion tons according to the mine plan estimates.However, because at least two of the new minesare captive operations, their construction and pro-duction schedules are dependent on the needs oftheir parent companies. Current indications arethat the Sage Point-Dugout Canyon Mine and theB Canyon Mine could be deferred several years,thus making about 4.2 million tons of 1991 pro-duction capacity somewhat uncertain.

Undeveloped Leases.—The 44 leases in centralUtah without mine plans cover 47,679 acres andcontain 447 million tons of recoverable reserves.These leases are 57.9 percent of the undevelopedleases, 42 percent of the undeveloped lease acresand 37 percent of the undeveloped Federal leasereserves in the State of Utah. The 44 undevelopedleases in the Uinta region are divided into 20 leaseblocks ranging in size from 80 acres to more


18,000 acres. Most of the reserves are under-ground minable only—however, one tract con-tains some surface recoverable reserves. About sixof these lease blocks have supported some miningactivities in the past. All of the undeveloped leasereserves in central Utah are bituminous with heatvalue of 11,000 Btu/lb or more, sulfur contents of1.5 percent or less, and ash contents of 15 percentor less.

Eight undeveloped lease blocks with 30 leaseshave enough good quality minable reserves to sus-tain a new average-size mine of 500,000 tons peryear with a 30-year mine life. These 30 leases con-tain a total of 417 million tons of recoverablereserves. The remaining 14 leases in 12 blocks didnot have enough reserves for a new large mine. Atleast three of these blocks (six leases) have ade-quate reserves for a small mine, however. Two ofthe three blocks have been mined previously andprobably would not be reopened because con-struction and safety costs would be prohibitive,Four undeveloped leases without enough reservesfor a new independent mine are adjacent to activeor proposed operation and could possibly beadded to those mines through assignments oroperating agreements,

After reviewing the quality and amount of re-serves, the mining conditions, transportationavailability and the expected market conditionsover the next decade, OTA classified as favorabledevelopment prospects the eight lease blocks withadequate reserves to support new mines, Theseeight blocks with a total of 30 leases and 417 mil-lion tons of reserves have almost 95 percent of theundeveloped lease reserves in central Utah. Threeone-lease blocks were rated as uncertain devel-opment prospects depending on the availability ofadditional reserves. The remaining 11 leases innine lease blocks have unfavorable prospects fordevelopment.

The eight blocks with favorable prospects in-clude two large tracts with a total of eight leasesheld by Kaiser Steel in the Book Cliffs Field andone very large block of eight leases in the EmeryField with more than 18,000 acres jointly held byConsolidation Coal Co. and Kemmerer Coal Co.Two other favorable blocks are held by companieswith active mines on Federal leases: one leaseblock held by a subsidiary of ARCO, Beaver CreekCoal Co. (successor to Swisher Coal Co.), and athree lease block held by Energy Reserves Group,Inc., adjacent to its proposed Skumpah Canyonoperation,

Three more blocks with favorable developmentprospects are located in a single township near

two proposed Uinta new lease sale tracts andseveral active mines on existing leases. * Theseblocks include: one tract of five leases in RildaCanyon owned by Utah Power & Light near itsDeer Creek-Wilberg Mine; a two-lease block con-trolled by Nevada Electric Investment Co, adja-cent to the Hiawatha Mine complex; and anotherblock that was originally a single lease and wasrecently segregated into two leases, one assignedto Northwest Carbon Corp. and the other to COPCoal Development.

Development plans for four of the eight favor-able blocks are known based on company inter-views. Kaiser Steel plans to develop the two-leaseSunnyside North tract which has metallurgicalcoal reserves as replacement capacity for the ex-isting Sunnyside Mine when it reaches the eco-nomic limits of its minable reserves. The block isnot contiguous to the existing mine. The six-leaseSunnyside South block with lower quality, metal-lurgical-grade reserves could be mined for steamcoal. Consolidation Coal, which already has oneproposed mine on Federal leases in the EmeryField, plans to combine surface and undergroundmining operations in developing its remainingeight leases near Interstate 70 in Emery County,Utah Power & Light is expected to mine its fiveundeveloped leases as either a new mine or as anexpansion of the Deer Creek-Wilberg Mine. UtahPower & Light is also actively seeking the Meet-inghouse Canyon and Rilda Canyon new leasetracts adjacent to these lease blocks to supply itscoal-fired powerplants.

The two blocks held by Beaver Creek Coal Co.and Energy Reserves Group will probably bemined when those companies shift operationsfrom existing mines as they are depleted. Produc-tion plans for the two remaining blocks are un-known, however, it is expected that they will bedeveloped since all three lessees involved own ad-ditional reserves in the same area and one lessee,Nevada Electric, is a major consumer of Utahcoal.

The total estimated capacity that could be sup-ported by the favorable lease blocks is 12 milliontons per year, By 1986, none of the leases are ex-pected to be producing, However, by 1991, the

‘All of these blocks have been acquirwi h~ the (,urrrrlt Icssm; withinthe []ast 2 years, onc hlock of fite Icas(!+ was rm;[,ntl~ a{ {Iuirt,(i })}, IJlahPower & I,]ght (;orp. I rom P{,ill)()(j} (;oi]l (;(), A n o t h e r I)lo(:k of leas(,swas segregated and lmrt was ,]cqulrrd hy hlorthuwst Carhon (;orp. Ther(:malndrr \\,as assigned to COP Coal Development and i]noth(.r l)lo(:km’as acquired h} (;O1] Coal I)t:\,[;iol)l?][~t~t (~orp trorn Pcaho(i},. A not hrrhlo( k is held h) the IN(N ada E:Ic( t ri( I n~ mtment. a suhs)diary of Nma(]aPo~flr Co.


leases could produce between 7,0 million and 8.6million tons.

No production is estimated for the three leaseswith uncertain development prospects or for the11 leases with unfavorable development prospectssince these leases are not likely to be producingduring the next 10 years unless they are combinedwith other reserves controlled by the lessee ormined as part of an adjoining operation, Two ofthe uncertain leases and four of the leases with un-favorable prospects are adjacent to or contiguouswith existing or proposed mines.

Some of the major concerns involving coal de-velopment in central Utah are: potential impactson water availability and water quality such as theinterruption of springs due to subsidence, in-terception of aquifers during mining operations,discharges into streams, increased sediment load,and leaching of salts, trace elements, and heavymetals from strata disturbed during mining. Otherconcerns include: losses in wildlife habitat fromexpansion of the areas disturbed by mining; im-pairment of air quality; and population increasesfrom mine development resulting in concentra-tion of socioeconomic impacts in the Price-Helperarea. These issues are addressed more fully in theenvironmental impact statements on central Utahcoal development and the recently completedfinal environmental impact statement for theUinta coal lease sales.

One area that could have substantial impactsfrom new mining on Federal leases is the EmeryField. The coal leases belonging to Consolidationand Kemmerer Coal companies are bisected by In-terstate 70-a major tourist route, However, be-cause the area would most likely be undergroundmined and the coal reserves in the vicinity of I-70are of poorer quality, it is unlikely that any miningwould be done near the highway. The Emery areais just west of the San Rafael Swell—a scenic areaof geologic interest—and expansion of mining ac-tivities could contribute to increases in airbornparticulate and to reduced visibility, especiallyduring dry spells. The Emery Field is not current-ly served by rail transportation so existing minestruck coal to loadout facilities near Price. The pro-posed Castle Valley Railroad would extend alongthe Wasatch Plateau to the Emery coalfield. Con-struction of the railroad is dependent on expand-ed mine production in that area.

Southwestern UtahThe Southwestern Utah coal region includes

the Alton, Kolob, Kaiparowits Plateau, and Henry

Mountains coalfields. The Henry Mountains Fieldhas no Federal leases, it does, however, have threePRLAs. The southwestern Utah coalfields haveboth underground and surface minable reserves,however, underground reserves predominate.There are no active mines in the region, althoughthere were several small mines operating on Fed-eral leases that supplied coal to local markets.Three new large mines have been proposed for theAlton and Kaiparowits fields. Proposed miningoperations in the Alton Field have encounteredsubstantial opposition from environmentalistsbecause of its proximity to several major nationalparks, the possible impacts on visibility andground water, and potential reclamation prob-lems. Mining on the Kaiparowits Plateau has beenopposed because it would occur in one of the lastremaining undisturbed roadless areas in theUnited States outside of Alaska, and also becauseof potential air quality impacts.

There are 96 Federal leases in the SouthwesternUtah coal region covering over 150,000 acres and1.75 billion tons of recoverable coal reserves. The24 pending PRLAs in the region cover an addi-tional 72,000 acres and over 1.0 billion tons of re-coverable reserves. Three new large mines havebeen preposed in southwestern Utah: The AltonMine with combined surface and undergroundoperations on 28 leases held by Nevada Power andUtah International, Inc.; and two proposed under-ground mines on the Kaiparowits Plateau—ElPaso Energy Co.’s Red and Blue Mines and theKaiparowits Mine on leases held by resourcedevelopment subsidiaries of three Southwesternutilities. These three proposed mines include 64 ofthe existing leasesover 93,000 acresreserves.

The remaining 32and 743.5 million

in southern Utah and coverand over 1 billion tons of

leases cover over 57,000 acrestons of recoverable under-

ground reserves. These undeveloped leases are di-vided into 11 lease blocks—seven single leaseblocks and four multilease blocks. Several of theleases supported small mines in the past. Six leaseblocks with 27 of the leases are located in the Kai-parowits Plateau.

Pending Mine Plans.—The three mine plans pro-posed for southwestern Utah contain over 1 bil-lion tons of recoverable reserves with about three-quarters of the reserves underground minable.The proposals include the Alton Surface Mine


and two underground mines on the KaiparowitsPlateau. Total annual production capacity of theproposed mines is 30 million tons. Estimated pro-duction in 1986 is about 600,000 tons. If all mineplans were approved in the next decade, produc-tion in 1991 could be as much as 25.4 million tons.All of these proposals face substantial uncertain-ties over whether and when they will go into pro-duction, All are located in remote areas that arenot currently active mining areas and which arenot served by rail transportation. All present po-tential environmental conflicts. All have substan-tial uncertainties over where the coal will be sold.

The Alton Mine located near the town of Alton,just south of the Paunsaugunt Plateau and BryceCanyon National Park, is probably the best knownof the southern Utah mine proposals because of its

location and concern over its potential impacts onthe park (see fig. A-6). The Alton Mine is part ofthe Allen-Warner Valley Energy Complex and isthe closest to development of any of the proposedmines in southwest Utah because it has success-fully obtained several necessary permit approvalsand, until recently, appeared to have a definiteconsumer for its coal production. But, recent de-velopments have clouded its future and the oper-ator, Utah International, Inc., has deferred initialproduction until at least 1986. The mine wouldinitially be a surface mine, but after about 20 yearsof operation, would begin underground mining onmore deeply buried reserves.

In December 1980, Interior Secretary Andrusissued his decision on the citizens’ petition todeclare Federal lands in the Alton coalfield un-

Figure A-6.– Federal Coal Leases in Southwestern Utah

i7

Mt. Carmel JI

Escalante

Rubys Inn

/ Paunsaugunt P Iateau

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.


suitable for mining under the Surface MiningControl and Reclamation Act of 1977 (SMCRA).This was the first section 522 unsuitability peti-tion accepted. Secretary Andrus declared Federallands adjacent to Bryce Canyon National Park asunsuitable for surface mining and the surface ef-fects of underground mining. The decision af-fected about 9,049 acres on the eastern side of theAlton Field out of the more than 26,000 acres leas-ed by Utah International and Nevada Power. As aresult of the decision, about 24 million tons of themore than 290 million tons under lease would notbe minable. The decision cited the potentialadverse impacts on the park from blasting, heavytruck traffic, air quality degradation, and noisefrom the mining operations which would have ex-tended to within 5 miles of the Yovimpa Pointlookout in Bryce Canyon Park. The original peti-tion had requested that Andrus declare a total of325,000 acres (240,000 acres of Federal land) asunsuitable for mining. The lessees have filed suitin Federal District Court in Salt Lake City chal-lenging the adequacy of the technical informationsupporting the decision and alleging that theAlton leases should be exempt from the unsuit-ability provisions because of substantial legal andfinancial commitments to development madebefore passage of the act.

In Feburary 1981, two of the partners in theAllen-Warner Valley Power project, SouthernCalifornia Edison and Pacific Gas & Electric,withdrew their applications for participation inthe project from consideration by the CaliforniaPublic Utility Commission. The decision was, inpart, based on the decisions by the Secretary of In-terior and EPA to approve permits for construc-tion of one portion of the project, the Harry Allenplant in Nevada, and to withhold approval of thesmaller Warner Valley Plant in Utah pending ad-ditional study. Southern California Edison also at-tributed its decision to a shift in company policyto the use of renewable energy sources. Substan-tial questions thus still remain over constructionof the two plants and of the proposed slurry linefrom the Alton Mine to the powerplants.

The Alton lessees have submitted an informalmine plan proposal for use in environmental anal-yses. The lessees have reportedly deferred submit-tal of a final plan until after the Alton unsuitabilitydecision was made. The proposed mine wouldproduce up to 11.2 million tons of coal annually.The impact of the unsuitability petition on devel-opment is still unclear—about 10 percent of the re-serves were withdrawn from production. Shouldthe decision stand, the lessees are expected to seek

an exchange of the affected leases for other com-parable Federal coal lands in the area. Interiorhad previously indicated it would give prompt at-tention to such a request.

Two mine plans have also been submitted forunderground mines on the Kaiparowits Plateau.El Paso Energy proposes to open a large under-ground mine complex on its 40,00()-acre” leasetract. The first two mines, the Red and BlueMines, would produce a total of about 1.1 milliontons per year. El Paso plans to expand productionon the plateau in other reserve areas to reach aneventual annual capacity of 6.8 million tons peryear.

The Kaiparowits Nos. 1-5 complex is proposedby a consortium of three resource developmentsubsidiaries of electric utilities: Mono Power, asubsidiary of Southern California Edison; Re-sources Co., a subsidiary of Arizona Public Serv-ice Co.; and New Albion Resources Co., a subsidi-ary of San Diego Gas & Electric Co. These leasesare located on the southern portion of the plateaujust south of the El Paso leases. The lessees plan toopen several underground mines on the jointlyheld lease tract of over 47,000 acres which wouldeventually produce 12 million tons per year. Theleases were originally acquired as PRLAs andwere intended to supply electric utilities in theSouthwest or, possibly, a powerplant near themine area. Because of concerns about impacts onthe region’s air quality and water supply, power-plant construction at or near the mine complex toserve out-of-State consumers is now consideredunlikely.

Development of the two planned mines on theKaiparowits Plateau is uncertain. Both mine planswere submitted before the implementation ofSMCRA and have not been updated to reflect thecurrent mine plan requirements. The major uncer-tainties affecting their development are lack oftransportation to move coal to market and lack ofany definite market for the production. Estimatesby the Union Pacific Railroad are that a minimumproduction of 30 million tons per year would benecessary to offset the costs of construction of arail line to the plateau. The two proposed mineswould produce 18.8 million tons at full capacity—just over 60 percent of the minimum required pro-duction. It is very uncertain whether a market forthe required 30 million tons or more of Kaiparo-wits coal will materialize over the next decade. Anadditional factor that affects the development ofthese mines is the remote location and the need toprovide a supporting infrastructure for mine de-velopment. 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 wouldbring an increase in population and greater de-mand for services such as roads, utilities, water,and housing to serve the mine employees. Theserequirements could put southwestern Utah devel-opment at a disadvantage when compared toother established mining areas.

Undeveloped Leases.—There are 32 undevel-oped leases in southwestern Utah. These leasescover 57,537 acres and 744 million tons of recov-erable underground reserves. The leases are di-vided into 11 lease blocks, 7 of these are singlelease blocks ranging in size from 40 to 1,440 acres.There are four multilease blocks ranging in sizefrom 6,400 acres to more than 25,500 acres, Six ofthe lease blocks are located on the KaiparowitsPlateau, and the five others are small leases thatare scattered across the region. Four of the fivesmall lease blocks have previously operated assmall mines but were shut down in the 1950’s and1960’s as local markets diminished.

In reviewing the development potential of theselease blocks, OTA found that four of the six tractson the Kaiparowits Plateau each had sufficientreserves of good quality coal that could support in-dependent mining operations. These four blocksinclude two separate tracts held by Peabody CoalCo., one large tract on the northern portion of thePlateau held by Consolidation Coal Co., and athree-lease tract held by Hiko Bell Oil & MiningCo. on the southern edge of the plateau near theGlen Canyon Recreation Area withdrawal. Twotracts on the plateau did not meet the minimumquality and reserve requirements for new mines.One block held by El Paso has difficult miningconditions relative to the lease configuration andis separated from the company’s other leases inthe Red and Blue mine plan proposal, The otherblock, a lease owned by an individual, is on thesouthern portion of the plateau with generallylower quality reserves and more difficult prob-lems of access to the seams because of topogra-phy.

All of the leases on the Kaiparowits Plateau arein an isolated, rugged area, not served by existingtransportation systems capable of moving coal tomarket. Access for mine development is difficultbecause of the steep, highly dissected cliff faces ofthe plateau and the complex geology of the multi-ple coal seams. The area would require more ex-ploratory and developmental drilling, and con-struction of roads, utility lines and other support-ing services before substantial mining operationscould begin. The 25 leases in the four lease blocks

on the plateau that could support new mines werethus rated as having uncertain development pros-pects. The two single lease tracts were classifiedas unfavorable development prospects.

The five remaining small lease tracts inSouthwestern Utah were found to have unfavor-able development prospects as new mines. Theygenerally did not have sufficient reserves to sup-port a new large mining operation. Their loca-tions made them potentially suitable to serve lim-ited local markets only, The reserves on the smalltracts are also generally poorer quality coals. Twoleases located near Zion NationaI Park have somepotential environmental problems (wildlife andwater quality impacts) although they have beenmined in the past and are not located in highlyvisible areas so they would not, as compared toAlton, pose a visual intrusion onto the park areas.

An analysis of the production potential of thefour tracts on the Kaiparowits Plateau with uncer-tain development prospects indicated that theycould support a total annual production of 7 mil-lion to 16 million tons depending on the choice ofmining technologies and mine life. This calcula-tion was made on the basis of available informa-tion on the reserves, geology, topography and pos-sible mining conditions that could be encoun-tered. Full production capacity is expected to beattained in 3 to 6 years from initial commercialproduction. At a minimum, because of the timeneeded for mine plan development and other con-struction, it was estimated that 1987 is the earliestdate 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 andother permits, and about 2 to 3 years of prelimi-nary mine development and construction. It is notknown how long it would take to construct the re-quired railroad or supporting community infra-structure. If the potential 7 million to 16 milliontons annual production capacity from the un-developed leases is added to the 18 million tons ofproduction proposed from the Kaiparowits and ElPaso mine complexes, the annual regional pro-duction approaches the range required to supportconstruction of the rail line. It was suggested inthe regional environmental impact statement forSouthwestern Utah that initial production frommines could be trucked to Page, Ariz., and usedfor power generation there—however, that ap-pears an unlikely alternative at present. It isbecoming clear, however, that development of ex-isting Federal leases on the Kaiparowits Plateau isvery much an all or nothing proposition.

OTAAPPENDIX B

Working Lease Listand Lessee Index

1. OTA working Lease ListFederal Mines and Undeveloped Lease Blocks

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...............409Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 416New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........419North Dakota... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............421Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................423Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............426Wyoming . . . . . . . . . . . . 0 . . . . . . . . . . . . . . . . . . ...............434

II. Lessee IndexA. Leaseholding Subsidiaries: Key for Locating Parent Companies. ....440B. 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

t-l u u-l‘uc~

Q.wc*vcal9.

8 1+..+o

F-1 aJ(J.d

&m

J=Ln0CAm.

G omu

-(o &

Nov+d+

o


m

m - I . - I

I ‘Q

In

I I 1I I

al4M

$w..

CL

...,-1 Q

.s

App. B—OTA Working Lease List and Lessee Index ● 411

ov

,-+4 4 .

-0wQ.o

‘uaJ

.-ial

‘a

~

uH

I II I

I II

1+al

8Gl-l \

aal

t.&!

.


o

\w

u e-)

u

1+

GL1 .

2H

al

& .II●

E8


com.,-4cc

3

U3. .6‘-u,+al.+

m

ue-l\A

40

:m0v

m

Mla+-0c

!$

t-l m m +u

I0

30)40u

3-u!3ah

.II.

dG

4-I-U~ .;

$-oal.,-(sVcn

.!+11C411


comm

.

uc0u

I UY‘M

i?2

mcmalz

II

II

-&al

.

II

.II

mcCd

!++0 .

App. B—OTA Working Lease List and Lessee Index ‘ 415

,+\m

●

▼✟

1+cd

8

II

.


.+ d u

I

wc

h

ma\.8

Goc

halucm~

II

.(a●✍

S .●

App. B-OTA Working Lease List and Lessee Index ● 417

1I

I

l-lCd

2.

4.

.


I

al

..4

VIJ-1

.

II

l-lalaJ

i%


u-l

c1I n m 4

I

%-( IIu

mCa

3 i% .,+$0

‘uc(u

.P.‘u

ct-o

II.

vcu

II

.

U - I *0 0u

. .w

II

.

II

.

r-((u

s .


ueoM\m

cm

II

II I I

I I

II

.mI-4 UJ

o-l


oCa

n.t-d

mwu)m .+ N

I

‘ol-l0l-l

2Gw

Cal+!+

Qal0.

2kw

ww

\II

.

8

.


Q!4

~

CJ

c0.+k-l

.-l .+ N

ua0.0

Wwc o

Immalcmc2

tdJ..-4(n

.w

II w

0

.

2a)4-I

6al

w

gc0.+

II

o-:c8


w-lal

hr-m

!--4U-1co

-4-4A $5-4

N

1+PImuU-J

(Iit-a9.

!-ld

s+

Cd

8

!+d

s\.uct-l

.UI!=!m

&-.

(no@u

H

z?u

.

i-+QJal

daJa

i%

-1

aaJ

r%s i%


\ \ o \ \ \ - l \b- +mmcq+m

Ind

u N

‘ual$20 ,4

Ii!

II

●

s

\.ucHI

I

●

l-lmlco+u

II

●

g

encII

1+1+1+lu

6.

-1Ld

—


Ml

.

‘ ual9.0

l-u4JUUlm

II

.

II


II

●

$

mal

.8

●✍

8 II

dal

WI

.sm

4cL(ow

d%-4o


t’:

d

*

In m m m

alc

fll’aC.c.+ 4-I

ac

●

s,2W4-)0

.Cn

2M+a

I-Y buI-1aJal

i%


t’i

0N

n

\Lnr= .

nalwLQs.

aaJ0

.

u

‘ocmmGv-l

I .-l.

~c0 ss!I

c

n. ‘3W.

InomowoDom

.s.

o!=G

3 *


m

‘ual

~

I

II

$-uca

l-l

:u

II

IIc

o?-lL1

l-l(6

.0, I

I

.a.

II

6.\(iL1

s

cwga

L1

a)>

($l-lalaJ

z

●

✘1+

w m.

a J-1alm

NalIn


I

II

II

II

IIII

II

‘uh0s

.E8 5

G(d

‘u


I

Ln

m. .


.

0

I

G0u2!

II

. .

I


QaJP.0

I II

II

dcd

s

1I

4 II

M

434 ● An Assessment ot Development and Production Potential of Federal Coal Leases

C-N

-ii‘ua>:P.a

o

● 88

.

App. B—OTA Working Lease List and Lessee Index . 435

m

uc0c) m .-4 (-0m m

.+

I a

II

.

8

-J


c

:WI

o

I

wc1.

u(n

:

\

&lc

u.,-+,-(


UT

ow

m

w.

i?

E

.


c

;

8

r- (=-I

‘dal?!Ma

J?

uaJ>:Ps

2

43a

‘u

;

rn2

.-

.

u(f)


wocoJ-l

8 m(-QalUI

l-l

.+. =

-uaJ

EMlc+mc:

1+

I

aJu

w

. II

.

6

0u

dCds

1+

\.$ Cn

+

f+Ca

2C9

-1+o

+o

.

440 . An Assessment of Development and Production Potential of Federal Coal Leases— —

.

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 cooFalkirk Mining Co.Fannin Square Corp.

Franklin Real Estate Co.Freeman United Coal Mining Co.GEX ColoradoKanawha & 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 ResourcesSt. Joe Minerals Corp.Ashland Oil & Hunt InterestsAtlantic-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 TransmissionCorp.

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 UtilitiesNorthwest 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)

- -- -

U n i o n P a c i f i c C o r p .( 5 0 p e r c e n t )

- -—- -- -- -

- -- -- -- -

- -- -

- -

- -—- -- -- -- -

U n i o n P a c i f i c C o r p .(50 percent)

—- -- -

Nevada Electric InvestmentNew 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 SalesSheridan 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 PipelineCo. (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. ofNew Mexico(50 percent)

Montana Power Co.Phelps Dodge Corp.Northwest Energy Corp.Black Hills Power & Light Co.Kansas Nebraska NaturalGas Co.

- -Peabody Holding Co.

(50 percent)

- -

- -—- -- -- -- -- -

Union Pacific Corp.(50 percent)

--- -- -—. -- -

Tuscon Electric Co.(50 percent)

- -- -- -- -


alu

I II z

c

Qdo,-4

App. B—OTA Working Lease List and Lessee Index . 443— . . — . — —

C&

CJ .-+

t I I I


In

u-l e-l .

94

<

.

I


oaJ zm.

mom.

Inm*

0.3

0m

mi--mIn04m

ccum(-0u0z

.

-0c0g.+c1

I

c1z !2


-3

.

1 I I I

.

oIn

App.

B—

OT

A

Working

Lease List

and Lessee

Index .

447

.c

W.-

al>8

0Ln

PARENT CO. Leaseholding Subsidiary (if any)

Coal Co. (continued)

percent

STATE

UT

VT

LEASE BLOCK OR MINE NAME

Emery Deep

/-IT CX Ranch

ND Glenharold

ND Renner s Cove

ND Velva

HI NE PLAN NUHBER STATUS OF LEASES

p

A

SERIAL NUMBER ACRES

U5287 720

UOI03107 2560 UOI03109 2557 UOI03129 2560 UOI03130 2554 UOI05418 2560 U0149373 2560 U098783 254 U098784 2538 U098785 2543 \J09a787 2560

U073039 2577 Gulf Oil Corp./Kemmerer Coal Co. U073040 2542 holds 50 percent interest in U073041 2558 these nine leases. UOI01213 2162 UOI01214 2314 UOI01215 856 UOI01217 640 UOI01218 1880 U090231 2497

1146292 674

M070203 477 M11269 260 M121209* 1668

:137829 322

MI5896** 40

*This lease is in a pend mine plan; however, it has been grouped 1.1: th leases in approved mine plans for the purpose of OTA's analysis because of its association with the two in the Glenharold mine plan.

**This lease was mined out before passage of the Surface Mining Control and Reclamation Act of 1977. However, it is c: assified as undeveloped since no mine plan was submitted with the Office of Surface Mining.


t--l

II 4. 4 ..+ 4 A 4

I II I

o


I

I

I

I

. - m

a


u

I

App.

B—

OT

A

Working

Lease List

and Lessee

Index ●

45

1

ZI

%P.w

W$

ZC

A

2

m. .

mal2-+ucou.u$5.

.LI

6

LESSEE LEASE BLOCK MINE PLAN NUMBER Leaseholding (if an~~) STATE OR MINE NAME STA TUS OF LEASES SERIAL NUMBER ACRES

General Electric Co. Utah International, In • con inued

UT Alton P 20 U0105404 1529 There are twenty-eight Federal UOl15938 1721 leases in this mine. The other U0122579 1120 eight are held by Nevada Power U0122582 582 Co./Nevada Electric Investment U0122583 320 Co. U0122584 320 UOl22623 280 U0122647 600 UOl22649 840 U0122650 1600 U0122651 1080 U0122652 80 U0122675 80 U0124768 200 U0126916 320 U0140770 519 U0147999 320 U0149582 560 U098774 2488 U09877 5 1599

General EXEloration! Inc. GEX Colorado CO Cameo A C01538 256{)

Cambridge Coal Co. CO Roadside A C078049 810

Gent's Flying Enterprises UT U S1050655 80

UT Tip Top U S1062648 80

Geo Resources EXEloration, Inc. ND Nelson Pit U M065329 320

Gettl 011 CorE' Kerr Coal Co. CO Marr A C22777 770

Energy Fuels Co. CO Ene r gy Fue Is A C20900 420 No. 1 & 2 C22644 1790

C22676 402 0052547 1145 C0128433 475 C081330 2215 C16284 263

452

● A

n A

ssessment

of D

evelopment

and P

roduction P

otential of

Federal

Coal

Leases

.

m

0w..m

. .

v.*

n

.

.

PARENT CO. LEASE BLOCK MINE PLAN NUMBER Leaseholding Subsidiarl (if anl) STATE OR MINE NAME STATUS OF LEASES SERIAL NUMBER ACRES NOTES

Gettl Oil Corp. Plateau Mining Co. (continued) UT Star Point 1 & 2 A 4 U7949 1631

S1031286 240 U13097 1360 U37045 698

Granite Creek Coal & Uranium Co. WY Granite Creek U 9039 280

Great National Cor~ OK McCurtain No. A NM24005 140

Gulf Oil Cor~ WY Gulf 1 & U W0236507 195 (Arvada) W0236621 2551

W0240559 1620

WY Gulf 3 U W025663 756

WY Wildcat U W0220516 1571

CO Edna Stri A 0033327 280 0041478 80 0053710 89

CO Trout Creek A&P C021601* 827

CO Pa"nia Farmer's U 0036955 280

NM McKinley A 4 NM057349 2513 NM057348 2485 NM0554844 540 NM065466 2560

Kemmerer Coal Co.*** WY Elkol-Sorenson A W055246 2401

WY North Block U W075207** 714 W0294513 519 M056471 960 W060274 745

WY North-North Block U W075206 1247

*This lease is in both the approved Edna Strip mine plan and the pending Trout Creek mine Plan. **This lease is contiguous to both the approved Elkol-Sorenson lease and North Block. However, present plans are to mine the lease as part of North Block. ***Gulf Oil Corp./Kemmerer Coal Co. holds 50 percent interest in an additional 12 leases in four other lease blocks. See leaseholdings under Conoco, Inc./Consolidation Coal Co.


I

.

a

I I

0v

.1

.


m 4. . . CNm

<& ZJ

.

m


m m m

u u

I I I

H!3


.8

.

.

El h

m

a

05


n., a

m

.8

458 . An A

ssessmen

t of

Developm

ent and

Production

Potential

of F

ederal C

oal Leases

— .+

L)<

C4

co.

mI

.

PARENT CO. LEASE BLOCK MINE PLAN NUMBER Leaseholding Subsidiary (if any) STATE OR MINE NAME STATUS OF LEASES SERIAL NUMBER ACRES -- NOTES

Northwest Industries, Inc. Lone Star Steel Co. (continued) OK U BLMC018125 2560

NM050406 2400

OK U NM059996 719

Occidental Petroleum CorE' Sheridan Enterprises, Inc. CO Lorna Complex P C0125436 2446

C0125437 2357 C0125438 2560 C0125439 2483 C0125515 2560 C0125516 2523

CO Joe s U D052546 60 Pacific Gas & Electric Co.

Eureka Energy Co. UT Sage Point-Dugout P U07746 2480

Canyon U089096 480 U092147 680 U0144820 2212 U07064 2416

UT U U05067 320 Pacific Power & Light Co.*

WY Dave Johns' A 6 C054769 120 W0244167 1803 W0312918 3779 W038597 1400 W038602 2000 W041355 560

WY Phillips Creek U W0136194 322 (1) W0136195 1477

W0136196 1560 W0324701 680

WY Phillips Creek U W0310712 40 (2)

*Pacific Power & Light Co. holds 66.6 percent interest in an additional three leases in another mine. See subsidiary leaseholdings under Idaho Power Co


al

ov

.--1 -YCl

El ah

2u0cCc

r- (-4aI I

I

0u

c+

mCJ

2

.


I

App.

B—

OT

A

Working

Lease List

and Lessee

Index ●

46

1

4

df-l

Ln

$&a

z

-1u

PARENT CO. Leaseholding Subsidiary (if any)

Peter Kiewit Sons, Inc.* Big Horn Coal Co.

Rosebud Coal Sales

Black Butte Coal Co. (50 percent

Cumberland Coal Co. (50 percent)

Petroleum International

Phelps Dodge Corp. Western Nuclear, Inc.

Pitkin Iron Corp.**

Public Service Co. of New Hexico Western Coal Co. (50 percent)

LEASE BLOCK STATE OR MINE NAME

Vi Armstrong

Vi Rosebud

HI ex Ranch (PKS)

Vi Black Butte

Vi South Haystack

OK

OK

Vi Western Nuclear

CO Cottonwood Creek

Nt-I Bisti

Nt! San Juan

MINE PLAN NUtIBER STATUS OF LEASES SERIAL NUMBER

U 8025369

A C057086 W483330

U M061686

A W6266

W06024

U Nt-!3174

U NH957

U W022978

P C020740

P 3 Nt-10186612 NM0186613 NM0186615

NH071448 NM045197 NM045217 Nt-1045196 NM28093

ACRES

80

1273 130

524

14902

408

2840

3342

80

40

2188 1240 2027

40 2565 1800 2467 3856

NOTES

Union Pacific Corp. holds 50 percent lnterest in Black Butte Coal ~.

Union Pacific Corp. holds 50 percent interest in Cumberland Coal Co.

There are a total of three Federal leases at this mine. One is held by James Brothers Coal Company. The other is held jointly by Pitkin Iron Corp., Kermit James and Richard James.

Tuscon Electric Co. holds 50 percent interest in Western Coal Co.

*Peter Kiewit Sons, Inc. holds 50% interest in an additional 5 leases in two other mines. See subsidiary leaseholdings under Pacific Power & Light Co. **Pitkin Iron Corp. holds 33.3 percent interest in one other lease. See leaseholding under James, Kermit and Richard.


(-lmo

UYu

I

I

I

I

I

I

I

I

. .

El

I

I

I A

I I II

I

I

I

-M


I

I

a

0v

I

I

In

0Pi

*

i

I

I

I

I

I

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

20

r=inN

.-3I

I

I

I4u-lou

I

u

I

I al

f%

I

I

I

I

I

malm

(-a>

ii

II II

ov

0m .


.em

0m

j

v!-l0.

.-. .04LP 04

ml

APPENDIX C

Acronyms, Abbreviations, and Glossary

Acronymns and Abbreviations

AARABSACLDSAMCAQCRAQSAVFBACTBIABLMBNbtCBOCEUM

CFRCNWCSMRI

CTCDEIS

DOEDOIDRIDSL

EAEDFEGREIAEISEMARS

EPAE.R.C.ERCOTETSIF.2dFCLAA

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.FWSGAOGMOGPOICCKRCRA

LMUMARCA

MERmtmtyNAAQS

NCANERC

NEPA

NETS

NSPSOSMOTAPILTPKSPPLPRBPSD

PRLASERISIDSIPSMCRA

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 particulateUP — Union Pacific RailroadU.S.C. — United States CodeUSGS — U.S. Geological SurveyWSCC — Western Systems Coordination

Council

App. C—Acronyms, Abbreviations, and Glossary . 467

Glossary

Acre Foot: A measure of water 1 ft deep by 1 acrein area, or 43,560 cubic feet.

Alluvial Valley Floor: Those stream valleyslocated west of the l00th Meridian which: 1)are underlain by unconsolidated gravel, sand,silt, and clay; 2) have a stream flowingthrough them; 3) have a generally flat valleyfloor topographic surface; and 4) have an agri-cultural importance. The relative importanceof these valleys is a function of the water sup-plies available in the specific valley area. Theagricultural activities generally include ir-rigated or subirrigated hay lands, developedpasture lands, critically important grazingareas, or lands that could be developed for anyof these purposes.

Approximate Original Contour: The surface con-figuration achieved by backfilling and gradingthe mined area so that the reclaimed area, in-cluding any terracing or access roads, closelyresembles the general surface configuration ofthe land prior to mining and blends into andcomplements the drainage pattern of the sur-rounding terrain, with all highwalls and spoilpiles eliminated.

Aquifer: A subsurface zone that yields economi-cally important amounts of water to wells; awater-bearing stratum or permeable rock,sand, or gravel.

Area Strip Mining: A mining technique charac-terized by the use of a power shovel, dragline,or bucket wheel excavator for removing over-burden. This type of mining first proceeds byconstructing a trench or box cut in the over-burden to uncover the initial strip of coal thatis to be mined. After the coal has been re-moved from the bottom of the box cut, the“spoil” or overburden material covering thenext strip of coal is removed and placed in thevoid left by the mining of the preceding stripof coal. Mining proceeds with succeedingoperations until the limits of the mining areaare reached.

Automated Coal Lease Data Systems (ACLDS): Acomputerized information system maintainedby the Bureau of Land Management of the De-partment of the Interior for Federal coalleases and lease applications. ACLDS con-tains a wide variety of technical and adminis-trative information on every lease and prefer-ence right lease application.

Best Available Control Technology (BACT): Atechnology or technique that represents the

most effective pollution control that has beendemonstrated, used to establish emission oreffluent control requirements for a pollutingindustry.

British Thermal Unit (Btu): The quantity of heatenergy required to raise the temperature of 1lb of water 1° F at, or near, its point of max-imum density (39.1° F).

Continuous Miner: A machine with rotating cut-ting bits used in underground mining to cutrelatively soft coal from the coal face. Thecoal is removed by breaking the coal from theface and then transferring it to loading ma-chines.

Continuous Operation: Requirement that a Fed-eral lease must produce at least an annualaverage of one percent of logical mining unitreserves after diligent development has beenachieved.

Conventional Mining: An underground miningtechnique in which specialized machines areused in sequence to perform individual min-ing operations. The mining face is first under-cut with a cutting machine resembling a chainsaw. A drill is then used to bore holes into theface at an appropriate spacing; the holes arethen filled with an explosive. After blasting,the coal is fragmented and allowed to drop onthe floor of the mine in front of a new face.The coal is removed, the roof is bolted forsupport, and the mining sequence is repeated.Conventional mining accounts for 35 to 40percent of underground mining in the unitedStates.

"De novo” Leasing: The original issuance of alease or prospecting permit by the FederalGovernment.

Development Potential: An assessment of theprospects for a lease or lease block being de-veloped and mined within the next decade,taking into consideration the reserves, miningconditions, geographic location, status of ad-jacent properties, surface resource values, en-vironmental impacts, potential markets, trans-portation availability and community infra-structure. Three development classificationswere used by OTA in this report:●

●

Favorable-development potential—The leaseor lease block has favorable developmentcharacteristics overall; the lease(s) meet thethreshold criteria for a viable mining prop-erty; there are no major technical or permit-ting problems or uncertainties associatedwith the lease development.Uncertain development potential—The lease


or lease block has uncertain developmentpotential because development is contin-gent on factors such as transportation avail-ability or synfuels development or becauseof lack of information about the lessee’s de-velopment intentions, Property character-istics can be good or marginal.

● Unfavorable development potential—Thelease or lease block has unfavorable devel-opment potential, generally because it hasone or more of the following property char-acteristics: small reserves, difficult miningor reclamation conditions, poor qualitycoal, or isolated location.

Diligent Development: As used in this report, dili-gent development generally refers to the re-quirement in the Mineral Leasing Act that alllessees must make a reasonable effort to bringthe lease into production. The Department ofthe Interior has issued regulations that definediligent development for Federal coal leasesas actual production of commercial quantitiesof coal from the lease or the logical miningunit of which the lease is a part by June 1,1986, or within 10 years after the lease isissued, whichever is later. Under certain con-ditions, the period for meeting diligence canbe extended to June 1, 1991, for leases issuedbefore passage of the Federal Coal LeasingAmendments Act of 1976.

Face: The solid unbroken surface of the coal seamexposed at the advancing end of the workingplace.

Federal Coal Lease: A lease issued under theMineral Leasing Act of 1920 which grants theexclusive right to mine Federal coal subject toconditions set in the act, the lease, and ap-plicable State and Federal laws and regula-tions.

Federal Coal Reserves: Coal reserves owned bythe United States,

Federal Lands: Lands or interests in land, in-cluding subsurface mineral rights, that areowned by the United States, regardless of howownership was acquired.

Federal Mine: A mine that includes a Federal coallease in its mine area.

Grading: The leveling or elevation of land to a rel-atively smooth horizontal or sloping surface.

Lease Assignment: The sale or transfer of a leaseor a partial interest in a lease from the currentlessee to another.

Lease Block: A single lease or a group of two ormore contiguous leases owned or controlledby the same lessee(s) or operator.

Lease Segregation: The division of an existinglease into two or more parcels at the request ofthe lessee. A new lease is then issued for eachnew parcel and the surviving lease is modifiedto reflect the reduced acreage, Lease segrega-tion requires the approval of the Departmentof the Interior. Segregation is frequently usedas a form of partial assignment.

Longwall Mining: An underground mining sys-tem that consists of a set of roof supports or“jacks” that are located parallel to the miningface, a conveyor system that runs along thebase of the face, and a cutting mechanism thatmoves back and forth along the face cuttingthe coal out of the face and dumping it on theface conveyor for transport out of the mine. Ina longwall system, parallel entries (typicallyfrom 300 to 600 ft apart are driven into thecoal seam using continuous miners. Then aninterconnecting passage is made between theentries. The exposed seam is then mined insuccessive slices using the longwall system.As the slices or panels are removed, the roofsupport system is moved forward and the un-supported roof is allowed to collapse into themined-out area left behind.

Maximum Economic Recovery (MER): Require-ment that all portions of the coal depositswithin a lease having an incremental cost ofrecovery (including reclamation, safety, andopportunity costs) less than or equal to themarket value of the coal, must be mined.

Mine Development: As used in this report, theprocess of acquiring detailed geological, engi-neering, environmental, technical, and eco-nomic data for mine planning, construction,and initial commercial operation,

Mine Plan: As used in this report a mine planrefers to: 1) an operating plan for a mine withFederal leases submitted to the U.S. Geologi-cal Survey (USGS) under the requirements ofthe Mineral Leasing Act of 1920; or 2) a min-ing and reclamation plan for a mine with Fed-eral leases submitted to the U.S. Office of Sur-face Mining (OSM) under the Surface MiningControl and Reclamation Act of 1977. A mineplan is a detailed description of the operator’sproposed method, rate and sequence of min-ing, environmental protection measures, andreclamation strategies. The mine plan must beapproved by USGS and OSM and appropriateState agencies before mining can begin.

Mine Size: As used in this report: A small mineproduces 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 mineproduces over 500,000 tons per year.

New Source Performance Standards: Standardsset for new facilities to ensure that ambientstandards are met and to limit the amount of agiven pollutant a stationary source may emitover a given time.

Non-Federal Coal Reserves: Include private,State, local government, and Indian coal re-serves.

Open-Pit Mining: A system of surface miningcharacterized by a series of benches, thenumber of which increases as the mine isdeepened. These benches are each 40 to 50 ftin height and allow excavation to hundreds orthousands of feet.

Overburden: Earth, rock, or other consolidated orunconsolidated material that overlies a com-mercially valuable mineral deposit, such as acoal seam, especially those deposit which aremined from the surface through open cuts.

Preference Right Lease: Noncompetitive coallease issued to the holder of a prospecting per-mit who discovers coal in commercial quanti-ties on the land under permit.

Public Lands: Lands and interests in land ownedby the United States and administered by theSecretary of the Interior through the Bureauof Land Management without regard as tohow the United States acquired ownership,except lands located on the Outer ContinentalShelf and lands held for the benefit of Indians,Aleuts, and Eskimos. Public lands are general-ly divided into public domain lands, whichhave never left Federal ownership, and ac-quired lands, which are not in the public do-main and which have been obtained by theUnited States through purchase, condemna-tion, gift, or exchange.

Reclamation: Restoring mined lands to produc-tive use; including replacement of topsoil, res-toration of surface topography, and revege-tation,

Recoverable Reserves: The amount of coal thatcan be economically extracted from a coal de-posit of known location, quantity, and qualityusing currently available technologies. (Seech. 4 of this report for additional discussion ofcoal resource classifications.)

Recovery Rate: The percent of minable coal ac-tually recovered. Typically 90 percent for aWestern surface mine and 40 to 50 percent foran underground mine.

Room-and-Pillar Mining: An underground min-ing method in which coal is removed in a sys-tematic pattern leaving behind mined-out‘rooms’ and unmined coal ‘pillars’ to supportthe overlying rock. The actual extraction ofcoal in the room-and-pillar mine is accom-plished with either conventional mining orcontinuous miners.

Royalty: A payment, either on straight fee per tonor as a percentage of the value of coal pro-duced, to the owner of the resource for per-mitting another to mine and sell coal.

Severance Tax: A special levy, assessed at flat orgraduated rates, on the extraction of naturalresources.

Spoil: The overburden or material removed ingaining access to the commercially recover-able coal deposit, also called waste.

Spoil Pile (or Bank): An area where spoil or over-burden material is deposited before backfill-ing; that part of the mine where the coal andother materials that are not marketable areleft,

Surface Subsidence: The settling or sinking of thesurface as a consequence of collapse of under-lying strata because of underground mining.

Terrace Pit Mining: This method of surfacemining combines the area-strip and open-pitmining techniques and is designed for thethick coal beds of northwestern Wyoming andsoutheastern Montana. The terrace pit minehas a system of benches like the open pit mine.However, there are more benches (six orseven) than with open pit mining. Also, theterrace pit mine, unlike the open pit mine,does not remain in the same location butrather moves across the property in a mannersimilar to a strip mine. Overburden is re-moved from one side of the pit, hauled aroundthe pit ends, and dumped on the other sidewhere coal has already been mined.

Undeveloped Lease: A lease for which no mineplan has been submitted,

APPENDIX D

Some Key References

Cannon, J. S., Leased and Lost: A Study of Pub-lic and Indian Coal Leasing in the West (NewYork: Council on Economic Priorities, 1974).

Cannon, J. S., Leased and Lost 1975, Council onEconomic Priorities Newsletter N5-9 (NewYork, Oct. 19, 1975).

Cannon, J, S., Leased and Lost, 1976, Council onEconomic Priorities Newsletter N6-8 (NewYork, Sept. 13, 1976).

Cannon, J. S., Mine Control: Western Coal Leasingand Development, Council on Economic Prior-ities (New York, 1978).

Colorado School of Mine Research Institute (forOTA), SynfueIs Potential of Western Coal,Draft Report (Washington, D. C., October1980).

Colorado School of Mine Research Institute (forOTA), Criteria for Determining Viable MiningProperties on Existing Federal Coal Leases inthe Western United States (Washington, D. C.,March 1980).

Council of Energy Resource Tribes, The Controland Reclamation of Surface Mining on IndianLands (Washington, D, C,: CERT, Sept. 30,

1 9 7 9 .

Department of Economic Planning and Develop-ment, 1975 Wyoming Mineral Yearbook (Chey-enne, Wyo. 1976).

Deurbrouck, A. W., Sulfur Reduction Potential ofCoals in the United States, RI 7633 (Washing-ton, D. C.: U.S. Government Printing Office,1972).

Energy and Environmental Analysis, Inc. (forOTA), Feasibility of Using Coal Market Projec-tions to Appraise Potential Production of Fed-eral Coal Leaseholds (Washington, D, C., EEA,Inc., 1981).

Federal Energy Regulatory Commission, Status ofCoal Supply Contracts for New Electric Gener-ating Units 1979-1988, draft report, February1981.

Glass, Gary B., Wyoming Coal Production andSummary of Coal Contracts (Laramie, Wyo.:The Geological Survey of Wyoming, 1980).

Hachman, F. (for OTA), Market Factors AssociatedWith the Assessment of the Development Po-tential of Federal Coal Leases in Utah (Wash-ington, D. C., 1980).

ICF Inc., Analysis and Critique of the Departmentof Energy’s August 7, 1980 Report Entitl1ed

—“Preliminary National and Regional CoalProduction Goals for 1985, 1990 and 1995, ”ICF, Inc., Washington, D. C., October 1980.

ICF Inc. (for DOE), Final Report, Survey of UnitedStates Coal Mine Expansion Plans (Washing-ton, D. C.: ICF, Inc., August 1980.

ICF Inc., Forecasts and Sensitivity Analyses ofWestern Coal Production (Washington, D. C.:IFC, Inc., November 1980).

Martin, J. E, (for OTA), Market Factors and Pro-duction Contingencies Determining the Presentand Future Demand for Colorado Coal, draftreport (Lakewood, Colo.: Colorado Energy Re-search Institute, October 1980).

McMeans, G. B., The Economic Viability of Pro-posed West Coast Coal Port Sites (Oakland,Calif.: Kaiser Engineers, Inc., 1981).

Mining Information Services, 1979 Keystone CoalIndustry Manual (New York: McGraw-HillMining Publications, 1979).

Mining Information Services, 1980 Keystone CoalIndustry Manual (New York: McGraw-HillPublications, 1980).

Murray, F, X. (cd,), Where We Agree: Report of theNational Coal Policy Project (Boulder, Colo.:Western press, 1978),

National Academy of Sciences, Rehabilitation Po-tential of Western Coal Lands: A Report to theEnergy Policy Project of the Ford Foundation(Cambridge, Mass.: Ballinger Publishing Co,,1974).

National Coal Association, NCA Long-Term Fore-cast (Washington, D. C.: NCA, 1981).

National Coal Association, Survey of Existing andProposed Synthetic Fuel Facilities (Washing-ton, D. C,: NCA, September 1980).

National Research Council, Surface Mining: Soil,Coal, and Society (Washington, D. C.: NationalAcademy Press, 1981).

Sebesta, J. J. (for OTA), Demand for Wyoming andMontana Coal, 1980-1991, Based Upon the Pro-jected Utility Coal Market (Washington, D. C.,O c t o b e r 1980) .

U.S. Department of Energy, Bituminous and Sub-bituminous Coal and Lignite Distribution(Washington, D. C.: U.S. Government PrintingOffice, April 1980).

U.S. Department of Energy, The 1980 Biennial Up-date of National and Regional Coal ProductionGoals for 1985, 1990 and 1995, DOE/FE-0013

470

App. D—Some Key References ● 471

(Washington, D. C.: U.S. Government PrintingOffice, 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. Gov-ernment Printing Office, January 1981).

U.S. Department of the Interior, Annual Report onCoal (Washington, D. C.: U.S. GovernmentPrinting Office, FY 1977).

U.S. Depar tment of the Interior, Federal CoalManagement Report (Washington, D. C.: U.S.Government Printing Office, FY 1978).

U.S. Department of the Interior, Federal CoalManagement Report (Washington, D. C.: U.S.Government Pr int ing Off ice , FY 1979) .

U.S. Department of the Interior, Final CoalManagement Report (Washington, D. C.: U.S.Government Printing Office, FY 1980).

U.S. Department of the Interior, Final Environ-mental Statement, Development of Coal Re-sources in Central Utah (Washington, D. C.:U.S. Government Printing Office, 1979).

U.S. Department of the Interior, Final Environ-mental Statement, Development of Coal Re-sources in Southwestern Wyoming (Washing-ton, D. C.: U.S. Government Printing Office,1978).

U.S. Department of the Interior, Final Environ-mental Statement, Development of Coal Re-sources in Southern Utah, FES 79-21 (Washing-ton, D, C,: U.S. Government Printing Office,May 1979).

U.S. Department of the Interior, Final Environ-mental Statement, Federal Coal ManagementProgram, Stock No. 024-011 -00099-2 (Wash-ington, D. C.: U.S. Government Printing Of-fice, 1979).

U.S. Department of the Interior, Final Environ-mental Statement, Northern Powder River Ba-sin Coal, Montana, FES 80-1 (Washington,D. C.: U.S. Government Printing Office, Janu-ary 1980).

U.S. Department of the Interior, Final Environ-mental Statement: Northwest Colorado Coal(Washington, D. C.: U.S. Government PrintingOffice, 1976].

U.S. Department of the Interior, Final Environ-mental Statement, Permanent Regulatory Pro-gram Implementing Section 501(b) of the Sur-face Mining Control and Reclamation Act of1977, OSM-EIS-1 (Washington, D. C.: U.S.Government Printing Office, January 1980).

U.S. Department of the Interior, Final Environ-mental Statement, Proposed Development ofCoal Resources in Eastern Powder River Wyo-ming (Washington, D. C.: U.S. GovernmentPrinting Office, 1979).

U.S. Department of the Interior, Final Environ-mental Statement, Proposed Leasing, CarbonBasin Area (Washington, D. C.: U.S. Govern-ment Printing Office, July 1979).

U.S. Department of the Interior, Final West-Cen-tral Colorado Coal Environmental Statement(Washington, D, C.: U.S. Government PrintingOffice, 1979).

U.S. Department of the Interior, Secretarial IssueDocument, Federal Coal Management Pro-gram, stock No. 0-295-110/6267 (Washington,D, C.: U.S. Government Printing Office, 1979),

U.S. Department of the Interior, Final West-Cen-tral North Dakota Regional Environmental Im-pact Study on Energy Development (Washing-ton, D. C.: U.S. Government Printing Office,October 1978).

U.S. Department of the Interior, Final Environ-mental Impact Statement, Proposed FederalCoal Management Program (Washington,D, C.: U.S. Government Printing Office, Sep-tember 1975).

U.S. Department of the Interior, Green River-Hams Fork Final Environmental Statement(Washington, D. C.: U.S. Government PrintingOffice, August 1980).

U.S. Department of the Interior, Uinta-Southwest-ern Utah Final Environmental Statement(Washington, D. C.: U.S. Government PrintingOffice, February 1981).

U.S. Department of the Interior, Southern UtahPetition Evaluation Document, Final 522SMCRA Evaluation OSM-PE-1 and Environ-mental Statement OSA4-EIS-4 (Washington,D. C.: U.S. Government Pr int ing Off ice ,November 1980).

U.S. Department of Justice, Competition in theCoal Industry, stock No. 027-000 -00678-7(Washington, D. C., U.S. Government PrintingOffice, May 1978).

U.S. Department of Justice, Competition in theCoal Industry, FY 1978, stock No. 027-000-00790-2 (Washington, D, C.: U.S. GovernmentPrinting Office, May 1979).

U.S. Department of Justice, Competition in theCoal Industry, FY 1979 (Washington, D. C., No-vember 1980).

472 ● An Assessment of Development and Production Potent/a/ of Federal Coal Leases

U.S. General Accounting Office, Issues Facing theFuture of Federal Coal Leasing, EMD 79-47(Washington, D. C., June 25, 1979),

U.S. General Accounting Office, Innacurate Esti-mates of Western Coal Reserves Should Be Cor-rected, EMD 78-32 (Washington, D, C., July 11,1978).

U.S. General Accounting Office, Mapping Prob-lems May Undermine Plans for New FederalCoal Leasing, EMD 81-30 (Washington, D. C.,Dec. 12, 1980).

U.S. General Accounting Office, ImprovementsNeeded in Administration of Federal Coal Leas-ing Program, B-169124 (Washington, D. C.,Mar. 19, 1972),

U.S. General Accounting Office, A Shortfall inLeasing Coal From Federal Lands: What Effecton National Energy Goals? EMD 80-87 (Wash-ington, D. C., Aug. 22, 1980),

Wiener, Daniel P., Reclaiming the West: The CoalIndustry and Surface Mined Lands (New York:INFORM, Inc., 1980),

APPENDIX E

Availability of OTA Working Papers

The following OTA staff and contractor paperswere used in the preparation of this report andwill be made available in early 1982 through theNational Technical Information Service:*J, Russell Boulding and Deborah L. Pederson, De-

velopment and Production Potential of Unde-veloped Federal Coal Leases and PreferenceRight Lease Applications in the Powder RiverBasin and Other Wyoming Coal Basins, FinalReport, November 1981.

Douglas W. Canete, Iris A. Goodman, and Deb-orah L. Pederson, Development and Produc-tion Potential of Existing Federal Coal Leasesin the Fort Union Region of North Dakota andMontana, Final Report, December 1981.

James S. Cannon, Karen L. Larsen, and J. StephenSchindler, The Development Prospects for Fed-eral Coal Leases in New Mexico, 1980-1991, Fi-nal Report, November 1981.

James S. Cannon and Cheryl A. Stevenson, Fed-eral Coal Preference Right Lease Applications:Their History, Ownership and Current Status,Final Report, December 1981.

Colorado School of Mines Research Institute, Cri-teria 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 WesternUnited States, Final Report, March 1980.

Dames & Moore, Analysis of Federal Coal Leases inMine Plans in Colorado, New Mexico, andUtah, final draft report, December 1980.

Karen L. Larsen and Nancy Greenebaum, Reviewof Undeveloped Federal Coal Leases in Utah:Results of Utah Coal Leasing Task Force, FinalReport, May 1980. (Includes: Frank Hachman,“Market Factors Associated With the Assess-ment of the Development Potential of FederalCoal Leases in Utah, Draft Report” [Universi-ty of Utah, Bureau of Economic and BusinessResearch), May 1980,)

Jack C, Schmidt, Sanna Porte, and Arnold J.Silverman, A Review of Current Productionand Anticipated Future Production on FederalMines and Selected Undeveloped Lease Blocksin Montana and Wyoming, Final Report (Geo-services West), December 1981.

Martin E. Zeller, Karen L. Larsen, Iris A. Good-man, The Development Prospects for FederalCoal Leases in Colorado, 1980-1991, Final Re-port, November 1981. (Includes: Joan E. Mar-tin for Colorado Energy Research Institute,“Market Factors and Production Contingen-cies Determining the Present and Future De-mand for Colorado Coal, ” final draft report,December 1980.)

o

473