United States
Environmental Protection
Agency
Office of
Research and Development
Washington. D.C. 20460
EPA-600/7-76-004b
July 1976
IMPACTS OF SYNTHETIC
LIQUID FUEL DEVELOPMENT
Automotive Market
.Volume II
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S.
Environmental Protection Agency, have been grouped into seven series.
These seven broad categories were established to facilitate further
development and application of environmental technology. Elimination
of traditional grouping was consciously planned to foster technology
transfer and a maximum interface in related fields. The seven series
are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from
the effort funded under the 17-agency Federal Energy/Environment
Research and Development Program. These studies relate to EPA's
mission to protect the public health and welfare from adverse effects
of pollutants associated with energy systems. The goal of the Program
is to assure the rapid development of domestic energy supplies in an
environmentally—compatible manner by providing the necessary
environmental data and control technology. Investigations include
analyses of the transport of energy-related pollutants and their health
and ecological effects; assessments of, and development of, control
technologies for energy systems; and integrated assessments of a wide
range of energy-related environmental issues.
This document is available to the public through the National Technical
Information Service, Springfield, Virginia 22161.
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Final Report EPA-600/7-76-004B
May 1976
IMPACTS OF SYNTHETIC LIQUID FUEL DEVELOPMENT
Automotive Market
Volume II
by
Edward M. Dickson, Robert V. Steele, Evan E. Hughes, Barry L. Walton,
R. Allen Zink, Peter D. Miller, John W. Ryan, Patricia B. Simmon,
Buford Holt, Ronald K. White, Ernest C. Harvey, Ronald Cooper,
David F. Phillips (Consultant), Ward C. Stoneman (Consultant)
Stanford Research Institute
Menlo Park, California 94025
Contract No. 68-03-2016
SRI Project EGU-3505
Project Officer:
Gary J. Foley
Office of Energy, Minerals, and Industry
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
Prepared for:
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
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DISCLAIMER
This report has been reviewed by the Office of Energy, Minerals,
and Industry, U.S. Environmental Protection Agency, and approved for
publication. Approval does not signify that the contents necessarily
reflect the views and policies of the U.S. Environmental Protection
Agency, nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
ii
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CONTENTS
LIST OF FIGURES xv
LIST OF TABLES xxi
1. PROLOGUE TO VOLUME II 1
A. Introduction 1
B. Objectives 2
C. Study Approach 3
D. Basic Information 5
E. Critical Factors 5
F. Complementing Work 6
G. Applicability : 6
2. AUTOMOTIVE FUEL SUPPLY AND DEMAND FORECASTS 8
References . . . 21
Appendix 22
3. REFERENCE SUPPLY CASE 24
A. Introduction 24
1. Content of Reference Case 24
2. Scenarios: Bases for Projections of Supply
and Demand ....... 25
3. Summary of Conclusions 28
B. Projected Domestic Oil Supply and Imported Oil
Requirements 30
C. Projected Resource Requirements for Production
of Domestic Oil 37
1. Drill Rigs, Labor, and Steel 37
2. Capital Investment 42
iii
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D. Projected Environmental Impacts 47
1. Impact Scaling Factors 48
a. Crude Oil Production 48
b. Crude Oil Distribution and Oil Imports. . . 56
c. Refineries 60
2. Environmental Impacts. .... 65
a. Onshore Production 65
b. Alaska Production 70
c. Offshore Production with Attendant
Transport and Refining Operations 75
APPENDICES
A. QUANTITIES OF OIL RESOURCES AND RESERVES 85
B. METHOD FOR HG3 REGIONAL SUPPLY PROJECTION 90
C. TRENDS IN PAST U.S. PRODUCTION AND THEIR
IMPLICATIONS FOR FUTURE PRODUCTION 93
1. A Brief History of U.S. Oil Production
and Oil Exploration 93
2. A Brief History of U.S. Crude Oil
Supply and Demand 98
REFERENCES 102
4. SYNTHETIC LIQUID FUELS: THE TECHNOLOGY, RESOURCE
REQUIREMENTS, AND POLLUTANT EMISSIONS 106
A. Introduction and Overview 106
B. Discussion of Technologies Ill
1. Liquid Fuels from Coal Ill
a. Extraction Ill
b. Conversion. 112
c. Distribution 123
2. Oil Shale 127
a. Extraction 127
b. Conversion 128
c. Distribution 135
iv
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C. Material and Energy Flow 138
1. Energy Efficiency 139
a. Methanol from Coal 139
b. Syncrude from Coal 142
c. Syncrude from Oil Shale . 143
2. Resource Consumption 147
a. Coal and Oil Shale 148
b. Water 149
c. Land 152
d. Labor 155
e. Steel 157
f. Other . .- 158
3. Byproducts and Residuals 160
a. Saleable Byproducts 162
b. Solid Waste 163
c. Effluents to Water 165
d. Effluents to Air 170
e. Trace Elements 173
4. Costs and Dollar Flows 177
a. Investment and Operating Costs 177
. b. Dollar Flow for Plant Construction
and Operation 180
REFERENCES 184
5. NET ENERGY ANALYSIS OF SYNTHETIC LIQUID FUELS
PRODUCTION 187
A. Introduction 187
B. Methodology . . 191
C. Analysis of Synthetic Fuel Processes 198
1. Coal Liquefaction (H-Coal Process) 198
2. Methanol from Coal 200
3. Oil Shale 205
D. Coal-to-Refined Products System 207
E. Summary 211
REFERENCES 214
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6. MAXIMUM CREDIBLE IMPLEMENTATION SCENARIO FOR
SYNTHETIC LIQUID FUELS FROM COAL AND OIL SHALE 210
A. Introduction 216
B. Implementation Schedule 216
C. Comparison with the National Academy of
Engineering Scenarios 219
D. Scenarios and Scaling Factors 221
E. Resources 227
REFERENCES 229
7. LEGAL MECHANISMS FOR ACCESS TO COAL AND OIL SHALE .... 230
A. Introduction: Principles 230
B. Federal Lands 234
1. Licenses 242
2. Permits 244
3. Leases 247
4. Federal Requirements in Pricing ........ 260
C. Indian Lands 260
D. Access to Oil Shale on Public Lands 265
E. Summary of Federal Oil Shale Leases 268
F. State Lands 274
1. Colorado 274
2. Montana 277
3. Wyoming 278
4. West Virginia 281
G. Vetoed Strip Mine Act 282
H. Existing Environmental Regulations 294
I. State Reclamation Statutes and Regulations 301
J. Other Regulations 301
VI
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8. FINANCING THE SYNTHETIC LIQUID FUELS INDUSTRY BY
THE U.S. CAPITAL MARKETS 302
A. Introduction 302
B. Outlook for Total Business Fixed Investment and
Other Related Macroeconomic Variables 303
C. Investment in the Energy Industry 306
D. Capital Availability in the Petroleum Industry . . . 311
E. Conclusions 316
APPENDICES
A. PROJECTIONS OF GNP, AND SOURCES AND USES OF FUNDS. . 318
B. PROJECTIONS OF CAPITAL INVESTMENT IN THE OIL AND
GAS INDUSTRY 328
C. PROJECTIONS OF CASH FLOW FOR THE PETROLEUM AND
GAS INDUSTRY 333
REFERENCES 341
/<
9. MARKET PENETRATION OF SYNTHETIC LIQUID FUELS--
KEY ROLE OF THE DECISION-MAKING PROCESS LEADING
TO DEPLOYMENT 342
A. Introduction 342
B. Synthetic Liquid Fuels and the Natural
Petroleum System 342
C. Common Misconceptions About the Petroleum Industry . 347
D. Example of the Decision-Making Process 349
E. Comparison of the Risks 354
F. Comparison of the Economic Risk 358
G. The Decision-Making Climate for Synthetic Liquid
Fuels 362
REFERENCES 363
vii
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10. GOVERNMENT POLICIES TO ENCOURAGE THE PRODUCTION OF
SYNTHETIC LIQUID FUELS 364
A. Introduction 364
B. Required Features of Federal Policy 365
C. Incentive Policy Options 366
1. Removal of Constraints 367
2. Tax Incentives 368
3. General Price Support 370
4. Special Price Supports 371
5. Government Participation 374
a. Government Ownership 374
b. Grants-in Aid 376
c. Loan Guarantees 377
D. Conclusions 379
REFERENCES 382
11. NATIONAL ECONOMIC IMPACTS OF THE SYNTHETIC FUELS
INDUSTRY 383
A. Introduction 383
B. Interindustry Relationships 384
C. Materials and Purchased Services Used by the
Coal Industry 387
1. MEC Task Force Projections 387
2. Overview 393
D. Conversion Facilities 394
E. Transportation 395
1. Railroad Equipment 396
2. Coal Slurry Pipelines 398
F. Geographical Distribution Sectors Supplying
Synthetic Liquid Fuels Industry 398
1. Mining and Construction Equipment 398
2. Explosives 400
3. Railroad Equipment 400
4. Steel 401
5. Summary 402
viii
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APPENDIX
A ESTIMATION OF DEMAND FOR WALKING DRAGLINES 404
REFERENCES 407
12. ECONOMIC IMPACTS IN RESOURCE DEVELOPMENT REGIONS 408
A. Introduction 408
B. Regional Employment Growth 410
1. Background Theory 410
2. Population Estimates for Coal Development . . . 410
3. Coal-Related Development in Campbell
County, Wyoming 411
4. Oil Shale Development in the Piceance
Basin, Colorado 415
C. Comparisons With Other Resource Regions 418
1. North Dakota Lignite 418
2. Appalachian Coal Development 419
3. Southern Illinois Coal Region 421
D. Overview 423
REFERENCES 425
13. COMPARATIVE ENVIRONMENTAL EFFECTS OF COAL
STRIP MINING 427
A. Introduction 427
B. Mining and Environmental Effects 430
1. Appalachia 430
2. Midwest and West 436
3. Summary . 440
C. Reclamation Potential 441
1. Introduction 441
2. Appalachia 441
3. Midwest 446
4. West 446
5. Summary 450
REFERENCES CITED 452
OTHER REFERENCES 453
ix
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14. OIL SHALE MINING AND SPENT SHALE DISPOSAL 455
A. Introduction 455
B. Oil Shale Mining 456
1. Underground Mining 456
2. Surface Mining 458
C. Spent Shale Disposal 460
D. Environmental Problems 462
1. Mining 462
2. Spent Shale Reclamation 463
REFERENCES 465
15. REGION SPECIFIC BIOLOGICAL IMPACTS OF RESOURCE
DEVELOPMENT 466
A. Powder River Basin 466
B. Piceance Basin 476
C. North Dakota Coal Fields 484
D. Illinois Coal Fields 489
E. Appalachian Coal Field 496
REFERENCES 503
16. AIR POLLUTION CONTROL FOR SYNTHETIC LIQUID FUEL PLANTS. . 507
A. Introduction 507
B. Synthetic Liquid Fuel Plants: Processes and
Emissions of Air Pollutants 512
1. Syncrude from Oil Shale 512
a. Control of Emissions 515
b. Options for Further Control . 521
c. Other Processes 522
2. Syncrude from Coal 522
a. Control of Emissions 522
b. Options for Further Control 526
c. Other Processes 527
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3. Methanol from Coal 528
a. Control of Emissions 529
b. Options for Further Control 532
4. Summary 532
C. Atmospheric Dispersion Modeling 532
1. General Principles 533
2. Modeling a TOSCO II Oil Shale Plant 536
a. Characterization of Emission Source .... 536
b. Characterization of Oil Shale Region. . . . 536
c. Results of Dispersion and Site Modeling . . 540
3. Modeling an H-Coal Syncrude Plant 549
a. Characterization of Emission Sources. . . . 550
b. Characterization of Powder River
Coal Region 550
c. Results of Dispersion Modeling 554
4. Effects of Multiple Plants in a Region 560
5. Sensitivity Analysis. . . .' 566
D. Control Requirements 575
1. Conclusions 579
2. Recommendations 581
REFERENCES 534
17. SECONDARY ENVIRONMENTAL IMPACTS FROM URBANIZATION .... 586
A. Sources of Secondary Environmental Impacts 586
B. Urban Growth: Coal and Oil Shale Regions of
the West . . . 586
C. Quantifiable Impacts 587
1. Scaling Factors 587
2. Water-Related Impacts 591
3. Air Quality Impacts 597
D. Nonquantifiable Impacts. 597
E. . Summary 602
REFERENCES 604
xi
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18. HEALTH ISSUES IN SYNTHETIC LIQUID FUELS DEVELOPMENT . . . 606
A. Introduction 606
B. Effects of Industrial Development in New Areas . . . 606
C. End Use Impacts 608
D. Localized and Occupational Health Problems 609
E. Research Needs 611
REFERENCES 613
19. WATER AVAILABILITY IN THE WESTERN UNITED STATES 614
A. Introduction 614
B. Water Rights and the Federal Government 616
1. Scope of Federal Water Rights 616
2. Federal Power over Navigable Streams 618
3. Federal Properietary Water Rights 619
4. Summary of Federal Water Power 622
5. Federal Reserved Land in the Oil Shale Region . 622
6. Implications of the Federal Power 623
7. Attempts at Resolution 624
8. The Mexican Treaty of 1944 629
9. The Federal Government as a Disburser of Water. 633
10. Indian Claims to Western Water 639
a. The Problem 639
b. Theory of Indian Water Rights 641
c. Measurement of Indian Water Rights 644
d. Relation of Indian Water Rjghts to
Water Rights Administered Under
State Law 645
e. Scope of the Problem 646
f. Conclusions . 647
C. Interstate Allocation of Water 649
D. State Systems for Water Allocation in the West . . . 658
1. General Systems 658
2. The Need for Certainty of Water Rights 660
3. Transfer of Water Rights 663
4. Interbasin Transfers 665
5. Conditional Decrees 666
6. Public Interest in Water 667
Xll
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7. Pricing of Water 670
8. Ground Water 672
9. State Action Generally 676
E. Water Requirements for Coal and Oil Shale
Development 677
F. Coal Transport: Pipeline versus Rail 696
1. Coal Slurry Pipelines 697
2. Railroad Transport of Coal 699
3. Critical Factors 700
4. Eminent Domain for Pipeline Right-of-Way. . . . 703
5. Railroad Opposition to Pipelines 704
6. Pipeline Regulation 706
7. Pipeline Impact on Railroads 706
8. Proposed Resolution 707
G. Summary 712
REFERENCES 718
20. WATER AVAILABILITY IN THE EASTERN UNITED STATES 730
A. Introduction ' 730
B. Water Requirements 731
C. Water Supply 736
1. Illinois 736
2. Kentucky 737
3. West Virginia 739
D. Legal Aspects of Water Availability 740
1. Riparian Law 740
2. Position of the States 744
E. Federal Programs that Relate to Water Resource
Development in the East 753
REFERENCES 758
21. THE IMPACT OF INDUSTRIAL GROWTH ON RURAL SOCIETY 759
A. Introduction 759
B. .Interest Groups 763
1. Local Government. 763
2. State Government 766
xiii
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3. Federal Government 767
4. Ranchers and Farmers 770
5. Workers and Other Residents 772
6. Businessmen 772
7. New Employees and Other Newcomers 773
8. The Energy Industrialists 774
9. Environmentalists 775
10. Energy Consumers 777
C. Dynamics of Urban Growth Related to Public
Expenditure 777
1. Stages of Urban Growth 778
2. Population Growth and Per Capita Costs 783
3. Growth and Revenue 786
4. Tax Lag 789
D. Policy Options for Controlled Growth Rates 792
1. Nonfiscal Options 792
2. Fiscal Options 795
REFERENCES 797
22. POPULATION GROWTH CONSTRAINED SYNTHETIC LIQUID FUEL
IMPLEMENTATION SCENARIOS 800
23. COMPARATIVE IMPACTS OF CONTROLLED AND UNCONTROLLED
URBANIZATION 813
A. Introduction 813
B. Impact of the Maximum Credible Level of
Synthetic Fuel Production 814
C. Development Constrained by a 5 Percent Annual
Growth Rate 817
D. A 5 Percent Growth Rate in Campbell County 825
E. The Maximum Credible Level of Oil-shale Mining
and Retorting Piceance Basin 830
F. Oil Shale Development by a 5 Percent Annual
Growth Rate—Piceance Basin 833
G. Implications for Appalachia 834
H. Implications for Southern Illinois 836
I . Summary 837
REFERENCES 840
xiv
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FIGURES
2-1 Automotive Energy Demand Compared to 1974
Petroleum Supply and Demand
2-2 Automotive Energy Demand Compared to Total
U.S. Energy Demand 10
2-3 Historical Growth Scenarios-Automotive Fuel
Demand and Domestic Supply Projections 16
2-4 Technical Fix Scenario-Automotive Fuel Demand
and Domestic Supply Projections 17
2-5 Zero Energy Growth Scenario-Automotive Fuel
Demand and Domestic Supply Projections 18
3-1 Reference Case Petroleum Fuel System 26
3-2 Index Map of North America Showing the Boundaries
of the 15 Oil Production Regions Onshore
and Offshore 31
A-l Diagramatic Representation of Petroleum Resource
Classification by the U.S. Geological Survey
and the U.S. Bureau of Mines 86
A-2 Comparative Estimates of Oil Resources in the
United States 88
C-l Proved Reserves of Crude Oil in the United States,
1945-1974 96
C-2 1973 Crude Oil Production from 228 Major Domestic
Oilfields by Year of Discovery 97
4-1 Synthetic Fuels Network 108
4-2 Production of Methanol From Coal 116
4-3 Coal Liquefaction Via Dissolution and
Hydrogenation 120
4-4 Crude Oil Pipeline Network 124
4-5 Oil Retorting and Upgrading 134
4-6 Existing Crude Oil Pipelines in Relation to Oil
Shale Areas 136
xv
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4-7 Methanol From Coal Energy Balance 140
4-8 H-Coal Liquefaction Process Energy Balance 144
4-9 TOSCO II Oil Shale Retorting and Upgrading
Energy Balance 145
4-10 Typical Construction Labor Profile for Large
Proposed Fuel Conversion Projects 156
4-11 River Water Utilization
(50,000-B/D TOSCO II Oil Shale Plant) 166
4-12 Emissions of Air Pollutants From Synthetic Fuels
Production 181
4-13 Concentration of Toxic Trace Elements in Oil Shale. . 183
5-1 Flow Diagram for Definition of Net Energy Ratio . . . 189
5-2 Annual Energy Inputs for Construction and Operating
a 5 Million Ton/Year Surface Coal Mine in the
Southwestern United States 195
5-3 Annual Energy Inputs for Construction and Operation
of a 100,000-B/D H-Coal Process Coal Liquefaction
Plant 199
5-4 Annual Energy Inputs for Construction and Operation
of an 81,433-B/D Coal-to-Methanol Plant 202
5-5 Annual Energy Inputs for Construction and Operation
of a 50,000-B/D Oil Shale Mining, Retorting, and
Upgrading Complex 204
5-6 Annual Energy Inputs for Converting Western Surface-
Mined Coal to Refined Products in the Midwest .... 209
7-1 Mechanisms of Legal Access to Mineral Estates .... 235
8-1 Projected Cash Flow for Domestic Oil and Gas
Industry—No Synthetic Liquid Fuels—at a Zero
Rate of Annual Inflation 312
8-2 Projected Cash Flow for Domestic Oil and Gas
Industry—Conventional Activities Plus Synthetic
Liquid Fuels—at a Zero Rate of Annual Inflation. . . 312
8-3 Projected Cash Flow for Domestic Oil and Gas
Industry—No Synthetic Liquid Fuels—at a Five
Percent Annual Rate of Inflation 314
xvi
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8-4 Projected Cash Flow for Domestic Oil and Gas
Industry—Conventional Activities Plus Synthetic
Liquid Fuels—at a Five Percent Annual Rate of
Inflation 314
8-5 Projected Cash Flow for Domestic Oil and Gas
Industry—No Synthetic Liquid Fuels—at an Eight
Percent Annual Rate of Inflation 315
8-6 Projected Cash Flow for Domestic Oil and Gas
Industry—Conventional Activities Plus Synthetic
Liquid Fuels—at an Eight Percent Annual Rate
of Inflation 315
9-1 Synthetic Liquid Fuels Production System 343
9-2 Natural Petroleum Products Production System 343
9-3 Early 1973 Perception of a Hypothetical Syncrude
Plant Beginning to Produce in 1973 350
9-4 Early 1973 Perception of a Syncrude Plant
Brought on Stream in 1980 350
9-5 Early 1973 Perception of the 19851 Status of a
Syncrude Plant Brought on Stream in 1980 350
9-6 Late 1973 Perception of the Hypothetical Syncrude
Plant Producing in 1973 350
9-7 Mid-1974 Perception of a Hypothetical 1974
Syncrude Plant, After Examination of Investment
Costs 350
9-8 Late 1974-Early 1975 Perception of Syncrude
Plant on Stream in 1980 350
11-1 Future Coal Production Levels for Project
Independence Scenarios and the SRI Maximum
Credible Implementation Scenario 388
11-2 Primary Concentration of Major Industrial Sectors
Expected to Supply the Coal and Oil Shale Industry. . 403
12-1 Counties Used for Economic Impact Discussions .... 409
13-1 Northern Great Plains Province 428
13-2 Interior Province 428
13-3 Eastern Provice 428
xvii
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13-4 Typical Cross-section (Dents Run Watershed,
Monongalia Co., W. Virginia 431
13-5 Diagram of a Contour Mine 432
13-6 Contour Strip Mining 432
13-7 Auger Hole Section and Spacing 433
13-8 Diagram of Area Mine 437
13-9 Area Strip Mining with Concurrent Reclamation .... 437
13-10 Perspective of Typical Mining Facilities,
Haulage Roads, Pit Operation, and Reclamation .... 439
13-11 Strip Mined Terrain 439
13-12 Modified Block Cut 442
13-13 Box-Cut Mining 444
13-14 Some Land Reclamation Techniques for
Contour Mining 445
13-15 Reclamation Potential 451
14-1 Room-and-Pillar Mining Concept 459
14-2 Schematic Open Pit Development 461
15-1 Natural Land Units of the Powder River 469
15-2 Vegetation of the Piceance Basin 479
15-3 Illinois Coal Basin 491
16-1 TOSCO II Plant Configuration 538
o
16-2 Annual Average Particulate Concentration ( g/m )
for a TOSCO II Oil Shale Plant Using Grand
Junction, Colorado Meteorology 541
16-3 24-Hour Worst Case Average Particulate Concentration
( g/m3) for a TOSCO II Oil Shale Plant Under
Conditions of Neutral Stability and a West Wind
of 1.5 m sec"1 542
o
16-4 Annual Average SO Concentration ( g/m ) for a
TOSCO II Oil Shale Plant Using Grand Junction,
Colorado Meteorology 543
16-5 24-Hour Worst Case Average SO Concentration
( g/m3) for a TOSCO II Oil Shlle Plant under
Conditions of Neutral Stability and a West Wind
of 1.5 m sec"1 544
xviii
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16-6 Stack Configuration for Coal Liquefaction Plant . . . 552
16-7 Worst Case 24-Hour Average Particulate
o
Concentrations ( g/m ) for a Coal Liquefaction
Plant 556
16-8 Annual Average SO Concentrations ( g/m3) For a
Coal Liquefaction Plant 557
16-9 Worst Case 24-Hour Average Particulate
Concentrations ( g/m3) for a Complex of Coal
Liquefaction Plants 562
16-10 Annual Average SO Concentrations ( g/m3) for a
Complex of Coal Liquefaction Plants 563
19-1 Indian Reservations in the Coal-and Oil-Shale-
Rich Regions of the West 640
19-2 Crow Indian Newspaper Announcement 642
19-3 Coal Development Alternatives, In-state and
Out-of-state 678
19-4 Historic Yellowstone River Basin Flows 686
s
19-5 Major Potential Delivery Systems, Northern Great
Plains Coal Resource Region 688
19-6 Coal Deposits in Relation to Transportation
Facilities. . 708
19-7 Economics of Coal Slurry Transportation 710
20-1 Water Resource Regions of the United States 732
20-2 Subareas for the 1975 Water Assessment 733
21-1 Public Investment Compared to Demand for Public
Services 779
21-2 "Boom" Construction and its Echo Effect
Contrasted with Flat-Age-Profile Construction .... 781
21-3 Major Investments and Decisions vs. Population
Growth for an Urbanizing Small Town 782
21-4 Correlation of Government Expenditures to
Population 785
22-1 Total Population Associated with Individual Plant
Construction and Operation Building Blocks 803
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22-2 Effects of the Maximum Credible Implementation
Scenario Upon Population in Campbell County,
Wyoming 804
22-3 Five Percent Constrained Population Growth
Rate Scenario for Campbell County, Wyoming
Illustrated with Coal Liquefaction Plants and
Associated Mines 805
22-4 Modified Five Percent Constrained Population
Growth Scenario for Campbell County, Wyoming
Illustrated with Coal Liquefaction Plants and
Associated Mines 806
22-5 Five Percent Constrained Population Growth
Scenario for Campbell County, Wyoming
In Which Coal Mines are Developed 807
22-6 Five Percent Constrained Population Growth
Scenario for Campbell County, Wyoming
Illustrated with Coal to Methanol
Conversion Plants 808
22-7 Five Percent Constrained Population Growth
Scenario for Campbell County, Wyoming
Illustrated with Coal to Methanol Conversion
Plants with Extended (5 Year) Construction Periods. . 809
22-8 Five Percent Constrained Population Growth
Scenario for Oil Shale Development in Garfield
and Rio Blanco Counties, Colorado 810
22-9 Ten Percent Constrained Population Growth
Scenario for Oil Shale Development in Garfield
and Rio Blanco Counties, Colorado 811
22-10 Maximum Credible Implementation Scenario for
Oil Shale Development in Garfield and Rio Blanco
Counties, Colorado. . 812
23-1 Growth Rates are Highest Near the Center of
Activity and Fall Off With Distance 822
23-2 Basis of Population Multiplier Concept 824
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TABLES
2-1 Gasoline Prices and Fuel Cost per Mile 1950-74. ... 11
2-2 Projected Annual Fuel Consumption by Sector 14
2-3 Oil Supply Projections 19
A-l Fuel Price Assumptions 23
A-2 Projected Automotive Fuel Demand for Constant and
Rising Prices 23
3-1 Conventional Domestic Oil Supply Projections 27
3-2 Domestic Oil Supply, Imports, and Total Demand
Under HG3 32
3-3 Onshore Oil Production from the Lower 48 States
Under HG3 34
/
3-4 Offshore Oil Production from the Lower 48 States
Under HG3 35
3-5 Onshore and Offshore Oil Production from Alaska
Under HG3 . 36
3-6 Labor, Drill Rig and Steel Requirements for Oil
Production Under HG3 38
3-7 Capital Investment Required for Secondary and
Tertiary Recovery 43
3-8 Approximate Capital Investment Required for
Onshore, Offshore, and Alaska Oil Production
by Advanced Recovery Techniques 45
3-9 Capital Investment in Conventional Oil
Production for HG3 46
3-10 Impact Scaling Factors for Normal Exploration
Operations 50
3-11 Impact Scaling Factors for Exploration
Accidents (Blowouts) 53
3-12 Impact Scaling Factors for Normal Production
Operations 55
xxi
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3-13 Impact Scaling Factors for Production
Accidents 57
3-14 Impact Scaling Factors for the Pipeline
Distribution System 59
3-15 Impact Scaling Factors for Normal Tanker
Operations 61
3-16 Impact Scaling Factors for Trans-Alaska
Pipeline Storage Terminal and Deepwater
Terminal 62
3-17 Impact Scaling Factors for Crude Oil
Pipelines and Tanker Accidents 63
3-18 Scaling Factors for Resource Requirements
for 106-B/D Refinery Capacity 64
3-19 Impact Scaling Factors for 10s -B/D Refinery
Capacity 66
3-20 Environmental Impacts from Onshore Oil Production
Under the Reference Case 67
3-21 Environmental Impacts in Alaska Under the
Reference Case 71
3-22 Environmental Impacts from Offshore Development
and Tanker Operations Under the Reference Case. ... 76
3-23 New Refinery Requirements for Reference Case
Over and Above 1975 Refinery Capacity (Imports
are Crude Oil Only) 80
3-24 New Refinery Requirements for Reference Case
Over and Above 1975 Refinery Capacity (50 Percent
of Imports are Refined Products) 81
3-25 Environmental Impacts from the Operation of New
Refineries Under the Reference Case 82
B-l Historical Growth Subscenario 3—Regional Supply
of Oil and Natural Gas Liquids 92
C-l Historical Record of Production and Proven Reserves:
Also the Ultimate Recovery and Original Oil in Place
by Year of Discovery—Total United States for
Selected Years 94
C-2 Statistics of the Petroleum Industry 99
xxii
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C-3 Oil Prices 101
4-1 Building Block Sizes in the Synthetic Liquid
Fuels Production System 137
4-2 Coal-to-Methanol Energy Requirement 142
4-3 Coal-to-Syncrude Energy Requirement 146
4-4 Oil Shale-to-Syncrude Energy Requirement 147
4-5 Annual Coal and Oilshale Requirements for 100,000-B/D
Synthetic Plants 150
4-6 Annual Water Requirements for a 100,000-B/D Oil
Shale Mining, Retorting, and Upgrading Operation. . . 151
4-7 Average Land Area Disturbed per Million Tons of
Coal Recovered 153
4-8 Catalyst and Chemical Requirements for a
100,000-B/D Oil Shale Retorting and Upgrading
Plant 161
4-9 Byproducts from a 100,000-B/D Coal-to-Methanol
Plant (Western Coal) 162
4-10 Coal Liquefaction Plant Biological Treating
Pond Water Effluent 168
4-11 Composition of Waste Water Used in Spent
Shale Moisturizing 170
4-12 Capital Investment Dollar Flows for H-Coal
Liquefaction Plant 172
4-13 Operating Dollar Flows for Western Coal
Liquefaction via the H-Coal Process (Basod
on 15% DCF Return on Investment and Cost of
Coal at $3.00/ton) 174
4-14 Mean Trace Element Concentrations (ppm, Moisture
Free) of Various Coals 175
4-15 Cost Estimates for Synthetic Liquid Fuels
(1973 Costs) 178
5-1 Factors for Converting Energy Content of
Purchased Fuels or Electricity into Resource
Energy 192
5-2 Energy Inputs for Construction of a 5-Million
Ton/Year Surface Coal Mine 197
xxiii
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5-3 Annual Energy Inputs and Output for a 5-Million
Ton/Year Surface Coal Mine 197
5-4 Annual Energy Inputs and Output for a 100,000-B/D
Coal Liquefaction Plant 201
5-5 Annual Energy Inputs and Output for an
81,000-B/D Coal-to-Methanol Plant 205
5-6 Annual Energy Inputs and Output for a 50,000-B/D
Oil Shale Mining, Retorting, and Upgrading Complex. . 207
5-7 Annual Energy Inputs and Output for a Coal-to-Refined
Products System (Based on a 100,000-B/D Coal
Liquefaction Plant) 210
5-8 Summary of Net Energy Calculations for
Synthetic Liquid Fuels 212
6-1 Hypothesized Growth Schedule of Synthetic
Liquid Fuels Industry 217
6-2 Maximum Possible Production of Synthetic
Liquid Fuels in 1985: NAE and SRI Projections .... 219
6-3 Hypothesized Locations of Plants for Producing
Synthetic Liquid Fuel from Coal 222
6-4 Syncrude from Coal: Maximum Credible
Implementation Scenario 223
6-5 Syncrude from Oilshale: Maximum Credible
Implementation Scenario 224
6-6 Methanol from Coal: Maximum Credible
Implementation Scenario 225
6-7 Surface Coal Mines Needed for Syncrude Plus
Methanol Production 226
6-8 States and Regions with Strippable Coal Reserves
Sufficient to Support a Large Synthetic Fuels
Industry 228
7-1 Environmental Stipulations to Prototype
Federal Oilshale Leases 273
8-1 Sources and Uses of Funds—1973 304
8-2 Projected Sources and Uses of Funds 305
8-3 Projections to 2000 of Capital Investment in U.S.
Domestic Energy Industry Under Historical Growth:
Billions of 1973 Dollars 307
xxiv
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8-4 Capital Expenditures for Energy Industry
Compared to Total U.S. Business Fixed
Investment Under Historical Growth 309
8-5 Capital Investment in U.S. Domestic Energy
Industry for Technical Fix Scenario (Excluding
Synthetic Fuels) 310
A-l Gross National Product—Historical and
Projections to 2000 319
A-2 Sources of Funds—Historical Data and
Projections to 2000 320
A-3 Business Fixed Investments—Historical and
Projections to 2000 322
A-4 Residential Construction—Historical and
Projections to 2000 324
A-5 Selected Uses of Funds—Historical and Projections
to 2000 326
B-l Energy Industry Investment for 1975, 1980,
and 1985 for HG1 , 329
B-2 Energy Supply Scenarios 331
B-3 Investment Requirements for Synthetic Fuels
Under the Maximum Credible Implementation Scenario. . 332
C-l Annual Investment Schedule for HG1 337
C-2 HG1 Cash Flow—No Inflation 338
C-3 HG1 Cash Flow—5 Percent Annual Inflation 339
C-4 HG1 Cash Flow—8 Percent Annual Inflation 340
9-1 Assets of Selected Major Oil Companies,
December 31, 1973 358
9-2 Offshore Leases in the Destin Area off
Florida's Panhandle 359
9-3 Group Participation in Oil Shale Leases and
Ventures 361
11-1 Economic Sectors Providing Inputs to the Coal
Mining Sector, Ranked by Size of 1967 Total
Requirement Coefficient 385
11-2 Projected Steel Availability 391
XXV
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11-3 Cumulative Demand and Supply Estimates for
Locomotives and Hopper Cars to 1985 (Project
Independence Base Case) 396
11-4 Employment in Construction and Mining
Equipment Industries by State, 1972 399
A-l Estimation of Dragline Production 1975-1990 406
12-1 Population in Colorado Oil Shale Region, 1970 .... 416
12-2 Population and Coal Production in Selected
Counties of Southern Illinois 422
16-1 Ambient Air Quality Standards 513
16-2 Electric Power Generation Emissions
Attributable to a TOSCO II Oil Shale
Processing Plant 516
16-3 Particulate Emissions for TOSCO II Oil Shale
Processing Plant 517
16-4 SO Emissions for TOSCO II Oil Shale Processing
Plant 518
16-5 NO Emissions for TOSCO II Oil Shale Processing
Plant 519
16-6 Characteristics of Representative Western and
Eastern Coals 523
16-7 Emissions for H-Coal Liquefaction of Powder
River Coal 524
16-8 Emissions for H-Coal Liquefaction of Illinois Coal. . 525
16-9 Controlled Emissions for SRC and CSF Coal
Liquefaction Plants 527
16-10 Emissions for Sasol Methanol Plant Using
Manufactured Fuel Gas 530
16-11 Emissions for Sasol Methanol Using Coal Fuel 531
16-12 Summary of Emissions from Alternative Synthetic
Fuel Plants Employing Best Available Control 533
16-13 Stack Parameters and Emission Rates for a
16,000-m3/D (100,000-B/D) TOSCO II Plant With
Emissions Controlled 540
xxvi
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16-14 Control Requirements Based on Federal Primary and
Colorado Air Quality Standards and Emissions From
a 16,000-m3/day (100,000 B/D) TOSCO II Plant,
Controlled 545
16-15 Control Requirements Based on Federal Secondary,
Class I and Class II Air Quality Standards and
Emissions From a 16,000-m3/day (100,000-B/D)
TOSCO II Plant, Controlled 543
16-16 Stack Parameters and Emission Rates for a
16,000-m3/day (100,000-B/D) H-Coal Plant Using
Powder River Coal 551
16-17 Worst-Case Meteorological Sequence for
Moorcroft, Wyoming 555
16-18 Control Requirements Based on Federal Primary
and Wyoming Air Quality Standards and Emissions
From a 16,000-m3/day (100,000-B/D) Coal Syncrude
Plant 558
16-19 Control Requirements Based on Federal Secondary,
Class I and Class II Air Quality Standards and
Emissions From a 16„000-m3/day (100,000-B/D)
Coal Syncrude Plant 559
16-20 Control Requirements Based on Federal Primary and
Wyoming Air Quality Standards and Emmissions From
a Complex of Four 16,000-m3/day Coal Syncrude
Plants 564
16-21 Control Requirements Based on Federal Secondary,
Class I, and Class II Air Quality Standards and
«2
Emissions From a Complex of Four 16,000-m /day
Coal Syncrude Plants 565
16-22 Stack Characteristics That Result in Various
Buoyancy Flux Values (F Values) 563
16-23 Single Stack Sensitivity Analysis Results 569
16-24 Two Stack Sensitivity Analysis Results 571
16-25 Control Requirements Based on a Single
16,000-m3/day (100,000-B/D) Oil Shale Plant 577
16-26 Control Requirements Based on a Single
16,000-m3/day (100,000-B/D) Coal Liquefaction Plant . 577
xxvii
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16-27 Control Requirements Based on a Complex of Four
16,000-m3/day (100,000-B/D) Coal Liquefaction
Plants 578
16-28 Summary of Emissions and Control Requirements .... 580
17-1 Scaling Factors for Urban Living 588
17-2 Water Runoff Coefficient "c" and Rainfall in
Wyoming and Colorado 589
17-3 Average Emission Factors for Highway Vehicles
Based on Nationwide Statistics 590
17-4 Impacts for Campbell County, Wyoming, Coal
Liquefaction and Methanol Production-Maximum
Credible Implementation Scenario 592
17-5 Impacts for Garfield and Rio Blanco Counties,
Colorado, Oil Shale Development-Maximum Credible
Implementation Scenario 593
17-6 Automotive Pollution Impacts for Campbell County,
Wyoming, Coal Liquefaction and Methanol Production-
Maximum Credible Implementation Scenario 594
17-7 Automotive Pollution Impacts for Garfield and
Rio Blanco Counties, Colorado, Oil Shale Development-
Maximum Credible Implementation Scenario 595
17-8 Air Pollution From Automobiles and Oil Shale Plants . 598
19-1 Percentage of Federally-owned Land in Colorado,
Montana, and Wyoming 617
19-2 Flows and Allocations in the Colorado River and
the Rio Grande 631
19-3 Industrial Water Contracts, Bousen and Yellowtail
Reservoirs 635
19-4 Annual Water Consumption for Various Coal Uses. . . . 680
19-5 Upper Missouri River Basin Water Availability
and Depletions 681
I9-6 Projected Annual Consumptive Use of Water for the
Year 2000—Northern Great Plains States 682
19-7 Syncrude and Methanol Consumptive Water Demands
for the Year 2000 683
xxviii
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19-8 Major Reservoirs That Affect Stream Flows in the
Northern Great Plains 685
19-9 Summary of Industrial Water Resources for the
Upper Missouri River Basin 689
19-10 Projected Increase in Water Demand for the
Upper Colorado River Basin 692
20-1 Eastern United States Maximum Credible
Implementation Scenario Water Requirements in
the Year 2000 734
20-2 Future Water Demand Compared to Water Supply
in the Year 2000 735
20-3 Projected Water Consumption by Electricity
Generating and Synthetic Liquid Fuel Plants
in the Year 2000 736
xxix
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1—PROLOGUE TO VOLUME II
A. Introduction
This study has its roots in the realization that historical growth
in automotive fuel demand cannot be sustained, especially if the U.S.
intends to become increasingly self-reliant in energy. Unless fundamen-
tal reduction occurs in the demand for available fuels, the United States
will be unable to satisfy all of its requirements for petroleum products.
Since automotive vehicles consume about 46 percent of all petroleum used
in this country, the future vitality of the automotive sector is at stake.
There are several approaches to satisfying desires for energy in
general and petroleum products in particular?
• Conserve.
• Step-up domestic oil (and gas) production by increasing activity
in new areas.
• Import crude oil and refined products.
• Develop synthetic liquid fuels based on abundant domestic coal
and oil shale resources.
The last option is the focus of this study.
Two previous studies,^ commissioned by the Alternative Automotive
Power Systems Division of the U.S. Environmental Protection Agency,
*Cars, trucks, and buses.
tKant, F., et al., "Feasibility Study of Alternative Fuels for Automotive
Transportation," Environmental Protection Agency, Report EPA-460/3-74-009
(June 1974).
Pangborn, J., et al., "Feasibility Study of Alternative Fuels for Auto-
motive Transportation," Environmental Protection Agency, Report EPA-460/
3-74-012 (July 1974).
-------
explored the economic and technical feasibility of a wide range of candi-
date synthetic automotive fuels ranging from hydrogen through methanol
to gasoline. Various sources and production systems were considered.
Both studies concluded that the leading candidates for automotive fuel
for the future (1980 and beyond) were
• Coal-derived
- Gasoline
- Distillates
- Methanol
• Oil shale-derived
- Gasoline
- Distillates.
B. Objectives
The basic objective of this study is to determine the feasibility
of alternative automotive fuels production in a broader context—one that
includes the environmental, societal, and institutional ramifications of
synthetic fuels development. To provide a frame of reference in which
to view these consequences, the environmental impacts of stepped-up
domestic production and oil imports are also described. Both futures
are based on the presumption that energy use growth rates are slackening
as a result of increased conservation.
To achieve the basic objective, several general goals were set:
• Determine the impacts of a major deployment of synthetic liquid
fuels technology
• Prepare a scenario of the maximum possible rate of deployment
• Identify the critical impacts that might decide the question of
deployment, prove intolerable unless mitigated, or prove not to
be amenable to mitigation
-------
Identify governmental policies that might lessen or avoid ad-
verse impacts or enhance prospects for deployment of synthetic
fuels capability
Develop criteria on which to base comparison of alternative
synthetic fuels options.
C. Study Approach
The study was organized as a technology impact assessment. The
study core team consisted of a group of professionals with expertise in
chemistry, physics, economics, sociology, and law. For supplemental
expertise, the team drew on professionals in chemical engineering, meteo-
rology, and biology. The team received inputs from experts at SRI, the
staff of two coordinate contractors (Exxon Research and Engineering and
The Institute of Gas Technology), industry, universities, and stake-
holder groups. The EPA project officers maintained a close working
liaison with the team and participated in a major observation trip in
the field and many working sessions.
To facilitate the sharing of information within the team and review
by outside parties, intermediate findings were put in the form of working
papers. These working papers were revised to reflect subsequent findings,
improvements in information, criticism from reviewers, and stakeholder
inputs, and in their form revised the backbone chapters of Volume II.
The chapters are the following:
2. Automotive Fuel Supply and Demand Forecasts
3. Reference Supply Case
4. Synthetic Liquid Fuels: The Technology, Resource
Requirements, and Pollutant Emissions
5. Net Energy Analysis of Synthetic Liquid Fuels
Production
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6. Maximum Credible Implementation Scenario for
Synthetic Liquid Fuels from Coal and Oil Shale
7. Legal Mechanisms for Access to Coal and Oil Shale
8. Financing the Synthetic Liquid Fuels Industry
by the U.S. Capital Markets
9. Market Penetration of Synthetic Liquid Fuels—
The Key Role of the Decision-Making Process
Leading to Deployment
10. Government Policies to Encourage the Production
of Synthetic Liquid Fuels
11. National Economic Impacts of the Synthetic Fuels
Industry
12. Economic Impacts in Resource Development Regions
13. Comparative Environmental Inputs of Coal Strip Mining
14. Oil Shale Mining and Spent Shale Disposal
15. Region Specific Biological Inputs of Resource
Development
16. Air Pollution Control for Synthetic Liquid Fuel Plants
17. Secondary Environmental Inputs from Urbanization
18. Health Issues in Synthetic Liquid Fuels Development
19. Water Availability in the Western United States
20. Water Availability in the Eastern United States
21. The Impact of Industrial Growth on Rural Society
22. Population Growth Constrained Synthetic Liquid
Fuel Implementation Scenarios
23. Comparative Inputs of Controlled and Uncontrolled
Urbanization
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The following paragraphs describe the relationship of each chapter
to the study as a whole.
D. Basic Information
The study required certain basic information as inputs to other
analyses: (The relevant chapters are indicated by the number in
parentheses.)
• Domestic automotive fuel demand and supply projections from
1975 to 2000 within a consistent total energy balance for
the United States. (2)
• Projections of the (geographical) sources of future conventional
domestic oil supplies to serve as the basis for the reference
impact case. (3)
• Descriptions of synthetic fuels production processes, capital
investments, labor forces, materials requirements, etc. (4)
• Information on the locations and amounts of coal resources. (5)
• Understanding of the institutional structure of the automotive
fuels supply system. (9)
The study also required development of the following:
• Impacts description of the reference case for supplying con-
ventional crude oil. (3)
• An implementation scenario for synthetic liquid fuels at the
maximum rate of deployment that can be credibly imagined. (6)
• A description of how corporate stakeholders in the fuels indus-
try perceive the prospective synthetic fuels industry would mesh
with the existing system. (9)
E. Critical Factors
From the outset, information obtained from the literature and stake-
holders made it clear that the following factors were critical and they
were emphasized in the study:
-------
• Availability of water for energy development—especially in the
arid West. (19, 20)
• Strip mining practices and reclamation potential. (13, 14, 15)
• Mineral leasing procedures and constraints (since much of the
relevant resource is owned by the federal government). (7)
• Control of air pollution from mines and conversion facili-
ties. (16)
• Availability of capital for synthetic liquid fuels invest-
ments. (8)
• Transportation of coal between mines and liquefaction
plants. (19)
• Corporate decisions about whether and when to deploy synthetic
fuels. (9)
• The creation of boom towns in coal and oil shale regions—
especially in sparsely populated regions of the West—and the
effects of constraining growth. (21, 22, 23)
• Governmental incentives for synthetic liquid fuels produc-
tion. (10)
F. Complementing Work
To provide a complete picture and to complement the analysis, it
was necessary to prepare:
• Descriptions of the environmental impacts of urbanization spe-
cific to the most likely regions of expected synthetic fuels
activity. (17)
• National and regional economic descriptions of synthetic fuels
industry development. (11, 12)
• Impacts of deployment of synthetic fuels facilities at the
maximum credible rate. (8, 11, 12, 18, 19, 23)
G. Applicability
Although this study is oriented toward fuels for the automotive sec-
tor, many of the analyses in the following chapters have more general
applicability. The results of the analyses have equal relevance to
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understanding the consequences of strip mining for coal, of synthetic
gas production, and of water intensive industrial development of the
West.
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2--AUTOMOTIVE FUEL SUPPLY AND DEMAND FORECASTS
By Edward M. Dickson
This study is concerned with the development of synthetic liquid
fuels for the automotive market. Here the word automotive is taken to
include cars, trucks, and buses. Together, these vehicles consume about
46 percent of all petroleum used in the United States. Cars, of course,
account for the majority of this use—some 70 percent. Figures 2-1 and
2-2 place automotive fuel use in perspective, both as a proportion of
total energy use and as a proportion of total oil use.
There are many forecasts of future automotive fuel demand in the
2-9
literature, but few of them are based on anything more sophisticated
*
than simple trend extrapolation. Most, moreover, implicitly assume con-
stant energy prices (in real terms). This assumption is understandable
because, as shown in Table 2-1, between 1950 and 1973 the real price of
motor fuels remained essentially constant with even a slight downward
trend. Since the Arab oil embargo, however, it is no longer credible to
assume either constant petroleum prices or availability of supplies to
meet the desires of motorists. Consequently, interest has begun to focus
on synthetic liquid fuels.
* 10
One recent, more sophisticated projection is described in the appendix.
We use the word desires here rather than demand because, in the language
of economics, supply must equal demand in an equilibrium economyr but
desires may exceed supplies.
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AUTOMOTIVE CONSUMPTION
(75% OF ALL TRANSPORTATION
ENERGY REQUIREMENTS)
FIGURE 2-2. AUTOMOTIVE ENERGY DEMAND COMPARED
TO TOTAL U.S. ENERGY DEMAND
10
-------
Year
Table 2-1
GASOLINE PRICES AND FUEL COST PER MILE
1950-74
Source: Reference 10
Real Price (1967 dollars)
($/gal)
1950
1955
1960
1965
1970
1973
1974
0.37
0.36
0.35
0.33
0.31
0.29
0.35
Real Fuel Cost
($/Mile)*
0S0248
0.0250
0.0246
0.0234
0.0226
0.0223
0.02 71
•T-
Based on fuel economy of vehicles in operation.
Assumed 1973 fuel economy.
11
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To appreciate the quantity of synthetic liquid fuels that the U.S.
might wish to produce in the years ahead, a forecast of both supply and
demand is needed and these components must be coupled through a common
and realistic assumption about fuel price. In addition, over a long
period, such as 1980-2000, considerable interfuel competition could take
place, which could result in substantial fuel switching. Thus, it is
also necessary to use a forecast in which automotive use of petroleum
(or equivalent) products is but a portion of a total energy economy
balance.
Since construction of such a complete forecast was beyond the scope
of this study, we have chosen to adapt for our use the three supply and
demand scenarios of the Energy Policy Project of the Ford Foundation
because they were the only such forecasts publicly available for the time
11 *
frame 1980-2000. Although they are flawed, the Ford scenarios are suf-
ficient to indicate the general magnitude of the future shortfall of
domestically produced petroleum compared with the desired supplies. This
shortfall is a measure of the amount of future petroleum imports that will
be required, of synthetic fuel production needed, or a combination of
these two alternatives.
The three Ford scenarios are entitled Historical Growth (HG), Tech-
nical Fix (TF), and Zero Energy Growth (ZEG). Basically, the HG scenario
assumes that consumers of fuels ignore the current high prices of fuels
and return to historical high consumption rates with no government restric-
tions on consumption. Under the HG scenario, oil prices fall back to the
*For example, the forecasts of aviation demand are generally agreed to be
excessively high and the assumptions of fuel price are never made explicit
Moreover, the Ford study makes the unrealistic assumption that synthetic
fuels could be developed (without governmental subsidies) at a cost of
$4-$6 per barrel.
12
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$4 to $6 per barrel range, which is low enough to maintain demand at
historical rates. The HG scenario assumes that fuels from nonconventional
fossil sources (e.g., oil shale) would have to be developed because of the
rapid growth of demand. However, one difficulty with the HG scenario is
the doubtful assumption that synthetic fuels could be produced (without
governmental subsidy) at a price range of $4 to $6 per barrel. Moreover,
it is unlikely that these low prices could hold in the face of the pro-
jected continued rapid growth in demand.
The TF scenario assumes that fuel consumers will respond to the
current high prices of energy and take steps to reduce fuel use over the
1975-2000 period and that the government will order mandatory conservation
measures. With conservation measures in effect, the annual growth rate
of total demand for energy is reduced from 3.4 percent under HG to 1.9
percent under TF. Primary factors in conserving energy are better insula-
tion of buildings and better automotive fuel economy. For example, auto-
mobiles are assumed to achieve an improved fuel economy from the current
14 mpg to 20 mpg by 1985 and to 25 mpg by 2000. The study maintains that
this could be achieved without giving up large automobiles and with
existing technology.
The ZEG scenario is similar to the TF but with more stringent govern-
mental controls. For example, the efficiency of automobiles increases
from its current 14 mpg to 33 mpg by 2000.
The Ford Foundation Energy Policy Project gives a complete energy
balance for the U.S. economy in all three scenarios. Table 2-2 shows the
annual fuel demand by the entire transportation sector and the annual fuel
demand by autos, trucks, and buses in the three Ford scenarios HG, TF, and
ZEG.
On the supply side, the Ford study not only presents different
assumed domestic petroleum supplies under the three main scenarios, but
13
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Table 2-2
PROJECTED ANNUAL FUEL CONSUMPTION BY SECTOR
*
Quadrillion Btu per year (million B/D product equivalent)
Source: Reference 11 (Tables 1, 5, 16, and A-8)
1970 1975 1985 2000
Total all sectors 66.0 78.0
Transportation 15.7 19.1
Autos, trucks, and buses 11.9 (6.2) 14.4 (7.5)
Percentage of
transportation 76% 75%
HG Total all sectors 116.1 186.7
Transportation 26.0 38.4
Autos, trucks, and buses 18.0(9.3) 21.9(11.4)
Percentage of
transportation 69% 57%
TF Total all sectors 91.3 124.0
Transportation 19.6 24.7
Autos, trucks, and buses 12.7(6.6) 11.4(5.9)
Percentage of
transportation 65% 46%
ZEG Total all sectors 88.1 100.0
Transportation 18.4 17.2
Autos, trucks, and buses 12.5(6.5) 8.5(4.4)
Percentage of
transportation 68% 49%
We use 1 bbl oil product (typically gasoline) = 5.25 x 10 Btu, so that
1 quad (10 Btu) per year equals about 0.5 million B/D; 1 quad is also
approximately equal to 10 GJ.
14
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subscenarios are also given. Under HG, three subscenarios are presented
—normal development (HG1), accelerated nuvlear development (HG2), and
high imports (HG3); these subscenarios are shown in Figure 2-3.* In HG2,
accelerated nuclear development substitutes for domestic oil in power
generation; in HG3, imported oil substitutes for the development of domes-
tic oil. The greatest assumed development of domestic oil occurs under
scenario HG1, Under TF, two subscenarios are presented—TF1 and TF2.
Under TF1, the United States moves toward self-sufficiency by reducing
imports by almost one-half. Under TF2, dependency on imports is not
reduced but some environmental restrictions are included. The TF scenario
is shown in Figure 2-4. The ZEG scenario, shown in Figure 2-5, includes
stringent environmental controls, which then restrict the development of
offshore and outer continental shelf areas. The various supply scenarios
are summarized in Table 2-3. As discussed extensively in Chapter 3, of
-*
the three assumed supply cases of HG, only the HG3 domestic supply scenario
has reasonable likelihood of being realized in light of the most recent
U.S. Geological Survey estimates of the total recoverable U.S. reserves
of petroleum.
Figures 2-3 to 2-5 indicate that an automotive fuel shortfall of
about 6 million B/D (HG1 demand minus HG3 supply) to 2 million B/D (TF
demand minus TF2 supply) might occur in the year 2000. Table 2-3 shows
that the total (for all sectors) liquid fuel shortfall (listed as imports)
might be in the range of 4 to 18 million B/D. This leaves a considerable
*Figures 2-3 to 2-5 assume that domestic crude production has been dis-
tributed among all use sectors in proportion to the demand of that sector
compared to total petroleum demand. This proportion varies with time.
The original projections in the Ford Foundation study assume that imports
are cut exactly in half from the levels given in the HG case. In this
table, all production of synthetic fuels shown in the Ford study has been
added to imports of crude oil.
15
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PROJECTIONS
HISTORICAL
IMPORTS
I960
1970
1980
1990
2000
YEAR
FIGURE 2-4. TECHNICAL FIX SCENARIO-AUTOMOTIVE FUEL
DEMAND AND DOMESTIC SUPPLY PROJECTIONS
17
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HISTORICAL
IMPORTS
I960
1970
YEAR
1980
1990
2000
FIGURE 2-5. ZERO ENERGY GROWTH SCENARIO-AUTOMOTIVE FUEL
DEMAND AND DOMESTIC SUPPLY PROJECTIONS
18
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Table 2-3
OIL SUPPLY PROJECTIONS
Million B/D (Quadrillion Btu)
1973 1985 2000
Domestic oil
HG1 11.0 (22) 15.9 (32) 20.9 (40)
HG2 15.9 (32) 17.7 (34)
HG3 13.4 (27) 13.4 (27)
TF1 14.9 (30) 17.9 (36)
TF2 14.4 (29) 17.4 (35)
ZEG 13.9 (28) 14.9 (30)
*
Oil imports
HG1 6.0 (12) 6.5 (13) 12.0 (24)
HG2 6.5 (13) 12.0 (24)
HG3 11.5 (23) 18.4 (37)
TF1 3.2 (7) 6.0 (12)
TF2 6.0 (12) 8.0 (16)
ZEG 4.5 (9) 4.5 (9)
HG1: Historical growth
HG2: High nuclear
HG3: High imports
TF1: Self-sufficiency (rapid coal development; cut imports
in half)
TF2: Environmental controls (no synthetic fuels)
*The synthetic liquid fuels in the Ford scenarios have
been shifted to this category.
19
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amount of uncertainty in the projected shortfall, an uncertainty matched
in global geopolitics and U.S. energy policy, which will largely determine
both the U.S. supply and demand for fuels.
In Chapter 6, we advance a Maximum Credible Implementation (MCI)
scenario for synthetic liquid fuels derived from coal and oil shale that
*
yields 10 million B/D. Thus, the MCI would be capable of filling a
substantial part of the total anticipated shortfall for liquid fuels.
of oil equivalent energy.
20
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REFERENCES
1. "Summary of National Transportation Statistics," Department of
Transportation, DOT-TSC-OST-74-8 (June 1974).
2. "Research and Development Opportunities for Improved Transportation
Usage," Transportation Energy Panel (September 1972).
3. Pangborn, J., et al., "Feasibility Study of Alternative Fuels for
Automotive Transportation," Environmental Protection Agency,
Institute of Gas Technology (1974).
4. Winger, J.G., et al., "Outlook for Energy in the United States to
1985," Chase Manhattan Bank (June 1972).
5. Dole, H.M., et al., "United States Energy, a Summary Review,"
U.S. Department of the Interior (January 1972).
6. Malliaris, A.C. and Strombotne, R.L., "Demand for Energy by the
Transportation Sector and Opportunities for Energy Conservation,"
in Energy, edited by Michael S. Macrakis (1974).
7. Jacobson and Stone, Energy/Environment, Factors in
Transportation, MITRE Corporation (April 1973).
8. Peterson, R.W., Chairman, Council on Environmental Quality, "A
National Energy Conservation Program: The Half and Half Plan,"
(March 1974).
9. Kant, F.H., et al., "Feasibility Study of Alternative Fuels for
Automotive Transportation," Environmental Protection Agency (June
1974).
10. Hemphill, R.F. and Difiglio, C., "Future Demand of Automotive Fuels,"
a paper presented at the General Motors Research Symposium, "Future
Automotive Fuels—Prospects, Performance, Perspectives," October 6-7,
1975.
11. A Time to Choose: America's Energy Future, Energy Policy Project of
the Ford Foundation (Ballinger, Cambridge, Massachusetts, 1974).
21
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APPENDIX
Reference 10 presents a sophisticated econometric model that projects
future automotive fuel demand taking into account the following variables:
• Automobile ownership
-The real price of automobiles by class
-The fuel efficiency of automobiles by class
-The real price of gasoline
-Total real disposable income
-Total number of households in each income group
-The unemployment rate.
• Travel demand
-household income
-trip purpose by income class
-cost factors.
The model relates five basic submodels:
• An estimator for market shares of new car sales (sales-weighted
fuel economy of new cars).
• An estimator for new car sales.
• An estimator for scrappage (fleet size, fleet fuel economy).
• An estimator for miles traveled.
• A fleet model to calculate fuel consumption.
The fuel demand projections are made with three assumed fuel price
schedules: constant fuel prices, rising fuel prices, and falling fuel
prices. Table A-l summarizes the fuel price assumptions.
22
-------
Table A-l
FUEL PRICE ASSUMPTIONS
(per gallon)
Source: Reference 10
Year
1976
1980
1985
1990
1995
2000
Constant
$0.61
0.61
0.61
" 0.61
0.61
0.61
Rising
$0.61
0.72
0.87
0.88
0.90
0.90
The model projects only car fuel demand, but this can be corrected
to total automotive fuel demand by assuming that cars use 70 percent of
all automotive fuel in all years. This conversion, shown in Table A-2,
allows easy comparison with the projections shown in Figures 2-3 to 2-5
in the text.
Table A-2
PROJECTED AUTOMOTIVE FUEL DEMAND
FOR CONSTANT AND RISING PRICES
(million B/D)
Source: Reference 10
Year
1976
1980
1985
1990
i995
2000
For Constant Price
7.4
7.6
8.3
9.2
10.3
11.4
For Rising Price
7.4
7.5
7.8
8.5
9.4
10.3
23
-------
3—REFERENCE SUPPLY CASE
By Barry L. Walton
A. Introduction
Meeting the anticipated fuel demands for autos, trucks, and buses
will require the development of oil resources in new areas together with
vigorous activity to enhance oil recovery from known fields. With con-
tinuing high prices for imports (about $11 per barrel of crude in 1974
dollars) and governmental price regulation of a kind to encourage new
production, stepped up attempts to develop domestic oil resources are
likely. However, even with increased production, domestic supplies of
oil will not meet demands for the entire period between now and the year
2000, and, in the absence of synthetic fuels, imports will be necessary
to supply the difference between domestic oil supplies and domestic oil
demands.
1. Content of the Reference Case
As a measure against which to set the topics treated in this tech-
nology assessment, we have developed a reference case in which the
expected shortfall in U. S. automotive fuels is met by increased produc-
tion within the existing petroleum industry, without the use of synthetic
fuels. Specifically, the demand is met by
• Onshore production—lower 48 states onshore and near-shore
production from state leases.
• Offshore production—outer continental shelf (OCS) production
from federal leases off the coasts of the lower 48 states.
• Alaskan production—onshore and offshore production.
* Imports—both crude oil and refined products.
24
-------
Figure 3-1 shows the boundaries of the reference case considered in this
chapter. Under the assumption of these sources of oil for the United
States to the year 2000, the reference case contains a projection of
(1) domestic oil supply by region and the requirements for imported oil,
(2) the resources required to increase domestic oil production without
recourse to synthetic fuels development, and (3) the environmental
impacts that could result from this production and importation. Environ-
mental impacts are given in terms of quantified indicators derived from
scaling factors applied to the projections of oil supply and demand and
the resource requirements for an intensive U.S. oil recovery program.
2. Scenarios; Bases for Projections of Supply and Demand
In selecting a domestic fuel supply scenario for the reference
case to correspond to the EPP demand forecasts described in Chapter 2,
we faced considerable difficulty. Although six possible supply project-
ions are described by the EPP , only HG3 retains some credibility in the
light of recent projections by the U.S. Geological Survey (USGS) of
2
domestic oil resources (Appendix A discusses these and other projections),
Table 3-1 shows the six EPP scenarios and displays approximate cumula-
tive production between 1973 and 2000 for these scenarios. For this
baseline analysis the synthetic fuels originally postulated by the EPP
have been shifted to the category of imports. The estimates of possible
domestic oil production shown in the table were made prior to the recent
USGS projections. Even the comprehensive Federal Energy Administration,
3
Project Independence Blueprint was based upon the out of date USGS
resource estimates shown in Appendix A, Table A-2. As discussed in
Appendix A, it is now necessary to abandon estimates of future crude oil
production which show impossibly large cumulative production estimates.
Among the scenarios of the EPP, HG3 projects the lowest cumulative pro-
duction rates into the next century.
25
-------
to
01
RESOURCE
PETROLEUM
I 1
DOMESTIC
OIL WELL
OFFSHORE
OIL WELL
ALASKA
OIL WELL
OVERSEAS
OIL WELL
L.
OVERSEAS
REFINERY
Excluded from the Reference Case
REFINERY
FIGURE 3-1. REFERENCE CASE PETROLEUM FUEL SYSTEM
-------
Table 3-1
CONVENTIONAL DOMESTIC OIL SUPPLY PROJECTIONS
Annual Projections Curamulative
in Projections
Millions of Barrels per day in
Supply Source (Quadrillion Btu per Year) Billions of Barrels
1973 1974 1985 2000 1973-2000
Domestic Oil
HG1 11.0 (22) 10.5 (21) 15.9 (32) 20.9 (40) 160
HG2 15.9 (32) 17.7 (34) 150
HG3 13.4 (27) 13.4 (27) 127
TF1 14.9 (30) 17.9 (36) 150
TF2 ' 14.4 (29) 17.4 (35) 140
ZEG 13.9 (28) 14.9 (30) 130
t
Oil Imports
HG1 6.0 (12) 6.0 (12) 6.5 (13) 12.0 (24)
HG2 6.5 (13) 12.0 (24)
HG3 11.5 (23) 18.5 (37)
TF1 3.5 (7) 6.0 (12)
TF2 6.0 (12) 8.0 (16)
ZEG 4.5 (9) 4.5 (9)
*
HG1: Historical growth
HG2: High nuclear
HG3: High imports
TF1: Self-sufficiency (rapid coal development; cut imports in half)
TF2: Environmental controls (no synthetic fuels; offshore production forbidden in new
areas until after 1985)
ZEG: Zero energy growth
t 6
5.5 x 10 Btu/barrel
Source: Reference 1, Tables 3, 13, 24.
27
-------
A problem with HG3 that had to be overcome for the reference case
is that it contains no corresponding regional supply projections which
are necessary for impact analysis. Accordingly, the relative regional
oil supplies from Project Independence Oil Task Force Report were
applied to the aggregated domestic supply projection under HG3 to give
regional supplies for our impact analysis requirements. Unfortunately,
no regional supply projections to the year 2000 using the most recent
USGS resource estimates have been made public, and the Project Independ-
ence projections were based on discredited resource estimates and were
not extended past 1988. We have, however, assumed that the relative
distribution among future producing regions given in Project Independ-
ence remain valid.
3. Summary of Conclusions
The major conclusions drawn from the reference case are the
following:
• Under all of the EPP scenarios the demand for liquid fuels
exceeds the HG3 domestic supply of conventional crude oil.
• Even with much higher crude oil prices, domestic petroleum
supplies are extremely unlikely to meet domestic demand,
even a demand as low as in ZEG.
• In the absence of synthetic crude oil, continued imports
will be necessary unless demand for crude oil is reduced
below the production level of HG3.
• Producing oil at the HG3 subscenario rate requires consid-
erable increase in oil production from offshore and Alaska,
and a massive tertiary recovery program onshore. Tertiary
recovery offshore and in Alaska would also be needed. Yet
domestic oil production from conventional sources will
begin a long term decline before 2000.
• Capital investment in domestic crude oil exploration and
production must increase to over $12 billion (1973 constant
28
-------
dollars) annually by 2000 if production is to approximate
that projected under HG3.
• Labor requirements for drilling will more than double
between 1977 and 2000.
• Steel requirements for crude oil production will increase
to over 3.5 million tons (3.2 billion kg) annually in 2000.
• The coastlines will be a major focus for the environmental
impacts from offshore resource development and from oil
import activity.
• Alaska will be a second major focus for the environmental
impacts from developing oil resources in offshore areas
and along the North Slope. A second TAPS is necessary for
transporting North Slope oil under HG3.
• The potential for large scale environmental disaster re-
sulting from a large oil spill along the coastal regions
is significant. Based on an extrapolation of past spill
statistics, perhaps 13 spills of over 100,000 barrels can
be expected.
The significant implications of these conclusions are the follow-
ing:
* Without synthetic fuels from coal and oil shale, imports
of petroleum will grow to over 18 million barrels per day
under demand levels of Historical Growth, and will grow to
over 10 million barrels per day under Technical Fix, since
these demand levels cannot be met by the HG3 supply.
• Supplying domestic oil at the HG3 rates will require con-
siderable capital investment. Recent investment and supply
projections made by Texaco and published in the Oil and Gas
Journal show 1990 crude oil production at about 13 million
barrels per day with annual investment in crude oil and
natural gas production at over $30 billion (1975 $). This
production and investment projection supports our conclus-
ion that the $12 billion required annually under HG3 is a
lower limit to the investment necessary to bring about oil
production at the HG3 levels.
29
-------
Because the better economic prospects for oil production
will be exhausted by the year 2000, investment costs for
new oil reserves will go to between $1.80 and $3.20
(1973 $). These costs are comparable to or greater than
investments for syncrude.
The price of crude oil in constant dollars will increase
under almost any realistic scenario, particularly if
national independence from foreign crude oil supplies is
sought.
Oil production from offshore and Alaskan oil resources will
continue to be the center of environmental controversy.
Indeed, the major impacts of future oil production result
from producing resources from these areas.
B. Projected Domestic Oil Supply and Imported Oil Requirements
To project detailed domestic oil supplies for HG3, the Project
4
Independence Oil Task Force supply projections are used to define the
relative percentages of oil supplied from each National Petroleum Council
*
(NPC) region. Figure 3-2 defines regional boundaries used in this
chapter. Table 3-2 shows HG3 supplies aggregated into onshore production,
t
offshore production, and Alaska production. The apparent heavy reliance
on oil supplies from Alaska, offshore, and tertiary recovery for future
6
production reflects general expectations of future production.
*
The NPC regions (modified from the usual National Petroleum Council
4
regions) as defined by the Oil Task Force.
t
Aggregated from Table B-l of Appendix B.
30
-------
S U CENTRAL ALASKA
(offshore oreos extend to
200-m water depth )
.
400
8OO MILES
0 400 BOO KILOMETRES
Source: U.S. Geological Survey, Circular 725
FIGURE 3-2. INDEX MAP OF NORTH AMERICA SHOWING THE
BOUNDARIES OF THE 15 OIL PRODUCTION REGIONS,
ONSHORE AND OFFSHORE
31
-------
Table 3-2
DOMESTIC OIL SUPPLY, IMPORTS, AND TOTAL DEMAND UNDER HG3
C
10 Barrels per day (% of Domestic Supply)
SUPPLY/DEMAND
YEAR
CO
to
CUMULATIVE
1974-2000
(109 Barrels)
Domestic Supply
Onshore
Lower 48 states
Offshore
Lower 48 states
Alaska
Onshore and offshore
Total
Imports
Total U. S. demand
1974
8.9 (85)
1.4 (13)
0.2 (2)
10.5
6.0
16.5
1985
6.8 (52)
3.0 (21)
3.6 (27)
13.4
11.5
24.9
From Advanced
2000 Total
5.0 (38) 63
4.0 (30) 28
4.4 (32) 30
13.4 121
18.4
31.8
rwi;u vex y
34
15
16
Source: Appendix B, Table B-l.
-------
Table 3-3 shows the onshore production for HG3 by NPC region.
Table 3-4 shows the offshore production for HG3 by offshore NPC region,
including production from military oil reserves in the Pacific and Gulf
of Mexico offshore areas. Table 3-5 shows the Alaska production for
HG3 by onshore and offshore areas.
Cumulative production under HG3 between 1973 and 2000 is approx-
9
imately 130 x 10 barrels of oil—about 25 percent greater than the
cumulative total U.S. production up to 1973. Cumulative tertiary
recovery under HG3 is assumed to be about 70 billion barrels, an
assumption that reflects the availability of oil through primary recov-
2
ery given the 1975 USGS resource estimates.
We assume that cumulative recovery between 1973 and 2000 from each
region by tertiary methods is proportional to total cumulative recovery
by tertiary methods divided by total cumulative recovery over the same
period.
33
-------
Table 3-3
ONSHORE OIL PRODUCTION FROM THE LOWER 48 STATES UNDER HG3
6
(10 Barrels per day)
Region or Source
Pacific Coast
NPC Region 2
Naval Petroleum Reserve No. 1
Western Rocky Mountains
NPC Region 3
Eastern Rocky Mountains
NPC Region 4
West Texas/Eastern New Mexico
NPC Region 5
Western Gulf Basin
NPC Region 6
Mid-Continent
NPC Region 7
Northeast
NPC Regions 8, 9, 10
Atlantic Coast
NPC Region 11
1974 1985 2000
0.792 0.59 0.38
0 0 0.08
0.215 0.16 0.12
0.614 0.34 0.23
2.553 1.6 1.1
3.526 3.2 2.4
0.994 0.68 0.56
0.213 0.28 0.19
0.007 0
0.01
Total
8.914 6.8
5.0
* See Figure 3-2 for geographical locations.
t Items may not sum to totals due to rounding.
34
-------
Table 3-4
OFFSHORE OIL PRODUCTION FROM THE LOWER 48 STATES UNDER HG3
6
(10 Barrels per day)
Region or Source
Offshore military reservations
Atlantic offshore
NPC Region 11A
Gulf of Mexico
NPC Region 6A
Pacific offshore
NPC Region 2A
1974 1985
2000
0 0 0.16
0 0.04 0.60
1.311 2.3 2.0
0.058 0.6 1.2
Total
1.369 3.0
4.0
* See Figure 3-2 for geographical locations.
t Items may not sum to totals due to rounding.
Source: Tables B-l, Appendix B
35
-------
Table 3-5
ONSHORE AND OFFSHORE OIL PRODUCTION FROM ALASKA UNDER HG3
6
(10 Barrels per day)
Region or Source
Prudhoe Bay
North Slope
Other than Prudhoe Bay
Naval Petroleum
Reserve No. 4
Gulf of Alaska and other
offshore areas
NPC Region 1
1974
1985 2000
0
0
1.8
1.3
1.2
0.68
0
0
0.201 0.54
1.6
0.96
Total
0.201 3.6
4.4
* See Figure 3-2 for geographical locations.
t Items may not sum to totals due to rounding,
Source: Table B-l, Appendix B
36
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The economic incentives provided by high prices for imported crude
oil and refined products will tend to increase the supply from the
three domestic sectors—onshore (lower 48 states), offshore (Atlantic,
Pacific, Gulf of Mexico areas), and Alaska (onshore and offshore). Of
course, the distribution of the supply available from each of the
sectors cannot be forecast to the year 2000 with precision,
C. Projected Resource Requirements for Production of Domestic Oil
Oil can only be produced with sufficient inputs of the resources
of equipment, manpower, steel, and capital. Projections of these inputs
under scenario HG3 are developed in this section.
1. Drill Rigs, Labor, and Steel
Table 3-6 shows the approximate annual requirements for drill
rigs, labor, and steel for the reference case. Labor and steel require-
ments are shown later for synthetic fuel development in the maximum
credible implementation (MCI) scenario, Chapter 6. The number of rigs
determines many of the oil production impacts.
Several considerations were used in generating the annual
*
resource requirements in Table 3-6: (1) Since annual production under
HG3 in 2000 corresponds closely to the Project Independence 1988 $11/B
Business-as-usual scenario, no increase in the annual resource
requirements beyond the Project Independence 1985 $11/B Business-as-
usual requirements is assumed except for investment and (2) this is
based on the assumption that future production is closely correlated
*
Annual oil production depends on resource inputs and exploration
activity. For example, it will take several years before a new
offshore field reaches peak production. More than one production
platform is likely for a large field.
37
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Table 3-6
LABOR, DRILL RIG AND STEEL REQUIREMENTS
FOR OIL PRODUCTION UNDER HG3
Exploration Drill Rigs in Use
Onshore
Offshore
Alaska
Onshore
Offshore
Offshore Production Platforms
Offshore
Alaska-offshore
1977*
Annually
930
240
125
26
1980
1,100
370
125
52
*
1985
1,250
500
150
110
t
1990
1,250
500
150
110
t
1995
1,250
500
150
110
t
2000
1,250
500
150
110
in Use Annually
90
6
Labor — Rig and Platform Crewmen Employed
Onshore
Offshore
Alaska
(Offshore)
22,000
24,000
3,000
(1,600)
150
12
Annually
25,000
37,000
5,000
(3,100)
200
25
29,000
52,000
8,000
(6,500)
200
25
29,000
52,000
8,000
(6,500)
200
25
29,000
52,000
8,000
(6,500)
200
25
29,000
52,000
8,000
(6,500)
Total 49,000 67,000 89,000 89,000 89,000 89,000
Steel — Thousands of Tons Required Annually
Onshore
Offshore
Alaska
1,400
1,400
200
1,600
1,700
200
1,700
1,400
400
1,700
1,400
400
1,700
1,400
400
1,700
1,400
400
Total 3,000 3,500 3,500 3,500 3,500 3,500
*
Data up to 1985 adapted from Reference 4, Tables VI-8, VI-9 and VI-10, by excluding the
heavy crude oil and tar sands data.
*A11 requirements after 1985 held constant.
This reflects the correspondence between production by 2000 under HG3 and the FEA
$11/B BAU scenario production by 1988 used in Appendix B to generate the regional
production for HG3.
38
-------
to exploration activity. The same drilling activity used to achieve
the FEA production by 1988 is assumed to achieve the HG3 production by
2000. The correlation is generally valid—more drilling activity
results in more future production, although according to those knowledge-
able in the field, it is becoming increasingly difficult to find oil
with the amount of oil discovered per foot of exploratory well drilled
6
on the decline. Since that trend can be expected to continue, the
resource requirements in Table 3-6 are probably underestimated.
The factors that will mean less production per unit of invest-
ment toward the end of the century are:
• Exploration of deeper oil prospects, which entails
more feet of drilling per well, fewer well completions
per foot of drilling, slower drilling rates per foot
of well, and greater expense per completed well.
* Exploration of more remote locations, which has
characteristics of exploration of deeper prospects.
Moreover, the drilling season is limited in such
places as arctic offshore regions.
* Exploration of the "better" prospects will be completed.
a. Drill Rig Requirements
Oil production on land requires drill rigs for exploration—
thereby the adage "the only true test for oil is the drill"—and for
drilling development wells and the extra wells required by secondary
and tertiary recovery or for workover. Onshore drill rigs are relative-
ly mobile and are often truck-mounted.
Offshore oil production requires drill rigs both for explora-
tory drilling—jack-ups, semisubmersibles and ship-mounted rigs are the
7
most common —and for production at locations where permanent platforms
39
-------
complete the production wells and support the production equipment. In
the future, more subsurface platforms (unmanned) are likely to be used
because they are cheaper and lighter than surface platforms. The
subsurface, unmanned platform is fixed to the ocean floor, and the wells
are drilled by a mobile drillship, which moves on after placing the
production tubing. The rig requirements shown for offshore production
in Table 3-6 fall into these categories.
The rig requirement shown for Alaska in Table 3-6 includes
both onshore rigs (rarely truck-mounted because of the severe environ-
ment of the North Slope tundra) and offshore rigs—similar to rigs used
offshore in other areas with the exception of those designed for use in
8,9
pack ice regions. Many of the impacts on Alaskan offshore waters
depend on the number of offshore rig requirements.
The HG3 scenario requires substantial drilling activity.
Alaska, particularly, will see large increases in drilling activity.
Because of much increased drilling for tertiary recovery under HG3,
onshore continues to receive the most drilling activity.
b. Labor Requirements
The total number of rig crewmen required depends on the
number of rigs in operation and whether they are operated on or offshore,
Onshore rigs each require about 25 men, while offshore rigs each require
4
about 50 men. Project Independence estimates Alaskan rigs require
somewhat fewer men than other onshore rigs—less than 20 men each; how-
ever, a backup crew is also required and a large number of support
personnel are required, while in onshore production elsewhere support
personnel are part of the general infrastructure.
40
-------
Labor requirements for drilling and production grow substant-
ially under HG3. The HG3 requirements in 2000 are double those in 1977,
The rigmen required for offshore may be overestimated if subsurface
production platforms become widely used toward the end of the century,
as may be likely.
c. Steel Requirements
Steel is required for the construction of drill rigs and
production platforms, for the -production of. the tubing used to support
the drill during drilling, for the well casing, and for surface equip-
ment such as storage tanks, equipment sheds, and pumps. The steel
requirements shown in Table 3-6 reflect these needs and are probably
underestimated since much of the steel required for tertiary production
(the extra wells) is not included. Neither are steel requirements for
oil transportation and distribution or refining included. These needs
can be substantial, particularly for oil pipelines from remote regions.
For example, the Trans-Alaska Pipeline (TAPS) will contain about 1.2
million tons of steel. Under HG3, the annual steel requirements are
about 3,000,000 tons by 2000, with onshore production requiring the
most steel (refer to Table 3-6).
An impact occurs during retirement of some production
facilities—the irretrievable investment of steel. Offshore rigs may
be left in place after their economic life is exceeded. During periods
of falling prices, rigs may remain idle which represent a large energy
investment in terms of the steel in the well pipe and rig. Some off-
shore rigs contain as much as 25,000 tons of steel. Whether this steel
will be left in place forever remains an open question. To give some
feeling for what this 25,000 tons of steel represents, we give the
41
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following illustrative calculation. An offshore production platform
must produce about 30,000 B/D to be economically viable. This fuel rate
will supply about 900,000 cars with each car using about 0.033 B/D
(20 miles/gal and 10,000 miles/yr). At 1 ton each, these cars contain
about 900,000 tons, or about 36 times as much steel as the offshore
platform supplying their fuel.
2. Capital Investment
To our knowledge, Project Independence contains the most
4
recent detailed estimates of investment in crude oil production, and
they have been adapted to form the basis of our projections. Unfor-
tunately, these investments were based on the 1972 USGS resource esti-
mates discussed in Appendix A. In order to create more realistic
investment estimates for HG3, we have assumed that the investment pro-
jections in Project Independence cover only the annual investment
necessary for primary and secondary recovery under HG3, and we have
gone on to assume that additional investment is necessary for the sub-
stantial tertiary recovery required for oil production under HG3 (dis-
cussed in Appendix B).
Table 3-2 showed cumulative production by advanced recovery
techniques necessary to support the HG3 production level from each
region. For this production to take place, the resources in each reg-
ion must first become economically producible reserves (Appendix A).
The capital investment necessary to convert resources into economically
producible reserves in each region is shown in Table 3-7. The Project
Independence Oil Task Force Report shows the investment required per
barrel of reserve added for 1974 and 1988. To estimate the minimum
capital investment necessary to convert 70 billion barrels of resource
into oil recovered by advanced techniques we have assumed that these
42
-------
Table 3-7
CAPITAL INVESTMENT REQUIRED
FOR SECONDARY AND TERTIARY RECOVERY
Dollars (1973) per Barrel of Reserve Added
1974-1988 1988-2000
Secondary Recovery
Region 1 $ 0.96 $ 1.92
Regions 2A, 6A, and 11A 0.64 1.28
Regions 2, 3-6, and 7-11 0.32 0.96
Tertiary Recovery
Region 1 1.68 3.12
Region 2 1.50 3.00
Regions 2A, 6A, and 11A 1.12 2.14
Regions 3-6, 7-11 0.80 1.76
Source: Project Independence Blueprint,
Oil Task Force Report
43
-------
investments pertain to the entire period to the year 2000 as shown in
the table. The investments shown in the second column probably under-
estimate the necessary investment for HG3 since many of the better
tertiary recovery prospects in each region will already be in production
by the last decade of the century.
The approximate capital investment for recovery by advanced
techniques is shown for onshore, offshore, and Alaska in Table 3-8.
The investment estimates represent a probable lower limit to the nec-
essary investment for reserves recoverable by tertiary methods since
these estimates reflect only the tertiary recovery that is actually
accomplished by 2000. In practice, there must be reserves of crude oil
left after any given year; in the past, reserves have been about ten
times annual production (Appendix C) so that additional investment, not
shown in the Table 3-8, is required for the reserves left in the year
2000. We have assumed that the total investment for the two periods,
1974-1988 and 1988-2000, is divided uniformly on an annual basis. This
probably will not be true in practice.
The approximate capital investment for all conventional oil
recovery to the year 2000 is displayed in Table 3-9. Capital invest-
ment in constant dollars increases over two and half times between
1977 and 2000. Project Independence forecasts considerably less
production from advanced recovery than is necessary for HG3 in the light
2
of the 1975 USGS resource estimates. Thus, we have assumed that the
annual investment levels projected by Project Independence approximately
cover the 60 billion barrels of production under HG3 that must come
from primary and secondary recovery methods. The investment allocated
for tertiary recovery in the Project Independence scenarios is probably
comparable to the additional investment for the tertiary recovery re-
serves in 2000 left out of our analysis, so that any investment that
44
-------
Table 3-8
APPROXIMATE CAPITAL INVESTMENT REQUIRED FOR ONSHORE, OFFSHORE, AND ALASKA OIL PRODUCTION
BY ADVANCED RECOVERY TECHNIQUES
01
Region Cumulative Production
(109 barrels)
Investment per Barrel Total Investment Annual Investment
(1973 dollars) (109 1973 dollars) (109 1973 dollars)
Onshore
Offshore
Alaska
Total
Onshore
Offshore
Alaska
17
7.5
8.0
17
7.5
8.0
$ 0.
1.
1.
1.
2.
3.
1974-1988
8 $
1
7
1988-2000
8
1
1
14
8.3
14
31
16
25
$ 1.0
0.6
1.0
2.6
2.6
1.3
2.1
Total
6.0
-------
Table 3-9
CAPITAL INVESTMENT IN CONVENTIONAL OIL PRODUCTION FOR HG3
(In 1973 dollars annually)
1974
1977
1980
1985
1990
1995
2000
Onshore Recovery
Primary and Secondary
Advanced
Subtotal
Offshore Recovery
Primary and Secondary
Advanced
Subtotal
Alaska
Primary and Secondary
Advanced
Subtotal
Total
1.3
1.0
2.3
0.3
0.6
0.9
0.7
1.0
1.7
1.4
1.0
2.4
0.3
0.6
0.9
1.2
1.0
2.2
3.3
1.0
4.3
0.5
0.6
1.1
1.2
1.0
1.2
3.9
1.0
4.9
0.9
0.6
1.5
1.3
1.0
1.3
3.9
2.6
6.5
0.9
1.3
2.2
1.3
2.1
3.4
3.9
2.6
6.5
0.9
1.3
2.2
1.3
2.1
3.4
3.9
2.6
6.5
0.9
1.3
2.2
1.3
2.1
3.4
4.9
5.5
6.6
7.7 12.1 12.1 12.1
Primary and secondary recovery investment data up to 1985 adapted from Reference 4, Table IV-16,
by excluding the heavy crude oil and tar sands data.
-------
has been underestimated in Table 3-8 is probably made up by the over-
investment in primary and secondary recovery implicit in Table 3-9.
The analysis in Appendix B leads to the conclusion that over
50 percent of the recovery should be coming from advanced recovery
methods toward the end of the century. Because of the higher invest-
ment levels necessary for advanced recovery relative to primary or
secondary recovery (refer to Table 3-7), the investment split between
primary and secondary recovery and advanced recovery should be heavily
weighted toward advanced recovery projects. Table 3-9 shows such an
emphasis on advanced recovery. The estimates shown in Table 3-9 are
designed largely for purposes of illustrating the necessary investment
for HG3. We do expect, however, that the investment projections for
advanced recovery and for overall recovery are approximately correct
and reflect current expectation of investment for future recovery.
5
Recent estimates of future production and investment made by Texaco
and published in the Oil and Gas Journal support the rough estimates
and trends for investment and production shown here for HG3.
D. Projected Environmental Impacts
The scope of the research did not permit detailed assessment of
the effect of oil extraction, distribution, and refining in the ref-
erence case on the environment; however, the material presented is
sufficiently detailed to indicate the probable environmental consequen-
ces of an intensive and accelerated industry effort to extract the
maximum amount of oil from onshore, offshore, and Alaskan sites. Only
major impacts are treated here. They are broadly grouped into land use
requirements, water requirements, employment and induced population,
oil spill probabilities and quantities, and major air and water pollu-
tant emissions. No attempt is made to rank the impacts in severity.
47
-------
The environmental impacts of the reference case are determined by
means of scaling factors for quantifiable characteristics of the oil
extraction, transport, and refining processes. For example, operation
of each barrel per day (B/D) of petroleum refining capacity is respons-
ible for a volume of water effluent averaging 770 gallons per day.
With a refining capacity of 20 million B/D, the water effluent would
6
approximate 20 x 10 x 770 gallons per day. This 15-billion gallon
per day effluent volume is a quantitative indicator of the environmental
impact of petroleum refining.
Scaling factors appropriate to the various activities involved in
crude oil production, distribution, and importation are derived in
Section 1, below. In Section 2, environmental impacts for onshore,
offshore, and Alaskan production, and oil transport (domestic and
imported) are developed by applying the scaling factors to the product-
ion estimates given in Section B and the equipment and labor require-
ments given in Section C, above.
1. Impact: Scasing Factors
a. Crude Oil Production
The scaling factors necessary for evaluating the major
environmental impacts of oil exploration and production on land use,
air quality, and water quality are presented in four groups:
• Impacts of normal exploration activity
• Impacts of exploration accidents
• Impacts of normal production activity
• Impacts of production accidents .
(1) Normal Exploration Activities
Impact scaling factors for the major environmental
48
-------
impacts of normal exploration are shown in Table 3-10. The three major
*
consequences of normal drilling activity are qualitatively:
* "Boom towns," increased urban growth, increased
automobile use, and increased demand for housing
and recreation created by the presence of drilling
crews, their families, and personnel in service
industries. These impacts occur off the drilling
site.
* Disturbed lands or ocean bottom, displaced species,
water pollution, or road construction at or adjacent
the drilling site.
" Solid waste produced by drilling, which may produce
water pollution or undesirable land fill.
Many important impacts of exploration result from the normal
human activities and demands of the exploration drillers, their families,
and associated personnel in service industries. These impacts, of
course, vary in severity depending on the degree of urbanization already
existent in the region: the less the urbanization, the greater the
impact.
Since individual environmental impacts that occur on the
drilling site are too site-specific to quantify, Table 3-10 gives only
the estimated land areas impacted by a typical drilling project onshore
and offshore. Onshore exploration rigs, including storage ponds for
drilling mud, occupy about one acre. Offshore rigs are considerably
larger than onshore rigs, containing crew quarters, storage facilities
*
Other geophysical and exploration activity results in minimal environ-
mental impact.
49
-------
Table 3-10
IMPACT SCALING FACTORS FOR NORMAL EXPLORATION OPERATIONS
Impact
Quantity
Scaling Factor
Units
Urban development, population growth
consequences of human activity
Surface lands affected by drilling
Submerged lands affected by
exploratory drilling
Solid waste produced by drilling
rig—drill cuttings consisting of
rock particles, sand, and drilling
mud
People employed per exploration rig:
24 Onshore
100 Offshore
12 Alaska (onshore)
60 Alaska (offshore)
Approximate land area disturbed by one
drilling rig:
1 acre plus land for service road (onshore)
1 acre plus land for housing (Alaska onshore)
3000 acres Approximate offshore land area disturbed
by an offshore drilling rig
63 tons Weight of cuttings (tons) produced per
4
1000 ft of exploratory drilling
T 2
Approximate conversion factors: 1 acre = 4000 m , 1 ton = 907 kg, 1000 ft = 300 m.
*Inferred from Table 3-6
-------
for equipment, and a processing area for drilling mud; their decks
occupy 1 to 2 acres of surface area. Large semisubmersible exploration
12
rigs have as many as 2 acres of surface area.
Wells can be drilled as far as 6000 ft (slant range) from an
offshore platform and may therefore tap an area of 4 square miles, or
2500 acres. About a 1 mile clear zone is maintained around offshore
rigs, which is intended to prevent ships and tankers from colliding
with the platform. Thus, an offshore platform impacts commercial
*
fishing and navigation by the removal of about 3000 acres of ocean
surface from many alternative uses and by presenting a hazard to navi-
7
gation.
In Alaska, drilling sites entail greater acreage than do
sites in the lower 48 states because large rigs, needed for the re-
latively deep wells, must also provide shelter from the weather for the
workers. Moreover, onsite housing, airfields, and other facilities
occupy considerable area. The Prudhoe Bay site consists of about 400
square miles, with only a small fraction occupied by exploration rigs.
Drilling produces considerable solid waste in the form of
drill tailings—sand, rock particles, and some drilling mud. The ave-
rage well is about 5000 ft (1.5 km) deep and would therefore produce
some 300 tons (270,000 kg) of drill tailings. In exploratory drilling
offshore, the USGS orders for OCS drilling allow onsite disposal of this
material; other solid waste must be fully processed or returned to
shore. Little is known about the environmental effects of the dis-
posal of drilling mud, although the unconsolidated sediment makes for a
*
Assuming 1'mile (1.6 km) distance between tankers and platform
is maintained.
51
-------
13
poor home for bottom-dwelling organisms.
(2) Exploration Accidents
Table 3-11 shows the major scaling factor for the
impacts of accidental or abnormal drilling operations. The environ-
mental impacts of oil in the marine environment, mainly the death of
large numbers of sea birds, the loss of aquatic life, have been widely
J 14-18
discussed.
Blowouts, a major source of oil entry into the environment,
result from excessive uncontrolled pressure buildup in the well. During
drilling, the drill mud composition and density are varied to assure
that the weight of drilling mud equals or exceeds the pressure in the
rock formation. An oil or gas pressure exceeding this weight can force
the drilling mud back up the drill hole. The resulting excess pressure,
if not controlled, forces mud and oil back up the well, which causes a
blowout. Blowouts can cause loss of life, equipment failure, broken
pipes, and other damage, and may result in fires as well as the uncon-
trolled release of oil into the environment.
Onshore, the probability of an oil blowout is much less than
1 in 2500, owing to the large number of high-pressure gas blowouts
included in this estimate. In part, the reduced risks of onshore
drilling come from the less sophisticated demands of onshore drilling
and from the more frequent drilling in oil formations with known
pressures.
52
-------
Table 3-11
IMPACT SCALING FACTORS FOR EXPLORATION ACCIDENTS (BLOWOUTS)
Scaling Factor
w
Impact
Potential for human casualties,
disruption and destruction of
marine biota, and scenic losses
from accidental discharge of oil
into the environment (blowout)
Quantity Units
Onshore probability of a blowout:
19
1 well in 2500 (includes high
pressure gas blowouts)
Probability of a blowout offshore:
1 well in 5007 (includes high
pressure gas blowouts)
1 well in 3300 (not including
gas blowouts)
-------
(3) Normal Production Activities
Table 3-12 summarizes the impact scaling factors
for the major environmental impacts from normal crude oil production
activities. These impacts are:
• Disturbed lands or ocean bottom, displaced
species, water pollution, or road construction
at the drilling site.
* Increased urban growth, increased automobile
use, and increased demand for housing and
recreation caused by presence of production
personnel, their families, and personnel in
service industries. These impacts occur away
from the production site.
• Water-related effects.
* Potential for air pollution.
The first two impacts are much the same as for explor-
ation activities.
Much of the byproduct water from oil production is
reinjected into the formation so that not all of the wastewater (which
contains low concentrations of oil and perhaps chemicals used in ad-
vanced recovery) enters the environment. Water demands for secondary
and tertiary recovery, although large, produce severe impacts only in
regions with a scarcity of water. Water injection has a number of side
effects. It can trigger seismic activity and the hydraulic pressure of
water injection can cause surface deformation and faulting. The inject-
ion of chemicals into wells can result in contamination of the deep
aquifers which are in contact with nearly all oil reservoirs.
54
-------
Table 3-12
IMPACT SCALING FACTORS FOR NORMAL PRODUCTION OPERATIONS
Scaling Factor
Impact
Urban growth, induced population
and effects on the environment
from human activity
Vfastewater production from normal
oil production operations
Makeup water requirements—water
injection for secondary and
tertiary recovery
Land use:
Onshore
Offshore
Alaska—onshore
Alaska—offshore
Chemical requirements for tertiary
recovery:
Biopolymers and
polyacrylamides
Surfactants (sulfonates)
Cosurfactants (isopropanol)
Air pollutant emissions from tertiary
recovery by thermal methods:
Particulates
S°2
NO
cox
Hydrocarbons
Solid waste production (drill cuttings
and spent mud components)
Oil release into offshore environ-
ments from normal DCS operations
Pollution from oil produced with
onshore wastewater (untreated)
Quantity
13,000
8
2 x 10
360 x 106
1/4
3000
65,000
3000
1-6 x 10
7-15 x 10
4-10 x 106
120
1,000
200-420
21
16
63
50
Units
Employees per million barrels
20
per day of production
Gallons per million barrels
20
per day of production
Gallons per million barrels
19
per day of production
10
Acres per development well
Acres per production platform"
Acres per million barrels per
21
day of production
Acres per production platform
11
11
6
Pounds per 10 barrels of oil
22
produced
Tons per million barrels of
oil recovered
3 *
Tons per 10 feet of well
Barrels per million barrels per
day of production
Barrels per million barrels per
day of production
* -33 3
Approximate conversion factors: 1 gal = 3.8 x 10 m , 1 ton = 907 kg, 1 barrel = 0.16 m ,
2
1 pound =0.45 kg, 1 acre = 4000 m .
Thermal recovery of oil (steam injection) requires about 1 barrel of oil burned for steam
23
for every four barrels produced. Emissions are assumed to be the same as for burning
residual fuel oil.
Three times as many development wells are drilled as exploratory wells.
25
55
-------
Oil production can contribute to air pollution. In some
regions in which it is uneconomical to transport oil's co-product,
natural gas, by pipeline, the gas is flared. However, most gas is
reinjected into the well if no gas transmission system is available.
Tertiary recovery by thermal methods, particularly fire flooding or
burning part of the oil underground to build heat and pressure in the
well, can result in gaseous emissions from the formation. Recovery of
high-sulfur crude may result in the release of highly toxic sulfurous
26
gases.
(4) Production Accidents
The impact scaling factors for abnormal production
activities are listed in Table 3-13. The most important impact results
from accidents to equipment, which release oil to the environment.
Most oil reservoirs contact groundwater aquifers. Many
tertiary recovery projects will require the injection of large quan-
tities of chemicals into oil formations and potentially can result in
the exchange of water soluble chemicals with groundwater. In locations
in which the hydrology is not well known, tracing the path of such
chemicals into underground aquifers proves difficult.
About 98 percent of the oil entering the world's ocean
7
environment results from man's activities. Much of this oil results
27
from accidents. To estimate a probability distribution from spills ,
we extrapolated historical data for the 25-year period between 1975 and
2000. These spill probabilities most likely represent upper limits for
the number of large spills.
b. Crude Oil Distribution and Oil Imports
The crude oil distribution system has two main components-
tankers and pipelines. At present, Alaskan oil flows from offshore
56
-------
Table 3-13
IMPACT SCALING FACTOR FOR PRODUCTION ACCIDENTS
Scaling
Impact
Quantity
Units
Major and minor offshore
oil spills:
More than 100,000 barrels 4.3
Between 10,000 and 100,000 13
barrels
Between 2,000 and 10,000 39
barrels
Average amount of oil spilled
in:
Major accidents 140-530
Minor accidents 25
Mean number of spills
c
per 10 barrels per
day of production
27
over 25 years
Barrels per 10
barrels of production'
* 63
Approximate conversion factors: 10 B = 160,000 m
57
-------
collector lines to onshore storage before being shipped by tanker to
the lower 48 states. In the future, the Trans-Alaska Pipeline System
(TAPS) will bring oil from Northern Alaska to Valdez for storage and
tanker shipment to the lower 48 states. Pipelines transport most on-
shore oil, while tankers transport about 90 percent of the imported oil.
Currently, most Canadian crude oil arrives by pipeline, but recent
trends in Canadian policy make any significant crude oil shipments to
28. 29
the United States after 1982 unlikely.
The major impacts of the crude oil distribution system
result from construction of pipelines, tanker ports, and storage facil-
ities (tank farms), from the normal operations of tankers, and from the
abnormal operations of tankers, pipelines, and onshore storage facil-
ities.
(1) Pipelines
Table 3-14 presents the scaling factors for the
major impacts of future pipeline construction. Since the present TAPS
is limited in capacity to about 2.5-million B/D, a second pipeline
would be required to increase production up to the 3.4-million B/D from
the entire North Slope unde HG3.
The normal operation of pipelines results in minimal
impact. Most onshore pipelines are buried and unobtrusive. Offshore
pipelines at depths shallower than 200 ft are also buried and present
minimal impact. Even the labor force necessary to operate a pipeline
is small by comparison with employment for refining crude oil. For
32
example, TAPS will employ only 300 people during its operation. For
the entire oil industry, only about 5 percent of the total employment is
QC
for pipeline operation—about 20,000 in 1973.
58
-------
Table 3-14
IMPACT SCALING FACTORS FOR THE PIPELINE DISTRIBUTION SYSTEM
Scaling Factor
Impact
Pipeline construction: soil
disturbance, vegetation
removal
Air pollution from new pipelines
onshore and offshore
Particulates
S02
Hydrocarbons
NO
cox
4
Air pollution from a TAPS
Particulates
S02
Hydrocarbons
K0x
CO
Offsite impacts induced by
employment, urbanization, and
recreation demands
5
Onshore
Alaska
Quantity
8000
1.25
16
0.38
5-8.8
0.50
2
25
2
36
11
> 0
300
Units
Miles per 10 B/D increase in crude
oil supply
Tons/day per 1000 miles pipeline
Tons/day per 1000 miles pipeline
Employees per 1000 miles of pipeline
Employees per Trans-Alaska Pipeline
System
Assuming a second TAPS from Naval Petroleum Reserve Number 4 to Valdez.
Assuming 50 percent of the total pipeline mileage of 220,000 miles (AF 299, Table 20) is
used for crude oil transportation and assuming 13 million barrels per day of crude oil
transported by pipeline. Both numbers are for 1971.
•^ 30
A 24-inch diameter crude oil pipeline requires 150 horsepower per mile of pipe. Using
distillate fueled pumps which use 0.064 gallons of fuel per horsepower hour, we calculate
0.3 x 10 gallons of distillate fuel per 1 mile of pipe per day. Emission factors for
distillate fuel burning pumps are:
SOg—142 lbs/103 gal, particulates—15 lbs/103 gal, NOX—40-80 lbs/103 gal, CO—4 lbs/103 gal.
Source: Compilation of Air Pollutant Emission Factors, Third Edition, U.S. Environmental
Protection Agency, 1973.2*
4
Summary Report Air Quality: "Stations and Related Facilities for the Trans-Alaska Pipeline,"
Alyeska Pipeline Service Company, April 1974, p. 6-331 We assume a second TAPS would have
these same emission factors.
Based on the average number of employees per mile of pipe (16,000 for 220,000 miles of pipeline).
6
Permanent employment for TAPS is anticipated to be 300 people.
tApproximate conversion factors: 106B = 160,000 m
1 ton = 907 kg
1 mile = 1.6 km
59
-------
(2) Tankers
Normal tanker operations have the potential to
create more environmental impact than do pipeline operations. Table
3-15 highlights the major impacts and scaling factors for normal tanker
operations. The two major impacts are oil releases to the marine
environment and sewage disposal. Tankers, generally in port only a few
days, produce little sewage in U.S. waters. The control of tanker
ballast cleaning operations, which can be a major source of water pollu-
tion, cannot be controlled beyond the U.S. 12-mile limit.
Table 3-16 shows the major impacts from storage
facilities. TAPS storage is the only storage facility included since
most other oil storage is located at refinery sites.
(3) Tanker and Pipeline Accidents
Tanker groundings and collisions have resulted in
major oil spills, for example, the Torrey Canyon. Dragged anchors have
resulted in several pipeline breaks, which released large quantities
33
of oil. Table 3-17 indicates scaling factors for the tanker and pipe-
line accidents that are the most likely to occur.
c. Refineries
Many of the impacts of refineries come from the manpower,
materials, capital, and water requirements for its construction and
operation. To provide information on refineries, analagous to that
presented in the MCI scenario (Chapter 6) for the synthetic fuels
technologies, Table 3-18 shows the impact scaling factors for refinery
60
-------
Table 3-15
IMPACT SCALING FACTORS FOR NORMAL TANKER OPERATIONS
Impact
Quantity
Scaling Factor
Units*
Oil releases to the marine environment
from ballast cleaning
7
Alaska to Pacific Coast
13-270
Barrels/1,000,000 barrels transported
Sewage from tanker operation in coastal
waters^
Imports
11
Alaska
11
1.5
1
10 gal/tanker-day
3
10 gal/tanker-day
* 63
Approximate conversion factors: 10 B = 160,000 m
3 3
10 gal = 3.8 m
Tankers are in port about 36 hours.
-------
Table 3-16
IMPACT SCALING FACTORS FOR TRANS-ALASKA PIPELINE
STORAGE TERMINAL AND DEEPWATER TERMINAL
Scaling Factor
o
to
Impact
Land disturbance and land withdrawn
34
from alternative uses
34
Tankers
Potential oil spills from ruptured
storage tanks during an earthquake
Permanent employment
36
Quantity
800
3
44
100
Units
Acres per TAPS pipeline
t
100,000 Dwt tankers/day
510,000 barrels per tank
People
Approximate conversion factors:
1 acre = 4000 m
1 ton = 907 kg ,
1 barrel = 0.16 m"
Dwt = Dead weight tons
-------
Table 3-17
IMPACT SCALING FACTORS FOR CRUDE OIL PIPELINES
AND TANKER ACCIDENTS
Scaling Factor
w
Impact
Maximum oil spill from break in an offshore
pipeline
35
Maximum oil spill from break in TAPS
Maximum oil spill from breakup of a
200,000-Dwt tanker
Maximum oil spill from rupture of
storage tanks for TAPS
7
Major accidents: Imports
Alaska
n
Minor accidents: Imports
Alaska
Quantity Units
3,000 Barrels/mile of 24-inch pipeline
50,000 Barrels/break
1,400,000 Barrels/tanker
20,000,000 Barrels/TAPS storage facility
34
34-182
1.5
3
Barrels/million barrels transported
M
t!
Approximate conversion factors:
tDwt = Dead weight tons
1 barrel = 0.16 m
1 inch = 0.025 m
-------
Table 3-18
SCALING FACTORS FOR RESOURCE REQUIREMENTS
FOR 106-B/B REFINERY CAPACITY
Scaling Factors
o>
Item or Resource
Required
Construction
37
Quantity
Units
6
10 1973 $ (cumulative)
Man-years (cumulative)
Acres
3
10 tons
10 1973 $/year
Number permanent employees
3
10 acre-ft/year
m
* 2
Appropriate conversion factors: 1 acre = 4000m , 1 ton = 907 kg,
1 acre-ft = 1,200 m3, 106B = 160,000
Capital
38
Labor
10
Land
38
Steel
Operation
37
Capital
39
Labor
37
Water
10
Electric power
2,000
37,500
22,000
850
500
9,500
60
250
m
-------
construction and operation. Table 3-19 shows the major environmental
scaling factors for plant operation.
Refinery emissions are the major source of air pollution for
the reference case, even when the average emission rates for the well-
controlled, relatively low emission refineries of Los Angeles are used
in the calculations. Thus, the scaling factors in Table 3-19 reflect
well-controlled sources.
Refineries demand more water than any other element in the
reference case system.
Refineries also account for about one-third of the necessary
employment for the reference case, with crude oil production requiring
most of the remaining two-thirds of the employment. Many of the offsite
or indirect impacts from population in the reference case result from
refinery employment.
2. Environmental Impacts
a. Onshore Production
The environmental impacts from tertiary recovery which
will be the major source of new impacts onshore are shown in Table 3-20.
These impacts will be the drilling activity necessary to begin tertiary
*
recovery, the growth of a chemical industry to produce the necessary
chemicals for micellar flooding, and the air pollutant emissions from
oil combustion to produce steam for injection.
We have assumed a relative recovery rate for tertiary recovery by
various methods of: Thermal: 29%, Micellar: 58%, CO : 8%,
£
Hydrocarbon miscible: 5%
65
-------
Table 3-19
IMPACT SCALING FACTORS FOR 10 -B/D REFINERY CAPACITY
Scaling Factor
Impact
Disturbed land or land removed
from alternative uses
Solid waste production (sludge)
Wastewater production
Water pollution10
BOD
COD
Oil
Phenols
Suspended solids
Dissolved solids
Sulfides
Phosphorus
Nitrogen
10
Air pollution
Particulates
S02
Hyd rocarbons
N0x
CO
Offsite impacts induced by employ-
ment, urbanization, and recrea-
tion demands
«i9
Permanent employees
Total population
Quantity
4400
Units
Acres
10
20
80 Cubic yards per day
6 20
420 10 gallons per day
15 Tons/day
55 Tons/day
4.0 Tons/day
1.0 Tons/day
10 Tons/day
250 Tons/day
1.5 Tons/day
0.5 Tons/day
2.0 Tons/day
5.5 Tons/day
76 Tons/day
69 Tons/day
34 Tons/day
41 Tons/day
9500 People
32,500 Population multiplier
(6.5) times the number
of people'
Approximate conversion factors: 1 acre = 4000 m , 1 ton = 907 kg,
1 cubic yd = 0.76 m3.
Population multipliers are discussed in Chapter 23.
66
-------
Table 3-20
ENVIRONMENTAL IMPACTS FROM ONSHORE OIL PRODUCTION UNDER THE REFERENCE CASE
Impact Scaling Factora and Scenario Quantities
'Activity
Exploration
Production
Tertiary recovery
by all methods
Tertiary recovery
by chemical
methods40
Chemical require-
ments
Impact
Urbanization and
Induced population
Employees
Total population
Solid waste produced by
drilling
Land area disruption
by drilling
Urbanization and
Induced population
Employees
Total population
Wastewater production
Chemical production
Biopolymer and
Polyacrylamlde
Surfactants
(Hydrocarbon Sulfon-
ates)
Co-surfactants
Impact Scaling Factor
Quantity Units*
24 People/rig
6.5 People/employee
63 Tons/103 It
1 Acre/exploratory
well
13,000 People/employee
6.5
210 g/water/B oil
0.58 Total tertiary
recovery
1-8 Lbs/B oil
7-15 Lbs/B oil
4-10 Lbs/B oil
Scenario Quantity which
Determines Impacts Quantitative Indicator
1975 1985 2000 Units 1975 1985
* *
1,100 1,250 1,250 Rigs 25* 29
25* 29 29 10 employees 160 190
1975 - 2000 1975 - 2000
9.5 IO8 ft of 60
exploratory
well
1975 - 2000 t 1975 - 2000
190 IO3 wells ' 190
6
8.9 6.2 5.0 10 B/D 116 81
116 81 65 10 employees 750 520
8.9 6.2 5.0 IO6 B/D oil 1.9 1.6
0 3.3
0 3.5 4.0 IO6 B/D Tertiary 0 2.0
recovery
6
0 2.0 2.3 10 B/D 0 0.7 - 5.8
0 2.0 2.3 IO6 B/D 0 5.1 - 11
0 2.0 2.3 IO6 B/D 0 2.9 - 7.3
of Environmental
Impact
200O Units
3
29 10
190 IO3
C
io6
io3
3
65 10
420 IO3
1.1 IO6
3
4.0 10
2.3 IO6
0.8 - 6.7 IO9
5.9-13 IO9
3.4 - 8.4 IO9
people
people
tonst
acres
employees
people
g/D
B/D
B/D
Ibs/yr
Ibs/yr
Ibs/yr
(Isopropanol)
Page 1 of Table 3-20
-------
Table 3-20
ENVIRONMENTAL IMPACTS FROM ONSHORE OIL PRODUCTION UNDER THE REFERENCE CASE
lnp»ct Scaling Factors and Scenario Quantities
Activity
Tertiary recovery 4Q
by thermal methods
Production
Impact
Impact
Quantity
Scaling Factor
41
Units
0.29 Total Tertiary
Air pollution
Participates
SO,
NO*
CO
Hydrocarbons
Land disruption
Solid vaste production
0.12
1
0.2 - 0.4
0.02
0.02
1
3
recovery
3 R
10 ton»/10° B oil
recovered
11
Scenario Quantity which
Determines Impacts Quantitative
1075 198S 2000 Unit! 1975
0 3.5 4.0 106 B/D 0
ft
0 1.0 1.2 10 B/D 0
0
Indicator
1985
1.0
0.12
1
" 0 0.2 - 0.4
it
"
Acres/development
well
Times the amount of
0
0
1975 - 2000 1975
570 103 develop-
ment well
1975 - 2000 197B
70 10° tons
0.02
0.02
- 2000
570
- 2000
210
of Environmental
Impact
*
2000 Units
1.2 106
0.14 10
1.2
0.24 - 0,48
0.02
0.02
103
106
B/D
tona/D
"
it
acres
tons11
00
waste produced by
exploration
Approximate converalon factors: 1 gal - 3.79 x 10~3m3, 1 ton • 907 kg, 1 acre . 4.05 x 103 «2, 1 ft - 0.305 m. 10s B •= 160,000 m3, 1 pound « 0.454 kg, 1 mile = 1.61 km
Accumulative for period Indicated.
Applies to 1980 only, not 1975.
Page 2 of Table 3-20
-------
Tertiary recovery, which requires many new wells in fields
already producing under primary and secondary recovery, will bring an
influx of drill rigs and well development personnel. This influx of
personnel and their families can be expected to produce boom-town
conditions in small communities that border large oil fields. For
example, West Texas and Rock Springs, Wyoming, currently experience
considerable oil-related activity as a result of recent crude oil
price increases.
The most significant potential for adverse environmental
effect will result from the production and use of large quantities of
chemicals necessary for tertiary recovery (up to 10 billion Ibs/yr
L4.5 x 10 kg/yrj of some of the chemicals). Many of these chemicals
are hazardous; polyacrylamide, for example, is carcinogenic. The
isopropanol production shown in Table 21 for example, will, in the year
2000, be at about the level of today's methanol production. At present,
no large-scale commercial production capacity exists for manufacturing
these chemicals.
With onshore production likely to begin a long-term decline
3,6,41
sometime in the next few decades, and with production unlikely
to increase significantly up to the onset of long-term decline, little
onshore construction directly related to production can be expected.
For example, pipeline construction will be confined mainly to that
necessary for the transport of oil from tanker ports and from new off-
shore and Alaskan oil fields.
Total oil industry employment directly related to onshore
production should also remain constant or decline with production
through the end of thjs century.
69
-------
b. Alaska Production
Under the reference case, Alaska undergoes the most substantial
increase in oil production since the current production of about 200,000
3
B/D (32,000 m /D) is projected to grow to over 3,400,000 B/D (540,000
3
m /D) by the year 2000—far greater than any increase projected for
other regions. The environmental impacts from this production increase
are shown in Table 3-21.
The large projected rise in oil production employment in
Alaska, from the current 3,000 to 57,000 by the year 2000, suggests
that this state, with a current population of only about 350,000,
will experience considerably more population related impacts than any
other region under the reference case. This is particularly true if
the 6.5 employment multiplier can be used to estimate the total increase
in population of over 370,000 people. These impacts will be concentrat-
ed along the coastline of the Gulf of Alaska, along the North Slope,
and in the Fairbanks region since it is the only large city close to
the North Slope.
With the largest area of unspoiled wilderness in the nation
and the second largest volume of crude oil reserves of all the states
(Texas has more), Alaska will likely become a legal and institutional
battleground for advocates of wilderness values and advocates of re-
source development. Opening the road to Prudhoe Bay to the public will
allow more people access to northern Alaska than ever before, and
perhaps will result in more environmental damage than the current TAPS
construction project or the construction of a second pipeline as
required in the reference case.
Alaskan offshore production can be expeoted to result in oil
spills off the coast. Two very large oil spills (over 100,000 barrels
70
-------
Table 3-21
ENVIRONMENTAL IMPACTS ON ALASKA UNDER THE REFERENCE CASE
Impact Scaling Factors and Scenario Quantities
Activity
Exploration
(normal)
Impact
Urbanization and
induced population
Employment
Onshore
Offshore
Total population*
Solid waste production
Onshore
Offshore
Onshore land area
disruption
Offshore
Urbanization and
induced population
Employees
Total population
Low-level oil releases
to the offshore marine
environment
Wastewater production
from onshore production
Onshore land area
disruption
Offshore land area
disruption
Impact Scaling Factor
Quantity Units
12 People/rig
60 People/rig
6.5 People/employee
63 Tons/103 ft of well
63 Tons/103 ft of well
5 Acres/well
3,000 Acres/well
13,000 Employees per
10 B/D
6.5 People
9 B per 106 B/D
production
210 gal/B oil
65 103 acres per
106 B/D oil
production
3 10 acres per pro-
duction platform
Scenario Quantity which
Determines Impacts
1975 1985 2000 Vnlts*
125* 150 150 Rigs
52* 110 110 Rigs
5,000* 8,000 8,000 Employees
1975 - 2000
6600 103 ft of well*
3800 103 ft of well*
1975 - 2000
660 Number of ex-
ploratory wells
1975 - 2000
380 Number of explor-
atory wells drilled
0.2 3.6 4.4 106 B/D
production
2.6 47 57 103 employees
0.2 0.5 0,98 106 B/D
0 3.1 3.4 106 B/D
0 3,1 3.4 106 B/D oil
12* 25 25 Production platform
Quantatlve Indicator
1975 1985
1,500* 1,800
3,100* 6,500
33* 52
1975 - 2000
0.42
0.24
1975 - 2000
3300
1975 - 2000
1.1
2.6 47
17 300
1.8 4.5
0 O.S5
0 200
39* 75
of Environmental Impact
2000 Units*
1,800 Employees
6,500 Employees
52 10 people
106 tons*
106 tons
Acres
106 acres*
3
57 10 employees
370 103 people
8.6 B/D oil
0.71 109 gal/D
220 103 acres
75 103 acres
Page 1 of Table 3-21
-------
Table 3-21
ENVIRONMENTAL IMPACTS IN ALASKA UNDER THE REFERENCE CASE
lupact Scaling Factom and Scenario Quantities
to
Activity
Production
(normal)
Exploration
(abnormal
operation!)
Production
(abnormal
operational
Impact
Solid waste production
Onshore
Offshore
Blowouts and accidental
releaae of oil Into the
environment. Bird louses,
oiled beachei, fire, loaa
of life.
Onshore
Offshore
Size of accidental oil
spills from offshore
operatlona
Greater than 100,000 B
Between 10,000 B
and 100,000 B
Size of oil spills
Between 2,000 B and
10,000 B
Impact Scaling factor
*
Quantity Units
3 Tines total solid
w«ate from explor-
ation
3 "
0.4 per 103 wells
drilled
0.3 per 103 wells
drilled
4.3 Mean number of
gpllls per 106-B/D
production over
29 years
13 Mean number of
spills per 108-B/D
production over
29 years
39 Mean number of
spills per 108-B/D
production over
2f> ye&rs
Scenario Quantity which
Determine* Impacts
*
1975 1983 2000 Units
1975 - 2000
6 t
0.42 10 tons
6 f
0.24 10 tone
1975 - 2000
660 Number of wells
drilled
280 Jtuo.be r of wells
drilled1
1975 - 2000
0.5 (Average produc-
tion )108 B/D*
0.5 (Average produc-
tion) 106 BA>1
0,5 (Average produc-
tion) 10* B/Tjt
Quantatlve Indicator oi Environmental Impact
1975 1989 2000 Units*
1975 - 2000
1.3
0.72
1975 - 2000
0.3
0.1
1975 - 2000
2.2
6.5
19
106 ton
109
tons'
Mean number
of blowouts
Mean number
of very large
oil spills'
Mean number
of large
Mean number
of moderately
large spills
over 25 years'
Page 2 of Table 3-21
-------
Table 3-21
ENVIRONMENTAL IMPACTS IN ALASKA. UNDER THE DEFERENCE CASE
Impact Scaling Factors and Scenario Quantities
CO
Activity
Pipeline construc-
tion over 1000
miles of terrain
from Naval Petrol-
eum Reserve Number
4 to Valdez.
Pipeline and
distribution
system
(abnormal
operations)
Impact
Air pollution from
second TAPS
Participates
S02
Hydrocarbons
NOX
CO
Induced urbanization
population and employ-
ment
Employees
Total population
Land disruption through
construction of new oil
storage facility for
TAPS Number 2.
Potential oil spill
from rupture of storage
tanks at Valdez
Potential oil spill
Impact Scaling Factor
Quantity
1000
2
25
2
36
11
300
6.5
800
510,000
50,000
Units
Mlles/TAPS
Tona/day
Tone/day
Tons/day
Tona/day
Tons/day
People/TAPS
People/employee
Acres
B/tank
B/rupture
Scenario Quantity which
Determines Impacts
19T5 1985 2000 Units
0 3.1 3.4 106 B/D prod-
uction
Oil Number of
" " " additional
" " " TAPS
it ti 11
it ii it
0 22 Number of TAPS
0 600 600 Employees
0 11 Number of new
TAPS
0 44 44 Number of
tanks
Quantatlve Indicator of Environmental Impact
1975 1985 2000
0 1,000 1,000
0 22
0 25 25
0 22
0 36 36
0 11 11
0 600 600
0 4,000 4,000
0 BOO 800
1980 - 2000
20
0.05
Units
Tons/day
Tons/day
Tons/day
Tons/day
Tons/day
Employees
People
Acres
Maximum
potential
oil splll-
106 B
"
from rupture of TAPS
Potential oil spill
from tanker grounding
1.5 x 106B B/tanker
1.5
Approximate conversion lectors: 1 gal = 3.79 x 10 3m3, 1 ton = 907 kg, 1 acre = 4.05 x 103 m2, 1 ft = 0.305 m, 10^ = 160,000 ra3, 1 pound = 0.454 kg, 1 mile = 1.61 km.
Cumulative for period Indicated.
*
Applies to 1980 only, not to 1975.
§
Employees plus associated population.
Page 3 of Table 3-21
-------
of oil) can be expected as the mean number over the next 25 years. All
Alaskan crude oil will probably be shipped to the West Coast states by
tanker; which implies oil spills and sewage production that occur from
tanker operations may impact the Pacific coastline from Alaska to Calif-
11
ornia.
Oil spill from earthquake damage to the Valdez storage facility,
with its 20-million barrel capacity, is possible, particularly with
the frequency and severity of tremors along the Gulf of Alaska (Valdez
was destroyed by the 1964 earthquake).
A second TAPS for transportation of oil from Naval Petroleum
Reserve Number 4 (NPR4) to Valdez is required sometime in the 1980s.
Considerable impact will be associated with its construction although
additional road construction would be needed only across the North Slope
tundra from the present pipeline corridor to NPR4.
Many of the impacts in Alaska, although quantitatively less
than for onshore production (compare similar categories in Tables 3-20
and 3-21), will be severe in Alaska because relatively few areas will
be impacted due to the geographic concentration of resources. Oil
production from Alaska will increase many fold under the reference case
and the impacts can be expected to rise proportionately.
Between 1899 and 1973, 13 earthquakes with magnitude over 7.0 on the
Richter Scale have occurred. *
74
-------
c. Offshore Production with Attendant Transport
and Refining Operations
The impacts from refinery construction under HG3 are given
for two cases: (1) in which all imported oil is unrefined, and (2) in
which 50 percent of the imported oil is already refined. If all import-
ed oil is in the form of refined products, then no new refinery capacity
is required. Table 3-22 shows the environmental impacts from offshore
production, Tables 3-23 and 3-24 show the requirements for additional
refinery construction and operation, and Table 3-25 shows the environ-
mental impacts from refinery operation.
The coastlines receive a large share of the environmental
impacts under the reference case, not only because considerable crude
oil production will take place offshore, but because the possibility of
large-scale oil spills from production and tanker accidents adds ecolog-
ical disaster potential without analogy in onshore oil production. New
refinery capacity is likely to be built along the coastlines at loca-
tions at which the increase in crude oil production under HG3 will be
delivered. Unless all imports are in the form of refined products,
additions to refinery capacity will be required under HG3. Expansion
of existing refineries (already concentrated on the coastal regions,
particularly the Gulf coast) will cover much of the projected needs.
The mean number of large oil spills (over 100,000 barrels)
under HG3 is projected to be 13 over the next 25 years.
Employment-related impacts from offshore oil production will
triple under HG3. Offshore-production-related employment will grow from
18,000 to 52,000. Of course, the impacts related to this employment
will be dispersed over the Atlantic, Gulf, and Pacific coasts.
The coastal regions experience the most pipeline construction
under the reference case. Offshore solid waste from well drilling will
75
-------
Table 3-22
ENVIRONMENTAL IMPACTS FROM OFFSHORE DEVELOPMENT
AND TANKER OPERATIONS UNDER THE REFERENCE CASE.
Impact Scaling Factor* and Scenario Quantities
0)
Scenario Quantity wblch
Activity Impact
Exploration Urbanization and
Induced population
along coastlines
Employees
Total population
Tons of drill cuttings
Offshore Isnd disrupt-
Ion
Production Induced urbanization
and employment
Employees
Total population
Tons of drill cuttings
Offahore land dlarup-
tion
Low concentration oil
releases to the marine
environment
Atlantic DCS
Gulf DCS
Pacific DCS
I Attract
Quantity
100
fl.S
63
3,000
13,000
6.5
3
3,000
9
9
9
Scaling Factor
Units
Employees/rig
People per
employee
Tons/103 ft of
exploratory well
Acres per explora-
tory well
Employees per
10e B/D
People per
employee
Times that produced
by exploration
Acres/production
platform
B/10* B oil
produced
B/108 B oil
produced
B/106 B oil
Determines
1975 1983 2000
370* 500 500
37* 52 52
1975 - 2000
11
11
1,4 3.0 4.0
18 39 52
1975 - 2000
6.9
150* 200 200
0 0.04 0.8
1.3 2.3 2.0
0.058 0.6 1.2
Impacts
*
Units
Riga
103 employees
107 ft of well*
103 wells1
10s B/D
10 employees
t
108 tons
Production
platforms
10s B/D oil
production
106 B/D oil
production
10* B/D oil
Quantative Indicator of Environmental Impact
1975 1985 2000 Units
37* 52 52 103 employees
240* 340 340 103 people
197S - 2000
6.9 106 tons'*'
11 106 acres*
18 39 52 1C3 employees
117 254 338 103 people
1975 - 2000
21 106 tons*
0.5 0.6 0.6 106 offshore
acres
0 0.36 0.54 B oil per day
12 21 18 B oil per day
0.5 5.4 11 B oil per day
produced
production
Page 1 of Table 3-22
-------
Table 3-22
ENVIRONMENTAL IMPACTS FROM OPPSHORE DEVE1OPMENT
AND TANKER OPERATIONS UNDER THE REFERENCE CASE.
Impact Scaling Factors and Scenario Quantities
Activity
Exploration
(Abnormal
activities)
Production
(Abnormal
activities)
Scenario Quantity which
Impact Impact Scaling Factor Determines Impacts
* *
Quantity Units 1975 1985 20OO Units
1975 - 2000
Blowouts and accidental 0.3 per 1000 exploratory 11,000 Exploratory
oil releases to the wells drilled wells*
marine environment:
bird deaths, spoiled
beaches, damage to
fisheries, cleanup
costs, fire and equipment
damage
Sizes and frequency of
probable number of oil
spills:
QuantatIve Indicator of Environmental Impact
1975 1985 2000 Units*
Greater than 100,000 B
Between 10,000 B and
100,000 B
Between 2,000 B and
10,000 B
4.3 Mean, number of spills
per 106 B of production
per 25 years
13 Mean number of spills
per 10 -B/D production
over 25 years
39 Mean, number of spills -
per 10 -B/D production
3,0
3.0
3,0
1975 - 2000
Average over
25 years
106-B/D oil
production
Mean number
of blowouts
expected*
Mean number
of very large
spills over
25 years
Mean number
of large
spills over
25 years
Mean number
of moderately
large spills
over 25 years
Crude Oil Pipe- Offshore pipeline con- 8,000
line System struction - seabed dis-
turbance and potential
navigational hazard
Miles of pipeline per
106 B/D Increase in
crude oil supply
1.7
2.r
10° B/D increase
ever 1974 prod-
uction
10-* miles of
offshore pipe-
line
Page 2 of Table 3-22
-------
Table 3-22
ENVIRONMENTAL IMPACTS FROM OFFSHORE DEVELOPMENT
AND TANKER OPERATIONS UNDER THE REFERENCE CASE.
Impact Sealing Factors and Scenario quantities
00
Activity Impact Impact Scaling Factor
*
quantity Units 1975
Crude Oil Pipe- Air pollutant emissions
line System Increase from new off-
shore crude oil pipe-
lines:
Particulates 1.25 Tons per 10 miles 0
of pipeline
SOj 16
Hydrocarbons 0.38
NOX 5-8.8
CO O.SO
Urbanization and assoc-
iated population; re-
creation demands
Employees 70 Employees per 1000 0
miles of new pipeline
Total population 6.5 People/employee 0
Tanker Operations Oil release to the marine
environment from ballast
cleaning operatlona
Alaskan Pacific Coast 13-270 B/106 B transported 0.2
oil shipped to west from Alaska
coast ports
Sewage produced in
tankers :
By Imports 1.5 103 gal/tanker 4
By Alaskan oil 1.0 103 gal/tanker - day 3
tankers
Probable oil spills
Major
Imports 34 B/10 B transported 6.0
Alaskan oil 34-180 B/106 B transported 0.2
Scenario Quantity which
Determines Impacts
e
1985 3000 Units
14 22 103 miles of
pipeline
"
'*
"
14 22 10OO miles new
pipeline
0.9 1.5 103 employees
3.8 4.4 10B B/D oil
from Alaska
7.5 12 200,000 dwt
tankers/day
40 50 Tankers
11.5 18.4 106 B/D oil
transported
3.6 4.4 106 B/D oil
transported
Q^antatlve
1975
0
0
0
0
0
2.6
to
54
8
3
200
6.8
to
36
Indicator
1985
18
220
6.3
70-120
7
0.9
5.9
47
to
970
11
40
390
120
to
650
of Environmental Impact
2000
28
390
8.4
110-190
11
1.5
10
57
to
1200
18
50
630
150
to
790
+
Units
Tons/day
11
"
"
10 employees
103 people
B/D
103 gal/D
103 gal/D
B/D oil
B/D oil
Page 3 of Table 3-22
-------
Table 3-22
ENVIRONMENTAL IMPACTS FROM OFFSHORE DEVELOPMENT
AND TANKER OPERATIONS UNDER THE REFERENCE CASE.
Impact Scaling Factors and Scenario Quantities
Activity
Impact
Tanker operations Probable oil spills
Minor
Imports
Alaskan oil
Impact Scaling Factor
Scenario Quantity which
Determines Impacts
1.5
3
Units
B/10 B transported
B/10 B transported
1985
2000
6.0 11.5 18.4 10 B/D oil
transported
0.2 3.6 4.4 106 B/D oil
transported
Qualitative Indicator of Environmental Impact
1975 1985 2000 Units
9
0.6
17
11
28 B/D oil
13 B/D oil
u>
Approximate conversion factors: 1 gal = 3.79 x 10 m
1 ton = 907 kg
1 acre = 4.05 x
1 ft = 0.305 m
106B = 160,000 m3
1 pound =: 0.454 kg
1 mile = 1.61 km
t
Cumulative lor period indicated.
*
Applies to 1980 only, not to 1975.
Page 4 of Table 3-22
-------
Table 3-23
NEW REFINERY REQUIREMENTS FOR REFERENCE CASE OVER AND ABOVE 1975 REFINERY CAPACITY
IMPORTS ARE CRUDE OIL ONLY
Impact for Year
oo
o
Data and Assumptions
Production Schedule: Refinery Capacity
In 10 Barrels per Day
Inputs
Items
Construction
Capital
Labor
Steel
Land
Operation
Operating costs
Labor force
Water
Electric power
and Outputs
Units
6
10 1973 $ (cumulative)
Man-years (cumulative)
3
10 tons (cumulative)
3
10 acres
106 1973 $/year
Number of people
10 acre-ft/year
MW
increase over 1975
Scaling Factors
per 106 B/D
of new capacity
(in units specified)
2,000
38,000
850
22
500
9,500
60
250
1975 1985
0 12.0
0 2.4 x 104
0 4.5 x 105
0 1.0 x 104
0 260
0 6 x 103
0 1.1 x 105
0 720
0 3,000
2000
19.0
3.8 x 104
7.1 x 105
1.6 x 104
420
9.5 x 103
1.8 x 105
1,100
4,800
Approximate conversion factors: 1 gal = 3.79 x 10~ m , 1 ton = 907 kg, 1 acre = 4.05 x 103 m ,
1 ft = 0.305 m, 106B = 160,000 m3, 1 pound = 0.454 kg, 1 mile = 1.61 km
-------
Table 3-24
NEW REFINERY REQUIREMENTS FOR REFERENCE CASE OVER AND ABOVE 1975 REFINERY CAPACITY
(50 PERCENT OF IMPORTS ARE REFINED PRODUCTS)
Impact for Year
Data and Assumptions
Production Schedule: Additional Capacity
Inputs
Items
Construction
Capital
Labor
Steel
Land
Operation
Operating costs
Labor force
Water
Electric power
and Outputs
*
Units
106 1973 $ (Cumulative)
Man-years (cumulative)
10 tons (cumulative)
3
10 acres
106 1973 $/year
Number of people
103 acre-ft/year
MW
in Units of 106 B/D
Scaling Factors
6
for a 10 B/D Plant
(in units specified)
2,000
38,000
850
22
500
9,500
60
250
1975
0
0
0
0
0
0
0
0
0
1985 2000
5.9 9.3
1.2 x 10 1.9 x 104
2.2 x 105 3.5 x 105
5.0 x 103 7.9 x 103
130 200
3 x 103 4.7 x 103
5.6 x 104 8.8 x 104
350 560
1,500 2,300
Approximate conversion factors: 1 gal = 3.79 x 10~ m , 1 ton = 907 kg, 1 acre = 4.05 x 103 m ,
1 ft = 0.305 m, 10^ = 160,000 m3, 1 pound = 0.454 kg, 1 mile = 1.61 km
-------
00
Table 3-25
ENVIRONMENTAL IMPACTS FROM THE OPERATION OK NEW REFINERIES UNDER THE REFEReXCE CASE.
Impact Scaling factors and Scenario Quantities
Activity Impact
Refineries Wavtewater production
Coastal regions
Water pollution
BOD
COD
Oil
Phenol*
Suspended solid*
Dissolved solid*
Sulfidea
Phosphorus
Nitrogen
Air pollution
Particulates
soa
Hydrocarbons
NOX
CO
Impact Scaling Factor
Quantity
420
15
55
4
1
10
250
1.5
0.5
2.0
5.3
76
69
34
41
*
Units
108 «al/D
per 106B/D
refined
Tona/D per
108 B/t
Tona/D per
109 B/D
Tona/D per
106 B/D
Ton«/D per
108 B/D
Tona/D per
106 B/D
Tona/D per
106 B/D
Tona/D per
109 B/D
Tona/D per
10s B/D
Tons/D per
106 B/D
Tona/D per
106 B/D
Tona/D per
106 B/D
Tons/D per
106 B/D
Tone/D per
10* B/D
Tona/D per
109 B/D
1973
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Scenario
Deteti
1985
5.9
12
5.9
12
5.9
12
5,9
12
5,9
12
5.9
12
5.9
12
5.9
12
5.9
12
5.9
12
5.9
12
5.9
12
5.9
12
5.9
12
5.9
12
Quantity which
mines Impacts
2000
9.3
19
9.3
19
9.3
19
9.3
19
9,3
19
9.3
19
9.3
19
9.3
19
9.3
19
9.3
19
9.3
19
9.3
19
9,3
19
9.3
19
9.3
19
Units
106 B/D
108 B/D
106 B/D
106 B/D
106 B/D
106 B/D
106 B/D
106 B/D
106 B/D
106 B/D
106 B/D
108 B/D
106 B/D
106 B/D
106 B/D
Quantatlve Indicator of Environmental
Imports
refined
In U.S.
50%
CK
50%
OX
50%
0%
50%
0%
50%
0%
50%
0%
50%
0%
50%
0%
50%
0%
50%
0%
50%
0%
50%
0%
50%
0%
50%
0%
50%
0%
1975
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1985
2.5
5.0
89
180
320
660
24
48
5.9
12
59
120
1,500
3,000
8.9
18
3.0
8.0
12
24
32
66
450
910
410
830
200
410
240
490
2000
3.9
8.0
140
290
510
1,000
37
76
9.3
19
93
190
2,300
4,800
14
29
4.7
9.5
19
38
51
100
710
1,400
640
1,300
320
650
380
780
Impact
Units
109 gal/D
Tons/D
Totis/D
Tons/D
Tons/D
Tons/D
Tons/D
Tons/D
Tons/D
Tons/D
Tons/D
Tons/D
Tons/D
Tons/D
Tons/D
Page 1 of Table 3-25
-------
Table 3-25
ENVIRONMENTAL IMPACTS FHOM THE OPERATION OF NEW REFINERIES UNDER THE REFERENCE CASE.
Impact Scaling Factors and Scenario Quantities
Activity Impact Impact Scaling Factor
Quantity
Refineries Employment, urbanization,
and recreation
Employment 9,500
Total population 6.5
*
Units
Employees
per 106B/D
capacity
People per
employee
1975
0
0
0
0
3 ena 1
Determines Impacts
1989
5.9
12
56
114
*
2000 Units
9.3 106 B/D
19
88 Employees
180
Qualitative Indicator of Environmental
Imports
In U.S.
50%
0%
50%
0%
1975
0
0
0
0
1985
56
114
360
740
2000
88
180
570
1,200
Impact
Units
10 employees
103 people
00
to
Approximate conversion factors: 1 ga! = 3.79 x 10~3 m3
1 ton = 907 kg
1 acre = 4.05 x 103 m2
1 ft » 0.30S m
106 B « 160,000 m3
1 pound =; 0.454 kg
1 mile = 1.81 km
Page 2 of Table 3-25
-------
create unconsolidated sediment and poor habitat around the sites of
offshore drilling; the volume will be about 200 ft by 200 ft and 1 ft
thick around the base of each drill site. However, this amount of
solid waste is dwarfed by the amount of sludge produced by coastal
cities (e.g., New York).
Employment-related impacts from refinery construction and
operation could be more substantial than for crude oil production.
Refinery employment under HG3 could double from 150,000 in 1975 to
over 300,000 in 2000 if all imports are in the form of crude oil.
The coastal regions will experience impacts that are quanti-
tatively similar to the impacts from onshore production (compare similar
categories in Tables 3-21 and 3-22); however, the impacts will be con-
centrated in a smaller region. In addition, pipeline construction,
refinery construction and operation, and increased tanker activity
will bring impacts to the coastal regions unlike those in onshore
production. Tables 3-22 and 3-25 support the conclusion that under
the reference case the coastal regions will experience the most
significant air pollution increases of the three reference case regions
and the greatest potential for large oil spills, in addition to major
employment-related impacts.
84
-------
APPENDIX A
QUANTITIES OF OIL RESOURCES AND RESERVES
The distinction between resources and reserves is often misunder-
stood. In general, resources refer to physical quantities, while
reserves implies recoverability of a fraction of the resource as deter-
mined by prevailing economics and technology. Figure A-l illustrates
the relationship of the various classes of oil resources and reserves.
2
The quantities of the important classes of resources and reserves are:
g
* 440 x 10 barrels of crude oil resources identified in the
United States as of January 1975.
9
• 106 x 10 barrels of crude oil resources produced as of
January 1975.
g
• 40 x 10 barrels of discovered crude oil resources classified
as economically producible (demonstrated reserves) as of
January 1975.
g
• 82 x 10 barrels of undiscovered oil resources estimated
by the USGS as producible with 50 percent certainty at 1973
crude oil prices (assumes 32 percent recovery of the undis-
covered resources).
9
* Up to an additional 130 x 10 barrels of oil of the resources
(discovered and undiscovered), which may be recoverable with
advanced recovery techniques (up to 50 percent recovery of the
original resources both discovered and undiscovered) at much
higher crude oil prices.
Much of the oil resource cannot be recovered because of the difficulties
of extracting oil from the porous oil-bearing rock strata, which can
lie up to 20,000 ft (6000 m) underground. Estimates of the percentage
of the resource eventually producible generally vary between 30 and 50
40
percent. Primary recovery (producing oil from self-pressured fields
85
-------
ECONOMIC
SUB-
ECONOMIC
DENTIFIED I
Demonstro led
MEASURED
J
INDICATED
RESERVE
UNDISCOVERED
Inferred
1
5 1
1
r\c_owurA^ii.o
1
1
1
I
INCREASING DEGRFF OF
ECONOMIC FEASIBILITY
INCREASING DEGREE OF GEOLOGIC ASSURANCE
FIGURE A-
DIAGRAMATIC REPRESENTATION OF PETROLEUM
RESOURCE CLASSIFICATION BY THE U.S. GEOLOGICAL
SURVEY AND THE U.S. BUREAU OF MINES
86
-------
or from artificially pumped fields) and secondary recovery (producing
oil by pressurizing the field through water injection or through natural
gas injection) together generally achieve about 30 percent recovery of
the original resource. Advanced recovery or tertiary recovery (produc-
ing oil by injecting solvents, steam, CO , or other chemicals or producing
2
oil by any technique not classed as primary or secondary recovery) may
achieve an additional 20 percent recovery of the initial resource. This
additional recovery percentage varies considerably among actual fields—
in some cases 90 percent recovery can be achieved. Unfortunately,
however, no general agreement exists over the percentage of the resource
40
that can be recovered by advanced recovery techniques.
Today's technology and economics make 70 percent of the resources
either too expensive to produce or impossible to produce. For future
oil production, increased oil prices can make some of the last 70 per-
cent of the resources available. However, it takes considerable time
to bring advanced recovery into widespread use and significant production
by advanced recovery cannot begin for at least a decade.
Considerable controversy surrounds the quantity of undiscovered oil
2
resources, although recent estimates agree remarkably. Figure A-2
shows several of the important estimates. In mid-1975, USGS estimated
that undiscovered ultimately recoverable oil resources (at 1973 crude
oil prices) consist of between 50 and 127 billion barrels with the mean
estimate of 82 billion barrels (assuming 32 percent recovery of the
undiscovered resources). A recent study by the National Academy of
Sciences reports that about 113 billion barrels remain to be found
42
and produced. These estimates implicitly assume recovery at 1973
prices.
87
-------
U.S. UNDISCOVERED RECOVERABLE RESOURCES OF LIQUID HYDROCARBONS
ONSHORE AND OFFSHORE
i ..i
ALASKA
8II.Kor«
n inert
Of UKor«
p., ho"
25B
ALASKA A"ND LOWER -18
-;,
I 3)
'••'
NAS
1975
'4)
1975
' 5)
I
Mobil
1974
(6)
'..
Rubber!
I960 1974
(7) (8)
UNDISCOVERED OIL AND NO L
USG
1965
( 3)
•
50-127
Mean
B2
USGS Hi,:
1975 1974
(5) (8)
•UNDISCOVERED OIL-
_ZOO
150
1O5
in
USGS AAPG USGS NPC
1965 197! 1975 1973
(3) (5) (10)
1970
'9)
•—UNDISCOVERED AND-*-
INFERRED (PROBABLE) OIL
i (i
50
Source- U.S. Geological Survey, Circular 725
( I ) Theobald and others, USGS Circ.650 (1972). Includes water depth to 2,500 m (8,200 ft).
( 2 ) USGS News Release (March 26, 1974). Includes water depth to 200 m (660 ft)
( 3 ) Hendricks, USGS Circ. 522 (1965). Adjusted through 1974. Includes water depth to 200 m ( 660 ft).
( 4 ) National Academy of Sciences, Mineral Resources and the Environment," (1975). Water depth not indicated.
( 5 ) USGS "Mean," Oil and Gas Branch Resource Appraisal Group (1975). Includes water depth to 200 rn (660 ft).
(6) Mobil Oil Corp,, "Expected Value," Science (12 July 1974). Includes water depth to 1,830 m (6,000ft).
( 7 ) Weeks, L.G., Geotimes (July-August I960). Adjusted through 1974. Water depth not indicated.
( 8 ) Hubbert, M. K., Senate Committee (1974). Includes water depth to 200 m (660 ft).
(9) American Association Petroleum Geologists Memoir 15, (1971); National Petroleum Council, "Future Petroleum Provinces of
the United States," (1970). Some areas are excluded from this estimate. Includes water depth to 2,500 m (8,200 ft).
(10) National Petroleum Council, "U.S. Energy Out look--Oil and Gas Availability," (1973). Includes water depth to 2,500 m (8,200 ft),
FIGURE A-2. COMPARATIVE ESTIMATES OF OIL RESOURCES IN THE UNITED STATES
-------
Thus, taking into account reserves, the USGS estimates that, at 1973
prices, recoverable resources yet to be produced amount to about 120
billion barrels. If advanced recovery could be applied to the remaining
discovered and estimated undiscovered resources so that 50 percent of
the resource could be produced, the recoverable resource, which could
actually be produced, would be about 250 billion barrels. More detailed
estimates of the oil recoverable by advanced techniques are not available
and the 250 billion barrels must, at this time, be viewed as the most
credible upper limit to the amount of resources left to be produced.
Furthermore, tertiary recovery is a slow process which takes many years
to complete in a given field but -it contributes to overall oil product-
ion by maintaining production rates higher and longer than possible
under long-term primary and secondary recovery. If today's oil prices
are maintained, then the limits of the reserves (120 billion barrels)
virtually assure that U.S. crude oil production will begin a long-term
decline in the early 1980s (completion of TAPS will stave off the decline
in U.S. production rate for 5 to 8 years). Higher crude oil prices
can extend the reserves to a maximum of 250 billion barrels, but because
of the long time required to bring tertiary recovery projects up to full
production and the generally slow rate of recovery by tertiary methods,
production rates during the late 1980s and thereafter for the nation as
a whole are unlikely to increase beyond those achievable in the early
1980s. Increasing crude oil prices will have the long-term effect of
preventing declines in production, but because of the limits of the
resource base now projected, substantial increases in future crude oil
production rates would seem impossible.
89
-------
APPENDIX B
METHOD FOR HG3 REGIONAL SUPPLY PROJECTION
The limitations of the oil resource base discussed in Appendix A
help determine a credible upper limit to the future production rate from
U.S. resources. Of the 120 billion barrels available at 1973 oil prices
and producible by primary and secondary recovery, about half of this
amount is physically producible by the year 2000 if prices remain constant
in 1973 dollars. Thus, cumulative production of more than about 60
billion barrels by the year 2000 requires much higher crude oil prices
and the application of advanced recovery to many fields. Indeed,
physical considerations together with the new USGS estimates imply that
crude oil production rates past the year 2000 cannot exhibit long-term
increases, not even a constant production rate.
With these limitations imposed on the quantity and the rate at which
oil can be recovered, we selected from among the EPP scenarios of domestic
oil production in the absence of synthetic crude oils scenario HG3, which
has the lowest cumulative production between 1975 and 2000 and a non-
increasing rate of domestic production between 1985 and 2000. The re-
mainder of the scenarios in Table 3-1 imply that the rate of domestic
production increases to the year 2000 and beyond.
Scenario HG3 itself requires that about 70 billion barrels of oil
be produced by advanced recovery techniques by the year 2000. Since
cumulative production over the last 100 years has only been 106 billion
barrels using conventional oil recovery techniques, the 70 billion
barrels recovered in 25 years by applying advanced techniques probably
represent the upper limit to domestic oil production, and indeed lower
90
-------
cumulative production and smaller production rates in the year 2000 than
HG3 are more likely, particularly if the new USGS estimates of the
domestic resources base are approximately correct. Thus, HG3 represents
a scenario of maximum credible domestic oil production, even assuming
much higher crude oil prices. (It is not possible to estimate at this
time what price of crude oil would be necessary to bring about production
of the 70 billion barrels of oil by advanced recovery techniques for
HG3, since not enough is actually known about the economics of applying
advanced recovery techniques on a wide scale.)
For analysis of the impacts of HG3, we have used the Project
4
Independence scenarios in the Oil Task Force Report for determining
the percentage breakdown of regional oil supplies from national produc-
tion under HG3 as shown in Table 3-1. Table B-l shows the regional oil
supply projected by HG3 and serves to illustrate environmental impacts.
The supplies shown in Table B-l may never be realized; they are intended
to serve a similar function in this study to that served by the maximum
v
credible implementation scenario, Chapter 6. One major difference in
credibility between the two scenarios rests in the area of the resource
estimated. No one really knows how much oil is left for discovery,
where it is, or how rapidly it can be produced. However, the location
and the quantities of the oil shale and coal resources for syncrude
are known.
91
-------
Table B-l
HISTORICAL GROWTH SUBSCENARIO 3—REGIONAL SUPPLY
OF OIL AND NATURAL GAS LIQUIDS
(Millions of barrels per day)
Region or Source
Prudhoe
North Slope
NPR4
NPR1
Military Reserves
1
2
2A
3
4
5
6
6A
7
8-10
11
11A
Percentage of HG3 Percentage of HG3
1974 Total Supply* 1985 Total Supply"^ 2000
0
0
0
0
0
0.201
0.792
0.058
0.215
0.614
2.553
3.526
1.311
0.994
0.213
0.007
0
13.4
9.4
0
0
0
4.0
4.4
4.5
1.2
2.5
12.1
24.0
17.4
6.4
2.1
0
0.3
1.80
1.30
0
0
0
0.54
0.59
0.60
0.16
0.34
1.60
3.20
2.30
0.86
0.28
0
0.040
8.6
5.1
11.7
0.6
1.2
7.2
2.8
9.0
0.9
1.7
8.0
18.1
15.2
4.2
1.4
0.1
4.5
1.20
0.68
1.60
0.08
0.16
0.96
0.38
1.20
0.12
0.23
1.10
2.40
2.00
0.56
0.19
0.013
0.60
Totals
10.50
100
13.400
100
13.400
Items may not sum to totals due to rounding.
t 4
Percentages based on data on Exhibit IV-2, Business-As-Usual, $7/B,
1985.
t 4
Percentages based on data in Exhibit IV-2, Accelerated Development,
$7/B, 1988.
92
-------
APPENDIX C
TRENDS IN PAST U.S. PRODUCTION AND THEIR
IMPLICATIONS FOR FUTURE PRODUCTION
Hundreds of oil fields produce oil in the United States. Production
into the rest of this century is certain to include oil from most of the
existing fields, some of which have been producing for over 60 years, and
presumably from fields yet to be discovered. Section 1 below presents
a brief history of U.S. consumption of crude oil and crude oil prices.
Declining annual discovery rates for new oil fields and declining crude
oil prices (in constant dollars) characterize the 20 years prior to 1973.
Dramatic crude oil price increases characterize the last two years.
1. A Brief History of U.S. Oil Production and Oil Exploration
Table C-l summarizes the history of U.S. crude oil production and
discovery. Column 2 of the table shows the annual U.S. crude oil
production for the selected years. Each year, oil is produced from the
economically proven reserves (Column 3 of Table C-l) remaining at the
end of the previous year. Production increased nearly 3 percent per
year on the average from 1890 until production peaked in 1970. After
1970, production began a decline, which continues (late 1975). This
trend is expected to continue until TAPS is completed. In 1974, reserves
Q Q
were estimated to be about 34 x 10a barrels, and production was 3.0 x 10
barrels. Thus, if all else were constant, economically producible known
reserves would be exhausted in only 11 years. However, each year brings
new discoveries and new economic conditions, which change estimates of
reserves. Increasing the real price of crude oil can result in new
93
-------
Table C-l
HISTORICAL RECORD OF PRODUCTION AND PROVEN RESERVES: ALSO
THE ULTIMATE RECOVERY AND ORIGINAL OIL IN PLACE BY YEAR
OF DISCOVERY—TOTAL UNITED STATES FOR SELECTED YEARS
(Billions of barrels of 42 U.S. gallons)
Selected
Years
(1)
For All Fields Discovered
to Date
For Fields Discovered
During Year
Production
During Year
(2)
Proved Reserves
at End of Year
(3)
1974 Estimate
of Ultimate
Recovery
(4)
1974 Estimate
of Original
Oil in Place
(5)
Pre-1920
1925
1930
1935
1940
1945
1950
1955
1960
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
5.1
0.8
0.9
1.0
1.3
1.7
2.0
2.4
2.5
2.7
2.9
3.0
3.2
3.2
3.3
3.3
3.3
3.2
3.0
19.9
25.3
30.0
31.6
31.3
31.4
31.4
30.7
29.6
39.0
38.1
36.3
35.3
34.3
25.8
1.0
7.7
2.5
3.8
2.2
2.6
1.5
0.9
1.3
0.5
0.7
10.6
0.6
0.7
0.4
0.2
0.2
0.06
98.0
4.0
13.6
7.1
9.6
7.0
7.3
5.6
3.1
4.5
2.0
2.9
25.4
2.3
2.2
1.3
,0
,0
1,
1,
0.3
Total
cumulative
for all
years 106
140
440
43
Source: Summarized from Tables III and IV of Reserves of Crude Oil,
Natural Gas Liquids in the United States and Canada; and
United States, Productive Capacity as of December 31, 1974.
94
-------
reserves. The following equation shows the relationship.
(Proven reserves in previous year) - (Production that year) +
(Discoveries in new fields) + (Extensions to old fields) =
(Proven reserves at the end of the year).
Indeed, since 1945, reserves have fluctuated around 10 times the annual
production.
For the past 20 years, discoveries in existing oil fields exceeded
9
discoveries of new fields—except for 1969 with 10 x 10 barrel discovery
under the Alaskan North Slope. The year 1974 exemplifies this dominance
trend. Discoveries in new oil fields (column 4 of Table C-l) added
9
only 0.1 x 10 barrels to ultimately recoverable oil while extensions
9
to old oil fields added approximately 1.9 x 10 barrels.
Column 4 of Table C-l reflects the 1974 estimate of the ultimate
recovery from all known oil fields at January 1974 crude oil prices—
9 9
approximately 140 x 10 barrels, of which 106 x 10 barrels have been
produced. Figure C-l shows the history of U.S. reserves since 1945.
A comparison of new field discoveries (column 4 of Table C-l) with the
new oil added (cross-hatched histogram in Figure C-l) demonstrates the
trend discussed in the previous paragraph.
Not only does much of the exploration activity take place in known
fields, but all production takes place in them as well. Figure C-2
shows the oil produced in 1973 from 228 major U.S. oil fields (fields
C
which produced at least 1 x 10 barrels during the year). The data are
tabulated by year of discovery of the field. Several apparent facts are:
* Approximately 80 percent of the oil from the 228 major fields
was produced from 190 fields, all at least 20 years old.
* The 228 major fields accounted for almost 60 percent of all
domestic production.
95
-------
ftlLllONS OF BARRELS
40
NiW OIL ADDED DURING YEAR
1945
1950
1955
1960
1965
1970
1974
Source: American Gos Association
FIGURE C-l. PROVED RESERVES OF CRUDE OIL IN THE
UNITED STATES, 1945-1974
96
-------
a:
a.
cc
o
LU
Ld
20
18
16
10
0
(19) = Number of major oilfields discovered
in indicated time period
(40)
(30)
(26)
(19)
(10)
(14)
(16)
(19)
(16)
(16)
6)
< 1910
1915
1916-
1920
1921-
1925
1926- 1931-
1930 1935
1936-
1940
1941-
1945
1946-
1950
1951-
1955
1956-
1960
1961-
1965
1966-
1970
YEAR OF DISCOVERY
Source : Based on data in 1974 International Petroleum Encyclopedia, p. 223.
FIGURE C-2. 1973 CRUDE OIL PRODUCTION FROM 228 MAJOR
DOMESTIC OILFIELDS BY YEAR OF DISCOVERY
-------
• Production from most of these major fields is likely to
continue into the rest of the century.
• Any impacts already associated with these oil fields will
continue.
A comparison of the statistics for 1968 on major U.S. oil fields (those
6 44 8
producing over 10 B per year) with statistics for 1973 shows that
production in many of these major fields increased substantially-most
often due to more wells coming into production by 1973 (i.e., new wells
were drilled).
Predicting future production from currently producing oil fields
is difficult. Future production depends on the price of crude oil, on
the existence of economic or other incentives for developing oil reserves
which are uneconomic to produce at today's prices and, crucially, on the
amount of oil left to produce.
2. A Brief History of U. S. Crude Oil Supply and Demand
Table C-2 shows the history of U.S. crude oil supply and demand
between 1944 and 1973. While domestic supply was 11.3 million barrels
per day in 1970, it declined to 10.5 million barrels per day in 1974;
6 6
imports nearly doubled, from 3.2 x 10 barrels per day to 6.2 x 10
barrels per day. Total U. S. demand between 1944 and 1973 rose at about
4 percent per year, while imports grew from supplying 23 percent of
domestic demand in 1970 to 36 percent of domestic demand in 1974. Table
C-2 makes three important points:
• Domestic demand grew between 1944 and 1973 at 4 percent
per year to 17.3 x 106 barrels per day in 1973.
• Imports grew between 1970 and 1974 to supply 36 percent
of domestic demand.
• Domestic supply fell between 1970 and 1974 to only
10.5 x 10 barrels per day in 1974.
98
-------
CO
Table C-2
STATISTICS OF THE PETROLEUM INDUSTRY
YEAR
1945
1946
1947
1948
1949
1950
1951
1952
1953
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
PRODUCTION
Crude
Oil
(1.000
B/0)
4.695
4,751
5.088
5,520
5.047
5.407
6.158
6.256
6.458
6.343
6,807
7.151
7.170
6.710
7.053
7.035
7.183
7.332
7.542
7.614
7.804
8.295
8.810
9.096
9.238
9.637
9.463
9.441
9.208
8.774
Nat. Gas
Liquids
(1.000
B/D)
315
322
364
402
431
499
562
612
655
692
772
801
809
808
880
930
991
1.021
1.098
1,155
1.210
1.284
1.410
1 .503
1.589
.660
.692
.744
,738
.688
Total
(1.000
B/D)
5.010
5.073
5.452
5,922
5.478
5.906
6,720
6.868
7.113
7.035
7,579
7.952
7,979
7.518
7.933
7,965
8.174
8.353
8,640
8,769
9,014
9,579
10.220
10,599
10.827
1 1 .297
11.155
11,185
10.946
10.462
IMPORTS
Crude
Oil
(1.000
B/D)
203
236
266
353
421
487
491
573
648
656
782
934
1,023
953
966
1,015
1.045
1.126
1,131
1.198
1,238
1.225
1.128
1,290
1,409
1,324
1.681
2,216
3.244
3,477
Refined
Products
(1,000
B/D)
108
141
170
161
224
363
353
379
386
396
466
502
552
747
815
799
871
956
- 992
1.060
1,230
1,348
1.409
1,550
1,757
2.094
2.245
2,525
3,012
2.611
Total
(1.000
B/D)
311
377
436
514
645
850
844
952
1.034
1.052
1.248
1.436
1.574
1.700
1.780
1,815
1.917
2.082
2.123
2.258
2.468
2,573
2.537
2,840
3,166
3.419
3.926
4,741
6.256
6.088
OTHER
SUPPLY1
_
—
—
—
—
2
7
7
20
23
34
43
42
64
86
146
179
175
202
217
220
245
292
348
340
355
439
444
485
500
TOTAL
SUPPLY
(1.000
B/0)
5.321
5,450
5.888
6.436
6,123
6.758
' 7.571
7,827
8.167
8,110
8,861
9,431
9,595
9.282
9.799
9.926
10.270
10,610
10.965
1 1 .244
11.702
12.397
13.049
13.787
14.333
15.071
15,520
16,370
17.687
17.050
PETROLEUM DEMAND
Domestic
(1,000
B/D)
4,857
4,912
5,452
5,775
5,803
6.509
7.060
7.283
7,624
7.784
8.493
8.822
8.860
9.146
9.494
9.807
9,985
10.410
10.753
11.032
1 1 .523
12.095
12.569
13,404
14.148
14.709
15.225
16.380
17.321
16,642
Export
(1,000
B/D)
501
419
450
368
327
305
422
436
401
355
368
430
568
276
255
202
174
168
208
202
187
198
307
231
233
259
224
222
231
220
Total
(1,000
B/D)
5.358
5.331
5.902
6,143
6.130
6.814
7,482
7,719
8.025
8.139
8.861
9,252
9.428
9.422
9.749
10,009
10.159
10.578
10,961
1 1 ,234
11,710
12.293
12.876
13.635
14.381
14.968
15.449
16.602
17.552
16,862
Source: Reference 25
-------
Table C-3 shows a history of crude oil prices. Although prices in
current dollars rose between 1954 and 1973, prices in constant 1973
dollars fell until 1974. The effective decline in crude oil prices
made drilling and exploring for oil increasingly unprofitable. For
example, the number of new oil wells drilled fell from 30,000 in 1954
25
to 9900 in 1973. The total footage of wells drilled also declined
6 6 25
from 220 x 10 ft in 1954 to 140 x 10 ft in 1973. Recent increases
in crude oil prices stimulated drilling activity and it remains to be
seen if many new resources are added and if a net U.S. production
increase takes place.
100
-------
Table C-3
OIL PRICES
Crude Oil at Well
(per barrel)
Year
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
November 1975
25
Current
$
2.78
2.77
2.79
3.09
3.01
2.90
2.88
2.89
2.90
2.89
2.88
2.86
2.88
2.91
2.94
3.09
3.18
3.39
3.39
3.89
6.74
Constant
1973 $
4.77
4.69
4.57
4.88
4.63
4.39
4.29
4.25
4.22
4.15
4.07
3.97
3.89
3.81
3.70
3.71
3.62
3.38
3.57
3.89
6.32
45
8.75
7.18
Source: References 25, 45
101
-------
REFERENCES
1. A Time to Choose: America's Energy Future, Energy Policy Project
of the Ford Foundation, Ballinger Publishing Co. (Cambridge,
Massachusetts, 1974).
2. B. M. Miller, et al., "Geological Estimates of Undiscovered
Recoverable Oil and Gas Resources in the United States," Geological
Survey Circular 725, U. S. Department of the Interior (1975)
3. "Project Independence Blueprint", Federal Energy Administration
(November 1974)
4. "Project Independence Blueprint, Final Task Force Report—Oil,"
Federal Energy Administration (November 1974)
5. "Exploration Step-up said Vital to U.S.," The Oil and Gas Journal,
pp. 146-7 (November 10, 1975)
6. M. King Hubbert, "U. S. Energy Resources, A Review as of 1972,
Part I," Committee on Interior and Insular Affairs, United States
Senate, Serial No. 93-40 (92-75) (1974)
7. D. E. Kash, et al., Energy Under the Oceans, University of
Oklahoma, Norman, Oklahoma (1973)
8. International Petroleum Encyclopedia, 1974, J. C. McCaslin ed.,
The Petroleum Publishing Company, Tulsa, Oklahoma (1974)
9. L. F. McGhee, "Drillers Weigh Offshore Options," The Oil and Gas
Journal, p. 270 (May 6, 1974)
10. "Environmental Considerations in Future Energy Growth," Battelle
Laboratories, Environmental Protection Agency, Contract #68-01-0470
(April 1973)
11. OCS Oil and Gas - An Environmental Assessment," A Report to the
Council on Environmental Quality (April 1974)
102
-------
12. "Aker Designs Bigger Version of Its Series," The Oil and Gas
Journal, p. 84 (December 2, 1974)
13. G. A. Rousefell, "Ecological Effects of Offshore Construction,"
NTIS Report AD 739704 (1972)
14. Oil Spills and the Marine Environment, D. F. Boesch, C. H. Hershner
and J. H. Milgram, Ballinger Publishing Co. (Cambridge, Massachu-
setts, 1974)
15. "Petroleum in the Marine Environment," National Academy of Sciences,
Washington D. C. (1975)
16. Oilspill, W. Marx, Sierra Club, San Francisco (1971)
17. D. R. Green, et al., "The Alert Bay Oil Spill: A One-Year Study of
the Recovery of a Contaminated Bay," Pacific Marine Science Report
74-9 Environment Canada (Victoria, B. C., June 1974)
18. M. Blumer and J. Sabs, "Oil Pollution, Persistence and Degradation
of Spilled Fuel Oil," Science, 176, pp. 1120-22 (June 9, 1972)
19. "Analysis of the Trade Off of Exploration between Onshore and Off-
shore Regions and Potential Environmental Hazards and Safeguards,"
Environmental Protection Agency (June 1974)
20. Civil Engineering Handbook, L. C. Urquhart, ed., McGraw-Hill
(New York 1950)
21. "Alaska: Alyeska isn't the whole story," The Oil and Gas Journal,
p. 78 (November 25, 1974)
22. "Oil Recovery Chemical Needs will Spiral," The Oil and Gas Journal,
p. 68 (March 10, 1975)
23. "California Pumps out more Oil," Business Week, p. 68H (May 12,
1975)
24. "Compilation of Air Pollutant Emission Factors," U. S. Environ-
mental Protection Agency, AP 42 (April 1, 1973)
25. "The Oil Producing Industry in Your State," 1975 edition,
Independent Petroleum Assn. of America, Washington, D. C.
103
-------
26. J. Carbery and D. Martin, "insidious Killer: A lethal gas freed
in oil-gas production poses a rising hazard - new techniques in
industry...," Wall Street Journal (December 5, 1975)
27. Oil and the Outer Coastal Shelf: The Georges Bank Case, W. R.
Ahern, Jr., Ballinger Publishing Co. (Cambridge, Massachusetts,
1973)
28. "Canada will cut crude exports to U. S.," The Oil and Gas Journal,
p. 29 (December 2, 1974)
29. "Canada's curb on oil exports should shock U. S. into action,"
(editorial) The Oil and Gas Journal (December 2, 1974)
30. "Report on the Gulf Coast Deep Water Port Facilities. Texas,
Louisianna, Mississippi, Alabama and Florida," Dept. of the Army,
Lower Mississippi Valley Division; Corps of Engineers (Vicksburg,
Mississippi, June 1973)
31. "Summary Report Air Quality: Stations and Related Facilities for
the Trans-Alaska Pipeline," Alyeska Pipeline Service Company
(April 1974)
32. Congressman L. Aspin, "Why the Trans-Alaska Pipeline should be
Stopped," Sierra Club Bulletin, pp. 14-17 (June 1971)
33. "Report of the Review Committee on the Safety of DCS Petroleum
Operations to the U. S. Geological Survey," National Academy of
Engineering Marine Board (June 1974)
34. "Developing the Last Frontier," Fortune, pp. 120-127
(December 1974)
35. 'Final Environmental Impact Statement, Proposed Trans-Alaska
Pipeline," U. S. Dept. of the Interior, 401 1-4 (1972)
36. R. Corrigan, Alaska embarks on its biggest boom as oil pipeline
gets under way," Smithsonian, pp. 37-48 (October 1974)
37. "Environmental Impacts, Efficiency, and Cost of Energy Supply and
End Use," Hittman Assoc. (Vol. 1 - Draft Final Report for CEQ/NSF-
RANN/EPA). Contract EQC 308.
104
-------
38. The Policy Study Group of the Energy Laboratory, M. I. T., "Energy
Self-Sufficiency, An Economic Evaluation: Synthetic Fuels"
Technology Review (May 1974)
39. "Project Independence Blueprint, Final Task Force Report—Labor,"
Federal Energy Administration (November 1974)
40. Gulf Universities Research Consortium, "Planning Criteria Relative
to a National RDT & E Program Directed to the Enhanced Recovery of
Crude Oil and Natural Gas." GURC Report No. 130. (Galveston,
Texas, November 30, 1973)
41. R. R. Bery, et al., "Prognosis for Expanding U. S. Production of
Crude Oil," Science, Vol. 184, p. 331 (April 19, 1974)
42. "Mineral Resources and the Environment," National Academy of
Sciences (1975)
43. "Reserves of Crude Oil, Natural Gas Liquids and Natural Gas in
the United States and Canada and United States Productive Capacity,
as of December 31, 1974." American Gas Association, American
Petroleum Institute, Canadian Petroleum Association, Vol. 29
(May 1975)
44. International Petroleum Encyclopedia, 1970, G. Weber, ed.,
The Petroleum Publishing Company, Tulsa, Oklahoma (197Q)
45. "Conferees vote 14% temporary rollback in price of oil; drive
for veto is expected," Wall Street Journal (November 7, 1975)
105
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4—SYNTHETIC LIQUID FUELS: THE TECHNOLOGY,
RESOURCE REQUIREMENTS, AND
POLLUTANT EMISSIONS
By Robert V. Steele
A. Introduction and Overview
To assess the impacts of large-scale production and use of syn-
thetic fuels it is necessary to set forth the technological systems or
networks through which these fuels proceed from resource extraction to
end use. We have attempted to do this by examining the technologies
that are likely to be utilized for synthetic fuels production, as well
as associated mining, transportation, refining, and distribution tech-
nologies. We have attempted to quantify flows of energy, materials, and
dollars through the systems and to identify specific areas where impacts
may be expected.
The level of detail with which the various technological system
elements have been discussed is sufficient to understand flows of mate-
rials, labor, dollars, and energy through the system, and to identify
flows of residuals into the environment. We have not undertaken detailed
engineering and economic analyses of these technologies since this work
has been performed elsewhere, often by several sources.
*Specifically, two previous studies on the feasibility of alternative
fuels for automotive transportation1's are pointed out as sources of
more detailed engineering and economic analysis.
106
-------
The basic elements that make up the alternative fuels network are
shown in Figure 4-1. This block flow diagram is sufficiently general
that the particular energy conversion technologies and the transporta-
tion and distribution steps need not be specified. These will be dis-
cussed in detail later. The important thing to notice about the diagram
is the way the alternative fuels are introduced into the conventional
fuel production and distribution system. It is our judgment that meth-
anol, because of its special properties, would have its own distribution
network parallel to, but distinct from, the conventional gasoline and
distillate fuel networks. On the other hand, for gasoline and distil-
late fuels derived from.coal and oil shale, we expect that once the
syncrude has been produced and introduced into the conventional pipeline/
refinery system, its fate will be essentially indistinguishable from the
natural crudes that are processed in the same system. The block flow
diagram reflects these judgments and also allows for the additional
alternative of introducing a methanol/gasoline blend at the last stage
of fuel distribution, i.e., at the pump.
It becomes apparent from the above discussion that most of the
social, economic and environmental impacts resulting from the develop-
ment of alternative fuels, with the possible exception of methanol, will
be in the extraction and conversion stages. For this reason, most of
the subsequent discussion, as well as the identification of impacts,
will center around these two stages. Since the production of methanol
from coal and of synthetic crude oil (syncrude) from coal and oil shale
are new technologies, they may have impacts that are qualitatively dif-
ferent from current types of energy conversion activities. In addition,
new types of impacts from the distribution and end use of methanol are
likely to occur. The extraction of coal for liquid fuels production is
not likely to pose any new problems in addition to those already encoun-
tered with conventional coal mining methods. However, the scale of
107
-------
COAL
MIKING
O
00
OIL SHALE
MINING
METHANOL
PRODUCTION
COAL
LIQUEFACTION
RETORTING
AND UPGRADING
REFINING
METHANOL
DISTRIBUTION
GASOLINE
DISTRIBUTION
DISTILLATE
DISTRIBUTION
BLENDING
AUTOMOTIVE
END USE
(CARS,
TRUCKS
AND BUSES)
FIGURE 4-1. SYNTHETIC FUELS NETWORK
-------
impacts is likely to increase in certain areas. The extraction and
processing of oil shale will have significant new impacts in shale-
bearing regions due to the very large amount of material that must be
mined and disposed of.
Two important considerations in the development of a synthetic
fuels industry are the cost and availability of the resource required
for input into the conversion processes. In coal conversion processes,
large quantities of coal are required by a single large plant (10 to 20
million tons per year), and this requirement contributes significantly
to the cost of producing the final product. Since it is important to
ensure a continuous supply of coal over the 20-year life of the plant,
the companies that operate the plants will attempt to "block up" (i.e.,
acquire leases) at least a 20-year supply of coal for each plant. The
large reserves required are more readily obtained in the western states
than in the eastern states. In addition, the costs of western coal ex-
traction are appreciably lower ($3-5/ton) than those for eastern coal
($8-10/ton) due the thick seams and low stripping ratios typical of
western coal deposits.
A large part of the expansion of the coal industry can be expected
to take place in the West. For this reason a large energy conversion
industry may also be centered in the western United States , in which
case many of the impacts due to synthetic fuels development would be
specific to this region. Thus, the use of western coal to produce
synthetic petroleum and methanol is emphasized in the following discus-
sion. This emphasis does not rule out the use of midwestern and eastern
coals for conversion to synthetic liquid fuels; in fact, there are
strong reasons for utilizing these high sulfur coals to produce clean
liquid fuels, and a major expansion of eastern coal production can be
expected. However, the judgment that the greater part of the projected
expansion of the coal and energy conversion industries is likely to take
109
-------
place in the West and that problems associated with this expansion are
more likely to be serious in the western states than in the eastern
states is reflected in this emphasis.
The technologies for converting coal and oil shale into liquid
fuels can best be described as emerging technologies in the sense that
bench scale, pilot plant, and, in some cases, demonstration plant, op-
eration of the various processes have been carried out, but none of the
technologies has yet been utilized in a commercial-sized plant. Of the
three technologies considered—crude oil from oil shale, crude oil from
coal and methanol from coal—it is widely accepted that the technology
for extracting crude oil from shale is the most advanced and the one
closest to commercial application. We judge the second most advanced
of the technologies to be the conversion of coal to methanol, even
though no pilot or demonstration plants have been built. The reason
for this judgment is that the two steps for converting coal to methanol--
production of synthesis gas and catalytic conversion of synthesis gas
to methanol—are both well understood and developed sufficiently so that
the combination of the two into a coal-to-methanol operation does not
present serious technical difficulty. Coal liquefaction is the least
advanced technology. Even though several processes have been tested
through the pilot plant stage, serious difficulties remain in the large
scale application of this technology, and the first commercial plants
are not expected for at least ten years.
Synthetic liquids derived from coal and oil shale are expected to
be expensive. Estimates of the market price range from $12 to $17 per
oil-equivalent barrel3 (two barrels of methanol have approximately the
same energy content as one barrel of oil). Some estimates go even
higher. A large fraction of the price of synthetic fuels is due to the
high initial capital investment required for a synthetic fuel plant.
This investment is of the order of $1 billion (1973) for a 100,000-B/D
110
-------
(16,000 m3/D) plant. Since construction costs have escalated at a rate
significantly higher than the overall rate of inflation, the capital in-
vestment may be much higher (in constant dollars) over the next ten years,
Ultimately technological improvements as well as standardization of some
process components can be expected to reduce both capital investment and
operating costs. The problems associated with generating the large
amounts of capital required to build up the synthetic fuels industry
constitute a significant economic and institutional impact, and are dis-
cussed in detail in Chapter 8.
Brief mention should be made of the kinds of products to be expected
from synthetic fuels pla'nts. In the conversion of coal and oil shale to
liquid fuels, a variety of products can be produced, ranging from light
oils and naphtha to fuel oil and synthetic crude oil. Some of these
products may be used as fuel for power plants, heating oil, etc. How-
ever, since this study is directed toward the use of synthetic fuels in
axitomotive transportation, we assume that the major end product of a
coal liquefaction or oil shale plant is synthetic crude oil, which is
suitable as a refinery feedstock, and which is ultimately converted to
gasoline and distillate fuel as well as to other refined products con-
sistent with the composition of the syncrude.
B. Discussion of Technolqgj.es
1. Liquid Fuels from Coal
a. Extraction
The various techniques for surface mining coal are dis-
cussed in detail in Chapter 13, and only brief mention is made here on
the extraction stage of coal conversion. The techniques of area strip
mining utilizing large "walking" draglines to remove overburden and elec-
tric shovels and heavy duty trucks to scoop out and remove the coal from
111
-------
the exposed seam are both well developed and well adapted to raining the
large western coal deposits lying near the surface. These mines can be
made rather large, in the 5- to 10-million ton per year (4.5 x 109 to
9 x 109 kg/Y) range, and thus it will be feasible to dedicate two or
three large mines to a single large (100,000 B/D or 16,000 m3/D) syn-
thetic fuel plant, which will require 10 to 20 million tons per year
(9 X 10s kg/Y to 18 X 109 kg/Y) of coal.
Although there are some large underground and surface
mines in Illinois (up to 5 million tons per year or 4.5 x ICT* kg/Y), most
eastern mines are much smaller,4 and many more of these mines will have
to be dedicated to a single synthetic fuel plant operating in the East.
It may be difficult to ensure a continuous source of supply from many
small mines unless they are all controlled by the same company that op-
erates the synthetic fuel plant.
Eventually western coal deposits lying near the surface
will be depleted and technology will have to be developed to extract the
much larger deep-lying coal resource. The presently used techniques such
as room-and-pillar and longwall mining, which are used in the relatively
narrow underground seams in the East, will have to be replaced by newer
methods suitable for the much thicker deposits in the West. The long-
term future of the western coal industry as well as the synthetic fuels
industry may hinge on the successful development of such techniques.
b. Conversion
Coal is an organic material consisting primarily of car-
bon and hydrogen and secondarily of oxygen, nitrogen, sulfur and other
inorganic constituents. The molecular constituents of coal are complex
aromatic (ring) compounds in which the atomic ratio of carbon to hydrogen
is about one. Typical carbon-to-hydrogen weight ratios are 11 to 15.
Under the appropriate conditions, these large molecules can be broken
112
-------
down into smaller ones, with carbon-to-hydrogen weight ratios of the
order of 6 to 8, and a liquid hydrocarbon fuel can be obtained. There
are three distinct routes for carrying out the conversion of coal to
liquid fuels, of which two are of interest for this study.
(1) Fischer-Tropsch Synthesis/Methanol Synthesis--
Fischer-Tropsch synthesis was used extensively by the Germans during
World War II to produce synthetic petroleum from coal when natural
petroleum was in short supply. Through 1943, large quantities of gaso-
line were produced in this fashion. Even though this method of coal
liquefaction is expensive and inefficient, it is the only coal liquefac-
tion process currently being used in a commercial plant (South African
Gas and Oil Company [SASOL]—operating at 6600 tons (6 X 106 kg) of coal
input per day). The main product of this plant is synthetic gasoline,
but significant amounts of diesel oil, liquefied petroleum gas (LPG),
waxes and alcohols are also produced.5 SASOL has recently announced
plans to expand the plant to three times its present size.
Fischer-Tropsch synthesis is actually the second step of
a two-step process for converting coal to liquid fuels. In the first
step, the coal is gasified to produce a synthesis gas consisting mainly
of carbon monoxide (CO) and hydrogen (H ). There are several processes
by which gasification can be accomplished. As an example, we will use
the Lurgi process, which is both well developed and widely used. In the
Lurgi process, coal is crushed and fed to a pressurized lock hopper from
which it is admitted to the gasification vessel. Inside the vessel the
coal moves from top to bottom by the force of gravity and is reacted with
a counterflowing stream of oxygen and steam at 1100-1400°F (590-760°C)
and 350-450 psi (2.4-3.1 x 106 N/m2). Ash is removed via another lock
hopper at the bottom of the vessel. The gas produced by the reaction is
113
-------
bled off at the top of the vessel. It consists primarily of CO and H2
along with carbon dioxide (CO2), water vapor (H2O), methane (CH4), and
contaminants such as hydrogen sulfide (HgS). After leaving the gasifier,
the hot gas is quenched with water to remove tars and oils, which are
formed during gasification, and then purified to remove the acid gases
CO. and H_S.
<• O
The resulting synthesis gas containing Hs and CO in the
approximate molecular ratio of 2/1 is suitable for conversion to hydro-
carbons via Fischer-Tropsch synthesis. This synthesis is carried out in
a fluidized bed catalytic reactor at 430-490CF (220-250°C) and 360 psi
(2.5 X 10s N/ms). The two major reactions on which the synthesis is
based are as follows, where (CH2)n is the symbolic representation of a
hydrocarbon containing n carbon atoms with n larger than about 4 or 5:
nCO + 2nH2
2nCO + nH _ (CH,,)n + nCOp .
-------
In methanol synthesis, a copper-zinc catalyst is used to
convert purified synthesis gas to methanol at 500°F (260°C) and 1500 psi
(1 X 107 N/ms). The principal reactions involved are:
CO + 2Hg _ CH3OH
C02 + 3H2 - CH3OH + H20 .
To achieve the maximum yield of methanol (CH3OH) it is important to have
the correct H0/(CO + CO ) molecular ratio in the synthesis gas. This is
3 i&
accomplished by allowing some of the gas to undergo CO shift conversion,
whereby steam and CO are reacted to form C0g and H2. This step consti-
tutes another difference between methanol synthesis and the Fischer-
Tropsch process.
Figure 4-2 shows a block flow diagram for the conversion
of coal to methanol. Nearly a third of the coal input to the plant is
converted to low-Btu fuel gas in a gasifier operating with air instead
of oxygen. This gas is burned on-site to provide steam and electricity
to run the various plant processes.6 This method of producing plant
fuel is not as efficient as burning coal directly but does result in
significantly lower emissions to the air.
Most of the processes associated with methanol production
have been discussed previously. Other processes shown in Figure 4-2 are:
methane reforming, wherein methane produced in the gasifier (methane is
not suitable as a feed to methanol synthesis) is reacted with steam to
produce additional CO and Hs; compression of the 300-400-psi (2.1-2.8 X.
106 N/m2) synthesis gas to the 1500 psi (1.0 X 106 N/m2) necessary for
methanol synthesis—since less than 7 percent of the synthesis gas is
converted to methanol during a single pass through the synthesis stage,
the remainder is recycled to the compression stage; sulfur recovery, in
115
-------
TAR, OIL AND NAPHTHA
t
ASK
GASIFICATION
AND
QUENCHING
COAL
COAL
PREPARATION
ASH
FUEL GAS
PRODUCTION
FUEL
GAS
STEAM AND
POWER
GENERATION
SYNTHESIS
GAS
PURIFICATION
CO SHIFT
CONVERSION
METHANE
REFORMING
SULFUR
RECOVERY
GAS LIQUOR
H2S
SULFUR
SYNTHESIS
GAS
COMPRESSION
WATER
METHANOL
SYNTHESIS
METHANOL
HIGHER ALCOHOLS
WATER
TREATMENT
PHENOL AND
AMMONIA
RECYCLE WATER
FIGURE 4-2. PRODUCTION OF METHANOL FROM COAL
-------
which H S is a concentrated stream from the gas purification stage is
reduced to elemental sulfur, which can be sold as a byproduct.
For the process shown in Figure 4-2, the thermal effici-
ency is rather low--56.6 percent if the heating value of all the byprod-
ucts is counted; 40 percent if only methanol is counted.6 Certain
changes in process components could result in a higher overall effici-
ency. Burning coal directly instead of converting it to low-Btu fuel
gas has been discussed previously. This procedure increases efficiency
but results in a higher environmental cost. Another process change
would be to utilize a high-temperature gasifier, which would produce a
negligible methane yield in the synthesis gas. This would eliminate the
energy consumptive methane reforming step, and high temperature operation
would produce far fewer byproduct tars and oils.
There are two commercially available gasifiers that have
low direct methane yields—the Winkler and the Koppers-Totzek. These
gasifiers also have the advantage of producing practically no tars and
oils, thus eliminating an additional separation step. However, both
gasifiers have the disadvantage of operating at atmospheric pressure,
thus requiring a large degree of compression of the gas before methanol
synthesis. In the Koppers-Totzek process, the additional energy savings
brought about by low tar and methane yield is offset by the large com-
pression energy requirement, resulting in an overall coal to methanol
efficiency of about 40 percent,2 the same as when the Lurgi gasifier is
used.
A number of advanced gasifiers suitable for producing
synthesis gas have been tested. These include the Bureau of Mines Syn-
thane process, the CO Acceptor process of Consolidation Coal Company,
the Westinghouse fluidized bed process and various in situ gasification
processes, developed by the Bureau of Mines, Lawrence Livermore Labora-
tory, and others. All of these processes incorporate design features
117
-------
which promote increased synthesis gas yields and other process improve-
ments that will eventually render the Lurgi and Koppers-Totzek processes
obsolete. However, none of these processes are commercially available
at present. First generation methanol plants will undoubtedly be de-
signed around current technology, while second and third generation
plants will incorporate the more advanced gasification technologies
mentioned above, as they become available.
(2) Pyrolysis—Pyrolysis is a technique for extracting
the volatile material in coal by heating it to high temperatures (about
1600"F) in successive stages. The volatile material driven off contains
most of the hydrogen in the coal, and consists of medium-Btu gas and a
high-density synthetic crude oil. A portion of the gas can be reformed
to produce hydrogen, which can then be used to hydrotreat the liquid
product, thus upgrading it to a crude oil suitable as a refinery feed-
stock. The material left behind after pyrolysis is called char; it con-
sists mostly of carbon and ash. This material may be usable as fuel if
the sulfur content is low enough.
Pilot plant tests made by FMC Corporation on its COED
(Char Oil Energy Development) coal pyrolysis process indicate that just
slightly over one barrel (0.16 m?) of synthetic crude oil is obtained
per ton (910 kg) of coal input.6 Thus, the coal-to-oil thermal effici-
ency is only about 25 percent. The remainder of the product energy is
in the form of char or gases. Since this study is directed toward the
production of liquid fuels from coal, and other processes are capable
of liquid fuel yields of three barrels per ton (0.53 m3 of oil per 1000
kg of coal) or more, we do not consider that coal pyrolysis is of suffi-
cient interest to warrant further analysis.
(3) Coal Dissolution—The process by which coal is dis-
solved in a solvent, hydrogenated, and converted into a liquid hydrocarbon
118
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fuel is known as coal dissolution. It is also referred to as solvent
hydrogenation or solvent extraction. This appears to be the most prom-
ising technology for converting coal into synthetic crude oil (syncrude).
It has the advantage of achieving a high liquid product yield (approxi-
mately three barrels per ton or 0.53 m3 per 1000 kg of bituminous coal)
with relatively high thermal efficiency (up to 75 percent). In addition,
most of the sulfur in the coal is removed during the process. Although
several variations of this process have been developed, there are some
steps common to all processes including the dissolution of the organic
matter in the coal in a process-derived solvent and hydrogenation of the
resulting product to yield synthetic crude oil. These are shown in the
block flow diagram of Figure 4-3. The dotted lines indicate the differ-
ent stages at which hydrogenation can take place, depending on the
process.
The three variants of the coal dissolution technique that
have been the most extensively evaluated are the Solvent Refined Coal
(SRC) process of Pittsburgh and Midway Coal Company, the Consol Synthetic
Fuel (CSF) process of Consolidation Coal Company and the H-Coal process
of Hydrocarbon Research, Inc. (HRI).
In the SRC process, the crushed coal is first slurried
with the solvent and then reacted with hydrogen at 815CF (435°C) and
1000 psi (6.9 X 106 N/m2), causing complete dissolution of the organic
matter. After separating unreacted solids and solvent, a low-sulfur,
ash free product, which is a solid at room temperature, is obtained. It
must be further upgraded by hydrotreating to yield synthetic crude oil.
Two pilot plants have been constructed to test the SRC process. A six
ton per day (5400 kg/D) plant producing a clean boiler fuel recently
completed a 75-day test run at Wilsonville, Alabama. Sponsors are the
Electric Power Research Institute (EPRI.) and the Southern Services
119
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to
o
COAL
1
COAL COAL/S
PREPARATION SLU
i
\
\
1
1
I
1
OLVENT COAL
RRY DISSOLUTION
i
iYDROGEN GENERATION
GAS
REMOVAL
SOLIDS
REMOVAL
\
FUEL GAS
SOLVENT RECYCLE
n
'
'
r n
I
HYDROGENATION
1
_J
PRODUCT /SOLVENT
SEPARATION
SYNCRUDE
FIGURE 4-3. COAL LIQUEFACTION VIA DISSOLUTION AND HYDROGENATION {FROM REFERENCE 7)
-------
Company. In Tacoraa, Washington, a 75 ton per day (68,000 kg/D) pilot
plant has been built for Pittsburgh and Midway under ERDA sponsorship.
The CSF process separates the dissolution and hydrogena-
tion steps. The crushed, dried, and preheated coal is first slurried
with a hydrogen donor solvent. Then it is passed through a tubular
furnace at 150 psi (1.0 X 10s N/m2) and 765°F (410°C) to an extraction
vessel where dissolution of the organic matter is completed. After un-
reacted solids are separated, the resulting liquid is fractionated. The
low-boiling fraction is recovered as solvent, and the heavy bottom prod-
uct is further hydrogenated at 800°F (430°C) and 3000 psi (2.1 X 107 N/m3)
to yield synthetic crude' oil.
A 70 ton per day (6.4 X 104 kg/D) pilot plant based on
the CSF process was operated at Cresap, West Virginia, for 40 months,
ending in 1970. Because of recurring equipment failures, the plant was
shut down for a detailed study of problem areas. However, it was con-
cluded that the process, as designed, is technically feasible. This
plant is scheduled to be reactivated by the Fluor Corporation; several
coal-to-liquid-fuels processes will be tested.
A third variant of the solvent refining method, the H-Coal
process, carries out dissolution and hydrogenation in the same step in
the presence of a catalyst. The slurried coal is reacted with hydrogen
in an ebullating bed reactor at 850°F (450°C) and 2700 psi (1.9 X 107
^
N/m ). Cobalt-molybdenum catalyst is continuously added to the reactor
as spent catalyst is removed. After separating gases and unreacted
solids, synthetic crude oil is recovered from fractionation of the re-
sulting liquid.
Initial testing of the H-Coal process has been carried
out in a three ton per day (2700 kg/D) pilot plant at the HRI facili-
ties at Trenton, New Jersey, under the sponsorship of Ashland, ARCO,
121
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Standard of Indiana, and Exxon. In addition, ERDA and HRI are planning
a 600 ton per day (5.4 X 105 kg/D) pilot plant at Catlettsburg, Kentucky,
to test the commercial feasibility of the H-Coal process. Industrial
sponsors include the ones mentioned above (except Exxon), EPRI and Sun
Oil.
Several additional variants of the coal dissolution method
are being tested. Gulf Research and Development recently began testing
a catalytic process in a one ton per day pilot plant. The Bureau of
Mines has contracted Foster-Wheeler Corporation to design an eight ton
per day pilot plant to test its Synthoil process, which is similar to
the H-Coal process, and has been tested through the one-half ton per day
(450 kg/D) pilot plant stage.
In all the above processes, large amounts of hydrogen
(15.000-20.000 cubic ft per ton of coal or 470-620 m3/1000 kg of coal)
are consumed. In most cases, sufficient hydrogen can be produced by a
combination of gasification of unreacted coal solids (char) and heavy
distillation products, and steam reforming of high-Btu byproduct gases.
If necessary, some of the feed coal itself can be gasified to provide
additional hydrogen.
At present no coal liquefaction processes are suitable
for incorporation into a commercial-size plant. Several processes have
been tested at the pilot-plant level as indicated above. However, con-
siderable research and development remains before the first commercial
coal liquefaction plants can be built and operated successfully. In
particular, areas in which further R&D are required are coal slurrying
and pressurization, durability of reactor materials under severe oper-
ating conditions, separation of unreacted solids from liquid products,
and maintenance of the activity of hydrogenation catalysts.
122
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It is widely believed that a single-step catalytic hy-
drogenation process, such as the H-Coal process, is the one most likely
to achieve rapid commercialization for the production of synthetic crude
oil from coal.1'7'8 While other processes, such as the SRC process,
may be utilized to provide clean boiler fuels for power plants, it ap-
pears that the H-Coal or a similar process is the most suitable for pro-
viding refinery grade crude oil in terms of cost, efficiency, and tech-
nological readiness. Other promising processes are currently undergoing
development, including the Union Carbide process, which has been chosen
by the Office of Coal Research to be used in a 2600 ton per day (2.4 X 106
kg/D) demonstration plant. However, details of this process are largely
proprietary, and furthermore half of the product output of the plant (on
a Btu basis) will be in the form of high-Btu gas—the liquid yield is
only 1.5 barrels per ton (0.26 m3/1000 kg) of coal.
Due to the substantial amount of analysis that has been
carried out on the H-Coal process,1'8 its suitability for producing
syncrude, and its advanced stage of technological development, we have
chosen it as the basis for scaling the impacts from coal liquefaction.
c. Distribution
Due to the similarity between coal-derived syncrude and
natural crude oil, the most likely mode of distribution is through the
presently existing crude oil pipeline system shown in Figure 4-4. De-
pending on the location of the syncrude plants, some new pipeline addi-
tions or extensions will undoubtedly be built. However, it is likely
that the location of crude oil pipelines, as well as the availability of
coal, water, etc., will be taken into account in siting the plants.
Once the syncrude has entered the pipeline distribution system, it will
\
probably be treated as another source of "sweet" (low sulfur) crude, as
123
-------
a .,,«.....
DISTRICT 2
I I r,Mil
CRUDE OR PRODUCING AREA
REFINING AREA
PLANNED OR UNDER CONSTRUCTION
SOURCE NATIONAL PETROLEUM COUNCIL
FIGURE 4-4. CRUDE OIL PIPELINE NETWORK
-------
is presently done with syncrude from Canadian tar sands, and distributed
to refineries as a supplement to natural crude supplies.
Once the syncrude has entered the refinery and is blended
with natural crudes, its fate will become indistinguishable from that of
other crudes, and products derived from refining the blended syncrude
will enter the product distribution network along with other refined
products. Due to the high aromatic content of H-Coal syncrude, it is
relatively more suitable for the production of gasoline than distillate
Q
fuel or other products. Thus, refineries that process significant
fractions of syncrude will undoubtedly produce an even larger proportion
of gasoline, relative to distillate fuel, than the 2 to 1 ratio that
characterizes the present average refinery product slate.
The distribution of methanol derived from coal presents
a different problem. There is no pipeline network suitable for trans-
porting methanol. Presumably such a pipeline system could be built, but
in the early days of the industry there would not be the financial incen-
tive to do so. Thus, it is likely that methanol will be transported to
major distribution centers in the same manner as other liquid chemicals,
via railroad tank car. If the industry grows to a large size and firm
markets are established, both volume requirements and economic incentives
would probably induce the construction of product pipelines to the regions
of highest consumption.
The distribution of methanol to final consumption (cars,
trucks, and buses) poses additional problems of handling and storage.
Since methanol is compatible with gasoline as a blend, it is likely to
be consumed initially as a 10-15 volume percent methanol/gasoline blend.9
However, small amounts of water in the methanol tend to cause phase sep-
aration in the gasoline/methanol mixture. To mitigate this problem, the
methanol should be stored and handled with special equipment designed to
125
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keep moisture out of the system, and blended with gasoline at the last
stage of distribution when the fuel is pumped into the vehicle. Thus,
methanol is likely to be distributed through the same network as gaso-
line, but with separate storage and handling facilities.
Ultimately, assuming new engines are designed to operate
with pure methanol, some distribution facilities may be built solely to
handle methanol sales, but most of the methanol would probably continue
to be sold through gasoline distribution facilities (service stations)
either in the pure form or as a blend.
An alternative to locating a coal liquefaction or meth-
anol plant near the mine and shipping the product to refining or dis-
tribution centers is to locate the plant near these centers and ship
the coal to the plant. In coal liquefaction, this is undoubtedly a more
expensive alternative than shipping syncrude via pipeline. However, the
tendency of some western states, such as Montana, to encourage resource
extraction, while discouraging energy conversion activities within the
state, will cause increased attention to be directed toward this alter-
native.
To transport the large quantities of coal required by
synthetic fuel plants, either unit trains or coal slurry pipelines will
be utilized. A single coal slurry pipeline could supply one or two
100,000-B D (16.000 ms/D^ plants. Four to five unit trains per day of
100-car length would be required to supply a single plant of the same
size. Assuming a two-day transit time between the mine and the plant,
about 20 to 25 unit trains would be required to be dedicated full time
to a single plant. Assuming several plants will be located in a par-
ticular area, say northern Illinois, an enormous supply problem can be
envisioned. Coal slurry pipelines will undoubtedly help relieve these
problems. However, at least one limiting factor will be the large
126
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amounts of water that are required for slurrying the coal—about 750
acre-ft per million tons (100 m3/1000 kg) of coal.10 Many western
states are reluctant to have scarce water supplies leave the state in
this fashion.
Further discussion of coal slurry pipelines and railroads
and problems involved in the large scale transport of coal can be found
in Chapter 19.
2. Oil Shale
a. Extraction
The production of synthetic crude oil from oil shale in-
volves mining and processing an enormous amount of material—1.4 tons of
shale per barrel of oil recovered, on the average. This means that an
oil shale retorting and upgrading plant producing 100,000 barrels
(16,000 m3) of syncrude per day must process about 50 million tons
(4.5 X 1010 kg) of shale per year. The mining operation for this plant
would be ten times larger than the largest underground coal mines now
in operation.
It is anticipated that most of the oil shale lying in
underground deposits will be mined via the room-and-pillar technique.
This is a conventional, well-established mining technology whereby large
underground "rooms" (about 60 ft X 60 ft or 18 m X 18 m) are blasted and
dug from the resource bed, and large "pillars" are left standing between
the "rooms" to support the roof of the mine. With this method, about
60 percent of the resource in-place can be extracted and 40 percent is
left in the form of "pillars."
When oil shale lies in deposits near the surface, open
pit mining can be carried out. The overburden is first stripped away
and stored, then the shale is recovered, crushed, and retorted. After
127
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all the resource is removed from the mine area, the overburden is re-
placed, contoured, and revegetated. The feasibility of surface mining
oil shale is determined by the overburden-to-resource ratio and the
availability of an area for overburden storage.
A more complete discussion of oil shale mining and spent
shale disposal and reclamation can be found in Chapter 14.
b. Conversion
Conceptually, the technology of obtaining liquid hydro-
carbons from oil shale is simple. The crushed shale is heated in a
closed vessel (retort) to a temperature of 900°F (480°C) or greater, at
which point the kerogen (the organic portion of the oil shale) vaporizes
and is separated from the solid inorganic portion of the rock. After
retorting, the shale oil is upgraded by means of hydrotreating (chemi-
cally reacting with hydrogen) to yield a synthetic crude oil, which is
suitable for transport via pipeline and can be used as a refinery feed-
stock.
The various methods for retorting oil shale differ in the
manner in which heat is generated and transferred to the shale. The sim-
plest method is the Fischer assay technique in which heat from an ex-
ternal source is transferred to the shale through the wall of the re-
tort. Any fuel may be used to supply the heat. Due to large capital
and operating costs, this method is unsuitable for commercial develop-
ment. However, it is commonly used on a laboratory scale to measure
the kerogen content of the shale.
There are four additional methods for retorting oil shale,
which are in various stages of development and which have the potential
for commercial application. These are discussed in the following
paragraphs.
128
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(1) Hot Solids or Solids-to-Solids Heating Method—
The TOSCO II process is the most advanced version of this technique.
In this process ceramic balls are heated by the combustion of byproduct
gases and liquids and transferred to the retort where they are mixed
with crushed, preheated shale. Shale oil vapor is driven off and re-
covered. The ceramic balls are separated from the spent shale (on the
basis of size) and subsequently reheated. A high efficiency of energy
recovery is achieved; however, capital and operating costs are high.
In the Lurgi-Ruhrgas version of this technique which has
been tested in a 12 ton per day pilot plant in West Germany, spent shale
is used as the heat carrier. The spent shale is heated by combusting
the carbon residue which remains after retorting, together with addi-
tional fuel as needed.
The TOSCO II process is essentially ready for commercial
application. Colony Development Operation (a joint venture of ARCO,
Ashland, Shell, and The Oil Shale Corporation) has successfully com-
pleted tests on a 25 ton per day test unit and an 1100 ton per day semi-
works plant at Parachute Creek, Colorado. Colony had announced plans
to begin construction in April 1975, of a 50,000-B/D commercial plant
based on the TOSCO II process. These plans were later postponed, with
Colony citing rapidly inflating construction costs and uncertainties in
U.S. energy policy as the basis for its decision.13
There are several other planned commercial operations in
which the TOSCO II retort will be used. These include the following:
a 50,000-B/D (8000 m3/D) plant planned to begin operation in 1982 by
ARCO, TOSCO, Ashland, and Shell as a joint venture on Colorado Tract
C-b; the Rio Blanco Oil Shale Project, a joint venture on Colorado
Tract C-a by Gulf Oil and Standard of Indiana with 50,000-B/D (8000
m3/D) initial production planned for 1980; the 75,000-B/D (12,000 m3/D)
129
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Sand Wash Project in Utah planned by TOSCO with start-up expected in
1981-83.
(2) Gas-to-Solids Heating/Internal Gas Combustion
Method—Crushed shale is fed to the top of a vertical retort and low-
Btu byproduct gas is injected at the bottom. The gas is combusted in
the retort along with residual carbon on the spent shale, and the hot
combustion gases heat the shale, driving off the oil vapors that are
condensed at the top of the retort. The noncondensible gases are re-
cycled for combustion. Due to the lack of external heating equipment,
this method is less costly than other types of retorts. Energy recov-
ery efficiency is somewhat lower, however.
The Bureau of Mines tested a version of this technique,
called the Gas Combustion process, in 1966-67. No tests have been car-
ried out on this process since then.
The Union Oil Company version of the process utilizes a
unique "rock pump" which injects shale at the bottom of the retort while
combustion gases are drawn down from the top by blowers, and retorted
shale oil is collected at the bottom. A 1000 ton per day (9 x 105 kg/D)
pilot plant was successfully demonstrated in 1957-58. A more advanced
version of this retort, called the steam gas recirculation (SGR) proc-
ess, was recently announced and a 1500 ton per day (1.4 x 106 kg/D)
demonstration plant based on this process will be built on private land
in Colorado. (The SGR retort is actually an example of the gas-to-solids,
external heat generation method discussed in the next section.) Union
reportedly plans to have a 50,000-B/D (8000 m3/D) commercial plant op-
erating by 1980.
A third variation on the process has been constructed by
Development Engineering, Inc. (DEI), the operating arm of Paraho Devel-
opment Corporation (a consortium of 17 firms). This process, usually
130
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referred to as the Paraho retort, utilizes patented shale-feed and spent
shale-discharge grates, which provide a uniform flow of shale through
the retort. Multilevel gas injectors are also used to carefully control
the level of incoming gases. DEI recently completed a successful 30-day
run on its 500 ton per day (4.5 X 105 kg/D) test plant near Rifle, Col-
orado, as part of a 30-month R&D program. Paraho has also proposed to
construct and test a commercial size retort on the Naval Oil Shale Re-
serve in Colorado.
Both of the planned commercial operations on federally
leased tracts in Utah have proposed to use primarily the Paraho retort.
However, since the Paraho- retort can operate only on coarse shale, the
TOSCO II process will also be used to deal with the 10 to 20 percent of
the crushed shale that is too fine for the Paraho process. Sun Oil and
Phillips Petroleum have leased the U-a tract and propose to have a 50,000-B/D
(8000 m3/D) plant operating by 1978. The White River Shale Corporation (a
joint venture of Sun, Phillips, and Standard of Ohio) has leased the other
Utah tract (U-b) and is also planning a 50,000-B/D (8000 m3/D) operation.
Due to the continguous nature of the two tracts, and overlapping ownership
in the two ventures, it is likely that these operations will be carried out
jointly by all the participants.
(3) Gas-to-Solids Heating/External Heat Generation
Method—Recirculated byproduct gas is used as the medium of heat trans-
fer; however, heating of the gas is carried out in the external furnace,
rather than by combusting the gas and spent shale within the retort.
Some of the byproduct gas, carbon residue on the spent shale, or any
other suitable fuel may be combusted to supply heat to the furnace.
During 1975, Paraho will begin testing a version of its retort which
operates with externally heated gases.
131
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The Brazilian national oil company (Petrobras) has tested
a 2200 ton per day (2.0 X 10s kg/D) version of the external gas heating
retort called the Petrosix process. The tests were successful; however,
there are no plans for commercial application in the United States.
(4) In-Situ Retorting—Shale rock is fractured in place
by explosives to form an underground retorting chamber. Air is injected
to combust part of the shale, and retorting is carried out via heat trans-
fer from the hot combustion gases. Shale oil is collected from a hollow
mined at the bottom of the shale column.
Numerous tests of this method have been made by various
companies. Commercial feasibility has not yet been demonstrated, al-
though recent tests by Garrett Research and Development, a subsidiary of
Occidental Petroleum, appear promising. A 30 x 30 x 70-ft (9 x 9 x
21-m) shale column was successfully retorted, resulting in a shale oil
yield of about 60 percent. Further tests are planned on a 100 x 100 X
250-ft (30 x 30 x 76-m) column, with yields in excess of 70 percent
expected. If the Garrett or other tests demonstrate the commercial
feasibility of in-situ retorting, the use of this method could consid-
erably reduce water consumption, spent shale disposal, and other prob-
lems presently associated with aboveground retorting. However, new
problems, such as surface subsidence and the release of large quantities
of combustion gases, would be created, and these would need to be care-
fully managed. This method is expected to be less costly than any above-
ground retorting technique.
The TOSCO II process is the most advanced retorting method
for which a sufficient amount of information is available to provide the
scaling factors required for analysis. In addition, it has been incor-
porated into the plans of a majority of the companies which will be ac-
tively developing oil shale. Thus, we have chosen to use it in our
132
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analysis of oil shale conversion. A block flow diagram showing the
steps in oil shale processing, from crushing through upgrading is shown
in Figure 4-5.
Subsequent to retorting, described previously, the shale-
derived gases and liquids must be processed to remove sulfur and nitro-
gen, and produce a syncrjude that is suitable as a refinery feedstock.
The raw shale oil is separated into naphtha, gas oil, and residual
fractions. The naphtha and gas oil are sent to separate hydrotreaters
where they are upgraded and desulfurized. The residual oil is sent to
the coker unit, where coke is produced along with additional naphtha and
oil, which are sent to the hydrotreaters. During hydrogenation of the
naphtha and gas oil sulfur and nitrogen compounds are converted to H2S
and ammonia, which are separated in the sour water waste stream and
subsequently recovered as ammonia solution and elemental sulfur.
The hydrogenated naphtha and gas oil are recombined and
leave the plant as synthetic crude oil. The high-Btu byproduct gases
from the retort are purified to remove H2S and ammonia impurities, and
to remove uncondensed liquids (naphtha). All of these gases are then
consumed on site, either as plant fuel to provide steam and heat, or as
leeu to tne steam reiorming lurnaces, where they are reacted to form
hydrogen for the hydrotreaters.
Although it is conceivable that the raw shale oil up-
grading could be carried out elsewhere, transporting it via pipeline
would pose severe problems due to its high viscosity. The viscosity
is reduced in the process of upgrading and the syncrude product is
suitable for shipment via pipeline.
133
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FUEL GAS
t
GAS RECOVERY
AND
PURIFICATION
OIL SHALE
CO
CRUSHING
AND DRYING
SPENT SHALE
H?S
GASES
RETORT AND
PRODUCT
SEPARATION
NAPHTHA
HYDROGEN
GENERATION
GAS OIL
RESIDUAL OIL
COKER
COKE
NAPHTHA
HYDROTREATING
GAS OIL
HYDROTREATING
SULFUR
RECOVERY
FOUL WATER
SULFUR
STABLIIZER
SYNCRUDE
AMMONIA
RECOVERY
AMMONIA
RECYCLE WATER
FIGURE 4-5. OIL SHALE RETORTING AND UPGRADING
-------
c. Distribution
As in coal-derived syncrude, the distribution of upgraded
shale oil will undoubtedly be done via the present crude oil pipeline
network. Colony Development Operation has proposed a pipeline system
that would originate in the Piceance Basin of Colorado and connect with
existing crude pipelines to carry shale syncrude to refinery centers.
Other pipeline connectors will undoubtedly be built as the oil shale
industry develops. Figure 4-6 shows the location of the existing crude
oil pipeline network in relation to the oil shale-bearing regions of
Utah, Wyoming, and Colorado.
3. Building Block Sizes
The sizes of building blocks which will make up the produc-
tion and transportation systems for synthetic liquid fuels from coal and
oil shale will be determined by many interacting factors. Among these
are the limiting physical size of the components of each building block,
the capacity at which economies of scale are achieved, and the level of
production or throughput that best fits into the regional energy supply/
demand picture. For the first generation of synthetic liquid fuel
plants there is another constraint on size—the amount of capital that
private companies are willing to risk in a venture based on technology
that has not been previously tested on a commercial scale.
An inspection of the literature on current energy industry
practices and future plans for synthetic fuel plants quickly reveals
that there is a range of sizes that characterizes building blocks in
the synthetic fuels system. Table 4-1 shows the higher and lower sizes
in the range typical of each building block. These figures are not
meant to indicate absolute limits on sizes; rather they are meant to
indicate what "large" and "small" building blocks look like in the
135
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w
05
SALT LAKE
CITY
DENVER
UTAH
| GRAND
JUNCTION
ARIZONA
COLORADO
NEW MEXICO
FIGURE 4-6. EXISTING CRUDE OIL PIPELINES IN RELATION TO OIL SHALE AREAS
-------
context of a synthetic fuel supply system. For example, there are many
Appalachian coal mines that produce less than 100,000 tons (9 X 107 kg)
per year. However, these are not considered to be viable building blocks
in the synthetic fuel system.
Table 4-1
BUILDING BLOCK SIZES IN THE SYNTHETIC LIQUID
FUELS PRODUCTION SYSTEM
Building Block Size
Building Block
Units
B/D
B/D of
capacity
B/D
Small
Western surface coal mine tons/yr 1 million
Eastern underground coal
mine
Unit train (coal)
Coal liquefaction plant
Methanol plant
Oil shale mine
Oil shale retort and
upgrading complex
Crude oil pipeline
Refinery
50,000
25,000
(8 in.)
50,000
Large
10 million
tons/yr
tons of
capacity
B/D
B/D
tons/yr
0.1 million
—
25,000
35 , 000
25 million
5 million
10 , 000
100 , 000
200,000+
75 million
150,000
1.5 million
(48 in.)
400,000
*1 ton/yr = 910 kg/yr
1 B/D =0.6 m3/D
1 in. = 2.54 cm.
In spite of the range of sizes possible for the different
building blocks, there tend to be certain nominal or "typical" sizes
137
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that characterize industry plans for synthetic fuels. For coal lique-
faction, the earliest commercial plants will probably be in the range of
25,000 to 40,000 B/D (4000-6400 m3/D). As the industry matures, the
plant sizes will probably increase to about 100,000 B/D (16,000 m3/D).
There are few indications that plants larger than this will be built.
The first planned commercial oil shale complexes are of the
order of 50,000 B/D (8000 m3/D). Later complexes of 100,000 B/D
(16,000 m3/D) or larger are contemplated. Plants larger than 100,000
B/D (16,000 ms/D) will probably be combinations of smaller units.
Consideration of methanol plant size is usually made by anal-
ogy with substitute natural gas (SNG) plants. A plant using Lurgi gasi-
fiers, which processes the same amount of coal as a 250 million cubic
ft per day (7.1 x 106 m3/D) SNG plant (typical size) can produce about
81,200 B/D of methanol. This is the approximate energy equivalent of a
40,000-B/D (6400 m3/D) syncrude plant. Although conceptual designs
have been carried out for much smaller coal-to-methanol plants, it ap-
pears that economy of scale will favor the larger plant sizes. Plants
with capacities in excess of 200,000 B/D (32,000 ms/D) are conceivable.
Recent trends in construction of the other building blocks in
Table 4-1 have been toward the higher end of the scale. However, to a
large extent synthetic fuel plants will have to interface with existing
facilities, which tend to be at the lower end of the scale. The coun-
try abounds with 8-in. (20 cm) pipelines and refineries with capacities
well under 100,000 B/D (16,000 m"/D).
C. Material and Energy Flows
In this section the quantities of raw materials, resource energy,
labor and capital required to produce a given quantity of synthetic fuel
are given and flows of these quantities are traced both through the
138
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extraction-conversion-distribution systems and to areas external to the
systems. Tracing the flows of these quantities is important to the
assessment of the social, economic, and environmental impacts of syn-
thetic fuels development.
1. Energy Efficiency
Since the processes for converting solid resources into syn-
thetic liquid fuels are themselves energy intensive activities, it is
important to identify both the sources of energy loss during conversion
and the requirements for external sources of energy to operate the con-
version plants. Additional energy will be consumed in the extraction,
transportation, refining, and distribution stages as well. By dividing
the energy available for end use by the initial resource energy plus
all the external energy inputs into the system, we can obtain an overall
efficiency for the production of each alternative fuel.
We are concerned here only with the efficiency with which re-
source energy can be converted into product energy. We do not address
the larger question of net energy, in which the energy required to man-
ufacture and deliver the materials that go into the plant along with
secondary energy inputs are considered. Net energy calculations are
carried out and discussed in Chapter 5.
a. Methanol from Coal
Figure 4-7 shows the energy balance for converting
39,000 tons per day (3.5 X 107 m3/D) of 8870 Btu/lb (2.1 X 106 J/kg)
Navajo coal into 100,000 barrels (16,000 m3) of methanol.14 All energy
consumed in the plant is derived from the initial coal input—no exter-
nal energy source is required. Of the 692 billion Btu per day (7.3 X
1014 J/D) entering the plant as the heating value of the coal, 272 bil-
lion Btu (2.9 X 1014 J) exit the plant as methanol, 120 billion Btu
139
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HEAT
291 X 10sBtu/D
J
COAL 39,000 T/D
692 X 109Btu/D
464 X 109Btu/D
228 X 10yBtu/D
GASIFICATION
METHANOL
PRODUCTION
PURGE GAS
11 X 109Btu/D
STEAM AND
POWER PLANT
FUEL GAS
PRODUCTION
PURGE GAS
41 X 109Btu/D
174 X 109Btu/D
LOW Btu FUEL GAS
METHANOL
100,000 B/D
272 X 109Btu/D
HIGHER ALCOHOLS
2 X 109Btu/D
TAR, OIL & NAPHTHA
108 X !0'JBtu/D
SULFUR, PHENOL
& AMMONIA
10 X 10
-------
(1.3 X 1014 J) are in the form of byproducts, and 300 billion Btu
(3.2 X 1014 J) end up as waste heat, endothermic reaction heat or in
the ash.14
There are several ways to define thermal efficiency, all
of which are useful in difference contexts. For this study we wish to
know the efficiency with which the energy in the initial resource (coal
in this case) can be converted into energy in the form of the alterna-
tive fuel of interest. With this definition, we simply divide the
heating value of the methanol by the heating value of the coal to
obtain:
272 x 10s
Efficiency (coal-to-methanol) = —§• = 39.3 percent.
692 X 10
(If the byproduct higher alcohols (ethanol, propanol, etc.) are not
separated but remain blended with the methanol, the product is called
"methyl fuel." The coal-to-"methyl fuel" efficiency is only slightly
greater, however, 39.6 percent.)
It is important to note that in this case significant
quantities of combustible byproducts are produced along with the
methanol—about 110 billion Btu per day (1.2 X 104 J/D). If these
byproducts are counted as part of the total useful product energy we
have
272 + 110 cc n
Efficiency (coal-to-products) = — = 55.2 percent.
O *7rfS
One final accounting method that is useful in comparing
one alternative fuel with another and in computing net energy is the
primary resource energy/ancillary energy method. Primary resource
energy is defined as the initial energy content (heating value) of the
141
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resource that is actually processed into the final product. The ancil-
lary resource energy is the energy content of the resource which is
required to provide the electricity, steam, or general fuel to run the
process. This concept is especially useful when the resource from which
the ancillary energy is derived is different from the primary resource.
In the coal-to-methanol conversion, 228 billion Btu
(2.4 x 10 4 J) of ancillary resource energy are required to convert
464 billion Btu (4.9 X 1014 J) of primary resource into 272 billion
Btu (2.9 X 1014 J) of methanol. The 52 billion Btu (5.5 X 1014 J) of
off-gas from methanol production are not counted in the ancillary energy
requirement since they are generated internally and do not place any de-
mand on external resources.
The primary and ancillary resource energy requirements
for producing 1012 Btu (1.1 x 1015 J) of methanol are tabulated in Ta-
ble 4-2 below.
Table 4-2
COAL-TO-METHANOL ENERGY REQUIREMENT
1012 Btu 1015 J
Methanol energy 1.00 1.06
Primary resource energy 1.71 1.80
Ancillary resource energy 0.84 0.89
b. Syncrude from Coal
The energy balance for converting 55,200 tons per day
(5.0 X 107 kg) of 7800 Btu per Ib (18 X 106 J/kg) Powder River coal
into 100,000 barrels (16,000 m3) of synthetic crude oil via the H-Coal
142
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process is shown in Figure 4-8.15 This process has been designed to
produce only plant steam and heat on-site. An additional 144,000 kW of
purchased electricity is required to operate the plant. The 35 billion
Btu per day (3.7 X 10l3 J/D) of ancillary resource energy required to
produce this quantity of electricity (assuming 33 percent conversion
efficiency) must be taken into account in the energy balance.
Unlike the coal-to-methanol process, this plant has been
designed to utilize all byproducts within the plant. The coal char and
vacuum bottoms (derived from fractionation of the coal hydrogenation
product) are gasified to produce hydrogen, and part of the high-Btu
byproduct gas is steam reformed to produce hydrogen. The remaining gas
is burned to provide process steam and heat (93 billion Btu per day or
9.8 X 1013 J/D).8 All the usable product energy is in the form of
syncrude.
The efficiency for converting the initial coal resource
into synthetic crude oil is:
567
Efficiency (coal-to-syncrude) = = 63.3 percent.
861 4- 3o
We have assumed that the 35 billion Btu per day (3.7 x 1013 J/D) of
resource input into electric power generation are in the form of coal.
The primary and ancillary resource energy required to
produce 1012 Btu of syncrude are shown in Table 4-3.
c. Syncrude from Oil Shale
The energy balance for oil shale mining, TOSCO II re-
torting and upgrading is shown in Figure 4-9.1S Mining is included in
this balance since it is considered to be an integral part of the oil
shale operation. All the process energy requirements are generated
143
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744 X 109Btu/D
COAL 55,200 T/D
861 X 10yBtu/D
COAL
35 X 10yBtu/D
ELECTRIC
POWER
117 X 10yBtu/D
12 X 109Btu/D
HEAT
289 X 109Btu/D
1
LIQUEFACTION
HIGH Btu GAS
93 X 109Btu/D
PROCESS HEAT
AND STEAM
WASTE HEAT
23 X 109Btu/D
ASH AND CHAR
9 X 109Btu/D
SYNCRUDE
• 100,000 B/D
567 X 109Btu/D
SULFUR & AMMONIA
8 X 109Btu/D
FIGURE 4-8. H-COAL LIQUEFACTION PROCESS ENERGY BALANCE
-------
OIL SHALE
132,000 T/D
850 X 10wBtu/D
Cn
SPENT SHALE
108,000 T/D -*•
71 X 109Btu/D
COAL
42 X 109Btu/D
HEAT
165 X 109Btu/D
J.
45 X 109Btu/D
GAS
MINE
ELECTRIC
POWER
PROCESS HEAT
& STEAM
23 X 109Btu/D
*""' OIL
RETORT
UPGRADING'
DIESEL FUEL
2 X 109Btu/D
14 X 10sBtu/D
HEAT
28 X 109Btu/D
I
SYNCRUDE
100,000 B/D
580 X 109Btu/D
COKE
42 X 109Btu/D
AMMONIA & SULFUR
6 X 109Btu/D
FIGURE 4-9. TOSCO II OIL SHALE RETORTING AND UPGRADING ENERGY BALANCE
-------
on-site by the combustion of byproduct gases and fuel oil except for
170,000 kW of purchased electricity.12
Table 4-3
COAL-TO-SYNCRUDE ENERGY REQUIREMENT
101S Btu 1015 J
Syncrude energy 1.00 1.06
Primary resource energy 1.31 1.38
Ancillary resource energy 0.27 0.28
The thermal efficiency for converting oil shale to syn-
crude is:
580
Efficiency (oil-shale-to-syncrude) = =67.6 percent.
858
Strictly speaking, the resource (probably coal) required
to produce the electric power for the plant should be included, so that
the resource-to-syncrude efficiency is:
580
Efficiency (resource-to-syncrude) = — = 64.4 percent.
42
The efficiency for conversion of resource to useful prod-
uct energy, including byproduct coke, is:
580 + 42
Efficiency (resource-to-products) = — — = 69.1 percent.
42
146
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The calculation of primary and ancillary resource energy
requirements has somewhat more meaning for oil shale than for the liquid
fuels from coal technologies, since without the investment of a certain
amount of ancillary energy from another resource, no useful products
could be produced from oil shale. Coal is already a useful form of
energy, and energy is invested only to convert it to another form.
Table 4-4 shows the primary and ancillary resource energy requirements
for converting oil shale into 1012 Btu of synthetic crude oil.
Table 4-4
OIL SHALE-TO-SYNCRUDE ENERGY REQUIREMENTS
101S Btu 1015 J
Syncrude energy 1.00 1.06
Primary resource energy 1.48 1.56
Ancillary resource energy 0.07 0.07
2. Resource Consumption
We have defined resource in a broad way to include not only
the primary resources coal and oil shale but also the quantities of
water, land, labor and steel necessary to build and operate synthetic
fuels plants. In addition we consider briefly the consumption of catal-
ysts, chemicals, and other such materials. The reason for defining re-
sources in this way is to be able to examine a broad range of social
and economic impacts from synthetic fuels development as well as impacts
on the natural environment. We therefore use the concept of societal/
industrial resources as well as natural resources. Strictly speaking,
capital should also be included as a resource, but due to the somewhat
147
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greater complexity of analyzing capital and operating costs, we defer
the discussion of capital to Section 4.
a. Coal and Oil Shale
The consumption of primary resources in a given synthetic
fuel conversion process depends on both the particular process design
and the energy content of the resource. We will maintain consistency
with our previous discussion by assuming here and in subsequent sec-
tions that coal is converted to syncrude via the H-Coal process; coal
is converted to methanol via Lurgi gasification followed by intermedi-
ate pressure methanol synthesis; and oil shale is converted to syncrude
via TOSCO II retorting followed by coking and hydrotreating.
The quantity of oil shale consumed is determined by its
kerogen content. Colony Development Operation has designed its first
commercial plant to operate on 35 gal/ton (0.15 m3/1000 kg) shale.12
Other processes have been designed to operate on shale with oil content
down to 27 gal/ton (0.11 m3/1000 kg) and we include this for comparison.
The coal requirement is the amount of western subbituminous coal which
must be burned to provide electric power for the shale plant.
The two U.S. coal types which we consider for liquefac-
tion are western subbituminous (8000-9000 Btu/lb (1.9 X 107-2.1 x 107 J/
kg) and eastern bituminous (11,000-12,000 Btu Ib or 2.6 X 107-2.8 x 107
J/kg). The amount of coal consumed is calculated on the basis of both
the primary resource required and the amount of coal necessary to provide
plant fuel and electricity. The considerably lower requirement for
eastern compared to western coal is due not only to the higher heating
value of eastern coal but also to the significantly larger amount of
byproduct gases recovered during eastern coal liquefaction which can be
Q
used in place of coal as plant fuel.
148
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In methanol produced from coal, we consider in addition
to bituminous and subbituminous coal, North Dakota lignite (about 6500
Btu Ib or 1.5 X 107 J/kg), which is an excellent feedstock for coal
gasification, and would thus be suitable for methanol production as well.
The production of methanol from bituminous coal requires technology other
than the Lurgi gasifier, which has not operated well with U.S. eastern
coals. We assume that either a modified Lurgi gasifier or another type
of gasifier such as the Koppers-Totzek will be used with bituminous coal.
The coal and oil shale requirements for the three tech-
nologies under consideration are shown in Table 4-5. These annual re-
quirements are based on daily resource inputs, assuming the plant is
operating 90 percent of the time over a period of one year.
b. Water
The water requirement for synthetic fuels production
arises mainly from the need for cooling water to dispose of waste heat,
and the chemical need for hydrogen in the conversion process. The chemi-
cal hydrogen requirement is more or less fixed for each process, while
the cooling requirement is variable depending on the degree to which wet
cooling versus dry cooling is used in the plant, and the level to which
heat given off during each process step can be recovered for useful pur-
poses. Other uses of water within the plant may be quenching of gaseous
products to remove oil and particulates, dust suppression, solid waste
disposal, and the generation of steam to drive turbines or gas com-
pressors.
In the conversion of coal to methanol, about 3300 acre-ft
of water per year (as steam) is consumed in chemical reactions (gasifica-
c
tion, shift conversion and methane reforming). For the H-Coal lique-
faction process, the chemical consumption of water is about 3500 acre-ft
149
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Table 4-5
ANNUAL COAL AND OIL SHALE REQUIREMENTS FOR
100,000-B/D SYNTHETIC FUELS PLANTS
01
o
Syncrude from oil shale
35 gal/ton (0.15 m3/1000 kg)
27 gal/ton (0.11 m3/1000 kg)
Syncrude from coal
Bituminous
Subbiluminous
Methanol from coal
Bituminous
Subbituminous
Lignite
Oil
Oil Shale Shale Coal
(million tons) (109 kg) (million tons)
43 39 0.8
55 50 1.0
13
18
10
13
18
Coal
(109 kg)
0.7
0.9
12
16
9
12
16
-------
per year (4.2 x 10 ms/Y) using either western or eastern coal.8 This
water is utilized as steam in the partial oxidation plant and steam re-
former to convert solid and gaseous byproducts, respectively, into hy-
drogen for the coal hydrogenation process. The chemical consumption of
water in oil shale processing is in the steam reforming furnaces, where
hydrogen is produced for use in hydrotreating raw shale oil products.
This use of water amounts to 1500 acre-ft per year (1.8 X 106 ms/Y) .i:L
Other uses for water in oil shale mining, retorting and
upgrading have been fairly well established and are shown in Table 4-6
below.
Table 4-6
ANNUAL WATER REQUIREMENTS FOR A 100,000-B/D OIL SHALE
MINING, RETORTING, AND UPGRADING OPERATION
Process
Mining and crushing
Retorting
Upgrading
Spent shale disposal
Power generation
Revegetation
Water
(acre-ft)
900
1300
3600
7300
1800
700
Water
(10s m3)
1.1
1.6
4.3
8.8
2.2
0.8
Total
15,600
18.7
Source: Reference 11.
Of the above total, about 3800 acre-ft per year (4.6 x
10s m3/Y) are consumed as makeup water to the evaporative cooling tow-
ers. This quantity could be reduced significantly if more costly dry
cooling were utilized. There are relatively few additional areas where
151
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water consumption could be reduced. Essentially all process waste water
will be reused within the plant.
Information on nonchemical water requirements for pro-
ducing methanol from coal is somewhat sketchy. Depending on the extent
to which air cooling is used, makeup water for cooling is in the range
of 12,000-24,000 acre-ft per year (14 X 106-28 X 10s ms'/Y) . Much of
the water requirement for steam generation and cooling can be made up
by treating and recycling process waste water. We estimate the total
water requirement for a 100,000-B/D (16,000 m3/D) plant to be 10,000-
20,000 acre-ft per year (12 X 10s-24 x 106 m3/Y).
Coal liquefaction via the H-Coal process consumes 22,000
acre-ft of water per year (26 x 10s m3/Y) in evaporative cooling losses.8
The total requirement is 26,000-29,000 acre-ft per year (31 x 10s-
35 x 10s m3/Y) with no waste water recycling. To the extent that dry
cooling and internal cleanup and recycling are used, this figure could
be reduced by about half.
c. Land
Land use for synthetic fuels production includes perma-
nent uses such as the plant site itself, roads, pipeline and utilities
corridors, and water storage areas. Temporary uses include areas dis-
turbed by mining and solid waste disposal, assuming the disturbed land
can be rehabilitated for other uses. To the extent that the land is
disturbed so that restoration or rehabilitation is not possible, these
uses of the land become permanent.
The permanent land requirement for a 100,000 B/D (16,000
ms/D) oil shale mining, retorting, and upgrading operation is about 600
acres (2.4 x 10° m2).12 In addition, about 150 acres per year (6.1 X
10" m /Y) are disturbed by the disposal of spent shale in deep canyons,
152
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assuming the disposal pile is 250-ft (76 m) high.11 Revegetation of
spent shale has not been convincingly demonstrated at this time, and it
remains to be seen whether canyons which have been filled with spent
shale can be reclaimed for other uses.
By analogy with synthetic natural gas plants, a coal-to-
methanol conversion facility will occupy about 1000 acres (4 x 10 m ) ,17
Solid waste in the form of ash will be returned to mined-out areas for
burial. A coal liquefaction plant and associated facilities will occupy
about 1000 acres (4 X 10s m3).
The land disturbed by surface coal mining depends strongly
on the area of the country in which the coal is mined and is a function
of the coal seam thickness and the method used for mining, i.e., contour
stripping versus area stripping. Table 4-7 shows the average amount of
1 8
land disturbed by area strip mining in several western states.
Table 4-7
AVERAGE LAND AREA DISTURBED PER MILLION
TONS OF COAL RECOVERED
State
Arizona
North Dakota
New Mexico
Montana
Wyoming
Land Area
(acres)
78
65
62
47
25
Land Area
(103 m3)
320
260
250
190
100
Source: Reference 18.
153
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Combining this information with data from Table 4-5, we
find that the land disturbed annually to supply coal to a 100,000-B/D
(16,000 ms/D) methanol plant ranges from 325 acres (1.3 X 106 m2) for
R O
Wyoming subbituminous coal to 1170 acres (4.7 x 10 m ) for North Dakota
lignite. For liquefaction of subbituminous coal at the 100,000-B/D
(16,000 ms) level, the land disturbed ranges from 450 to 1400 acres per
year (1.8 X 106-5.7 x 10s m2/Y).
In the Midwest, coal seams are much thinner than in the
West; consequently, more land must be disturbed per unit of coal recov-
ered. The average land area disturbed in the Midwest per million tons
of coal recovered is 144 acres (5.8 X 105 m2),19 Thus, 1440 acres
(5.8 x 106 m2) must be disturbed annually to supply a 100,000-B/D
(16,000 m3/D) methanol plant and 1870 acres (7.6 X 10s m2) must be dis-
turbed to supply a 100,000-B/D (16,000 m3/D) coal liquefaction plant.
In Appalachia, most surface coal mining is done by con-
tour stripping, in which land is disturbed not only in the area of over-
burden removal but also by covering the downslope region with a spoil
bank and to a lesser extent by drainage ditches and induced landslides.
The average land area disturbed in Appalachia per million tons of coal
recovered is 415 acres (1.7 x 106 m2) for the contour stripping method.19
This means that 4150 acres (1.7 x 107 m2) must be disturbed annually to
supply a methanol plant and 5400 acres (2.2 X 107 m2) must be disturbed
to supply a coal liquefaction plant.
The reclamation potential for surface mining in the major
coal-bearing regions of the United States is discussed in detail in
Chapters 13 and 15. Generally speaking, it is possible in almost all
areas for some form of reclamation to take place and is in fact now re-
quired by law in many states. Therefore, we may consider land disturbed
154
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by surface mining to supply synthetic fuels plants a temporary land
use.
Land disturbance from eastern underground coal mining is
mostly in the form of surface subsidence. The degree to which subsidence
occurs will depend on the mine depth, the strength of the rock formation
above the mine, and the type of mining which is employed. For example,
long-wall mining results in greater subsidence than room-and-pillar
mining. The effect of subsidence is more or less permanent but does not
necessarily remove the land from other uses. Using an average figure of
0.1 acres (400 m2) of subsidence per 500 tons (4.5 X 105 kg) of coal
mined,20 we find that 2000 acres (8.1 X 10s m3) could be disturbed an-
nually to supply a methanol plant, and 2600 (1.1 x 107 m2) acres could
be disturbed to supply a coal liquefaction plant.
d, Labor
To assess impacts due to the buildup of population in
rural areas where much of the synthetic fuels development is expected
to occur, it is necessary to know the manpower requirements for con-
struction and operation of the plants. The influx of personnel required
for plant construction will represent a temporary population buildup
lasting three to four years, while the plant operation and maintenance
personnel will represent a stable long-term population increase in the
area. However, in oil shale development, where synthetic fuels plants
and mines are concentrated in a small area and there is a gradual build-
up of large productive capacity, the population increase due to the
*The reclamation potential of many arid regions of the West has not been
established, and surface mining in some areas may result in permanent
land disturbance.
155
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construction labor force will be spread out over a longer time period—
perhaps 10 to 15 years.
Colony Development Operation has estimated that 40 months
will be required for construction of its 50,000-B/D (8000 ms/D) oil
shale complex, and that the construction force will rise from several
hundred at the beginning of construction to a peak of 1200 halfway
through the project.12 Assuming a model for the buildup and fall-off
of construction personnel as shown in Figure 4-10, we calculate about
cr
Lu
-------
maintenance, and administrative personnel will total 900-1000 for its
50,000-B/D (8000 m3/D) complex. A mining, retorting, and upgrading op-
eration twice this size might be expected to employ 1500-1800 people.
Labor requirements for a coal-to-methanol plant can be
estimated by comparison with El Paso Natural Gas Company's 288 million
SCF per day (8.2 X 10s m3/D) SNG plant.17 Construction time will be
about three years with a peak construction force of 3500. Assuming
that the labor force at the beginning and end of the project is about
one-fourth the peak force, we estimate that 7500 man-years are required
to build a 100,000-B/D (16,000 ms/D) methanol plant. Operating person-
nel requirements will total about 900.
Labor requirements for coal liquefaction plant construc-
tion are difficult to estimate. Estimates range from about 50008 to
about 12,000 man-years of effort31 over a period of three to four years.
On the basis of the total plant investment cost, we estimate the level
of construction effort to be 7000-8000 man-years, with a peak labor
force of 2000-3000. The number of workers and supervisors involved in
operating the plant will be about 1400.
Construction of a 5 million ton per year (4.5 X 109 kg/Y)
surface coal mine in the western United States requires a 250 man-year
effort over a period of two years with a peak labor force of about 150.
? p
Operating personnel required to run such a mine number about 100.
e. Steel
The principal material requirement in the construction of
synthetic fuels plants will be steel. This will be in the form of equip-
ment and machinery, piping, girders for building construction, etc. A
rough estimate of the total steel requirement for a synthetic fuels
plant can be made through a breakdown of plant investment costs (shown
157
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in Section C-4) using some average cost for fabricated steel. We have
used the figure $1 per pound ($2.20/kg) for fabricated carbon steel and
$2.50 per pound ($5.50/kg) for fabricated stainless or alloy steel. We
have also assumed that approximately one-quarter of the fabricated steel
is stainless. Construction steel is assumed to be carbon steel. With
these rough estimating methods, we obtain a figure of about 100,000 tons
rj
(9.1 x 10 kg) of steel as the requirement for a coal-to-methanol coal
liquefaction, or oil shale plant of 100,000-B/D (16,000 m3/D) capacity.
The Oil Shale Task Force Report and Synthetic Fuels from
Coal Task Force Report of Project Independence Blueprint estimate that
about 130,000 tons (1.2 x 108 kg) of steel will be used in a 100,000-B/D
(16,000 m3/D) oil shale mining, retorting, and upgrading plant or coal
liquefaction plant.23»S4 By way of comparison, the MIT Energy Labora-
tory has estimated that 170,000 tons (1.5 x 10s kg) of steel are re-
quired for construction of a 200,000-B/D (32,000 m3/D) petroleum
refinery.3~
f. Other
The second most critical material will probably be cop-
per, primarily in the form of electrical wiring, instrumentation, wind-
ings for electric motors, etc. Based on the percentage of plant facil-
ities investment spent for major equipment and for electrical supplies
and materials and using the figures 3.7 tons (3.4 x 103 kg) of copper
per million dollars of output and 23 tons (2.1 x 104 kg) of copper per
million dollars of output26 for the Industrial Equipment and Machinery
sector and Electrical Equipment and Supplies sector of the economy,
p
respectively, we estimate that about 1500 tons (1.4 x 10 kg) of copper
will be utilized in a 100,000-B/D (16,000 m3/D) synthetic fuels plant.
The Synthetic Fuels from Coal Task Force Report of Project Independence
158
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Blueprint estimates that about 1200 tons (1.1 x 10s kg) of copper are
required for a 100,000-B/D (16,000 m3/D) Fischer-Tropsch synthesis type
gasoline-from-coal plant.24
In addition to the metals requirements, there will be
other materials requirements such as concrete (several hundred thousand
cubic yards or several hundred thousand m3 for foundations, parking
areas, etc.), insulation and paint.
Major equipment components will probably be fabricated
elsewhere and shipped to the construction site, although the largest
items, such as pressure vessels, may be fabricated on site due to the
difficulty in shipping such large objects. Numerous smaller pieces of
equipment such as pumps, motors, valves and conveyor belts will be needed
as well. Most of these items are not unique to synthetic fuels plants
but, due to the possible remote location of some of the plants, there
may be difficulties and delays in supplying equipment and materials.
Delays in equipment deliveries can contribute to increased costs due
to the necessity of keeping construction personnel on-site for longer
periods of time.
Once the plant has been constructed, the materials re-
quirements for operation and maintenance are much smaller. Other than
coal or oil shale, water and fuel, the main requirements are for the
chemicals and catalysts consumed in various chemical processes and in
water cleanup and air pollution control equipment. A large supply of
spare parts, lubricants, tools, and other maintenance equipment will be
needed. Again, the supply of these materials presents no special prob-
lems other than those imposed by the remote location of some of the
plants.
The catalysts and chemicals requirement will vary with
the types of chemical processes employed in the production of each
159
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synthetic fuel. In coal liquefaction, about 5500 tons (5.5 X 10s kg) of
cobalt-molybdenum catalyst are consumed annually in the coal hydrogena-
tion process,7 as well as 230 tons (2.1 x 105 kg) of nickel oxide cat-
alyst in the steam reforming plant.
In the coal-to-methanol conversion process, 875 tons
(7.9 x 105 kg) of copper-chromium-zinc catalyst for methanol synthetic
must be replaced every 1-2 years. Other catalysts such as the nickel
oxide catalyst for methane reforming and copper-zinc or iron-chromium
catalysts for CO shift must be replenished every 2-5 years.
Colony Development Operation has set forth requirements
for the processing and treating steps in the production of oil from oil
shale. These are listed in detail in Table 4-8. The replacement time
written after each quantity of catalyst is roughly the lifetime of
the catalyst.
Some additional chemicals that may be required in syn-
thetic fuels plants for water treating and cleanup, fuel gas cleanup,
stack gas scrubbing, etc. include lime (CaO), alum, salt, methanol,
isopropyl ether, sulfuric acid, and sodium hydroxide.
3. Byproducts and Residuals
- ™ "--•»' • 'i—•——^ a
In addition to the production of end products—syncrude and
methanol—for which synthetic fuel plants are designed, there will be
byproducts and residual materials generated which will be sold or dis-
posed of. Usable byproducts which can be sold on the open market bring
in additional revenue to the plant and help defray the production costs
of synthetic fuels. Solid, liquid, or gaseous waste materials gener-
ated during synthetic fuels production must be considered environmental
contaminants. The manner in which these wastes are disposed governs
the degree of environmental acceptability of the plant. At present,
160
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Table 4-8
CATALYST AND CHEMICAL REQUIREMENTS FOR A
100,000-B/D OIL SHALE RETORTING AND UPGRADING PLANT
Naphtha and gas oil hydrotreaters
670 tons (6.1 x 105 kg)/2yr (max) hydrodenitrogenation
catalyst
Steam reformer
270 tons (2.4 X 105 kg)/4 yr cobalt-molybdenum hydro-
desulfurization catalyst
5 tons (4.5 x 103 kg)/day caustic soda (NaOH)
30 tons (2.7 x 104 kg)/2 yr zinc oxide sulfur guard
100 tons (9.1 X 104 kg)/5 yr iron-chromium CO shift catalyst
100 tons (9.1 X 10? kg)/3 yr copper-zinc CO shift catalyst
Sulfur conversion
300 tons (2.7 x 105 kg)/2 yr bauxite claus plant catalyst
200 tons (1.8 X 104 kg)/5 yr cobalt and nickel molybdate
tail gas hydrotreater catalyst
Fuel gas treating
17.5 tons (1.6 X 104 kg)/2 wk diatomaceous earth filter
17.5 tons (1.6 x 104 kg)/2 wk activated carbon sulfur trap
Source: Reference 12.
there are no federal standards that govern emissions from synthetic
fuels plants, although there are standards which govern individual proc-
esses which may occur in the plant, such as combustion of fuel in steam
boilers. New Mexico has promulgated emission standards for coal gasi-
fication plants, and undoubtedly other states as well as the federal
government will direct increasing attention towards synthetic fuels
plants as the industry develops.
161
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a. Salable Byproducts
A variety of byproducts is produced from the conversion
of coal to methanol. These generally are produced during purification
processes in which impurities are removed from the synthesis gas or
methanol product. Tar, oil, and naphtha are removed during quenching
of the synthesis gas exiting the gasifier. The quench water dissolves
ammonia and phenols which are recovered in the water treatment plant.
Sulfur is a product of the sulfur recovery plant which treats the acid
gas stream which results from synthesis gas purification. Finally, a
small quantity of higher alcohols (ethanol, propanol, butanol, etc.)
are formed during methanol synthesis, and these are separated from the
final product by distillation.
The quantities of different byproducts generated by a
100,000-B/D (16,000 m3/D) methanol plant utilizing western coal are
listed in Table 4-9.
Table 4-9
BYPRODUCTS FROM A 100,000-B/D
COAL-TO-METHANOL PLANT
(Western Coal)
Tar, oil, and naphtha
Phenols
Higher alcohols
Ammonia
Sulfur
15,200 B/D (2400 m3/D)
840 B/D (130 m3/D)
405 B/D (64 m3/D)
450 T/D (4.1 X 105 kg/D)
170 T/D (1.5 X 10s kg/D)
Source: Reference 6.
162
-------
All of these products have commercial value and could be sold if a mar-
ket could be found for them. Otherwise they would have to be stored or
disposed along with the solid wastes.
The H-Coal liquefaction process is designed to maximize
syncrude production and to minimize the production of byproducts.8 The
large quantities of high-Btu gases generated are utilized as plant fuel
or as feed to the steam reformer. The heavy bottoms product, which is
separated from the syncrude, is fed to the partial oxidation plant for
hydrogen production. The only usable byproducts generated from this
process are 320 to 420 tons per day (2.9 X 105-3.8 X 10s kg/D) of am-
monia and 200 to 1300 tons per day (1.8 X 105-1.2 X 106 kg/D) of sulfur.8
A small amount of char is also produced, but it is not of commercial
value and will be disposed of with the ash.
As in the case of coal liquefaction, oil shale processing
will result in a minimum of byproducts. All gases and C4 liquids (bu-
tane and butene) produced from retorting will be consumed on-site as
plant fuel. The main byproduct will be 1600 tons per day (1.5 X 10s
12
kg/D) of coke, derived from the heavy residual shale oil fraction.
This product may or may not be of commercial value. Other byproducts
are 400 tons per day (3.6 X 10B kg/D) of elemental sulfur and 300 tons
per day (2.7 x 105 kg/D) of ammonia.
b. Solid Waste
The main solid waste resulting from coal liquefaction
and methanol production is the ash that remains after the organic por-
tion of the coal is converted to liquid and gaseous products. The
amount of ash produced depends on the original ash content of the coal.
Typically, 3000 to 4000 tons (2.7 X 106-3.6 X 10s kg) of ash and char
(mostly ash) will be generated per day by a 100,000-B/D (16,000 m3/D)
163
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coal liquefaction or coal-to-methanol plant. If the plant is located
near the mine, then this waste material can be disposed of in the mine--
either buried in a mined-out area in the case of an underground mine, or
added to the spoil piles and buried under topsoil during reclamation
operations for a surface mine. If it is not feasible to return the ash
to the mine, it must be stored in waste piles or used as landfill.
The major solid waste from oil shale retorting and up-
grading is, of course, the spent shale which results from retorting the
oil shale, amounting to 100,000 to 150,000 tons per day (9.1 X 107-
1,4 X 10e kg/D). The enormity of this disposal problem is reflected in
the plan proposed to deal with it—filling in a 250-ft (76 m) deep can-
yon. The land area required for such an operation was discussed earlier
in Section 2c.
It may be possible to dispose of some of the spent shale
in areas of the mine where recovery operations have been completed.
There is general reluctance in the industry to do this, however, since
lower grade deposits that might be economically recoverable at a later
date would be made inaccessible. In any case, not all the spent shale
could be disposed of in this way since the total shale volume expands
10 to 30 percent in crushing and retorting.11
Other minor solid wastes generated by synthetic fuel
plants include coal and shale dust, spent catalysts, and char and coke
if these cannot be sold commercially. In general, these wastes will be
disposed of along with the spent shale and ash.
The potential for recovering valuable minerals or metals
from spent shale or coal ash has yet to be assessed. At present there
are no plans to process spent shale. Of the major constituents of
spent shale, the only ones of value are magnesium, aluminum, and iron
oxides. Valuable trace metals such as gold, silver and platinum are
164
-------
present in quantities less than 0.1 part per million. There is about 1
part per million of uranium. The spent shale itself may have potential
uses as filler in concrete and building blocks, or as road substrate.
However, only a tiny fraction of the total spent shale generated by a
mature industry could be used in this way.
Coal ash also contains aluminum, magnesium and iron
oxides, and perhaps trace quantities of valuable metals. The possibil-
ity has been raised of recovering uranium from North Dakota lignite ash.
In general the uranium content of western coal ash is from 1 to 10 parts
per million.
c. Effluents to Water
In principle, the effluents to water from synthetic fuels
plants can be reduced effectively to zero. This can be done by treating
and recycling all boiler and cooling tower blowdown water, process waste
water, etc., and discharging to on-site evaporation ponds any remaining
water that is too highly contaminated to be recycled. All discharges
to streams and rivers can thus be eliminated. Furthermore, the raw
water requirement for plant operation can be considerably reduced. This
is particularly important in arid western regions where water supplies
are limited.
Colony Development Operation has designed its first com-
mercial 50,000-B/D oil shale retorting and upgrading plant so that no
waste streams from the plant are discharged to natural sources.12 Most
of the process water waste streams are treated and used for cooling or
processed shale moisturizing. This results in considerable water con-
sumption savings. The overall water use and treatment plan for the
Colony plant is shown in Figure 4-11. Although not all the steps in
this scheme are directly applicable to other synthetic fuels processes,
165
-------
r"90
NATURAL SHALE ?. 1 )6j _
SURFACE MOISTURE
110-
RAW SHALE SURFACE
MOISTURE
VI
v>
I
COOLING
TOWERS
REVE6ETATIW -70
O)
O)
-250-
DUST
CONTROL ON
PROCESSED
SHALE
EMBANKMENT
PYROLYSIS
AND
OIL RECOVERY
UNIT
131
UTI
BOI
J
— 2Zu
MAKEUP
WASTE HEAT
AND
1
*
BFW 1300
FIRE/
SERVICE/
DRINKING
MAKEUP
1300-
I
REGENERATION
FOUL WATER
WATER
TREATMENT
PLANT
•1
fl
STRIPPED WATER
370-
580-
• RIVER WATER SUPPLY
«LL RATES IN 6PM
* 'WILL INCREASE TO 700 6PM
IN 12 YEARS
TOTAL RIVER WATER SUPPLY •
rOR YEARS I-II: 49700PM
FOR YEARS K-ZO: 5600 6PM
FOR DESI6N PURPOSES, NO CREDIT
TAKEN FOR SURFACE IJUNOfF.
25
STRIPPED WATER
PURGE FROM
rFOUL WATER*
J! _t
FOUL
WATER
STRIPPER
GA$
RECOVERY
AND
TREATING
UNIT
COKER
TT
I-JUJ
Lja
PROCESSED AMMONIA SEPARATION
SHALE UNIT
MOISTURIZING
WASH WATER
180 '
FIGURE 4-11.
RIVER WATER UTILIZATION (from Reference 1 1 )
(50,000-BPD TOSCO II OIL SHALE PLANT)
-------
it does serve to illustrate the kinds of steps which may be taken to re-
duce aqueous emissions to zero.
El Paso Natural Gas Company has also developed a waste
water treatment and recycling plan for its Burnham, New Mexico, coal
gasification project.17 In this scheme, most of the treated waste water
is used to replace water lost in cooling tower evaporation—the single
largest consumptive use of water in the plant.
The sources and ultimate disposition of aqueous contami-
nants are different for each synthetic fuel process. In the conversion
of coal to methanol, most of the contaminants originate in the coal
gasification process. In addition to the tar, oil, naphtha, and phenols
formed from volatile matter in the coal, the nitrogen and sulfur com-
pounds are converted to ammonia, hydrogen cyanide (HCN), hydrogen sul-
fide, carbon disulfide (CS2) and carbonyl sulfide (COS) in the gasi-
fier.27 Subsequent to gasification, during the synthetic gas quenching
step, the tar, oils, and naphtha are condensed, decanted, and recovered
as byproducts. The remaining quench water (called gas liquor) contains
dissolved phenols and ammonia, which are recovered by the (proprietary)
Phenosolvan process. The remaining water containing small amounts of
all the above contaminants is sent to the water bio-treating plant and
recycled for use as cooling water and boiler feedwater.
The sulfur compounds and hydrogen cyanide remaining in
the synthesis gas are removed by the Rectisol process (cold methanol
scrubbing) and sent to a Stretford sulfur recovery unit where the HCN,
CSo, and COS are converted to sodium thiocyanate (NaSCN) and sodium
thiosulfate (NaS203). The contaminated Stretford solution is periodi-
2*7
cally replaced with fresh solution and sent to water bio-treating.
In coal liquefaction, aqueous contaminants are produced
during coal drying and coal hydrogenation in which the oxygen, nitrogen
167
-------
and sulfur in the coal are converted to water, ammonia, and hydrogen
sulfide, respectively. The contaminated water is sent to the ammonia
stripper unit where aqueous ammonia is recovered as a byproduct and a
concentrated H2S stream is generated and sent to the Claus sulfur recov-
ery plant. The remaining water can be sent to a bio-treating unit along
with the waste water from coal drying, cooling tower and boiler blowdown
^ Q
and other process waste water.
The levels of contaminants expected in the effluent water
from a biological treatment pond in which waste water from coal liquefac-
tion is treated is shown in Table 4-10. A 100,000-B/D coal liquefaction
plant produces about 5 million gallons of waste water per day; this weighs
about 21,000 tons (1.9 * 107 kg). Therefore, the concentrations shown in
Table 4-10 multiplied by the above figure give the amounts of these
contaminants discharged daily if the waste water is not recycled or sent
to on-site evaporation ponds.
Table 4-10
COAL LIQUEFACTION PLANT BIOLOGICAL
TREATING POND WATER EFFLUENT
Concentration
Constituent (wt ppm)
Sulfide < 0.005
Ammonia 0.11
Oil 0.68
Biological oxygen demand (BOD) 10.5
Suspended solids 12.9
Phenol 0.38
Chemical oxygen demand (COD) 45
Phosphate 0.11
Chromate 7.1
Zinc 3.5
Source: Reference 28.
168
-------
During the retorting and upgrading of oil shale, waste
water is generated as excess moisture from the retorting process and the
gas recovery unit, as process water and condensed moisture from the cok-
ing unit and boiler and cooling tower blowdown, as well as fuel gas and
stack gas scrubbing water. Waste water containing H^S and ammonia is
C
recovered in the foul water stripper and recycled. Most of the treated
waste water is disposed of by using it to moisturize the spent shale
generated during retorting. This use amounts to about 4 million gallons
per day (1.5 X 104 m3/D)3 which weighs about 17 tons.
The water used to moisturize the spent shale will consist
of any mine drainage water-and spent shale runoff water that has been
collected in addition to process waste water. The approximate concentra-
tions of contaminants expected in this water are listed in Table 4-11.
A potential source of water pollution is leaching or runoff from the
spent shale disposal pile into local aquifers. Except in catastrophic
failure of the pile or flash flooding, catchment dams will probably be
sufficient to retain any runoff water. The potential for water contami-
nation due to leaching depends on several factors, such as the degree of
compaction of the spent shale, and has yet to be fully assessed.
In addition to direct plant discharges, there are pos-
sible indirect water contamination problems. For example, the with-
drawal of low salinity water from the Upper Colorado River Basin for use
in oil shale processing will result in an increase in salinity in the
Lower Colorado, due to a decreased dilution effect. The salinity in-
crease resulting from a 1-million B/D oil shale industry would be about
10 parts per million (out of a present level of 860 ppm) at Imperial
Dam.12 Even though this increase is small, the fact that the United
States is planning to build a desalination plant on the lower Colorado
River to meet its treaty obligations with Mexico indicates that some .
169
-------
additional costs will be incurred (and paid for by the taxpayers) due to
this additional—indirectly caused—salinity increase.
Table 4-11
COMPOSITION OF WASTE WATER USED IN
SPENT SHALE MOISTURIZING
Constituent
Sulfates
Thiosulfates
Carbonates
Phosphates
Chlorides
Cyanides
Hydroxides
Phenol
Ammonia
Amines
Organic acids
Chelates
Chromates
Arsenic
Concentration
(wt ppm)
510
60
520
15
330
50
30
60
30
1900
1000
3
130
0.03
d.
Source: Reference 12.
Effluents to the Air
Sufficient information on plant design and emission
sources has been set forth in the literature so that quantitative esti-
mates can be made of the emissions of air pollutants. Generally speak-
ing, there are two major sources for the emission of contaminants to the
air from synthetic fuels production—the combustion of fuels to provide
170
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heat, steam and electricity to drive the various plant processes and the
emission of sulfur-containing waste gas (tail gas) from sulfur recovery
operations. In almost all cases, some sort of emission controls, di-
rect or indirect, have been incorporated into the plant designs. Al-
though there are presently no federal performance standards for synthe-
tic fuels plants, it is generally assumed that combustion of fuel in
boilers, for example, will be required to meet federal standards. It
is likely that standards for such plants will be promulgated as the
industry develops.
Since a more detailed discussion of air pollutant emis-
sions and controls will be-given in Chapter 16, only a summary of the
relevant emission data is given here. Table 4-12 shows the quantities
of S02, particulates, NOX and hydrocarbon emissions that may be expected
to result from the liquefaction of Montana-Wyoming coal and eastern coal
via the H-Coal process,8 the conversion of Navajo coal to methanol6 and
the retorting and upgrading of 35 gal/ton oil shale to syncrude,1 all
at the 100,000-B/D level. The emission levels shown in Table 4-12 are
those resulting from application of the "best available" emission con-
trols appropriate to each technology. The types of controls applied are
discussed in detail in Chapter 16.
All the emissions and NO., shown in Table 4-12 result
A.
from the combustion of gaseous, liquid, or solid fuels to power the
various plant processes. The total includes the combustion of fuel
necessary to provide purchased electricity when it has been incorpor-
ated into the plant design. All particulate emissions are from fuel
combustion or coal drying, except for oil shale processing where one-
fourth of the particulate emissions are in the form of fugitive dust.13
We have assumed a level of control of 99.5 percent using electrostatic
precipitors or Venturi scrubbers for reducing stack gas emissions from
171
-------
Table 4-12
EMISSIONS OF AIR POLLUTANTS FROM
SYNTHETIC FUELS PRODUCTION
(Tons per 100,000 Barrels of Product)
Particulates NOX Hydrocarbons
Coal liquefaction (H-Coal)
Montana/Wyoming coal 11 7.1 96 1.6
Illinois No. 6 coal 16 2.7 28 0.4
Coa1-to-methanol (Lurgi)
Navajo coal 15 2.0 25 0.4
Oil shale retorting and
upgrading (TOSCO II)
35 gal/ton shale 40 10 72 7.6
coal combustion. Fugitive dust control is assumed to be 98-99.8 percent
effective (see Chapter 16).
The SOZ emissions shown in Table 4-12 result from both
fuel combustion and sulfur recovery plant tail gas. We have assumed a
level of control for stack gas emissions from burning high sulfur fuels
of 90 percent, while for tail gas emissions a control level resulting
in SO~ emissions of 250 ppm by volume (equivalent to about 95 percent
SO2 removal) has been assumed. The relative proportions of SO2 emis-
sions from fuel combustion and tail gas are as follows: eastern
coal liquefaction, 59 percent from combustion, 41 percent from tail gas;
western coal liquefaction, 86 percent from combustion, 14 percent from
tail gas; methanol from Navajo coal, 94 percent from combustion, 6 per-
cent from tail gas; syncrude from oil shale, 96 percent from combustion,
4 percent from tail gas.
172
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e. Tracjg Elements
The question of the fate of toxic trace elements in coal
and oil shale conversion processes has received considerable attention
due to the potential for highly toxic metals such as mercury, lead,
beryllium, arsenic, cadmium, selenium, and fluorine to enter the air,
water, or soil and ultimately to create a health hazard. At present,
few pathways of trace elements through energy conversion activities
have been identified. It is known, for example, that volatile elements,
including those listed above, will be discharged to the air during com-
bustion. Other nonvolatile elements will end up primarily in the ash.
However, the fate of these"elements during coal gasification and lique-
faction and oil shale retorting is not as clearly defined.
The quantities of toxic trace elements which are found
in oil shale and coal are shown in Tables 4-13 and 4-14, respectively.
The oil shale determinations were made on 35-gallons per ton (0.15 m3/
1000 kg) Green River oil shale. The coal analyses were based on a
variety of coals found in both the eastern and western United States.
Typically, as seen from Table 4-14, eastern coals have a somewhat higher
trace element content than western coals.
During the coal gasification step of methanol production,
volatile elements in the coal are vaporized and may exit the gasifier
along with the raw synthesis gas. During gas quenching these elements
are condensed and separated out along with the tar, oil, and naphtha or
as part of the gas liquor stream. It is unlikely that any significant
fraction of the tnace elements in the coal make their way to the final
methanol product.
n q
In tests made on the Bureau of Mines Synthane gasifier,
it was determined that 20 trace elements were present in the raw gas
quench water in the range of 2 parts per billion to 4 parts per million.
173
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The concentration of selenium was 360 parts per billion and that of
arsenic was 30 parts per billion. Byproduct tar was found to contain
3 parts per billion of mercury and 0.7 parts per million of arsenic.
Only 0.01 parts per billion of mercury could be detected in the cleaned
synthesis gas, and none could be detected in the final product (methane)
Table 4-13
CONCENTRATION OF TOXIC TRACE
ELEMENTS IN OIL SHALE
Element
Arsenic
Beryllium
Cadmium
Fluorine
Lead
Mercury
Selenium
Concentration in
Oil Shale
(wt ppm)
7.2
35
0.14
1700
10
< 0.1
0.08
Source: Reference 12.
During coal liquefaction, coal is exposed to considerably
different conditions than in gasification, the primary differences being
the presence of a solvent (and perhaps a catalyst) and hydrogen at high
t
pressures. These conditions strongly affect the fate of trace elements.
A large portion of the trace metals will remain with the ash and un-
reacted solids that are separated from the liquid product. Gasifica-
tion of this solid material to produce hydrogen will produce trace
elements in waste streams in a fashion similar to coal gasification.
174
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Table 4-L4
MEAN TRACE ELEMENT CONCENTRATIONS (ppm, Moisture Free) OF VARIOUS COALS
Western Region
Eastern Region
Element
Beryllium
Fluorine
Arsenic
Selenium
Cadmium
Mercury
Lead
Bromine
Zinc
Copper
Nickel
Chromium
Vanadium
Barium
Strontium
Colorado,
Valmount
Power
Station,
S Boulder
Be
F
As
Se 1.9
Cd
Hg 0.07
Pb S5
Br
Zn 7.3
Cu 9.6
Ni
Cr
V
Ba
Sr 120
Montana Wyoming
and Powder Montana
Dakotas River Colstrip Utah
0.12-3,9 0.25* Trace 1.0
65 56.5 31.6 66
2.1 Trace 0.5
1.1 0.016 1.2
O.llt 0.23 <0.2
0.07 0.12 0.15 0.04
7 5.3* 4.8 5
21.0 23
6.6 10
15 13.7 £100 10
7 4.0 4
7 7.7 2.9 7
16 20.9 2.5 10
206.3
92.6
Tenn. Maryland
Penn.- Allen Chalk Pt
Ohio- Power Power
Illinois W. Va. Plant Plant
1.9 2.0-3.1 0.3
42-134 50-120
14 3-59 5 25
2.2 5.1
SO. 2-22 (0.39) 0.46
0.24 0.12-0.21 0.12
49 4-14 4.9 9.6
15 4.3 41
342 (24.8) 80
15 14-17
23 9.7-20 25
17 11-15 29
34 19-25 40
150
86
*44 percent of the coal samples contained less than 0.15 ppm beryllium.
t70 percent of the coal samples contained less than 0.1 ppm cadmium.
*8 percent of the coal samples contained less than 1.5 ppm lead.
Source: Reference 31.
175
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Trace elements such as arsenic and selenium, which can
react with hydrogen, may enter the gas phase during liquefaction.30
Those that are not removed during cooling and scrubbing of the gas will
enter the atmosphere if byproduct gases are combusted to provide plant
steam and heat.
Finally, some trace elements, especially those which are
bound to organic molecules in the coal, will be carried through into the
synthetic crude oil product.
During oil shale retorting, trace elements are carried
over into the raw shale oil product. Twenty-nirfe trace elements have
been detected in raw shale oil,12 including all of those listed in Ta-
ble 4-13. Undoubtedly, a large fraction of the trace elements will re-
main with the spent shale. Further processing and upgrading of the raw
shale oil may result in the introduction of some elements into waste
streams. The ultimate disposition of all solid and liquid waste streams
will be in the spent shale pile. Therefore, the major potential source
of environmental contamination will be from leaching from this pile or
failure of a catchment dam.
Although it is certain that some of the trace constitu-
ents in the raw shale oil will remain in the syncrude product, there
has been no quantitative measurement of their concentrations. In gen-
ei-al, few quantitative assessments of the presence of trace elements in
synthetic fuel products or waste streams have been made. Much more
research must be carried out in this area before any realistic evaluation
of potential health hazards from trace element emissions from synthetic
fuel plants can be undertaken.
176
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4. Costs and Dollar Flows
a. Investment and Operating Costs
The Arab oil embargo of late 1973 and the subsequent in-
creases in world oil prices brought about a renewed interest in the pos-
sibility of using synthetic crude oil from coal and oil shale to augment
declining domestic oil reserves. One of the greatest areas of concern
has been the question of whether synthetic liquid fuels can be economi-
cally competitive with conventional fuels even at high prevailing world
prices.
During 1974, a number of studies were carried out in
which new cost estimates were made, or previous estimates revised, to
determine the costs at which synthetic fuels could be produced from coal
and oil shale, and the prices at which they would have to be sold to
achieve a reasonable return on investment. Table 4-15 summarizes some
of the estimates of costs and prices made during this period. All dol-
lar figures are in 1973 dollars.
Unfortunately, these estimates were made during a period
of rapid inflation, and few knowledgeable sources would consider the
figures shown in Table 4-15 to be representative of current costs. The
figures do, however, provide a relative basis of comparison for the costs
of synthetic fuels.
From mid-1973 to late 1975 chemical plant construction
and operating costs have increased by nearly 30 percent. Thus, the
synthetic fuel prices shown in Table 4-15 would be at least 30 percent
higher if estimated using current cost figures. However, even if infla-
tion is properly accounted for in making cost estimates, there is another
reason why the resulting figures are likely to be low. As new technolo-
gies move from the R&D stage through the pilot plant and demonstration
plant level and approach commercialization, the bases for making
177
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Table 4-15
COST ESTIMATES FOR SYNTHETIC LIQUID FUELS (1973 COSTS)
Size
Type of Plant (B/D)
a
H-Coal 100,000
(Navajo coal)
b
H-Coal 100,000
(Powder
River coal)
b
H-Coal 100,000
(Illinois
coal)
c
H-Coal 30,000
(Bituminous
coal)
a
Mcthanol 81.200
(Navajo coal;
Lurgi gasi-
ficr)
d
Mcthanol 81,200
(Xavajo coal;
Lurpi gasi-
fier)
Mcthanol 35,800
(Illinois
coal ;
Koppcrs-
Totzck
unsi f icr)
Oil shale, a 100, OOO
mining, re-
tort ins Si
up-1-.idiiiK
(TOSCO II
retort : 35-
K:I! ton
sh.i 1 1-)
Capital Operating
Cost Cost
(S106) ($108/yr)
1014 160
199
668 133
685 188
260 61
475 63
79
517 82
353 50
643 70
Cost of
Byproduct Credits Coal
($10e/yr) ($/ton)
113 3
(Sulfur, 1.8;
ammonia, 9.5; 5
fuel gas, 102)
12 3
(Sulfur, 1.5;
ammonia, 10.5)
20.3 9
(Sulfur, 7.6;
ammonia, 13.7)
33 8
(Fuel gas)
28 3
(Tar, tar oil.
naphtha , phenol 5
ammonia, and
sulfur, 18;
methane, 10)
36 3
(Tar oil, naphtha,
phenol , ammonia ,
sulfur and higher
alcohols)
1 7.30
(Sulfur)
5
(Coke, sulfur and
ammonia)
Rate of
Return
(% DCF)
10
15
10
15
10
15
10
15
10
15
10
15
10
15
15
12
10
15
Price of
Product
($/B)
8.00
10.70
8.70
11.40
7.80
9.80
9.30
11.40
8.08
10.70
5.10
6.70
5.70
7.30
4.10
9.80
4.70
6.00
(continued)
178
-------
Table 4-15 (concluded)
Capital Operating Cost of Rate of Price of
Size Cost Cost Byproduct Credits Coal Return Product
Type of Plant (B/D) ($106) ($106/yr) ($106/yr) ($/ton) (% DCF) ($/B)
Oil shale, 100,000 522 82 8.6 — 12 5.20
mining, re- (Coke, sulfur.and 15 6,10
torting t ammonia) 20 7.90
upgrading
(gas com-
bustion
retort, 30-
gal/ton shale)
Oil shale,g 54,500 421 82 7 — 12 8.70
mining, re- (Coke, sulfur and
torting t ammonia)
upgrading
(gas com-
bustion
retort; 30-
gal/ton shale)
a. From Reference 1.
b. From Reference 8.
c. From Reference 25. Capital recovery factors of 20 and 30 percent were used to calculate
prices in the table instead of 15 percent used in this reference.
d. From Reference 6. Methanol price based on utility financing, assuming a 75/25 debt-to-equity
ratio and a 9 percent cost of capital.
e. From Reference 2.
f. From Reference 32.
g. From Reference 33.
179
-------
accurate cost estimates become more concrete. Cost estimates made early
in the developmental stage of a technology are simply not able to antici-
pate the cost factors that are realized at later stages of development.
Oil shale retorting and upgrading is currently closer to
commercial development than any of the other synthetic liquid fuels con-
sidered in this paper, and recent cost estimates have tended to confirm
the above discussion. When Colony Development Operation announced sus-
pension of its plans to develop the first commercial oil shale facility
(October 1974), the capital cost estimates for a 50,000-B/D plant had
increased 45 percent (from $435 million to $630 million) in six months.
This sort of cost inflation, due to actual increases in components of
construction costs plus more realistic estimates of total costs, will
undoubtedly continue to characterize the synthetic fuels economic
picture.
b. Dollar Flows for Plant Construction and Operation
To understand the disposition of money spent for the con-
struction and operation of synthetic fuel plants it is not necessary to
display the total cost of construction or plant operation but only the
relative sizes of the components of the total costs. Figures 4-12 and
4-13 show breakdowns of the capital cost and operating expenses for a
100,000-B/D H-Coal plant. These breakdowns were derived from actual
costs presented in Reference 8 and the capital cost estimating techniques
discussed in Reference 34. The relative costs of construction shown in
Reference 34 were updated from 1969 to 1973 using components of plant
cost indices published in Chemical Engineering.
Figure 4-12 shows that equipment and materials constitute
the largest source of capital expenditure, contributing nearly 50 per-
cent of the plant construction cost. The next largest single item is
180
-------
00
EQUITY FINANCING
jlOO
CAPITAL
INVESTMENT
11
INTEREST
DURING
CONSTRUCTION
,79
PLANT
CONSTRUCTION
,. 30
EQUIPMENT
,, 16
MATERIALS
0.15
LAND
COSTS
2.4
ROYALTIES
ENGINEERING,
SUPERVISION
AND LABOR
6.3
PAYROLL
BURDEN AND
OVERHEAD
2.4
FIGURE 4-12. CAPITAL INVESTMENT DOLLAR FLOWS FOR H-COAL LIQUEFACTION PLANT
-------
labor (including engineering and supervision) which contributes over
20 percent of the cost if payroll burden (fringe benefits) is counted.
In the operation of a coal liquefaction plant, the single
largest expense item is the coal. The operation is not particularly
labor intensive. On the other hand, the coal mining operation is con-
siderably more labor intensive, with salaries and associated benefits
consuming 30 percent of the mine revenue.
As shown in Figure 4-13, capital recovery and profit—the
sum of depreciation, net income, and income taxes—contribute an over-
whelming amount to the price of syncrude—nearly .two-thirds if the
operation of both mine and liquefaction plant are counted. These figures
are proportional to the capital cost of the plant and mine so that in the
long run it is mainly the initial capital investment in synthetic fuel
facilities that will determine the viability of the industry. This is
true, of course, not only because of the effect of capital costs on
product prices, but also because of the difficulty in marshalling
sufficient capital for the development of the industry.
182
-------
J^
LABOR AND
STTPFRVTSTON
SUPERVISION
PRODUCT AND
BYPRODUCT SALES
INCOME
TAX
OPERATING
COSTS
11
DEPRECIATION
5.4
, PAYROLL
BURDEN AND
OVERHEAD
,16
COAL
4.2
UTILITIES
6.8
CATALYSTS ,
CHEMICALS AND
SUPPLIES
16
COAL MINE
REVENUE
1.6
DEPLETION
ALLOWANCE
9.6
OPERATING •
COSTS
0.44
UTILITIES
DEPRECIATION
1.6
4.9
LABOR AND
PAYROLL
BURDEN
2.7
0.44
qiTPPT TF
-------
REFERENCES
1. F. H. Kant, et al.f "Feasibility Study of Alternative Fuels for
Automotive Transportation," Exxon Research and Engineering Co.,
EPA Contract No. 68-01-2112 (June 1974).
2. J. Pangborn, et al., "Feasibility Study of Alternative Fuels for
Automotive Transportation," Institute of Gas Technology, EPA Con-
tract No. 68-01-2111 (June 1974).
3. D. C. White, "Overview of the Energy Shortage Situation: How Real
Is It and What Are the Options for the 1970s and the Necessary
Policy Decisions to Make Them Viable," Business Economics, p. 46
(September 1974).
4. "Project Independence Blueprint, Final Task Force Report—Coal,"
Federal Energy Administration (November 1974).
5. W. W. Bodle and K. C. Vyas, "Clean Fuels from Coal," The Oil and Gas
Journal, p. 73 (August 26, 1974).
6, "A SASOL Type Process for Gasoline, Methanol, SNG, and Low-Btu Gas
from Coal," M. W. Kellog Co., EPA Contract No. 68-02-1308 (July
1974).
7. "Evaluation of Coal Conversion Processes to Provide Clean Fuels,"
University of Michigan, College of Engineering, Electric Power
Research Institute Project 206-0-0 (February 1974).
8. R. Goen, et al., "Synthetic Petroleum for Department of Defense
Use," Stanford Research Institute, ARPA Contract No. F30602-74-C-
0265 (November 1974).
9. T. B. Reed and R. M. Lerner, "Methanol: A Versatile Fuel for
Immediate Use," Science, 1299, 182 (1973).
10. N. T. Cowper, et al., "Processing Steps: Keys to Successful Slurry-
Pipeline Systems," Chemical Engineering (February 7, 1972).
11. "Final Environmental Statement for the Prototype Oil Shale Leasing
Program," U.S. Department of the Interior, Vol. I (1973).
184
-------
12. "An Environmental Impact Analysis for a Shale Oil Complex at
Parachute Creek, Colorado," Colony Development Operation,
Part 1 (1974).
13. "Oil Shale Set Back By Colorado Plant Delay," New York Times
(October 5, 1974).
14. Quantities shown in Figure 4-7 were scaled up from the material
and energy flows presented in the analysis of a 81,433-B/D plant
in Reference 6.
15. Quantities shown in Figure 4-8 were derived from the process
description and flow diagrams in Reference 8.
16. Quantities shown in Figure 4-9 were derived from information in
Reference 12 and K. E. Stanfield, et al., "Properties of Colorado
Oil Shale," U.S. Bureau of Mines Report of Investigations, 4825
(1951).
17. "Revised Report on Environmental Factors, Burnham Coal Gasifi-
cation Project," El Paso Natural Gas Co. (January 1974).
18. Rehabilitation Potential of Western Coal Lands, National Academy
of Science, Ballinger Publishing Co. (Cambridge, Massachusetts,
1974).
19. "Environmental Impacts, Efficiency and Cost of Energy Supply and
End Use," Hittman Associates, Inc., Council on Environmental Qual-
ity, Contract No. EQC 308 (September 1973).
20. "Energy and the Environment: Electric Power," Council on Environ-
mental Quality (August 1973).
21. "Environmental Impacts of Alternative Conversion Processes for
Western Coal Development," Thomas E. Carroll Associates, Old West
Regional Commission Contract No. 10470040 (October 1974).
22. "Cost Analyses of Model Mines for Strip Mining of Coal in the
United States," U.S. Bureau of Mines Information Circular 8535
(1972).
23. "Project Independence Blueprint, Final Task Force Report—Oil
Shale," Federal Energy Administration (November 1974).
185
-------
24. "Project Independence Blueprint, Final Task Force Report—Syn-
thetic Fuels from Coal," Federal Energy Administration (November
1974).
25. M. A. Adelman, et al,, "Energy Self-Sufficiency: An Economic
Evaluation," Technology Review (May 1974).
26. These figures were derived from data contained in The Statistical
Abstract of the U.S., Sec. 28 (October 1974) and "Mineral Facts
and Problems," Bureau of Mines Bulletin 650 (1970),
27. H. Shaw and E. M. Magee, "Evaluation of Pollution Control in Fossil
Fuel Conversion Processes; Gasification; Section 1, Lurgi Process,"
Exxon Research and Engineering Co., EPA Contract No. 68-02-0629
(July 1974).
28. "Environmental Factors in Coal Liquefaction Plant Design," The
Ralph M. Parsons Co., R&D Report No. 82, Interim Report No. 3,
Office of Coal Research Contract No. 14-32-0001-1234 (May 1974).
29. "Analysis of Tars, Chars, Gases and Water Found in Effluents from
the Synthane Process," U.S. Bureau of Mines, Pittsburgh Energy
Research Center, Technical Progress Report 76 (January 1974).
30. P. S. Lowell and K. Schwitzgebel, "Potential Byproducts Formed
from Minor and Trace Compounds in Coal Liquefaction Processes,"
presented at the Environmental Aspects of Fuel Conversion Sym-
posium, St. Louis, Missouri (May 1974).
31. M. D. Levine, et al., "Energy Development: The Environmental
Tradeoffs," Vol. 4, Stanford Research Institute, EPA Contract
No. 68-01-2469 (December 1975).
32. "An Economic Analysis of Oil Shale Operations Featuring Gas Com-
bustion Retorting," U.S. Bureau of Mines Technical Progress Re-
port 81 (September 1974).
33. K. C. Vyas and W. W. Bodle, "Coal and Oil Shale Conversion Looks
Better," The Oil and Gas Journal, p. 45 (March 24, 1975).
34. K. M. Guthrie, "Capital Cost Estimating," Chemical Engineering,
p. 114 (March 24, 1969).
186
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5—NET ENERGY ANALYSIS OF SYNTHETIC LIQUID
FUELS PRODUCTION
By Robert V. Steele
A. Introduction
The concept of net energy has recently been introduced into the
area of energy policy in an attempt to understand the efficiency with
which society uses energy in obtaining new energy supplies. Net energy
can be expressed as a measure of the energy return that is obtained per
unit of energy invested in the energy-producing sectors of the economy,
although analogies with capital investment are not strictly appropriate.
The concept of net energy can be illustrated by the use of an
input/output analysis1 to calculate the energy cost of producing differ-
ent forms of energy. For example, the petroleum refining sector of the
economy provided 44 percent of U.S. energy needs in 1963. However, this
sector also consumed 6.4 percent of the petroleum products, 1.3 percent
of the electricity, and 5.6 percent of the natural gas produced in the
United States during that same year,1 as well as various chemicals and
materials. Consequently, approximately 0.2 unit of resource energy
(coal, crude oil, natural gas, and nuclear and hydro-power equivalents)
was consumed for each energy unit of petroleum products delivered to
the U.S. economy. Thus, the energy return per unit of energy expended
in the petroleum refining sector was approximately 5-to-l in 1963.
The rationale behind the concept of net energy is that new sources
of energy or new energy conversion activities can be examined to deter-
mine those that provide the highest return per unit of energy invested.
If there are two or more competing technologies for accomplishing the
187
-------
same result, then net energy analysis provides a basis for choosing one
over another. There are, of course, other basic considerations such as
cost, environmental impact, social disruption, and so forth, which will
be taken into account in deciding the technology that should be employed.
However, in an age in which energy resources are in great demand and sup-
plies are dwindling, net energy analysis can be an important policy con-
sideration in determining how energy resources can be used wisely.
In principle, net energy analysis should clarify discussions of the
resource utilization efficiency of various energy technologies. In prac-
tice, however, probably as much confusion has been generated as under-
standing. This is due, in part, to the varying definitions of net energy
used by different sources, and in part to the various advocacy positions
that net energy calculations are called on to support. In this chapter,
we will attempt to define carefully what is meant by net energy and to
set forth clearly the processes by which numerical values are obtained.
Often, net energy is defined as the energy value of the products
delivered to society by an energy-producing or conversion process minus
the energy required to carry out the production or conversion. The in-
tent of this definition is to allow one to determine how much energy is
actually made available to society by a process if one also counts the
energy that is consumed, or made unavailable, as a result of carrying
out the process. It has been common practice to express the energy con-
sumed in carrying out the process in terms of the energy value of the
energy resources that are consumed to provide fuel, materials, and so
forth, to run the process. Thus, the net energy figure is expressed as
the difference between energy in the form of deliverable products and
energy in the form of raw resources. This is somewhat akin to subtract-
ing apples from oranges, although both energy figures are expressed in
Btu or the equivalent. The problem has to do not so much with the
thermodynamic "quality" of the energy form (expressed as availability,
188
-------
or the ability to do work), although this may occasionally be an impor-
tant factor, as it does with the "quality" of the energy form as measured
by its usefulness to society. The social utility of a Btu of gasoline
is obviously much higher than that of a Btu of crude oil in the ground.
Thus, it is desirable to express net energy in a way that makes clear
the nature of the units specified.
The mathematical formulation of net energy used throughout this
chapter is explained with the help of the energy flow diagram shown in
Figure 5-1. In this diagram, the quantity Ereg is defined as the energy
content or heating value of the resource that is converted to a useful
product. It is sometimes called the "primary" resource energy. Eprod
is defined as the energy content or heating value of the product that is
produced by the conversion process. Since there is always some energy
• res
ENERGY
CONVERSION
PROCESS
•*• Eprod
Efuel
Emat
Eprod
NET ENERGY RATIO =
( Eres — Eprod ) + Efuel +
FIGURE 5-1. FLOW DIAGRAM FOR DEFINITION OF
NET ENERGY RATIO
189
-------
loss during conversion, EDrocj is always less than Eres. (The conversion
efficiency of a process is sometimes referred to as the ratio of Eprotj
to Ereg.) Tne quantity (Ereg - Eprod) represents the resource energy
lost during the conversion process. Other energy inputs to the process
include any externally supplied fuel, which is consumed to provide steam,
heat and electricity for running the process, and the energy consumed in
building the plant and in fabricating the materials used in operating
and maintaining the plant facilities. These energy inputs are repre-
sented by Ejuel and Emat, respectively. (The quantity E is sometimes
called the ancillary energy.) It is important to note that E.pu ^ in-
cludes, in addition to the energy value of the fuel itself, all the
energy consumed in extracting and processing the fuel as well as dis-
tributing it to the point of use.
With these definitions we have the tools to formulate a working
relationship for the net energy ratio of a process: it is defined sim-
ply as the useful product energy output of the process divided by the
resource energy that has been lost during conversion or consumed in the
form of fuel or materials input to the process.
Eprod
Net energy ratio = — - - -
-------
This result tells us that for every two units of product energy produced,
one unit of resource energy was expended. Thus, the net energy ratio is
merely a measure of the quantity of energy that is made available to
society in a particular form per unit of resource energy consumed in the
conversion process.
It is clear from the discussion above that the net energy ratio can
have any value between zero and infinity. Higher net energy ratios are
more desirable than lower net energy ratios since a greater energy re-
turn on energy investment is achieved. Net energy ratios less than one
mean that the break-even point for return on investment has not been
attained; more energy was consumed than was produced as product energy.
However, this does not necessarily mean that the technology in question
should not be employed. For example, the production of electricity,
which supplies a large fraction of the nation's energy needs, has a net
energy ratio of about 0.36 (1967 data).2 Society is willing to expend
nearly three units of resource energy to obtain one unit of electricity
since electricity is a convenient, clean, transportable, and efficient
energy form relative to the resources from which it is obtained. Thus,
net energy considerations have a relatively small impact on society's
judgment about the development and use of this energy source.
With respect to the development of new technologies (such as those
for producing synthetic fuels for automotive transportation) in which
several different processes are capable of meeting the same end-use
needs, net energy analysis can provide a valuable input to decision
making regarding the most efficient use of resources.
B. Methodology
With the definition of net energy established, there remains the
task of obtaining the appropriate data to calculate numerical values of
191
-------
the net energy ratios for coal liquefaction, methanol from coal, and oil
shale processing. These data are generally available in the literature
or from published reports on conceptual designs for synthetic fuel plants,
The data are generally of two types. One is simply the energy value of
the resource input, ancillary fuel requirement, and product output of
the process in question. These values can be used directly in the net
energy calculation with one exception: any fuel that must be purchased
from external sources (i.e., is not generated within the process itself)
must have its energy content multiplied by the appropriate factor to ac-
count for the resource energy that is required to extract, process, and
transport that particular fuel. External energy sources to which this
correction applies are natural gas, refined petroleum products, and
electricity. The fuel-to-resource conversion factors are shown in Ta-
ble 5-1.
Table 5-1
FACTORS FOR CONVERTING ENERGY CONTENT OF
PURCHASED FUELS OR ELECTRICITY INTO RESOURCE ENERGY*
Conversion Factor
Fuel (Btu/Btu)
Refined petroleum products 1.208
Natural gas 1.101
Electricity 3.796
Source: Reference 2.
The second class of data is that in which inputs of materials into
the construction or operation of a plant are given in dollar values.
These values can also be converted to resource energy equivalents by
192
-------
using the energy input/output table in Reference 2. This table lists
the energy input (in the form of direct fuel and materials purchases
from all other sectors of the economy) per unit dollar output for each
of 360 sectors in the U.S. economy for 1967 (the latest year for which
complete input/output data are available). To account for inflation,
the appropriate deflator is applied to convert from costs applicable to
the year in which the dollar estimates were made to 1967 costs. These
deflators are obtained from the Plant and Equipment Cost Indices pub-
lished monthly in Chemical Engineering.
It would be preferable to obtain the energy embodied in materials
inputs by knowing the quantities of materials involved and multiplying
by the appropriate value of resource energy required to produce a unit
quantity of material. However, in many cases either the quantities of
materials are not readily available or the energy required for producing
the materials is not known. This is why the input data in Reference 2
are particularly useful. However, it is important to realize that the
Btu per dollar figure for a given sector averages over many different
types of products whose energy inputs per unit quantity and dollar val-
ues per unit quantity may vary widely. Thus, these numbers should be
considered only a gross estimate for a given type of material input.
The roughness of this estimation is considerably mitigated, however,
because the energy embodied in material inputs is generally a small
fraction (2 to 5 percent) of the total energy input to synthetic fuels
production. Thus, considerable error in these estimates leaves the net
energy ratio hardly affected.
The method of performing net energy calculations can be illustrated
by calculating the net energy ratio for surface coal mining in the south-
western United States.
193
-------
The net energy of surface coal mining is important for synthetic
fuels net energy calculations since this is the first step in the set of
activities by which coal is converted to methanol or synthetic crude oil.
The data for surface coal mining were obtained from Bureau of Mines in-
formation3 as well as from plans by El Paso Natural Gas Company for sup-
plying coal to its proposed Burnham, New Mexico, coal gasification plant.4
Since the coal seam thickness tends to be lower, and stripping ra-
tios higher, for southwestern coal deposits than those in the Northern
Great Plains area, the energy required to extract a given quantity of
coal is significantly higher for the Southwest than for other major
western coal areas. Thus, the net energy ratio calculated for surface
coal mining may be considered to be at the lower end of the range of
possible values for western coal.
Figure 5-2 shows all the annual material and fuel inputs required
for the operation of a 5-million ton/year (4.5 X 109 kg/yr) surface coal
mine. The electricity figure includes the electric power required to
operate the dragline, conveyor belts for coal loading and all other
electrical equipment. The diesel fuel figure includes the fuel require-
ments for coal trucks, bulldozers, reclamation equipment, and all other
mine vehicles. Both of these energy requirements have been converted to
resource energy using the conversion factors shown in Table 5-1. In
Figure 5-2 and in subsequent figures, fuel inputs are shown as ellipses,
materials inputs are shown as squares, and resource energy inputs are
shown as triangles.
To calculate the resource energy embodied in the materials utilized
in the coal mining operation, dollar figures for these quantities (shown
in the appropriate squares in Figure 5-2) were taken from Reference 3
and subsequently converted to resource energy inputs by using the 1967
input-output table of Reference 2. Since this table is broken down into
194
-------
EXPLOSIVES
$0.68 x I06
SPARE PARTS
$2.0 x 10
6
MINE
CONSTRUCTION
$2.1 XIO6
MISC.
$0.25 X I06
MATERIALS
LUBRICANTS
$0.07 XIO6
/ XIO12
TIRES
$0.18 XIOe
COAL MINING
LOADING AND
STORAGE
/DIESEL FUEL
X^ 0.14 XIO12
^^*- I,. i.—'
Z' \J.\Jl\J
XIO12
NOTES: All resource energy inputs and product outputs are in Btu
All dollar figures are in 1969 dollars per year
FIGURE 5-2. ANNUAL ENERGY INPUTS FOR CONSTRUCTING AND OPERATING
A 5 MILLION TON/YEAR SURFACE COAL MINE IN THE
SOUTHWESTERN UNITED STATES
195
-------
only 360 sectors, it is not always possible to find a sector that ex-
actly matches a particular material. In this case, the Btu-per-dollar
figure for the sector that seemed the most appropriate was used. For
example, the spare parts input has no exact equivalent in the table
since the nature of the parts is not specified. However, there is a
fabricated metal products sector, and this was deemed appropriate for
this case.
In Figure 5-2 the dollar figure and resource energy figure for mine
construction are both based on the total mine capital investment amor-
tized over the assumed 20-year life of the mine. The capital investment
for mine construction includes both the initial capital investment of
$28.6 million (1969) and a deferred investment of $0.716 million (1969)
yearly.3 The resource energy associated with the various material in-
puts or other energy consuming activities are shown in Table 5-2. These
inputs or activities were derived from total capital cost estimates in
Reference 3 using a module approach to capital cost estimation to break
out dollar values of individual components of the total cost such as
equipment, labor, and so forth.
Other costs not included in the table are labor, engineering, over-
head, various indirect costs, interest, fees, etc. Resource energy in-
puts due to deferred investment contribute another 0.64 x 1013 Btu
(0.68 x 1015 J) to the total shown in Table 5-2.
Using all the resource energy inputs to the coal mining operation
shown in Figure 5-2, it is possible to calculate a net energy ratio for
this activity. The breakdown of energy inputs and the results of the
calculations are shown in Table 5-3. There is no entry for energy lost
during "conversion." For example, coal left in the ground due to inef-
ficiencies of the extraction process is not counted as "lost" energy.
The calculated net energy ratio of 54 indicates that surface coal mining
is a very efficient activity, requiring slightly less than 2 percent of
196
-------
Table 5-2
ENERGY INPUTS FOR CONSTRUCTION OF A
5-MILLION TON/YEAR SURFACE COAL MINE*
Resource Energy
Components of Construction IP15 Btu 1015 J
Mining machinery
Equipment ($11.4 million) 0.75 0.79
Materials ($3.1 million) 0.28 0.30
Exploration, roads and buildings
($2.2 million) 0.14 0.15
Unit train loading facilities
($0.75 million) 0.046 0.049
Freight ($0.73 million) 0.052 0.055
Total 1.27 1.34
*Investments in 1969 dollars.
Table 5-3
ANNUAL ENERGY INPUTS AND OUTPUT FOR A
5-MILLION TON/YEAR SURFACE COAL MINE
Resource or
Product Energy
1012 Btu 1015 J
External energy inputs
Electricity 0.93 0.98
Diesel fuel °-16 °-17
Materials 0.41 0.43
Construction and equipment replacement 0.10 0.11
Total i-60 i-69
Mined coal output 87 92
87
Net energy ratio = -—- = 54
1. o
197
-------
the resource energy made available to be consumed in extraction. How-
ever, this does not include the energy consumed in transporting the coal
away from the mine or otherwise making it available for end use.
C. Analysis of Synthetic Fuel Processes
1. Coal Liquefaction (H-Coal Process)
The conversion of western coal to synthetic crude oil via the
H-Coal process is an energy intensive activity characterized by approxi-
mately a 25-percent loss of resource energy during processing and con-
sumption of ancillary resource energy equivalent to nearly 30 percent of
the product energy output.6 Much of the energy lost during processing
is in the form of byproduct gases, which are consumed as additional plant
fuel or steam reformed to provide hydrogen for liquefaction. Additional
loss occurs in the form of char and vacuum bottoms (derived from frac-
tionation of the product), which are gasified to produce hydrogen.
Relatively little of the ancillary energy contribution is in
the form of materials or plant construction. The coal input, product
output, and energy inputs from all other sources are shown in Figure 5-3.
The resource energy input for coal mining and transport is derived from
the data in Figure 5-2 and the additional assumptions that the coal is
hauled by trucks 5 miles (8 km) to the plant, and that 1 percent of the
coal is lost during loading and unloading. The resource energy inputs
for catalysts, chemicals, and maintenance supplies have been calculated
as previously described.
Two different methods were used to calculate the resource
energy inputs for plant construction. The first method was similar to
that used to calculate the coal mine construction energy inputs. Capi-
tal costs from Reference 6 were used in conjunction with plant construc-
tion module data from Reference 5 to break out dollar figures for various
198
-------
co
CD
COAL MINE
AND
TRANSPORT
PLANT
CONSTRUCTION
$30 X I06
MAINTENANCE
SUPPLIES
$10.5 X I06
COAL LIQUEFACTION PLANT
( H-Cool Process)
v COAL ^"X
38.6 X IOI2>/
NOTES: All resource energy Inputs and product outputs are In Btu
All dollar figures ore in late 1973 dollars per year
FIGURE 5-3. ANNUAL ENERGY INPUTS FOR CONSTRUCTION AND OPERATION OF
A 100,000 B/D H-COAL PROCESS COAL LIQUEFACTION PLANT
-------
equipment, materials, and other construction components. The total con-
struction energy input calculated by this method was 21 X 1012 Btu
(22 x 1015 J). The second method simply involved taking the total plant
capital investment figure (late 1973 dollars deflated to 1967 dollars by
a factor of 1.35) and multiplying by the conversion factor in the table
of Reference 2 for the public utilities construction sector. This sector
was chosen since it most nearly represents the construction of the type
of energy conversion facility required for a coal liquefaction plant.
The energy input obtained by this method is 36 X 1012 Btu (38 X 1015 J).
Since the first method of energy accounting tends to underestimate the
construction energy input due to the inability to account for all cate-
gories, it was decided to use the figure derived from the second method.
This provides a simple and direct method of computing construction energy
inputs and is probably a more complete one since the input/output method
takes into account energy inputs from all sectors that contribute to the
construction of the plant.
Table 5-4 shows the resource energy lost during conversion,
along with the breakdown of ancillary resource energy inputs and the cal-
culation of the net energy ratio for coal liquefaction.
The table indicates that the liquefaction of western coal is
a fairly energy consumptive process, returning only about 50 percent more
useful product energy than was invested in the conversion process. How-
ever, for midwestern coal, the more favorable composition of the organic
portion of the coal results in a somewhat lower ancillary energy con-
sumption during liquefaction; the net energy ratio in this case is
about 1.8.
2. Methanol from Coal
The conversion of coal to methanol is a two-step process which
involves the gasification of coal by reaction with steam and oxygen
200
-------
followed by the catalytic conversion of the resulting synthesis gas to
methanol. Due to inefficiencies in both steps, the overall conversion
efficiency for the process is only about 59 percent. In addition, a con-
siderable quantity of coal is consumed as fuel to provide heat, steam,
and electricity to run the process. In the process design on which the
net energy calculation was based,7 it was assumed that to meet environ-
mental regulations the coal is gasified to form a clean, low-Btu fuel
gas, rather than being burned directly. This method of utilizing coal
as an ancillary fuel requires the consumption of about 50 percent more
coal than would burning it directly.
Table 5-4
ANNUAL ENERGY INPUTS AND OUTPUT FOR A
100,000-B/D COAL LIQUEFACTION PLANT
Resource or
Product Energy
1012 Btu 1015 J
Internal conversion loss 58 61
External energy inputs
Coal 40 42
Electricity 15 16
Materials and construction 5.1 5.4
Coal mining and transport 7.3 7.7
Total 125 132
Syncrude output 186 196
186
Net energy ratio = —- = 1.5
12 5
The energy inputs required for the production of 81,400-B/D
(13,000 m3/D) of methanol from Navajo coal are shown in Figure 5-4. The
201
-------
to
o
to
COAL MINE
AND
TRANSPORT
PLANT
CONSTRUCTION
$22 X 10
6
MAINTENANCE
SUPPLIES
$7.0 X I06
COAL TO METHANOL
CONVERSION PLANT
( Lurgi Process)
Notes: All resource energy inputs and product outputs are in Btu
All dollar figures ore in 1974 dollars per year
FIGURE 5-4. ANNUAL ENERGY INPUTS FOR CONSTRUCTION AND OPERATION OF AN
81,433-B/D COAL-TO-METHANOL PLANT
-------
types of inputs are the same as for coal liquefaction, except that all
the electricity required to run the process is produced on-site, and the
energy requirement is included in the ancillary coal input. The produc-
tion of 2000 B/D (320 ms/D) of byproduct naphtha is included in the out-
put since this is a high quality product suitable for refining to gaso-
line and other fuels.
Not shown on the output end of methanol production in Fig-
ure 5-4 is the 25 X 1012 Btu/yr (26 X 1015 J/yr) of tar and tar oil,
which are produced as additional byproducts of Lurgi gasification. These
products are of low quality and are not suitable for refining to other
fuels. Although there is some possibility that they could be used as
boiler fuel, it is more likely that they will be used in nonfuel appli-
cations. Other gasification technologies, such as the Koppers-Totzek
process, yield essentially no byproducts. Nearly all of the coal is
converted to synthesis gas. However, an analysis of methanol production
using the Koppers-Totzek gasifier has shown that the overall coal-to-
methanol conversion efficiency is roughly the same as that of the Lurgi
gasifier. The ancillary fuel requirement, however, is slightly less.8
Table 5-5 shows a tabulation of the conversion energy losses
and external energy inputs along with the calculation of the net energy
ratio for the conversion of coal to methanol. The fact that the net
energy ratio is less than one for this process indicates that more energy
is consumed in conversion than is provided to society as methanol prod-
uct. By comparison with coal liquefaction, the conversion of coal to
methanol appears to be a relatively inefficient use of resources. How-
ever, the coal liquefaction product must be further refined before it
can be used as an automotive fuel, while methanol can be used directly.
The net energy ratio for the entire coal-to-refined products system is
examined in a later section.
203
-------
Table 5-5
ANNUAL ENERGY INPUTS AND OUTPUT FOR
AN 81,000-B/D COAL-TO-METHANOL PLANT
Internal conversion loss
External energy inputs
Coal
Construction and materials
Coal mining and transport
Total
Methanol output
Naphtha output
Resource or
Product Energy
1012 Btu
47
77
Net energy ratio = = 0.66
1015 J
50
63
2.7
^^^•^^^^^••B
117
73
3.6
66
2.8
4.0
124
77
3.8
3. Oil Shale
Oil shale is a resource that is not used directly as a fuel.
It must first be processed to extract the organic portion of the shale
rock (about 11 percent by weight for 35 gal/ton shale), which must then
be upgraded to be suitable as a refinery feedstock or fuel oil. The re-
torting process by which shale oil is extracted is very energy intensive
and involves the heating of large quantities of shale to 900CF (480°C).
However, much of the organic material in the shale can be recovered; the
TOSCO II retorting process recovers essentially all of it.
Because oil shale is unusable in its raw form, a certain amount
of care must be taken in computing the net energy ratio for mining, re-
torting, and upgrading. Unprocessed oil shale has a heating value that
204
-------
can be measured, but in computing the energy loss during retorting and
upgrading this value is not used as the energy content of the resource.
Instead, the energy content of the products of retorting is used as the
basis for the energy loss because the energy contained in the shale is
not useful until it has been extracted as a liquid or gaseous hydrocar-
bon. In practice, the only energy-containing material that cannot be
extracted from the shale is a carbon residue which remains on the spent
shale after retorting.
Figure 5-5 shows the annual energy inputs for oil shale min-
ing,9 retorting,10 and upgrading.10 As mentioned above, the resource
energy input for oil shale includes only the heating value of the hydro-
carbon products actually recoverable by retorting. As shown in Figure 5-5,
the diesel fuel consumed by the mining equipment is obtained as a byprod-
uct from shale oil upgrading.10 This fuel consumption is counted as a
conversion loss. Other conversion losses occur mainly in the form of the
combustion of retort gases as well as some fuel oil to provide heat and
steam for retorting and upgrading. The product from oil shale retorting
and upgrading is simply called synthetic fuel since the process design
on which the analysis is based was for the production of fuel oil and
liquified petroleum gas (LPG) rather than synthetic crude oil.10 The
production of synthetic crude oil probably would not result in a signifi-
cantly different net energy ratio.
Table 5-6 shows the breakdown of conversion energy loss and
external energy inputs, as well as the computation of the net energy
ratio, for a 50,000-B/D (8000 m3/D) oil shale complex. The net energy
ratio of 2.3 for oil shale processing is the highest of the three dif-
ferent alternatives that have been examined for producing synthetic fuel,
probably because oil shale (or at least the organic portion of it) in its
raw form is closer in composition to the final product that is coal,
which results in less severe (less energy consumptive) processing. In
205
-------
(O
§
Notes: All resource energy inputs and product outputs are in Btu
All dollar figures are in 1973 dollars per year
FIGURE 5-5. ANNUAL ENERGY INPUTS FOR CONSTRUCTION AND OPERATION OF A 50,000-B/D
OIL SHALE MINING, RETORTING, AND UPGRADING COMPLEX
-------
addition, it appears that retorting methods such as gas combustion or
in-situ may have been even higher net energy ratios, although the calcu-
lations have not been fully carried out due to insufficient data.
Table 5-6
ANNUAL ENERGY INPUTS AND OUTPUT FOR A 50,000-B/D
OIL SHALE MINING, RETORTING, AND UPGRADING COMPLEX
Resource or
Product Energy
IP13 Btu 1015 J
Internal conversion loss 29 31
External energy inputs
Electricity 10.2 10.8
Plant construction and materials 1.8 1.9
Mine construction and materials 0.45 0^47
Total 41.5 43.8
Synthetic fuel output 94 99
94
Net energy ratio = —;—- = 2.3
41.5
D. Coal-to-Refined Products System
The production of synthetic crude oil from coal, of course, is not
the final step in converting coal into liquid fuels usable by society.
The syncrude must be transported to a refinery to be processed to yield
gasoline, diesel oil, heating oil, and other products. Both the trans-
port and the refining process are energy consumptive and consequently
decrease the net energy ratio of the final products.
207
-------
The energy consumed in transporting crude oil via pipeline has been
calculated assuming a 24-inch (61 cm) diameter pipeline 1000-miles (1600
km) long, corresponding to shipment of syncrude from eastern Montana or
Wyoming to the Midwest for refining. The motive power requirement for
this diameter pipeline is 151 horsepower/mile (70 kW/km), corresponding
to a capacity of 14 million tons per year (1.3 X 108 kg/yr).11 The
resource energy requirement is calculated to be 780 Btu/ton-mile (560 J/
kg-km) for diesel engines or 1020 Btu/ton-mile (740 J/kg-km for electric
motors. An average figure of 900 Btu/ton-mile (650 J/kg-km) has been
used in the net energy calculation. In addition, the energy required to
produce the 500,000 tons (4.5 X 108 kg) of steel used in the pipeline
has been included in the pipeline energy requirement (assuming a 20-year
pipeline life). This contribution represents about 10 percent of the
total.
The energy losses (due mostly to internal use) and external re-
source energy consumption during refining are calculated from data in
Reference 2 as 7.1 percent and 6.5 percent of the crude oil energy input,
respectively. These figures correspond closely with the figures of 6.8
percent and 6.7 percent obtained from nationwide refinery energy effici-
ency and external energy use data.*
The annual resource energy inputs required for the entire coal-to-
refined products system are shown in Figure 5-6. The size of the system
is scaled to a 100,000-B/D (16,000 m3/D) coal liquefaction plant. Ta-
ble 5-7 tabulates the data from Figure 5-6 and shows the net energy
*The results of a recent SRI study6 indicate that the internal loss is
2 percent and the external resource.energy use is 12 percent for re-
fining a 50-50 blend of syncrude and natural crude. The total energy
consumption is about the same as quoted above, however.
208
-------
is)
O
(£>
(246XI012 )
(244XIQ12)
COAL
LIQUEFACTION
PLANT
(100,000 B/D)
XIO
Note '• All resource energy inputs and product outputs are in Btu
FIGURE 5-6. ANNUAL ENERGY INPUTS FOR CONVERTING WESTERN SURFACE-MINED
COAL TO REFINED PRODUCTS IN THE MIDWEST
-------
ratio calculations for the system. The net energy ratio of l.T r?^ii-
cates that nearly as much energy is expended in obtaining refined fuels
from coal than is contained in the fuels themselves.
Table 5-7
ANNUAL ENERGY INPUTS AND OUTPUT FOR A
COAL-TO-REFINED PRODUCTS SYSTEM
(Based on a 100,000-B/D Coal Liquefaction Plant)
Resource or
Product Energy
IP15 Btu 1015 J
Internal conversion loss
Coal transport 2.4 2.5
Coal liquefaction 58 61
Refinery 13 14
External energy inputs
Coal mine 4.5 4.7
Coal transport 0.4 0.42
Coal liquefaction plant 60 63
Pipeline 5.0 5.3
Refinery 12 13
Total 155 164
Refined products output 173 183
173
Net energy ratio = = 1.1
A similar calculation for the oil shale-to-refined products system
results in a net energy ratio of 1.6. For methanol the only additional
step required in the system is transportation since no further refining
is necessary. Adding transportation reduces the net energy ratio for
methanol only slightly, to 0.65.
210
-------
E. Summary
The net energy ratios for three different synthetic fuel processes,
as well as for coal mining and the entire resource-to-end products sys-
tems, have been calculated. These ratios are a measure of the product
energy that is made available per unit of resource energy consumed in
the synthetic fuel conversion process. The net energy ratio calculations
for the three synthetic fuel processes are summarized in Table 5-8 along
with the calculations for the three resource-to-fuels systems.
The main conclusion to be drawn from Table 5-8 is that the conversion
of coal to automotive and other fuels via coal liquefaction is a more ef-
ficient use of resources than is the conversion of coal to methanol.
This remains true even when the additional energy inputs and losses in-
curred in refining the syncrude product are taken into account. On the
basis of converting western subbituminuous coal, about 1.8 times as much
resource energy is consumed in converting coal to methanol as there is
in converting coal to refined products via coal liquefaction.
In considering the conversion of oil shale to refined products, the
comparisons are not as straightforward. On the basis of total resource
consumption, oil shale conversion is clearly the most efficient use of
resources. However, due to the distinctly different nature of the re-
source, it is difficult to draw conclusions regarding the attractiveness
of oil shale with respect to coal liquefaction on the basis of total re-
source utilization. Unlike coal, oil shale has no other practical uses,
and some energy penalty must be exacted just to convert the shale to a
usable form. However, most of the energy consumed in this conversion
is provided by the oil shale itself, in the form of products of retort-
ing. On the basis of the consumption of resources other than oil shale,
the conversion of oil shale to synthetic crude oil appears to be espe-
cially attractive compared with the coal conversion technologies.
211
-------
Table o-B
SUMMARY 01' NKT ENERGY CALCULATIONS FOR SYNTHETIC LIQUID FUELS
Conversion Process
Rcsource-to-Fucls System^
to
M
to
Technology
Coal liquefaction
11 -Coal process,
Powder River coal,
100,000 B/D
11-Coal process,
Illinois coal,
Internal
Lo s s
Btu/yr)*
58
81
Ex tcrnal
Input
(lO1^
Btu/yr) *
67
27
Product
Yield
do1-
Btu/yr)*
186
195
Net
Energy
Ratio
1.5
1.8
Internal
Loss
(101 r
Btu/yr)*
71
98
External
Input
(10lr
Btu/yr) *
84
42
Product
Yield
Btu/yr)*
173
182
Not
Energy
Ratio
1.1
1.3
100,000 B/D
Mcthanol I'rom coal
Lurgi process,
Navajo coal,
81,433 B/D
47
70
77
0.66
47
72
77
0.65
Oil shale
TOSCO II process,
35-gal/ton shale,
50,000 B/D
29
12.5
94
2.3
35
20
88
1.6
* Includes mining of resource.
tlncludes 1000 miles of pipeline for shipment of syncrude or methanol.
ln Btu/yr = 1.06 X 10lh J/yr.
-------
There are several sources of error in computing the values dis-
played in Table 5-8. First, it is impractical to account for all the
energy inputs into a given system. However, since it is possible to
account for the most important inputs, the net energy ratios quoted
above are expected to be in error by no more than 5 to 10 percent due
to such oversights. Several inputs or activities such as research and
development, engineering, etc., which are energy consumptive were not
added into the total simply because the insignificance of the contribu-
tions (much less than 1 percent of the total) was not worth the addi-
tional effort expended in deriving the numbers. Neglecting such con-
tributions represents a real, though very small, source of error.
Moreover, errors may occur in assigning energy values to aggregated
dollar values for certain types of inputs such as construction or main-
tenance. Whenever possible, these figures were compared with calcula-
tions of energy inputs associated with a known subcategory of input as
a check on the reasonableness of the total value. For example, the
energy consumed in the production of roof bolts for room-and-pillar oil
shale mining might be expected to contribute significantly to the total
energy consumption for this activity since large numbers of roof bolts
are required for such a mine (nearly 1000 tons per year or 9 X 105 kg/yr
or a mine supplying a 50,000-B/D plant or 8000 m3/D) . The energy re-
1 P
quired for producing steel roof bolts is about 0.05 X 10 Btu/yr
(0.05 X 1015 J/yr). This compares with the total energy input calcu-
lated for mine supplies of 0.37 x 10ls Btu/yr (0.39 X 1015 J/yr).
Much more work needs to be done on expanding the data base for net
energy calculations to provide straightforward data on as many types of
energy inputs as possible. More information is needed on other types of
synthetic fuel processes as well to facilitate the comparison of differ-
ent processes that accomplish the same objective. The net energy calcu-
lations in this chapter provide a starting point for understanding the
total energy picture for synthetic fuels development.
213
-------
REFERENCES
1. C. W. Bullard and R. A. Herendeen, Energy Use in the Commercial
and Industrial Sectors of the U.S. Economy, 1963," University of
Illinois Center for Advanced Computation Document No. 105 (November
1973).
2. R. A. Herendeen and C. W. Bullard, "Energy Cost of Goods and Serv-
ices, 1963 and 1967," University of Illinois Center for Advanced
Computation Document No. 140 (November 1974).
3. "Cost Analyses of Model Mines for Strip Mining of Coal in the United
States," U.S. Bureau of Mines Information Circular 8535 (1972).
4. "Revised Report on Environmental Factors, Burnham Coal Gasification
Project," El Paso Natural Gas Company (January 1974).
5. K. M. Guthrie, "Capital Cost Estimating," Chemical Engineering,
p. 114 (March 24, 1969).
6. R. Goen, et al., "Synthetic Petroleum for Department of Defense Use,'
Stanford Research Institute (November 1974).
7. "A SASOL Type Process for Gasoline, Methanol, SNG and Low-Btu Gas
from Coal," M. W. Kellog Company, EPA Contract No. 68-02-1308
(July 1974).
8. J. Pangborn, et al., "Feasibility Study of Alternative Fuels for
Automotive Transportation," Institute of Gas Technology, EPA Re-
port No. 460/3-74-012c (July 1974).
9. "An Economic Analysis of Oil Shale Operations Featuring Gas Com-
bustion Retorting," U.S. Bureau of Mines Technical Progress Report
81 (September 1974).
10. "An Environmental Impact Analysis of a Shale Oil Complex at Para-
chute Creek, Colorado," Vol. 1, Colony Development Operation (1974).
214
-------
11. "Report on Gulf Coast Deep Water Port Facilities—Texas, Louisiana,
Mississippi, Alabama, and Florida," Department of the Army, Corps
of Engineers (June 1973).
12. "Environmental Impacts, Efficiency and Costs of Energy Supply and
End Use," Hittman Associates, Inc., Vol. 1, Report No. HIT-561
(January 1974).
215
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6—MAXIMUM CREDIBLE IMPLEMENTATION SCENARIO FOR SYNTHETIC
LIQUID FUELS FROM COAL AND OIL SHALE
By Evan E. Hughes, Robert V. Steele
A. Introduction
Many speculations have been advanced in recent years concerning
future levels of production of synthetic fuels from coal and oil shale.
To set an upper limit on the possible impacts that would result from
production of these fuels, this study requires an implementation scenario
that sets forth the maximum credible rate at which the synthetic fuels
industry (coal and oil shale syncrudes, methanol from coal) could be ex-
pected to develop. This maximum implementation scenario is the subject
of this chapter. It is extremely important to recognize that this
scenario is not a_ prediction of what will occur but is an attempt to
elucidate the maximum possible impact situation.
B. Implementation Schedule
The maximum credible implementation scenario is derived from a hy-
pothesized growth schedule for a synthetic liquid fuel industry presented
in Table 6-1.* The growth schedule indicates a slow start for synthetic
*Approximate conventional-to-metric unit conversion factors relevant to
this chapter are the following:
100,000 B/D is about 16,000 nrVD
1000 AF/Y is about 1.2 X 106m3/Y
10G tons/Y is about 900 X 106kg/Y
1000 acres is about 4.0 X 10sm3.
216
-------
Table 6-1
HYPOTHESIZED GROWTH SCHEDULE OF SYNTHETIC
LIQUID FUELS INDUSTRY
Number of Plants Producing
Year
Fuel Description
Syncrude from coal
30,000 B/D plant
100,000 B/D plant
Total production
(10s B/D)
Syncrude from oil shale
50,000 B/D plant
100,000 B/D plant
Total production
(10s B/D)
Methanol from coal
50,000 B/D plant
100,000 B/D plant
Total production^
(106 B/D oil equivalent)
1980
0
0
0
2
0
0.1
1985
3
0
0.09
2
4
0.5
1990
7
3
0.5
2
14
1.5
1995
7
13
1.5
0
20
2.0
2000
0
40
4.0
0
20
2.0
2
0
0.05
2
5
0.3
2
19
1.0
0
50
2.5
0
80
4.0
*Note that 100,000 B/D is about 16,000 m3/D.
tTo a close approximation, the energy content of a barrel of methanol is
half that of a barrel of oil.
liquid fuels with negligible production before 1985, followed by a rapid
growth until the year 2000. The relatively slow start stems from the
present situation in the oil industry: (1) the increased activity to
find and produce energy from conventional petroleum sources, and (2) the
steady increase in cost estimates for synthetic fuel plants. As a result,
the oil industry can be expected to postpone construction of synthetic
liquid fuel plants in favor of investment in more familiar resources.
217
-------
The scenario projects accelerated growth for oil shale processing
after 1980 and for the coal-based fuels after 1985. Such growth, of
course, assumes that the first plants are successful, both technically
and economically. This assumption is made solely to facilitate construc-
tion of a scenario that depicts the maximum rate at which an industry
could be deployed subject only to physical and general economic con-
straints. Of course, other real world constraints, such as water avail-
ability, would lead to a lower actual rate of deployment.
The rapid increases in synthetic fuel production shown in Table 6-1
have been derived on the basis of several considerations:
• The impact study would be most instructive if it included a
scenario that showed synthetic liquid fuels playing a major
role in meeting U.S. requirements for liquid fuels.
• The rates of growth projected during early years of the commer-
cial production of the alternative fuels should be reasonable
for a new industry.
• The requirements for economic and physical resources to build
and operate the plants should be realistic.
The maximum credible implementation scenario reflects several
judgments regarding the relative states of development of the three
basic synthetic liquid fuel technologies: Oil shale technology is ready
for commercial deployment. Tests have been made on a scale large enough
to confirm the feasibility of the technology and guide the design of a
large plant. Future improvements in the technology (excluding the pos-
sibly significant case of in-situ technology) are not expected to be
pronounced enough to render obsolete a plant begun today. Hence, our
maximum credible scenario for oil shale shows two 50,000 B/D plants in
1980 and an addition of four 100,000 B/D plants by 1985. The commercial
production of methanol and syncrude are restrained relative to oil shale
to reflect the anticipated benefits of further research, development,
and demonstration work on processes of making syncrude from coal and the
218
-------
market uncertainties concerning introduction of methanol for large-scale
use as a fuel. The status of the technology for production of methanol
from coal is similar to that of syncrude from shale—basically ready for
first generation commercial production. The more advanced development
of methanol compared with coal syncrude production derives from the sim-
ilarities of producing methane and methanol from coal, and the greater
attention that SNG technology has received in the last decade compared
with coal liquefaction technology. Oil shale production is shown level-
ing off as a reflection of anticipated water shortages.
C. Comparison with the National Academy of Engineering Scenarios
The National Academy of Engineering (NAE) projection of the maximum
production of synthetic fuels possible in the next 10 to 12 years1 is
compared with those of this study in Table 6-2.
Table 6-2
MAXIMUM POSSIBLE PRODUCTION OF SYNTHETIC LIQUID
FUELS IN 1985: NAE AND SRI PROJECTIONS
NAE SRI
(million B/D oil (million B/D oil
Fuel equivalent)* equivalent)*
Syncrude from coal 0.3 0.09
Methanol from coal 0.3 0.3
Syncrude from shale 0.5 0.5
Total synthetic
liquid fuel in 1985 1.1 0.89
*Note that one million B/D is about 160,000 m3/D,
219
-------
The NAE projections were based on the lead times required to plan
and construct the facilities and on the resources of capital and labor
that must be mobilized to build and operate them. The lower level of
production of syncrude from coal reflects the need for more prototype
plant testing of coal liquefaction plants before beginning the commit-
ment to commercial plants. Oil shale technology is taken to be well
enough developed to justify commitment to a commercial facility now.
Although the NAE Task Force on Energy viewed the technology for produc-
ing methanol from coal as adequately developed to justify commitment to
commercial sized plants, it, too, apparently felt that uncertainties in
the uses of methanol as a fuel on a commercial scale would limit the
estimated maximum production in 1985 to a level comparable to the esti-
mate for syncrude from coal and below the estimate of syncrude from oil
shale.
As Table 6-2 shows, the SRI study's schedule for the maximum cred-
ible implementation of syncrude from coal is lower than the NAE level
for 1985 reflecting our judgment that the expectation of great improve-
ment in technology, combined with the uncertainties inherent in all of
the synthetic fuels, makes the postponement of commitments to commercial-
scale coal liquefaction facilities inevitable. The situation was suc-
cinctly described by a vice president of Exxon Research and Engineering
Company in a talk at Stanford University: Coal liquefaction differs
from other synthetic fuel processes (coal gasification and oil shale
production) in that substantial savings are expected from second genera-
tion technology compared to that presently available. In particular,
while the 10 or 15 percent savings expected from improvements in gasi-
fication technology over the next five years are not sufficient to
justify postponement of construction, the larger (but unspecified) sav-
ings expected from advanced liquefaction technology warrant a go-slow
attitude. Because it is technologically reasonable to deploy present
22O
-------
technology for production of methanol from coal or syncrude from oil
shale, these are suitable levels for a maximum credible implementation
scenario. Therefore, our schedule in Table 6-1 puts methanol and oil
shale production at the levels projected in the NAE study.
In both the oil shale and the methanol cases the actual realization
of the schedules of Tables 6-1 and 6-2 requires that present uncertain-
ties be resolved soon in a way that encourages development of the syn-
thetic fuels. Several recent events make it questionable whether the
maximum credible production levels for 1985 can still occur: (1) The
recent announcement by the Colony Development Company that it will not
start the construction originally planned for spring 1975 on its
50,000 B/D oil shale plant at Parachute Creek in Colorado, (2) the lack
of enthusiasm for oil shale displayed in the "Project Independence
Blueprint" recently published by the Federal Energy Administration
(FEA) ,2 and (3) commercial scale uses of methanol as a fuel will have
to be apparent soon to justify the deployment of the 300,000 B/D (oil
equivalent) production level by 1985. The most likely candidate uses
of methanol emerging before 1985 are fuel for electric utilities (espe-
cially as fuel for gas turbine or combined cycle generators) and auto-
motive fuel for fleet vehicles.
D. Scenarios and Scaling Factors
The projected fuel production schedules shown in Table 6-1 have
been assigned the hypothetical locations shown in Table 6-3 in propor-
tion to reported reserves of surface and underground minable coal and
have been used to derive the scenarios in Tables 6-4 through 6-7. The
scaling factors shown in the tables are used to account for the quan-
tities of capital, labor, steel, and land required for the construction
and operational phases of each of the building blocks used in these
scenarios".
221
-------
Table 6-3
HYPOTHESIZED LOCATIONS OF PLANTS FOR PRODUCING
SW1THETIC LIQUID FUEL FROM COAL
Units for table entries are as follows:
Coal syncrudc plants: S = 30,000 B/D
L = 100,000 B/D*
Mcthanol plants:
S = 50,000 B/D (methanol)
L = 100,000 B/D (methanol)
Surface mine:
Underground mine:
Water:
5 million tons/year
1 million tons/year*
103 acre-ft/year*
Cumulative Quantities
State
Wyoming
Coal syncrude
Mcthanol
Surface mines
Water
Montana
Coal syncrude
Mcthanol
Surface mines
Water
North Dakota
Mcthanol
Surface mines
Water
Mew Mexico
Mcthanol
Surface mines
Water
Illinois
Coal syncrude
Mcthanol
Surface mines
Underground mines
Water
Kentucky
Coal syncrudc
Mcthanol
Surface mines
Underground mines
Water
ttcst Virginia
Coal syncrudc
llclhanol
Surface mines
Underground mines
Water
Ohio
Coal synrriKk'
Mi th.rnol
Stir face mines
Underground mines
Water
1980
0
0
0
0
0
0
0
0
IS
2
8
0
0
0
0
0
0
0
0
0
IS
1
0
8
0
0
0
0
0
0
0
o
0
0
1985
2S
0
2
58
0
0
0
0
IS, 2L
9
39
1L
3
15
IS
1L
1
9
29
0
IS, 1L
1
10
23
0
0
0
0
0
0
0
0
0
0
Year
1990
3S, 2L
2L
14
116
IS
1L
4
24
IS, 5L
20
86
3L
8
46
IS, 1L
4L
3
40
98
IS
IS, 3L
3
23
62
IS
1L
1
9
24
0
0
0
0
0
1995
3S, 5L
8L
42
297
IS, 3L
5L
25
174
13L
47
202
4L
10
62
IS, 3L
9L
8
93
231
IS, 1L
7L
7
52
144
IS
3L
2
21
54
1L
1L
1
18
44
2000
13L
13L
81
584
11L
10L
66
479
21L
76
326
4L
10
62
7L
14L
14
161
415
4L
10L
13
87
266
2L
5L
1
56
134
3L
3L
•1
•19
133
Noli that 100,000 H'D is about 1(5,000 nT/D, 1 million tons/year is about
900 million kg/year, and 1 acri foot is about 1200 ntVycar.
222
-------
Table 6-4
SYXCRUDE FROM COAL: MAXIMUM CREDIBLE IMPLEMENTATION SCENARIO
Scenario for Year
to
to
CO
Data and Assumptions
Production Schedule
Cumulative capacity
(million B/D)
Number of Plants
Small (30,000 B/D)
Large (100,000 B/D)
Inputs and Outputs
Items
Construction
Capital
Labor
Steel
Land
Production
Operating costs
Labor force
Coal (Western)
Water
Electric power
Units
10J 1973 $
10n man-years
10'"3 tons
10'" acres
10- 1973 $/year
103 people
106 tons/year
103 acre-ft/year
MW
1980 1985 1990
0 0.09 0.5
037
003
Scaling Factors
for a
100,000 B/D Plant
(in units specified) 1980
1995
1.5
7*
13 ^"""^
1985
2000
4.0
0
^ 40
Year
1990
1995
2000
Cumulative Amount
0.67 0
7.3 0
110 0
1 0
0.60
6.6
100
0.9
3.4
37
560
5.1
10
110
1700
15
27
290
4400
40
Annual Amount
130 0
1.4 0
18 0
29 0
140 0
120
1.3
16
26
130
650
7.0
90
145
700
2000
21
270
435
2100
5200
56
720
1160
5600
*Arrow indicates that small plants are enlarged and enter large plant classification.
-------
Table 6-5
SYNCRUDE FROM Oil, SHALE: MAXIMUM CHEDI13LE IMPLEMENTATION SCENARIO
Scenario for Year
Data and Assumptions
Production Schedule
Cumulative capacity
(million B/D)
Number of Plants
Small (50,000 B/D)
Large (100,000 B/D)
Inputs and Outputs
I terns
Construction
Capital
Labor
Steel
Land
Production
Operating costs
Labor force
Shale
Wa t e r
Electric power
Land
Units
10r: 1973 $
103 man-years
10P tons
10''' acres
W 1973 $/year
10'? people
10' tons/year
10n acre-ft/year
MW
10° acres/year
1980 1985 1990
0
2
0
.1 0.5 1.5
2 2*
4 14^^
Scaling Factors
for a
1995
2.0
0
20
100,000 B/D Plant
(in
units specified) 1980
1985
2000
2.0
0
20
Year
1990
1995
2000
Cumulative Amount
0.75 0.75
5.4 5.4
90 90
0.6 0.6
3.8
27
450
3.0
11.3
81
1350
9.0
15.0
108
1800
12
15.0
108
1800
12
Annual Amount
80 80
1.7 1.7
54 54
16 16
170 170
0.15 0.15
400
10.2
270
80
850
0.750
1200
25.5
810
240
2250
2.25
1600
34.0
1080
320
3400
3.0
1600
34.0
1080
320
3400
3.0
*Arrow indicates that small plants are enlarged and enter large plant classification.
-------
Table 6-6
METHANOL FROM COAL: MAXIMUM CREDIBLE IMPLEMENTATION SCENARIO
Data and Assumptions
1980
Scenario for Year
1985
1990
1995
2000
to
en
Production Schedule
Cumulative capacity
(million B/D oil
equivalent)
Number of Plants
Small (50,000 B/D)
Large (100,000 B/D)
Inputs and Outputs
I terns
Units
Construction
Capital
Labor
Steel
Land
Production
Operating costs
Labor force
Coal (Western)
Water
Electric power
10" 1973 $
103 man-years
103 tons
103 acres
10s 1973 S/year
10'? people
10C tons/year
10° acre-ft/year
MW
0.05
2
0
0.3
2
5
Scaling Factors
for a
100,000 B/D Plant*
(in units specified)
0.59
7.5
100
1
70
0.9
13
15
100
1.0
2.5
4.0
- °
'^^^50 80
1980
1985
Year
1990
1995
2000
Cumulative Amount
0.59
7.5
100
1
70
0.9
13
15
100
3.5
4.5
600
6
Annual
420
6.4
78
90
600
11.8
150
2000
20
Amount
1400
18
260
300
2000
29.5
375
5000
50
3500
45
650
750
5000
47.2
575
8000
80
5600
72
1040
1200
5000
*The energy of a barrel of methanol is half that of a barrel of oil.
tArrow indicates that small plants are enlarged and enter large plant classification.
-------
Table 6-7
SrHFACK COAL MINKS NEEDED FOR SYNCRUDE PLUS METIIANOL PRODUCTION''
Scenario for Year
CO
Data and Assumptions
Production .Schedule
Cumulative capacity
(million tons/year)
Number of mines
(5 million tons/year)
Inputs and Outputs
Items
Units
Construction
Capital
Labor
Steel
Land1"
Production
Operating costs
Labor force
Wa tot-
Electric power
Land
103 1973 $
lO'"5 man-years
10P tons
Acres
10s 1973 $/year
10'° people
10° acre-ft/year
MW
10'- acres/year
1980 1985 1990
13
3
Seal
for a
Year
94 350
19 70
ing Factors
5 Million Ton/
Surface Mine
(in units specified) 1980
1995
920
184
1985
2000
1760
352
Year
1990
1995
2000
Cumulative Amount
0.03 0.09
0.25 0.75
3 9
10 30
0.57
4.75
57
190
2.1
17.5
210
700
5.5
46.0
552
1840
10.6
88.0
1060
3520
Annual Amount
12 26
0.1 0.3
0.15 0.45
10 30
0.25 0.75
228
1.9
2.85
190
4.75
840
7
10.5
700
17.5
2210
18
27.6
1840
46
4220
35
52.8
3520
88
*Assumes all of the coal requirements for syncrude and methanol plants are supplied by surface mines.
tLand for buildings, storage and handling facilities, parking, etc.; this is not land for mining.
-------
E. Resources
By far, the majority of the commercially significant oil shale
reserves (25 to 30 B/ton of shale or 4.4 to 5.3 m3/103kg) are found in
the Piceance Basin in western Colorado. Unlike oil shale, coal is
widely distributed in the nation. Table 6-8 shows a recent tabulation
of strippable coal reserves and the number of coal liquefaction plants
that these reserves could sustain. Since synthetic fuels will require
low cost feedstocks to be economically competitive (at least initially)
with conventional petroleum fuels, strippable coal has been emphasized.
Clearly, strippable reserves would be able to sustain this study's maxi-
mum credible production scenario for several plant lifetimes. However,
when other coal demands are also taken into account, there is a good
chance that early in the 21st century, strippable reserves will be near-
ing depletion.* This suggests the need to develop both in-situ recovery
techniques and improved methods of underground mining (especially since
present methods cannot efficiently mine the very thick, deep seams of
coal found in the West),
*However, it is important to note that distinction between resources
and reserves. Reserves are the fraction of resources that are eco-
nomically recoverable with state-of-the-art technology at any given
time. Hence, both changes in the market price of a mineral, and the
technology available can alter estimates of reserves, while resource
estimates can be changed only with new discoveries.
227
-------
Table 6-8
STATES AND REGIONS WITH STRIPPABLE COAL RESERVES
SUFFICIENT TO SUPPORT A LARGE SYNTHETIC FUELS INDUSTRY
States
and Regions
Montana
Strippable
Reserves
10s Tons*
43
Number of 100,000 B/D
Plants Sustainable
for 20 Years
at 20 MT/Year
110
Wyoming
North Dakota
24
16
60
40
Illinois/Western
Kentucky 16
West Virginia/
Eastern Kentucky 8.7
40
22
*Note that one ton is about 900 kg.
Source: Reference 3, "Demonstrated Reserve Base,
U.S. Bureau of Mines (1974).
228
-------
REFERENCES
1. U.S. Energy Prospects: An Engineering Viewpoint, Task Force on
Energy, National Academy of Sciences, Washington, D.C. (1974).
2. "Project Independence Blueprint," Federal Energy Administration,
U.S. Government Printing Office (1974).
3. "Demonstrated Reserve Base," U.S. Bureau of Mines (1974),
229
-------
7—LEGAL MECHANISMS FOR ACCESS
TO COAL AND OIL SHALE
Prepared by David F. Phillips (Consultant)
Edited by R. Allen Zink
A. Introduction: Principles
Access to mineral deposits is governed first by the obvious ques-
tion, "Who owns the land?" Actually, the question should be "Who owns
the minerals under the land?" There is an ancient maxim of law that the
owner of the soil owns as well the air above and the earth below—all
the way up and all the way down. The owner of land may dispose of it
as he wishes; he may sell, lease, or otherwise dispose of his rights to
the land, and he may carve up his interest in any way which pleases him.
The principal importance of this in mineral law is that a landowner may
sever the surface and mineral estates (rights), selling or leasing one
and retaining (or selling or leasing to someone else) the other. He
may, in other words, divide his land both vertically (by dividing the
surface) and horizontally (by severing the mineral estate, or even by
severing different mineral strata and disposing of or retaining them
separately). It is common for land to be conveyed with a reservation
of mineral rights, or vice versa.
However, if the mineral estate is severed, the mineral estate be-
comes the "dominant" estate and the surface of the "servient" estate
(that is to say, secondary in right to the mineral estate), which means
that the owner of the surface may not use his ownership to interfere
with the use of the mineral estate beneath. Use of the mineral estate
means doing what is necessary to remove desired minerals from beneath
230
-------
the surface of the land and carry them away. The owner of a mineral
estate has the right of access to it, and the right of entry onto the
surface as is necessary to exploit his mineral estate. He may build
such improvements (roads, buildings, etc.) as are necessary to his use
of the mineral estate. What he does must be "reasonable," and must not
unreasonably injure the surface estate (for example by removing coal in
a way that causes subsidence) ; a bond may be required to protect the
surface owner's estate. The same rule applies in theory to strip min-
ing—as generally understood, a lease or other interest in the mineral
estate does not entitle its owner to devastate the surface. However,
the damage "reasonably" necessary to conduct strip mining operations
may be very extensive indeed. While it may be true that the owner of
the dominant estate may not destroy the usefulness of the servient es-
tate without being liable to compensate the surface owner, even such
compensation may be inadequate from the standpoint of the owner of the
surface. If the owner of the mineral estate decides to exploit his
estate by strip mining, and in the process of so doing utterly destroys
the surface, and is required to pay to the surface-owner the full market
price of the surface, what has happened in effect is that the mineral-
owner has exercised a sort of private eminent domain. This may be un-
satisfactory to the people who live above the mineral, but that is the
way it is in the absence of overriding state laws to the contrary.
The extent of the interest conveyed in a mineral-land transaction
(severance, ownership, leasehold, etc.) and the terms of the transaction
(in the case of a lease rent, royalty, duration, etc.) are matters of
agreement between the parties. Even general common law principles may
be altered by their mutual agreement, subject to the general rules of
contract law on unconscionable contracts, equity, and the like. State
and federal police power is, of course, paramount in the areas where it
properly applies. A state strip mining law is an exercise of police
231
-------
power, and overrides any agreement between the parties. Under the Com-
merce clause of the U.S. Constitution, any coal mines producing coal,
for example, which enters the stream of commerce (and just about all
coal mines are covered by this provision) are subject to the federal
coal mine operating safety laws, as well as to state laws of similar ef-
fect. But beyond this, insofar as access to and rights in the land are
concerned, it is the intentions of the parties which govern any transac-
tion involving rights to minerals. As will be seen, this is true whether
the proprietor of the land is a private citizen, a state, or even the
federal government.
So the first question is "Who owns the mineral estate?" If the
answer is that title to the mineral estate is held by a private indivi-
dual, or by a corporation, or by any entity other than a state or the
United States (holding title either for itself or in trust for an Indian
or Indian tribe), the law which governs access is private law, the law
of contracts and real property. Most of the law regulating the relations
between vendors and vendees, or lessors and lessees, of mineral estates
in private ownership is the result of the common law process. It has
grown out of the decisions of the courts in individual deeds and leases,
in which the object is always to determine and give effect to the inten-
tions of the parties and to do justice in terms of realizing those in-
tentions and in terms of basic equity. They have general application
only in that they govern the interpretation of language in other private
agreements in the same jurisdiction. The term of any future agreements
involving access to coal or oil shale lands in private ownership will
depend largely on what is worked out between the lawyers for the owners
and the lawyers for the developers. There are no regulations to be com-
plied with (environmental protection restrictions are exercises of police
power and are another story).
232
-------
Essentially the same principle governs lands in public (state or
federal) ownership. In permitting access to mineral deposits on land,
the mineral estate of which it owns, the state (or the United States)
acts not as sovereign but as proprietor. The whole elaborate mechanism
of the federal Mineral Leasing Acts, for example, is not an attempt to
regulate access to mineral lands in general but only governs the "inten-
tions of the lessor" when the lessor is the United States. What the law
determines and what the regulations regulate is the terms that the owner
of the mineral estate will insist on in what is essentially still a pri-
vate law transaction The regulations bind the government, but the lease
incorporating the terms the regulations require (and whatever other terms
not required by the regulations but thought wise to insist on by the
Bureau of Land Management) is what binds the lessee. In understanding
any state or federal mineral leasing program it is essential to remember
this basic fact: the end product of the whole process is a lease bind-
ing the government as lessor and the developer as lessee. We are accus-
tomed to thinking of regulations as governing citizens directly, but the
mineral leasing regulations are nothing at all like, say, the Selective
Service regulations. The regulations may require, for example, an annual
rent of not less than $1 an acre, but the lease offered by the government
may require an annual rental of $6 an acre. Even if no state law requires
reclamation of strip-mined lands, a stipulation may be inserted in the
lease as offered by the given state requiring such reclamation and setting
forth in detail what will be required as compliance, and this binds the
lessee not as a matter of oublic law but as a matter of the private law
of his lease. A prospective lessee bids on a lease as offered by the
government, and it is the lease the government offers, when signed by
the lessee, that is the controlling factor in his access to the lands.
233
-------
B. Federal Lands
Figure 7-1 shows the multiple aspects of land generally necessary
to an understanding of the problems of access to mineral lands. Private
lands may be leased or sold at the will of the parties, and state lands
may be leased under the provisions of state law applicable in each case,
as discussed above. But where the federal government is the proprietor
of lands valuable for coal or oil shale, or where (as, for example, under
the Stock Raising Homestead Act) the United States has reserved the min-
eral estate underlying the surface, the land (or mineral estate) may not
be alienated under any circumstances. Title will remain in the United
States, that is, one cannot buy federal coal lands. Access to coal and
oil shale under federal lands may be had only through license, lease, or
permit under the Mineral Leasing Laws, principally the Mineral Leasing
Act of 1920 and the Mineral Leasing Act for Acquired Lands of 1947, both
as amended and amplified by the regulations issued under their authority.
In the days before the Mineral Leasing Act of 1920, access to fed-
eral mineral lands was governed by the General Mining Law of 1872.
There was a separate act for coal, the Coal Land Act of 1873, which is
still carried on the books at 30 USC §§71 et seq., but which has been
effectively superseded by the Mineral Leasing Act, as described below.
The compilers of the U.S. Code state their doubt that the laws codified
as 30 USC §§71 et seq. should even be carried in the Code.) Under the
Mining Law (which still governs access to minerals other than those
specifically mentioned in the Mineral Leasing Act*) land "chiefly valu-
able for minerals" was reserved from sale or distribution under the
*The Mineral Leasing Act covers coal, phosphate, sodium, potassium, oil,
gas. oil shale, native asphalt, solid and semisolid bitumen, and bitumi-
nous rock (including oil-imoregnated rock or sands from which oil is
recoverable only by special treatment after the deposit is mined or
quarried). 30 USC §181
234
-------
MINERAL
ESTATE
UNDER FEDERAL
CONTROL
STATE MINERAL
LEASING PROGRAM
to
W
PUBLIC
LANDS
1
LICENSE
PROSPECTING
PERMIT
1
MINING LEASE
FIGURE 7-1. MECHANISMS OF LEGAL ACCESS TO MINERAL ESTATES
-------
general land laws. Entry for prospecting purposes was, however, gener-
ally permitted at will onto public lands. When a prospector discovered
a mineral deposit, he could file a mineral location or claim. He was
then entitled to the exclusive right to extract the minerals and dispose
of them as his own even though he did not hold title to the land. This
practice had its origin in the customs of the early western miners, whose
customs in the absence of any other law in the mining camps of those days
took on the force of law themselves and were more or less recognized and
legitimated by the Mineral Location Act of 1872. Although the Coal Lands
Act of 1873 differed from this model in some respects, it was similar in
approach, and because it is no longer in use, and because the change to
the current leasing system was made with reference to the philosophy of
mineral development exemplified in the 1872 Act, this part of the discus-
sion does not attempt to distinguish between the practices under the 1872
and 1873 laws.
A prospector who filed a mineral location under the old law had an
exclusive right of possession of the surface of the land included within
his location, and the right to the minerals beneath it. There were cer-
tain limits on acreage covered by each claim (although there was no limit
to the number of claims each prospector could file), and to protect his
rights against those of a subsequent locator, a certain dollar amount of
improvements was required of him to ensure that the mineral deposits were
in fact developed and not simply held for speculative purposes. But as
long as he was engaged in mining activity, the fruits of his labor were
available to him without charge.
Title to land worked under a mineral location remained in the United
States unless an application was made for a patent. Frequently, since
the location was sufficient to secure exclusive possession of the surface
and access to the minerals beneath it, miners proceeded under these lo-
cations until their mines were worked out, at which point they simply
236
-------
abandoned their claims and moved on. If, however, a miner wishes to ac-
quire title to the lands from the government, he could do so easily.
His proof of mineral discovery (which he needed in any case for his lo-
cation) and proof of improvements totalling $500 in five years usually
sufficed to secure him, if he wished, a patent on the lands. In return
for $2.50 an acre for placer claims, and $5.00 an acre for lode claims,
the United States would patent to the miner a fee simple estate (abso-
lute ownership) in the lands.
The purpose of these liberal mining laws was to encourage the devel-
opment of the mineral resources in the public lands of the West. But in
the early years of the 20th century it began to be called into question
whether this encouragement was any longer needed, whether this policy of
permitting almost unlimited transfer of public mineral lands was any
longer serving the public interest. At the time, the conservation move-
ment was gaining political power in the United States. In addition,
there were massive oil strikes in California, all of which were subject
to patenting under the Oil Placer Act of 1897. The freedom given all
citizens, discoverers of oil and (under the Oil Placer Act) those who
had sense enough to file locations on land adjoining known strikes, prom-
ised a rapid transfer of the California oil fields into private control.
In 1909 the Director of the U.S. Geological Survey (USGS reported to the
Secretary of the Interior that at the rate public oil lands in California
were being located and patented by private parties, it would
"be impossible for the people of the United States to continue
ownership of oil lands for more than a few months. After that
the government will be obliged to repurchase [for the Navy and
other government purposes] the very oil that it has practically
given away."
The Director of the USGS asked that the filing of claims on the California
oil lands be suspended pending legislation on the subject. On September
27. 1909,-President Taft issued a proclamation "in aid of proposed
237
-------
legislation" withdrawing over 3,000,000 acres of public domain oil lands
in California and Wyoming from location, entry, or disposal under the
mining laws. There was some question of the constitutionality of the
executive withdrawal of public domain lands from entry and location and
authority was sought and obtained from Congress for this sort of with-
drawal. The law granting this authority was known as the Pickett Act
(43 USC §§141-3). + The Pickett Act gave to the President authority
"at any time in his discretion, temporarily L^°J withdraw from
settlement, location, sale or entry any of the public lands of
the United States. . .and reserve the same. . .for public pur-
poses. . .and such withdrawals shall remain in force until
revoked by him or by an Act of Congress."
During the years 1910-20, most of the public domain land was with-
drawn by executive action from location for nonmetallif erous minerals,
and there was a vigorous debate in the Congress on what the new federal
policy should be in this area. In 1920 it was decided and enacted that
public domain land valuable for coal, oil, phosphate, oil shale, gas and
sodium should be developed only by lease, reserving title (and such con-
trol over its development that the leasing method would provide) to the
United States, rather than permitting the alienation of mineral lands by
patent. From the enactment of the Mineral Leasing Act on February 25,
1920, forward, the older Mining, Coal, and Oil Placer Acts ceased (except
in situations relating to claims filed before enactment) to have appli-
cation to coal and oil shale development, and the Mineral Leasing Act
*Resolved in favor of its constitutionality in United States v. Midwest
Oil Company, 236 U.S. 459 (1915).
f(The constitutionality of the Pickett Act has never been decided by the
Supreme Court, but the Attorney General has ruled in its favor, 49 Op.
Atty.Gen. 73 [l941J. Especially in light of the Midwest decision cited,
however, there is not really any serious doubt of the constitutionality
of withdrawal of public mineral lands.)
238
-------
became the keystone of the law relating to development of coal and oil
shale on the vast public domain.
The phrase "public domain" requires some explanation. It will be
noted in Figure 7-1 that a distinction is made between public domain land
and acquired lands. The Mineral Leasing Act of 1920 itself only covers
public domain lands, which are not coextensive with the lands owned by
the federal government. Public domain lands are those lands to which
title has never been in state or private hands since the land became
subject to United States sovereignty by conquest or treaty, but which
have been in federal ownership since the beginning of American dominion,*
A great portion of the lands in Montana, Colorado, and Wyoming are public
domain lands, never having been alienated by the United States. The Min-
eral Leasing Act of 1920 also applies to the mineral estate of public
domain lands where the surface estate was severed and conveyed but the
mineral estate retained, as was the case under the Stock Raising Home-
stead Act.
West Virginia, on the other hand, was formed from Virginia during
the Civil War and Virginia was one of the original states. Title to (as
opposed to sovereignty over) nonprivate land in Virginia was not origi-
nally in the United States, having been transferred from Crown to Common-
wealth at the time of independence or before. There are, therefore, no
public domain lands in West Virginia.
*Lands that were in private ownership at the time of cession to the United
States remained in private ownership; sovereignty changed but proprietor-
ship did not. In some cases, however, depending on the law which applied
before cession, only the surface estate was in private ownership and the
mineral estate, or part of it, was in the possession of the former sov-
ereign and therefore passed to the United States and is in the public
domain. This is an intricate problem of title which has to be resolved
on an individual basis for the lands in question.
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The situation whereby the Mineral Leasing Law, and its underlying
policy, applied to some federal lands and not to others was an anomalous
one to say the least, and it was cured by the passage of the Mineral
Leasing Act for Acquired Lands (30 USC §§351 et seq.) in 1947. Under
the Mineral Leasing Act for Acquired Lands, provision is made for lands
acquired by the United States in other ways to be administered and leased
in the same way as are public domain lands.
There are several surviving applications of the difference between
public domain lands and acquired lands for federal mineral leasing pur-
poses. First, not all acquired lands are covered. As with public domain
lands, some lands are excluded from disposition under the Act, including
lands in incorporated cities, towns and villages, lands in national parks
or monuments, lands in military petroleum or oil shale reserves, etc.
Lands acquired for development of their mineral deposits and land ac-
quired by foreclosure or otherwise for resale are excluded from the Ac-
quired Lands Act. Also, there are certain technical differences in the
wording of the two Acts. For example, the 1920 Act excludes "lands with-
in the naval petroleum and oil shale reserves," whereas the Acquired Land
Act excludes "lands set apart for military or naval purposes, including
lands within the naval petroleum and oil shale reserves." It therefore
becomes important, if there is coal discovered beneath some vast military
gunnery range in Utah, whether the lands are public domain (in which case
they would be subject to leasing under the Act if the decision was made
to switch the use of the land from gunnery to mining) or later acquired
(in which case they would be excluded from the leasing program by the
language of the statute). These are concerns that matter only as to
individual tracts, but the distinction is still important for this
reason.
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Second, acquired lands may be sold. This is not to say that patents
can be awarded as under the old system, but public domain lands chiefly
valuable for Leasing Act minerals may not be sold.
Third, acquired lands are frequently under the jurisdiction of some
agency of government other than the Bureau of Land Management. If that
is the case, the head of the government agency having control over the
lands is to be called to report whether he has objections to the lease
being granted. If he recommends a special stipulation be inserted into
the lease to protect the interest of the United States, that will be
done. If the lands are segregated for a special purpose, that purpose
is to be considered the dominant purpose of the land, and mining opera-
tions under lease will be permitted only insofar as they are consistent
with the primary purpose of the land. The point is that acquired lands
acquired for mineral purposes are excluded from the application of the
Mineral Leasing Act for Acquired Lands, and acquired lands acquired for
some other purpose may well be being used for that other purpose or at
least be administratively segregated for another purpose, and fall under
the jurisdiction of some other agency, in which case additional steps
must be taken to involve the administering agency in the terms of a pro-
posed lease, to protect the primary purpose of the land, and so on.
(Public domain lands may also be administratively segregated.)
Fourth, lands leased under the 1920 Act and lands leased under the
Acquired Lands Act are computed separately for purposes of acreage lim-
itations on coal leases, and those held under one Act are not credited
against the limitation of the other Act. The acreage limitations for
each Act are the same—it is the intention of the Acquired Lands Act
that the acquired lands subject to the Act be administered in the same
way as the public domain lands—but the separate computation provides a
loophole to permit a lessee to go the limit in a given state twice.
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Beyond these differences, however, the distinction between public
domain and acquired lands does not have much significance. The lines
on the chart now rejoin, and we turn our attention to the three methods
of disposition—license, permit, and lease—without further reference
to the distinction. It should be noted that the following discussion
applies to coal only. Although oil shale is a Leasing Act mineral, ac-
cess to oil shale on federal lands presents special problems and will be
dealt with separately at the conclusion of the discussion of coal.
1. Licenses
A license is a permission to enter on land and do something
which would otherwise be unlawful—for example, a license to remove coal—
which conveys no interest in the land is (unlike a lease) terminable at
the will of the licensor. There is provision in the law for licenses to
remove coal from public land without charge. These are of no real eco-
nomic importance as matters now stand, but they merit a brief discussion
because the license concept has great potential for federal aid to cities
in providing for their own energy needs at no cost to the municipal
budget.
43 CFR §3530.0-1, issued under authority of 30 USC §208, pro-
vides as follows:
"Coal licenses may be issued for a period of 2 years
[renewable] to individuals and associations of indi-
viduals to mine and take coal for their own local
domestic need for fuel, but in no case for barter or
sale, without the payment of any rent or royalty.
[No corporations, except municipal corporations as
follows.] Licenses may be issued to municipalities
to mine and dispose of coal without profit to their
residents for household use. Under such a license
a municipality may not mine coal either for its own
use or for nonhousehold use such as for factories,
stores, other business establishments and heating
and lighting plants."
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Usually such licenses to individuals or associations are limited to 40
acres, and licenses to municipalities to various acreages are dependent
upon their populations. Provision is also made for four-year coal li-
censes to be issued to established state relief agencies to take coal
for distribution to families on their rolls who need the coal for fuel
and cannot pay for it.
As the law now stands, the licensing authority is very limited
and the Act specifically prohibits municipalities from taking coal under
a license for any other purpose than the household use of its residents.
If the law were to be changed, however, it could permit licenses to be
issued to municipalities to take public coal for municipal purposes—
city power plants, street lighting, public buildings, etc. This would
amount to a nonbureaucratic, noncash direct grant of energy to muncipal-
ities, and could be of great benefit to them. Whether the utility com-
pany lobbies would permit its application is another question. The
existence of provision and precedent for coal licenses is something to
think about in forming energy policy in the areas in the West where pub-
lic coal lands are close enough to allow their use.
On February 17, 1973, Secretary of the Interior Morton announced
a moratorium on all coal permits and leases, with certain exceptions, to
permit the formulation of a new coal leasing policy, primarily with ref-
erence to environmental concerns but also, presumably, with reference to
other defects in the present system. (The moratorium had been in effect
de facto since 1971.) This action was similar in intent to the executive
withdrawals of the 1909-19 period discussed above, in that it stops most
further disposition of the public mineral lands pending development of a
program to reflect new policies. Under the moratorium, prospecting per-
mits, one of the two major forms of access to federal coal lands, are not
being granted at all, and new coal leases are being offered only where
they are needed to maintain an existing operation or where coal is needed
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as a reserve for production in the near future. In this "short-terra
leasing program," as it is referred to, the words "short-term" apply
to the program and not to the leasing, since under the law, new coal
leases must still be for an indeterminate term. But these leases are
being offered only on an individually negotiated basis, with extensive
environmental stipulations. Very few are being offered at all. The
moratorium is expected to extend until the completion and adoption of
a programmatic statement on the new coal leasing program. When the
new program is completed and approved, it will go into force and the
moratorium will be over. The present situation is confused. The new
leasing program proposal imposes reclamation and performance standards
upon operations mining federal coal. Moreover, there is a bill being
considered in Congress that would also modify coal leasing on federal
lands. Entitled "Federal Coal Leasing Amendments Act of 1975" (S391),
the bill would make six basic changes in the provisions of the 1920
Mineral Leasing Act.
2. Permits
Under the premoratorium system, prospecting permits were
awarded in the following way. To begin with, as with public land leases
there was a requirement of citizenship. This is not likely to change.
Under the Mineral Leasing laws, prospecting permits and mining leases
could be held only by U.S. citizens. They might be held by such citizens
individually, in associations (if the federal or state laws under which
the association was formed and the instrument establishing the associa-
tion permitted it), or by corporations (subject to the same restrictions).
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An alien might participate only as a stockholder of a corporation, and
then only if the country of which the alien was a citizen afforded re-
ciprocal rights to U.S. citizens.
Once this requirement was satisfied, the Secretary of the In-
terior was authorized to issue prospecting permits to qualified appli-
cants (by which was meant applicants who met the citizen requirements,
did not hold permits or leases in excess of the acreage limitations,
were in fact capable of performing prospecting operations, etc.). The
purpose of the permits was to allow entry and prospecting for coal on
unclaimed and undeveloped areas of the public lands. Since that was the
purpose of the prospecting permit, permits were not granted to prospect
areas where the minerals sought were already known to exist in workable
quantit ies.
Permits were issued to prospect areas in 40-acre units not in
excess of 5120 acres (eight square miles), or for an amount not to exceed
36,080 acres in combination with other oermits and leases in a single
state. The permit ran for two years and could be extended for up to two
additional years if necessary. Coal lands did not have to be surveyed
for prospective purposes, but could be described by metes and bounds,
the actual surveying to be done at the expense of the government. The
two-year permit granted the permittee an exclusive right of entry and
prospecting in the permit area, although no coal was to be removed other
than what was needed for experimental purposes or to demonstrate the
existence of commercial quantities of coal. A plan of operations had to
be submitted and approved. Permit tracts had to be contiguous or at
least reasonably compact in form. An advance rental fee was required
of not less than 25
-------
As with ordinary raining leases, if the lands were under some
other authority than the Bureau of Land Management, stipulations re-
quired by the other authority to protect the primary purpose of the land
were to be inserted in the permit. (To protect the interests of the
United States as potential royalty-owner in the most economical and
fruitful development of the lands, there was also required a demonstra-
tion that there was a need for additional coal which could not otherwise
be met, and that a new coal mine was needed in the area. In practice,
however, these additional need requirements were not enforced.)
If, during the two-year period of the permit (or its exten-
sion) , the prospector demonstrated that he had found coal deposits in
his permit area sufficiently extensive and workable to permit commercial
exploitation, he was entitled as a matter of right to a regular mineral
lease. This was called a preference right lease, and was the incentive
and the payoff for prospecting. The concept of the preference right
lease is under great criticism at the moment. Among other objections,
it is contended that it deprives the government of the bonus it could
otherwise expect if it were to conduct a competitive offering, that it
is not necessary to the encouragement of prospecting (the price of coal
being on the way up), and that it locks up more land in the leasing pro-
gram without sufficient government control. Preference right leases are
not awarded on the successful conclusion of prospecting under a prospect-
ing permit on Indian lands.
During the moratorium, no new prospecting permits have been
awarded and the future of the system is in doubt. Since the preference
right is included in the law (30 USC §20l[b], either the law will have
to be changed or the department can simply adopt the policy of denying
applications for prospecting permits in the future as it has during the
moratorium. This can be justified on the ground that there are already
great areas of public land under coal lease that are not producing coal
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and that there is at present no need to look for more. It seems likely
that the present prospecting permit system will not be a major practical
factor in the new leasing program. However, at the moment at least 147
preference right applications are filed and pending, and it is more than
questionable, if they meet the requirements of the law, whether they may
legally be denied.
The leases awarded under a preference right were, except in
the manner of their awarding, similar to ordinary mineral leases to which
we now turn our attention.
3. Leases
Procedure. Again, the law and the regulations bind the govern-
ment, but it is the lease that binds the lessee. Federal coal leases
(other than preference right leases) are offered on a competitive basis
by advertising the lease it is proposed to offer in a local newspaper of
general circulation in the county where the lands lie. The terms of the
lease are set forth in the offering and are not subject to negotiation;
the competitive bidding has reference to a "bonus" bid that is for the
privilege of signing the lease. These leases may be offered either on
the motion of an applicant or on the motion of the Bureau of Land Man-
agement (BLM), but it appears that in the entire history of the coal
leasing program there has never been a Bureau motion lease sale. It
has been the practice in the past to await a request from the industry
and then to offer the area the industry asks for. A great proportion of
"competitive" lease sales did not attract more than one bidder. Some-
times sealed bids were solicited, and sometimes the lease was sold at
public auction; latter practice permitted even the original applicant
not to bid and to have the lease awarded without paying any bonus at all.
Sometimes the two methods were combined. Of course, the awarding of
these leases was discretionary, and the right of the Secretary to reject
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even the highest bid is preserved in the law, but according to the fig-
ures in the Council on Economic Priorities' (CEP) Leased & Lost, single-
bid and no-bid awards were not uncommon, and there is an inverse rela-
tionship between number of bidders and amount of bonus. The frequently
noncompetitive nature of the competitive bid process, the awarding of
leases without bonus, and the practice of offering leases on industry
demand are all matters which, it can be expected, will be reviewed by
the department. Although these practices may well continue as a matter
of fact, their continuation should not be counted on in the new leasing
program.
Duration. 30 USC §207 sets the duration of federal coal leases
as follows:
"Leases shall be for indeterminate periods upon condi-
tion of diligent development and continued operation
of the mine or mines, except where such operation
shall be interrupted by strikes, the elements, or
casualties not attributable to the lessee, and upon
the further condition that at the end of each twenty-
year period succeeding the date of the lease such
readjustment of terms and conditions may be made as
the Secretary of the Interior may determine."
This means, essentially, that "coal leases are forever." The require-
ment of diligent development and continuous operation has not been en-
forced in the past, although this is likely to change under the proposed
rules discussed below. Twenty years must pass before even such basic
matters as rents and royalties can be adjusted to conform to current
economic conditions. A lease may be surrendered, with the agreement
of the Secretary of the Interior, but the government may cancel it for
nonperformance of terms only by bringing an action against the lessee in
federal court, something which apparently has never happened in the his-
tory of the coal leasing program. The result of the indeterminate term
and the nonenforcement of the diligent development and continuous
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operation requirements has been that very large numbers of coal leases,
including those awarded under the preference-right system, are not pro-
ducing coal. The land is being held unproductive. The Council on Eco-
nomic Priorities believes that a lot of this is due to developers holding
the land for speculative purposes, waiting for the price of coal to rise.
Vice-President William Hynan of the National Coal Association takes vio-
lent exception to this. He says (and his point is supported by CEP
Leased and Lost figures, pp 36-47) that a lot of these leases were
awarded in the 1960s, and the time it takes to go from lease to produc-
ing mine is quite long. He says that at the time a lease is executed
(other than a preference right lease) the developer does not really know
where the coal is, or even.where to look. This seems surprising, since
competitive leases are supposed to be offered on land where the USGS has
determined there is coal. Nevertheless, Hynan says that extensive ex-
ploration is required, and that before a mine can be operated economi-
cally 35 years' worth of coal reserves have to be located, and that in
some cases the remoteness of the coal fields requires construction of
railroad spurs up to 60 miles long. The whole question of nonproductive
leases is the result of ignoring the "diligent development and continuous
operation" requirements of the law and the leases which include these re-
quirements. It is an indication of how seriously these requirements have
been taken over the years that no definition of "diligent development"
or of "continuous operation" had been thought necessary for 54 years
after the passage of the act.
New rules were proposed by the ELM in the Federal Register on
December 11, 1974. If the new rules are adopted, they will clarify these
definitions, and more conscientious applications of the rules can be
expected. The original closing date for comments on the new rules was
January 10, 1975, but it was extended on January 14 to February 3. Bu-
reau of Land Management deliberations pertaining to these regulations
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must now be underway. Mr. Hynan of the National Coal Association objects
to the new rules. The scheme the new rules propose for enforcement of
these statutory lease terms seems to be a sound one, however little it
appeals to coal companies holding unproductive leases, and while it is
not possible to predict the outcome of the political process involved in
making these proposed rules effective, a statement of the proposed new
system will probably be a fair guide to what the new system will be.
Under the new system as set forth in the proposed rules, within
two years of the effective date of the new regulations, all federal coal
leaseholders must have their leases included in what will be called a
"Logical Mining Unit" (LMU). An LMU is defined in the new regulations
as
". . .a compact area of coal land that can be developed
and mined in an efficient, economical and orderly manner
with due regard to conservation of coal reserves and
other resources and in accordance with an approved
Mining Plan."
An LMU may include one or more federal leaseholds and intervening or
adjacent nonfederal coal lands under the effective control of the same
operator or joined by an approved contract for collective development.
Future leases will be predicated on the LMU concept, and existing leases
must, within two years, be transformed into IMUs unless that proves im-
possible, in which case the existing leases will still be considered as
if they were LMUs and will thus be included in the new system. This
amounts to a reorganization of the existing leasing patterns, and this
reorganization is taken as the opportunity to require a new mining plan
to be submitted and approved by the Mining Supervisor of the USGS.
"Diligent development" is now defined as
". . .preparing to extract coal from an LMU in a manner
and at a rate consistent with a Mining Plan approved
by a Mining Supervisor " [emphasis supplied]
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and a long list of activities that may constitute diligent development
is included in the proposed rule.
"Activities that may be approved as constituting dili-
gent development of an LMU include: environmental
studies, including gathering base-line environmental
data and design and operation of monitoring systems;
on-the-ground geological studies, including drilling,
trenching, sampling, geophysical investigation and
mapping, engineering feasibility studies, including
mine and plant design, mining method survey studies;
and research on mining methods, contracting for pur-
chase or lease of operating equipment and develop-
ment and construction work necessary to bring the
LMU into production. The work performed and the ex-
penditure of monies may take place on or for the
benefit of the leased land, or on other lands within
the LMU, or at a location remote from the land so
long as they are undertaken for the purpose of ob-
taining production from the LMU." [emphasis supplied]
"Continuous operation" is defined in the proposed rules as
". . .extraction, processing, and marketing of coal
in commercial quantities from the LMU without in-
terruptions totalling more than six months in any
calendar year, subject to the exceptions [strikes,
elements, etc.] contained in 30 USC §207 and in the
lease, if any."
A coal lease will therefore in the future, as in the past in theory only,
be maintained only on a showing of diligent development or, when required
by the Mining Supervisor, continuous operation. New leases will be let
on the LMU basis, and old leases will be transformed (or will be consid-
ered as having been transformed) into LMUs within two years. A mining
plan must be submitted and approved. Within 30 days from the anniversary
of the establishment of the LMU in even-numbered years (i.e., every two
years) the operator must report to the Mining Supervisor his work and
expenditures for the period just past and advise him of his plans for
development in the two years to come, to meet to the Mining Supervisor's
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satisfaction the requirements of diligent development (if the mine is
not in production) or continuous operation (if it is). The Mining Super-
visor is responsible for determining whether the lessee is in compliance
with the diligent development and continuous operation conditions of the
lease, and, presumably, if he is not, action can be taken to recover on
his bond or even to terminate the lease on the ground of failure to per-
form duties required under it. At the moment a lease may be cancelled
only by suit in federal court, but it may be that administrative measures
can be devised subject to appeal to federal court. Certainly this is
possible by stipulation in new leases.
The intent, and certainly the effect if actually enforced,
will be to require all holders of federal coal leases to file an approv-
able plan for immediate beginning of development of coal lands, to get
the plan approved, to do what the plan calls for (under the supervision
of the Mining Supervisor) to get the mine ready for production, and then
to keep the mine in production in commercial quantities at least six
months of the year, all under penalty of losing the lease. If the new
rules go into effect and are enforced, the new system has the potential
for eliminating the problem of leased tracts being unused and will ensure
that leases granted for the development of public mineral holdings will
actually ensure such development. It is a very ingenious system in the
way it brings existing leases under the new system by requiring their
conversion into LMUs.
30 USC §208 permits the Secretary of the Interior, in his dis-
cretion, to accept in lieu of the continuous operation provision of the
lease, an advance royalty on a minimum number of tons of coal. The regu-
lation issued under authority of this provision allows for a payment of
such royalties, less rental in lieu of actual production. Section 2(d)
of the standard-form coal lease provides that this minimum royalty be
equivalent to a royalty of $1 an acre. Since the rental after the fifth
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year is also $1 an acre, and since rentals are credited against royal-
ties, this section of the lease in effect gives the Secretary the author-
ity to forget entirely about the continuous operation provision of the
lease. That is what has been done in the past. But it is inconsistent
with the policy of the proposed rules to permit this in the future. It
will be interesting to see whether the Secretary permits this statutory
loophole to be used on an ad hoc basis by holders of coal leases to
avoid the requirements of the new system.
All federal coal leases are subject to maximum acreage require-
ments. No one may hold permits or leases in excess of 46,080 acres in
any one state except as described below. Partial interests, direct and
indirect holdings, percentage of holdings of corporations holding leases,
and the like are all calculated and prorated so that no one holds more
than the maximum, except that ownership of less than 10 percent of the
stock in a corporation is not chargeable, so that in theory it is pos-
sible to hold 9 percent interest in 20 corporations, each holding the
maximum of 46,080 acres, and avoid the limitation.
As noted above, acreage held in separate states and acreage
held on public domain lands as opposed to acquired lands are computed
separately and are not charged one against the other. Applications for
leases or permits in excess of the maximum will be denied, and if it is
discovered that anyone holds acreage in excess of the limit, the leases
or permits on the excess land will be cancelled or forfeited.
Cooperative mining, involving pooling of separate leases by
separate leaseholders, is permitted with the approval of the Secretary
of the Interior subject to restrictions against apportionment of produc-
tion or royalty to ensure that the cooperative agreements really are co-
operative enterprises for the more economical and efficient utilization
of the coal resources. They may be exempted from the acreage require-
ments by the Secretary of the Interior.
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Furthermore, a lessee who wishes to secure leases or permits
in addition to the prescribed limit of 46,080 acres in a given state may
be allowed additional acreage. He must make a showing that the addi-
tional acreage is necessary to "carry on business economically" and that
it would be in the public interest to grant him more acreage. His appli-
cation must disclose any interest the applicant (who may be a corporation)
has in other federal or nonfederal coal leases and permits within the
state, and the estimated coal reserves he has within the state. Addi-
tional permits or leases, if granted, will be in multiples of 40 acres,
but not more than an additional 5120 acres. The filing of an application
for additional lands will cause those lands to be withdrawn from disposi-
tion under the Mineral Leasing laws until a ruling on the application is
made. Public hearings are required before the additional lands may be
let. The new lease may require a cash bonus higher than that required
for the original lease, and/or higher rent and/or royalty, and any addi-
tional terms the Secretary may wish to impose.
Moreover, a holder of a lease may apply for a modification of
his existing lease to include contiguous coal lands or deposits if the
appropriate federal official considers such an extension to be in the
interest of both parties to the existing lease. If it is simply a mat-
ter of tacking on some odd extra land, that is one thing, but if it ap-
pears that the lands sought to be included in the modification are ca-
pable of independent operation, and that there is a competitive interest
in them, those lands are supposed to be offered on a competitive basis.
If a showing is made by a lessee that within three years the
deposits of coal in a given 40-acre tract covered by a lease will be
"exhausted, worked out, or removed," an additional tract may be leased.
An application must include a proposed plan of operation, method of entry,
and an estimate of recoverable reserves. Upon a determination that the
proposed additional lands constitute an acceptable leasing unit, they
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will be offered on a competitive basis and if the applicant is the suc-
cessful bidder and the new lands can practicably be operated with the
lessee's existing leasehold as a single mining operation, the lease may
be modified to include them.
Bonds. Under the coal leasing program in force before the
moratorium, various bonds were required of holders of federal mining
leases. First, there was a "compliance bond" to ensure compliance with
the terms of the lease, which for coal was set at $1000 minimum per
lease, or $25,000 for coverage of all leases held on a statewide basis,
or $75,000 for nationwide coverage. In addition, other bonds could be
required in the terms of the lease, including bonds for surface protec-
tion in strip mining operations, special bonds for work done on Forest
Service lands, bonds to protect the surface interest of a holder of the
surface estate under a stock raising homestead patent, and so on. It
seems likely that the bonding requirements will be substantially in-
creased, especially with reference to environmental protection, and that
the bond will be a substantial factor in access to federal coal lands.
Rents and Royalties. The statutory minimum for rental of coal
land is as follows:
For the first year, not less than $0.25 an acre
For the second year through fifth years,
not less than 0.50 an acre
For each succeeding year, not less than 1.00 an acre
Although it has apparently been the practice in the past for the BLM to
set rents at the statutory minimum in setting forth the terms of the
leases it offers, this need not be the case, and indeed there have been
efforts in recent years to set the rates at a higher level. This can be
expected to continue, and is especially important when you remember that
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these terms, once set, are not adjustable for 20 years under present
law.
A rental once due becomes a debt to the United States, and the
United States can sue for its recovery. Rentals are credited against
royalties, which more or less eliminates the problem for producing mines
when the rents are set at the statutory minimum.
The statutory minimum for royalties on federal coal leases is
5? a ton. Recent practice has apparently been to set the royalties at
a considerably higher rate, as follows:
Underground mining: 15? a ton for the first 10 years
17-1/2? a ton for the next 10 years
Surface mining: 17-1/2? a ton for the first 10 years
20? a ton for the next 10 years
In addition, government offerings have been made incorporating a royalty
calculated as a percentage of the value of the mine run, again differen-
tiated according to method (strip or auger versus deep mining). There
is nothing in the regulations to prevent this, and it seems to be a bet-
ter deal from the standpoint of the United States as lessor, especially
in view of the statutory 20-year period that must elapse before lease
terms can be adjusted and of the increasing price of coal. Since the
terms of a lease are determined by the BLM as offering agency, subject
only to the statutory minimum, there is nothing to stop the government
from devising other methods of computing royalties such as the sliding-
scale royalties now applicable to oil shale. Royalties could be set at
a rate inversely proportional to the sulfur content of coal as a way of
encouraging extraction of low-sulfur coal. There are all sorts of things
that might be done. The statute only specifies a minimum royalty of 5?
a ton. and the regulations state specifically that royalties are to be
determined on an individual basis before a lease is issued. The regu-
lations also require that the leases be conditioned on the payment of
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the royalty, whatever it is, on a minimum annual production beginning
with the sixth year of the lease. The royalty thus fixed may be paid,
or could be paid under the system in effect before the new LMU rules
come into effect in lieu of the continuous production required statu-
torily under the lease. But since rentals were required anyway and
could be credited against royalties, the net amount paid over the rental
on nonproducing leases under the old system often turned out to be very
little if at all. Thus, a lessor, for payment of a small amount, could
hold onto a nonproducing lease for speculative or other purposes. The
new rules should more effectively guarantee genuine continuous operation.
On application by a leaseholder, the Secretary of the Interior
may determine that the subject mine cannot be economically operated be-
cause of the royalty terms, or he may find that further promotion of
coal recovery is desirable. In either case he is empowered under the
regulations to waive, suspend, or reduce all or part of the royalties.
If the government finds a lessee cheating on the mine run and reporting
for royalty purposes less than was actually mined, the lessee is liable
to a penalty of twice the royalty on the part withheld.
Assignments and Overriding Royalties. A federal mining lease,
or any part of the rights held thereunder, may be assigned or subleased
with the prior approval of the Secretary of the Interior, provided the
assignee, sublessee, or whoever the succeeding party in interest is meets
the requirements of being capable of running the mining operation, being
in conformity with the citizenship and acreage requirements, and so on.
The arrangement between the assignor and the assignee is a matter of
private law between them, as are the arrangement between joint holders
of federal mining leases, and the mineral leasing laws do not provide a
federal common law to regulate the relations between parties. The su-
preme Court has held to this effect in Wallis v. Pan American Petroleum
Corp., 384 US 63 (1966). There is a requirement, however, that an
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assignment of a coal lease not create an overriding royalty to be paid
by the sublessee to the sublessor in excess of 50 percent over the roy-
alty to be paid to the United States under the primary lease, unless it
can be shown that the sublessor has made significant improvements, which
justify a higher rate.
Easements. It may be that the land contained within a federal
leasehold does not communicate directly with roads or railroads. If the
intervening land is also held by the government, it is the policy of the
BLM to grant on application an easement over the intervening public
lands, for the purpose of building a road or a rail spur or a tramway,
etc., subject to stipulations on where the road (or whatever) is to be
built, with appropriate environmental restrictions. If the intervening
land is is in private hands, it is the government's policy to acquire
the easement at government expense and include it in the lease, the
thought being that this adds to the value of the leasehold and that this
added value will be reflected in the bonus bids. As we have seen, re-
liance on bonus bids to assure that the government receives maximum or
fair economic benefit is not, nor has it been, an effective device. In
certain cases an easement will be condemned by the government. In the
oil shale leases more recently offered, for example, easements were con-
demned to make the prototype lease sale easier. This is not ordinary
policy, however, but it can be done.
Nondiscrimination in Employment. Federal mining leases are
subject to a requirement of nondiscrimination in employment on grounds
of race, creed, color, or national origin, as well as various other
provisions for the protection of mineworkers (workers must be paid twice
a month, there are restrictions on hours worked, etc.).
Adjustment of Terms. The right reserved in the lease (and in
the statute) to adjust "reasonably" the terms of the lease after 20 years
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poses some difficult problems. In the past the practice has been to ad-
just the terms of the lease to conform to the leases being issued at the
time of the adjustment. But as appear likely, the terms of new leases
contain rent and royalty provisions considerably above those of the past,
and the reclamation and environment restrictions in new leases differ
dramatically from those of 20 years ago, there may be some conflict as
the meaning of the term "reasonable." Before the expiration of the 20-
year term, the BLM may set forth new terms, and the lessee is deemed to
have agreed unless he files objections. If he files objections, there
may be no compromise possible.
One suggested remedy is for the government to sue for cancel-
lation, and for the lessee to defend on the ground of illegality of the
3fc
new terms. This seems cumbersome at best, and has not been done in the
past; it seems likely that in most cases administrative appeals channels
will provide an acceptable compromise. Since the Secretary is entitled
by the lease to adjust the terms subject only to a requirement of "rea-
sonableness," and since courts are very unwilling to find abuses of dis-
cretion or unreasonable conduct on the part of responsible officers of
government, a lessee would be well advised in most cases to accept the
best deal he can get, and if he cannot live with it, to take advantage
of the other terms of the law that permit the Secretary to waive royal-
ties or give other indulgences if it appears that the mine cannot be run
economically otherwise. As a last resort a lessee can apply for suspen-
sion of operations or surrender his lease. It seems unlikely that the
department would impose ruinous terms on a lessee in any other than the
environmental area. However, should a federal lessee feel that "ruinous
*Parr, J. F., "Terms and Conditions of Federal Mining Leases," Rocky
Mountain Mineral Law Foundation Institute on Federal Mineral Leasing
(non-oil and gas) , (1971).
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terms" had been imposed in the environmental area, he would be unlikely
to find relief in the courts because they would be inclined to find the
Secretary's action "reasonable."
4. Federal Requirements in Pricing
There exists a provision in 30 USC §187 stating:
"Each lease shall contain. . .such. . .provisions as
[the Secretary of the Interior] may deem necessary to
insure the sale of the production of such leased
lands to the United States and to the public at rea-
sonable prices, for the protection of the interests
of the United States, for the prevention of monopoly,
and for the safeguarding of the public welfare."
So let the developers beware: there is a provision that can be used to
regulate coal prices. If it is the lease it can be used, and if it is
not the lease the validity of the lease is open to question.
C. Indian Lands
The rules governing mineral leasing on Indian lands are essentially
the same in outline as those governing mineral leasing on public lands,
but differ in several important particulars. Distinction must be made
among lands that are tribal lands, owned by the tribe as a corporate or
quasi-corporate unit, lands that are allotted to individual Indians, and
lands that, although held by Indians, are not subject to restrictions on
alienation by the Bureau of Indian Affairs (BIA).
Tribal lands may be leased by the tribal council or other author-
ized representative of the Indian's tribe, with the approval of the
Secretary of the Interior. Indian leases may, with the permission of
the Secretary of the Interior, be negotiated separately and privately
on an individual basis. This method is coming into increasing favor
since it permits lease provisions requiring, e.g., employment of Indians
in the construction of mining improvements, building of a health care
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center for Indians in the area (provisions such as this have been in-
cluded in negotiated leases in the Southwest), and so on. Concern that
the BIA is lax in representing the interests of the Indians in negoti-
ating leases is eased where the lease is negotiated by an informed and
hard bargaining representative of the tribal council. In such a case
the possibilities are good for the Indians to get something substantial
in return for access to the mineral deposits under their tribal land.
The potential developer should be aware that much may be required from
him, including some form of economic partnership in the production of
the mine and his doing things for the benefit of the Indians, which have
no counterpart in other mineral leases. It depends, of course, on what
the negotiators for the developers and the negotiators for the Indians
decide between them.
When the negotiated lease method is not used, the terms of the
lease will be somewhat parallel to those of a regular mining lease. The
lease tract must be advertised for sale and bids taken for bonuses in
addition to the usual rents and royalties. There is a requirement, for
a 25 percent deposit in advance, to be forfeited if the lease is dis-
approved by the Secretary of the Interior (whose agreement is required
to all Indian leases) through no fault of the lessor. The lands are
held in trust for the Indians by the United States, and the United States
acts as lessor of the lands, as trustee. The Secretary may reject the
highest bid, if he believes it is in the interest of the Indians to do
so. The BIA takes the role occupied in public land leases by the Bureau
of Land Management.
Bonds may be required in varying amounts, but these may be reduced
with the consent of the Indians if circumstances appear to warrant it
and the rights of the Indians will be protected. The schedule is as
follows:
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Acreage Bond
Less than 80 acres $1000
80 to 120 acres 1500
1200 to 160 acres 2000
For each additional 40 acres 500
A "statewide bond" of $15,000 may be offered, even though lands within
the offering may be Indian reservation lands which in fact extend beyond
state boundaries. Nevertheless, the bonded land may not exceed 10,240
acres. The bond may be increased when the BIA officer in charge feels
it necessary.
The lands must be in a reasonably compact form, and no lease may be
offered for a tract extending more than one mile along the outcrop. No
operator may hold more than 2560 acres, but a combination of leases, or
a lease in excess of the maximum, may be allowed if the Commissioner of
Indian Affairs finds it in the interest of the Indians and necessary to
permit the establishment of thermal electric power plants or other indus-
trial facilities on or near the reservation. He may insert into the
lease a requirement of relinquishment if the facilities are not con-
structed, and may require advance rental and/or minimum royalty as a
condition of the lease.
Indian leases run for 10 years, "and as much longer as the sub-
stances specified in the lease are produced in paying qualities." In
time of war or national emergency, the U.S. government reserves the
right to buy all or part of the output of the leased land at the market
price. (There are similar provisions in public land leases.)
Unless otherwise authorized, rents are not less than $1 per acre,
royalties not less than 10? a ton of coal of the mine run, including
slack, and there is a required yearly development expenditure of not
less than $10 an acre. In the event of discovery of minerals in paying
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quantities, all advance payments may be credited against stipulated roy-
alties for the year for which such advance payments have been made.
On Indian leases, the rent is due for the period of the lease even
if the lease has been surrendered or cancelled. Suspension of the rent
is permitted with the consent of the tribe and the Secretary of the In-
terior "whenever during the primary term of the lease [lO years] it is
considered that marketing facilities are inadequate or economic condi-
tions unsatisfactory."
Written permission is required from the U.S. Geological Survey
(USGS) to begin operations on an Indian lease. Failure to comply with
the terms of an Indian lease or the regulations or orders of the BIA
Superintendent or the USGS Mining Supervisor subjects the lease to can-
cellation by the Secretary and the lessee to a penalty of up to $500 for
each day the lessee is in violation. The lessee gets notice and a hear-
ing by the Mining Supervisor, with a right of appeal to the Secretary,
but proceedings in federal court are not required as they are in an
ordinary federal mining lease.
Assignments are subjected to the requirement that the lessee's en-
tire interest be assigned, and not just a partial interest. In ordinary
federal leases partial assignments are permitted.
Leases may be surrendered, subject to proceedings against the bond,
and cancelled by the Secretary of the Interior if the lessee is in vio-
lation of the terms, or cancelled on application of the lessee if a
satisfactory showing is made of provision for the protection and con-
servation of the land. Prospecting permits are allowed, subject to the
same requirement that no minerals may be removed except that quantity
necessary for experimental or other such work, but a prospecting permit
does not entitle a successful prospector to a preference right lease.
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The regulations in 25 CFR Part 171, governing the leasing of tribal
lands for mining, may be superseded by tribal constitution, charter, or
law issued pursuant to the Indian Reorganization Act of 1934 (25 USC
§461-79) , or an ordinance issued thereunder. Insofar as not superseded,
these regulations apply to all leases not privately negotiated, the val-
idity of which requires the approval of the Secretary of the Interior.
Allotted lands, i.e., those that have been allotted to individual
Indians in severalty (alone) are let on much the same rules, with certain
exceptions. Permission to negotiate privately is for 30 days only, sub-
ject to reasonable extension separately applied for, but privately nego-
tiated leases are still subject to rejection by the Secretary and to
being offered for competitive bids. There are slightly different rules
for disclosure by corporations who seek leases. Allotted lands are held
by individual Indians, and although they are still subject to restrictions
on alienation and the BIA is still involved to some extent in the title
to the lands, they may be passed on by inheritance, which causes some
problems if all the heirs cannot be found. The regulations provide for
procedures by which leases of allotted lands can still be auctioned even
if all the heirs cannot be located. This makes acquisition easier than
if the lands were in private hands, or were in the hands of Indians but
not subject to BIA supervision, in which case the usual complicated prob-
lem of providing clear title to lands to which all the heirs cannot be
found would apply. The rule requiring that assignments of leaseholds
be of the entire interest of the assignor does not apply to allotted
lands. Other than that, the rules are for all practical purposes the
same.
It should be noted that the allotments mentioned here are allotments
by the United States to individual Indians. Such lands are not tribal
lands. Tribal lands may also be allotted by the tribal council to
Indians within the tribal system. Such lands are not allotted lands
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for the purpose of the law, but these tribal allotments may be leased by
the Indians to whom the mineral rights have been so assigned, subject to
the terms of the tribal constitution and the approval of the Secretary.
Preference is to be given to Indian cooperative associations and indi-
vidual Indians in making such leases.
When lands are removed from the control of the BIA and restrictions
against alienation have been removed, the lands are treated as private
lands and neither the Secretary of the Interior nor the BIA is involved
at all.
D. Access to Oil Shale on Public Lands
Of the worthwhile oil shale land in the West, 10 percent is in pri-
vate hands, either because the land is just plain private land or because
it was transferred by mining patents or under old homestead laws, which
did not reserve mineral rights to the United States, Another 5 percent
may or may not have been transferred under patents granted under the
grandfather clause in the Mineral Leasing Act covering claims made under
the old mining laws before the Mineral Leasing Law came into force.
There is, and has been for many years, an incredibly complex debate on
the subject of these old claims, some of which do not seem to have been
made in compliance with the law in force at the time. The actual result
of the dispute is not of major importance, however, since only a small
portion of the oil shale land is involved. If the lands return to gov-
ernment hands, they will not be made available for leasing in any event
for a long time, as will be seen below. If they are in private hands,
either the development will be done by the owners of the patents or the
lands, or the use of them, or some interest in them will be assigned by
the patentholder on a private law basis.
The remaining lands are public domain lands or Indian lands. These
contain the best and richest of the deposits. After the Mineral Leasing
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Act went into effect in 1920, there were a few leases given out in the
early 1920s, but these have lapsed. In 1930, oil shale reserves on pub-
lic lands were withdrawn from leasing by Executive Order No. 5327.
The section of the Mineral Leasing Act of 1920, which deals speci-
fically with oil shale is codified as 30 USC §241. There are no regula-
tions issued under authority of this section, and the regulations that
do exist under the general authority of the Mineral Leasing Act or other
associated statutes scarcely ever mention oil shale. There were regula-
tions initially governing oil shale leasing, and a few leases, since
lapsed, were issued in the 1920s. But when some hopeful developers at-
tempted to have some of the land made available for lease in the mid-
1960s, the government revoked the regulations. There was another at-
tempt in 1968, as Secretary Udall was leaving office. The Secretary,
under conflicting pressures, agreed to accept bids for oil shale leases
around Christmas of 1968. However, all of these bids were rejected.
The next attempt was made in 1973, and this was successful. Six
tracts were offered, two each in Colorado, Utah, and Wyoming. No one
bid on the Wyoming oil shale. The leases in Colorado and Utah went for
enormous bonuses. Since there were no regulations covering the oil shale
leases, and since the offering of these leases was in the nature of a
prototype, the terms of these leases were also the nature of a prototype.
The terms were published in the Federal Register of November 30, 1973,
along with the order modifying the Executive Order, which had withdrawn
the oil shale lands from the public domain. Because this was a proto-
type program, no further oil shale leases can be expected for quite a
few years. The prototype time table is as follows:
• Two years for gathering baseline data and
another year for producing a mining plan,
as required by the lease end of 1976
• Two years for study end of 1978
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• Two to three years after study is approved
for building of plant end of 1981
• Two more years for production and
evaluation of results end of 1983,
It is in the nature of a prototype program to see how it turns out be-
fore going ahead. This means that it will be 1983 before more oil shale
leases will be offered on public lands. This prediction may, of course,
be altered by a number of factors. There may be litigation of some
sort, which will permit earlier awarding of other leases (although it
is doubtful that anyone could sue to be awarded a lease to develop pub-
lic lands under withdrawal.* There is the possibility that the results
of development on private or state lands may accelerate the date on
which a sensible decision can be made on the practicality and usefulness
of more oil shale leasing on public lands. There also is the possibility
that the need or alternative domestic sources of energy may prompt this
Administration or another to award more leases without waiting for the
results of the prototype program. Even so, with all the environmental
requirements, it will be some time before anything can be accomplished
on public lands.
Since it is a prototype program, it is questionable how much gen-
eral application the terms of the four leases actually offered will have.
They take up 12 pages of small print in the Federal Register, but they
apply only to the parties involved. They are not regulations.
*See Boesche v. Udall, 373 U.S. 472 [l963], which holds very strongly
for the discretion of the Secretary, and effectively removed the word
"temporary" in withdrawals as a basis for forcing leases to be issued.
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E. Summary of Federal Oil Shale Leases
Although by no means exhaustive, the following summary includes
many of the principal terms of the government oil shale leases awarded
in 1973. It is essential to remember that these leases were prototype
leases and were made on an ad hoc basis. There is no assurance whatever
that future federal oil shale leases, if any, will follow these terms.
1. Acreage
The acreage is determined by the offering. There were six
leases offered, and each one was specific as to the lands included within
it. The rules were only one lease to a customer. Since there are no
other federal oil shale leases being offered, the question of acreage
restrictions has not yet come up.
2. Duration
The leases were for terms of 20 years and for so long there-
after as production is had in paying quantities. This is to be distin-
guished from the intermediate coal lease, in that if the mine is not in
production on the 20th anniversary the lease will lapse by its own terms.
There is a provision for readjustment after 20 years; this is done by
the government proposing changes to which the lessee is deemed to agree
if he does not object within a stated time. If he does object, a com-
promise is to be worked out, and if that is not possible (there are
elaborate appeal procedures) the lease can be terminated by either party
at that time. There are provisions for suspension and earlier surrender,
but cancellation still requires action in federal court.
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3. Bonuses
The applicants bid by means of offering bonuses and the leases
in fact went for millions of dollars. The bonuses were to be paid in a
first installment with the balance to be paid in four equal annual in-
stallments. There is provision, however, for crediting improvement
costs against the bonuses. Expenses attributable to operations on the
leased property in the first three years may be credited against the
fourth installment, and credit for expenses so attributable in the first
four years not claimed against the fourth installment may be claimed
against the fifth and final installment. After that, credits are al-
lowed against minimum royalties, as set forth below.
4. Rents and Royalties
Rent is set at a flat 50? an acre and can be credited against
royalties for the lease year (the year from one anniversary of the ef-
fective date of the lease to another).
The royalty scheme for oil shale leases is very complex. It
begins with a division between oil shale obtained by mining methods as
opposed to that obtained by in situ methods. For mined oil shale, the
basic royalty is 12? a ton, varying up or down by 1? a ton as the amount
of oil recoverable from a ton of oil shale varies up or down from a
base of 30 gallons a ton. Thus, at 30 gal/ton, the basic royalty is
12? a ton; at 29 gal/ton, it is 11?; at 31 gal/ton, it is 13?, etc. In
no case, however, is it allowed to go below 4? a ton. For oil shale
processed by in situ methods, the royalty is 12? a ton, and there is a
very complicated formula for arriving at the proper amount.
The basic royalty is adjusted as a function of the combined
average value per barrel of all crude oil and crude shale oil produced
in Colorado, Utah, and Wyoming (the three states in which leases were
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offered). As the combined average value of all this oil goes up or down
a percentage point over the year before, the royalties are adjusted by
the same percentage. In this way the royalties are tied to oil on other
leaseholds, oil in private production, etc., in these three states. In
no case may the royalty go below 4$ a ton.
Credits are allowed against royalties in the sixth through
tenth lease years for expenditures attributable to operations on the
lease site not claimed against bonus installments. However, if the fa-
cility is in actual production, there is no credit allowed against the
first $10,000 annual minimum royalty.
The minimum royalty payable on each tract is set separately
and individually in the lease offering. There is one figure for the
sixth through fifteenth lease years and another for the years thereafter.
This can be excused in whole or in part and for as long as the Secretary
decides is necessary if the expenditures necessary to meet the reclama-
tion and other requirements of the regulations exceed those in the con-
templation of the parties at the time the lease was signed. There are
various discretionary provisions allowing the Secretary to make things
easier if necessary. This minimum royalty is, by its nature, payable
whether there is production or not, but, as an incentive to get into
production early, if there is production prior to the eighth anniversary
of the lease, and the royalty payable exceeds the minimum royalty payable
in any event as stipulated in the lease, the lessee is excused from pay-
ment of one half the royalty in excess of the minimum.
5. Bonds
To begin with, there is a compliance bond of $20,000. Then
there is a reclamation bond, set for the first three years at $2000 an
acre for spent shale disposal sites and $500 an acre for other areas,
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and renewable at three-year intervals at a figure to be determined by the
lessor as necessary for reclamation and restoration of the site. This
may be increased even during the three-year period if there is a change
in the development plan, which, in the opinion of the lessor (speaking
through the USGS Mining Supervisor) , increases the risk and amount of
environmental damage. The bond may be released as to land reclaimed and
restored to the satisfaction of the government. There is a third bond
required in an amount not less than $20,000 conditioned on faithful com-
pliance with 30 CFR Part 231 (Mine Operation Regulations) and 43 CFR
Part 23 (Reclamation), the environmental stipulations in the lease, and
observation of all federal environmental standards, the development plan,
and anything else which might affect the environment. This may be modi-
fied as is thought necessary.
A development plan must be filed, setting forth the plan for explo-
ration, development, production, processing and reclamation, a detailed
statement of how the lessee intends to comply with the operating and
reclamation regulations mentioned earlier, and a requirement that the
lessee use "due diligence" to attain, as early as he can in light of the
environmental restrictions placed on him, production in an amount equal
to the rate on which the minimum royalty stipulated in his lease is com-
puted. The USGS Mining Supervisor looks into the plan, holds hearings
on it, and finally, after whatever changes are necessary have been made,
approves it. It becomes the basic document; any change in the lessee's
plan of operations requires a corresponding change in the approved devel-
opment plan, etc. There is a requirement of annual reporting of oper-
ations .
6. Other Requirements
Other provisions of the oil shale lease require fair employment
practices (e.g., hours worked) nondiscrimination and nonsegregation, and
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one which reserves to the United States the right to promulgate and en-
force orders and authorities pursuant to 30 USC §§187 and 189 to ensure
sale of mine output at reasonable prices, to prevent monopoly, and "to
safeguard the public welfare."
Assignment is permitted at the option of the lessee, subject
to disapproval by the lessor only if the assignee is unqualified to hold
a lease or unable to post an adequate bond, or where the assigned or re-
tained portion would, in the opinion of the lessor, be too small to per-
mit economic development. Overriding royalties, except where improve-
ments warrant more, are limited to 25 percent over the royalty fixed in
the primary lease.
There are provisions covering surrender and relinquishment,
disposition of property on termination, protection of proprietary infor-
mation, and so on. It is a very comprehensive document, not at all like
the four-page standard coal lease. It must be remembered that these are
prototype leases; future leases, if any, may be quite different.
Following the lease itself, there is a set of "Environmental
Stipulations." These consist of about 15 or 16 columns of Federal
Register type; the Table of Contents is reproduced as Table 7-1 to give
an idea of the scope of the stipulations. The technique of environmental
stipulations included by reference in the lease and thus binding the les-
see directly as a matter of private law is a very novel and effective
one, which may be considered as a coming idea.
Land in state ownership is sold or leased according to the pro-
visions in the appropriate state code governing disposition of state
land. Most of the land that comprises the oil shale and coal-rich west-
ern states was originally owned by the United States. When these states
entered the Union, certain of the public lands in the states were given
by the United States to the state governments. The most important
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Table 7-1
ENVIRONMENTAL STIPULATIONS TO PROTOTYPE
FEDERAL OIL SHALE LEASES
Sec.
Sec.
General
(A) Applicability of Stipulations
(B) Changes in Conditions
(C) Collection of Environmental Data
and Monitoring Program
(D) Emergency Decisions
(E) Environmental Briefing
(F) Construction Standards
(G) Housing and Welfare of Employees
(H) Posting of Stipulations and Plans
Access and Service Plans
(A) Transportation Corridor Plans
(B) Regulation of Public Access
(C) Existing and Planned Roads and
Trails
(D) Waterbars and Breaks
(E) Pipeline Construction Standards
(F) Pipeline Safety Standards
(G) Shut-off Valves
(H) Pipeline Corrosion
(I) Electric Transmission Facilities
(J) Natural Barriers
(K) Specifications for Fences and
Cattleguards
(L) Crossings
(M) Alternate Routes
(N) Off-Road Vehicle Use
Fire Prevention and Control
(A) Instructions of the Mining
Supervisor
(B) Liability of Lessee
Fish and Wildlife
(A) Management Plan
(B) Mitigation of Damage
(C) Big Game
(D) Posting of Notices
Health and Safety
(A) In General
(B) Compliance with Federal Health
and Safety Laws and Regulations
(C) Use of Explosives
Historic and Scientific Values
(A) Cultural Investigations
(B) Objects of Historic or
Scientific Interest
7 Oil and Hazardous Materials
(A) Spill Contingency Plans
(B) Responsibility
(C) Reporting of Spills and Discharges
(D) Storage and Handling
(E) Pesticides and Herbicides
8 Pollution—Air
(A) Air Quality
(B) Dust
(C) Burning
9 Pollution—Water
(A) Water Quality
(B) Disturbance of Existing Waters.
CO Control of Waste Waters
(D) Cuts and Fills
(E) Crossings
(F) Road Surfacing Material
10 Pollution—Noise
11 Rehabilitation
(A) In General
(B) Management Plan
(C) Stabilization of Disturbed Areas
(D) Surface Disturbance on Site
(E) Areas of Unstable Soils
(F) Materials
(G) Slopes of Cut and Fill Areas
(H) Impoundments
(I) Flood Plains
(J) Land Reclamation
(K) Overburden
(L) Revegetation
12 Scenic Values
(A) Scenic Considerations in General
(B) Consideration of Aesthetic Values
(C) Protection of Landscape
(D) Signs
13 Vegetation
(1) In General
(2) Timber
(3) Clearing and Stripping
14 Waste Disposal
(A) Mine Waste
(B) Other Disposal Areas
(C) Disposal of Solid and Liquid Wastes
(D) Impoundment of Water
(E) Slurry Waste Disposal
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portions of these grants are the so-called school sections. Land was
divided into rectangular divisions by the public land surveys, and such
a division six miles by six miles (36 sq mi) is called a township. Each
of these townships is subdivided into 36 sections of one square mile
(640 acres), and numbered consecutively. Of the sections in each town-
ship, it was the practice in these areas to allocate to the new states
sections 16 and 36, or two square miles in each 36, to provide revenue
for the support of the state school system. These are the school sec-
tions; they comprise a major portion of the state lands in these states.
(No such system, of course, existed in coal-rich West Virginia, which
is not a public land state, but which was formed from Virginia during
the Civil War.) The administration of these and other public lands in
the states are under the jurisdiction of State Boards and Land Commis-
sioners (there are various local practices), who have the authority under
certain restrictions to lease state lands for mineral purposes.
F. State Lands
1. Colorado
The disposition and control of state lands in Colorado is vested
by the state constitution in the State Board of Land Commissioners, who
have the right to sell, lease, or otherwise dispose of state lands,
whether derived from the school sections or not. It has been the policy
in Colorado since 1911 not to sell mineral rights to state lands, but to
make them available only through lease.
Coal. The rules for leasing state coal lands are as follows.
Prospecting is permitted only with the approval of the Board. Leases
are issued by the Board on application, and the Board may, of course,
reject any application. The regulations specify that leases are to be
issued only "in the name of one party" unless there is a specific
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provision of joint tenancy with right of survivorship. While on the
face of it, this might raise a question as to the eligibility of asso-
ciations and corporations, the statutes make regular reference to such
organizations.
Leases are let in 40-acre units. The amount of acreage to be
included in a single lease is subject to limitation by the Board, but
there is no limitation on the number of leases that any one party can
hold. If the surface is already leased (for grazing purposes, for ex-
ample) , the Board can, and often does, cancel that surface lease.
Leases usually run for ten years, subject to renewal; renewal
is at the option of the Bo-ard and is not a right. If, however, a mine
is in continuous production (by which is meant production not interrupted
for more than six months at a time without an extension granted by the
Board) , the lease is continued in force as long as there is continuous
production. Thus, in contrast to the federal system, if a mine is ac-
tually producing, the lease will continue in force but if not it will
lapse.
Rentals are set at $1 an acre, yearly, and unlike the federal
system, rentals are not credited against royalties.
There is a statutory minimum royalty of 15£ a ton, a ton being
defined as 27 cubic feet of coal. Royalties by statute may be adjusted
after five years if the royalty is on a fixed (i.e., not a percentage)
basis. In practice, however, royalties are now set at 15? an acre or
5 percent of the value of the mine run, whichever is greater, so the
opportunity for adjustment after five years is not used. The opportunity
comes at the expiration of the lease. There is provision for the setting
of minimum royalties due, but if in the year following one exceeds one's
minimum, one's payment of royalty for this year over that due on actual
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production may be credited against one's excess royalty payment for the
next year.
There is an interesting wrinkle in the statute, interesting
for the purposes of the synthetic fuels study. The 15£ a ton statutory
minimum has a statutory exception. If the coal is to be used for the
production of chemicals, or synthetic fuels, or power at the plant of
operation, and not less than 250,000 tons a year are mined, the Board is
permitted to set the royalties at 5£ a ton instead of 15?. (If fewer
than 250,000 tons a year are mined, the reduced statutory minimum does
not apply.) In practice, this provision is not used.
The Land Commissioners require a $2000 bond for the protection
of the personal property of the surface owner (cow killed by a truck,
etc.). The major bond, and it can be quite substantial, for the protec-
tion of the land itself is required by the Department of Natural Re-
sources' Division of Mines.
Assignments are permitted with the approval of the Board, which
will then issue an assignment lease to the assignee.
Surrender is permitted in whole or in part.
Oil Shale. There is no oil shale to speak of in Colorado state
lands. There is apparently a little in Moffatt County, but it is of such
low grade that it is not worth considering commercially. The Piceanse
Valley, one of the world's major oil shale deposits, is in Rio Blanco
and Garfield counties, and there is oil shale in Mesa, Delta, Montrose,
and Gunnison counties as well, but unfortunately for the state of Colo-
rado at the time of statehood this land was part of the Ute Indian Res-
ervation and so no school sections were granted the states in this area,
but other, so-called "indemnity" lands in other parts of the state were
granted instead. The result is that "The State of Colorado doesn't own
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an inch of oil shale." As a consequence, there is no state oil shale
leasing policy or program whatever.
Since the public lands in Colorado are vested in the Board of
Land Commissioners by provision of the state constitution and since in
theory they can sell whatever they like, there is a provision in the law
to get around this. If it appears that certain state lands that have
"unique economic or environmental value for the public" are, because of
their control by the Board of Land Commissioners (which is now an agency
of the State Department of Natural Resources), subject to sale, the
Director of the Department of Natural Resources may acquire these lands
from the Board by condemnation via an intricate interagency transaction.
2. Montana
Coal leasing in Montana has been under a moratorium since 1971,
according to the Mineral Leasing Bureau of the Department of State Lands.
The Montana legislature is presently considering new legislation on coal
leasing, and until that process is completed there will be no new regu-
lations issued.
The old statute (the one presently in force but not being used)
provides that the State Board of Land Commissioners be in charge of the
leasing of Montana state lands or mineral estates however acquired, that
leases have a maximum length of 20 years, and that royalties be individu-
ally set by mine depending on local conditions but in no event to be less
than 12-1/2C a ton.
*Tom Bret^: Colorado State Board of Land Commissioners.
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3. Wyoming
Lands in the possession of the state of Wyoming may be leased
for mining purposes by the State Board of Land Commissioners. There are
some lands to which title is held not by the State Board of Land Commis-
sioners but by the Wyoming Farm Loan Board. These lands came into state
possession during the Great Depression as a result of foreclosures. Some
were resold, but in compliance with the state law, mineral rights were
reserved. Depending on ownership, the land (or mineral estate) is leased
by the Land Commissioners or the Farm Loan Board, and the regulations
make reference to both Boards, but in practice leasing is administered
in both cases by the Land Commissioners and action by the Wyoming Farm
Board is pro forma.
State law provides that any patent of state lands be with a
reservation to the state of rights to minerals, whether known at the
time or not, along with rights of access for mining or prospecting pur-
poses, so that access to minerals in state lands must be by lease.
The Board has "wide discretion," expressly given in the regula-
tions, to lease to such parties and upon such terms as "shall, in the
judgment of the Boards, insure to the greatest benefit to the State."
To qualify as an applicant for a lease, one must be 21 years
of age, a U.S. citizen (or have declared the intention to become one),
or an association or corporation permitted by law and charter to engage
in mining activities. There is no competitive bidding; applicants get
priority on vacant land for which they submit lease applications until
a decision is reached on their application. If a lease that is not pro-
ducing comes up for renewal, there is a competition (in which the lease-
holder may participate) but it is done on a lottery basis and there is
no bonus involved.
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Coal. Rents are set at a yearly minimum of $1 an acre, and
minimum is what is charged in practice. After discovery of coal in com-
mercial quantity (called commercial discovery"), rents can be credited
against royalties.
Royalties are set by a statutory minimum of 5£ a ton of the
mine run. In practice, however, the Board has adopted a percentage
royalty of 7 percent of the value of the mine run, but in no case less
than 25£ a ton.
Acreage restrictions are as follows: A lease must generally
be of contiguous or cornering lands, but variances may be granted by
the Board if necessary, provided the lands fall within a 6 sq mi area
(or six surveyed sections, which amounts to the same thing) in the
Board's discretion. Only one class of lands (state lands, school, farm
loan lands, or individual institutional lands) may be included in any
one lease, and each lease may include no more than 1280 acres (2 square
miles). The number of leases any single party may hold is within the
discretion of the Board to decide "in the interest of fair trade, proper
competition, and prevention of monopoly."
Duration of leases is to be up to 10 years, with a preference
right of renewal for additional 10-year periods if the mine is in pro-
duction. If it is not in production, as stated above, the lease is made
available to the leaseholder and other applicants on a lottery basis.
Although the provision of the statute requiring bonds was re-
moved in 1965, bonds may still be, and are still, required by regulation.
At present, the bond requirement is a compliance bond of $5000 per lease,
or $25,000 statewide. There is also an environmental bond in an amount
equal to 100 percent of the potential damage development may do to the
land.
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Only one producing state coal lease is presently in effect
in Wyoming, although there are a million acres leased for prospecting
(there is no essential difference between the two prospecting and pro-
ducing leases for there is no prospecting permit system comparable to
the bifurcated federal system. A lease is a lease, and if it produces,
it is a producing lease, with royalty and renewal preference rights).
Assignment of lease interests is permitted with the approval
of the Board. Overriding royalties (the royalty paid the sublessor
by the sublessee), however, are limited to 5 percent over that in the
primary lease.
Relinquishment of leases, or parts of them, is permitted.
Modification of lease terms while the lease is in force is by agreement
between the Board and the lessee. A lease may be cancelled for non-
compliance or nonpayment, but there is a right of recourse to the courts.
Oil Shale. At present there is no oil shale leasing in Wyom-
ing, state or federal. The Wyoming Mining Rules and Regulations booklet
states on the cover "except oil and gas and oil shale." There has not
been any state oil shale leasing in Wyoming for a long time, if ever.
The state's primary holds are the school sections, and it seemed un-
likely that anyone would be interested in oil shale development of 640-
acre plots. The Board of Land Commissioners thought the market for
state oil shale lands would be among holders of federal oil shale leases,
to tack adjacent lands onto their federal leaseholds. There was excite-
ment about this prospect when the two federal oil shale tracts were of-
fered in 1973. However, the federal oil shale leases in Wyoming did not
sell. So everyone drew back to consider what to do next. There are now
rules being drafted for oil shale leasing on Wyoming state lands, but
they will not be ready until midsummer, 1975, at the earliest. Until
then there is no oil shale leasing to be done on Wyoming state lands.
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4. West Virginia
Mr. George Wise, the Land Agent with the West Virginia State
Land Corporation, states that there is no body of leasing regulation.
The Land Corporation uses as a reference the statute itself, Chapter 20
of the Laws of West Virginia. He states that there has been no coal land
leased since 1967.
According to Mr. Wise, all applications for coal leasing must
go first to the Director of the Department of Natural Resources, who
then refers the application to the appropriate Division Chief, if the
land comes under his jurisdiction. No mining is permitted in state parks,
which means that strip mining is not to be permitted and deep mining is
allowed only if the shaft is begun outside the state park boundary and
then tunneled underneath. Applications concerning other lands under the
jurisdiction of the Department of Natural Resources go to the appropriate
Division Chiefs: forests, parks and recreation, and hunting and fishing
areas. The State Auditor's Office handles land that has come to the
state through escheat or default of taxes. The Highway Department han-
dles lands they control. The Public Land Corporation has title to all
land not assigned elsewhere, including specifically land in the beds of
navigable streams.
West Virginia state lands are not sold, but may only be leased.
And it is provided by statute that all leases must have the written ap-
proval of the Governor of West Virginia. In theory, bids are submitted
to the Director of Natural Resources (or other responsible officer), who
may reject them all or take the highest bid from a responsible bidder
subject to the Governor's approval. Unlike the federal system in which
all the terms are set in advance by the lessor and the bidder is only for
bonuses, in West Virginia the system preserves more of the private law
character, and lease bids are considered in their entirety. Thus, one
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bid may have a higher rent but a lower royalty than another, and this
calls for judgment on the part of the Director (or other responsible
officer). It is to be expected that when (and if) West Virginia state
coal leasing resumes there will be a new set of guidelines on acceptable
rents, royalties, and other terms and procedures.
G. Vetoed Strip Mine Act
The Surface Mining Control & Reclamation Act of 1974 contained a
fairly comprehensive regulatory system covering surface mining and the
surface effects of underground mining of coal. The bill would have had
a marked impact on the coal situation had it gone into law, but it was
vetoed by President Ford. This year a similar bill has been vetoed, and
attempts in the House to override the veto failed. The major provisions
of the vetoed bills will be described.
The basic premises were that, climate and terrain and local condi-
tions being what they are, the best way to administer a program govern-
ing and limiting the effects of strip mining and mandating and supervis-
ing reclamation would be to have it done by the states. Accordingly,
the framework that was established provided the states with primary
administrative responsibility. The regulatory agencies created by the
state were to demonstrate to the satisfaction of the Secretary of the
Interior that they were capable of establishing and enforcing programs
containing criteria no less stringent than those put forth in the Act.
If they did so, then their programs would govern, and they could indeed
be more severe than the federal program. If the states were unable to
satisfy the Secretary that they could set up programs capable of this
enforcement, or if, having set them up, the Secretary determined that
the state programs were not properly enforcing the minimum criteria of
the Act, he could establish a federal program in the area to preempt
state enforcement, and keep it in force until such time as a satisfactory
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state program was put forth. The Secretary was also to enforce these
requirements in federal leasing programs, or on federal lands generally,
except Indian lands, which were considered separately. Among the prin-
cipal elements of the program were stiff and explicit requirements for
protection of the environment during the mining, and similarly stiff and
explicit requirements for reclamation. The benchmark for restoration
was to be the uses the land was capable of supporting before any mining
was done on it, whether that mining was done by the present or proposed
operator or by someone else 30 years before. It is to be noted that the
present BLM regulations in 43 CFR Part 23 (Surface Exploration, Mining
and Reclamation of Lands) and USGS regulations in 30 CFR Part 211 and
231 (Operating Regulations) have been or are being revised by the De-
partment to reflect the wording and intention of the vetoed strip mine
bills.
The first major reform would have been the removal of supervision
and enforcement of surface mining and reclamation procedures from the
BLM and the USGS and the placing of them in a new office in the Depart-
ment of the Interior, to be called the Office of Surface Mining Recla-
mation and Enforcement. By law, no federal authority, program, or func-
tion having as its purpose the promotion of the development of any min-
eral resource shall be transferred to this office. The idea was to
protect the new office from any conflicts of interest.
The states would have had 18 months from enactment to submit a pro-
gram if they wish to assume exclusive jurisdiction to regulate surface
mining and reclamation in their states (this does not include activity
on federal leaseholds) . The Secretary would have had 6 months to review
the program and approve or disapprove it. If he disapproved it, the
state would have had 60 days to resubmit, and the Secretary 60 days more
to redecide. If a state did not submit a program within the 18 months,
or resubmit a disapproved one in the required time, or if the Secretary
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determined that a state program in operation did not meet the require-
ments of being able to enforce, at a minimum, the standards for operation
and reclamation specified in the Act, he would then put a federal program
in operation in that state. There would have been, of course, compli-
cated hearing requirements. A state that did not apply or qualify in
time could try for approval at any time; conversely, a state program
deemed not to be working could be superseded in whole or in part at any
time by a federal program. The idea was to have state programs for those
states that want exclusive jurisdiction and can demonstrate that their
programs would be sufficient in fact, not just on paper, to ensure that
surface mining (and the surface and hydrological effects of underground
mining) would be regulated and kept at least within the standards pro-
vided in the Act. States would have been quite free, in their own pro-
grams, to require a higher standard of performance from operators, but
if it appeared that a lower standard would in practice be required, the
federal program would have substituted to ensure this minimum compliance.
And the "minimum" would not have been easy, either; the criteria in the
federal program were rather stiff. A state program would have to incor-
porate, at a minimum, the environmental protection criteria discussed
below, would have to provide sanctions, including bond forfeiture, sus-
pension and revocation of permits, and civil and criminal penalties no
less stringent than the federal program, would have to demonstrate the
existence of sufficient personnel with sufficient expertise to enforce
the requirements of the Act, would have to include a permit system that
met the requirements of the Act, a procedure for designating areas un-
suitable for any surface mining at all, and coordination procedures to
prevent federal/state duplication. If it worked, the system would ensure
that the provisions of the Strip Mine Act applied everywhere without the
necessity of direct federal supervision or enforcement if the states
would do it (or more) themselves.
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Approval of a state program would require the approval of the Ad-
ministrator of EPA as to air and water pollution regulation , and the
input of EPA, Agriculture, and other federal agencies, a public hearing,
and a finding by the Secretary that the state had the legal authority
and personnel to enforce its program. (There was a provision suspending
introduction of a federal program if implementation of the state program
was held up by an injunction, such suspension not to exceed one year.)
Permits granted by a state program later superseded by a federal
program are valid, but reviewable by the new authority, and vice versa.
Since it was in the contemplation of the Act that the same standards,
at minimum, would be enforced by a state program or a federal program,
the Act used the words "regulatory authority" to refer either to the fed-
eral Office of Surface Mining Reclamation and Enforcement or to an ap-
proved state authority, depending on the circumstances. This is helpful
word usage, and for the sake of clarity it will be used here.
The so-called Environmental Protection Performance Standards stated:
1. Recovery of the coal is to be maximized so as to prevent the
necessity of remining.
2. The land is to be restored to a condition at least fully
capable of supporting the uses which it was capable of sup-
porting before any mining was done, or "higher and better"
uses if it is consistent with a local land-use plan, etc.
The important thing is that an operator could be held re-
sponsible for returning land, which was mined before he
arrived, to the condition it was in before anyone mined it.
In other words, he could be required to leave the land
better than he found it.
3. The approximate original contour of the land must be re-
stored. This means backfilling, compacting where necessary
because of volumetric expansion of spoil and mine waste,
eliminating all highwalls (to prevent isolation of the land
above the highwall), getting rid (in specifically approved
ways) of spoil piles, depressions (unless needed for water
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for revegetation), etc. Mountaintop mining is permitted
under certain circumstances. Grading is required until
the original contour is restored. If there is too much
overburden and spoil, a contour so arranged to prevent
slides, erosion, etc., must be created. Drainage of and
covering of all acid-forming or toxic substances. A lot
of complex technical requirements were given, but the
crux was that the original contour must be restored un-
less there were too much overburden, in which case a con-
tour would have to be created, which did not exceed the
angle of repose.
4. Surface areas including spoil piles must be stabilized to
control air and water pollution or erosion.
5. Topsoil must be segregated when removed so it (or a su-
perior stratum if one is discovered) may be put on the
top when the reclamation begins, and the topsoil or best
available subsoil must be stored to preserve it, and it
must be put back on the top of the restored contour. If
the topsoil has to be segregated for so long that it
would deteriorate, it may be necessary to plant vegeta-
tion on it to preserve it. It must be kept free of acid
or other soil contaminants. The topsoil must be re-
stored when mining is finished.
6. Offsite areas must be protected from slide or damage,
and no spoil or waste may be put there.
7. Permanent impoundments of water may be created if called
for in the reclamation plan (see below) subject to a
number of severe requirements on size, dam construction,
quality and level of impounded water, etc. Quality of
water of surrounding users may not be impaired.
8. Auger holes must be filled with impervious and noncom-
bustible substances.
9. The hydrologic balance must be preserved by avoiding
acid or other toxic mine drainage, preventing contribu-
tion of suspending solids into stream flow or runoff
above the level as measured before any mining in the
area, removing siltation structures from drainways
after revegetation, restoring aquifer capacity, pro-
tecting alluvial valley floors (if any), and so on.
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10. Waste must be disposed of in compacted layers, etc.
11. Surface coal mining within 500 feet of active or aban-
doned underground mines is not allowed, subject to
variances.
12. Groundwater must be protected from acid or other toxic
leachates.
13. Conditions lending themselves to sustained combustion
must be avoided.
14. The use of explosives is subject to restrictions.
15. Placement of access roads is subject to environmental
restrictions (erosion, siltation, damage to wildlife
habitat, water pollution, damage to private property,
etc.).
16. Drainage channels or stream beds must not be blocked.
17. Regraded areas must be revegetated, using native
species if possible, and the operator is responsible
for seeing to it that the revegetation takes hold.
His responsibility would have lasted 5 years after
the last year of augmented seeding, fertilization,
irrigation or whatever, or 10 years if the annual pre-
cipitation averages less than 26 inches. If the post-
reclamation use is intensive agriculture, his period
of responsibility would start with the initial planting.
18. Reclamation must be done in an "environmentally sound
manner" and as contemporaneously as possible with the
mining activity.
19. No debris on the downslope, etc.
This list gives a general idea of the breadth of the requirements;
these requirements were stated in a much more complex manner in the bill
itself. Certain variances are allowed, subject to restrictions and safe-
guards, and keyed to the post-mining land use plan. Thus the program
was very comprehensive, with enforcement measures built in.
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The Act required that, from date of enactment, anyone opening a new
or previously abandoned mine must have a permit if the mine is within a
state with an existing state program. There were initial regulatory pro-
cedures. Beginning with the date of enactment, any mining on a permit
granted on or before enactment would have to meet some of the standards
of the bill, those relating to restoration to condition capable of sup-
porting before any mining, those relating to restoration to original
contour, to segregation of topsoil, to hydrological balance, to water
retention facilities, to revegetation, and to deep slopes. Work on per-
mits issued before the date of enactment would have to meet these stand-
ards within 135 days. By the time 20 months had elapsed operators must
have a permit from the state agency if they contemplate future work under
the state program.
Federal or approved state programs would have to provide for random
inspections, unannounced, to be held at least every three months. Later
the inspection requirements are escalated to every month. It might be
pointed out that the Environmental Impact Assessment Project study of
the Proposed Coal Leasing Program EIS has noted that there are not
enough agents available in the department now to cover even the minor
inspection duties currently that would have been required. Although the
bill contemplated establishment of a new office, there was doubt that
even the new office would be able to obtain sufficiently trained manpower
to do the inspection the bill would require. More important, it is
equally or more doubtful that the states would have been able to obtain
enough inspectors, and if they cannot demonstrate that they would have
sufficiently trained people to carry out the requirements of the program
they could not have gotten a state program approved, and a federal pro-
gram would have to have been instituted.
Permit applications would have to have been accompanied by extensive
documentation, a lot of it highly technical and expensive. Furthermore,
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the application fee for a permit under the new system "shall be based. . .
upon the actual or anticipated cost of reviewing, administering, and
enforcing such permit. . .," which is also likely to have been very ex-
pensive .
The strip mine bill also included an ambitious program of restoring
abandoned strip mine sites not related to present operations: the scars
of Appalachia, and so forth. This was to be paid for in large measure
by fees from operators. The reclamation fee was, in the 1974 Act, set
at 35£ a ton for surface mining and 25«? a ton for underground mining.
It is interesting that, first, present operators would have been re-
quired to pay to reclaim land the destruction of which they had nothing
to do with, and second, that the reclamation standards would have re-
quired restoration of the land to its use potential before any mining
was done. Thus, in at least these two ways, present operators would
have been required to pay for the sins of their predecessors. It is an
interesting public policy to require coal operators to clean up a mess
they themselves did not create.
An applicant for a mining operation permit under the Act would have
had to present a reclamation plan, setting forth past and projected
future land use, the capacity of the land to support a variety of alter-
native land uses, a detailed description of how the reclamation would
be accomplished, intricate technical data of many sorts, results of
test borings, a timetable, and a host of other information. One of the
objections that the coal industry had to the Strip Mine bill was the
immense amount of paperwork it would have imposed on them; at almost
every step detailed reports and proposals would have been submitted.
These would be expensive and would have added substantially to the cost
of operating a coal mine.
A performance bond would have to have been posted, which is suffi-
cient to pay for the cost of putting into effect the approved reclamation
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plan if done by a third party. This includes recontouring, compacting,
construction of water retention facilities, revegetation, etc., a very
complicated and expensive business. Not only would this have been paid
by the operator, but he would also have to post a bond of 100 percent of
the cost. Surety premiums can be substantial, especially since the re-
sponsibility for revegetation extends 5 or 10 years after everything
else is over and the bond can be increased during the term of the permit
if necessary. Cumulatively, there appeared to be merit to the industry
complaint that this bill would drive up their costs spectacularly.
There were also coal exploration permits, which would have required
less elaborate information but which would have required an application
fee similar to that described above for operating permits and the written
consent of the surface owner.
Another important provision of the bills related to areas unsuitable
for surface mining. The federal program provided, and the state programs
to be approved would have to have provided, for procedures to declare
certain areas unsuitable for any surface mining and therefore to prohibit
surface mining at all on the area. On petition by any interested party,
which can include agencies of government, areas could be declared un-
suitable if the regulatory agency determined that reclamation pursuant
to the requirements of the Act was not "feasible." Moreover, if the
mining operations themselves would be incompatible with existing land
use plans or programs, if they would affect "fragile or historic lands"
in which the operations could result in damage to historic, cultural,
scientific, or aesthetic values, if the operations could affect renew-
able resource lands and could result in substantial damage to water
supply or food or fiber products or aquifers, or if the lands are
"natural hazard lands" (floods, "unstable geology," etc.). In federal
lands, the Secretary was directed to survey the federal lands and with-
draw from leasing any such unsuitable lands. A public hearing was
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required. Withdrawn also were coal areas in the National Parks, Na-
tional Forests, National Wildlife Refuges, National Trails, National
Wilderness Areas, National Wild and Scenic Rivers, and National Recre-
ation Areas. Withdrawn also were publicly owned parks or places in-
cluded in the National Register of Historical Places, if an adverse
impact was anticipated, unless the regulatory agency and the agency
having authority over the park or place agreed, near roads (subject to
permission to move the road), etc. In these areas surface mining per-
mits would simply not be issued at all.
Another provision of interest: although the principal focus of the
bills were on surface mining, there was also provision for protection
against the harmful surface effects of underground mining. Permits
would have to be issued for these effects, too, and would include pro-
vision for measures to prevent subsidence, maximize stability, maintain
the surface value of the lands, make proper provision for disposal of
mine waste of all sorts, keep leachate from the ground and surface
waters, revegetate regraded areas, protect the hydrological balance,
seal portals, and do various other things, which would be expensive and
time-consuming.
Penalties could have been severe. There was a sort of graduated
schedule, beginning with show-cause orders, proceeding through cease and
desist orders and permit revocation, finally arriving at civil penalties
for violations of the Acts, the state or federal program or their regu-
lations, or the lease terms incorporating these restrictions, up to
$5000 for each violation, each day being considered a separate violation.
These civil penalties might be sought in any violation, but matters of
past history, good faith attempts at abatement, seriousness of violation
and consequencies, size of business (capability of absorbing the penalty),
and negligence could all be taken into account. Hearings and appeals
were provided. Willful or knowing violations could lead to criminal
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penalties, up to a $10,000 fine or a year in prison, or both. For ap-
proval, state programs had to include penalty provisions at least as
stringent as these. False statements on any application, report, or
other document involved in the program could also draw a $10,000 fine
and/or a year in prison. There was nothing in the federal mining law
up to this point that provided any of these sorts of penalties.
Protection of surface-owner interests: these provisions were de-
feated in the Senate markup of the latest bill. These would have re-
quired the written consent of the surface-owner for any mining of fed-
eral coal beneath his land that involved other than underground opera-
tions. In addition to this, the developer was required to pay the full
money value of the surface-holder's interest as fixed by three appraisers,
one appointed by the Secretary, one by the surface-owner, and one by the
other two appraisers. The amount began with the fair market value of
the surface estate, and then added to loss of income to the surface-
holder during the mining operations, the cost of livestock, crops, water
and so on, the cost of any other damage that might be done, and an addi-
tional amount related to the length of tenure of the surface-owner
(uprooting long-established holdings, etc.), not to exceed the amount
of the four additions listed or $100 an acre, whichever was less. This
amount, if paid in installments, might be adjusted according to increases
in the consumer price index. And it appears that the surface-owner would
have gotten to keep his title to the surface estate.
To quality for this protection a surface-owner would have had to
hold title, legal or equitable, to the surface estate, have a principal
residence on the land or personally farm or ranch it or derive a sig-
nificant portion of his income from such farming or ranching, and he
would have had to have met these conditions for three years, provided,
however, that if three years had not elapsed the Secretary could hold
up putting the land into a leasing tract until the three-year period had
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been satisfied. This applied only to split-fee lands where the mineral
estate is owned by the United States. Consent was not required under
this section if the coal was not federal coal. There was also a provi-
sion that anyone who offered anything of value to a surface-owner to
induce him to consent, or any surface-owner who accepts anything of
value for his consent, was liable to a civil penalty of 1-1/2 times the
value of the item of value. Consequently, no private deals were per-
mitted. Federal lessees of surface interests (e.g., for grazing) were
entitled to protection in the form of a consent requirement and the re-
quirement of a bond against damage to the surface estate.
There were a number of other provisions to the bills of which the
most interesting include:
1. Provision, in the case of checkerboards or other closely re-
lated federal and nonfederal lands, for cooperation between
the state and federal authorities to avoid duplication.
Since either one could delegate authority to the other,
operators would have only one authority and set of rules
and forms to deal with, instead .of two.
2. Extensive provisions for hearings, public participation and
public standing to sue in many of the stages of the program.
3. Special exemptions and provision for other arrangements for
certain bituminous coal mines located west of the 100°
meridian, and for anthracite mines, principally in
Pennsylvania.
4. Exemption from the Act of people who took coal from their
own land for their own use, and commercial operations lim-
ited to two acres or less.
5. Exemption of Indian lands from this program, pending a
study. The idea of the study was to see if it can be
arranged to have the Indian tribes act as states, running
their own programs subject to federal preemption in the
same fashion as state programs are.
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It should be noted that these programs covered only coal, pending
a study of extending the program, or devising a different program, for
other minerals presumably including oil shale.
H. Existing Environmental Regulations
Three bodies of regulations deal with the environmental impact of
coal exploration and mining: 43 CFR Part 23, which details the proce-
dures of the BLM prior to issuance of a lease or permit, 30 CFR Part 211
ff., which details the responsibilities of the USGS for enforcement of
the restrictions included in a lease or permit by the operation of
43 CFR Part 23, and 25 CFR Part 177, which covers Indian lands.
The Department of the Interior overhauled the first two of these
sets of regulations with the intention of including in them as much as
possible of the language of the 1974 Strip Mine bill. The title of
43 CFR Part 23 is "Surface Exploration, Mining and Reclamation of Lands.'
The principal provisions of the current regulations include the fol-
lowing:
1. No one may explore, test or prospect for Leasing Act min-
erals in such a way as to disturb the surface of the earth
without a permit.
2. In connection with an application for a permit, the Dis-
trict Manager of the BLM must make or cause to be made a
technical examination of the effects of the proposed
exploration or surface mining on a variety of environ-
mental elements, including:
• Recreational, scenic, historical and ecological values.
• Control of erosion, flooding and water pollution.
• Isolation of toxic materials.
• Prevention of air pollution.
• Reclamation prospects, by revegetation, replacement
of soil, or other means.
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• Prevention of slides.
• Protection of fish and wildlife, and their habitats.
• Prevention of hazards to public health and safety.
3. Based on this technical examination, the BLM District
Manager formulates general requirements for environ-
mental protection that must be included in the lease
or permit. Participation of other agencies, if they
have the primary responsibility for the land, is pro-
vided for.
4. The District Manager may limit or prohibit operations on
land where "previous experience under similar conditions
has shown that operations cannot feasibly be conducted
by any known methods or measures" to avoid:
• Dangerous rock- or landslides.
• Substantial deposition of silt or sediment into streams,
lakes, or reservoirs.
• Lowering of water quality below levels established by
the state water pollution control agency, or by the
Secretary.
• Lowering of the quality of waters that exceed minimum
standards, absent a certification that it will not
preclude assigned uses of the water and that such
lowering is "necessary to economic and social de-
velopment ."
• Destruction of "key" wildlife habitat.
• Destruction of "important" scenic, historic, natural,
or cultural features.
Water quality objections bring into force a requirement of
consultation with the Federal Water Pollution Control Ad-
ministration and a finding by them that the proposed ac-
tivity will not violate the Federal Water Pollution Con-
trol Act.
5. Before disturbing the surface to explore, test, or pros-
pect for Leasing Act minerals, an exploration plan must
filed and approved by the USGS Mining Supervisor in con-
sultation with the BLM District Manager. The exploration
plan must include information on the land, proposed op-
erating methods, and methods proposed to prevent fire,
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erosion, pollution, damage to wildlife, public safety
and natural resources both during and after exploration
activities. There are provisions for negotiation if
the plan is not initially acceptable.
6. Before beginning any mining operations under a federal
permit or lease, a mining plan must be filed and ap-
proved by the USGS Mining Supervisor with the consulta-
tion of the BLM District Manager , as in an exploration
plan. This proposed mining plan must include much
information, including information about the land and
• A statement of proposed operating methods, with
information on proposed roads, trails, and struc-
tures .
• An estimate of proposed water use and pollution.
• A design for impoundment and treatment of runoff
water, to prevent erosion, sedimentation, and
pollution.
• Description of methods to prevent fire, soil ero-
sion, water pollution, damage to fish and wildlife,
and dangers to public health and safety.
• If revegetation is required, a detailed plan must
be provided.
• If regrading and backfilling is required, a de-
tailed plan must be provided.
There are provisions for negotiations and for approval
of a partial plan, and similar administrative measures.
7. A performance bond is required sufficiently large to
satisfy the reclamation requirement of the approved
exploration or mining plan, but not less than $2000.
8. Elaborate reporting is required of the operator, de-
tailing his progress in performing each of his obli-
gations under the approved plan.
9. There is a provision headed "Notice of Noncompliance;
Revocation," which provides for issuance of notices
of noncompliance by the USGS or the BLM but does not
mention revocation. As noted earlier, revocation of
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a federal mining lease is not as easy as perhaps it
should be,
10. There are appeals procedures.
25 CFR Part 177 governs Indian lands. It is very similar to
43 CFR Part 23, except:
1. In place of the BLM District Manager there is substituted
the Superintendent of the BIA or his representative.
2. This will be superseded, since the Strip Mine bill does
not apply to Indian lands, pending a study of the feasi-
bility of having Indian tribes set up their own programs
on a par with state programs.
3. There ij provision for suspension and cancellation by the
Mining Supervisor in case of noncompliance.
4. The Superintendent must consult with Indian landowners
on actions he plans to take concerning technical exami-
nation, granting or denial of permits, exploration plans,
noncompliance actions, etc.
30 CFR Part 211 provides Coal Mining Operating Regulations. It
is principally concerned with the responsibilities of the USGS during
the process of approval of exploration and mining plans and the super-
vision and enforcement of the statutes, regulations, and environmental
protection restrictions incorporated into the terms of permits or
leases. It applies to all federal leaseholds regardless of surface
ownership, and to Indian lands. It provides, however, that (except
with respect to §211.37, Surface Mining) in case of conflict with
43 CFR Part 23 and 25 CFR Part 177, discussed above, those regulations
shall be considered superior to these.
The latest available text is that of a proposed revision, published
in the Federal Register on January 30, 1975, but yet to be officially
promulgated. This revision is part of the effort mentioned above to
bring the existing federal regulations in line with the language of the
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Strip Mine bill. Section 211.37 incorporates much of that language, and
there are numerous other instances of strengthening of provisions in the
existing Part 211.
There seems little point in detailed recitation of the provisions
of this Part. Section 211.l(b), however, sums up the purpose of the
provisions:
"The purpose of the regulations in this part is to promote
orderly and efficient prospecting, exploration, testing,
development, mining, preparation and handling operations
and production practices, without avoidable waste or loss
of coal or other mineral deposits or damage to coal or
other mineral-bearing formations; to encourage maximum
recovery and use of coal resources; to promote operating
practices which will avoid, minimize or correct damage to
the environment—land, water and air—and avoid, minimize
or correct hazards to public health and safety; to require
effective reclamation of lands; and to obtain a proper
record and accounting of all coal produced."
(The last purpose—that of a record—is there because the USGS has the
responsibility for assessing and collecting royalties.)
The responsibilities of the USGS Mining Supervisor are enumerated.
He is to inspect to prevent waste or damage, and regulate operations to
conserve mineral resources. He is to require that operators obey the
law and the regulations and conform to the requirements in their lease
or permit, and in their approved exploration or mining plans. He is to
require that work be performed in an environmentally sound manner, and
that reclamation be done as contemporaneously as possible with the mining
itself. He is to obtain and check production records and assess and
collect rent and royalty money. He is to decide on applications for
suspension of operations or termination of suspension (and on Indian
lands transmit such applications to BIA officials). He is to determine
whether operations that have ceased or that have been abandoned have
conformed to reclamation and other requirements. He is to inspect and
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determine the adequacy of air and water pollution control methods, and
require that they be sufficient to meet the requirements of the law, the
lease or permit, and the operations plan. He is to determine the amount
of reclamation bonds. He is to prescribe or approve methods of protec-
tion of water from leakage from wells and prospect holes drilled through
coal. He is authorized to issue mining operations orders as necessary
to assure compliance with the rules.
There is included in the next section a series of obligations of
permittees and lessees, which obligations the USGS Mining Supervisor may
also enforce, since they are made obligations by the regulations. Oper-
ators must conform with the laws, the regulations, the terms of leases
and permits, the terms of approved plans, and the orders and instructions
issued by the Mining Supervisor. They must take precautions to prevent
waste and damage to mineral formations. They must "take such action as
may be needed to avoid, minimize or control" soil erosion, air pollution,
water pollution, alteration of water flow, damage to crops, vegetation
or timber, injury to fish and wildlife and their habitat, unsafe condi-
tions, damage to improvements, by whomever owned, and damage to recrea-
tional, scenic, historical, archaeological, and ecological values. All
of which is purposefully vague; it is the responsibility of the Mining
Supervisor to determine questions arising under these obligations, and
his word is (subject to appeal procedures) the final one. He may issue
mining operations orders to enforce any of these obligations as he sees
fit ("Don't build the road here, build it there." "install a mine drain-
age discharge monitoring device here, here and here," etc.).
There follow a number of highly complex and technical requirements
dealing with reporting, maps and plans, requirements for the contents of
proposed exploration and mining plans, surveillance wells and blowout
control devices, etc. One thing of importance, which is not dealth with
elsewhere, is a provision that production must be conducted in a manner
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to yield the maximum recovery of coal deposits consistent with environ-
mental values, and that a lessee shall not "leave or abandon any coal
which otherwise could be safely recovered by approved methods of mining
when in the regular course of mining the time shall arrive for mining
such coal." This is for the purpose of conserving natural resources,
protecting the government's royalty interest, and preventing the envi-
ronmental consequences attendant upon secondary or tertiary recovery
attempts.
There is also provision in this part for such things as permission
to mine narrow isolated strips of nonleased coal to prevent their loss,
and other similar minor housekeeping matters.
Section 211 deals only with coal. Oil shale is included in the
coverage of Part 231. However, there is no need to examine these provi-
sions, which are very similar to those in Part 211, because the only
federal oil shale leases that are likely to be let for some time have
already been let, with elaborate environmental protection provisions of
their own, and the study of the differences between USGS enforcement of
coal leases and plans and oil shale leases and plans is not, at this
point, very profitable.
It should be noted, however, that both parts of the regulations
stipulate that if the orders of the Mining Supervisor are not obeyed,
after due notice of noncompliance and so on, the Mining Supervisor may
order suspension of operations. Appeals from Mining Supervisors' deci-
sions go to the Director of the USGS (or, on Indian lands, to the Com-
missioner of the BIA), and from there to the Board of Land Appeals in
the Office of Hearings and Appeals in the Office of the Secretary of the
Interior.
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I. State Reclamation Statutes and Regulations
It seems likely that in the light of federal action, state systems
will be revised and/or will be superseded by the federal/state system
outlined in the section on the Strip Mine bill. By and large, the state
laws do not rise to the level that will be expected of them under the
Strip Mine bill. Two things should be kept in mind, however. The first
is that in Montana, contour mining is prohibited. The second thing to
bear in mind is that in West Virginia the legislature has passed, for
the third time in a row, a two-year moratorium on surface mining in
counties in which there has been no surface mining in the past. If the
Governor has not yet signed the bill, he is expected to.
J. Other Regulations
There are other agencies of government that have impact on coal
mining. In addition to the Environmental Protection Agency (air and
water pollution standards), there is also the Mining Enforcement and
Safety Administration (Department of the Interior), which enforces the
Federal Coal Mine Health and Safety Act of 1969. There is enforcement
of nondiscrimination provisions of federal leases. These are tax
issues. There are state mining safety laws, and requirements for li-
censes from state authorities to open and operate mines (which are pri-
marily concerned with safety and competence of personnel). There are
zoning and local land use regulations. The law on the subject is indeed
a seamless web. This paper has endeavored to give the background of
coal and oil shale leasing, and has attempted to shed some light on the
principal environmental restrictions which affect rights under leases.
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8—FINANCING THE SYNTHETIC LIQUID FUELS
INDUSTRY BY THE U.S. CAPITAL MARKETS
By Ronald L. Cooper, John W. Ryan,
Barry L. Walton
A. Introduction
The future outlook for investment in the U.S. domestic energy
industry must be considered within the framework of capital expenditure
requirements for other sectors of the economy. Capital requirements
for the aggregate economy in turn depend on the future growth of the
GNP and the rate of inflation.
The discussion in this chapter begins by outlining the framework
in which the capital expenditures requirements for the aggregate econ-
omy and the domestic energy industry are generated. First, the projec-
tions for the aggregate economy are based on the Ford Foundation Energy
Policy Project (EPP), A Time to Choose: America's Energy Future,1 as
well as other sources.2~7 Projections for the energy industry to 1985
rely heavily on the study carried out for the Ford Energy Policy Project
by Hass, Mitchell, and Stone.8 Projections for 1985-2000 are based on
the extrapolation of past trends and the 1973-1985 relationships between
capital expenditures and energy output. Second, the capital expenditures
for the energy industry are discussed for two main scenarios: Histori-
cal growth (HG), and technical fix (TF). HG assumes that the growth of
energy consumption continues in the future at rates close to historical
rates, with little or no conservation. TF assumes a much greater amount
of demand conservation which, in turn, significantly lowers the growth
of energy consumption over the 1975-2000 period. Under HG, three
302
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subscenarios are considered: (1) accelerated development of domestic
petroleum supplies (HG1); (2) accelerated nuclear development (HG2);
(3) continued heavy reliance on imports of crude oil (HG3). The domes-
tic capital requirements for the energy industry differ for each scenario.
Third, the capital requirements of the petroleum industry with and with-
out synthetic fuels are compared to the petroleum industry's sources and
uses of funds.
B. Outlook for Total Business Fixed Investment and Other Related
Macroeconomic Variables
Business fixed investment represents one use of total savings in
the aggregate economy. Other competing uses of savings funds are financ-
ing increases in business inventories, residential construction, and
federal, state, and local debt financing. Total savings comes from two
main sources: business savings, and personal savings of households.
Another source of savings, when funds flowing into the country exceed
funds flowing out, is net foreign investment. The total sources and
uses of savings and investment funds for 1973 are shown in Table 8-1.
Projections of the total sources and uses of funds are made for 1975-2000,
and funds statements for 1985 and 2000 are presented in Table 8-2 for il-
lustration. Also shown are the cumulative totals for the sources and
uses of funds over the 1975-2000 period. The projections are made in
two stages. First, predictions of "desired" capital are made for the
25-year period for each sources and uses component. The methodology
behind these projections, which covers each category in Table 8-2, is
explained in Appendix A, Tables A-l through A-5. Since the total sources
of funds must balance the total uses, Table 8-2 includes both the
"desired" and "realized" projections. For each year over the 1975-2000
period, the total use of funds exceeds the total supply of funds on a
"desired" basis. The equality between the total sources and uses of
303
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Table 8-1
SOURCES AND USES OF FUNDS—1973
(Billions of Current Dollars)
Sources of Funds
Business savings 136.5
Personal savings 74.4
Net foreign investment CKj.
Total sources 211.0
Uses of Funds
Business fixed investment
Residential construction
Inventory investment
Federal deficits
State and local government borrowing
Credit agency borrowing
Statistical discrepancy*
Total uses 211.0
Savings Gap 0
*The statistical discrepancy arises from the inability to
measure the uses of funds with precision.
Source: Reference 6.
funds in each year is accomplished by interest rate adjustments in the
capital markets. To eliminate the discrepancy between total investment
and total saving, the total sources have been increased by half the
amount of the gap, and the total uses have been similarly decreased.
The total amounts within the sources and uses are allocated to each
component on the basis of historical shares.
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Table 8-2
PROJECTED SOURCES AND USES OF FUNDS
(Billions of Current Dollars)
1985
2000
Cumulative 1975-2000
Sources of Funds
Business savings
Personal savings
Net foreign investment
w
o Total sources
w
Uses of Funds
Business fixed investment
Residential construction
Inventory investment
Federal deficits
State and local
government borrowing
Credit agency borrowing
Total uses
Savings Gap
Desired
$378
139
0
$517
446
135
27
4
3
10
$625
108
Realized
$417
153
0
$570
408
123
25
3
2
9
$570
0
Desired
$1326
535
0
$1861
1623
475
96
4
5
15
$2218
357
Realized
$1453
586
0
$2039
1492
437
88
3
5
14
$2039
0
Desired
$14,639
5,696
300
$20,635
17,413
5,223
1,053
91
103
335
$24,218
3,538
Realized
$15,910
6,191
326
$22,427
16,126
4,837
975
84
95
310
$22,417
0
-------
Current dollar projections of business fixed investment are con-
verted to constant 1973 dollar projections by dividing the current dol-
lar figure by the projected implicit price deflator corresponding to
business capital expenditures. The methodology for projecting the capi-
tal expenditures price deflator is explained in Appendix A, Table A-3.
C. Investment in the Energy Industry
Energy investment is projected in Table 8-3 for the five major
energy groups—domestic petroleum, electric utilities, natural gas, coal,
and nuclear—for 1975-2000 for the three options under the HG scenario.
Energy investment projections are also developed for the TF scenario.*
In the reference case, synthetic fuels are excluded from energy
investment over the 1975-2000 period. The EPP energy projections are
adjusted to exclude synthetic fuels by shifting synthetic fuel entries
to the imports category. Table 8-3 shows capital expenditure projections
at 5-year intervals for 1975-2000 for the three options under HG. The
average annual growth rates of capital expenditures in 1973 dollars for
HG1, HG2, and HG3 are, respectively, 4.79, 4.72, and 4.53 percent. The
corresponding average annual growth rate for total business fixed invest-
ment (Appendix A, Table A-3) over the same time span is 4.3 percent.
Thus, because investment in the energy industry under HG is projected
to grow at a faster rate than for the economy as a whole, the share of
total investment devoted to the domestic energy industry must increase
significantly for the projected domestic supply options to be met.
Under HG, the increasing shares of energy investment reach a maximum
*In the Ford study,1 a third main scenario is considered—zero energy
growth (ZEG). However, insufficient information is provided in that
study for SRI to develop energy investment projections for ZEG.
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Table 8-3
PROJECTIONS* TO 2000 OF CAPITAL INVESTMENT IN U.S. DOMESTIC ENERGY
INDUSTRY UNDER HISTORICAL GROWTH: BILLIONS OF 1973 DOLLARS
(Excluding Synthetic Liquid Fuels)
1975 1980 1985 1990 1995 2000
HG1
Domestic petroleum and natural gas
production and refining
Electric utilities, including
nuclear facilities
Natural gas distribution
Coal production (excluding coal
for synthetic gas)
Nuclear fuel production
Total
HG2
Domestic petroleum and natural gas
production and refining
Electric utilities, including
nuclear facilities
Natural gas distribution
Coal production, excluding coal
for synthetic gas
Nuclear fuel production
Total
HG3
Domestic petroleum and natural gas
production and refining
Electric utilities, including
nuclear facilities
Natural gas distribution
Coal production, excluding coal
for synthetic gas
Nuclear fuel production
Total
13
21
5
2
_0
41
13
21
5
2
0
41
13
21
5
2
0
41
18
30
5
2
2
57
18
31
5
2
2
58
14
30
5
2
_2^
53
23
42
5
2
_2
74
23
43
5
2
2
75
16
42
5
2
_£
67
25
57
5
2
_3
92
24
59
5
2
4
94
18
57
5
2
3
85
28
72
6
3
5
114
25
75
6
2
6
114
20
72
5
3
5
105
30
87
6
3
6
132
26
92
6
3
8
135
22
87
6
3
6
124
*Appendix B describes the methodology underlying the projections.
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in 1995 and somewhat decline between 1995 and 2000. For example, under
option HG1, as shown in Table 8-4, the energy share of investment in-
creases from about 29 percent in 1975 to 34 percent by 1995, and 32 per-
cent in 2000.
Table 8-4 shows the increases in the energy share of total invest-
ment with the introduction of synthetic fuels for automotive transporta-
tion. The synthetic fuels investment projections are taken from Chap-
ter 6.* It is observed from Table 8-4 that the required shares of in-
vestment in energy increase much more significantly with the introduction
of synthetic fuels. For example, under option HG1, the share of energy
in total investment increases from about 29 percent to a maximum of
36 percent in 1995, and then falls back to 35 percent in 2000.
Table 8-5 presents capital expenditures at 5-year intervals for
1975-2000 under the technical fix scenario (TF1). Because of the much
greater amount of energy conservation in TF than HG, energy investment
requires much lower shares of total business fixed investment.
Under both historical growth and technical fix scenarios, energy
industry investment has to increase relative to total business fixed
investment because of increased reliance on domestic energy sources.
Past growth in energy demand has been met by larger imports while
domestic production has declined.
Under all scenarios electric utility investment requires a major
portion of the total energy industry investment—roughly 60 percent or
more. Therefore, the funds and interest rates available to other indus-
tries are quite sensitive to events concerning electric utilities.
*It is assumed that the production of synthetic fuels for automotive
transportation will replace an equivalent amount of crude oil imports,
and it will not substitute for domestically produced oil. Table B-3
summarizes the annual synthetic fuels investment for the maximum cred-
ible implementation scenario.
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Table 8-4
CAPITAL EXPENDITURES FOR ENERGY INDUSTRY COMPARED
TO TOTAL U.S. BUSINESS FIXED INVESTMENT
UNDER HISTORICAL GROWTH
(Percent)*
Excluding synthetic
fuels
Including synthetic
fuels'''
1975 1980 1985 1990 1995 2000
HG1:
HG2:
HG3:
29
29
29
31
31
29
32
32
29
33
33
30
34
34
31
32
33
30
HG1:
HG2:
HG3:
29
29
29
32
32
30
33
33
30
35
36
32
36
36
33
35
35
33
*Defined by dividing energy investment from Table 8-3 by "desired"
business fixed investment for the appropriate year from Table A-3.
tAnnual investment for synfuels from the maximum credible implemen-
tation scenario (Table 6-8, Chapter 6) was added to investment in
Table 8-3.
Investment required for coal production is less than 5 percent of the
electric utilities investment. Since electric utilities are a regulated
industry, the government can (through a liberal treatment of rate re-
quests) provide the utilities with an internal source of funds financed
by the general public. Thus, while historical financial markets will
play a role, the ultimate outcome to financing energy production will
be dominated by politically dictated policies.
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Table 8-5
CAPITAL INVESTMENT IN U.S. DOMESTIC ENERGY
INDUSTRY FOR TECHNICAL FIX SCENARIO
(EXCLUDING SYNTHETIC FUELS)
(Billions of 1973 Dollars)
1975 1980 1985 1990 1995 2000
Domestic petroleum and
natural gas production,
refining, excluding gas
pipelines
Electric utilities, includ-
ing nuclear facilities
Natural gas pipelines
Coal production, excluding
coal for synthetic
natural gas
Nuclear fuel production
Total
$13 $17 $21 $21
21
0
25
30
34
$22
38
$22
43
$41 $50 $59 $63 $69 $74
ENERGY'S SHARE OF TOTAL INVESTMENT
(Percent)*
Excluding synthetic fuels
Including synthetic fuels'
29 28 25 23 20 18
29 28 27 25 23 20
Note: Appendix B describes the methodology underlying the projections.
^Defined by dividing energy investment from the upper part of the table
by business fixed investment for the appropriate year from Table A-3.
tAnnual investment for the maximum credible scenario Table A-8 was added
to energy investment.
310
-------
D. Capital Availability in the Petroleum Industry
To assess the impact of synthetic fuels industry on capital markets,
the sources and uses of funds within the petroleum industry were calcu-
lated for the HG1 scenario with and without synthetic fuels. The analy-
sis was carried out to the year 2000, using the methodology of Hass, et
al.;8 the data and details of the financial relationships are presented
in Appendix C. Briefly, the industry assets are used to project the
internal sources of funds based on a rate of return after taxes and a
depreciation rate. The uses of funds are annual investment and dividends.
The annual investment data are shown in Table C-l. Assumptions made in
the calculations are as. follows:
1. The historical after-tax return applies to new investments as
well as existing investments.
2. Depreciation rates will approximate recent levels as a percent
of assets.
3. External funds will be available to maintain historical debt-
equity ratios.
4. Historical payout rates will be maintained.
The initial calculations were carried out using constant 1973 dol-
lars for investment and cash flow calculations. The cash flow for the
domestic petroleum industry are depicted in Figures 8-1 and 8-2 (see
Table C-2 for basic data) for no synthetic liquid fuels and with syn-
thetic liquid fuels. In both cases, after 1985 there are excess funds
available, which are assumed to be paid out in dividends. Prior to 1985,
*This assumes that federal energy policy concerning synthetic fuels will
both establish conditions making synthetic fuels as profitable as con-
ventional fuels and also mitigate business risks to the extent that a
rate of return on investment higher than conventional fuels would not
be justified.
311
-------
60 r-
co
M
to
50
en 40
-------
there is a shortage of internally generated funds shown by the shaded
gap between the sources and uses levels in the figures.
This constant dollar analysis implies no large impact of synthetic
fuels on capital markets since the petroleum industry generates more
cash than it needs. This occurs in spite of the low productivity of
assets employed. In 1973, total assets were $80 billion and output was
45 X 10 Btu;* according to the balance sheet figures as projected in
Appendix C, the productivity of assets diminishes as follows:
Total Assets Energy Output Productivity
1985 $247 billion 63 X 1015 Btu 0.25 X 10s Btu/$
2000 $417 82 X 1015 Btu 0.20 X 106 Btu/$
This implies that the assumptions of a constant rate of return on
assets is important, since lower productivity requires more assets which,
under constant return, generate more net income as well as more depreci-
ation funds. It is implicit in the rate of return assumption that the
petroleum companies are able to maintain prices at a level high enough
to generate a 10 percent return on total financing.
The analysis was extended to consider the future flow of funds
under inflation at 5 and 8 percent per year. The results show that
in an inflationary environment, borrowed funds are needed whether or not
synthetic fuels are assumed. Figures 8-3 to 8-6 show the necessary bor-
rowings in these cases. Under 8 percent inflation, the petroleum indus-
try with synthetic fuels must borrow $58 billion in 2000; however, this
*A quadrillion (1015) Btu is about 1018 J.
313
-------
200 r-
180
160
140
ir
d
Q
cr
cc
o
100
CO
o
m 80
o
_)
_i
co 60
40
ANNUAL INFLATION RATE: 5%
INVESTMENT
PLUS DIVIDENDS.
NFT INCOME AFTER
TAXES PLUS DEPRECIATION
3 NEW BORROWINGS REQUIRED
1975 1980 i985 1990 1995 20i~C
YEAR
FIGURE 8-3. PROJECTED CASH FLOW FOR DOMESTIC OIL
AND GAS INDUSTRY-NC SYNTHETIC LIQUID
FUELS-AT A FIVE PERCENT ANNUAL RATE
OF INFLATION
2CO.-
I8C
160
140
I2C
o:
I ICC
o
o
2 80
o
CD
ec
4C
20
ANNUAL INFLATION RATE: 5°/c
INVESTMENT
PLUS DIVIDENC S-
NETINCOME AFTER
TAXES PLUS DEPRECIATION
BORROWINGS REQUIRED
1975 i960 1985 I99C 1995 200C
YEAR
FIGURE 8-4. PROJECTED CASH FLOW FOR DOMESTIC OIL AND
GAS INDUSTRY - CONVENTIONAL ACTIVITIES
PLUS SYNTHETIC LIQUID FUELS-AT A FIVE
PERCENT ANNUAL RATE OF INFLATION
-------
400 r-
03
300
en
o
£200
tr
_
o
en
z
o
d
OD
100
400
ANNUAL INFLATION RATE: 8%
INVESTMENT
PLUS DIVIDENDS-
NET INCOME AFTER
TAXES PLUS
DEPRECIATION
NEW BORROWINGS REOUIRED
19/5
1980
1985
YEAR
1990
1995
2000
FIGURE 8-5. PROJECTED CASH FLOW FOR DOMESTIC ClL
AND GAS INDUSTRY-NO SYNTHETIC LIQUID
FUELS-AT AN EIGHT PERCENT ANNUAL
RATE OF INFLATION
300
">
ce
<
200
o
en
_
_J
CD
100
ANNUAL INFLATION RATE: 8%
INVESTMENT
PLUS DIVIDENDS'
NET INCOME AFTER
TAXES PLUS
DEPRECIATION
••ff/1 NEW BORROWINGS REQUIRED
1975
I960
1985
1990
1995
2000
YEAR
FIGURE 8-6. PROJECTED CASH FLOW FOR DOMESTIC OIL AND
GAS INDUSTRY-CONVENTIONAL ACTIVITIES
PLUS SYNTHETIC LIQUID FUELS-AT AN EI&HT
PERCENT ANNUAL RATE OF INFLATION
-------
is a small fraction of its total each flow of $315 billion in 2000 and
less than the dividend payout (see Table C-4).
The reason for the shortage of internal funds under inflation is
that depreciation of fixed assets is based on historical rather than
replacement cost. Consequently, cash flow from depreciation does not
generate sufficient cash to replace existing assets and to add to
assets as well.
E. Conclusions
The findings of this flow of funds analysis of the petroleum indus-
try demonstrate the importance of inflation rates and governmental policy
on industry cash flow. Fiscal policies that result in inflation prevent
depreciation credits from providing enough cash flow to actually replace
existing assets at the higher prices. As a result, industry must use a
portion of its after-tax income to maintain existing asset levels. Funds
for growth are thereby diminished and the need to attract funds from
external sources is increased. In the petroleum industry, funds for
growth have been hurt by recent changes in the tax laws affecting deple-
tion allowances and foreign tax credits.
The results of this chapter project faster growth for petroleum
industry investment than for total business fixed investment. In the
early 1970s the petroleum industry accounted for 7.5 to 9 percent of
total business fixed investment while our projections are that the per-
centage will double to 18 percent by 1995. There will be much compe-
tition from other sectors of the economy for capital that will work
against realizing such growth.
Within the energy industry itself, for example, electric utilities
will require vast amounts of new capital. Likewise, other basic indus-
tries need large amounts of capital for expansion, modernization and
316
-------
pollution control. Such needs will likely cause intense competition for
newly formed capital.
However, the projections of this chapter show the petroleum indus-
try able to provide internally for an increased fraction of its invest-
ment funds by the year 2000.* Our model (and assumptions) project that
in an 8 percent inflation economy, new borrowings by the petroleum indus-
try would fall from 31 percent down to 15 percent of cash flow by the
year 2000.
*The projections of this chapter are based partly on the assumption that
real GNP will grow at an average annual rate of 3.6 percent. This as-
sumption may be valid only if energy prices remain relatively cheap.
It was, unfortunately, beyond the scope of this effort to also attempt
to model the dependency of GNP on energy prices.
317
-------
Appendix A
PROJECTIONS OF GNP, AND SOURCES AND USES OF FUNDS
318
-------
Table A-l
GROSS NATIONAL PRODUCT—HISTORICAL AND PROJECTIONS TO 2000
(Billions of Dollars)
Historical
1967
1968
1969
1970
1971
1972
1973
1974
Average annual change
1967-1974
Current
Dollars
$
Constant
1973 Dollars
790
860
920
970
1,050
1,160
1,300
1,397
$1,060
1,100
1,130
1,130
1,160
1,220
1,300
1,267
8.5%
3.3%
Gross National
Product Deflator
1973 = 100
74.7
78.1
82.0
86.4
90.8
94.9
100.0
110.3
5.0%
Projections
1975
1980
1985
1990
1995
2000
1,480
2,340
3,560
5,420
8,270
12,590
1,220
1,590
1,890
2,260
2,700
3,220
121
147
188
240
306
391
Sources: Historical data. Constant 1973 dollars were obtained
from Survey of Current Business, Bureau of Economic
Analysis, Sept. 2974, p. 6, Table A; current dollars
are from Table 1, various issues. Deflators were de-
rived by dividing current dollars by 1973 constant
dollars.
Projections. Real GNP was projected at an annual
growth rate of 3.6 percent, taking off from 1974.
The deflators were projected at 5 percent annually
for the period 1975-2000. Current GNP was obtained
by multiplying real GNP by deflators.
319
-------
Table A-2
SOURCES OF FUNDS--HISTORICAL DATA AND PROJECTIONS TO 2000
(Billions of Current Dollars)
Historical
1967
1968
1969
1970
1971
1972
1973
Business
Savings*
$
93
97
97
97
110
126
137
Personal
Savings
$
40
38
38
55
61
53
74
Net Foreign
Investment
$
2.2
-0.3
-0.9
1.2
-2.1
-9.1
0.1
Projections
1975
1980
1985
1990
1995
2000
165
249
378
574
872
1,326
65
95
139
218
342
535
20
40
0
0
0
0
Cumulative 1975-2000
14,639
5,696
300
*Business savings is equivalent to the sura of undistrib-
uted corporate profits, corporate inventory valuation
adjustment, corporate and noncorporate capital consump-
tion allowances, and wage accruals less disbursements
in the Survey of Current Business.
• Business savings
Sources: Historical. Survey of Current Business, National
Income and Product Table 15, various issues.
Projections. The equation 3.5 + 0.105 (GNP) was
used to project business savings. (See Refer-
ence 3.)
(continued)
320
-------
Table A-2 (concluded)
• Personal savings
Sources: Historical. Survey of Current Business, National
Income and Product, Table 10, various issues.
Projections. Personal savings was projected using
a ratio of personal savings to GNP (on a sliding
scale of 0.0425-0.039 for 1975-1985 and 0.039-
0.0425 from 1985-2000). (See Reference 3.)
• Net foreign investment
Sources: Historical. Survey of Current Business, National
Income and Product, Table 12, various issues.
Projections. Net foreign investment (NFI), which
historically has fluctuated around zero, is as-
sumed to increase to $20 billion in 1975, to con-
tinue to grow, reaching a high of $40 billion in
1980, and then to fall to zero again by 1985. The
sharp rise in NFI expected over the 1975-85 period
is due to recycling of "petro-dollars." In 1975,
it is estimated that OPEC surplus revenues (i.e.,
the difference between oil exports and total im-
ports) will be about $65 billion. Currently,
about 31 percent of these funds are returning to
the United States. OPEC surplus revenues are
expected to increase to about $130 billion by
1980, and assuming the 31 percent share for the
United States persists, a NFI in 1980 of about
$40 billion results. NFI is anticipated to de-
cline steadily between 1980 and 1985 as the dol-
lar value of imports to OPEC countries gradually
overtakes the dollar value of oil exports. By
1985 it is assumed that the oil surplus will
disappear.
321
-------
Table A-3
BUSINESS FIXED INVESTMENT—HISTORICAL AND PROJECTIONS TO 2000
(Billions of Dollars)
Historical
Current
Dollars
Constant
1973 Dollars
1967
1968
1969
1970
1971
1972
1973
1974
Average annual change
1967-1973
$
88
89
99
101
106
117
137
149
$
106
110
116
113
111
121
137
136
4.3%
Business Fixed
Investment
Deflator
1973 = 100
78.5
81.1
85.0
89.7
95.1
96.3
100.0
109.4
4.1%
Projections
1975 167
1980 273
1985 446
1990 686
1995 1,055
2000 1,623
Cumulative 1975-2000 17,413
142
181
232
280
337
407
6,775
118
151
192
245
313
399
*Business fixed investment is equivalent to nonresidential
fixed investment in the Survey of Current Business.
Sources: Historical data. Survey of Current Business,
National Income and Product, Table 1 (various
issues) for current dollars; Table 16 for de-
flators. 1958 base year deflators were con-
verted to 1973 base year by dividing deflators
by the year 1973 deflator. Constant 1973 dollars
were obtained by dividing current dollars by the
deflators.
(continued)
322
-------
Table A-3 (concluded)
Projections. Current dollars were projected at an
annual growth rate of 10,3 percent for the period
1975-1985 and 9 percent from 1985-2000, Deflators
were projected using an average ratio (0,9588) of
business fixed investment deflators to GNP deflators
(1958 = 100) and converted to a 1973 base year. Con-
stant 1973 dollars were calculated by dividing cur-
rent dollars by the deflators.
323
-------
Table A-4
RESIDENTIAL CONSTRUCTION—HISTORICAL AND PROJECTIONS TO 2000
(Billions of Dollars)
Historical
Current
Dollars
1967
1968
1969
1970
1971
1972
1973
Average annual change
1967-1973
$
25
30
32
31
43
54
57
14.7%
Constant
1973 Dollars
$
36
40
40
39
51
60
57
8.3%
Residential
Construction
Deflator
1973 = 100
70.7
74.6
79.2
80.4
84.2
90.5
100.0
6.0%
Projections
1975 58
1980 88
1985 135
1990 205
1995 312
2000 475
Cumulative 1975-2000 5,223
53
63
76
90
108
±29
2,224
109
139
178
227
290
370
*Residential construction is equivalent to residential struc-
tures fixed investment in the Survey of Current Business.
Sources: Historical. Current dollars are from Survey of
Current Business, National Income and Product,
Table 1, various issues. Deflators (1958 = 100)
from Table 16 were converted to 1973 base year
and divided into current dollars to obtain con-
stant 1973 dollars.
(cont inued)
324
-------
Table A-4 (concluded)
Projections. Projections of constant prices were made
by taking an average ratio (0.0354) of residential
construction (1958 prices) to GNP (1958 prices) for
the years 1967-1973 and multiplying by real GNP pro-
jections for 1975-2000. Deflators were projected by
the same method (using average ratio of deflators)
and converted to a 1973 base year. Current dollars
were obtained by multiplying constant dollars by the
deflators.
325
-------
Table A-5
SELECTED USES OF FUNDS—HISTORICAL AND PROJECTIONS TO 2000
(Billions of Current Dollars)
Historical
1967
1968
1969
1970
1971
1972
1973
Inventory
Investment*
$ 7.4
7.3
8.5
4.9
3.6
8.5
15.4
Federal
Deficit
$12.7
5.2
-9.2 (surplus)
12.9
21.7
17.5
5.6
Credit Agency
Borrowing
$
8.2
7.7
8.6
9.5
State and
Local Borrowing^
$ 1.8
1.5
0.6
-2.8 (surplus)
-4.8 (surplus)
-12.3 (surplus)
-9.2 (surplus)
Projections
1975 12
1980 18
1985 27
1990 41
1995 63
2000 96
Cumulative 1975-2000 1,053
4
4
4
4
4
4
91
10
10
10
15
15
15
335
3
3
3
5
5
5
103
*Inventory investment is equivalent to change in business inventories in the Survey of
Current Business.
• Inventory investment
Sources: Historical. Survey of Current Business, National Income and Product,
Table 1, various issues.
Projections. Current dollars were projected by taking an average ratio
(0.0076) of inventory investment to GNP for the period 1967-1973 and
multiplying by projected GNP in current dollars.
• Federal deficit
Sources: Historical. Survey of Current Business, National Income and Product,
Table 13, various issues.
Projections. The federal deficit is assumed to average about $3.5 billion
per year over the 1975-2000 period the same as the average for the nonwar
years of 1954-1963. This projection was used in the New York Stock Exchange
study for the 1975-1985 period and is assumed to continue in the 1985-2000
period. It is important to recognize that the $3.5 billion annual deficit
projected for 1975 is only an average over the 1975-2000 period. The actual
deficit in 1975 may be anywhere between $50 and $80 billion because the
economy is current in a recession. However, part of the 1975 deficit is
expected to be offset in future years by a government surplus when the
economy is operating close to full employment again.
(continued)
326
-------
Table A-5 (concluded)
• Credit agency borrowing
Sources: Historical. Federal Reserve Bulletin, Total New Issues table under Federally
Sponsored Credit Agencies, various issues.
Projections. Credit agency borrowing is taken from the New York Stock Ex-
change study over the 1975-1985 period and extrapolated to year 2000.
• State and local borrowing
tState and local borrowing is equivalent to state and local surplus or deficit in the
Survey of Current Business.
Sources: Historical. Survey of Current Business, National Income and Product, Table 14,
various issues.
Projections. These projections are taken from the New York Stock Exchange
study for the 1975-1985 period and extrapolated to 2000.
327
-------
Appendix B
PROJECTIONS OF CAPITAL INVESTMENT
IN THE OIL AND GAS INDUSTRY
328
-------
Appendix B
PROJECTIONS OF CAPITAL INVESTMENT
IN THE OIL AND GAS INDUSTRY
The capital investments in the five categories of energy investment
shown in Table 8-3 were projected using the data through 1985 from Hass,
Stone and Mitchell in Financing the Energy Industry (FBI),8 and converted
into 1973 constant dollars using the deflator from Table A-3.
Table B-l
ENERGY INDUSTRY INVESTMENT FOR 1975, 1980,
AND 1985 FOR HG1
(Billions of Constant Dollars)
1970 Dollars 1973 Dollars
Energy Sector 1975 1980 1985 1975 1980 1985
Domestic petroleum and
natural gas production
and refining, exclud-
ing chemical plants $12.0 $17.0 $22.0 $13.4 $19.0 $24.5
Electric utilities, in-
cluding nuclear
capacity 18.6 26.8 37.6 20.7 29.9 41.9
Natural gas pipelines
and distribution 4.0 4.0 4.0 4.5 4.5 4.5
Coal production 1.5 1.5 1.5 1.7 1.7 1.7
Nuclear fuel production 0.0 1.4 1.4 0.0 1.6 1-6
Totals $36.1 $50.7 $60.5 $40.3 $56.7 $74.2
329
-------
To obtain investment in the domestic petroleum industry without
synthetic fuels, it was assumed that energy output per dollar invested
is identical for conventional petroleum and synthetic fuels.
The ratio of energy output from conventional oil and gas, and syn-
thetic gas from coal (including conversion losses) to energy output from
conventional oil and gas, and synthetic liquid fuels from coal and oil
shale from the HG1 scenario (Table B-2) was used to scale down the in-
vestment in conventional oil and gas plus synthetic from FEI to exclude
synthetic liquid fuels. It is assumed that the investment schedule from
FEI, Table 6-1, applied to the HG1 scenario shown in Table B-2. The
resulting investment in 1973 constant dollars under HG1 for the domestic
petroleum industry fuel is:
1975 $13.4 billion
1980 18.2
1985 23.0
These projections are used for the HG1 projections through 1985
shown in Table 8-3. The investment requirements for HG1 through 2000
and the investment requirement for HG2 and HG3 shown in Table 8-3 and
for TF1 shown in Table 8-5 are generated by scaling the HG1 investment.
First, HG1 is extended to 2000 based on the ratio of energy output in
1990, 1995, and 2000 to energy output for 1985. For other scenarios,
the HG1 investment figure was scaled using the ratio of energy output
relative to the HG1 energy output for the same category and year.
Table B-2 shows the energy outputs from the various energy investment
categories which are used for the scaling. Table B-3 gives the annual
investment requirements for the maximum credible implementation scenario.
330
-------
Table B-2
ENERGY SUPPLY SCENARIOS
(Quadrillion Btu)*
CO
u
Domestic Oil and Gas
Domestic oil (no synthetics)
Domestic gas
Synthetic gas from coal
Conversion losses, coal to
synthetic gas
Total domestic gas and oil^
Natural Gas for Distribution
Domestic gas
Synthetic gas
Imported gas
Total gas consumption^
Nuclear fuel produced*
Coal production''' (excluding
use for liquid synthetics)
Energy input to electricity
generation*
Actual
1973
22
23
0
0
45
23
0
1
HG1
1985
32
29
1
0.5
63
29
1
1
2000
40
37
3
1.5
82
37
3
0
HG2 HG3 TF1
1985
32
29
1
0.5
63
29
1
1
2000
34
31
3
2
70
31
3
2
1985
27
26
1
0
54
26
1
4
2000
27
27
3
1.5
59
22
3
5
1985
30
27
0
0
57
27
0
1
2000
36
32
1
1
60
32
1
0
24
1
13
21
31
10
25
41
40
40
33
85
31
12
23
41
36
50
33
85
31
10
20
41
35
40
38
85
28
8
16
29
33
11
22
42
*Note a quadrillion (101S) Btu is about 1018 J.
tReference 1, Tables 3 and 13.
iReference 1, Tables F-2, F-3.
-------
Table B-3
INVESTMENT REQUIREMENTS FOR SYNTHETIC FUELS UNDER THE
MAXIMUM CREDIBLE IMPLEMENTATION SCENARIO
Billions of
Year 1973 Dollars
1975 $0.0
1980 0.7
1985 2.6
1990 5.6
1995 7.2
2000 9.0
332
-------
Appendix C
PROJECTIONS OF CASH FLOW FOR
THE PETROLEUM AND GAS INDUSTRY
333
-------
Appendix C
PROJECTIONS OF CASH FLOW FOR
THE PETROLEUM AND GAS INDUSTRY
The following gives financial accounting relationships used to de-
rive cash flow for the petroleum and gas industry, summarized from Hass,
Stone and Mitchell,8 Appendix B and Table 3-4.
Assets
TA(t) = TA(t-l) + ACA(t) + AOA(t) + INV(t) - DEP(t)
where
t = year
TA(t) = total assets in year t.
ACA(t) = change in cash assets (CA(t)) from the previous year.
AOA(t) = change in other assets (OA(t)) from the previous year.
INV(t) = investment in year t.
DEP(t) = depreciation on total assets in year t.
and
CA(t) = a TA(t) a =0.32
DEP(t) = d TA(t-l) d = 0.064
OA(t) =
-------
The base year taken was 1973, and total assets were derived from
total fixed assets given by Reference 4, excluding chemical plants and
pipelines, of $48.3 billion. The total assets for 1973 are therefore
$80 billion.
Total Financing
TF(t), total financing, is defined as
TF(t) = TA(t) - CL(t) - OL(t)
where
and
then
Cash Flow
where
CL(t) = current liabilities in year t.
OL(t) = other liabilities in year t.
CL(t) = c TA(t) , c = 0.20
OL(t) = Q, TA(t) , a = 0-24
TF(t) = (1-c-oO TA(t)
= 0.56 TA(t)
Sources (cash flow in) = uses (cash flow out)
Cash flow in = NIAT(t) + DEP(t) + net new borrowings
NIAT(t) = net income after taxes
New borrowings = net new debt financing issued
plus new equity financing (all
common stock-assuming no pre-
ferred stock).
NIAT(t) =0.10 TF(t)
assuming a 10% rate of return after
taxes on total financing
335
-------
DEP(t) = 0.064 TA(t-l)
Cash flow out = INV(t) + DIV(t)
INV(t) = annual investment
DIV(t) = dividend payments on common shareholder
equity
DIV(t) = PO • ECS(t)
PO = dividend payout rate
= 0.50
ECS(t) = equity share of the total financing
= 0.10 TF(t) - 0.08 DEBT(t)
DEBT = total debt financing in year t.
= 0.04 TF(t) (assumes a constant debt/equity
ratio) .
336
-------
Table C-l
ANNUAL INVESTMENT SCHEDULE FOR HG1
(Billions of 1973 Dollars)
HG1 HG1
Year (no synthetic liquid fuels) (with MCIS synthetic fuels)
1973
74
1975
76
77
78
79
1980
81
82
83
84
1985
86
87
88
89
1990
91
92
93
94
1995
96
97
98
99
20OO
$ 9.8
12.0
13.0
14.0
15.0
16.0
17.0
18.0
19.0
20.0
21.0
22.0
23.0
23.4
23.8
24.2
24.6
25.0
25.6
26.2
26.8
27.4
28.0
28.4
28.8
29.2
29.6
30.0
$ 9.8
12.0
13.0
14.2
15.3
16.5
17.6
18.7
20.1
21.5
22.8
24.2
25.6
26.6
27.6
28.6
29.8
30.6
31.4
32.4
33,4
34.3
35.2
36.0
36.7
37.5
38.2
39.0
Sources: Table 8-3 and Table 6-8 (in Chapter 6).
337
-------
Table C-2
HG1 CASH FLOW—NO INFLATION
(Billions of 1973 Dollars)
Cash Flow In
Cash Flow Out
Year
1975
1980
1985
1990
1995
2000
With
1975
1980
1985
1990
1995
2000
NIAT(t)
$ 5.9
9.6
13.8
17.5
20.6
23.4
Maximum
5.9
9.9
14.7
19.7
24.4
28.8
DEP(t)
$ 5.9
10.1
14.8
19.2
22.8
26.1
Credible
5.9
10.3
15,6
21.4
26.9
32.0
New
Borrowings INV(t)
No Synthetic Fuels
$3.6 $13
2.1 18
23
25
28
30
Implementation Scenario
3.6 13
2.5 18.7
1.2 25.6
30.6
35.2
39.0
DIV(t)
$ 2.4
3.8
5.5
7.0
8.2
9.3
Synthetic
2.4
4.0
5.9
7.9
9.8
11.5
Excess
Funds
$ 0.1
4.7
7.2
10.2
Fuels
2.6
6.3
10.3
338
-------
Table C-3
HG1 CASH FLOW—5 PERCENT ANNUAL INFLATION
(Billions of Current Dollars)
Cash Flow In
Cash Flow Out
rear NIAT(t)
1975
1980
1985
1990
1995
2000
With
1975
1980
1985
1990
1995
2000
$ 6.0
11.6
20.3
31.6
46.3
65.8
Maximum
6.0
11.9
21.7
36.1
55.8
82.4
DEP(t)
No
$ 6.0
11.7
20.9
33.3
49.1
70.3
Credible
6.0
11.9
22.1
37.5
58.7
87.4
New Borrowings
Synthetic Fuels
$ 4.7
6.6
8.2
5.0
5.0
2.2
Implementation Scenario
4.7
7.3
10.9
10.9
10.8
9.2
INV
$14.3
25.3
41.3
57.3
81.9
112
Synthetic
14.3
26.3
46.0
70.1
103.0
146.0
DIV
$ 2.4
4.6
8.1
12.6
18.5
26.3
Fuels
2.4
4.8
8.7
14.4
22.3
33.0
339
-------
1'abiL- C-4
HG1 CASH FLOW—8 PERCENT ANNUAL INFLATION
(Billions of Current Dollars)
Cash Flow In
Cash Flow Out
Year
1975
1980
1985
1990
1995
2000
With
1975
1980
1985
1990
1995
2000
NIAT(t)
$ 6.1
13.0
25.7
45.4
76.0
123.4
Maximum
6.1
13.3
28.0
52.2
92.2
155.4
DEP(t)
No
$ 6.0
12.9
25.8
46.7
78.5
128.3
New Borrowings
Synthetic Fuels
$ 5.5
10.1
16.7
18.6
28.1
37.7
Credible Implementation Scenario
6.0
13.1
27.5
52.9
94.3
160.4
5.5
10.9
20.0
28.8
41.8
57.9
INV
$ 15.2
30.8
57.9
92.5
152.2
240
Synthetic
15.2
32.0
64.5
113
191.4
311.5
DIV
$ 2.4
5.2
10.3
18.2
30.4
49.4
Fuels
2.4
5.3
11.0
20.9
36.9
62.2
340
-------
REFERENCES
1. A Time to Choose: America's Energy Future, the Energy Policy Project
of the Ford Foundation, Ballinger Publishing Co., Cambridge, Mass.
(1974) .
2. "Energy Financing: The Outlook for Banking," Economic Research and
Planning Division, Irving Trust Co. (undated).
3. "The Capital Needs and Savings Potential of the U.S. Economy, Projec-
tions through 1985," New York Stock Exchange, Inc. (September 1974).
4. R. S. Dobias, et al. , Capital Investments of World Petroleum Indus-
try, The Chase Manhattan Bank (December 1974).
5. E. T. Palmer, "The Outlook for U.S. Capital Markets, Remarks," paper
presented before the International Financial Conference, London
(September 10, 1974).
6. Survey of Current Business, Dept. of Commerce, various issues.
7. R. C. Sparling, et al., Annual Financial Analysis of a Group of
Petroleum Companies, The Chase Manhattan Bank (August 1973).
8. J. E. Hass, E. J. Mitchell, B. K. Stone, Financing the Energy Indus-
try, Ballinger Publishing Co., Cambridge, Mass. (1974).
341
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9—MARKET PENETRATION OF SYNTHETIC LIQUID FUELS-
THE KEY ROLE OF THE DECISIGN-MAKING
PROCESS LEADING TO DEPLOYMENT
By Edward M. Dickson
A. Introduction
For most new product offerings, the manufacturer is properly con-
cerned with obtaining an estimate of the share of the market that his
new product may capture. It would seem appropriate, therefore, to ask
what fraction of the consumer market gasoline produced from oil shale,
for example, might ultimately capture. However, discussions with energy
industry experts* and stakeholders* have revealed that the question of
market penetration of the final consumer product is less fundamental to
the impact study than is the question of how and why decisions to deploy
synthetic liquid fuel production technologies will be made.
B. Synthetic Liquid Fuels and the Natural Petroleum System
The nature of the synthetic fuel production processes and of the
existing fuel production and distribution infrastructure with which
synthetic fuels must mesh is at the root of this. Figure 9-1 shows a
simplified block representation of a synthetic fuels production process
and Figure 9-2 shows a simplified representation of the existing auto-
motive fuels production system. Two markets are involved in both cases:
*Exxon Research and Engineering and Stanford Research Institute.
tAtlantic Richfield, Shell Oil, Carter Oil (a subsidiary of Exxon),
Texaco, and Chase Manhattan Bank.
342
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COAL OR
OIL SHALE
MINE
CONVERSION OF ORE
TO A SYNTHETIC
CRUDE OIL
REFINING SYNTHETIC
CRUDE INTO
CONSUMER PRODUCTS
SUCH AS GASOLINE
FIGURE 9-1. SYNTHETIC LIQUID FUELS PRODUCTION SYSTEM
CRUDE OIL
(ONE SOURCE)
CRUDE OIL
(SECOND SOURCE)
CRUDE OIL
(OTHER SOURCES)
REFINING OF
CRUDE OIL TO A MIX
OF CONSUMER
PRODUCTS
GASOLINE
JET FUEL
(KEROSENE)
FUEL OIL
OTHER
PETROLEUM
PRODUCTS
FIGURE 9-2. NATURAL PETROLEUM PRODUCTS PRODUCTION SYSTEM
crude oils and refined products. The synthetic fuels and natural petrol-
eum fuels systems could be joined or could compete at either of the two
points.
If the two systems were to join in the market for refined products,
there could be two alternative market forms (not mutually exclusive):
(1) The synthetic gasoline could be sold separately through a
distinct distribution system in direct competition with
conventional gasoline.
343
-------
(2) The synthetic and conventional gasolines could be mixed
together to be marketed and sold through the existing
distribution system.
Both alternatives allow the possibility of either new or established cor-
porate entities, with no previous association with the automotive fuels
market, making and selling synthetic gasoline. The first alternative
would require creation of a new marketing network and competitive pric-
ing of the product. Since it is expected that synthetic gasoline cannot
be made as cheaply as conventional gasoline,1 this market will be diffi-
cult to enter competitively. The second alternative avoids the estab-
lishment of a new network and expenditures on advertising, and allows
the product to be sold at the average price of all the inputs that are
blended together, rather than at the actual marginal price of the syn-
thetic gasoline. Of course, if the synthetic gasoline were to cost more
to produce than the conventional gasoline, there would be little enthu-
siasm for using this cost averaging mechanism to create a market for
synthetic gasoline. Nevertheless, provided that synthetic gasoline did
not cost too much more than conventional gasoline and that it was not
too large a share of the total product to be marketed, the second alter-
native would offer this "roll-in" mechanism that could be employed if a
fallback proved necessary because of a poor business decision. However,
if the synthetic gasoline were produced by organizations outside the
existing natural petroleum based industry, such synthetic gasoline would
have to wholesale competitively with conventional gasoline before exist-
ing oil companies could be expected to purchase it and absorb it in their
existing marketing system.
The first alternative, the competitive approach of a fully inte-
grated synthetic fuel company, is clearly the more risky course and
because of the very strong position of existing oil companies in the
automotive fuels marketplace there has been apparently no serious
344
-------
contemplation of this approach of potential corporate producers outside
this existing industry. Indeed, for excellent reasons that are rooted
in the chemical engineering of the processes, even the second alterna-
tive, the consumer product blending approach, has not been taken seri-
ously even by those corporations expressing interest in synthetic
liquid fuels.
The product mix shown as a single refinery output in Figure 9-2
results not simply from the consumer demand for diverse products, but
also from the nature of crude oil and the chemistry and engineering
associated with its processing. Crude oil consists of a mixture of
hydrocarbon molecules that cover a wide range of physical and chemical
properties. The first step in refining is the distillation of the oil
into its various components (fractions). Some of these are processed
fairly directly into consumer products while other components that are
present in quantities that exceed their market demand are chemically
altered into products that are in more demand. Although it would be
possible to convert crude oil entirely into a gasoline product, this
would entail so much chemical reforming that it would be economically
prohibitive as well as costly in terms of process energy (largely sup-
plied from the petroleum stream itself). Consequently, it is standard
practice to design modern, large refineries so that they can be tuned
to yield an optimal product mix for any (sensible) blend of crude inputs.*
Because it is standard for refineries to accept and utilize a blend
of crude inputs and the natural intermediate output of a synthetic liquid
fuels plant is a synthetic crude oil rather than refined product, the
*Such as a large chemical company.
tSome old, small refineries do, however, accept crude from a single
field. These represent an historical artifact.
345
-------
the corporate interests and governmental research elements involved in
synthetic liquid fuels development have emphasized joining the synthetic
liquid fuels and the existing fuels system at the synthetic crude node
rather than at the synthetic consumer product node. The natural indus-
try approach to synthetic liquid fuels is to produce a synthetic crude
and to add that product to the pool of all available crudes. Thus, the
key market is not the consumer market but is the intra-industry market
for crude oil.
Once this mixture occurs, of course, it is extremely unlikely that,
on an atom-to-atom basis, the carbon derived from either the fossil coal
or oil shale deposits would actually all be consumed in the form of
automotive fuel. Instead, as in a game of musical chairs, a carbon atom
previously destined to become fuel oil might end up as kerosene, while
an atom previously headed for kerosene might end up as gasoline, and the
atom from the coal or oil shale might end up as fuel oil. Thus, whether
the coal or oil shale is made straight into gasoline or into a syncrude
that is blended with natural crudes, the net result is the same: Devel-
opment of coal or oil shale resources has resulted in gasoline being
made available. In either event, the consumer would be no more aware
that any given purchase of gasoline came from coal or oil shale than he
is now aware whether his gasoline came from domestic or foreign crude,
or from a particular oil field.
Depiction of the series of synthetic fuels product events as a
single chain from coal to gasoline is a useful heuristic device to dem-
onstrate that coal or oil shale could provide energy for automotive uses,
but this device does not reflect reality adequately to serve as a basis
for impact analysis. Through discussion with people well informed about
the petroleum industry and with energy industry stakeholders, the SRI
study team has verified that the key element is the process by which
decisions will be made to produce synthetic crudes. Once these decisions
346
-------
are made, synthetic crude will become available for blending into the
pool of total crude and this, in turn, will facilitate the production of
automotive fuels. A key element in the decision to deploy synthetic
liquid fuels technology will be the decision maker's perception of the
risks of synthetic crude production compared with his perception of the
risks of alternative investments in conventional crude exploration and
production. Moreover, both of these alternatives will be compared to
investment opportunities outside the fuels arena.
The petroleum business is inherently very complex, but myriad gov-
ernmental regulations make it even more complex. Nevertheless, the
analysis below captures the essential features, although not the nuances,
of the decision-making process concerning synthetic liquid fuels. Cor-
porate stakeholders have verified that the major thrust of the descrip-
tion is correct.
C, Common Misconceptions About the Petroleum Industry
Before the decision-making process can be discussed properly, it is
essential to dispose of some commonly held misconceptions about the oil
industry.
First, there is no single price for crude oil. There are many
sources of crude oil, each possessing different chemical and physical
properties—some more highly valued than others. For example, some oils
are rich in the less viscous hydrocarbons and are called "light," while
others are rich in more viscous hydrocarbons (such as asphalt or bitumen)
and are termed "heavy;" some oils have low sulfur content (less than 1
percent) and are called "sweet," while others with higher sulfur content
are called "sour." In general, American refiners prefer the light,
sweet crudes because these can most easily and economically be used to
produce the mix of products desired by American consumers; their use
347
-------
also permits environmental standards to be met most readily. Conse-
quently, there are price differentials for crude oils of different qual-
ities; at the extreme, these variations approach $2 per barrel ($12/m3).
The common practice of referring to the market price of crude oil is
merely a shorthand for speaking of a representative price of a major
crude oil or of the government controlled price of domestic crude.
Second, there is no single cost of producting natural crude oil.
Since there are many wells (some 500,000 in the United States at the end
of 1973) in many different fields at different stages of depletion, pro-
ducing oils of many different qualities, recovery costs are highly vari-
able. Some fields are self-pressured and the oil flows to the surface
naturally, while some wells require pumping. Wells that produce less
than 10 B/D (1.6 m3/D) are termed "stripper wells." In 1973, nearly
14,000 stripper wells became uneconomic to operate and were closed down;
the size of this number shows that many stripper wells are on the verge
of being phased out at any given time. Many wells are very old but still
producing; for these, the exploration and development costs have been
fully written off long ago so only operating costs are now pertinent.
Clearly, therefore, the costs of producing crude oil vary widely, and
thus so does oil well profitability.
Third, the market for crude oil is far from a "free market," owing
to the cartel of the Organization of Petroleum Exporting Countries (OPEC)
and complicated federal government price controls.1 For example, "old"
oil comes both from new wells and from increased production from old
*The raw oil shale and coal syncrudes can be upgraded to superb quality
(sweet and light) and, therefore, could command a premium price over
most natural crudes.
348
-------
wells, and can be sold at whatever the market will bear. There is also
"released oil, that is, old oil that has been reclassified as new in
accord with a government exploration incentive that allows reclassifica-
tion of one barrel of old oil for each barrel of new oil produced.
Stripper wells are exempt from the "old" classification. The complex
price structure is further complicated by an "entitlements" program by
which the federal government guarantees to all refiners the equivalent
of an equal percentage access to low price old oil. Companies with
ownership or contract rights to old oil in excess of the industry aver-
age must purchase entitlements from companies with less old oil than the
average. By this strategem, the government seeks to spread the blow of
the suddenly higher cost of imported oil over all petroleum companies.
These governmental interventions were temporary expedients stimulated
by the Arab oil embargo; they are subject to change at any time.
D. Example of the Decision-Making Process
The recent rise in world oil prices caused by the strong position
of the OPEC cartel is an excellent example of the decision-making proc-
ess concerning synthetic crude. The description that follows is simpli-
fied; in particular, the extreme complications caused by U.S. oil price
regulations and the entitlements program are suppressed in the interest
of providing a readily intelligible picture of the decision-making
process.
Figure 9-3 is a snapshot in time that shows a hypothetical" curve
depicting the spectrum of natural crude oil production costs, relative
*Relative to the pertinent monthly reference period in 1972 for each pro-
ducing property.
tThe shape of the curve and the breadth do not represent actual data.
Such data is proprietary to the producer and therefore not available to
this study.
349
-------
EXPECTATIONS
LESS LOW-COST
CONVENTIONAL
CRUDES
LOWER COST SYNCRUOE
PERTINENT COSTS
EXPECTATIONS
• LESS LOW-COST CRUDE
• SLIGHT CRUDE PRICE RISE
TO PI BECAUSE OF HIGHER
PRODUCTION COSTS
• PRODUCTION Of SOME
CRUDES PREVIOUSLY
UNPROFITABLE
• DECREASE IN SYNCRUOE COST
OWINS TO "DEBOTTLENECKINQ"
THE PLANT
FIGURE 9-3. EARLY 1973 PERCEPTION OF A
HYPOTHETICAL SYNCRUDE PLANT
BEGINNING TO PRODUCE IN 1973
FIGURE 9-4. EARLY 1973 PERCEPTION OF A
SYNCRUDE PLANT BROUGHT ON
STREAM IN 1980
FIGURE 9-5. EARLY 1973 PERCEPTION OF THE
1985 STATUS OF A SYNCRUDE PLANT
BROUGHT ON STREAM IN 1980
W
Ul
O
EXPECTATIONS
• SYNCRUDE PLANT NOW
ECONOMIC
• PREVIOUSLY UNECONOMIC
CONVENTIONAL CRUDES
ATTRACTIVE
OPEC PRICE RISE
FIGURE 9-6. LATE 1973 PERCEPTION OF THE
HYPOTHETICAL SYNCRUDE PLANT
PRODUCING IN 1973
EXPECTATIONS
PRICE ft DECLINES
SOMEWHAT TO Pj
SVNCRUDE COSTS RISE
SOWEWHAT
SVNCRUDE ONLY
MARGINALLY PROFITABLE
PREVIOUSLY UNPROFITABLE
CONVENTIONAL CRUDES STILL
NEWLY PROFITABLE
• PRICE DECLINES TO P, ,
MARKEDLY LOWER THAN Ps
BUT STILL ABOVE PO
• MANY NEW CONVENTIONAL
CRUDES IN PRODUCTION
• RE-EVALUATED COSTS OF
SYNCRUDE HIGHER THAN P,
MAKING IT UNPROFITABLE
FIGURE 9-7. MID-1974 PERCEPTION OF A HYPOTHETICAL
1974 SYNCRUDE PLANT. AFTER
EXAMINATION OF INVESTMENT COSTS
FIGURE 9-8. LATE 1974-EARLY 1975 PERCEPTION
OF SYNCRUDE PLANT ON STREAM
IN I960
-------
to the average market price, Po, for crude oil. The portion just to the
left of Po is largely composed of stripper wells. Whenever the pertinent
costs of a particular well rise above Po , that well is shut down. During
the lifetime of a well, or ensemble of wells, producing from a particular
field, the tendency is for the costs to be at the leftward end of the
spectrum when the well or field is young and progressively shift to the
right as production rate declines with increasing depletion until finally
the wells enter the category of stripper wells. Figure 9-3 also shows
how a hypothetical, newly producing commercial-scale syncrude plant would
have looked to a decision maker in early 1973. At that time there was
no actual producing syncrude plant, but if there had been, it would have
represented the technology at 1965, when its design would have begun.
In early 1973, the best estimates for the syncrude plant showed that pro-
duction would cost considerably more than the going crude oil market
price, and, hence, the plant would have lost money. In 1973, then, it
was apparent that petroleum companies had made the correct decision years
earlier when they chose not to build syncrude plants.
Figure 9-4 shows how, in early 1973, the same decision maker would
have perceived a syncrude project begun that year but not scheduled to
produce crude until 1980. Thus, the curves represent his perception of
the state of affairs that would pertain in 1980. First, the conventional
crude production spectrum would have narrowed somewhat as the easier-to-
find-and-produce conventional crudes were depleted, thereby eliminating
the lowest cost crudes (at the farthest left portion of the production
spectrum). The price, Po, was left essentially unchanged, because the
weight of the historical evidence favored basically a stable price ex-
pectation for crude oil. Although the production cost for syncrude is
shown to be slightly lower than in Figure 9-3 (because there would have
been some improvement in technology), the costs were still expected to
351
-------
exceed the market price in 1980; consequently, in early 1973 the deci-
sion still would have been not to build a syncrude plant.
Figure 9-5 represents the same decision maker's perception of 1985—
still from his vantage point in 1973. All the trends described for Fig-
ure 9-4 continued and this led to an expectation that there might be a
slight price increase in crude (to P ), reflecting the increased diffi-
culty of providing the supply. Nevertheless, a syncrude plant scheduled
to begin production in 1985 still looked like a poor investment.
Then, however, OPEC initiated a series of stunning price increases
for crude oil, which opened an unprecedented gap between the then-
operational production spectrum and the new crude oil market price, PS.
This event is shown in Figure 9-6, which shows that from a late 1973
vantage point it suddenly looked as if the hypothetical syncrude plant
of Figure 9-3 (producing in 1973) would then be profitable if only it
had been built. The sudden price increase, however, also meant that
many conventional crude production possibilities, which had previously
been unprofitable, would now also be profitable if only they were in
operation. In fact, any activity and activities in the range of produc-
tion costs between Po and P_ now could be taken seriously as profitable
investment opportunities. Thus, during the initial period following the
OPEC price rises, the price rise stimulated interest in many new sources
of crude oil—including synthetics and advanced recovery techniques from
old fields.
Often, alternatives that seem very unattractive after only a coarse
analysis are set aside without performing a more costly, more refined
analysis. This was largely true of the analysis of synthetic crude
plants. As shown in Figure 9-7, between late 1973 and mid-1974, when
the possible syncrude investment option was examined more closely, cost
estimates were revised upwards, and once again it appeared that a syncrude
352
-------
investment would be only marginally profitable. This conclusion was
enhanced by the prospect that the OPEC price would not hold at P2 and
would shift downward somewhat, to at least P3. Thus, within the spec-
trum of new options lying in the range Po to P3 , syncrude seemed to be
one of the costlier crudes to produce and therefore one of the least
profitable. Moreover, there seemed to be many conventional crude ex-
ploration and production opportunities that could still be undertaken
that would be more profitable than production of syncrude. Indeed, even
some previously shut down stripper wells could justifiably be returned
to operational status. Moreover, many difficult conventional crude
production activities such as deep offshore, arctic offshore, and ter-
tiary recovery might all prove profitable.
By late 1974 and early 1975, reevaluation of the expectations of
the future and the costs of options had improved further. Figure 9-8
indicates how the same decision maker generally thought the situation
would appear in 1980. First, the syncrude plant was found to produce
an even (slightly) more costly product than last thought, and conviction
that the OPEC price would fall to P4 grew stronger. Thus, once again,
syncrude looked like it would lose money. In addition, the conviction
that much more conventional crude could be produced at costs between Po
to P4 led to rekindled interest in extensions of the conventional ap-
proach to oil production and away from the temporary, but heady, enthu-
siasm for syncrudes. Important to this rekindled interest was the fact
that the decision maker felt more comfortable with the historical con-
ventional approach than he did with the syncrude approach to obtaining
his supplies of crude.
It must be emphasized that the above analysis concerns commercial
scale plants, not demonstration or pilot plants, and not research and
development activities. All of these activities are in progress and
will continue in spite of unfavorable expectations for commercial plants,
353
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Indeed, there may be so much publicity given to pilot or demonstration
plants built to further the research and development efforts that the
public could easily leap to the premature conclusion that the day of
synthetic fuels had dawned. The tempo of research and development ac-
tivity will, of course, be modulated by the decision maker's expecta-
tion of when synthetic fuels will be competitive with future alternatives.
E. Comparison of the Risks
Besides a straightforward (although difficult to calculate) compari-
son of the relative profitability of alternative ways to gain new crude
supplies based on the pertinent costs of production and market price,
other factors enter into the decision-making process. Foremost among
these is the risk involved.
Building a synthetic crude plant, although it requires much capital
and complex engineering, carries very little risk concerning the ultimate
existence of the product. In that respect the risk is very much like an
oil refinery or a chemical plant where the major risk is the likelihood
of a misestimate of the cost of the feedstock and of making the product,
not the actual existence of the product. Thus, a synthetic crude plant
very much resembles many other manufacturing type activities. Basically,
there is a single decision to "go ahead" and there are no major inter-
mediate decision exit points between the start and the finish.
Exploring and developing oil resources, by contrast, involves risks
of a completely different nature, and there are several crucial inter-
mediate decision exit points between the initial exploration go-ahead
and the actual production of oil. First, there are geological explora-
tions to determine formations likely to contain commercially significant
accumulations of oil and gas. Second, based on these geological data,
there are decisions to be made about whether and where to drill. Third,
354
-------
based on the findings of the exploration wells, there are decisions to
be made about whether the discoveries (if any) are sufficiently large to
justify drilling of production wells. At each decision-making juncture
there are risks associated with proceeding to the next juncture, but it
is important that there be a series of exit points should the project
begin to look unfavorable.
The salient feature of the synthetic crude plant risk* is the un-
certainty in production costs, while the major risk* in oil exploration
investments is the actual presence of the oil. As conventional produc-
tion shifts increasingly to offshore areas and distant, unfamiliar, hos-
tile environments (e.g., Alaska, or deep waters of the outer continental
shelf), experience on which decision makers can base their estimates of
the inherent risks diminishes. Ultimately, rational investors will
decide that the risks of oil exploration exceed the risks of synthetic
fuels production—but today there is much disagreement over when syn-
thetic fuels will become commercially competitive.
In a very real sense, the world has just embarked on an oil explo-
ration experiment. Never before has there been such a large sudden jump
in the market price of crude oil. As a result, there is no historical
experience to show how much additional oil can really be located and
produced under the stimulus of such an incentive. By 1980 the indica-
tions will be strong and by 1985 the results of this experiment will be
*The comparison of risks on just the basis of crude production is incom-
plete because much of the natural gas used in the United States is found
associated with oil, thus there is a byproduct credit involved; simi-
larly synthetic crude plants also produce byproducts with value such as
gas (which may however be consumed internally to power the plant), sul-
fur, and ammonia.
355
-------
known. The success rate of finding and producing new oil will have a
profound effect on decision makers concerned with synthetic crude be-
cause, as shown in Figures 9-3 to 9-8, their perception of the future
of conventional petroleum strongly affects their perception of the need
and profitability of synthetic fuels.
Besides risks associated with the nature of the fuel production
methods themselves, there are substantial uncertainties about the in-
stitutional setting. In particular, corporate interests in the petrol-
eum business translate uncertainties about governmental policies into
risks. Examples of uncertainties affecting the decision-making process
and the sphere of influence include:
Federal Government
• Domestic and international actions to establish a stable
crude oil market price.
• Future domestic oil price regulations.
• Environmental regulations on extraction of coal by strip
mining, oil shale refuse disposal, and production of oil
from offshore leases.
• Resource leasing policies.
• Environmental restrictions that affect direct burning of
coal and oil (mainly control of sulfur compound emissions).
• Policies concerning the degree of energy independence to
be achieved.
• Policies affecting the development of alternative energy
technologies.*
*Since oil is the "swing fuel," or the one that has historically taken
up the slack in the availability of other energy forms, the role of oil
is especially sensitive to the total national energy mix, or interfuel
balance.
356
-------
• Rate of inflation.*
• Stability of governmental policies and regulations,
State Governments
• Growth policies.
• Water allocation policies in the energy resource-rich
portion of the West.
• Environmental restrictions on development.
• Stability of state policies.
Foreign Governments
• Stability of foreign ownership rights, export policies,
and taxes. -
• OPEC price-setting actions.
Perhaps the most crucial risk element—recurring over and over
again in discussions with synthetic fuels corporate stakeholders—was
the one of stability of governmental policies.3 When there is expecta-
tion that policies will be stable, even when the policies are unfavor-
able to the stakeholder and greatly restrict their freedom of action,
there is a feeling that the investment decisions can be made with a
tolerable degree of risk.
*Rapid inflation increases risks of investment in capital intensive
projects for several reasons: First, the continual escalation of costs
during construction diminishes the purchasing power of the initial fi-
nancing. Second, because depreciation is based on the initial (book)
value of the plant but the depreciation tax deductions are always in
current dollars, the capital actually recovered fails to meet the true
replacement costs.
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F. Comparison of Economic Risk
The investment in synthetic crude oil plants is very large—of the
order of $0.5 to 1 billion (in 1973 dollars) for a production of 100,000
B/D (16,000 m3/D). The size of this investment can be compared to the
net worth of the corporations that might make the investment and the
size of alternative crude production investments.
Data obtained from a standard financial reference4 concerning oil
company assets are shown in Table 9-1. A decision to invest $0.5 to 1
billion in a synthetic crude plant is a very grave event for even the
largest companies. For example, such an investment would amount to
some 4 to 7 percent of Exxon's net worth in 1973, and 25 to 50 percent
of Phillips' net worth in 1973. To contemplate having such a large
fraction of their shareholders equity riding on such a risky single
project is especially sobering to the smaller companies, and not taken
lightly by the large ones either.
Table 9-1
ASSETS OF SELECTED MAJOR OIL COMPANIES, DEC. 31, 1973
(Billions of Dollars)
Company Gross Assets Net Worth
Exxon 25.1 13.7
Gulf 10.1 5.6
Mobil 10.7 5.7
Phillips 3.6 2.0
Shell 5.4 3.1
Standard of California 9.1 5.8
Standard of Indiana 7.0 4.1
Standard of Ohio 2.0 1.1
Sun Oil 3.4 1.9
Texaco 13.6 8.0
Atlantic Richfield 5.1 3.1
Source: Reference 4.
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By contrast, the investment in individual exploration and develop-
ment projects for conventional crude oil, although considerable, is not
as large. Moreover, the step-by-step decision process allows several
exit points. For example, a 3-company consortium obtained offshore
drilling rights in 6 contiguous tracts off the Florida Panhandle. On
the basis of geophysical exploration by many companies, this region had
been expected to be a large producer of oil. The $632 million cost5 of
rights to explore this so-called Destin Anticline is summarized in Ta-
ble 9-2. This bid is about 10 times as large as the usual successful
lease bid. Exxon is reported to have spent $15 million drilling 7 dry
holes.6'7 Other companies, drilling in the vicinity, have also failed
to strike meaningful accumulations of oil. The consortium has surrend-
ered the leases and will have to write off a $632 million lease bid.7
This example illustrates that while oil exploration is costly and carries
the risk of complete failure, the initial stakes of even an extreme ex-
ample are not as high as with synthetic crudes.
Table 9-2
OFFSHORE LEASES IN THE DESTIN AREA OFF
FLORIDA'S PANHANDLE
(Millions of Dollars)
Company Share
Exxon 311
Mobile 211
Champ1in 111
Total* 632
*Total does not add because of rounding.
Source: Reference 5.
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It is noteworthy that for large contemporary conventional crude ac-
tivities, such as the Destin venture, companies find it prudent to spread
the risk by forming consortia. The same approach has been applied to the
development of the tar sands resource in Canada and to the development of
oil shale technology and oil shale lease bids (Table 9-3). Besides
spreading the risk, this group approach allows the smaller oil companies
to participate. Naturally, however, the participation of several com-
panies complicates the decision-making process because they do not possess
common perceptions of the future and the risk to each differs in propor-
tion to their total assets. However, coal leases are not, generally,
being acquired by consortia, apparently because, unlike oil shale, there
are many alternative uses of coal besides liquid fuels, and, therefore,
the risks are much smaller.
If the disappointing Destin exploration experience in the eastern
Gulf of Mexico should be repeated in other frontier offshore areas—where
much of the future domestic oil is expected to originate—corporate de-
cision makers will reevaluate the relative attractiveness of the gamble
on conventional exploration compared to synthetic crude production.
This would result from their reevaluating the expected marginal cost of
new conventional crude and its effect on the market price. Added to the
comparison between the future of domestic crude discovery and production
and synthetic fuels is the future of foreign activity in conventional
crude. Most oil companies feel that worldwide there is still much oil
to be developed, but after recent experiences with nationalization they
must weigh the risk of foreign investment against those of domestic in-
vestment—including synthetic crude. Companies now generally insist on
higher rates of return in foreign countries where political instabilities
threaten their investments.
Foreign governments affect the decisions of U.S. oil companies in
another important way. As Figure 9-8 showed, any activity that could
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Table 9-3
GROUP PARTICIPATION IN OIL SHALE
LEASES AND VENTURES
Oil Shale Leases
Colorado-a
Gulf
Standard of Indiana
Colorado-b
Atlantic Richfield
TOSCO
Ashland
Shell
Utah-a*
Phillips
Sun
Utah-b*
White River Oil Shale
Sun
Phillips
Standard Oil of Ohio
Colony Development (as of
July 1974)
Atlantic-Richfield (ARCO)
Shell
TOSCO
Ashland
Share
(percent)
50
50
25
25
25
25
50
50
33
33
33
25
25
25
25
*To be operated jointly.
produce a crude at a cost between Po and P4 would prove profitable. Yet,
if companies commit investment capital to these activities they run the
risk of OPEC cutting the price of their oil, thereby pulling the rug out
from under the investments that produce crude at a cost above the new
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price. The fear of this possibility inhibits investments in synthetic
crudes.
G. The Decision-Making Climate for Synthetic Liquid Fuels
Published information and our discussions with corporate stake-
holders revealed that today the indicated poor profitability (even loss)
of synthetic crudes, coupled with guarded optimism about the success of
redoubled efforts to find new reserves of conventional crude, tip the
scales against deployment of commercial synthetic crude production fa-
cilities. The outlook for decisions being made to go ahead with syn-
thetic liquid fuels is very poor without either direct risk mitigation
or indirect risk mitigation through the stabilization of policy and, most
2
probably, some concomitant—direct or indirect—economic subsidy. A
high level of synthetic liquid fuels production will probably not be
attainable without the creation of strong incentives; with a governmen-
tal hands-off policy, it is most likely that hardly any synthetic liquid
fuels will be produced in this century.
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REhERENCES
1. Kant, F. H., et al., Feasibility Study of Alternative Fuels for
Automotive Transportation," Environmental Protection Agency Report
EPA-460/3-74-009 (June 1974).
2. MacAvoy, P. W. , et al. , "The Federal Energy Office as Regulator of
the Energy Crisis," Technology Review, pp. 39-45 (May 1975).
3. Sponsler, G. C., "Synthetic Fuels Incentives Study," National Sci-
ence Foundation and Federal Energy Administration (November 1974).
4. "Moody's Industrial Manual," Moody's Investor's Service, Inc. (1975).
5. "Hopes Wane for Big New Reserves in Eastern Gulf," Oil and Gas
Journal, pp. 21-24 (March 10, 1975).
6. "Exxon Abandons Destin Well, No Further Drilling Planned," Oil and
Gas Journal, p. 41 (June 16, 1975).
7. "A New Face for Exxon's New Role in Oil," Business Week, pp. 136-146
(July 14, 1975).
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10—GOVERNMENT POLICIES TO ENCOURAGE THE
PRODUCTION OF SYNTHETIC LIQUID FUELS
By Ernest C. Harvey
A. Introduction
In the past, various government policies have been adopted to en-
courage investment in specific industries, to protect industries from
foreign competition or domestic overproduction, and to generate rapid
increases in the output of particular products. Measures such as investment
incentives provided through the tax structure, price support formulas,
import quotas or tariffs, and investment grants or loans have been em-
ployed. At the time it was initiated, each of these policies was re-
garded as appropriate for the industry for which it was adopted. Whether
any of these or other policies would be appropriate for a synthetic liq-
uid fuels industry, or would be regarded by the Administration or Con-
gress as politically feasible, depends on the specifics of national
energy policy, on the contribution that might be made by this industry
to the objectives of this policy, and on the cost to the public of
achieving this contribution—not only in dollars but in environmental
degradation, disruption of local economies, and other costs.
To assess alternative policies in this context, it is necessary
first to examine the characteristics of this industry and to identify
the principal features of a policy that could be expected to stimulate
the commercialization of synthetic liquid fuels. Industry characteris-
tics have been described in detail in other chapters, as well as the
factors that would affect the decisions of private sector companies to
commit resouces to the production of synthetic liquid fuels. These
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characteristics and factors are summarized and policy requirements are
identified in the next section. The principal policy mechanisms that
might be considered are examined in the following sections along with
the assessment of their applicability to synthetic fuels.
B. Required Features of Federal Policy
There are two principal characteristics of a new synthetic liquid
fuels industry that would influence both business decisions to commit
resources to the industry and government decisions to provide incentives
or other support:
• Large investment relative to output.
• High level of uncertainty regarding major factors that deter-
mine potential profitability.
Investment costs of producing synthetic liquid fuels have escalated
rapidly in the last few years. For this analysis it is accurate enough
to know that investment would be in the neighborhood of $1.0 billion
(1973 dollars) for an output of 100,000 B/D.* As has been pointed out
in other chapters, this is a very large investment even for large com-
panies, an investment with none of the exit points that exist for explo-
ration and development activities and involving techniques with which
oil companies are not familiar.
*Colony Development Operation is currently estimating more than $800 mil-
lion for a 50,000-B/D (8,000 m3/D) oil shale facility; other companies
are hesitant to make any firm estimate. The exception seems to be
Occidental's in. situ oil shale process, which is expected to require
about $100 million investment for a 50,000-B/D output. Industry ex-
perts are skeptical at this point about Occidental's estimates.
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The uncertainty is not limited to investment requirements. There
are sharp differences between the Administration and the Congress on the
specifics of a federal energy policy, and the future world price of oil
is highly uncertain in view of the apparent instability of OPEC and the
large discoveries that have been made around the world.
It is clear that the commercial production of syncrude is a high-
tig
risk venture and that the short-term contribution to domestic self-
sufficiency in crude production would be negligible. Without some form
of federal incentive, it is unlikely that investments of the size re-
quired to achieve significant output will be made by the private sector,
particularly if relatively high rates of inflation persist. It is also
unlikely that the federal government will consider costly incentive pro-
grams unless they can be relied on to significantly reduce the nation's
dependence on foreign sources of oil.
Under these circumstances the most appropriate federal policy would
appear to be one that limited itself to determining, and, to the extent
possible, reducing, the costs of commercialization of synthetic liquid
fuel production. The time required to accomplish this would permit more
careful analysis of energy demand/supply prospects and development of
energy policy guidelines within which a longer-term incentive program
for synthetic fuels could be established.
C. Incentive Policy Options
For purposes of analysis, incentive policies can be grouped into
several categories that reflect increasing levels of government in-
volvement :
*With the possible exception of Occidental's in situ oil shale process
and a proposed venture by Superior Oil Company that includes recovering
nahcolite and dawsonite along with kerogen from the oil shale.
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• Removal of constraints
• Tax incentives
• General price supports
• Specific price supports
• Government participation in investment.
These incentives are discussed briefly below, with comments regarding
their applicability to synthetic liquid fuels.
1. Removal of Constraints
In a study of incentives recently completed by the National
Science Foundation (NSF) and the Federal Energy Administration (FEA)
23 companies were asked if the removal of a number of constraints
would constitute an incentive.1 The constraints related primarily to the
lack of a firm government policy with respect to independence from for-
eign sources of oil and to the current "excessive" government involvement
in the energy market.
There was a consensus that a comprehensive national energy pol-
icy should encompass policy decisions in a variety of areas, provide for
improved coordination among the many government agencies involved in
regulation or approval of synthetic fuels development, and incorporate
a commitment that these policies will remain in effect at least through
1990. The areas most in need of firm policy determination were listed
as availability of federal land (on which most of the best oil shale is
located) and clarification of environmental regulations.
In view of the controversial nature of these and other identi-
fied policy areas, it is unlikely that such a comprehensive energy policy
will be developed in the near future. It is also unlikely, given the
short-term perspective of most members of Congress, that the type of com-
mitment fe.lt to be necessary will, in fact, be made.
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With respect to government involvement in the market, the
major constraints are price controls on crude oil and regulation of the
price of natural gas. Although the Administration favors removal of
these constraints, Congress is reluctant to do so; proposals have, in
fact, been made to roll back the price of old oil and place a ceiling
on the price of new and released oil. However, respondents to the NSF/
FEA survey were not consistent: although they called for a free market,
they gave high priority to guaranteed procurement of synthetic liquid
fuels and to loan guarantees and direct grants.
It was the conclusion of the NSF/FEA study that removal of
constraints, although important, would not be sufficient to ensure com-
mercialization of synthetic liquid fuels production. The key to such
development is the assurance of profitability. Current statements by
the industry, as reported in trade journals, recognize the importance of
uncertainties surrounding government policy but also place major empha-
sis on cost and the uncertain future course of crude oil prices as major
deterrents to commercialization.
2. Tax Incentives
Historically, a variety of tax incentives has been used to
stimulate investment generally or in specific industries. Investment
tax credits and rapid write-off provisions have been offered; minerals
industries are allowed depletion allowances and the timber industry is
accorded capital gains treatment. These policies are effective only
where profitability can be assumed, even if it is marginal. The objec-
tive in such cases is to raise potential profitability of the activity
receiving special treatment to a level that would make it competitive
with alternative uses of funds, without recourse to a direct, overt
subsidy.
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An investment tax credit was given relatively high priority by
respondents to the NSF/FEA survey, ranking 9th out of 45. However, most
of the companies surveyed indicated that a credit significantly greater
than that suggested (7-10 percent) would be required—perhaps as large
as 50 percent—although it was recognized by many that credits in excess
of 10 percent probably would not be politically acceptable. A tax credit
of 7 percent was available for new investment at the time of the survey.
This had been increased to 10 percent under the new tax law. Therefore,
the 7-10 percent range for synthetic fuels investment does not consti-
tute a special incentive.
In practice, the effectiveness of a tax credit of a given size
will vary with the characteristics of the companies considering synthetic
liquid fuels production and the specific application of the credit. If
the credit is applicable only to synthetic fuels production it will not
constitute an incentive unless there is reasonable assurance of profit-
ability. If it is not restricted in application, considerations include
the cash flow and profitability implications of initiating synthetic
fuels production and taking advantage of the credit relative to other
investment alternatives.
It should be pointed out that current congressional sentiment
is to eliminate special tax "privileges." The oil depletion allowance
has already been eliminated and elimination of other special tax provi-
sions has been discussed. It seems clear that if production of synthetic
liquid fuels were determined to be required in the national interest Con-
gress would prefer to direct subsidy rather than the indirect and somewhat
uncertain route of tax incentives. Congress has already expressed concern
about the profits of oil companies, which are prime candidates for devel-
opment of synthetic liquid fuels production, has taken action to con-
strain these profits by removing the depletion allowance and retaining
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controls on crude oil prices, and has considered an excess profits tax.
A new tax incentive is unlikely.
3. General Price Support
Price support programs of various types have been used in ag-
riculture for years. The general approach was to set floor prices for
the various farm crops. At harvest time farmers could store their crops
and receive payment, on a loan basis, at the support price. If the mar-
ket price rose above that level he could sell the crop and repay the
loan; if it declined title passed to the Commodity Credit Corporation.
The Sugar Act provided for maintenance of the domestic sugar price by
limiting imports of foreign sugar by means of a quota system. Crude oil
and petroleum products received similar support before March 1973. Im-
ports were restricted through quotas and duties, which made possible
the continued existence of a relatively high-cost domestic oil industry.
Programs of this type are effective in large-output situations
in which the problem is one of overproduction relative to market demand.
In agricultural price supports, acreage limitations were also imposed
to restrict output and reduce the downward pressure on prices. The ob-
jective is to maintain the market price at a level sufficient to ensure
reasonable profitability. However, such a program would not be applic-
able to synthetic liquid fuels because, at least in the near and medium
term, the output would not be large enough to affect the price of crude
oil. Other measures, such as restrictions on imports, would be required
to force up the price of conventional crude to the level required to
*Imports of No. 4 distillate and residual fuel oil into the East Coast
were exempt from quota.
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make synthetic fuels profitable. Largely because of consumer pressure,
Congress has not accepted Administration proposals to free the price of
old oil, and as stated earlier, it is considering a rollback of the old
oil price and a ceiling on the price of new and released oil. Therefore,
Congress is not likely to support a program that would induce signifi-
cantly higher price increases, with its potential impact on the rate of
inflation and on profits of the oil companies.
The general price-support approach could, of course, be used
to provide a price guarantee to producers of synthetic liquid fuels,
recognizing that, for the foreseeable future, the government would have
to assume title to the output and sell it at a loss. This program would
become a specific price support program; such programs are discussed in
the next section.
4. Specific Price Supports
Several types of specific price support have been suggested
and are under study by FEA. These include government procurement at
cost plus a fixed fee, at a fixed price, or under a contractual arrange-
ment with adjustments for inflation. Another mechanism, which is not
technically a price support but which is similar in effect, is the pay-
ment of direct subsidies to producers of synthetic fuels.
Each of these proposals would require industry to provide the
necessary capital funds unless capital expenditures were also subsidized.
Rate of return on these funds would depend on the fee or fixed price
negotiated or on the level of the subsidy provided. The cost plus fixed-
fee arrangement would probably be the fastest way to achieve commercial-
ization unless the rate of return implied by the negotiated fee were
perceived to be less than could be obtained from other uses of funds.
Furthermore, this approach would provide no incentive for efficiency
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unless provision were made for renegotiation of the fee upward to re-
flect substantial reductions in cost.
Although the fixed-price and contractual approaches would tend
to encourage efficiency, many of the uncertainties—e.g., future world
crude prices and government import and tariff policies—that have pre-
vented commercialization to date would remain. The negotiated price
would have to include a substantial allowance for these uncertainties
to ensure even a reasonable prospect of profitability, even if provision
were made for inflationary adjustments. If the negotiated price were
high enough the impact on efficiency might be minimal, but, if it were
significant, it would probably generate government pressure for renego-
tiation.
A direct subsidy would contain elements of several of the
above approaches. It could be a fixed amount negotiated in advance or
an amount sufficient to cover the excess of costs over revenues, with
or without allowance for profits. Advantages and disadvantages similar
to those indicated above apply, depending on specifics.
Any of these schemes could be handled on a levy/subsidy basis.
An extra tax collected on gasoline could be distributed to synthetic
crude producers to reduce the sales price of syncrude to the market
level. The amount required would depend on government policy with re-
spect to the pricing of domestic oil and the levying of tariffs on im-
ported oil and on the future world price of oil. However, as long as
the supplies of syncrude remained small, a relatively small tax would be
sufficient. Presumably, a large increase in the proportion of syncrude
produced would be accompanied by, and would indeed be conditional on
reductions in its relative cost of production. In that event, the levy/
subsidy arrangement could be adapted without undue hardship to the con-
sumer to accommodate a proportion of the order of 10 percent of total
supplies in the form of syncrude.
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An alternative to a levy/subsidy mechanism would be to allo-
cate a proportion of any extra costs entailed in the production of syn-
crude to each refiner in proportion to output. This type of approach
is currently employed in the oil "entitlements" program to eliminate
disparities in cost among companies with varying proportions of old oil,
new and released oil, and imported oil in their refinery mixes. Its ap-
plication to syncrude production, given its administrative complexity
and the small quantities involved initially, does not seem appropriate
in the short run.
There has been no discussion in recent articles in trade maga-
zines of the mechanics and cost of marketing syncrude. Incentive pro-
grams entailing government purchase would presumably leave the marketing
function to the government; either party could be responsible under a
direct subsidy program. So long as the output remained small, marketing
*
should not present serious problems. However, if relatively large quan-
tities of syncrude were produced ultimately, substantial investment in
new pipeline links would almost certainly be required. More generally,
to the extent that syncrude replaces imports (which would be the logical
limit on making it, unless and until it becomes cheaper than conven-
tional crude) it will be necessary to contemplate adding to the pipeline
network sufficient capacity to transport it where it is needed for re-
fining. If syncrude served as a replacement for imports, one important
destination would be the northeastern states that presently have about
a million barrels a day of refinery capacity supplied by imports, but
no crude pipelines other than one from Portland, Maine, to Montreal.
This problem of transportation should be carefully evaluated before an
incentive policy contemplating a significant long-run expansion of syn-
crude production is formulated.
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5. Government Participation in Investment
The government can stimulate the development of specific in-
dustries by participating in investment in varying degrees. The most
direct participation in investment is government ownership of industrial
plants. The government can participate to a lesser extent by sharing
investment costs with private enterprise or by guaranteeing private
loans.
a. Government Ownership
Under a program of direct government ownership of indus-
trial plants, the plants are constructed and operated by private enter-
prise under contracts with the federal government. After the development
of the industry or, as the national need for the industrial output de-
creases, private firms would have the option of leasing or purchasing
the facilities.
This approach to the rapid development of an urgently
required industry is illustrated by the U.S. synthetic rubber industry
in World War II. The rapid Japanese advance early in 1942 cut off the
greater part of Allied supplies of natural rubber. Over the next two
and a half years, to late 1944, 51 plants for producing various types
of synthetic rubber and their ingredients from petroleum were built in
the United States. The capital cost, some $600 million, was funded by
the federal government; running costs and profits of sales were for
government account. The plants were run by large private firms (because
large firms alone possessed the necessary technical knowledge) on a fee
basis which was, in effect, a substitute for profits. Of course, in
war time there was a ready market for all the synthetic rubber that
could be produced; indeed, the United Kingdom, which had agreed to take
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rubber from the United States rather than produce it for itself, re-
mained somewhat short of supplies.2
After the war, 22 of the synthetic rubber plants were
disposed of in fairly short order, but the others remained in federal
ownership. A market for synthetic rubber was assured by regulating by
law the amount of natural rubber that might be used in various finished
goods. As time went on, and the quality of the synthetic rubber im-
proved, manufacturers became willing to take more than was legally
obligatory, and in 1953 the obligation was ended. In the same year an
act was passed (P.L. 205, 83rd Congress, 1st Session, Chapter 338) es-
tablishing a Disposal Commission to sell off the remaining 29 rubber-
producing facilities, and by the middle of 1955 this process was vir-
tually complete. The plants were disposed of mainly by sale to the
companies that were operating them on behalf of the government, although
there were one or two exceptions, and one or two unsalable plants that
had to be put on a care and maintenance basis. Particular care was taken
to ensure that the purchasers would reserve part of their production for
small business. The proceeds of the sales realized the federal govern-
ment more, on paper, than the cost of building the facilities in the
first place (if no allowance is made for the fall in the value of the
dollar between 1942 and 1955). The day-to-day conduct of the businesses
was also profitable.
Aluminum is another example of this approach. During
World War II, the output of aluminum was greatly enlarged through the
mechanism of government-owned plants constructed and operated by private
enterprise under contracts with the U.S. Reconstruction Finance Corpora-
tion. At the end of the war, aluminum production was sharply curtailed
and uneconomically located capacity was retired. Government aluminum
plants were declared surplus for lease or sale. The lease or sale pro-
gram was.designed to dispose of facilities to producers other than Alcoa,
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which until 1940 was the sole producer of aluminum in the U.S. and had
been subject to antitrust action.
However, the analogy between either synthetic rubber or
aluminum and any prospective synthetic liquid fuel is not close. Both
rubber and aluminum were required urgently for wartime needs in large
quantities; the raw material was plentiful, and the technology was known.
By contrast, synthetic crude would be a marginal addition to total energy
supplies at best for many years, if only because of actual availability
of the raw material, be it coal or shale. Moreover, the investment re-
quired per unit of output is many times greater than that required for
synthetic rubber or aluminum. The approach used in synthetic rubber to
assure a market after World War II could be applied to synthetic crude,
either by requiring acceptance of syncrude or purchase of an entitlement.
However, this procedure does not seem justified, given its administrative
complexities and the relatively small syncrude output involved in the
near term.
b. Grants-in-Aid
The government could participate in investment to a les-
ser extent than in either synthetic rubber or aluminum by sharing, on a
grant basis, the investment costs with private enterprise. Direct or
convertible grants, if they are large enough, and if they can be used,
in effect, to offset costs in excess of market price, might provide the
necessary incentive for commercialization of synthetic fuels production.
*These limitations are most likely to arise from environmental restric-
tions; from shortages of labor and transport facilities; from demand
for more urgent needs, such as electricity generation; and from politi-
cal opposition in the western states.
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However, this indirect approach to subsidy has political drawbacks and
would require extensive government surveillance; furthermore, under this
arrangement, it would be difficult to assess the potential for produc-
tion of syncrude on a private enterprise basis.
c. Loan Guarantees
A third way the government can participate in investment
is through loan guarantees, which could be provided for some percentage
of the required amount. Unlike the other types of participation, a
loan program does not require a direct commitment of federal funds;
federal funds are only committed in the event of default on the loans.
Although loan guarantees are not direct government investments, they do
allow the private market to invest under conditions of risk and uncer-
tainty. Such guarantees have been used to stimulate home, farm, and
small business loans. There is usually a limit on the rate of interest,
and in times of tight money the margin to lenders is not particularly
attractive. Furthermore, unless there is a 100 percent guarantee, the
lender must assume a portion of the risk and in any event he is usually
required to exercise prudent lending practices. In addition, the re-
porting and paperwork required under these programs is regarded by
many as inordinate. The specific requirements of a loan guarantee pro-
gram established for synthetic crude production, therefore, would govern
its acceptability to lenders. However, given the current level of un-
certainty, such a program is unlikely to provide sufficient incentive to
potential procedures of syncrude to stimulate commercialization of syn-
thetic fuels production.
There have been two recent proposals for government ac-
tion to stimulate the development of a synthetic fuels industry. The
first is a loan guarantee program applicable only to the development of
a synthetic fuels industry. The second is contained in a broader
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program designed to supplement and encourage private capital investment
to meet the energy needs of the nation.
The Senate version of the ERDA Authorization Bill (HR3474)
included a $6 billion loan guarantee program for the development of a
350,000 B/D (56,000 m3/D) synthetic fuels industry. Since the addition
of this provision, ERDA has requested an additional $5.5 billion: $600
million for plant construction; $4.5 billion for price supports; and
$400 million for loan guarantees to communities that would have to cope
with the new industry.
Legislation creating an Energy Independence Agency (EIA)
was submitted to Congress by the President in October 1975. The EIA,
which will have a 10-year life, would have financial resources of $100
billion, consisting of $25 billion of equity and $75 billion of debt.
Financial outlays are intended to be recovered by the government and
would be used to support projects that would contribute directly and
significantly to energy independence and that would not be financed
without government assistance. Financing could take a variety of forms
including direct loans, loan guarantees, guarantees of price, purchase
and leaseback of facilities, and purchase of convertible or equity
securities. Emphasis would be placed on loans and loan guarantees, and
government ownership is authorized only for limited periods and under
specified conditions.
These proposals indicate an awareness, at least on the
part of the Administration, that significant investment in synthetic
fuels is unlikely in the near term without government assistance. How-
ever, there appears to be little support for these programs on the part
of many legislators and industry spokesmen. There is considerable con-
troversy concerning the size, scope, and timing of a synthetic fuels
program, which is itself part of the larger controversy regarding a
378
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national energy policy. Any decision with respect to financial involve-
ment by the government must await resolution of these controversies.
D. Conclusions
The combination of high cost seemingly irremedial uncertainty make
synthetic fuels investment unsuitable for private business. If synthetic
fuels are to be produced in significant amounts in the near future, gov-
ernment assistance will probably be necessary. There is considerable
disagreement among Congress, the President and industry regarding the
degree of government participation in the synthetic fuels industry.
Even if a variety of inducements could be provided, it is not clear
whether private investment could be attracted, especially since most
inducements are subject to considerable uncertainty in that they can be
modified or eliminated at short notice. The need for long-term commit-
ment to firm energy policies was emphasized by respondents to the NSF/FEA
study. Such commitment would be particularly important for synthetic
liquid fuels production because of the large' investment requirements and
uncertain future market. However, by its very nature, Congress cannot
commit itself to firm, long-term policies, and its record with "long-
term" policies in the past does not instill confidence.
If the government decides that development on a commercial scale is
desirable, it would seem appropriate for it to finance a commercial plant
or plants. The government has already become heavily involved in the
financing of a demonstration plant under the terms of a contract between
the Energy Research and Development Administration (ERDA) and Coalcon
*Coalcon is a joint venture formed by Union Carbide and Chemical Construc-
tion and has recruited members of a consortium being formed to build and
operate the demonstration plant.
379
-------
of New York. The initial funding for plant design and engineering will
be provided by the government and costs of construction, evaluation, and
operation will be shared equally by the government and industry. Total
government funding will be $137 million, and the private sector will
contribute $100 million. The plant is expected to be operating by 1983
and will convert 2600 tons/day (2.4 X 106 kg/D) of coal into 3900 B/D
(4100 ms/D) of liquid product and 22 million cubic ft (620,000 m3/D) of
pipeline-quality gas per day. This plant is very small compared with
the sizes considered suitable for commercialization elsewhere in this
study.
If commercialization is determined to be required before the re-
sults of this demonstration are in, the government will probably have to
furnish the capital to build the plant (and possibly to open an associ-
ated mine), arrange for the transportation of the product to refineries
(building pipelines if necessary) and enter into contracts with a firm
or firms for the day-to-day management of the plant on a fee basis, and
for the purchase of the product at a range corresponding to the differ-
ence in quality between it and competing conventional crude. Although
this rate might represent a premium over the market price, it seems
clear that it would have in it a large element of subsidy. These tasks
would have to be carried out by one or more of the big companies in the
industry.
This undertaking would inevitably involve the government in the
industry in a variety of complicated ways that it would doubtless prefer
to avoid. As the NSF/FEA report makes clear, government involvement
would also be unpopular with the oil companies. For example, one of the
*This represents about an equal division of energy in liquid and gaseous
forms.
380
-------
companies surveyed observed that it would be a disincentive to synthetic
fuels development activities by the private sector, although it is dif-
ficult to believe that anyone making this observation had looked care-
fully into the question of comparative cost. Another company observed
that the most likely outcome would be that "the government would end up
as the sole owner of an unprofitable plant," which is perhaps much nearer
the mark. However, government financing of a commercial plant would pro-
vide a firmer basis than now exists for estimating the likely costs of
synthetic liquid fuels production and for establishing a policy regard-
ing the role of these fuels in the future supply of domestic oil. If
successful, the experience gained in the synthetic rubber program could
be used to turn the activ-ity over to the private sector.
381
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REFERENCES
1. "Synthetic Fuels Incentives Study," NSF and FEA, final report by
International Planning Management Corporation, Bethesda, Maryland
(November 13, 1974). The study included 13 large oil companies,
4 small independent oil and research and development companies,
4 utilities, and 2 banks.
2. J. Hurstfield, The Control of Raw Materials (U.K. Official History
of World War II, London, 1953), pp. 171, 292, 298.
382
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11—NATIONAL ECONOMIC IMPACTS OF THE
SYNTHETIC FUELS INDUSTRY
By John W. Ryan
A. Introduction
The production of synthetic fuels from coal or oil shale results in
impacts at several levels in the economy. The chief impacts are those
associated with the employees (and their families) of the mining and
processing facilities. The secondary economic impacts are those that
result, in turn, from the primary development. These include the in-
duced growth of and competition with other industries. Most commonly
discussed are the supporting industries that gather around the primary
development. However, there are many supporting and supplying indus-
tries that will provide goods and services from a distance; many of these
are already established and are unlikely to relocate. The demands for
the goods and services of these supporting sectors will be substantial
under the levels of resource development required by the SRI scenarios.
This chapter discusses the availability of materials and equipment
and describes the impacts in geographic regions distant from the loca-
tion of the primary mining and processing facilities. The nature of
the impact and general magnitude of the demand are discussed, along with
the geographic location of the major supplying industries. Specific
forecasts of impacts are not attempted because there are too many in-
fluences outside of the system of synthetic fuels production.
383
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B. Interindustry Relationships
The principal sectors supplying the coal mining industry (and by
inference the future oil shale mining industry) can be determined from
the total requirements table of the 1967 input-output (I-O) matrix of
the U.S.1 The coefficients in this table specify the direct plus
indirect output of other industries needed to produce a dollar's worth
of coal delivered to final demand. For example, the coefficient for
mining machinery (sector 45.02) is 0.026; this means that for every
thousand dollars of coal sold in 1967 to final demand, purchase of $26
of mining machinery is required. Table 11-1 lists the 20 coal supplying
sectors with the largest total requirements coefficients.
The largest coefficient in Table 11-1 belongs to the coal industry
itself; for every dollar of coal delivered to final demand, another 0.15
dollar's worth is consumed by sectors that in turn supply the coal mining
industry. Nonindustrial sectors with large coefficients are real estate
and miscellaneous business services. These reflect the importance of
land purchases and leases and of repair services, such as welding and
armature rewinding. Legal services are classified under sector 73.03,
miscellaneous professional services, with a coefficient of 0.010.
Several manufacturing sectors appear in Table 11-1. Blast furnaces
and basic steel products (sector 37.01) have the largest coefficient and,
therefore, can be expected to be of utmost importance for expanded coal
production. Other sectors that one would expect to be important are
construction and mining machinery. Chemical industries (sectors 27.01
and 27,04) appear primarily because of the importance of blasting mate-
rials in mining.
Petroleum refining is classified as a manufacturing sector accord-
ing to I-O classifications, although it actually represents oil as a
384
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Table 11-1
ECONOMIC SECTORS PROVIDING INPUTS TO THE COAL MINING
SECTOR, RANKED BY SIZE OF 1967 TOTAL REQUIREMENT COEFFICIENT
Source: Reference 1.
Input/Output
Rank Industry Title Coefficient Sector Code
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Coal mining
Real estate
Blast furnaces and basic steel
products
Wholesale trade
Miscellaneous business services
Electric utilities
Mining machinery
Petroleum refining
Screw machine products and bolts,
nuts, rivets, washers
Miscellaneous chemical products
Maintenance and repair construction
Construction machinery
Industrial chemicals
Imports
Reclaimed rubber and miscellaneous
rubber products
Railroads and related services
Crude petroleum and natural gas
Miscellaneous professional services
Insurance
Logging camps
1.148
0.075
0.037
0.034
0.034
0.031
0.026
0.020
0.017
0.017
0.016
0.015
0.014
0.013
0.012
0.011
0.011
0.010
0.010
0.009
7.00
71.02
37.01
69.01
73.01
68.01
45.02
31.01
41.01
27.04
12.02
45.01
27.01
80.00
32.03
65.01
8.00
73.03
70.04
20.01
385
-------
source of energy analogous to the coal, natural gas, and electric util-
ity sectors. The coefficient for petroleum refining is 0.020, while
that for electric utilities is 0.031. These high values reflect the
direct importance of petroleum products and electricity to coal mining,
as well as their importance to all sectors supplying the coal mining
industry.
Input-output tables reveal the relative contribution of various
sectors to the output of coal mines. However, potential constraints on
the expansion of the coal industry depend largely on the size of coal
industry demand compared with other demands for the capacity of each
supplying sector.
The level of aggregation in the input-output table is a source
of difficulty. The aggregation can obscure key parts of selected indus-
tries. One attempt to overcome this problem is reported in Bureau of
Mines Information Circular 8338, "The Interindustry Structure of the U.S.
Mining Industries - 1958," which contains detailed tables listing mate-
rials and purchased services for coal and other mining industries. For
example, this more disaggregated table reveals that the reclaimed rubber
and miscellaneous rubber products sector is important because of the mis-
cellaneous rubber products (SIC 3069) component, which includes conveyor
belting and rubber hoses.
Thus, in summary, the interindustry relationships given in input-
output tables are useful to identify the major inputs needed by the coal
mining sector, especially from indirect suppliers of the coal mining
sector that could easily by overlooked otherwise. The next section ex-
pands the analysis to discuss the demand levels for specific equipment
and the potential for bottlenecks.
386
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C. Materials and Purchased Services Used by the Coal Industry
The availability of goods and services used in energy production was
analyzed by the Materials, Equipment, and Construction (MEC) Task Force
of Project Independence,3 which covered all energy sectors; this paper,
however, is concerned only with coal and oil shale. Other demands on
supplying sectors from other energy sectors cannot be discussed in de-
tail but may have an effect on the availability of materials for coal
production.
1. MEC Task Force Projections
The MEC Task Force considered two scenarios in their analysis:
1. BAU, "Business-as-Usual" scenario of the Project
Independence Coal Task Force.
2. AD-C, "Accelerated Development" scenario of the
Coal Task Force, as constrained by the availabil-
ity of walking draglines.
Figure 11-1 shows coal production for the maximum credible
implementation scenario (MCIS) developed for this study added to that
of the Ford Energy Policy Project's Historical Growth scenario (HG1)
without synthetic liquids from coal. Together, the scenarios call for
3.6 billion tons of coal consumption in 2000. The 1990 production for
the BAU and AD-C scenarios of the MEC Task Force are shown in Figure 11-1
as two points at 1.3 billion tons and 1.8 billion tons, respectively.
Because the AD-C scenario is approximately equal to the total for HG1
plus MCIS in 1990, the conclusions of the MEC Task Force can be applied
directly—assuming (1) that the split between underground and surface
mining remains approximately the same between 1990 and 2000, and (2) that
trends in capacity expansion continue to 2000.
The future availability of the selected items was based on
Department of Commerce analyses of production capacity for the commodities
387
-------
4.0
3.8
3.6
3.4
3.2
^ 3.0
o
o>
Q.
2.8
2.6
c
o
r 2.4
o
£ 2.2
o
5 2.0
i
o 1-8
§ 1-6
Q
2 1.4
O
o
1.2
1.0
0.8
0.6
0.4
0.2
0
I97O
HG1 PLUS MAXIMUM
CREDIBLE IMPLEMENTATION,
FOR SYNTHETIC FUELS
PIB BAU
SCENARIO
I
1975
1980
1985
YEAR
1990
1995
2000
FIGURE ll-l. FUTURE COAL PRODUCTION LEVELS FOR PROJECT
INDEPENDENCE SCENARIOS AND THE SRI MAXIMUM
CREDIBLE IMPLEMENTATION SCENARIO (PIB: Project
Independence Blueprint; HG1- Ford Energy Policy Project
Historical Growth 1)
388
-------
involved. Export demand (a fraction of capacity) was assumed to con-
tinue at current levels, with the remainder of production available for
domestic consumption. MEC estimated the portion sold to the energy sec-
tors by techniques such as trend line extrapolation, input-output, and
contacts with manufacturers.
The MEC investigated basic materials, such as steel and cement;
intermediate materials, such as forgings, castings, and explosives;
equipment components, such as compressors, pumps, and valves; and major
equipment, such as continuous miners and draglines. Potential problems
for the future expansion of coal mining were found in:
• Steel
• Walking draglines
• Castings and forgings.
However, problems are not expected for:
• Continuous miners
• Construction equipment
• Crushers
• Explosives
• Mine roof bolts
• Power shovels.
Before discussing the problem areas further, however, the analysis behind
other coal-related categories will be considered.
The MEC Task Force made various assumptions in its analysis.*
For example, although the demand for continuous miners depends on the
coordinate availability of horizontal and vertical boring machines, the
*To fully understand the MEC assumptions about the supply situation, the
reader should refer to the MEC Task Force Report for each category.
389
-------
latter two were not analyzed or discussed in detail. It should be noted
that continuous miners are made to mine specifications and not available
from open inventory. About 94 percent of the continuous miners produced
in 1973 and 1974 were shipped to the coal mining industry, but in the
period to 1990 the MEC estimates that the percentage will drop to 86 per-
cent. About 95 percent of mine roof bolts will go to coal mines. As-
suming that roof bolt supplies are not again disrupted by price controls,
as they were in 1972 and 1973, the MEC foresees sufficient flexibility
to expand roof bolt production in existing facilities. This should re-
main true even if legislation greatly curtails surface mining and forces
an increase in underground mining. The estimates for categories that
sell to end users besides mining are not as critical because productive
capacity that has historically gone to other sectors could, in principle,
be diverted to the coal industry. This is true of construction equip-
ment, explosives, crushers, and power shovels, where less than 50 per-
cent of output goes to coal mining.
a. Steel
The MEC Task Force found that there would be a shortage
of steel supplies available in the energy sector if no more than the
historical percentage of steel output went to energy industries. Based
on the historical distribution of steel between energy and nonenergy
uses, a 7.3 percent availability to energy industries was selected as a
conservative estimate, while an upper value of 11.1 percent was chosen
on the basis of figures for the first half of 1974. The results are
summarized from the MEC report in Table 11-2.
*Especially now that the interstate highway system is nearing completion.
390
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Table 11-2
PROJECTED STEEL AVAILABILITY
(Millions of Tons)*
1980 1990
Steel mill capacity 125.9 150.2
Available to energy sector:
@ 7-2% 9.1 10.8
@ H.1% 14.0 16.7
Requirements:
Scenario BAU ' 10.3 13.4
Scenario AD-C 11.6 14.6
*Note 1 ton is about 907 kg.
Source: Project Independence Materials, Equip-
ment and Construction Task Force.
Table 11-2 shows that the requirements for scenarios BAU
and AD-C of the MEC fall between the 7.2 percent and 11.1 percent produc-
tion values. Thus, with synthetic liquids included, the energy sector
will need to purchase a greater proportion of steel output than it has
averaged historically. Steel for the coal industry, including production
allocated to liquid synthetic fuels, reaches 6 percent of energy sector
requirements in 1980. This is such a small portion of total steel demand
that it is unlikely that coal mining will be seriously affected by short-
ages of gross steel capacity; however, as discussed below, specialty
products may prove constraining.
391
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b. Ferrous Castings and Forgings
Castings and forgings are usually discussed together be-
cause of the similarity of their production. Production capacity is
fragmented among several industries producing diverse products, which
leads to great difficulties in estimating current capacity for castings
o
and forgings. Clearly, future capacity depends on availability of
steel, capital, labor and energy, but a major portion of future capital
expenditures must be oriented towards compliance with regulations on
health, safety, and environmental quality. Unfortunately, the small
size and low profitability of many firms in these industries make them
unattractive to capital sources. Even though the MEC Task Force was
unable to develop quantitative estimates of availabilities and require-
ments for castings and forgings—because it found that even though the
industry is operating multiple shifts, delivery times are growing and
shortages are developing—it concluded that expansion of energy produc-
tion was likely to be constrained.
c. Walking Draglines
The MEC Task Force concluded that walking draglines would
be the limiting item in accelerating coal output. Indeed, their AD-C
was derived by scaling the "Accelerated Development" scenario of the
Coal Task Force of Project Independence that called for 2.8 billion tons
of coal in 1990. The MEC concluded that in 1990 only 1.8 billion tons
could be produced because the availability of draglines would constrain
future development of surface mines. Thus, since the sum of HG1 and
MCIS scenarios correspond to the AD-C scenario, walking draglines can be
expected to inhibit synthetic fuels development.
Behind this conclusion are the following facts:2
• Orders now on the books are sufficient to keep the
industry at full production through 1979.
392
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• Producers plan to ship 45 draglines in 1977—up
from 21 in 1974. (MEC Task Force estimates 1980
annual capacity at 50 to 55 units.)
• Historically, 25 percent of the walking draglines
have been exported (helping to balance capital
outflows from the United States).
• Manufacturers have been able to raise capital for
expansion in the past.
Unfortunately, the MEC Task Force does not present the
details of its supply/demand estimates, so the basis for its conclusion
is not readily apparent. In fact, a simple analysis of the supply situ-
ation compared with the number of mines necessary to meet the 1990 pro-
duction levels of the AD-C scenario suggests that dragline production
should be more than sufficient. The details of the estimate made for
this study are given in Appendix A.
2. Overview
The level of economic activity of the moment can influence an
analyst's views of material shortages. The work of the MEC Task Force
was conducted in mid-1974 during a period of material shortages and long
delivery times. The recessionary situation of early 1975 was quite dif-
ferent; except for the energy sector, there was considerable idle capac-
ity and unemployment. It might be expected that the fraction of future
production capacity available to energy sectors is likely to increase as
suppliers turn to that market, seeking to cultivate stable and growing
markets. Thus, historical relationships are likely to change as the
economy shifts back to growth, with more emphasis on capital goods sec-
tors and less on consumer durables, such as automobiles.
393
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D. Conversion Facilities
Possible constraints on the construction of three processing oper-
ations for the production of synthetic liquid fuels are considered here:
• Coal liquefaction plants
• Oil shale retorts
• Methanol plants.
The input-output approach used above cannot be used to identify the major
supplying industries to the future synthetic fuels industry since the
data do not exist. Moreover, after exploring possible parallels with
the petroleum refinery sector in the input-output data, it was concluded
that the analogy was not strong enough to justify elaboration. However,
engineering analyses have provided estimates of the needed materials and
equipment. Liquefaction plants and oil shale retorts require similar
amounts of steel for large-scale operations; however, methanol production
requires almost twice the steel per unit of output (see the construction
scaling factors in Chapter 6).
Coal liquefaction is a highly complex process requiring large pres-
sure vessels and high-quality piping; both require numerous pumps and
compressors. Consequently, the construction of coal liquefaction plants
is more likely to meet with materials and equipment shortages than con-
struction of oil shale retorting facilities.
Availability of steel plate for pressure vessel construction is
limited. According to the Project Independence Task Force Report on
Synthetic Fuels from Coal, only one steel company presently has the ca-
pability to produce steel plate in large widths;3 lead times in 1974
were reported to be 2 years.
Even if the necessary steel plate were available, fabrication of
pressure vessels poses another bottleneck. Most of the capacity able
394
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to produce heavy-walled pressure vessels needed in coal liquefaction is
currently committed to nuclear power facilities, and it is unlikely that
large amounts of capacity will be available for coal liquefaction with-
out substantial additions to capacity.3 The major fabricators are cur-
rently committed through the 1970s. The present competition for mate-
rials is not likely to change significantly over the long term under
current U.S. policy. Even in the 1990s when the scenarios of this study
show rapid growth in coal liquefaction, the demand for nuclear power is
expected to remain a strong competitor for steel suitable for pressure
vessels.
Future production of pumps and compressors depends on the availa-
bility of castings and forgings as opposed to plant capacity. The engi-
neering lead times for synthetic fuels plants is longer than the time
needed to tool up for increased production of these goods.2
Material constraints on oil shale retorts and methanol plants seem
less critical. While large amounts of steel are required, the necessary
pressure vessels are smaller and easier to fabricate. Consequently,
there are more mills capable of producing the necessary steel products.
The availability of castings and forgings is a possible bottleneck in
this portion of the synthetic fuels production chain as well.
E. Transportation
The impacts in the transportation sector depend very much on the
location of mines and conversion facilities. Coal liquefaction may
either be done at the mine (mine-mouth) or the coal may be shipped to
a remote liquefaction plant by rail or slurry pipeline. (See Chapter 19.)
There is no transportation problem for the oil shale industry because
processing must be performed at the mine to be economic, and the syn-
thetic crude can be shipped by pipeline using relatively short branch
lines to"connect with existing crude pipelines.
395
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Regulatory policies will be a key factor. Present air quality
standards will increase demand for low sulfur western coal, and the dis-
tance to utility markets will increase the demand for rail facilities.
If western states pass regulations prohibiting development of conversion
facilities, then rail shipments or slurry pipelines will be necessary
to move coal to distant liquefaction plants.
1. Railroad Equipment
Presently, railroads haul 78 percent of all coal, and this
amounts to approximately 20 percent of all rail traffic.4 Under their
"Base Case" scenario, Project Independence calculations show that rail
shipments of coal will more than double by 1985 to a level of 730 mil-
lion tons per year.4 The resulting supply/demand balance for locomo-
tives and hopper cars for 1985 is shown in Table 11-3.
Table 11-3
CUMULATIVE DEMAND AND SUPPLY ESTIMATES FOR
LOCOMOTIVES AND HOPPER CARS TO 1985—
PROJECT INDEPENDENCE BASE CASE
Manufacturing
Capacity
Required Minimum Maximum
Locomotives 10,465
14,600 19,100
Hopper cars 274,800 180,000 310,000
Source: Reference 4.
396
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Table 11-3 indicates that there would be sufficient locomo-
tives if all new production could be used to move coal. Total require-
ments are over two-thirds the estimated minimum productive capacity to
1985, leaving only one-third of the new locomotives to be used by the
other 75 (or more) percent of rail traffic. Hopper cars are in even
tighter supply according to Project Independence; the projected require-
ments for coal shipments are 88 percent of the maximum production
through 1985, and 50 percent greater than the minimum.
Because of slight differences in coal production rates and
time horizons assumed in the MEC and this study, it was necessary to
adjust the MEC's railway equipment projections upwards by 22 percent.
This yields an upper-bound estimate of locomotive and hopper car re-
quirements. This gives a requirement for 335,000 hopper cars and ex-
ceeds the maximum estimated production capacity shown in Table 11-3.
The production of railroad equipment requires that steel goods
be available in sufficient quantities. For example, a typical 100-ton
hopper car requires 30 tons of steel, but castings and forgings needed
for wheels and axles, truck side frames, and couplings are likely to be
in limited supply. Thus, the gross availability of steel may not con-
strain coal car production as much as the lack of specialty products.
Financing of new equipment will be a definite problem for
deficit-plagued railroads. However, institutional changes affecting
the ownership of rail cars are occurring; in particular, utilities and
other large coal users are now purchasing cars directly to guarantee
their shipments. This trend, coupled with equipment leasing, will alter
the nature of railroad financing in the future.
397
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2. Coal Slurry Pipelines
The use of slurry pipelines will not drastically alter the
materials and equipment requirements for coal transport. Indeed, the
Project Independence analysis concluded that slurry pipelines "... are
not going to offer major savings in total dollar investment, steel or in
labor."4 However, they may drastically alter the institutional structure
of the coal transportation industry. (See Chapter 19.)
F. Geographical Distribution of Sectors Supplying Synthetic Liquid
Fuels Industry
The impacts of rapid development of coal and oil shale resources to
make synthetic liquid fuels will extend to most of the major manufactur-
ing areas of the United States. However, the magnitude of the impacts
is not likely to be large compared with the total economic activity in
an area—in contrast to the situation in western mining areas where
rapid growth rates are expected because of the small current base
population.
1. Mining and Construction Equipment
Firms manufacturing mining and construction equipment will be
considered together, since many construction equipment items, such as
power shovels and front-end loaders, are used by the coal mining (and
future oil shale) industry.
Two-thirds of the total employment in the construction machin-
ery (SIC 3531) and mining machinery (SIC 3532) industries is located in
the 6 states listed in Table 11-4. Within these states, plants are con-
centrated in the vicinity of Chicago, Cleveland, and Milwaukee; smaller
metropolitan areas of importance in Illinois are Peoria and Springfield;
and in Ohio, Bucyrus and Marion. The manufacture of mining equipment is
398
-------
a much smaller industry having only 22,000 employees versus 132,000 for
construction equipment. Only four states are major producers—Ohio, Wis-
consin, West Virginia, and Pennsylvania. As coal mining in the West
grows, some new plants will be opened. For example, Bucyrus Erie, one
of the three firms that manufacture walking draglines, has opened a
plant in Pocatello, Idaho.
Table 11-4
EMPLOYMENT IN CONSTRUCTION EQUIPMENT AND MINING
EQUIPMENT INDUSTRIES BY STATE, 1972
Employment
(thousands of employees)
State
Illinois
Ohio
Iowa
Wisconsin
Pennsylvania
West Virginia
Total U.S.
Construction
Equipment
45.7
13.7
12.1
10.7
5.9
n.a .
132.1
Mining
Equipment
0.9
2.2
n.a.*
2.8
5.0f
1.8
21.7
*n.a. = not available.
tEstimated for this study.
Source: Dept. of Commerce, Bureau of the Census,
1972 Census of Manufacturers.
There are a few items of mining equipment that are currently
produced by a limited number of firms. Two prominent examples are drag-
lines and continuous miners having, respectively, only three and five
399
-------
producing firms. A third example is off-highway trucks; the 1974 Buying
Directory of Coal Age lists 20 manufacturers, but only 10 are major fac-
tors in the manufacture of large coal hauling trucks used at surface
mines.
2. Explosives
Approximately 45 percent of the U.S. output of explosives is
used by the coal mining industry, and the vast majority (96 percent) is
consumed by surface mines.2 In 1967, the eight largest companies ac-
counted for 91 percent of total shipments. The only significant con-
centration of plants is in New Jersey, where Hercules, Inc., has three
plants and duPont has one.
3. Railroad Equipment
The manufacture of and market for locomotives in the United
States is shared by General Electric Co., and the Electro Motive Division
of General Motors Corp., with plants located at Erie, Pennsylvania, and
Chicago, Illinois, respectively. GM captured over 75 percent of domes-
tic orders in 1974, but GE supplied 100 percent of the foreign orders
for locomotives.5
Freight cars are manufactured by several companies, including
divisions of the railroads themselves. On December 1, 1974, order back-
log stood at nearly 91,000 cars.5 Open hopper cars suitable for coal
represented 27 percent of this backlog, although they constitute only
20 percent of the total current fleet of cars. Thus, the fraction of
hopper cars (both open and covered) in the freight car fleet is
increasing.
Ten firms dominate the freight car manufacturing industry, but
not all of them manufacture open hopper cars.8 The conversion of other
400
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car production lines to coal hopper cars could be accomplished readily
if demand warranted. Moreover, Pullman-Standard, a major manufacturer
of coal cars, has recently completed a new production line in Butler,
Pennsylvania (employing 3,000), to make hopper cars for the Burlington
Northern; this company is planning a similar production line at its
plant in Bessemer, Alabama.6
The impact of increased demand for railroad equipment will
most likely be concentrated in current producing areas. These are the
Chicago-Gary-Hammond region of Illinois and Indiana and medium-sized
towns in the western Pennsylvania region. These Pennsylvania producers
are all within the sphere of influence of Pittsburgh (although not in
the SMSA itself). Other regions that can expect impacts less concen-
trated than the above are St. Louis, Missouri; Seattle, Washington; and
Bessemer, Alabama (near Birmingham).
4. Steel
In the above discussion of the relationship of energy growth
and steel demand, the main conclusion was that energy-related steel
demand will be a relatively small portion of total capacity. Conse-
quently, the geographical impacts will be minor and can only be dis-
cussed in general terms. Assuming no rapid shutdown of aging facili-
ties to meet environmental regulations, the current steel producing
centers will probably be dominant to the end of the century. These
major production centers are Pittsburgh, Pennsylvania; E. Chicago/Gary,
Indiana; Baltimore, Maryland; Buffalo, New York; and Youngstown, Ohio.
All are in highly developed metropolitan economies, so that any growth
will have little percentage impact. If traditional steel markets di-
minish in the future (such as might result from smaller cars using in-
creased fractions of plastic), then energy-derived demand could help
to maintain.steel industry output and employment. In general, however,
401
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the state of the steel industry will depend more on the nation's overall
economic strength than on demand derived from energy industries.
5. Summary
Although little can be said to pinpoint future changes in the
locational patterns of the four industries that are important to the
future development of coal resources, it is unlikely that any rapid
changes will take place. Heavy industrial centers in the United States
have developed where raw materials, labor force, energy, and transpor-
tation are available; once established, institutional inertia slows the
pace of change.
For the most part, the supplying industries discussed through-
out this paper are located in a crescent-shaped region around the south-
ern edge of the Great Lakes, stretching from Milwaukee on the west to
Pittsburgh, as shown in Figure 11-2. Historically, this is the region
that has supported coal mining and heavy industry, and it appears that
it will continue to do so in the future.
402
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'.
,
I COLORADO ' 1
I
NOTF : BASED ON 1967 INPUT/OUTPUT DATA
OF THE UNITED STATES ECONOMY
FIGURE 11-2. PRIMARY CONCENTRATION OF MAJOR INDUSTRIAL SECTORS EXPECTED
TO SUPPLY THE COAL AND OIL SHALE INDUSTRY
-------
Appendix A
ESTIMATION OF DEMAND FOR WALKING DRAGLINES
404
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Appendix A
ESTIMATION OF DEMAND FOR WALKING DRAGLINES
Using data from the MEC Task Force and assuming sufficient mate-
rials are available, as shown in Table A-l, about 400 draglines should
be available from 1975 to 1990, even assuming no expansion beyond the
MEC estimate of 1980 production levels.
The number of surface coal mines that would have to be opened to
produce 1.8 billion tons of coal was estimated as follows. Underground
production is assumed to double from 0.3 billion tons in 1974 to 0.6
billion tons in 1990. The 1.2 billion tons of surface production was
assumed to come from 300 mines: 100 east of the Mississippi River,
each producing 2 million tons annually; and 200 western mines, each
producing 5 million tons annually. (The estimate of draglines needed
will be conservative if it is assumed that all these mines are new.)
Without delving into details concerning overburden thickness and
stripping ratios, a straightforward comparison shows that an average of
1.33 (400/300) draglines per mine could be produced to 1990. According
to a Bureau of Mines cost analysis,7 more than one dragline would be
necessary only in rare cases, such as a 5-million-ton per year lignite
mine in North Dakota. Most of the model mines described have only one
dragline for removing overburden and use power shovels for mining coal
and loading trucks. Moreover, in some mines, such as the open pit
Belle Ayre mine in Wyoming, draglines are not used.
However, a large increase in power shovel production cannot be ex-
pected since they are manufactured mainly by the same firms that make
walking draglines.
405
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Table A-l
ESTIMATION OF DRAGLINE PRODUCTION
1975-1990
Year(s)
1975
1976
1977-79
1980-89
Total produced 1975 to 1990
Exports @ 25%
Noncoal @ 20%
Total available for coal
Annual
Production
(units)
25
Total
Units
25
30
45
50
30
135
500
690
-175
-103
412
Source: Reference 2.
406
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REFERENCES
1. "input-Output Structure of the U.S. Economy: 1967, Volume 3, Total
Requirements for Detailed Industries," U.S. Dept. of Commerce, Bureau
of Economic Analysis, Washington, D.C., U.S. Government Printing
Office (1974).
2. "Availabilities, Requirements, and Constraints on Materials, Equipment
and Construction," Federal Energy Administration, Project Independence
Blueprint, Final Task Report (November 1974).
3. "Synthetic Fuels from Coal," Federal Energy Administration, Project
Independence Blueprint, Final Task Report (November 1974).
4, "Project Independence Report," Federal Energy Administration (November
1974).
5. L. S. Miller, "Some Counter-Cyclical Optimism," Railway Age, p. 5
(January 27, 1975).
6. "Pullman Delivers First of 'New Family' Open-Tops," Railway Age,
p. 23 (February 24, 1975).
7. "Cost Analyses of Model Mines for Strip Mining of Coal in the United
States," Bureau of Mines, Information Circular 8535, U.S. Government
Printing Office, Washington, D.C. (1972).
407
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12—ECONOMIC IMPACTS IN RESOURCE DEVELOPMENT REGIONS
By John W. Ryan
A. Introduction
The development of oil shale and coal resources for synthetic liq-
uid fuels will create employment opportunities at mines and processing
facilities. In the Midwest, such employment opportunities will result
in relatively little population migration because of the underemployment
of the existing labor force and existence of a substantial base popula-
tion. In the Northern Great Plains and the Rocky Mountain West, however,
the indigenous population is not nearly sufficient to meet the labor de-
mand. The result will be a large immigration into the relatively small
towns of the western coal and oil shale areas. Judging from past oil
and uranium booms, as well as the present beginnings of a coal boom, the
influx of new workers and their families will cause substantial economic
changes.
The purpose of this paper is to describe the economic impacts of
such induced growth under various assumptions. The analysis concen-
trates on two western regions: (1) for coal, Campbell County, Wyoming,
the center of the Powder River Basin coal field and the location of
nearly all the strip-minable coal in the Basin; and (2) for oil shale,
Rio Blanco and Garfield counties, Colorado, the counties that encompass
most of the high-grade oil shale resources in the Piceance Basin. Im-
pacts in these regions will be compared and contrasted with the expected
impacts in other resource regions, namely, western North Dakota, south-
ern Illinois/western Kentucky, and Appalachia. The location of all these
regions is outlined in Figure 12-1.
408
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COLORADO
GARFIELD • DENVER
MESA
ILLINOIS
ST. LOUIS,
ST. CLAI
PERRY
NORTH DAKOTA
• MINOT
MCLEAN
LIVER
ME!ER •8ISMARK
WYOMING
CAMPBELL
CASPER
KENTUCKY
WILLIAMSON
HUNTINGTON
ARTIN
PIKE
FIGURE 12-1. COUNTIES USED FOR ECONOMIC IMPACT DISCUSSIONS
409
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B. Regional Employment Growth
1. Background Theory
The classical approach to regional economics is to distinguish
between basic or export employment and secondary employment. The theory
is that basic employment generates income by exporting goods to other
regions;* this income is then able to support local service industries,
such as wholesale and retail trade. Regional growth projections are
made by projecting basic employment and then adding secondary employment
based on a ratio of secondary to basic employment. Population totals
are derived by assuming some labor force participation rate or average
family size.
2. Population Estimates for Coal Development
The population that is likely to result from coal mining and
processing has been estimated for portions of the western coal regions
in many previous reports.1"5 The method of approach is basically the
same in all cases. Employment in coal mining and related activities
(gasification, liquefaction, and power generation) is estimated on the
basis of the number and sizes of facilities. The employment in service
or derivative sectors is estimated using a ratio of total employment to
basic coal-related employment. In one instance,8 income is used as the
basis for the predictive relationship. Total population is then esti-
mated using labor force participation ratios and family size. Several
refinements are possible:
• Secondary-to-basic employment ratios may be distinguished
by basic industry: mining, manufacturing, construction.
*Additional income is generated by imports of mortgage money to finance
construction.
410
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• Secondary-to-basic employment ratios may be distinguished
by size of town (i.e., scale effects are assumed to exist).
• Secondary-to-basic employment ratios may differ by the
distance between the basic industry and trade centers.
• Labor force participation rates may be broken down by age
and sex to allow for varying age characteristics of the
immigrants.
The result is that by judicious choice of ratios, a wide range
of total population estimates can result from any assumed basic employ-
ment number. Thus the casual use of multipliers or ratios derived from
historical relationships in the study areas has drawbacks.
Additional forecasting difficulties arise because there are
problems in defining the base area and obtaining data. Regional econ-
omies rarely adhere to the political boundaries for which data are
usually published. Another problem—one that often confronts local
planning officials—is accounting for time lags in growth. Secondary
development often lags growth in basic industries because service in-
dustries are usually not attracted to an area until the initial employ-
ment growth has already occurred. On rare occasions—as in the recent
Alaskan oil finds—substantial investments in service industries are
made before large-scale primary development occurs.
The large construction projects usually contribute another
element of uncertainty because much construction labor is transient and
creates service industry demands resulting from its family and age char-
acteristics that are different from those of permanent residents.
3. Coal-Related Development in Campbell County, Wyoming
The population in Campbell County for 1975 to 2000 was calcu-
lated for two basic scenarios:
411
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• Maximum credible implementation (MCI) of synthetic liquid
fuels technology.
• Growth constrained (GC) at 5 percent compound growth rate
annually.
In the growth-constrained scenario, five combinations of coal mines and
processing facilities were outlined to assess the implications of peaks
in the construction labor force:
• Mines only—coal exported from the county
• Mines plus large and small liquefaction plants
• Mines plus small liquefaction plants
• Mines plus methanol plants—3-year construction periods
• Mines plus methanol plants—5-year construction periods.
For these cases, the coal development that can be accommodated
within various growth constraints is depicted in Figure 22-2 through
22-7 (Chapter 22). Figure 22-2 shows the growth in Campbell County
population implied by the maximum credible implementation (MCI) sce-
nario. The coal mines and facilities for the MCI scenario were derived
by assigning 25 percent of the Wyoming portion of the MCI to Campbell
County.
First, the base population of Campbell County was estimated
at 17,000 in 1975, using Bureau of Census data and information from dis-
cussions with county planning officials. Then, a 5 percent annual growth
rate curve was derived as shown in Figures 22-2 through 22-7. The popu-
lation levels consistent with a 5 percent growth rate were divided by a
population-to-basic employment multiplier of 6.5 to determine the basic
construction and plant operating employment possible each year. Then an
appropriate level of coal mines and processing facilities was devised
that would (more or less) utilize the basic employment allotment for the
year.
412
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A ratio of 6.5 for total population-to-basic employment is a
reasonable approximation of the product of (1) primary-to-total employ-
ment ratio, and (2) population-to-total employment ratio (the inverse of
the labor force participation rate). For example, a primary-to-total
employment ratio of 2.6 and a population-to-total employment ratio of
2.5 are multiplied to obtain a composite multiplier of 6.5. According
to data from Matson and Studer,6 the 1970 multiplier for Campbell County
was 5.9. Matson and Studer use multipliers in the 6.7 to 7.3 range in
their growth scenarios for Campbell County. The higher ratios used for
future growth are justified because the anticipated population influx
will be able to support a wider range of service activities than is
currently available in Campbell County. Thus, by the standards of Mat-
son and Studer, the population growth forecasts of this study are con-
servative; or conversely, the level of resource development that is con-
sistent with a 5 percent growth rate is optimistic.
Figures 22-2 to 22-7 show only coal processing facilities to
make synthetic liquid fuels. But there are good correspondences in
plant sizes that will allow these scenarios to depict other coal devel-
opment as well. In particular, a 100,000-B/D liquefaction plant has the
same effect as a 250 million cubic-foot-per-day coal gasification plant;
the permanent labor force at a 1,000-MW, coal-fired, electric generating
plant closely matches that of a 5 million ton-per-year coal mine. How-
ever, the construction force for a 1,000-MW electric generating station
would be much larger than for a mine and the work would be spread over
a 5-year period rather than a 2-year period.
There is some room for alteration in the scenarios shown in
Figure 22-2 to 22-6 concerning the timing of new construction projects
depending on what short-term growth rates one might be willing to
accept. Figures 22-2 and 22-6 for large liquefaction or methanol plants
illustrate the conflict between the objectives of local planning agencies
413
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and resource developers. Planners want slow, smooth changes in popula-
tion levels so that the community can develop necessary facilities for
a growing population. On the other hand, investors want to minimize
no-income construction time so that revenue producing operations can
begin as soon as possible. Construction delays increase the interest
costs on invested funds and are especially costly as a project nears
completion when the most capital is tied up. The economics of these
large-scale developments imply that communities must have mechanisms
to prepare for short periods of rapid growth.
The obvious economic impact on Campbell County of 5 percent
annual population growth will be to transform it from a relatively rural
area with less than 2,000 basic employees in 1972 to a much more highly
industrialized area with roughly 8,500 basic employees in 2000, and a
total population of 56,000. Agricultural employment is already in de-
cline and a gradual decline is expected to continue until agriculture
becomes an insignificant factor in the county's economy in 2000. At
that time, agricultural employment will number approximately 500, less
than one percent of the population.
The other basic employment would be concentrated in the coal
mining and processing industries. Some small manufacturing operations
would probably be established to provide repair parts for the construc-
tion and mining industries, such as machine shops that make special
order items. No large-scale influx of manufacturing plants is likely
to follow coal development since many of the regional disadvantages
(such as distance to markets and shortages of skilled labor) that dis-
couraged past development will remain.
At present, Gillette is the only community of note in Campbell
County; its population in 1975 is estimated at 13,000. It will continue
to serve as the economic hub of the county; however, it is possible that
414
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a new community will be built in the southern area of the county as coal
development in that region proceeds. As the county grows, more whole-
salers and warehousing would probably locate in Gillette; however, major
support would be expected to continue from Casper 130 miles to the south
(the largest city in Wyoming) and from Denver, Colorado. The only other
regional trading center near Gillette is Billings, Montana; impacts
there would accrue from growth in both the Wyoming and the Montana por-
tions of the Powder River Basin. Alone, growth in Campbell County would
not exert any appreciable impact on Billings.
In the environmental impact studies recently prepared for re-
source developments in the area, the construction phase is carefully
distinguished from the operation phase of proposed facilities. This is
a very important distinction for geographically isolated, one-time de-
velopments, because the construction work force attracted to rural areas
has different family characteristics and is more transient than operat-
ing labor. However, the almost continuous development patterns envi-
sioned in the MCI should be able to attract and hold a stable construc-
tion labor force. Construction activity will still have peaks, but
substantial construction activity will exist continuously.
Secondary construction activity will be required for the hous-
ing, commercial, and public works needed for new population. In the
past, because of time and cost advantages, mobile homes have been used
to fill a large part of the demand for new housing units. Consequently,
the mobile home industry in the area will probably grow.
4. Oil Shale Development in the Piceance Basin, Colorado
Mesa, Garfield, and Rio Blanco counties in northwestern Col-
orado (see Figure 12-1) are expected to receive the bulk of the impacts
of any oil shale development in the region. The 1970 total and urban
population are shown in Table 12-1.
415
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Table 12-1
POPULATION IN COLORADO OIL SHALE REGION, 1970
County
Mesa
Garfield
Rio Blanco
1970
Population
54,400
14,800
4,800
Percent
Urban
47 . 8%
27.7
0.0
Total 74,000 40.7%
Grand Junction with 20,200 people in Mesa County is the only
city of note in the region. It lies on Interstate 70 and is some dis-
tance from the center of the oil shale deposits. Farther up the Col-
orado River in Garfield County are Glenwood Springs with 4,100 people
in 1970 and Rifle with 2,150. Meeker in Rio Blanco County had 1,600
people in 1970 and is not considered urban by Census Bureau definition.
Primary development is expected to concentrate in Garfield
and Rio Blanco counties because it is there that the richest oil shale
lies. Access to and from the center of the mining/processing region to
Grand Junction will be about 50 or 60 miles over some very rugged ter-
rain. Consequently, it is expected that Mesa County will become only a
secondary trading center for the region. Towards the end of the century,
under pressure of development, the access from Grand Junction to the
producing region would probably be improved by new roads.
Population growth of 5 percent annually would raise the com-
bined 1975 population of Garfield and Rio Blanco counties from 23,000
in 1975 to 79,000 in 2000. Shale oil production would be 400,000 B/D
according to a 10 percent growth scenario depicted in Chapter 22. Under
MCI, shale oil output is predicted to reach 2 million B/D in 2000. If
416
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the associated population were restricted to Garfield and Rio Blanco
counties, the population growth rate would have to average 17 percent
annually. In reality, such a scenario would result in great disorder
because the existing transportation network and other elements of the
infrastructure could not expand as rapidly as needed to accommodate such
growth.
Currently, Garfield and Rio Blanco counties export agricul-
tural and mining products and depend on other regions for wholesale and
retail goods. New development in Garfield County is expected to result
in population increases primarily in the existing small communities along
the Colorado River—Glenwood Springs, New Castle, Rifle, and Grand Val-
ley. The rugged topography of the area eliminates much of the county
from consideration for urban development; thus, future immigrants can
be expected to settle in much the same geographic pattern as the pres-
ent population. Of course, this may be altered should resource companies
decide to develop their own land for new communities.
Although some spillover effects from Garfield County would be
felt in Mesa County, there would be little spillover to Rio Blanco
County because of the poor existing highway network (constrained by ter-
rain) . Denver, on the other side of the Rockies, is the center of the
major trading area, serving western Colorado, and has already begun to
feel the impact of the current interest in energy resources as companies
have established or enlarged regional offices. Distributive sectors will
be affected as development increases; however, the impact will be slight
until demonstration projects have proved the feasibility of oil shale
development.
Compared with Gillette, Wyoming, the economic impacts of re-
source development in Colorado will most likely be felt by several exist-
ing communities rather than only one. However, coordinated planning would
417
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be required to prevent one community from bearing the brunt of the ad-
verse impacts. Yet, because so much of the U.S. oil shale resources are
in this corner of Colorado, development would doubtless result in a con-
centration of impacts in just a small region. By contrast, coal devel-
opment will take place in many states from Appalachia to Utah; very
little such flexibility is possible for oil shale development—there
are other small reserves only in eastern Utah and southwest Wyoming.
Agriculture in this 3-county area of Colorado consists prima-
rily of livestock grazing. Thirteen percent of farm acreage is cropland
and lies in the valleys that are also most desirable for new housing.
Crop revenues in Rio Blanco and Garfield counties were $1.2 million in
1969—10 percent of total 1969 agricultural* revenues in those counties.
Whatever the level of development, there is likely to be considerable
impact on the small amount of existing cropland, thereby insuring the
decline in agriculture.
C. Comparisons with Other Resource Regions
1. North Dakota Lignite
Western North Dakota contains considerable lignite reserves
that have been mined on a small scale for years. The local economy is
much like the areas of Wyoming and Colorado described above but with more
prosperous agriculture. Most counties in southwestern North Dakota lost
population between 1960 and 1970; many lost 20 percent or more. A large
fraction of the reserves in North Dakota lie in Dunn, McLean, Mercer,
and Oliver counties, having a total population of 24,600 in 1970. Their
collective population loss between 1960 and 1970 was over 5,000 or
*Livestock accounted for most of the other 90 percent.
418
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17 percent. The setting is basically rural, with a few small towns
sprinkled about; per capita income in the region was less than 75 per-
cent of the national average in 1970.
Development of lignite mines in Dunn, McLean, Mercer, and
Oliver counties will impact the current regional centers of Bismarck
and Minot; next in the hierarchy of trading centers is Minneapolis,
Minnesota, some 500 miles away. The state, local, and federal govern-
ments are the largest employers in the 4-county area, with over 35 per-
ry
cent of total employment in 1971; agriculture was roughly 10 percent
and declining. Impacts on agriculture will be greater than in the arid,
high plateau areas of Wyoming, because the land is more productive. In
1969, these 4 counties accounted for 6 percent of the value of agricul-
tural products sold in North Dakota; approximately half of the sales
came from crops. Since most lignite is surface mined, cropland will be
disrupted in North Dakota, and the impacts of resource development on
agriculture can be expected to be more costly than in Wyoming or Colorado,
Lignite development will reverse the population decline in
these counties by providing jobs for the indigenous population as well
as to newcomers. In many ways, southwestern North Dakota is more amen-
able to development in general than Campbell County, Wyoming, because
transportation links with the Midwest are shorter. Nevertheless, in the
main, development over the foreseeable future is expected to be energy-
related because the disadvantages of remoteness tend to discourage other
industries from moving so far from (nonenergy) raw material sources and
markets.
2. Appalachian Coal Development
Discussion of economic impacts in the Appalachian region will
be based on the Big Sandy Area Development District (BSADD), which
419
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consists of the following 5 counties of eastern Kentucky: Floyd, John-
son, Magoffin, Martin, and Pike. Population in the BSADD declined 12
percent between 1960 and 1970 to 134,000. Unemployment in 1972 was
Q
9.3 percent versus 3.6 percent for Kentucky as a whole. Mining employ-
ment stood at 8,000 in 1970, down from 20,000 in 1950. The situation
has been reversed in 1974 due to surging demand for coal; in Martin
County, for example, the unemployment rate has declined from 8.4 percent
in 1972 to 3.2 percent in January 1975.9 Employment in agriculture and
forestry has all but disappeared—in 1970 it stood at 338 or 4 percent
of the 1950 level. Sectors registering employment gains between 1960
and 1970 were construction, manufacturing, and public administration.8
Transfer payments, such as social security and welfare benefits, are a
large source of personal income in the area; in Martin County alone,
26 percent of per capita income came from transfer payments in 1973.9
Compared with the impacts of expanded coal mining in western
coal regions, impacts in BSADD will be less disrupting because of the
larger existing base population. In addition, the region has the basic
infrastructure to provide services for a larger population, as well as
service industries for coal mining equipment repair. Because the rural
population is spread about in small clusters, expanded coal mining is
disrupting existing population differently than in the West. Mining
operations are carried out closer to residences, making them vulnerable
to noise and shock from blasting, to say nothing of landslides. In ad-
dition, coal is sometimes hauled by truck on county roads, increasing
maintenance costs and decreasing safety.
The outlook for a diversified economy in the BSADD is not much
improved by coal development. The area will remain relatively remote
unless rail and highway links are improved. In addition, areas suitable
for development of industrial parks are limited due to the lack of level
land. Land ownership and use are complicated because mineral rights have
420
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often been sold separately from surface rights. Eastern Kentucky coun-
ties receive major wholesaling and financial support from the Ashland,
Kentucky-Huntington, West Virginia, metropolitan area. It is a major
support center for coal mining, and any additional mining activity for
synthetic fuels is unlikely to have a large fractional impact.
3. Southern Illinois Coal Regions
The economy of counties in southern Illinois provide a distinct
contrast to the regions discussed above. Much of the remaining coal re-
serves lie in the 6 counties listed in Table 12-2 and outlined in Fig-
ure 12-1. Perry and St. Clair each have over one billion tons of strip-
pable reserves and another billion tons of deep reserves remaining.10
The remaining 4 counties combined have over 17 billion tons of deep re-
serves remaining. St. Clair, Washington, and Franklin counties were
identified in a recent study13 as likely sites for coal gasification
plants. These same counties could serve as sites for coal liquefaction
plants.
Compared with other regions discussed above, the area is rela-
tively urban and has a relatively large population. The high urban pop-
ulation in St. Clair County shown in Table 12-2 is due to the city of
East St. Louis, a suburb of St. Louis, Missouri; however, the eastern
areas of the county are more rural in character. Of the other counties,
only Washington is more than 50 percent rural; together, the 6 counties
presently contain 437,500 people—far more than in the other regions
discussed.
Except for Washington, the counties are currently major pro-
ducers of coal; collectively, they accounted for 57 percent of the Illi-
noise production in 1972.1:L Their existing reserves will insure that
this role will continue into the future.
421
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Table 12-2
POPULATION AND COAL PRODUCTION IN SELECTED
COUNTIES OF SOUTHERN ILLINOIS
1972 Coal
County
Franklin
Jefferson
Perry
St. Clair
Washington
Williamson
1970
Population
38,300
31,400
19,800
285,200
13 , 800
49 , 000
Rural
(percent)
50%
49
49
17
78
43%
Operating
Coal Mines
(1973)
3
4
5
2
0
6
Production
Millions
of Tons
7.3
7.4
11.2
7.3
0.0
4.0
Rank in
State
4
2
1
3
NR*
7
*NR = no rank.
Sources: Bureau of the Census, Census of Population 1970, "General
Characteristics" - Illinois.
Reference 10 and 11.
Agricultural output in southern Illinois consists of both
livestock and crops—corn and soybeans. However, the 6 counties are
not major producers—accounting for only 1 percent of the Illinois corn
output and 3 percent of soybeans in 1972.11~1S In Franklin, Jefferson,
Perry, Washington, and Williamson counties, 1972 yields per acre of
both crops were 80 percent of the statewide average.11"1 Further de-
velopment of Illinois coal will disrupt land more valuable per acre than
in the other resource regions discussed; however, it will not be prime
agricultural land; and as discussed in other working papers, there is
good prospect for reclamation.
422
-------
Even ignoring St. Clair County, the population impacts will be
considerably less severe on a percentage basis than in the West. Devel-
oped urban areas already exist in these counties, and basic economic ac-
tivity is more diversified than other resource regions discussed. In
Franklin, Jefferson, Perry, Washington, and Williamson counties combined,
manufacturing employment was 21 percent of total employment in 1970.
Service industries are currently well established in the region so that
secondary employment multipliers for future energy developments should
be lower than places like Gillette, Wyoming. St. Louis, Missouri, is
the nearest large metropolitan area and serves as a manufacturing, whole-
sale, and service center for southern Illinois.
D. Overview
In differentiating the impacts of resource development for typical
regions, the obvious conclusion is that economic impacts in western
regions will tend to be greater than elsewhere because of the smaller
economic base, which requires substantial secondary development and
structural change to accommodate even low levels of development. Growth
constraints would help to mitigate any adverse consequences by allowing
local areas to plan for change and adjust as circumstances dictate. By
conventional measures of economic welfare (such as personal income and
gross area product), economic well-being would rise in the regions dis-
cussed. However, by more comprehensive, but more ambiguous, measures
(such as the "quality of life"), the direction of change is not so clear.
Production of liquid fuels from coal and oil shale will reorder the
economic hierarchy of communities because most of resource regions dis-
cussed would not grow economically otherwise. The changes that will oc-
cur manifest a process that has been taking place throughout history;
namely, the comparative economic attraction and advantage of regions and
nations depends on their resources and the needs of human activity.
423
-------
Today, the need is for energy, and, worldwide, the regions that have
energy sources are growing in economic power.
As resource concentrations are depleted until they are no longer
profitable to exploit, regions once rich in resources begin to decline
in economic power, and population is attracted elsewhere. Often, such
decline is gradual. Appalachia is only now beginning an upswing after
a long period of decline in coal consumption persisting since World
War II. Many areas of the West still exhibit remnants of the gold and
silver industries of the last century. Boom and bust cycles are common;
Gillette, Wyoming, itself went through a rapid cycle in the 1960s, caused
by oil exploration. Thus, there is a need to consider the longer run
consequences and, in particular, the likelihood of a rapid decline in
economic activity caused perhaps by a technological breakthrough in
nuclear or solar power that reduces the importance of coal resources.
In decline, the West is likely to have a considerable problem be-
cause, to provide civic services for an expanding population, localities
will probably have to resort to bonded indebtedness, which might well
still exist when the boom is over. If decline comes too soon or is
rapid, the eroding tax base could force communities into bankruptcy.
This does not mean that these synthetic fuel developments should not
occur, but it does mean that the planning process must include not only
an expansion phase but have built-in capability for an orderly con-
traction phase should the need arise.
424
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REFERENCES
1. "Final Environmental Impact Statement: Proposed Development of
Coal Resources in the Eastern Powder River Basin of Wyoming,"
Volume I, Dept. of Agriculture, Interstate Commerce Commission,
Dept. of the Interior (October 1974).
2. Polzin, Paul, "water Use and Coal Development in Eastern Montana,"
University of Montana, Missoula (November 1974).
3. "Draft Environmental Impact Statement on Colstrip Electric Generat-
ing Units 3 & 4, 500 Kilovolt Transmission Lines & Associated
Facilities," Vol. 1,- Summary, Energy Planning Division, Montana
State Department of Natural Resources and Conservation, Helena,
Montana (November 1974).
4. Bender, Lloyd D. and Robert Coltrane, "Ancillary Employment Multi-
pliers for the Northern Plains Province," Economic Research Serv-
ice, Montana State University, Bozeman, Montana (January 1975).
5. Northern Great Plains Resource Program, Draft Report, Denver,
Colorado (September 1974).
6. Matson, Roger A. and Jeannette B. Studer, "Energy Resources Devel-
opment in Wyoming's Powder River Basin: An Assessment of Potential
Social and Economic Impacts," Revised Draft, Water Resources Re-
search Institute, University of Wyoming (April 23, 1974).
7. Leholm, Arlen et al., "Local Impacts of Energy Resources Development
in the Northern Great Plains," Interim Report, North Dakota State
University, Fargo, North Dakota (April 1974).
8. Kentucky Development Data Series, Big Sandy Area Development Dis-
trict, Volume XI, Office for Local Government, Commonwealth of
Kentucky (April 1973).
9. Arnold, Bob, "Renaissance of Coal Brings Booming Days to Appalachian
Hills," Wall Street Journal (April 8, 1975).
425
-------
10. Hopkins, M. E., and J. A. Simon, "Coal Resources of Illinois,"
Illinois Mineral Note 53, Illinois State Geological Survey,
Urbana, Illinois (January 1974).
11. "Statistical Abstract 1973," State of Illinois Bureau of the Budget,
Springfield, Illinois (1973).
12. Hoglund, B. M. and J. G. Asbury, "Potential Sites for Coal Gasifi-
cation in Illinois," Illinois Institute for Environmental Quality
(October 1974).
426
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13—COMPARATIVE ENVIRONMENTAL EFFECTS OF COAL STRIP MINING
By Edward M. Dickson
A. Introduction
The question of strip or surface mining inevitably arises in any
discussion of the impacts of synthetic fuels production from coal or oil
shale.1-7 The methods and environmental effects of these mining activi-
ties are very different and must be considered separately. The practice
of strip mining for coal -and the potential and procedures for reclamation
also differ so much that it is necessary to discuss this issue on a re-
gional basis. For this report we have selected three areas with abundant
coal resources for illustration (see Figures 13-1 to 13-3):
• Appalachian coal as typified by West Virginia and eastern
Kentucky.
• Midwestern coal as typified by the coal field in southern
Illinois, western Kentucky, and western Indiana.
• Western coal as typified by the Powder River Basin in northeast
Wyoming.
These three suffice to demonstrate that there are few valid generaliza-
tions about strip mining for coal.
These days almost any discussion of coal strip mining becomes emo-
tionally charged and polarized into camps of proponents and opponents
and usually includes reasoning by questionable analogies. In particular,
industry emphasis is often placed on the reclamation success in the Mid-
west as a model for the arid West or on the steep slopes of Appalachia,
while environmentalists have used imagery describing the aesthetic impact
of the disturbed and unreclaimed lands in Appalachia to convey a forecast
427
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PENM ANTHRACITE REGION
AMINItOINt REGION
FORT UNION REGION
to
oo
NORTHERN REGION
WESTERN REGION
RATON MESA REGION
SOUTHWESTERN REGION
APPALACHIAN RES10I
ATLANTIC
COAST REGION
ADAPTED FROM "DRAFT ENVIRONMENTAL IMPACT STATEMENT ^ PROPOSED FEDERAL COAL LEASING PROGRAM," U.S. DEPARTMENT OF THE
INTERIOR (U.S. GOVERNMENT PRINTING OFFICE, WASHINGTON D.C.) 1974
FIGURE 13-1. NORTHERN GREAT
PLAINS PROVINCE
FIGURE 13-2. INTERIOR PROVINCE
FIGURE 13-3. EASTERN PROVINCE
-------
of the effect in Wyoming. Neither is appropriate. Moreover, the very
language chosen by the opposing groups is indicative of their perceptions
and biases. The following matrix illustrates how the connotations of
language depend on the user and his intentions.
Concept
A mine consisting of tunnels
and shafts
A mine consisting of a broad
shallow hole
Material that lies over the
coal when still in place
The same material when dis-
placed from above the coal
Coal Industry Environmentalists
Deep mine
Overburden
Spoil
Underground mine
Surface mine Strip mine
Soil
Spoil
Waste
Spoil
For example, to the lay person, a "surface" mine sounds more benign and
less violent than a "strip" mine; "underground" mine conveys, in con-
trast to a "strip" mine, the image of a tidy, nondisruptive activity.
Likewise, "overburden" has a built-in disregard for distinctions such as
topsoil, subsoil, and bed-rock and conveys the notion that it is all
merely something to be moved out of the way. Without attempting to take
sides or further dispute the accuracy of the terms, this chapter uses
the following technology for the four concepts outlined because we feel
that it offers the most succinct phraseology:
• Underground mine
• Strip mine
• Overburden
• Spoil.
The following pages first describe modern mining in the three regions
and then describe reclamation potential in the regions. It should be
429
-------
noted, however, that in the past, and even today, the land recontouring
activity described is not always performed by some companies.
B. Mining and Environmental Effects
1. Appalachia
The coal country of Appalachia is characterized by low moun-
tains and hills with many valleys and hollows. The coal lies in a plane
that is more or less level, but geological weathering over the ages has
cut away the landscape so that the valley floors lie beneath the coal
seam. As a result, the coal seam is present in the hills but not in the
valley bottoms. The area is well watered, receiving about 45 (110 cm)
inches of precipitation annually, almost evenly spread throughout the
year. Winters are cold and snowy, and summers are humid with frequent
rains.8'10
Figure 13-4 shows a cross-sectional view of typical coal de-
posits in Appalachia. The coal often outcrops on the side of a hill, and
usually is in seams 3 to 5 ft (1 to 2 m) thick and overlain by 100 ft
(30 m) or more of material. In general, strip mining is uneconomic
when the overburden is greater than about 10 times the thickness of the
coal seam. This is measured by the "stripping ratio." Thus, strip
mining the coal from the side of the hill penetrates only a small dis-
tance into the hillside, and the extraction follows the contours of the
hillsides. Thus, strip mining in Appalachia is usually termed "contour
mining." The origin of other common terminology such as "highwall" and
*The stripping ratio is actually defined in terms of the volume (cubic
yards) of overburden per ton of coal.
430
-------
I
me"
ADAPTED FROM REFERENCE 8
FIGURE 13-4. TYPICAL CROSS SECTION (DENTS RUN WATERSHED,
MONONGALIA CO., W. VIRGINA)
"bench" can be seen from Figures 13-5 and 13-6. Contour mining is, by
far, the most common form of coal strip mining in the East. Between
80-90 percent of the coal is usually recovered by this method.9
"Auger" mining is an adjunct to contour mining designed to
increase the coal obtained from a given unit of stripping. Once the
stripping ratio becomes too high to justify further excavation of the
hillside, the coal on the bench is removed leaving a highwall with an
exposed coal seam. Large augers are then used to bore horizontally into
the coal seam still lying under the hill for distances of 120 to 150 ft
(35 to 45 m), as shown in Figure 13-7. To lessen the chance of collapse
of the overburden, these holes are separated by 1/6 an auger diameter.
Because such a long auger sags as it penetrates the hill, the diameter
auger used is about 30 percent smaller than the seam thickness. Wherever
the highwall executes a turn, pie shape segments are left unaugered.
431
-------
OVERBURDEN
HIGHWALL
BENCH
SPOILS
ADAPTED FROM REFERENCE 12
FIGURE 13-5. DIAGRAM OF A CONTOUR MINE
I. S/7E PREPARATION
2. DRILLING 8, BLASTING OVERBURDEN
3. REMOVAL OF OVERBURDEN
4. EXCAVATING A LOADING COAL
SOURCE' REFERENCE 9
FIGURE 13-6. CONTOUR STRIP MINING
432
-------
LONGITUDINAL SECTION OF AN AUGER HOLE
z
*
u
HIGH
WALL
HOLE DIAMETER = 2/3 X COAL SEAM-
SPACING OF AUGER
HOLES. DRILLED FROM THE HIGHWALL
«/»
10
X. Note: Unmined coal is left around
— holes and wasted.
ii <
X Q
1/6 X
SOURCE: REFERENCE 9
FIGURE 13-7. AUGER HOLE SECTION AND SPACING
Clearly, auger mining leaves behind a large portion (about 65 percent)
of the coal penetrated.9
As might be expected from Figures 13-5 to 13-7 and the config-
uration of contour and auger mining coupled with abundant precipitation
is an open invitation for severe environmental problems in Appalachia.
In the past, when no significant reclamation attempt was made, great
environmental disruption has indeed resulted from contour mining. These
impacts have included
433
-------
• Sheet erosion
• Sliding of unstable spoil ranks
• Acid drainage
• Siltation of streams
• Loss of vegetative cover.
In addition, there has been significant aesthetic loss from the creation
of highwalls, benches, and spoil banks in the place of wooded hillsides
and turbid or acidic streams in the place of clear streams.8'9'ia
Once the soil is exposed, erosion of the highwall, the benches,
and the spoil bank occurs. However, with no attempt to contour, terrace,
or compact the spoil bank, the most severe erosion occurs on the bank of
loose spoil. Large volumes of silt frequently move into streams by this
mechanism or by the collapse and sliding of portions of the bank. The
rate of erosion is enhanced by the increased runoff rate caused by the
removal of vegetation, topsoil (however thin), and plant litter, which
normally serve to reduce the impact of rain and to absorb precipitation
slowing runoff. Thus, unreclaimed contour mining activity serves to
increase the amount of runoff, to compress it in a shorter time, and to
increase the turbidity of the runoff streams. As a result, the water
quality effects of contour mining are felt for large distances
downstream.8 »9•11
Acid mine drainage is another, and very severe, cause of water
quality degradation in or downstream from areas where contour mining is
practiced. Handling of the overburden results in the exposure and scat-
tering of pyritic material (FeS ). Exposed to moisture and oxygen, chemi-
3
cal reactions convert the pyrite to sulfuric acid and dissolved iron
sulfate. In addition, other metals, notably manganese, copper, and zinc,
dissolve in the acid water. Few plants and no fish can survive in this
acid water that also corrodes immersed structures. The cumulative effect
434
-------
of acid mine drainage on streams has often been so great that beneficial
uses of the water are greatly impaired.8'9'11
When the spoil is heaped on the downhill side of the bench, it
smothers the vegetation under the spoil bank. Subsequent erosion and
sliding disrupt the vegetation further downhill. Thus, contour mining
disturbs more vegetation than that immediately over the coal. In spite
of the abundant moisture, the removal of topsoil, and frequently the
absence of other fertile soil on the spoil bank slows (for decades) the
natural establishment and succession of vegetation on the scarred hill-
side. Reestablishment of a natural and stable ecosystem without human
intervention is generally a poor prospect.
Access and haul roads also involve earthmoving disturbances.
In Appalachia, the serpentine aspect of contour mining and short period
of time spent mining in any particular spot requires frequent additions
and changes in roads. Since the use of these roads is short lived, they
are frequently poorly constructed and are an additional major source of
land surface disturbance and erosion.9
The thinness of the strippable coal deposits and their occur-
rence partway up the hillsides, means that, in Appalachia, large-scale
production of coal causes the disruption of many hillsides. As early as
1965, before strip mining became so common, there were already about
25,000 linear* miles (40,000 km) of disruption in Appalachia.9 It is no
wonder, then, that to many people the effect of strip mining on the
aesthetics of the countryside in Appalachia is appalling.
^Because contour mining results in a relatively narrow but long bench,
the use of linear rather than area measurement is appropriate. However,
in the West, area measurement is appropriate.
435
-------
2. Midwest and West
Mining operations in the relatively flat regions in the Mid-
west and West are quite different from those in Appalachia. In both
regions the coal seams lie in flat beds roughly parallel to the surface
although the thickness of the seam varies. The slight tilt of these
seams relative to the surface means that in places the coal has dipped
too deep to be mined economically with present stripping methods. Coal
occurs in the Midwest in multiple seams about 5 ft (2 m) thick, often
separated by "partings" 50 to 100 ft (15 to 30 m) thick. In the Powder
River Basin, seams are generally 30 to 100 ft (10 to 30 m) thick with
a few as much as 250 ft (75 m) thick. Because the current limit on the
stripping ratio is about 10/1, strip mining in the Midwest is restricted
to much shallower depths than in the Powder River Basin.9»12«13
The activity that characterizes strip mining in the Midwest
and part of the Powder River Basin is shown in Figures 13-8 and 13-9.
In some parts of the Powder River Basin the thick seams facilitate a
type of strip mining that resembles open pit or quarry operations (Fig-
ure 13-10). Because the nature of the terrain and coal deposit facili-
tates the complete mining of large tracts of land, both of these approaches
are called "area" mining. These methods recover about 95 percent of the
coal in the seams.9'12
Area strip mining is inherently less environmentally disruptive
than contour mining because it is efficient to place the overburden from
one cut in the hole left by the previous cut. Roads have a long useful
lifetime and are therefore well constructed. Moreover, the relative
*Such thick seams are not found everywhere in the West,
436
-------
ADAPTED FROM REFERENCE \2~
BENCH
FIGURE 13-8. DIAGRAM OF AN AREA MINE
A*.-. ,;. , , •-• ,,*,, „
f V -, r';; +,-
v-\"- . • -r-, • •'• ' •'• ,•- - „;;
STRIPPING BENCH —~
SOURCE- REFERENCE 9
FIGURE 13-9. AREA STRIP MINING WITH CONCURRENT RECLAMATION
437
-------
flatness of the terrain leads to less erosion of the roads, highwall,
and spoil pile. Nevertheless, without efforts to reclaim the land, the
result of area mining is the creation of a corrugated artificial terrain
caused by the heaping of spoil in rows for each cut. At the starting
edge of the area, a line of spoil remains piled on the surface of unmined
land while at the final edge of the area a trench and highwall remain.
Figures 13-9 and 13-11 show this very well. In open pit mining (Fig-
ure 13-10), the overburden from the initial large cut is either stored
in a pile or deposited in a depression nearby. Subsequent spoil is then
deposited in a mined-out part of the pit. At the end of mining, the
spoil from the initial cut is either returned to the pit or other spoil
is contoured to reduce the highwall. For thick coal seams, the reclaimed
Q 19
land surface is much lower than the original level. '
In the Midwest, although the coal has a high sulfur content and
the precipitation is high (about 40 inches or 100 cm per year), the for-
mation of acid drainage is less of a problem than in Appalachia.9 In
much of the West, however, especially the arid Powder River Basin, the
combination of very low precipitation (about 13 inches or 33 cm per year)
and low sulfur content of the coal almost eliminates acid mine drainage
as an environmental problem.9'14 For the same reasons of terrain and
precipitation, erosion and siltation from area mining in the Midwest are
less severe than from contour mining in Appalachia; in the Powder River
Basin erosion and subsequent siltation are periodically moderate to severe
from flash flooding from thunderstorms.
In the Midwest, the precipitation is ample enough and the sur-
face stable enough that some natural revegetation of spoil piles occurs
in a few years. In the very arid Powder River Basin, however, where the
undisturbed vegetation is itself sparse, recovery of natural vegetation
is extremely slow1 —although the noxious imported annual weed called
Russian Thistle, or tumbleweed, establishes quickly on the spoil piles.
438
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SOURCE' REFERENCE 4
FIGURE 13-10. PERSPECTIVE OF TYPICAL MINING FACILITIES, HAULAGE
ROADS, PIT OPERATION, AND RECLAMATION
,*£- r,.,..
SOURCE REFERENCE 5
FIGURE 13-1 I STRIP-MINED TERRAIN
439
-------
Concern with moisture is not limited to the land surface, how-
ever. In some places in the West, the coal seam is part of the aquifer.
The mining of large areas disrupts the continuity of the aquifer, thereby
affecting nearby groundwater resources and sometimes the water in season-
ally dry streams. In arid country, disruption of the groundwater is a
matter of importance to residents. Disruption of the aquifer usually
results in the accumulation of water in the mine itself. This water is
often used to control the dust stirred up by the earthmoving machinery.
Aesthetically, most people find unreclaimed area strip mining
in the West less objectionable than contour strip mining in the East.
There are several apparent reasons for this. First, and foremost, is
the manner in which area mining concentrates the effect to a well-defined
tract and affects essentially only the area from which the coal is re-
moved (e.g., there is no deposit of spoil down the hillside), while con-
tour mining leaves a long, linear scar along the hillside. Second, the
presence or absence of sight lines linking the observer and the disrup-
tion is important. Area mining is less visible because in relatively
flat terrain there are few vantage points to see the disruption while
contour mining can be seen readily from nearby hills or even from the
valleys.
3. Summary
The foregoing descriptions illustrate the differences in
methods and environmental effects of strip mining in Appalachia, the
Midwest, and the West (Powder River Basin). The effects are suffici-
ently different that it is equally erroneous for environmentalists to
maintain that Wyoming could become another West Virginia or for mining
companies to assert that reclamation success in the Midwest provides the
knowledge base for reclamation in the West.
440
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C. Reclamation Potential
1. Introduction
Just as approaches and effects of strip mining were seen to
differ in major ways from region to region, so do the potentials for
reclamation. The most critical single parameter is available moisture,
which is clearly related to precipitation and its annual pattern. The
amount and timing of precipitation affect the stability of man-made
slopes, and the erosion from slopes. These in turn affect the ability
to return lands to agriculture or to reestablish, in a reasonable time
span, a facsimile of the natural vegetation and thereby permit recovery
of the wildlife populations. Once disrupted, ecosystems are not neces-
sarily easily restored and it can take a long time before the ecology
is returned to equilibrium.
It is important to make clear that "restoration," meaning a
return to original conditions, is generally not possible while "recla-
mation," or "rehabilitation," implying a return to some stable, produc-
tive state, but not necessarily the original one, is generally possible.14
However, reclamation requires a conscious and careful effort on the part
of man, including a degree of land husbandry for a number of years.14
2. Appalachia
Reclamation is far simpler if it is an integral part of the
mining plan, for then the spoil can both be placed behind the line of
advancement rather than downslope and can be segregated into true top-
soil, fertile subsoils, benign subsoils, and toxic or infertile mate-
rials. To create conditions conducive to plant growth, it proves impor-
tant to layer the recontoured spoil so that the best soils are placed
on top with the infertile and toxic materials underneath. Figures 13-12
441
-------
Cut I
Highwall -
Hill
Diagram A
Valley
Spoil Bank
Spoil Backfill
Outcrop Barrier
Cut
Cut I
Highwall—
Hill
Diagram B
Valley
Hill
Diagram C
Highwall —
Cut 3
Valley
Hil
Diagram D
Valley
Hill
Diagram
Cut
Cut 5
Valley
Hill
Diogrom F
Cut 5
Valley
SOURCE: REFERENCE II
FIGURE 13-12. MODIFIED BLOCK CUT
442
-------
to 13-14 show some of the techniques that have been used to recontour the
land following mining.9'12'14«1E>16
One of the important steps in the reclamation process follow-
ing auger mining is the plugging of the auger holes in a manner that
prevents drainage of acidic water. Clearly, this must precede the re-
contouring of the spoil.9
In Appalachia, seeds of native species are abundant and the
ample moisture leads to relatively rapid reestablishment of a vegetative
cover on reclaimed contour mines, although artificial seeding speeds
recovery. Once the soil is protected from erosion by the initial growth
of any species, natural species replacements (succession) can be allowed
to proceed or other species can be introduced. For example, rather than
waiting for the native hardwood forest species to reinvade the area,
faster growing conifers may be planted to speed reforestation. Recent
work in nonmined areas has shown, however, that the runoff from a dense
stand of native hardwoods is significantly greater and different in
temporal characteristics than the runoff from a dense woods of young
(about 15 years old) conifers.17 Thus, although reclamation with coni-
fers may seem to be an environmental success from the point of view of
aesthetics, erosion, and siltation, the question always remains whether
the alteration in stream flows is within acceptable limits.
Pursuit of such a reclamation activity requires chemical analy-
ses of the soil and subsoil and the attention of personnel trained in
reclamation. Reclamation can be achieved at reasonable costs when the
goal of reclamation is integrated from the start into the mining plan.9
On the basis of cost-per-unit weight of coal, reclamation in Appalachia
is more costly than in the other two regions because less coal is recov-
ered per area disturbed.
443
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-Diversion Ditch
-Highwall
Mineral Seam
Original Ground Surface-
ISJ STEP
Toe of
-Diversion Ditch
-Highwall
Spoil from
Original Ground Surface-
2ND STEP
Toe of
-Diversion Ditch
•Highwall
Excess Spoil from
- a 2— Pits
Mineral Seam
Original Ground Surface
-Diversion Ditch
Toe of
Fill
Finished Grade
Surface -\
Original Ground Surface
4TH STEP
/-Reverse Terrace Slope
X
N. Toe of
OFill-
SOURCE •• REFERENCE I I
FIGURE 13-13. BOX-CUT MINING
-------
TYPICAL PASTURE BACKFILL
BACKFILLED GROUND SLOPE
— I0^_
— 4' WIN COVER
TYPICAL REVERSE TERRACE (I) BACKFILL
• Original Ground Surface
Backfilled Ground Surface
Impermeable Material
0.9 Meter (3') Mm
'Dilution-Forming
Material
''-—Graded Material
0.9 Meter (3') Win.
CROSS SECTION OF
STRIP MINE SHOWING POLLUTION-
FORMING MATERIAL BURIAL
SOURCES^ REFERENCES 8 AND II
FIGURE 13-14. SOME LAND RECLAMATION TECHNIQUES FOR CONTOUR MINING
445
-------
3. Midwest
Reclamation in the Midwest is made relatively easy by the
facility with which materials can be handled in area mining. Without
difficulty, the topsoil—usually very rich and often several feet thick—
can be removed and stockpiled easily and so can the other materials
capable of supporting vegetation. In area mining, it is a straight-
forward matter to smooth off and recontour the corrugations left by
different cuts and to spread subsoil and topsoil.13'18'19 This can be
quickly followed by plantings. The area of coal deposits in the Midwest
is a farming region, and Meadowlark Farms, a subsidiary of AMAX Corpora-
tion, has had notable success in farming reclaimed strip mine lands in
the Midwest for many years. Without doubt, for successful reclamation,
the most favorable combinations of terrain, soil, and moisture are found
in the Midwest.
4. West
The development of western coal resources has been the subject
of growing discussion in recent years and a dominant component of that
discussion has been the potential for reclamation of strip mined lands
in the arid West.14"16 One of the more definitive examinations of this
issue was prepared by the National Academy of Sciences,14 which con-
cluded that the success of reclamation with native species in areas
receiving less than 10 inches (25 cm) per year of precipitation was in
doubt. Although the total precipitation in the coal region of Wyoming
is about 13 inches (33 cm), some of it is in the form of snow. In these
areas of low humidity, as much as 60 to 80 percent of the snow may sub-
lime (go directly into the vapor state without passing through the
liquid state), thereby reducing the amount of precipitation that actu-
ally moistens the soil. The length of the growing season is also im-
portant . The Powder River Basin is at a high altitude (about 4500 ft
446
-------
or 1.4 km) and the frost-free period is only about four months (from late
May to late September).4
The natural vegetation in the Powder River Basin is sparse,
consisting of low clumps of grass and small desert shrubs ("sagebrush"
types of plants such as fourwing saltbush). However, in many places,
overgrazing has reduced this vegetation below its natural level. Be-
cause of the aridity, the native plants have extensive shallow, wide-
spreading root systems with the majority of their total tissues under-
ground. These roots effectively absorb moisture from a wide radius,
and, as a result, competition among plants leads to a spacing between
major plants of a foot (0.3 m) or more. It is frequently not appreci-
ated that the root sys'tems of this apparently sparse vegetation serve
as a soil binder that retards erosion.4
In such arid areas, it is difficult to farm and consequently
little cultivation (cropping) is practiced. Instead, the major agricul-
tural activity is cattle ranching and about 50 acres (200,000 m2) are
required to sustain a single animal.4 As a result, ranches usually
consist of many thousands of acres.
To date, reclamation attempts that appear most successful are
those that do not seek to restore the natural vegetation but that rather
to seek to introduce nonnative but well-adapted species (often grasses),
which are compatible with the natural ecosystem and are more productive.*
In general, however, the experimental reclamation plots have either been
too small or have not been established long enough (only a few years) to
*One of the difficulties preventing more vigorous attempts to reestablish
the natural ecosystem is the nearly total lack of a commercial source
for native seeds. If this were to become a goal, a'small seed industry
would have to develop.
447
-------
yield quality information about the long-term stability of revegetation
attempts. It is widely held that decades may be needed before it will
be known whether even the apparent success will survive the occasional
several-year periods of drought (above and beyond the normal aridity)
common to the area, and whether a stable, although nonnative, ecosystem
will develop.14
There have been some notable revegetation successes in the
region such as at the Big Horn Mine near Sheridan, Wyoming (owned by
Peter Kiewit and Sons) and the Belle Ayre Mine owned by AMAX Corporation
and rehabilitated by Meadowlark Farms.1'18 These two efforts illustrate
the benefits that accrue from a constructive attitude towards reclamation,
which includes complete integration of reclamation within the mining
plans. Yet, impressive as the reclamation at these two mines is, the
reclamation is only a few years old and the object of considerable at-
tention including watering and initial fertilization. It remains to be
seen what will happen to the reclaimed areas when the coal is mined out
and the attention of the reclaimers is turned elsewhere.
The successes at Big Horn and Belle Ayre have depended on soil
chemistry and expertise in agronomy. The arid conditions and the slow
growth of low density plants have not been conducive to the buildup of a
deep topsoil with much humus. The true topsoil is very thin on the
average (3 or 4 inches or about 7 to 10 cm) and is not evenly distributed
because the almost continuous winds in the region have scalped some high
spots and deposited the soil in depressions. At Belle Ayre, for example,
before mining begins, the true topsoil is removed by a scraper under the
supervision of an agronomist and is stockpiled. When there is no true
topsoil, nothing is scraped off, but when a pocket is found, it is all
taken. The scraper then proceeds to collect all subsoil that chemical
tests indicate would sustain plant growth and stockpiles it separately.
Some of this is later used as a substitute for the true topsoil.80 The
448
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rest of the overburden, judged too poor to serve as true or substitute
topsoil, is left for the regular mine equipment to handle as spoil.
During backfilling, care is taken to place rock and the toxic
subsoil on the bottom. This is then followed first by a layer of the
acceptable subsoil and then by a layer of the true or substitute topsoil.
With agronomists participating in the reclamation, there is recognition
that topsoil is not just a collection of lifeless physical dust particles
but that it consists of a complete ecosystem of micro flora and fauna
that are essential to plant growth and decay.20 Stockpiling the topsoil
can, through lack of air, kill off some of these organisms although most
persist as spores. To reestablish this soil micro ecosystems, it is often
necessary to add some -plant matter—such as straw—for decay followed by
moisture.20 Cognizance of these biological facts and a concerted effort
to make intelligent use of agricultural knowledge appears to result in
successful rehabilitation (at least in the short term).
Agricultural practice, such as the dimpling of the raw soil
surface to lessen wind erosion until a plant cover is established, in-
creasing moisture retention by making use of stubble to catch and pre-
vent snow from drifting away, and the use of a "nurse crop," has played
a role in revegetation successes with nonnative plants. For example, at
Belle Ayre, steps (1) and (3) in the following sequence have been
completed:30
(1) Recontour the land
(2) Plant winter wheat
(3) Harvest, leaving straw as mulch and stubble to catch
winter snow
*A crop planted solely to provide cover for a more desirable crop planted
as an understory. As the desired crop becomes established, the nurse
crop is crowded out.
449
-------
(4) Plow under mulch leaving summer fallow
(5) Plant a full crop of legumes and grass with a nurse crop
of oats
(6) Pasture cattle on legumes and grass.
While there is good reason to expect that reclamation of the
surface can be successful, serious efforts to restore disrupted aquifers
have not been made. This may not be possible. As long as western strip
mining is confined to a few isolated mines, the disruption of aquifers
is unlikely to be serious. But a high level of mining activity, spread
around the countryside in disconnected blocks, will increase the propor-
tions and importance of this problem.
5. Summary
Reclamation is possible in all regions. It is far less costly
when the effort is begun by including provision for it in the mining plan
itself. Reclamation is probably easiest in the Midwest, where a combina-
tion of terrain and natural moisture simplifies the task, and most diffi-
cult in Appalachia, where the steep slopes and excess moisture make soil
control and acid drainage difficult, and in the West, where a lack of
moisture retards reestablishment of vegetation. However, in the West,
the chances are good that revegetation can succeed if the reclaimed land
is given careful attention over a long period and nonnative plants are
accepted. The ease of reclamation is indicated by Figure 13-15, which
relates environmental parameters to potential for success. In all cases
the attention and responsibility of the restorers must extend over many
years (or decades) and not terminate as soon as some seed are sown.
450
-------
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REFERENCES CITED
1. "The Coal Industry's Controversial Move West," BusinessWeek, pp.
134-138 (May 11, 1974).
2. Nephew, E. A., "The Challenge and Promise of Coal," Technology
Review, pp. 21-29 (December 1973).
3. Stacks, J. F., Stripping, Sierra Club, San Francisco, California
(1972) .
4. Final Environmental Impact Statement, "Proposed Development of Coal
Resources in the Eastern Powder River Coal Basin of Wyoming," Dept.
of Agriculture, Interstate Commerce Commission, Department of the
Interior (October 18, 1974).
5. "Some Steps to Stop Oil Blackmail," Time, p. 65 (November 18, 1974).
6. Josephy, A. M. Jr., "Agony of the Northern Plains," Audubon (July
1973).
7. Cornforth, C., "Wyoming Mine Complex Protects Area Lifestyle," Coal
Mining and Processing (March 1974).
8. Zaval, F. J. and J. D. Robins, "Water Infiltration Control to Achieve
Mine Water Pollution Control—A Feasibility Study," Environmental
Protection Agency (EPA R2-73-142) (January 1973).
9. Grim, C. and R. D. Hill, "Environmental Protection in Surface Mining
of Coal," Environmental Protection Agency (EPA-670/2-74-093)
(October 1974).
10. Schmidt, R. A. and W. C. Stoneman, "A Study of Surface Coal Mining
in West Virginia," prepared for West Virginia Legislature, Stanford
Research Institute, Menlo Park, California (February 1972).
11. "Processes, Procedures, and Methods to Control Pollution from Mining
Activities," Environmental Protection Agency (EPA 430/9-73-011)
(October 1973).
452
-------
12. "Energy Alternatives: A Comparative Analysis," prepared for the
Council on Environmental Quality and six other federal agencies
by the Science and Public Policy Program, University of Oklahoma
(May 1975).
13. Carter, R. P., R. E. Zimmerman, and A. S. Kennedy, "Strip Mine
Reclamation in Illinois, Argonne National Laboratories (December
1973).
14. Rehabjjj/tatipn Potential of Western Coal Lands, Study Committee on
the Potential for Rehabilitating Lands Surface Mined for Coal in
the Western United States, Environmental Studies Board, National
Academy of Sciences, Ballinger Publishing Company, Cambridge,
Massachusetts (1974).
15. "Guidelines for Reclamation of Surface-Mined Areas in Montana,"
Soil Conservation Service, U.S. Department of Agriculture, Bozeman,
Montana (August 1971).
16. Thilenius, J. F. and G. B. Glass, "Surface Coal Mining in Wyoming:
Needs for Research and Management," Journal of Range Management
(September 1974).
17. Swank, W. T. and J. E. Douglass, "streamflow Greatly Reduced by
Converting Deciduous Hardwood Stands to Pine," Science, Vol. 185
(September 6, 1974).
18. "Concept of Mining as 'Intermin Land Use1 Keys AMAX Coal's Policies,"
Coal Age, pp. 131-138 (October 1974).
19. Grandt, A. T., "Reclamation Problems in Surface Mining," Mining
Congress Journal, pp. 29-32 (August 1974).
20. Personal communication with Mr. D. Knott, Belle Ayre Mine, Gillette,
Wyoming (September 1974).
OTHER REFERENCES
Breslin, J. J, and R. J. Anderson, "Observations on the Surface Mining
of Coal," A Battelle Energy Program Report (March 1974).
Cassiday, S. M. (ed.), Elements of Practical Coal Mining, Society of
Mining Engineers, Port City Press, Inc., Baltimore, Maryland (1973).
453
-------
Curry, R. R., Biogeochemical Limitations on Western Reclamation,"
Sierra Club Research, presented at Practices and Problems of Land
Reclamation in Western North America Symposium, Revised March 1975.
Plass, W. T., "Revegetating Surface-Mined Land," Mining Congress Journal
pp. 53-59 (April 1974).
454
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14—OIL SHALE MINING AND SPENT SHALE DISPOSAL
By Robert V. Steele
A. Introduction
An important aspect of the recovery of oil from the oil shale re-
sources of the western United States is the large amount of material
that must be mined, processed and ultimately disposed of if a large-
scale oil shale industry is developed. Many of the adverse environmen-
tal consequences likely to result from oil shale development are directly
related to the large volumes of material that are involved, as well as
the nature of the material itself. This chapter presents the techniques
and problem areas of oil shale mining and spent shale disposal, and pro-
vides background for the discussion of more specific environmental im-
pacts in Chapter 15.
It has been estimated that 1.5 trillion barrels (240 billion m3) of
oil are contained in the oil shale deposits of the Green River Formation
in Colorado, Utah, and Wyoming, although a much smaller quantity is prac-
ticably recoverable. The amount of recoverable oil contained in 25-gal/ton
(0.1 m /1000 kg) grade or higher shale (suitable for above ground
retorting) is estimated to be 240 billion barrels (38 billion m3), of
which 83 percent is located in the Piceance Basin of Colorado.1 A 1 mil-
lion B/D (160,000 m3/D) industry operating for 20 years would only re-
cover about 3 percent of this amount, however.
The physical form of the resource is not liquid oil but a solid
organic material called kerogen, which is imbedded in a marlstone matrix.
Only about 15 percent by weight of the oil shale is kerogen (for 30-gal/
ton or 0.13 m3/1000 kg shale). The remaining marlstone component of oil
455
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shale is a relatively useless material, which must be disposed of after
the kerogen has been converted to liquid form and recovered. The fact
that the organic portion of the shale constitutes such a small portion of
the resource has important implications for the future of oil shale devel-
opment. The recovery of even a small portion of the oil shale of the
Green River Formation would bring about the largest mining operation in
the history of mankind.
A mature oil shale industry of I million B/D (160,000 m3/D) would
involve the mining of 1.4 million tons of oil shale per day, and the
disposal of 1.2 million tons (1.1 X 109 kg) of spent shale per day. The
mining operation to support a single 100,000-B/D (16,000 ms/D) retorting
and upgrading plant (140,000 tons/day or 1.3 X 10s kg/D) would be larger
than the largest mine now in operation in the United States—the 110,000
ton/day (1.0 X 108 kg/D) Bingham Canyon open pit copper mine in Utah.2
The disposal of spent shale is in itself an enormous problem. If
the spent shale is disposed away from the mine, a 1-million B/D industry
would fill the equivalent of a box canyon one-mile long (1.6 km), 1000-ft
wide (0.3 km), and 250-ft deep (76 m) every 1.5 months. The enormity of
this problem indicates that the methods chosen to deal with it will be
crucial to the future of the oil shale industry.
B. Oil Shale Mining
1. Underground Mining
Mining the oil shale from the thick deposits characteristic of
Colorado's Piceance Basin presents no special technical problems. The
most suitable underground mining method is the "room and pillar" tech-
nique, which has been widely used in coal mining and has been established
as a reliable method for oil shale mining in prototype operations by the
Bureau of Mines. The numerous outcroppings of the kerogen-rich Mahogany
456
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Zone along the canyons of the Piceance Basin provide ready access to
deep-lying oil shale deposits.
The first step in the development of a room-and-pillar mine is
to excavate the entrances, or adits, through which mining equipment is
transported. The nature of the oil shale deposits will permit horizon-
tal adits to be used generally, which will allow easy passage of equip-
ment and the use of trucks to haul out the mined shale. Vertical adits
may also be used, however, when horizontal adits are impractical.
Once the adits have been established, the development of the
mine proceeds as follows. First, horizontal holes 30-ft (9 m) deep are
drilled along the width of a "room" to be excavated. The holes are filled
with an ammonium nitrate-fuel oil (ANFO) mixture, which is then detonated.
The shale rubble is loaded onto large ore trucks with front end loaders
for delivery to the primary crushers outside the mine. Next, a hydraulic
backhoe scrapes away the remaining shale, which was fractured but did not
fall away. After all the shale is removed from the room, roof bolts are
installed to strengthen the roof against failure. Mining proceeds from
room to room, with pillars of solid shale rock left in place to support
the roof of the mine. Prototype mine experience has indicated that the
optimum room size for an oil shale mine is 60 X 60-ft (18 X 18-m) with
rooms separated by 60 X 60-ft (18 X 18-m) pillars.
Since the oil shale zone varies in quality, a 60- to 80-ft
(18- to 24-m) thickness has to be mined to yield an average grade of
shale (about 30 gal/ton) suitable for retorting. Generally, this width
of deposit will be mined in two steps. First the "upper bench," 30- to
40-ft (9- to 12-m) high, will be developed as described above. Then the
"lower bench" will be developed in a similar manner, with the exception
that the blast holes will be drilled vertically instead of horizontally.
457
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Figure 14-1 shows the room-and-pillar mining plan envisioned
by Colony Development Operation.3 Using 60 X 60-ft (18 X 18-m) rooms
and pillars, and developing two 30-ft (9-m) benches of 35/gal/ton
(0.13 m/1000 kg) average oil shale grade, Colony anticipates that 60 per-
cent of the in-place resource can be extracted. To supply a 50,000-B/D
(8000-m3/D) plant for 20 years the mine would eventually occupy an area
of 4100 acres (6.4 sq miles or 17 km3) underground.3
2. Surface Mining
Surface mining of oil shale deposits that lie close to the sur-
face will be an economical alternative to underground mining. The eco-
nomy of surface mining is determined by the stripping ratio, which is a
measure of the amount of overburden that must be removed relative to the
amount of resource recovered. On the basis of a ratio of the thicknesses
of overburden and resource, oil shale deposits may be economically sur-
face mined up to a stripping ratio of about 2.5. Thus, even some areas
of the Piceance Basin, which have 1000 ft (300 m) of overburden, are
amenable to surface mining due to thickness of the recoverable resource
(up to 2000 ft or 600 m).
There are two kinds of surface mining—strip and open pit.
For the very lowest stripping ratios (less than about 0.5), strip mining
is the appropriate method of resource recovery. In this type of surface
mining, which is commonly used to extract coal in the west, explosives
are used to loosen the overburden and large draglines are used to remove
it. Power shovels are used to excavate the exposed resource seam and
load the shale onto trucks (see Chapter 13). The overburden is stored
at a nearby site until a large enough area is mined to allow backfilling
operations to begin.
Strip mining will probably be suitable only for oil shale de-
posits lying considerably nearer the surface than 1000 ft (300 m) because
458
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tU
yi
to
FIGURE 14-1. ROOM-AND-PILLAR MINING CONCEPT
Source : Reference 3
-------
of the difficulty of excavating such a large depth of overburden with
draglines. Open pit mining can be used for deeper deposits, and deposits
with stripping ratios of 0.5 to 2.5 can be extracted economically.4 In
open pit mining, the overburden is also loosened by blasting; however,
the ore is removed by power shovels and trucks rather than by draglines.
As the pit is deepened, a series of benches are established, which pro-
vide stability for the sides of the mine. When the desired shale deposit
is reached, it is loosened by blasting, loaded onto trucks, and conveyed
to the crusher. Figure 14-2 illustrates the characteristics of an open-
pit mine.
In open pit mining, as in strip mining, large amounts of over-
burden are generated, and a suitable site for storage must be found.
Eventually, all the overburden can be returned to the mine and reclama-
tion can take place.
C. Spent Shale Disposal
After the oil shale has been mined, crushed, and retorted, approxi-
mately 85 percent of the original shale mass remains for disposal. The
consistency of the spent shale may be of a fine granular form covered
by carbonaceous residue if TOSCO II retorting is used, or a chunky mate-
rial similar to agglomerated ash if the Paraho or another gas-combustion-
type retort is used.5 In either case, the spent shale is a relatively
uselesss material, the disposition of which poses a major problem in
oil shale development.
Most plans for oil shale development call for the disposition of
the spent shale in canyons near the retorting operation. The plan is
to spray the hot shale with water as it exits the retorts to cool it
and control the dust, and then to transport the waste by conveyor belt
to the disposal site.3 There it will be graded, compacted, contoured
460
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Isometric
•Road
Source: Reference 5
Section
FIGURE 14-2. SCHEMATIC OPEN PIT DEVELOPMENT
461
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and eventually revegetated, once the pile has reached its final height.
Compaction will be required to minimize erosion and leaching of the
pile, and to prevent the collapse of the pile's leading edge. In addi-
tion, the slope of the sides of the pile can be no greater than a three-
or four-to-one grade if sliding is to be prevented.
Runoff from the pile due to melting snow and rain will be highly
saline due to the high concentration of salts in the spent shale. There-
fore, a catchment dam must be constructed at the foot of the pile to
collect runoff so that local streams are not contaminated.
Some of the spent shale can be returned to the mine. This is most
readily accomplished if surface mining is employed, since it can be done
in conjunction with the return of overburden to the mined-out areas.
Spent shale can also be returned to the mine if underground mining is
employed, but it will be more difficult because it will interfere with
mining operations. In addition, the return of spent shale prohibits
future recovery of shale contained in the pillars or in lower grade
deposits.
In either case, disposal problems will remain since the volume of
shale expands under retorting (10 to 30 percent, depending on the re-
torting process used) and not all the spent shale can be returned to
the mine. Furthermore, temporary disposal sites will still be required
since several years of mine development are needed before backfill op-
erations can begin.
D. Environmental Problems
1. Mining
The environmental disruption associated with oil shale mining
is typical of that of any large surface or underground mining operation,
462
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except that the sheer size of the operation will mean that the scale of
the disruption will be much greater than any previously encountered.
Clearly, underground mining will cause the least ecosystem
disruption. The major surface disturbance is the construction of roads
for mine access. Surface subsidence should not be severe if pillars are
properly placed within the mine.
Potentially serious is the contamination of aquifers in the
mine area. The Mahogany Zone in which the richest shale occurs, forms
an impermeable layer between the relatively pure aquifers that lie above
this zone and the saline aquifers that lie beneath it in the Leached
Zone. Shale mining will disturb this layer, permitting the saline
aquifers to contaminate the upper aquifers, which recharge the streams
of the region.6 Furthermore, groundwater will seep into the mine from
this highly saline zone, and dewatering the mine will produce large quan-
tities of saline wastewater for disposal. To avoid the contamination of
nearby streams, this wastewater must be eliminated through deep well
injection or evaporation from lined ponds.5
Surface mining will cause similar disturbances of aquifers and
saline water contamination problems. However, the major environmental
disruption will be the disturbance of the area being mined and the re-
sulting need to dispose of large quantities of overburden. Although the
overburden will eventually be returned to the mined-out area for recla-
mation, a total of 2000 acres (8 X 10s m2) could be disturbed per
100,000-B/D (16,000 m3/D) operation before any reclamation would take
place.5
2. Spent Shale Reclamation
Even under the best reclamation strategies, the naturally
occurring ecosystems of the canyons in which the spent shale may be
463
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deposited will be completely covered and destroyed. The goal of recla-
mation is to establish a new ecosystem on the spent shale piles, which
can be self-sustaining long after human involvement has ended. This
goal involves stabilization of the pile against erosion and sliding,
establishment of a suitable plant cover, and ultimately the generation
of a plant succession system similar to other systems in the area.
Stabilization of spent shale from TOSCO II retorting appears
to be possible with the appropriate amount of compaction and careful
grading of the pile. After one or two years of natural weathering, the
surface layers may be leached enough to reduce the salt concentration to
a point where plant life can exist.
Research carried out by Colony Development Operation, and
others, has indicated that a wide variety of plants can be grown if the
spent shale pile is carefully fertilized and watered. However, only a
ry
few types of wheat-grass vill survive on unattended spent shale. Re-
vegetation of the type of spent shale created by other types of retorts
may be more difficult due to its clinker-like quality.
In general, the prospects for achieving a long-term stable
ecosystem on massive spent shale piles have still not been fully as-
sessed and it remains one of the major problems of oil shale development,
Additional discussion of spent shale revegetation problems can be found
in Chapter 15.
464
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REFERENCES
1. "Potential Future Role of Oil Shale: Prospects and Constraints,"
Project Independence Blueprint Final Task Force Report, Federal
Energy Administration (November 1974).
2. "A Practical Approach to Development of a Shale Oil Industry in
the United States," Colorado School of Mines Research Institute
(October 1975).
3. "An Environmental Impact Analysis for a Shale Oil Complex at
Parachute Creek, Colorado," Vol. 1 Colony Development Operation
(1974) .
4. "U.S. Energy Outlook—An Interim Report," National Petroleum
Council (1972).
5. "Final Environmental Statement for the Prototype Oil Shale Leasing
Program," U.S. Department of the Interior (1973).
6. E. E. Hughes, et al, "Oil Shale Air Pollution Control," Stanford
Research Institute, EPA Report No. EPA-600/2-75-009.
7. M. B. Bloch and P. D. Kilburn, "Processed Shale Revegetation
Studies, 1965-1973," Colony Development Operation (December 1973).
465
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IS—REGION SPECIFIC BIOLOGICAL IMPACTS
OF RESOURCE DEVELOPMENT
By Buford R. Holt
A. Powder River Basin
1. Introduction
Three significant classes of biological impacts can be impor-
tant in the Powder River Basin of Wyoming:
• Retardation of revegetation by drought, erosion, heavy
grazing, and spreading of toxic spoils.
• Adverse behavioral modification of big game and small game
predators by mining and coal transport activities.
• Destruction of locally rare habitats.
The sections that follow focus on the environmental setting,
major sources of impacts, and the potential for mitigation. Accounts of
lesser impacts and additional biological detail can be found in the Final
Environmental Impact Statement for the Eastern Powder River Coal Basin of
Wyoming.1
2. Environmental Setting
The Powder River Basin is a broad, shallow topographic depres-
sion superimposed on a structural basin. The landscape consists of low,
gently rolling hills, interrupted by broad flood plains containing shal-
low braided streams. Buttes, mesas, and rough, hummocky terrain add
minor but significant diversity to the generally featureless terrain.
The climate is typically arid with frequent, unpredictable
droughts. Most of the precipitation is derived from summer thunderstorms.
466
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The winter snows are light and the snowmelt usually runs off before the
ground thaws. Soil moisture is sufficient in the wettest years to sup-
port dryland farming, and lands near the Powder River Basin were plowed
after the First World War, contributing to the subsequent dust bowls of
the thirties. Comparable abuse by overgrazing has also been fostered by
a tendency to be misled by the relatively high forage yields of the wet-
test years, resulting in substantial overstocking in the drier years.
Consequently, the range in the basin has been severely degraded by dec-
ades of overgrazing.
The soils are generally clayey, with slow to moderate internal
drainage. Contrary to experience in humid regions, these clayey soils
have less available water than sandy soils and are dominated by the more
drought-tolerant species of the short grass prairie and elements of the
cold deserts to the west. Water infiltrates more slowly into the fine
textured soils and is more readily lost since even the fraction which
penetrates below the first few inches can move to the surface by capil-
lary action and is subsequently lost. On sandy soils water penetrates
quickly and deeply, with loss only of that fraction in the surface
layers. Correspondingly, the soils with the best moisture relations
are the coarse textured soils of the scoria (baked shale) outcrops and
the fine textured soils along stream courses. However, although they
are deep and moist, the latter are generally either saline or alkaline
and could be troublesome to rehabilitate if the underlying coal is
strip-mined.
The vegetation of the basin is chiefly stunted plants of big
sagebrush and sparse stands of blue grama, a drought-tolerant grass.
Desert shrubs and arid grassland species dominate the overgrazed uplands
and gentle slopes that prevail in the Basin, but pine forests cover the
hills bordering the basin, and tall shrub communities line the larger,
intermittent streams. Within the shrub and grassland communities, these
467
-------
conspicuous patterns are paralleled by significant variations in spe-
cies composition even though the local variation in elevation is gen-
erally less than 100 ft as shown in Figure 15-1. The scoria outcrops
are covered mainly by bluebunch wheatgrass and blue grama but contain
several of the grasses characteristic of the wetter prairies to the
east, including little bluesteam, prairie sandreed, and Indian ricegrass,
Some of these more demanding grasses such as needle and thread are also
found on the loamy upland soils where relatively good infiltration and
storage of water can be expected. The big sagebrush-blue grama mixture
predominates on the drier, clayey soils on the prevailing sideslope
terrain (Figure 15-la, Ib) . Western wheatgrass and other salt-tolerant
species dominate the relatively moist and productive alluvial lands.
The dominant grasses within each vegetation type consistently include
both cool and warm season grasses, designations based on the periods of
maximum growth. However, these differences in the seasonality of growth
are also correlated with differences in water loss during photosynthesis
and may make the warm season grasses slightly more suitable for initial
reclamation efforts. The establishment of both groups of grasses is
necessary to maximize productivity over the entire growing season and
to maximize the availability of the nutritionally superior new foliage
throughout the calving period.
The dominant vertebrate land animals are small mammals and
birds, with a conspicuous lack of large predators. Coyotes, badgers,
foxes, and bobcats are the largest native predators in the Basin, but
smaller ones also occur, including weasels, raccoons, and the black-
footed ferret (an endangered species).1 The big game species are lim-
ited to elk, mule deer, antelope, and white-tail deer. Small game spe-
cies include sage grouse, wild turkey, sharp-tailed grouse, ring-necked
pheasant, and cottontail rabbit.
468
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UPLANDS
SCORIA (BAKED CLAY)
PLAYAS
^L—
ALLUVIAL LOWLAND
a. TOPOGRAPHIC DESIGNATIONS
BIG SAGEBRUSH
NEEDLE AND THREAD
BLUE GRAMA
BLUE BUNCH WHEATGRASS
BLUE GRAMA
BIG SAGEBRUSH
WESTERN WHEATGRASS
BLUE GRAMA
INLAND SALTGRASS
WESTERN WHEATGRASS
b. VEGETATION TYPES
INLAND SALTGRASS
WESTERN WHEATGRASS
SILVER SAGEBRUSH
GREASEWOOD
350 Ib/acre
(4,188,000 acres)
260 Ib/acre
(27,300 acres)
450 Ib/ocr?
(148,400 acres)
450 Ib/acre
(250 acres)
600 Ib/acre
(120,000 acres)
C. PRODUCTIVITY AND AREAL EXTENT
FIGURE 15-1. NATURAL LAND UNITS OF THE POWDER
RIVER BASIN
469
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Invertebrate animals (insects, spiders, snails, etc.) have
been little studied in the Basin, apart from surveys of species impor-
tant to game fishes. Even so, these data on aquatic invertebrates
should be useful as indicators of changes in water quality, and the
available baseline data should be augmented.
The aquatic vertebrates are mostly warm-water fishes, reflect-
ing the shallowness of the sparsely shaded streams and the consequent
high summer temperatures and the fluctuations in water level and tur-
bidity, which result from irrigation use. Most of the fish species are
small, nongame species, but game species include large and small mouth
bass, bluegills, and catfish, and, where water quality permits, various
species of trout.
3. Immediate Impacts
It is unlikely that adverse effects on the animal population
will be significant early in the exploitation of the Powder River Basin,
but those that do occur will probably result from changes in the move-
ment and distribution of game species or their predators.
The causal mechanisms are likely to arise from seemingly in-
noculous barriers such as sheeptight fencing, which antelope can leap
over but frequently do not.1 (Paradoxically, the antelope typically
crawls under fencing rather than jumping it even though it is a con-
spicuously good jumper.)2 Similarly, erection of utility poles may
significantly increase the intensity of predation on small mammals or
breeding grouse by providing perches for predatory birds, although
large raptors are frequently killed when over-extended nests get wet,
droop, and cause shorts. An analogous impact of fencing on songbird
distributions, however, probably will not be important since shrubs
provide an abundance of perches for songbirds. Conversely, some of the
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more conspicuous landscape changes, such as the fragmentation of shrub-
land corridors by mining activity, may not affect game movements in the
Powder River Basin because the big game species are either highly local
in their movements, such as the white-tail deer, or exceptionally wide
ranging, such as the mule deer and elk, species which readily travel
across grassland.
4. Cumulative Impacts
The most extensive impacts will derive from the destruction of
habitats during mining and the subsequent replacement of the present
shrub-grass mixtures with predominantly herbaceous vegetations of poten-
tially lower productivity, thereby removing deer and antelope winter
browse plants.
The magnitude of the potential productivity changes of these
mined landscapes is the subject of dispute.1 It is unlikely that the
productivity of the reestablished vegetation will be much larger than
the overgrazed range which they replace, without routine irrigation and
reductions in the grazing intensity. The upper limit of productivity on
these lands, even if well managed, probably will be less than the current
maximum of 600 pounds of forage per acre characteristic of the wettest
sites and may, as the Powder River Environmental Impact Statement (EIS)
suggests, be as low as 200-500 pounds per acre, approximately the pres-
ent productivity of scoria lands. This lower estimate is markedly below
the present productivity of 350 pounds of cattle forage per acre of the
dominant sagebrush vegetations and if the estimate is accurate it repre-
sents a long-term reduction in productivity of 25-50 percent.
Impacts attributable to modifications of productivity and the
species composition of the vegetation will be greatest for the deer
populations and least for the elk, which inhabit the pine forests just
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to the east of the strip-mine areas. The elk, however, are expected to
be heavily affected by the increased human activity in the vicinity of
the mines with a consequent reduction in the acceptability of an other-
wise usable habitat,1 Impacts of increased human activity should be
minor for most small game; this may possibly cause declines in rabbit
populations, and possibly long-term increases in prairie dog abundance.
If the latter is true, the vegetation changes set forth in the EIS might
enhance the survival probabilities of the black-footed ferret, an en-
dangered predator of prairie dogs.
However, impacts on wildlife should be greater than productiv-
ity reductions alone would indicate since shifts in the species composi-
tion of the vegetation are probable and may be drastic. Deer and ante-
lope depend on shrub forage much of the year, and elk utilize shrubs
seasonally.1'3 Correspondingly, deer and antelope utilize little grass,
mostly in the spring when the carotene, digestible protein, and phos-
phorous contents are adequate. However, the magnitude of the effect of
shrub removal will depend partially on the species removed and their
location, for the shrublands comprising the winter range are the most
critical, and their removal would most heavily affect the big game
populations. *
The greatest long-term impacts on rare and upland game species
will probably derive from the destruction of winter ranges, mating
grounds, or tall shrub-woodland habitat. With the exception of the tall
shrub and woodland habitats, which are essential for white-tail deer and
elk throughout the year, these impacts involve the destruction of envi-
ronments needed during restricted, but crucial portions of the organism's
life cycle. For example, it is not clear that man can reproduce the en-
vironmental conditions necessary for the formation of a grouse dancing
or strutting ground. However, it is probable that winter range for deer
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and antelope can be recreated by replanting shrubs,4 although economic
pressures may preclude this in private lands.
Restoration of stream habitats to their original mix of mean-
ders, pools, and riffles, is improbable and certainly the thin shade
provided by greasewood will not be quickly restored. Consequently, it
is probable that mining activities in the Powder River Basin will se-
verely affect local fish populations, may seriously impact local upland
game species, and may reduce or eliminate at least the elk herd in the
hills immediately to the east of the mines. The latter impact is per-
haps the most serious, for the other species are widespread. The elk
is largely confined to the western mountains and portions of the Cana-
dian wilderness, even though it was once widespread throughout the North
American woodlands east of the Rockies.3
5. Mitigation
Presently anticipated mitigation of the impacts of fencing,
stream diversions, mining, and urbanization is largely limited to res-
toration of the original gently rolling topography and the reestablish-
ment of vegetation in the mined areas.1 No mention is made in the EIS
of any plans to rehabilitate streams, possibly reflecting their minor
economic importance of the wildlife which they contain.1
The probability of successful rehabilitation of terrestrial
vegetation is moderate if the mine spoils are carefully layered and
appropriate steps are taken to facilitate vegetation establishment.5
Rehabilitation efforts have been moderately successful in areas receiv-
ing at least 10 inches of rain, even in the absence of irrigation.5
However, the rehabilitation programs are still young, and it
is too early to appraise their success in the face of the recurrent
droughts characteristic of the western plains. Moreover, appraisals to
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date have focused on the mass of plant material produced to the exclu-
sion of their nutritional value. Since the species used typically pro-
vide good forage, the implicit assumption of high nutritional quality is
probably sound, but the possibility remains that deficiencies of biologi-
cally essential elements in the new soils, and hence in the forage, may
necessitate the addition to the soil of trace elements such as cobalt or
copper. However, the data base on rehabilitation covers a broad enough
range of sites to permit eventual refinement of appraisals of rehabili-
tation steps that will be necessary on the most difficult sites.
The preliminary data from these rehabilitation experiments are
sufficient to rank the rehabilitation probabilities of various sites
within the West. The most difficult sites to rehabilitate are really
the least extensive but most are in the Powder River Basin.5
The principal, universal constraints on rehabilitation in the
West appear to be drought, inadequate seed sources, excess salinity,
premature grazing, and the necessity for reshaping and appropriately
layering the spoils.5 In some areas instability of the soil surface
must be added to the list,5 as must frost-heaving on clay-rich soils
during the relatively wet winter months.6 Mitigation of all these con-
straints is feasible for small areas, but the prospect of mitigation of
drought and grazing constraints over the large areas that would be in-
volved over the 5-25 years variously estimated as the minimum duration
of "post rehabilitation" is questionable. Indeed, the magnitude of the
rehabilitation, irrigation, and fencing operations under those condi-
tions probably would warrant an environmental appraisal in themselves.
Availability of suitable seed stock is considered to be a
significant constraint for floodplain and badlands (severely eroded)
sites,5 but it should not be an unsolvable problem since cottonwood and
willow are easily propagated by cuttings in the East, and research with
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mechanized planting techniques for upland shrubs is well advanced in
the West.4 Similarly, the greater availability of seeds of tall and
mid-grass prairie species5 probably owes more to the development of com-
mercial markets for them in recent years than it does to any inate su-
periority over western grasses for successful seed production.
The salinity problems cannot be easily avoided in all cases,
but they can be minimized by reliance on sandy soils as top-dressings.
Use of sandy top-soils would have the subsidiary benefit of good soil-
moisture relations, for in arid regions sandy, not clay-rich soils con-
tain the maximum amount of water that is available for plant growth. In
arid regions, clay soils are seldom wetted deeply and the deeper bodies
of water are readily lost through capillary movement and subsequent en-
vaporation. In contrast, water infiltrates fairly deeply into the
sandier soils, and is retained in all but the upper two to three centi-
meters due to the absence of capillary movement.7 The moderately sandy
soils also tend to be less erosion-prone than the salinized clay-rich
soils5 and should minimize the probability of frost-heaving of young
plants,6
Protection of young plants during the establishment phase will
be consistently difficult because new tissues are typically the most
nutritious and most highly favored by grazers.3 Erection of sheeptight
fencing around the newly revegetated areas should reduce this hazard,
but it will be at best an expensive, partial solution. To the extent
that it is effective, however, it reduces the winter range of antelope
in the short run.
In all cases, however, the addition of top soil as surface
o
coating (top-dressing) enhances success of vegetation establishment.
In the absence of irrigation and fertilization, native species can be
expected to yield 2-3 times as much forage as introduced species. If
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ample fertilization and irrigation are available, the introduced species
yield perhaps 10-20 percent more than the native species.8
In summary, successful rehabilitation appears to be feasible
in wet years on sites recovered with the regional soils, but the success
of rehabilitation programs in drought years is yet to be appraised.
B. Piceance Basin
1. Introduction
Environmental impacts in the Piceance Basin are dominated by
three factors.
• Unsuitability of shale residues for plant growth without
intensive supplemental management.
• Chronic drought and meager supplies of water for supple-
mental irrigation.
• Instability of many of the ungullied riverbottoms, causing
substantial risks of heavy erosional damage and downstream
sedimentation.
On balance, reclamation costs are likely to be higher in the Piceance
than in any of the western or eastern coal fields because acid wastes
and acid drainage excepted, the factors that most strongly limit recla-
mation in the coal fields are present. In addition, there is an immense
problem of saline drainage.
The sections that follow focus on the environmental setting,
the major sources of impacts, and the potential for mitigation. Addi-
tional detail can be obtained from the Environmental Impact Statement
for the Colony Development Operation9 and the Colorado State University
report on surface rehabilitation potential.10
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2. Environmental Setting
The Piceance Basin is a tectonic feature in arid, northwestern
Colorado, which is overlain by a topographically diverse landscape. The
"basin" is divisable into a rugged southern section, cut by thousand-foot
canyons, and a more subdued northern plateau. The southern portion is
characterized by dendtritic drainage patterns with deeply incised streams
and marginally stable valley bottoms. Although these streams appar-
ently are not transporting significant sediment loads out of the basin
now, any action that significantly increases runoff would trigger massive
and rapid erosion with consequent sedimentation downstream, which would
cause biological impacts well outside the oil shale region itself.
The soils in the Piceance Basin are typically shallow, weakly
developed, and stony. The surface horizons are thin and lack conspicu-
ous organic layers except in the forested regions. The subsurface tem-
peratures are quite low, reflecting the low mean annual temperature.
The soils are typically dry during all or most of the warm season, when
growth would otherwise be most favorable.10 A fairly broad spectrum of
soils occurs within the region, but the more fertile ones are rare and
typically restricted to the canyon bottoms and the floodplains of the
major streams.
The climate is characterized by cold winters, warm summers,
and chronic drought. Annual precipitation ranges from 12-15 inches with
approximately two-thirds occurring as snow, and the rest as thunder-
storms.10 The frost-free season ranges from 90-120 days.10 Snowmelt
occurs as late as June11 and initiates the period of highest runoff.
Minimum stream flows occur in February when the soils are frozen and the
snowmelt is mimimal.
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Surface runoff averages less than an inch per year,11 but is
strongly pulsed, such that the erosion and flash flood hazards are great
throughout the region. The dissolved solids content of the surface
waters is moderate, as is water hardness.11 The ground waters are
meager and saline at shallow depths.11
The vegetation of the basin is dominated by pinyon-juniper
woodlands on the plateaus, tall shrub communities in the highly dis-
sected southern region, and sagebrush communities on the fine textured,
seasonally moist stream bottom soils in both regions. Riparian or
gallery forest occurs along the larger streams in the south where water
is available throughout the warmer months. ° These gross characteriza-
tions are explicable in terms of the seasonality of water availability
and the amount of water that is available during the respective growing
seasons. The region as a whole is arid, but the lower temperature pre-
vailing at the higher elevations lowers the loss rates from both plant
and soil surfaces, rendering the higher elevations effectively wetter.
The dominant plants are pine, juniper, and sagebrush. There are shallow-
rooted species, which are metabolically active at the relatively low
temperature prevailing in the spring and can effectively utilize the
relatively abundant water supplies available just after the snowmelt.
In contrast, the tall shrub communities of the lower elevation southern
region are tap-rooted species that are metabolically active slightly
later in the spring but that are able to utilize the deeper subsurface
reservoirs of water that occur on the coarse textured soils of the lower
valley slopes. The sagebrush species dominate the seasonally wet, fine
textured alluvium in both regions, due to their tolerance of the extreme
dryness of these soils during the summer months and their ability to
utilize the moisture available in the late spring. On sites where the
water supplies are dependable in the warm summer months, relatively
rapidly growing deciduous trees such as cottonwood, boxelder, and
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chokecherry become dominant. Small areas of Douglas fir and aspen occur
on the cooler, moister north facing slopes in the canyons at high ele-
vations and shadscale, a desert shrub, covers the driest, steeper slopes
as shown in Figure 15-2.
The terrestrial fauna of the area has received little attention
to date, but as many as 100 mammalian species might be expected in the
region, including 15 species of bats.12 However, mule deer, coyotes,
rabbit, and rock squirrels are the most conspicuous segment of this di-
verse fauna, although a number of familiar but rare species such as
cougar and wild horses are to be expected in the region.13 The reptilian
fauna should be similarly diverse, with an abundance of lizards and snakes,
but the amphibians are"probably poorly represented. At least 62 species
of birds are known to frequent the area,14 but the total is probably at
least twice that number.15 Among these are a number of rare and en-
dangered species such as the golden eagle, the bald eagle, the peregrine
falcon, the Yuma Clapper rail, and the prairie falcon, most of which are
favored targets of unthinking hunters,
The aquatic fauna is very poorly known,13 but does include
several rare species including one of potential interest as breeding
stock for game fish hatcheries, the Colorado cutthroat trout.
3. Immediate Impacts
The immediate impacts of development will probably be felt
most strongly in the aquatic ecosystems of the basin itself, with lesser
impact on the biota of the Colorado River, and minor impacts on the up-
land communities. The principal hazards in the short run will probably
be those associated with routine construction, particularly erosion and
sedimentation.
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00
o
ASPEN, MIXED MOUNTAIN SHRUBS,
OR DOUGLAS FIR
(HIGH ELEVATION, NORTH FACING SLOPES)
PINYON-JUNIPER
SHADSCALE
(DRY UPPER SLOPES)
STREAMSIDE WOODLANDS
(LARGE STREAMS)
OAK BRUSH
(LOWER SLOPES OF CANYONS)
BIG SAGEBRUSH
(VALLEY BOTTOMS)
SOURCE: ADAPTED FROM REFERENCE 10
PINYON-JUNIPER WOODLAND
(LEVEL UPLANDS)
FIGURE 15-2. VEGETATION OF THE PICEANCE BASIN
-------
4. Cumulative Impacts
The principal long-term impacts will be associated with the
mining and oil extraction processes themselves and will derive largely
from the alternations in runoff, water quality, and the deposition of
waste materials. An additional effect may be felt in lease tract C-a
where strip mining is feasible since this tract stretches across the
migration route of the White River mule deer herd, a group of possibly
several thousand animals, which, unlike most deer populations, is migra-
tory.13 Extensive mining operations potentially could disrupt this
normal pattern of movement, leading to overgrazing of portions of the
herd's range and consequent long-term decreases in the herd size.
At full production (as the maximum credible implementation
scenario), with approximately 20 retorting plants in operation, there is
a possibility that the water flowing through the major streams in the
area, Piceance, Parachute, Roan, and Yellow Creeks, may be significantly
increased from runoff derived from disposal of spent shale.* However,
the relative importance of evaporative losses and surface drainage are
very sensitive to the disposal practices used. Losses are only likely
when the spent shale deposits are watered with more water than needed
simply to keep the surface wetted, which in this water-deficient region
is most likely to occur during efforts to reestablish vegetative cover.
If a water surplus is not added, or steps taken to provide a barrier to
upward movement of capillary water, salt will accumulate to toxic con-
centrations in the surface soils. If these soils are rich in clays,
*The estimated 8000 acre-ft per year of water that will be needed to wet
down the spent shale and reestablish vegetation for a single oil shale
processing plant represents the runoff from a square area approximately
14 miles on a side; for the basin as a whole with 20 plants operating, the
water needed would be about twice the runoff occurring naturally.
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salinization will cause dispersion of the soil particles, making the
soil impervious and causing substantial increases in runoff. If simple
overwatering is used as an inhibitor of salinization of the surface
soils, substantial leaching of the underlying deposits of spent shale
can be expected. Either method of water manipulation alone may conse-
quently destabilize the stream bed deposits and cause massive erosion.10
If this occurs rapidly, the biota of these streams will probably be dec-
imated, although eventual recovery should follow the development of en-
larged channels.
Impacts on stream biota can also be expected if local streams
are used as water sources for dust control programs on roads and waste
dumps. Removal of substantial fractions of water would tend to cause
replacement of the biota of permanent streams by organisms characteris-
tic of intermittent streams. Particularly strong reductions in the
larger sized classes of those species that are most susceptible to human
or avian predation due to restriction to isolated pools, lead to reduc-
tions in their breeding stocks.
Changes in salinity or in the suspended sediment concentrations
will significantly affect the biota of the streams within the "basin,"
and, if sufficiently large, also within the Colorado River. Moreover,
the latter impact is more difficult to appraise because the salinity and
sediment concentrations are both high now and the percentage change ex-
pected is small.16 Nonetheless, small increments have enormous biologi-
cal and economic significance when the baseline values are near the
limits of tolerance of the species at risk. One must also factor this
into evaluations of the economic utility of energy extraction when the
increased salinity requires that an energy intensive desalinization be
undertaken downstream to meet international treaty obligations.
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The prognosis for the probable impacts on terrestrial biota is
less ambiguous but equally grim. The o*verburden in strippable areas con-
sists of mixtures of limestone, siltstone, shale, and sandstone that
yield rather coarse particles under the handling conditions that appear
economically feasible.10 While sand-sized particles enhance moisture
availability for plants in arid regions by allowing rapid, deep pene-
tration of the water, the larger particle sizes to be expected in the
overburden spoils will retain too little water to sustain early growth.
The spent shales, on the other hand, are almost wholly comprised of
small particles, ranging in size from that of sand (< 2mm diameters)
down to silt and clay (< 0.002 mm). As a substrate for plant growth,
they are particularly unfavorable due to the previously mentioned arid-
ity of the region, their dark coloration, and the lethally high tempera-
tures that occur at the surface of spent shale piles. Moreover, spent
shale is highly resistant to wetting, a property of some arid soils in
the West, soils which are notably slowly revegetated following dis-
turbances .
5, Mitigation
The basic mitigation steps for reclamation of spoil heaps and
spent shale dumps broadly parallel those described for the western coal
fields. It is essential that care be given to the stockpiling of soils
and weathered rock, in strip-mined areas, for use as top dressings on
the spoil heaps; that care be taken in the selection of the plants used
for revegetation; that operations be planned whenever possible to capit-
alize on the relative moistness of north facing slopes; and that recla-
mation proceed closely behind the stripping or dumping operations.
Spent shale will probably require additional steps to prevent wind
erosion during the disposal process and to prevent subsequent salini-
zation of the upper layers of the reclaimed waste piles. The former
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objective can be achieved by continual wetting of the surface, although
at enormous costs in water consumption, but it might also be achieved by
spreading a layer of gravel on the surface to form an artificial desert
pavement at the end of any given dumping program. The second problem
might be solved by laying a sufficiently thick layer of gravel on the
spent shale before adding the top dressing of soil to prevent upward
movement of salt-laden water by capillary processes. Such a coarse
layer would prevent salinization of the surface soil and, by reducing
the volume of water needed for revegetation, should reduce the impact of
leached salt on the surface waters of the region. Soil for the reclama-
tion of the spoils resulting from underground mining could be obtained
from the meta-stable deposits of the streambeds with the side-benefit of
reduced hazard of mass erosion, but these soil and weathered rock sup-
plies may be grossly inadequate. If so, dredging in the Colorado River
may be environmentally and economically acceptable as an alternative.
Impacts on streams within the "basin" can best be mitigated
by pacing development to preclude abrupt changes in water quality and
quantity but some impact seems unavoidable.
C. North Dakota Coal Fields
1. Introduction
The principal impacts in the North Dakota lignite fields
should resemble those of the Powder River Basin but should be much less
intensive. The principal differences are:
• Rehabilitation potential in North Dakota is higher due to
greater water availability and soil fertility.
• Less disruption of wildlife habitat will occur in North
Dakota due to prior conversion of substantial acreage to
cultivation.
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Destruction of regionally rare aquatic and streamside habitats
remains a potential impact, although these mining impacts are dwarfed by
the impacts of the dams constructed by the Corps of Engineers on the
adjacent Missouri River.
The sections that follow focus on the environmental setting,
the major impacts, and the probability of successful rehabilitation of
the land assuming appropriate layering and reshaping of the soils.1
2. Environmental Setting
Broad, level uplands and gentle slopes dominate the topography
although occasional hills and broad river valleys provide some diversity,
To the east and north, the region is bounded by the bluffs and broad
floodplains bordering the Missouri River, and to the west, by the bad-
lands of the Little Missouri. Southward, the gentle terrain of the
coal fields continues to South Dakota without interruption. Wetlands
are rare southwest of the Missouri, but the regions eastward and down-
wind of the mining and industrial region are dotted with small ponds
that are heavily utilized by migrant and breeding waterfowl.11'17
The climate in the coal fields is characterized by extremes
of temperature and precipitation similar to those in the Powder River
Basin, although the temperature range in North Dakota is larger and the
moisture range is generally less than in the Powder River Basin. Pre-
cipitation is more strongly concentrated in the summer in North Dakota
than in the other western coal fields, which, combined with the slightly
lower summer temperatures, makes the effectiveness of precipitation in
1. 8
North Dakota greater than in the Powder River Basin.
The soils of the region are loamy, slightly alkaline, moder-
ately deep (up to 2 ft), with relatively high sodium concentrations.5'19
As a consequence of the relatively high sodium and clay contents,
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formation of large soil particles (aggregates) is impeded in these soils
and they are consequently readily eroded, particularly following re-
peated freezing and thawing.1'5
The vegetation of the Dakota fields is a mosaic of rangeland
and small grain fields, with rare strips of woodlands along the major
streams. The western border contains a small forest of ponderosa pine
and the Little Missouri National Grasslands, which consists of farms
that were abandoned during the dust bowl years of the 1930s. The wood-
lands along the Missouri, the Knife, the Little Missouri, and the Spring
rivers consist of cottonwoods, elms, green ash, and boxelder, with small
amounts of bur oak on the better drained river terraces.20 These are
rapidly being cleared for cultivation, now that the flood frequency has
been greatly reduced by the construction of major dams on the Missouri,
but they still provide extensive deer habitat.20 The rangeland vege-
tation resembles that of the Powder River Basin with the exception of
the greatly reduced incidence of shrubs30'21 and the significantly
higher productivity of even the poorest of the North Dakota sites. The
range of forage production in the North Dakota is 980-1600 lb/acre,sl
roughly three times the productivity of the Powder River grasslands
where approximately 50 acres are needed to support one cow.1 The uplands
are typically characterized by silty soils covered by stands of buffalo
grass and needle and thread, while needle grass and little bluestem
cover the relatively moist slopes of the steep-sided ravines that occur
at the ends of the local drainage systems. Prairie dropseed and needle-
grass dominate the sandiest ravine bottom soils.31
The vertebrate fauna of the fringes of the lignite fields are
quite diverse due to the diversity of habitats provided by the mixture
of urban, riverine, agricultural, and range environments. Approximately
150 species of birds are reported for the Missour Valley Region of North
Dakota, including substantial numbers of woodland and aquatic species. °
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Although censuses do not appear to be readily available, the number of
species actually occurring in the lignite fields should be substantially
smaller, due to the rarity of wetlands and forest. The major wetlands,
and consequently the major waterfowl breeding areas are to the north and
east of the Missouri River,17 but there are four wildlife refuges within
2 2
the lignite region. Similar but less pronounced declines in species
diversity with distance from the Missouri River may occur among the mam-
mals and will surely occur within the amphibians, while reptiles may
increase in diversity. In general, diversity among North American mam-
mals increases with aridity, and particularly with increased variability
in rainfall; extrapolating from these general patterns, it would appear
that the mammalian fauna reported for the region do not reveal their
true diversity.33 Mule deer are the largest common mammals although
cougar and black bear have been sighted in recent years.20 The fish
fauna is fairly well known, with preponderance of warm or turbid water
species (i.e., species tolerant of low oxygen levels during the hottest
months). As a whole, vertebrate fauna are dominated by small, geographi-
cally widely dispersed species, apparently lacking notable populations
of rare or endangered species.
Invertebrate fauna have received exceptionally little atten-
tion apart from the grasshoppers which are economically important pests
regionally.20
3. Immediate Impacts
Significant impacts are unlikely in the short run except in
the highly localized areas of activity. Certainly, immediate impacts
associated with road construction and mining should be less than in the
Powder River Basin where the existing network of roads and fencing is
less dense. Nor is significant restriction of the movement of game
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likely since the species present are either small or readily jump
fences.20
4. Cumulative Impacts
The most significant impacts in the North Dakota coal fields
are likely to be the destruction of the less common habitats such as
steep slopes, which would be extremely difficult to reestablish. Such
sites are characterized by locally unique combinations of microclimate
and water availability, and consequently maintain distinctive plant com-
munities. Apart from the eradication of these western representatives
of the eastern prairies, the ultimate impact of mining should be modest
if reclamation proceeds closely behind the stripping operations and is
conducted with care. The soils are somewhat saline and become increas-
ingly so with increasing depth, and spoils from the deeper layers
rapidly become impermeable to water. Raw spoils particularly from the
deeper layers are consequently exceedingly difficult to reclaim, but
sites treated to a topdressing of material from within 10 ft of the
surface typically have the highest reclamation potential of any within
the Great Plains coal fields, due to the relatively favorable water
balance prevailing in the region.5 Disruption of lands along the river
fringes due to coal development is likely to be minor relative to the
changes already occurring in species composition in the floodplain for-
est in response to changes in the flooding regime caused by the major
dams on the Missouri.24
5. Mitigation
Mitigation measures applicable in North Dakota are the same as
those described in the appraisal of the Powder River mining operations.
Their application in North Dakota is facilitated, however, by the greater
availability of suitable seeds and water, and an academic base of
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experience in prairie reestablishment. However, care must be taken in
those portions of both regions that have stony soils not to create gravel
layers too close to the soil surface since they form an effective barrier
to root penetration in arid regions.25
D. Illinois Coal Fields
1. Introduction
Three impacts dominate the Illinois coal region:
• Destruction of prime agricultural land.
• Production of acid drainage.
• Potential destruction of the floodplain forests of the
Wabash River.
Impairment of wildlife habitat and destruction of natural eco-
systems are generally not problems in Illinois due to the prior impacts
of agricultural land uses, which have left only rudimentary fragments of
the original prairies in cemetaries and along railroad rights of way.
The dominant wildlife species are typified by Virginia deer and ring
neck pheasant, both of which depend on the habitat fostered by man, and
consequently tend to increase with increased human activity in humid
regions.
Rare or endangered species are unlikely to be threatened
throughout northern and central Illinois, but do warrant consideration
along the extreme southern fringe of the Illinois coal basin where the
unglaciated terrain is characterized by usually rugged topography and
underlain by extensive cave systems. This combination of topographic
diversity and absence of glaciation have permitted the persistence of
a number of endemic plant species as well as a number of broadly dis-
tributed species, which reach their northern distributional limits in
southern Illinois. The vegetation of the southern fringe of the coal
489
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basin is consequently distinctive and rich.36 The Wabash floodplain
represents a special case of this general pattern, and, while heavily
logged, still represents a unique extension of the rapidly disappearing
southern floodplain forests of the Mississippi River.37
The sections that follow focus on the environmental setting,
the major impacts, and the probable potential for rehabilitation. Addi-
tional biological detail and extensive bibliographies of pertinent lit-
erature are available in the Missouri Botanical Garden's report on the
OR
biota of the St. Louis region.
2. Environmental Setting
The Illinois coal basin straddles the eastern extension of the
tallgrass prairies and shares the climatic variability characteristic of
the great plains but in a much milder form. Minimum monthly rainfall in
Illinois is roughly equivalent to the maximum rainfall of the Powder
River Basin and the average annual rainfall in Illinois is three times
that of the Powder River Basin.29 Approximately half of the precipita-
tion in Illinois occurs during the growing season as a consequence of
thunderstorm activity, and the remainder is precipitated as either rain
or snow during winter storms associated with larger atmospheric movements
(frontal storms). Floods occur primarily in the winter when the soil is
frozen and in the early spring as the seasonal rainfall within the region
is augmented by snowmelt.30
The topography of the midwestern coal fields is essentially
featureless except for the gentle hills and low cliffs of their southern
fringe. The major portion of the Illinois coal region is a level plain
of glacial debris overlain by windborne sediments, which is transected
by a few small rivers that meander through broad floodplains.30 As
shown in Figure 15-3 the southern boundary of the region is comprised
490
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of low, unglaciated hills underlain by an extensive cave system. The
drainage system is well developed and lakes are consequently rare
throughout the region.3'
IOWA
MISSOURI
KENTUCKY
J^aSJ SURFACE MINED AREAS
3 COAL DEPOSITS
SOURCE:ADAPTED FROM REFERENCE 31
FIGURE 15-3. ILLINOIS COAL REGION
Streams in the region are typically alkaline but generally
less so than in the western coal fields.1 Hardness expressed as ppm
of CaC03 ranges from 120-240 ppm in the Illinois basin, while it is at
least 180 ppm in the Powder River Basin and typically over 240 ppm.
Similarly both regions have exceeding hard groundwater, with concentra-
tions in excess of 240 ppm except in the southern portions of the
Illinois coal fields where a steep gradient in water hardness marks a
transition to soft waters south of the Ohio River.1 Sediment concen-
trations in the western and midwestern fields are similar, reflecting
491
-------
the easily eroded nature of the Illinois soil and the heavy use of row
cropping in the Midwest, The water pollution potential from commercial
fertilizers and domestic sewage is considerably greater in the midwestern
region where fertilizer use is the heaviest in the nation.11 Groundwater
aquifers are absent in the central Illinois coal region, except for nar-
row aquifers along river courses. Moreover, since groundwater use is
generally small, groundwater depletion is a problem only in the
northern portion of the coal region.30
The soils of the region are generally 4 to 5 ft deep and ex-
ceptionally fertile, although soils in the southern portion of the region
*^O *^ ?
are characterized by impervious clay layers, which impede drainage. '
The structure and to some degree the fertility of the soils
still reflect the nature of the original plant cover, the more strongly
leached soils being those that developed under forest cover, which oc-
curred in patches throughout the region. The soils are easily eroded
and erosion to date has been characterized by the USDA as moderate to
*an
severe.
»
The current vegetation of the northern and central portions
of the Illinois coal basin is essentially a matrix of corn interspersed
by roadside weeds such as giant ragweed, sunflowers, goIdenrods, asters,
marijuana, and assorted grasses. Remnants of the original prairies are
found only in older cemetaries and along railway rights of way and pres-
ently consist of major prairie grasses such as little and big bluestem,
i
Indian grass, and switchgrass, along with a number of broad leaved herbs
which superficially resemble the weeds of abandoned croplands. The
original woodlands are likewise rare, since the woodlands were settled
before the prairies.33 Woodland species are consequently found predomi-
nantly within the vicinity of homesites and along streams. In virtually
all cases, woodland must be regarded as second growth, heavily disturbed
stands.
492
-------
The vegetation of the southern portions of the coal region is
predominantly oak-hickory forest, a forest type widely distributed
throughout the eastern United States.34 The principal exceptions to
this are the extensive floodplain forests of the Wabash River along
the eastern edge of the coal field, which represents the northernmost
extension of the rapidly disappearing floodplain forests of the alluvial
plains of the Mississippi River. These forests have been logged, but
still represent a unique resource even though the mammoth trees recorded
in early photographs, including bald cypress, swamp gum, and sweet gum35
are gone. A number of locally rare variants of these lowland forest
vegetations have been described36 for areas lying along the southern
fringe of the coal area, many of which will be disturbed by mining if
acid drainage is uncontrolled. The upland forest of oak and hickory
have been repeatedly logged and burned, and most postdate the heavy
logging of the 1890s and endured a second wave of logging during the
1920s.36 It is of interest that the oaks of these forests fall into
two groups reminiscent of the cool season-warm season distinction of
the grassland dominants. Unpublished data from Brookhaven National
Laboratory suggest that these groups, the red and the white oaks, are
differentiated with respect to elemental composition and it is intu-
itively plausible that the distinctions between the two groups extend
to other physiological properties. While significance of these dis-
tinctions is not clear, it is probable that they enhance the productiv-
ity of mixed forests and may have nutritional significance for browsers
such as deer.
The flora and the vertebrate and invertebrate faunas of the
major portion of the coal region probably contain few rare or endangered
species given the extensive prior manipulation by man. However, the
areas bordering the southern mining region contain a number of endemic
and locally rare plant species such as French's Shooting Star in the
493
-------
unglaciated uplands bordering the Ohio River, and large numbers of rare
animals are to be expected in the cave ecosystems underlying this region.
While these probably will not be extensively impacted by mining, it is
possible that they will be damaged by drainage waters from the strip-
mined regions if adequate care is not taken to bury the toxic spoils to
retard oxidation of sulfur containing overburden. The impact of mining
warrants appraisal, but the greatest hazard to rare species in the region
probably is associated with a proposed waterway development project on
the Wabash.
The vertebrate animals of the uplands are typical of species
found in the fringes of woodland, abandoned fields, and roadsides
throughout the eastern half of the United States. Deer are the largest
of the wild game, which includes the usual mixture of small game such
as rabbit, raccoon, possum, squirrel, pheasant, quail, and dove. The
total vertebrate fauna in the uplands consist of perhaps 40 species of
reptiles, 10 species of amphibians, and 80 species of mammals,32 and
115 species of birds.15 The region borders the Mississippi flyway and
a modest number of transient species pass through the area.
The vertebrate fauna of streams contain several additional
species of reptiles and amphibians, as well as a large number of fish,
including such game species as largemouth and smallmouth bass, crappie,
bluegill, and catfish.38'33 Individual streams draining the study area
28
may have as many as 30 species of fish.
Enormous numbers of invertebrates such as insects, leeches,
snails, sowbugs, and crayfish are present in both upland and aquatic
habitats, and they have been relatively well studied by the Illinois
Natural History Survey. Indeed, as a consequence of the long continued
efforts of the Natural History Survey and the state and federal soil
conservation services, the biota and soils of Illinois are exceptionally
494
-------
well known, and the appraisals of impacts for this region can be defined
with greater precision than for any other coal region.
The productivity of the region is high and diverse cropping is
biologically feasible, although corn production dominates. In contrast
to the Powder River Basin where as many as 50 acres may be needed per
cow, approximately one acre per cow is sufficient in Illinois.30
3. Immediate Impacts
The immediate impacts of substantial expansion of the present
mining activities should be much less than in the Powder River Basin or
the North Dakota coal fields. The road and fencing networks are already
substantial, and the game species involved are less strongly affected by
fencing, both negating the impact of additional fencing. All impacts in
the short term will be the consequence of increases in the areal extent
of active mining itself.
4. Cumulative Impacts
The long-term impacts of strip mining will be relatively minor
if reasonable care is taken to restore the land surface by layering and
grading the spoils as outlined in the Environmental Impact Statements
for the Powder River Basin.1 Indeed, the restoration process is easiest
here due to the presence of adequate rainfall during the growing season
in all but the most exceptional years, the presence of deep layers of
topsoil throughout much of the strippable region (up to 4 ft in thick-
n o
ness), and the ready availability of seeds for both native and commer-
cial plant species.5 It is unlikely that destruction of shrub cover at
any one time will be sufficient to substantially affect the game popula-
tions, and the rates of recovery of shrub cover should be high if recla-
mation is attempted.39 Slow but uneven recovery can be expected even
495
-------
without reclamation,39'40 although the erosion hazard is enormous in the
western portion of the coal field where the loess deposits are deep.11
Indeed, the greatest impacts will probably be seen in the
aquatic environments in response to increased turbidity and acidity of
surface waters and the silting of spawning beds. However, with care,
these impacts can be kept to relatively low levels, and the probability
of exposure of sulfur rich deposits appears to be fairly low in much of
the basin.3 The principal problems with acid mine drainage can be ex-
pected in the southern fringe of the strip-mineable area.
5. Mitigation
The necessary mitigation measures are the same as those de-
scribed for the Powder River Basin but are much easier to implement.
Indeed, rehabilitation should be easier in Illinois than in any other
coal field in the United States.
E. Appalachian Coal Fields
1. Introduction
The Appalachian coal fields are characterized by four envi-
ronmentally significant features:
• Acid mine drainage is frequent from both surface and
underground mines.
• Surface disruption of strip mining is exceptionally severe
due to the rugged topography.
• Restoration of the land surface to the original contours
is rarely feasible, although partial restoration is
practical.
• Erosion is severe on sites which are not reclaimed.
These problems are not unique but are exceptionally frequent
and severe in Appalachia.
496
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The sections that follow focus on the environmental setting,
the potential for mitigation, and the probable range of responses to
attempted rehabilitation.
2. Environmental Setting
The Appalachian coal field occupies a southwest-northeast
trending series of ridges and valleys and adjacent plateaus. The region
as a whole is an intricate network of deeply incised streams, most of
which empty into the Ohio River or its tributaries.30 Topographically,
the plateau consists of broad tableland, which grades into dendritically
dissected hill land on both the northern and southern extremities and
is underlain by horizontal or gently warped strata. The ridge and val-
ley region is characterized by ridges up to 1500 ft high and tens to
hundreds of miles in length, underlaid by strongly folded and faulted
strata;41
The soils are thin to moderately deep, well drained, and
easily eroded. Throughout much of the region, the uplands are too steep
to farm, and the narrow floodplains are often plagued with poor drainage
or frequent flood damage. The dominant land use is consequently fores-
try, with mixtures of pasture and cropland on the gentler terrain. As
is generally true in the nation as a whole, the best agricultural soils
are also the best soils for construction and are preferentially occupied
by roads and urban areas.41
The climate is continental, with cold winters and hot, humid
summers. The rainfall varies from 38 to 66 inches per year. The frost-
free season averages 165 days and ranges from 150-200 days.41 Precipi-
tation is evenly spread throughout the year but varies in form from the
cloudbursts of summer to the gentle, steady rains or snows of winter.
Snowfall ranges from 2 to 60 inches, with between 10 and 40 inches being
497
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typical of most of the region. Soils in the northern portions regularly
remain frozen throughout the winter but are subjected to sporadic freezes
and thaws in the south. Frost penetration ranges from 3 to 20 inches and
generally extends through the most densely rooted portions of the soil
(the upper 6 inches).ia
Surface water runoff is high, varying from 10 to 20 inches per
year. Minimum stream flow occurs in late summer and early fall, and
maxima occur in late winter or early spring when the soils are frozen or
saturated and the transpiration losses are low. Groundwater supplies
are typically marginal and are unimportant water sources throughout the
region as a whole. Dissolved solids and salinity values are typically
low, and the water quality in unmodified waterways is the best of the
four coal regions considered. Surface waters are soft and, consequently,
weakly buffered relative to those of the other regions—roughly half the
hardness of water in Illinois—a factor that makes them particularly
susceptible to change in response to acid mine drainage. Pollution from
agricultural sources is low due to the topographic restrictions on
mechanized agriculture, but urban pollution is locally severe.11
Streams in the region are generally shallow with frequent
alternation of pools and riffles and a variety of bottom types. Typi-
cally, they are densely shaded during the warmer months and exhibit
peaks of phytoplankton productivity in early spring and late fall when
sunlight at the stream surface is maximal. Reproduction of both inver-
tebrate and vertebrate fauna typically occurs in the spring when the
decomposition of the accumulated tree litter accelerates and the phyto-
plankton production peaks. Most of the fishes migrate upstream to
spawn, rendering the head waters critical to the maintenance of diver-
sity in the larger streams.
The terrestrial vegetations are predominantly forests and in-
clude the most diverse forests of the continent in the highly dissected
498
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rim of the Cumberland Plateau and the Smoky Mountains. These forests
frequently contain as many as 20 commercial species and several species
of understory trees such as redbud, serviceberry, and hawthorn. This
rich assemblage of sugar maple, white and red oak, hickories, ash, bass-
wood, birches, magnolias, elms, beech, cherry, buckeye, and tulip-popular
grades into less diverse stands of oak and hickory on the drier sites,
and ultimately into stands of red cedar on dry limestone outcrops. On
the shale barrens of Pennsylvania and the more acid, nitrogen-deficient
mine spoils, black locust, which possesses a nitrogen fixing symbionic,
becomes dominant. The wetter sites are dominated by sycamore, willows,
red maple, elms, hackberry, black walnut, and assorted shrubs. The un-
disturbed forests on most, well-drained sites characteristically have
relatively few shrubs but possess an exceptionally diverse herbaceous
flora, which is metabolically most active before closure of the tree
canopy in the late spring. As sites become either wetter or drier, and
the tree canopy more open, the understory vegetations become more dense
with a shift towards shrubs and ultimately drought-tolerant herbs on the
drier sites such as ridge top and rock outcrops and a shift towards tall
shrubs on the wetter, more poorly drained sites.4
Terrestrial vertebrates of recreational interest include gray
squirrel, turkey, bear, deer, grouse, raccoon, possum, woodcock, and
rabbit, but in general the fauna parallel the diversity of the vegeta-
tion, and the number of organisms of biological interest is large.41
The southern Appalachians are a center of diversity for salamanders and
other amphibians, while the region as a whole is moderately rich in mam-
malian species, with roughly 50 species of quadrupedal mammals and 10-15
species of bats.33 Birds are likewise well represented, with perhaps
115 species in the region as a whole.15
Aquatic vertebrates include the species to be expected in
Illinois but also include assorted cold-water species, although the
499
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trout populations are significantly augmented yearly with hatchery stock
in all but the most remote cold-water streams. Smallmouth, stripe,
spotted, rock, white, and largemouth bass; walleye, catfish, crappie,
and bluegill constitute the major warm-water game fishes of the region41
but a rather small portion of the total fish population, which includes
minnows, suckers, and other nongame species.
Invertebrate fauna, both aquatic and terrestrial, are very
diverse but as usual are unlikely to be endangered, with the possible
exception of cave dwellers along the fringes of the mining regions.
3. Immediate Impacts
The immediate impacts of strip mining and the associated dirt
roads are severe and, without considerable care, are both persistent and
widespread. The coal seams are thin and the amount of overburden is
extremely high. The spoils typically include substantial amounts of
large rock fragments. As this overburden is first blasted and then
shoved away from the seam, large rocks frequently roll down the adja-
cent hillsides, creating a swath of disruption somewhat larger than that
caused by simple excavation and displacement of soils and other loose
material. The resulting scars are often 50 to 100 ft high, including
the terrain buried by displaced fill, and may stretch for miles. Se-
vere as these impacts of the mining cut are, however, they may have only
slightly more local impact on terrestrial biota than the less contro-
versial interstate highway system, which has left equally permanent, if
less vivid, scars on the landscape.
The immediate impacts of underground mining are modest, but
the eventual impacts through waste disposal or acid drainage are often
severe, even if less extensive than stripping.
500
-------
In contrast to the impacts on land animals, the immediate- to
long-term impacts of both strip and deep mining activity on aquatic
organisms are persistent and often more severe than routine earth-moving
activities such as highway construction. The increments to the silt load
of streams is often severe in both mining and construction, but the mine
wastes have the additional impact of significantly altering the acidity
of streams by the continual release of extremely acid waters. In effect,
acid mine drainage preempts the headwaters spawning grounds for many
fishes, leading to inadvertent changes in the species composition of the
biota downstream of the areas of immediate kill and this means a replace-
ment of species that spawn in headwaters by those that spawn in the
shallows of large streams, which in turn implies displacement of cold-
water species, such as trout, by warm-water species, such as bass, cat-
fish, or carp.
4. Cumulative Impacts
The long-term impacts scarcely differ qualitatively from those
characteristic of the short term. The biological productivity of the
land is lowered, life is often excluded from small streams, and more
subtle changes in the biota of the intermediate-to-large streams are
probable.
5. Mitigation
The mitigation steps applicable to Appalachia are similar to
those of the midwestern and western coal fields but are far more diffi-
cult to implement. The thinness of the layers of weathered bedrock and
soil combined intensify the need for careful analysis and handling of
the overburden, while the steepness of the topography makes such pain-
staking work exceedingly difficult and expensive. Even in the best of
circumstances, it is improbable that it will be economically feasible
501
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to restore the land to its approximate original contours, although it
should generally be possible to greatly lessen the incidence of acid
drainage and to speed the reestablishment of vegetation. The method-
A n A A
ology is basically in hand to reclaim spoils ' and, given adequate
incentives for implementation, should be effective.
502
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1. "Final Environmental Impact Statement: Proposed Development Coal
Resources in the Eastern Powder River Coal Basin of Wyoming,"
Dept. of Agriculture, Interstate Commerce Commission, Dept. of
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2. E. T. Seton, Lives of Game Animals, Vols 1-4.
3. C. W. Cook, "Wildland Shrubs—Their Biology and Utilization," USDA
Forest Services, General Technical Report INT-1, pp. 303-310.
4. R. B. Ferguson and S. B. Monsen, "Research with Containerized
Shrubs and Forbs in Southern Idaho," paper presented at the North
American Containerized Forest Tree Seedling Symposium, Denver,
Colorado, August 26-29, 1974.
5. P. E. Parker, "Rehabilitation Potentials and Limitations of Surface-
Mined Land in the Northern Great Plains," USDA Forest Service,
Ogden, Utah (July 1974).
6. D. Smith, Forage Management in the North (W. C. Brown, Co., Dubuque,
Iowa).
7. H. Walter, Vegetation of the Earth in Delation to Climate and the
Eco-Physiological Conditions (Springer-Verlag, New York, 1973).
8. E. E. Farmer, R. W. Brown, B. Z. Richardson, and P. E. Parker,
"Revegetation Research on the Decker Coal Mine in Southeastern
Montana," USDA Forest Service Research Paper INT-162, Inter-
mountain Forest and Range Experiment Station, Ogden, Utah (1974).
9. J. W. Narr and D. Buckner, "Ecological Analyses of Potential Shale
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503
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10. C. W. Cook, "Surface Rehabilitation of Land Disturbance Resulting
from Oil Shale Deposits,"Final Report, Phase 1, Dept. of Range
Science, Environmental Resources Center, Colorado State University,
Ft. Collins, Colorado (March 1, 1974).
11. J. J. Geraghty, D. W. Miller, F. van der Leeden, and F. L. Troise,
Water Atlas of the United States, a Water Information Center Pub-
lication (1973).
12. J. W. Wilson III, "Analytical Zoogeography of North American Mam-
mals," Evolution, Vol. 28, 124-140 (1974).
13. C. W. Knoder and D. Sumner, "Comments of the National Audubon Soci-
ety on the Proposed Prototype Oil Shale Leasing Program," Draft
Environmental Impact Statement (September 1972).
14. "Socio Economic Studies," Environmental Impact Analysis, Appen-
dix 16, Geoecology Associates, Marlatt and Associates, and Voorhees
Associates for Colony Development Operation, Atlantic Richfield
(July 1974).
15. S. J. McNaughton and C. C. Wolf, General Ecology (Holt, Rinehart
and Winston, New York).
16. "Potential Future Role of Oil Shale: Prospects and Constraints,"
Interagency Task Force on Oil Shale under the direction of the Dept,
of Transportation, Federal Energy Administration Project Independ-
ence Blueprint Final Task Force Report (November 1974).
17. S. C. Freden, E. P. Mercanti, and M. A. Becker, eds., "Third Earth
Resources Technology Symposium," NASA, Vol. 1, pp. 1671-1685.
18. J. E. McClelland, C. A. Mogen, W. M. Johnson, F. W. Schroer and
J. W. Allen, "Chernozems and Associated Soils of Eastern North
Dakota: Some Properties and Topographic Relationships," Soil
Sci. Soc. Amer. Proc., Vol. 23, 51-56 (1959).
19. S. R. Eyre, Vegetation and Soils: A World Picture (Aldine Pub-
lishing Co., Chicago, Illinois, 1968).
20. "Stanton Generating Station Unit Number 2 and Associated Transmis-
sions, and Unit Number 1 Precipitation, Stanton, North Dakota,"
North Dakota Environmental Impact Statement, REA.
504
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21. R. E. Redmann, "Production Ecology of Grassland Plant Communities
in Eastern North Dakota," Ecol. Monogs., Vol. 45, 83-106.
22. G. Laycook, The Sign of the Flying Goose (Anchor Press, Garden City,
New York, 1973).
23. J. W. Wilson III, "Analytical Zoogeography of North American Mam-
mals," Evolution, Vol. 28, pp. 124-140 (1974).
24. R. L. Burgess, W. C. Johnson and W. R. Keammerer, "Vegetation of the
Missouri River Floodplain in North Dakota," Res. Proj. No. A-022-
NDAK, Dept. of the Interior, Office of Water Research.
25. J. K. Lewis, "Primary Producers in Grassland Ecosystems," Science
Series No. 2 Suppl., Colorado State University Range Science Dept.,
pp. 241-1 to 241-87 (1970).
26. J. W. Voight and R. H. Mohlenbock, Plant Communities of Southern
Illinois (Southern Illinois University Press, Carbondale, Illinois,
1964) .
27. A. W. Kucher, "Potential Natural Vegetation of the Conterminous
United States," Amer. Geog. Soc. Sp. Publ. No. 36.
28. "An Introduction to the Biological Systems of the St. Louis Area,"
Vol. 1-4, Missouri Botanical Garden (June 1974).
29. G. R. Rumney, Climatology and the World's Climates (Macmillan & Co.,
New York).
30. C. B. Hunt, Physiography of the United States (W. H. Freeman & Co.,
San Francisco, 1967).
31. V. C. Finch, G. T. Trewartha, A. H. Robinson, and E. H. Hammond,
Elements of Geography: Physical and Cultural (McGraw-Hill Book
Co., New York, 1957).
32. L. H. Gile, Jr., "Fragipan and Water-Table Relationships of Some
Brown Podzolic and Low Humic-Gley Soils," Soil Sci. Soc. Amer.
Proc., Vol. 22, 560-565 (1958).
33. "Environmental Assessment: Clarence Cannon Dam and Reservoir,"
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34. A. W. Kucher, "Potential Natural Vegetation of the Conterminous
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35. A. A. Lindsey, R. O. Petty, O. K. Sterling, and W. V. Asdall,
"Vegetation and Environment Along the Wabash and Tippecanoe
Rivers," Ecol. Monogs., Vol. 31, 105-156 (1961).
36. E. T. Estes, "The Dendrochronology of Black Oak (Quercus velutina
Lam.), White Oak (Quercus alba L.) and Shortleaf Pine (Pinus
echinata Mill.) in the Central Mississippi Valley," Ecol. Monogs.,
Vol. 40, 245-316 (1970).
37. R. L. Smith, Ecology and Field Biology (Hargus and Ron, New York,
1974).
38. R. R. Carter, R. C. Zimmerman, and A. S. Kennedy, "strip Mine Rec-
lamation in Illinois," Argonne National Laboratory, Argonne, Illi-
nois (December 1973).
39. N. L. Rogers, "Strip-Mined Lands of the Western Interior Coal
Province," Missouri Agric. Expt. Station Research Bulletin, Vol.
475, 1-55 (1951).
40. R. A. Bullington, "The Stabilization of a Gully by Natural Forest
Succession," Trans 111. Acad. Sci.
41. "Kanawha Basin Comprehensive Study, Appendix D: Land Resource
Availability, Use and Treatment," Kanawha River Basin Coordinating
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42. G. R. Trimble, J. H. Patric, J. D. Gill, G. H. Moeller, and
J. N. Kockenderfey, "Some Options for Managing Forest Land in the
Central Appalachians," General Technical Report NE-12, USDA Forest
Service (1974).
43. "Kentucky Guide for Classification, Use and Vegetative Treatment
of Surface Mine Spoil," USDA Conservation Service, Kentucky
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506
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16—AIR POLLUTION CONTROL FOR
SYNTHETIC LIQUID FUEL PLANTS
By Evan E. Hughes, Patricia Buder Simmon,
and Ronald K. White
A. Introduction
1. Organization of the Discussion
In the assessment of the need for new technology for air pol-
lution control in a future synthetic liquid fuel industry, the major
steps are the following: (1) description and evaluation of the proc-
esses, emissions, and controls that can be used in the production of
synthetic liquid fuels from coal and oil shale, (2) modeling the dis-
persion of pollutants emitted to the atmosphere, (3) comparing calcu-
lated ambient concentrations of pollutants with air quality standards
that could apply in regions where the plants may be built, and (4) draw-
ing conclusions regarding the adequacy of air pollution control tech-
nology for synthetic fuel plants. These steps are amplified in Sec-
tions B through E of this chapter, as indicated in the following
paragraphs.
Section B identifies the sources of emission of air pollutants
from various synthetic fuel processes by unit operation within the proc-
ess and specifies the emissions that could be expected with best avail-
able control applied to each unit. Explicit assumptions about what
constitutes the best available control are given and some of the choices
that must be made in selecting the control technology to be applied to
various unit operations within the process are discussed. Tables are
given to summarize the resulting emission characteristics of each of the
507
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processes considered. Two processes for making synthetic crude oil are
emphasized: TOSCO II retorting of oil shale and H-Coal liquefaction of
western coal.
Section C uses the emission characterization of Section B to
specify the source terms for atmospheric dispersion modeling. Reason-
able assumptions regarding stack configurations and parameters are com-
bined with meteorological data from energy resource regions in Colorado
and Wyoming to calculate ambient concentrations of air pollutants. The
calculated values are compared with various ambient air quality stand-
ards. Finally, the results of a preliminary sensitivity analysis are
presented as an indication of the range of control requirements that
could be derived from such calculations.
Section D summarizes the two preceding sections by presenting
our best estimates of the percent additional control required to meet
the Class II nondegradation standards. These standards are expected to
apply in the oil shale and coal regions of Colorado and Wyoming, as well
as to other energy resource regions of the western United States.
Section E presents conclusions and recommendations based on
this analysis of air pollution control for synthetic liquid fuel plants.
2. Background
The assessment reported is a continuation of SRI work for EPA*
in which the environmental implications of the development of solar,
geothermal, oil shale, and solid waste energy sources were studied.1
Phase II of that work focused on determination of the requirements for
additional air pollution control for an oil shale industry2 and is the
*Under contract No. 68-01-0483.
508
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prototype for the analysis presented here on the broader problem of air
pollution control for synthetic liquid fuel plants.
The context for this discussion of air pollution control is
established in Chapters 4, 6, and 9 of this report. Chapter 4 on the
technology of alternative fuel production is most closely related to the
air pollution problems and is referred to for some description of the
processes. However, Chapter 6, on maximum credible implementation sce-
narios, and Chapter 9, on decision making for synthetic fuels, while
not referred to explicitly here, help to set the stage for this discus-
sion by indicating the possible magnitude of a major shift to synthetic
liquid fuel production.
3. Air Pollution Standards
Standards play a key role in this assessment of air pollution
control requirements.
Emission standards regulate the quantities of pollutants that
can be emitted to the atmosphere from various specific processes or fa-
cilities. Such standards may be expressed as the amount of pollutant
allowed per unit weight or volume of the total emission stream or as the
amount of pollutant allowed per unit level of operation of the facility.
Examples of the former are (1) the Colorado emission standard of 500
parts per million (ppm) of SO2 relative to the total flue gas emitted
from a stack and (2) the so-called "new source performance standard" for
•3 *
municipal incinerators of 0.18 g/m (0.08 gr/SCF ) of
*Grains per standard cubic foot. One pound equals 7000 grains. A
standard cubic foot of any gas is the amount of gas that occupies a
cubic foot at a standard temperature and pressure, in this case a,tem-
perature of 15° C (60°F) and a pressure of 1 atmosphere.
509
-------
particulates in the exit flue gas. The latter type of emission standard
is expressed in units used for "emission factors," such as pounds of sul-
fur dioxide (SO3) released to the atmosphere per ton of copper ore proc-
essed in a smelter or kilograms of nitrogen oxides (NOX) per gigajoule
(GJ) of energy consumed in a boiler.
The emission standards referred to in this chapter are among
the "new source performance standards" promulgated by EPA. These regu-
lations set maximum emission rates for a number of industrial processes
and facilities. "New source" is used to designate the fact that these
standards apply only to facilities begun after some date specified in
the notice of the standard. When new source performance standards are
set by EPA, the nature of the processes employed in the industry and the
availability of control measures that can be applied at reasonable costs
are taken into account. New source performance standards for industrial
boilers that consume solid, liquid, or gaseous fossil fuels are variously
referred to in this chapter as power plant emission standards, utility
boiler standards, or fossil fuel-fired boiler standards.
Air quality standards regulate the concentration of pollutants
found in the "ambient" air that the general population breathes or could
breathe. Ambient air is that found in the ordinary environment beyond
the plant boundary, usually at ground level. Concentrations of pollu-
tants are expressed either in parts per million (a volume of pollutant
to volume of air ratio) or in mass per unit volume. The latter expres-
sion is now preferred, and all of the federal ambient air quality stan-
dards are expressed in units of micrograms per cubic meter of air
(ug/m3). The atmospheric dispersion model used in this work uses emis-
sion rates, which could themselves be compared directly only to emission
standards, and calculates from them the ambient air quality, in ug/m3,
at various points in the vicinity of the emission source. These
510
-------
calculated concentrations can be compared directly to ambient air qual-
ity standards.
Ambient air quality standards used in this chapter include:
(1) national primary standards, set by the federal government at concen-
tration levels intended to be low enough to prevent adverse effects on
human health, (2) national secondary standards, also set by the federal
government acting under the same law, but set at lower levels of concen-
tration intended to prevent economic damage, especially to living plants,
(3) state air quality standards, in particular those of Colorado and
Wyoming, and (4) three classes of ambient air quality standards intended
to prevent significant deterioration of air quality in regions in which
air pollutant concentrations are currently well below the national
standards.
Standards in the last category are frequently referred to as
"nondegradation standards." The specific classes and levels of standards
in this category have been promulgated by EPA recently.3 EPA proposed
that the states be responsible for designating the clean air regions
within their borders as belonging to one of three classes. Ambient
air quality standards, expressed as increases in levels of concentra-
tions of air pollutants to be allowed within the region, were set by
EPA for each of the three classes. Of the three, Class I is the most
strict, intended to keep air quality virtually unimpaired and consistent
with very minimal industrial development of the regions so classified.
Class II standards are strict but generally not so strict that substan-
tial development is precluded, provided the development includes appreci-
able effort directed toward air pollution control. Class III standards
allow the air quality in a region to meet the national primary or secon-
dary levels, whichever is the strictest.
511
-------
The complete specification of an ambient air quality standard
includes, in addition to a level of concentration, the time interval
over which the concentration is to be averaged. Standards mentioned in
this chapter involve annual averages, 24-hour averages, and 3-hour aver-
ages. To completely specify standards tied to a daily or hourly average,
the statement of the standard must also name the number of times per
year that the specified level may be exceeded. Thus, the 24-hour or
3-hour levels of concentration are viewed as "worst-case" situations,
with worst-case defined as the number of days per year a situation that
severe is to be allowed under the standard. All such standards referred
to in this chapter are to be exceeded no more than one day per year.
Table 16-1 is a summary of the ambient air quality standards
referred to in this chapter. The standards are listed in the order of
lenient to strict. Because background concentrations (pollutant
levels present in the absence of any industrial activity in a region)
must be added to the contributions from synthetic fuel plants for com-
parisons with all the standards other than Class I and Class II, it is
possible that Class II, and perhaps even Class I, standards may not be
as strict as a state standard in some cases. For example, due to back-
ground levels of SO2 present in the Piceance Basin of Colorado, it would
be easier for an oil shale industry to comply with the Class I nondeg-
radation standard for SO2 than with the corresponding state standard.
B. Synthetic Liquid Fuel Plants; Processes and Emissions of Air
Pollutants
Emissions of air pollutants are estimated for three principal
synthetic fuel processes:*
*These and other competitive processes are described and discussed in
Chapter 4.
512
-------
Table 16-1
AMBIENT AIR QUALITY STANDARDS
Standard
Federal*
primary
Federal*
secondary
Colorado'
(nondesignated
areas)
Pollutant
Particulates
80s
N02
Hydrocarbons (HC)
Particulates
S0g
Particulates
SO0
Concentration Level
for Different
Averaging Times
(ug/m3)
1-yr
60
45
24-hr
3-hr
75 260
80 365
100
150
150
15
160
1300
Wyoming'
Particulates
SO2
N02
HC
60
60
100
150
260
1300
160
Class II'
Particulates
SOr,
10
15
30
100
700
Class I3
Particulates
S02
5
2
10
5
25
*Federal primary and secondary from The Federal Register, quoted in
Environment Reporter, The Bureau of National Affairs, Inc. (1975).
tColorado and Wyoming standards from The Federal Register, quoted in
Environment Reporter, The Bureau of National Affairs, Inc. (1975).
+Class I and II from The Federal Register, Vol. 39, No. 235, Part III
(5 December 1974).
513
-------
• TOSCO II production of oil from shale
• H-Coal production of oil from coal
• SASOL production of methanol from coal.
As cited earlier (Chapter 4), these processes were selected for study
because of the advanced or proven development of the process, the suit-
ability of the product for further refinement into automotive fuels in
substantial proportion, and the availability of process data. In addi-
tion, data that were available on emissions associated with the Solvent
Refined Coal (SRC) and Consol Synthetic Fuel (CSF) coal liquefaction
processes have been included for comparison.
The relatively rich shale deposits of the Piceance Basin in Colorado
are the source of raw material for the TOSCO II process. The H-Coal proc-
ess emissions are estimated for two representative coals—a relatively
high sulfur midwestern (Illinois No. 6) coal and a low sulfur subbitumi-
nous western (Powder River, Wyoming) coal. The data cited for the SRC
and CSF processes pertain to the use of a "northwest" coal, similar to
the Powder River coal, and a "central" coal, which is similar to the
Illinois coal. The SASOL process consumes a low sulfur "western" coal
similar to Powder River coal. Two process variations are also considered
in the SASOL case: (1) the "design" process in which plant heat demand
is met with a fuel gas manufactured from the coal and (2) an alternative
process in which the necessary coal is burned directly. The latter proc-
ess conserves energy but increases emissions.
In each case emissions from the production of electricity needed by
the plant are estimated. These emissions are ascribed to the process
regardless of plans to purchase the electricity or generate it on-site.
However, the ambient concentration modeling in Section C excludes emis-
sions ascribed to generation of electricity.
514
-------
1. Syncrude from Oil Shale
The process of extracting the organic material from oil shale
and of converting and upgrading the material to a suitable product is de-
scribed in Chapter 4 and the analysis of air pollution control neces-
sary for the TOSCO II process"1 is summarized here. Also included here
are emissions that result from the generation of electricity supplied to
the plant. Plans for the first TOSCO II installation by Colony Develop-
ment Operation4 call for purchase of electricity; other installations
may generate electricity on-site. In either case the resulting emissions
are attributable to the plant. Comparisons with the other synthetic
fuels, those derived from coal, will then include emissions from all
combustion needed for the plant. In all cases it is assumed that coal
is consumed to generate electricity.
In addition, the TOSCO II plant is considered to produce a
synthetic crude oil rather than a fuel oil. The difference in product
does not have a significant effect on the air pollution expected from
the plant. The dominant emissions from the plant are from the ore-
preparation system and the pyrolysis and oil recovery unit, and these
processes are the same for either product. Emissions from the product-
upgrading units could vary with product changes, but these units consume
relatively little fuel and therefore are relatively minor contributors
to emissions. The crude shale oil must be upgraded to some degree in
any case to permit transport by pipeline.
a. Control of Emissions
Emissions of a TOSCO II plant producing 16,000 m3/day
(100,000 B/D) of syncrude are summarized in Tables 16-2 through 16-5.
Table 16-2 lists emissions attributed to the generation of electricity.
Tables 16-3 through 16-5 summarize emissions of each major pollutant
515
-------
Table 16-2
ELECTRIC POWER GENERATION* EMISSIONS ATTRIBUTABLE TO A TOSCO II
OIL SHALE PROCESSING PLANT
(16,000 m3/day of syncrude)
01
Type Emission
Particulates
SO;
NO.
x
Emissions Without
Control Devices
Factor Rate
(kg/103kg)t (g/s)
46.4
9.5
1280
260
245
Control Methods
Efficiency
Device
HC
0.15
4.2
Electrostatic
precipitator
Flue gas
desulfurization
None
None
99.5
90
Emissions
Remaining With
Best Control
Factor
(kg/GJ)!
0.013
0.052
0.50
0.0083
Rate
(g/s)
6.4
26
245
4.2
*Assumes use of Powder River Coal (see Section B-2).
Q
tRefers to kg of pollutant per 10 kg of coal burned in the boiler.
tRefers to kg of pollutant per 109 joules (about 10 Btu) of heat input to the boiler.
-------
Table 16-3
PARTICULATE EMISSIONS FOR TOSCO II OIL SHALE PROCESSING PLANT
(16,000 ra3/day)
Emissions
Without Control
Devices
Control Methods
Emissions
Remaining With
Best Control
System
Ore preparation
Primary crusher
Final crusher
Fine-ore storage
Pyrolysis and oil
recovery
Raw shale preheat
Steam superheater--
ball stacks
Processed shale
moisturizer
Product-upgrading
Hydrogen unit
Naphtha hydrogenation
Gas oil hydrogenation
Feed heater
Fired reboiler
Delayed coker
Utility boilers
Loading
(mg/m3)
2,300
26,000
21,000
16,000
5,900
8,200
9
7
7
7
9
50
Amount
(g/s)
540
7,400
1,600
\
18,000
1,400
970
2.7
0.05
0.23
0.20
0.39
2.5
Device
Baghouse
Baghouse
Baghouse
Venturi scrubber
Cyclone and Venturi
scrubber
Venturi scrubber
None
None
None
None
None
None
Efficiency
(%)
98.0
99.8
99.8
99.7
99.2
99.4
Loading
(mg/m3)
46
46
46
46
46
46
9
7
7
7
9
50
Amount
(g/s)
11
13
3.3
53
11
5.6
2.7
0.05
0.23
0.20
0.39
2.5
-------
Table 16-4
SO3 EMISSIONS FOR TOSCO II OIL SHALE PROCESSING PLANT
(16,000 m3/day)
00
System
Pyrolysis and oil
recovery
Raw shale preheat
Steam superheater—
ball stacks
Product upgrading
Hydrogen unit
Naphtha hydrogenation
Gas oil hydrogenation
Feed heater
Fired reboiler
Delayed coker
Utility boilers
Sulfur plant
Emissions Without
Control Devices
Factor
(kg/GJ)
27
6.0
22
22
6.0
6.0
22
43
i.OOO*
Amount
(g/s)
295
5.3
81
1.3
1.8
1.5
11
23
320
Control Method
Device or
Other Method
Treated fuels1
Treated fuels
Treated fuels
Treated fuels
Treated fuels
Treated fuels
Treated fuels
Treated fuels^
Tail-gas
scrubber
Efficiency
Emissions
Remaining With
Best Control
95
Factor
(kg/GJ)
24
6.0
22
22
6.0
6.0
22
34
*
250
Amount
(g/s)
255
5.3
81
1.3
1.8
1.5
11
19
16
*Units for sulfur plant emission factor—ppm by volume.
tTreated fuels include fuel oil meeting federal new source performance standards for power plants
instead of fuel oil planned by Colony.
-------
Table 16-5
NO EMISSIONS FOR TOSCO II OIL SHALE PROCESSING PLANT
(16,000 ma/day)
System
Emissions Without
Control Devices
Factor
(kg/GJ)
Amount
(g/s)
Control Methods
Emissions
Remaining With
Best Control
Factor
(kg/GJ)
Amount
(g/s)
01
M
CO
Pyrolysis and oil
recovery
Raw shale preheat
Steam superheater—
ball stacks
Product upgrading
Hydrogen unit
Naphtha hydrogenation
Gas oil hydrogenation
Feed heater
Fired reboiler
Delayed coker
Utility boiler
107
39
1,160
33
Treated fuels
None
37
37
39
39
37
210
135
2.3
11
9.2
19
114
None
None
None
None
None
Trea
28
39
295
33
37
37
39
39
37
13
135
2.3
11
9.2
19
6.9
^Treated fuels include fuel oil meeting federal new source performance standards for power
plants instead of fuel oil planned by Colony.
-------
from individual subsystems in the plant. The only other substantial
emission is 76 g/s of hydrocarbons from the raw shale preheat system.
An incinerator controls hydrocarbon emissions to this level.
The final column for each table lists the estimate of
emissions remaining after application of "best control." The assumptions
leading to establishment of standards for best control are:
• Dust loading controlled to a level not exceeding
46 mg/m3, equivalent to 0.02 gr/ACF.*
• Use of treated fuels, including use of a fuel oil
meeting the federal new source performance stand-
ards for oil fired boilers, to control levels of
SO,, and NO...
2 A
• Sulfur plant emission of SO,, controlled to a level
of 250 ppm by volume.
• Electric power plant emission of particulates con-
trolled 99.5 percent and emission of S0_ controlled
X5
90 percent.
A principal uncertainty in the estimates is the oil originally intended
to fuel the plant. Other captive fuels planned for use have relatively
lower emissions than the fuel oil in all categories.2 Colony has indi-
cated that this fuel oil will be subjected to further hydrotreatment,
reducing both sulfur and nitrogen content, when it is necessary to in-
sure that the plant meets relevant emission or ambient standards.5
This procedure is said to be expensive, although relatively less costly
than flue gas desulfurization. Until experience is gained with the
*Grains per actual cubic foot; at the elevated temperatures involved,
an actual cubic foot is considerably less dense than a cubic foot at
normal temperatures and pressures.
520
-------
process in its given environment, the present estimates serve best for
comparison with other synthetic fuel processes.
A recent discovery5 at Colony, not yet fully confirmed,
adds another element of uncertainty. It appears that SOa emissions in
the raw shale preheat subsystem (Table 16-4) may be effectively lowered
by contact with materials present in the raw shale. The effect on emis-
sion levels would be significant since most of S03 is emitted from this
unit. The tentative finding is that as much as two-thirds of the ex-
pected S02 may be removed from the raw shale preheat exhaust.
b. Options for Further Control
Later- sections of this chapter indicate that further con-
trol of particulates and SO2 may be required.
It is likely that improved control of particulates can be
obtained. Principal sources are shale dust from the ore-preparation sys-
tem and the raw shale preheat subsystem. Where shale dust is controlled,
estimates of efficiency were derived using the quantities of sludge dis-
posed to estimate loadings before control. This procedure overestimates
efficiency since coarse particles are trapped by gravity to some extent
before final collection. Since no measure of the proportion of fine par-
ticulates was available, the estimated emissions must be considered an
upper limit. In addition to this consideration, the "best control" level
used here may be conservative, depending on the proportion of fine par-
ticulates present.
Flue gas desulfurization remains an option for further
control of the SO2 levels. The economics of this process compared with
hydro treatment of the fuel oil, at the time of plant construction and
later, would determine the selection.
521
-------
c. Other Processes
In general, the estimates of emissions for ore-preparation
systems and product upgrading systems associated with other surface re-
torting processes would be similar to TOSCO II. The emissions from a
different retorting module could vary significantly, especially in dust
emissions. The TOSCO II estimates would probably be highest of all
processes under consideration with regard to dust from this module.
Other emissions would depend primarily on similarity of fuels. Further
discussion of these considerations may be found in Reference 2.
2. Syncrude from Coal
In estimating the emissions to the atmosphere from the opera-
tion of an H-Coal plant* producing 16,000 m3/day (100,000 B/D) of syn-
crude two cases are considered: (1) processing Wyoming Powder River sub-
bituminous coal, and (2) processing Illinois No. 6 bituminous coal. The
characteristics of these coals are given in Table 16-6.
a. Control of Emissions
Tables 16-7 and 16-8 contain a summary of the emissions
for an H-Coal plant processing each type of coal. In contrast to
TOSCO II, a detailed breakdown of the fuel consumed in each major unit
of the process is not available. Only two fuels are consumed—a captive
fuel gas and coal. Emission factors for natural gas7 were used for the
fuel gas.
For Illinois coal, adequate quantities of fuel gas are
expected to provide all fuel needed for the process. Coal is combusted
*H-Coal process is described in Chapter 4 and Reference 6,
522
-------
Table 16-6
CHARACTERISTICS OF REPRESENTATIVE
WESTERN AND EASTERN COALS
Ultimate Analysis
(% by wt)
33
5.8
45.7
3.2
11.1
0.5
0.7
10
9
62.7
4.8
8.9
3.5
1.1
Wyoming Powder River Illinois No. 6
Subbituminous Coal Bituminous Coal
Moisture
Ash
Carbon
Hydrogen
Oxygen
Sulfur
Nitrogen
Total 100.0 100.0
Higher heating value
MJ/kg (Btu/lb) 18(7800) 26(11,000)
only to provide the electricity required. For Powder River coal, the
fuel gas evolved in the process is not adequate to supply fuel needs,
and coal is used to make up the difference as well as to produce elec-
tricity.
The emission factor for coal dust from the dryers is a
>ice from the range of factors7 that are lil
of essentially all moisture is specified for the process.
pessimistic choice from the range of factors7 that are likely. Removal
Control of emissions from coal combustion,8 using an
electrostatic precipitator and flue gas desulfurization, is estimated
at 99.5 percent for particulates and at 90 percent for SO2. While the
estimate for SO2 removal may be controversial, the best independent
judgment at present is that it can be met.8 A high performance Venturi
523
-------
Table 16-7
EMISSIONS FOR H-COAL LIQUEFACTION OF POWDER RIVER COAL
(16,000 m3/day)
Emissions Without Control Devices
Control Methods
Emissions Remaining
With Best Control
Coal drying
Dryer exhaust
Fuel combustion
(coal)
Steam reformer
Fuel combustion
(gas)
Oi
to
Plant
Fuel combustion
(coal)
Fuel combustion
(gas)
Sulfur plant
Electricity
Fuel combustion
(coal)
Type
Particulates
Particulates
80 a
NOX
HC
Particulates
S02
NOX
HC
Particulates
SO2
NOX
HC
Particulates
S02
NOX
HC
S02
Particulates
soa
NOX
HC
Factor
12.5 kg/103 kg*
46.4 kg/103 kg
9.5
9
0.15
290 kg/108 m3
9.2
3700
48
46.4 kg/103 kg
9.5
9.
0.15
290 kg/10a m3
9.2
3700
48
5000 ppm (vol)
46.4 kg/103 kg
9.5
9.
0.15
Rate
(g/s)
4200
1325
271
257
4.3
5.8
0.19
74
1.0
2340
479
454
7.6
1.3
0.04
17
0.2
320
1079
221
209
3.5
Device
Multiple cyclones and
Venturi scrubber
Electrostatic
precipitator
Flue gas desulfurization
None
None
None
None
None
None
Electrostatic
precipitator
Flue gas desulfurization
None
None
None
None
None
None
Tail-gas scrubber
Electric
precipitator
Flue gas desulfurization
None
None
Efficiency
(%) Loading
99.0 36.7 mg/m3t
99.5 12.8 g/GJ
90 52.4
496.
8.3
6.2
0,2
81.
1.
99 . 5 12 . 8
90 52 . 4
496.
8.3
6.2
0.2
81.
1.
95 250 ppm (vol)
99.5 12.8 g/GJ
90 52 , 4
496.
8.3
Rate
(g/s)
44
6.6
27.1
257
4.3
5.8
0.19
74
1.0
11.7
47.9
454
7.6
1.3
0.04
17
0.2
16.
5.4
22.1
209
3.5
*2,87 gr/dSCF (grains per dry standard cubic foot).
tO.03 gr/dSCF.
-------
Table 16-8
EMISSIONS FOR H-COAL LIQUEFACTION OF ILLINOIS COAL
(16,000 m3/day)
Emissions Without Control Devices
Control Methods
Emissions Remaining
With Best Control
Ui
to
Ol
Source Unit
Coal drying
Dryer exhaust
Fuel combustion
(gas)
Steam reformer
Fuel combustion
(gas)
Plant
Fuel combustion
(gas)
Sulfur plant
Electricity
Fuel combustion
(coal)
Type
Particulates
Particulates
S02
NOX
HC
Particulates
SOS
NOX
HC
Particulates
S02
iro
X
HC
S02
Particulates
S02
NOX
HC
Factor
12.5 kg/103 kg*
290 kg/106 m3
9.2
3700
48
290 kg/108 m3
9.2
3700
48
290 kg/106 m3
9.2
3700
48
5000 ppm (vol)
72 kg/103 kg
66.5
9
0.15
Rate
(g/s)
4520
0.69
0.02
8.8
0.11
2.19
0,07
28.0
0.36
9.47
0.30
121
1.57
1370
1080
998
135
2.25
Efficiency
Device (%)
Multiple cyclones with 99.8
Venturi scrubber
None
None
None
None
None
None
None
None
None
None
None
None
Tail-gas scrubber 95
Electrostatic precipitator 99.5
Flue gas desulfurization 90
None
None
Loading
43.3 mg/m3t
6.0 g/GJ
0.2
76.4
1.0
6.0
0.2
76.4
1.0
6.0
0.2
76,4
1.0
250 ppm (vol)
14.1 g/GJ
260
351.7
5.9
Rate
(g/s)
10.7
0.69
0.02
8.8
0.11
2.19
0.07
28.0
0.36
9.47
0.30
121
1.57
68.7
5.4
99.8
135
2.25
*12.68 gr/dSCF (grains per dry standard cubic foot).
tO.03 gr/dSCF.
-------
scrubber following multiple cyclones is likely to be necessary8'9 to
meet the proposed federal standard9 for coal drying—70 mg per dry normal
cubic meter (0.03 gr/dSCF).* The efficiencies shown necessary to meet
this standard are judged to be reasonable.8 »9
Sulfur plant emissions were calculated from the sulfur
input and output rates. The efficiency of the scrubber applied to the
tail-gas from the sulfur plant was estimated at 95 percent, a commonly
achieved figure.
Combustion calculations were performed for all fuels (the
fuel gas has a different composition for the different coals) to deter-
mine the flow rates and the set of stack parameters used in Section C to
calculate the ambient air quality in the plant vicinity. Coal dryer flow
rates were determined from coal moisture and typical exhaust temperatures.
The plant processing Illinois coal was assumed to be at
sea level, while the Powder River elevation, 1230 m (4000 ft), corre-
sponds to a pressure of 87.4 kPa (25.84 in. Hg).
b. Options for Further Control
The level of control indicated above is estimated in
later sections to be adequate. Should further control become necessary,
particulate emission from the coal dryers would be closely examined.
Some improvement, especially for Powder River coal, seems possible with
the same type of equipment. Improvement in flue gas desulfurization
would bring about the best improvement in S02 levels. An alternative
would be to replace at least part of the coal with a cleaner fuel.
*Grains per dry standard cubic foot.
526
-------
c. Other Processes
Emissions associated with other coal conversion processes
have been estimated by others.10 Total emissions from SRC and CSF
plants are given in Table 16-9 for comparison with other synthetic fuel
processes. Emissions are shown for central coal (25 MJ/kg, 11.3 percent
ash, 3.7 percent sulfur) and northwest coal (20 MJ/kg, 6 percent ash,
0.5 percent sulfur). These are very similar to Illinois No. 6 and Powder
River coals, respectively (Table 16-6).
Table 16-9
CONTROLLED EMISSIONS1" FOR SRC AND CSF
COAL LIQUEFACTION PLANTS
(16,000 m3/day)
Process and Operation
SRC
Combustion and drying
Combustion
Sulfur recovery
CSF
Combustion and drying
Combustion
Sulfur recovery
Emission Rate by
Coal Type
(g/s)
Pollutant
Particulates
S02
NO
X
HC
S02
Particulates
SO3
NOV
X
HC
SOP
Central
34
97
900
2.9
203
24
257
550
2.7
64
Northwest
35
16
900
2.9
32
21
44
540
2.5
14
*SRC and CSF processes are described in Chapter 4,
tlncludes emissions from electricity generation.
527
-------
The level of control of emissions assumed for Table 16-9
was similar to that used for H-Coal. Coal dryer dust was controlled to
the 99.85-percent level with a Venturi or Baghouse following the multiple
cyclones, and sulfur plant tail-gas scrubbing was 95 percent effective.
The SRC plant derives 92 percent of fuel demand from a captive fuel gas
and the remainder from a product fuel oil. Since the sulfur content of
the fuel gas is negligible, and the fuel oil contains only 0.28 percent
of the sulfur level of the feed coal, no further control is imposed on
the SRC plant. The CSF plant fuel needs are met 84 percent with fuel
gas containing 0.4 percent of the sulfur level of the feed coal; the
remaining 16 percent fuel needs are satisfied with coal. As above, an
electrostatic precipitator plus flue gas desulfurization control emis-
sions from the burning of coal—particulates are reduced 99.5 percent
and SO2 is reduced 90 percent (95 percent was assumed in Reference 10—
this was adjusted to give the data shown in Table 16-9). Emissions
associated with generation of the required electricity are included in
Table 16-9.
3. Methanol from Coal
A general description of the process for producing methanol
from coal is given in Chapter 4 with the SASOL process described in more
detail in Reference 11. In estimating emissions to the atmosphere re-
sulting from the operation of a SASOL plant producing 16,000 ms/day
(100,000 B/D) of methanol, two cases are considered: (1) operation of
the plant as designed11 using a fuel gas manufactured from the coal,
and (2) operation of the plant burning the coal directly to obtain nec-
essary process steam and electric power. A western coal yielding 20
MJ/kg (8700 Btu/lb) and containing 19 percent ash and 0.69 percent sul-
fur is assumed for both cases. This coal is of somewhat lower quality,
528
-------
in terms of ash and sulfur content, than the Powder River coal (Ta-
ble 16-6).
a. Control of Emissions
Tables 16-10 and 16-11 present emissions for a SASOL
plant processing coal to methanol for each fuel scheme. In both cases
all fuel is consumed in a steam and power generation plant, and all
purge gases (those evolved as a byproduct) are consumed. For the case
considered in Table 16-10, part of the coal input is gasified to produce
a fuel gas that is cleaner burning than the coal. The efficiency of
this conversion is about 67 percent, leading to a total coal input rate
of 35,4 X 106 kg (39,000 tons) per day. When the coal is burned di-
rectly (Table 16-11), the total coal input rate is 31.6 X 10s kg (34,800
tons) per day for the same methanol output.
Emission factors for natural gas7 were used for both the
purge gas and the manufactured fuel gas with one exception. The known
sulfur content11 of the manufactured fuel' gas, in the form of HSS, was
assumed to be entirely converted to SOS during combustion. Sulfur con-
tent of the purge gas was specified11 to be negligible, so that the
factor for natural gas7 was used. Emission factors for the coal7 were
calculated from the properties specified above. Since coal drying is
not specified for this process, no special dust emissions are listed for
this potential source. The uncontrolled emission rate for the sulfur
plant was calculated from the specified11 H2S in the tail-gas stream.
This flow was adjusted in Table 16-11 to account for deletion of manu-
factured fuel gas.
No controls are added for the relatively clean-burning
gas. Controls for the coal burning are analogous to those imposed for
the liquefaction processes (see Section B-2) . A reduction in
529
-------
Table 16-10
EMISSIONS FOR SASOL METHANOL PLANT USING MANUFACTURED FUEL GAS
(16,000 ma/day)
Control Methods
Emissions Remaining
Emissions Without Control Devices
Ol
CO
o
Source
Combustion
Purge gas
Manufactured
fuel gas
Type
Particulates
S02
NOX
HC
Particulates
S02
NO
HC
Factor
290 kg/106 m3
9.2
3700
48
290
9000
3700
48
Rate
(g/s)
4.6
0.1
60
0.8
16
151
202
2.7
Device With Best Control
Device or Efficiency
Other Method 1
None
None
None
None
None
Treated fuel
None
None
(%) Loading
7.3 g/GJ
0.16
95
1.3
7.3
71
95
1.3
Rate
(g/s)
4.6
0.1
60
0.8
16
151
202
2.7
Sulfur plant
1960 ppm (vol)
194
Tail-gas scrubber
95
250 ppm (vol)
9.7
-------
Table 16-11
EMISSIONS FOR SASOL METHANOL PLANT USING COAL FOR FUEL
(16,000 m3/day)
Control Methods
Emissions Remaining
CO
Emissions Without Control Devices
Source
Combustion
Purge gas
Coal
Sulfur plant
Type
Particulates
S03
NO
X
HC
Particulates
S02
NO
X
HC
S03
Factor
290 kg/106 m3
9.2
3700
48
154 kg/103 kg
13.1
9
0.15
1960 ppm (vol)
Rate
(g/s)
4.6
0.1
60
0.8
13960
1190
816
14
134
Device
Efficiency
Device (%)
None
None
None
None
Electrostatic 99.5
precipitator
Flue gas 90
desulfurization
None
None
Tail-gas scrubber 95
With Best Control
Loading
7.3 g/GJ
0.16
95
1.3
39
66
450
7.7
250 ppm (vol)
Rate
(g/s)
4.6
0.1
60
0.8
70
119
816
14
6,7
-------
particulates8 of 99.5 percent is expected for an electrostatic precipi-
tator followed by flue gas desulfurization, and a reduction of SO3
level8 is expected to be about 90 percent. The tail-gas scrubber should
be 95 percent effective in removing sulfur from the tail-gas stream of
the sulfur plant.
b. Options for Further Control
The clearest option for better control is to select the
process using the manufactured fuel gas. The SO3 levels are similar
but the other emissions are considerably lower. The cost in coal feed
is about 12 percent of the total feed rate. Another option would be to
treat the fuel gas for further sulfur removal. The SO loading from the
tC
fuel gas combustion is already comparable to the scrubbed flue gas from
the coal.
4. Summary
Table 16-12 summarizes the total emissions from each process-
ing plant and feedstock combination considered. These values include
the emissions attributed to generation of electricity needed for each
plant. However, the values given in parentheses in Table 16-12 exclude
the generation of electricity, and are used in Section C to model the
ambient concentrations for those processes. Electricity is assumed to
be generated off-site for the processes modeled.
C. Atmospheric Dispersion Modeling
Requirements for additional control, beyond the levels taken to
represent best available control in the preceding section, are derived
by comparing ambient concentrations of air pollutants that result from
synthetic fuel plant emissions to ambient air quality standards that
532
-------
could apply in the vicinities of the plants. This section describes the
atmospheric dispersion modeling used to calculate ambient concentrations
from emission levels and presents the results of those calculations.
These results are displayed later in this section as possible control
requirements. A subset of these results forms the basis for estimates
of the applicable control requirements (Section D).
Table 16-12
SUMMARY OF EMISSIONS FROM ALTERNATIVE SYNTHETIC
FUEL PLANTS EMPLOYING BEST AVAILABLE CONTROL*
TOSCO II
H-Coal—Powder River
H-Coal—Illinois No. 6
SRC—Northwest
SRC—Central
CSF—Northwest
CSF—Central
SASOL—Fuel gas
SASOL--Coal
Total Emissions Including Electricity
(g/s)
t
Particulates
109(103)
75(69)
28
35
34
21
24
21
75
so2
420(394)
113(91)
169
48
300
'58
321
161
126
NOX
761(514)
1011(802)
293
900
900
540
550
262
876
HC
80(76)
17(13)
4
3
3
3
3
4
15
*Plant size taken to be 16,000 m3/day (100,000 B/D).
tNumbers in parentheses exclude emissions attributed to generation of
electricity.
1. General Principles
Atmospheric dispersion modeling requires suitable specifica-
tion of input data describing both the sources of emission of air pollu-
tants and the region into which the pollutants are emitted. The model
533
-------
employed here requires a standard set of data to characterize sources:
the heights, diameters, temperatures, gas flow rates, pollutant emission
rates, and positions of the stacks comprising the source of emissions.
It also requires readily available meteorological data. (Appropriate
data for source characterization are shown in Tables 16-13 and 16-16 and
Figures 16-1 and 16-6 later in this section.) Information on the emis-
sion source is combined with information on the site in question to form
an estimate of the ambient air quality. The required data are available
for sites near but not precisely at western oil shale and coal regions.
The model used here for calculation of air pollutant concen-
trations is the Climatological Dispersion Model (CDM),12»13 which is a
computerized model that permits calculation of seasonal or annual aver-
age pollutant concentration patterns resulting from stationary point
sources and area sources. The fundamental physical assumption of the
model is that the steady-state spatial distribution of pollutant con-
centration from a continuously emitting point source is given by the
Gaussian plume formula. It is assumed that meteorological conditions
over short periods of time (of the order of one hour) can be regarded
as steady-state and that these conditions can be approximated with a
constant and spatially uniform wind vector for the entire area.
Gaussian plume assumption is used when there are no restric-
tions on vertical diffusion. When vertical diffusion is restricted to
a finite mixing depth, a uniform vertical concentration distribution is
assumed at distances a few kilometers downwind.
Equations for the long-term average concentrations due to
point and area sources are weighted according to a frequency function to
account for the variability of meteorological conditions. These empiri-
cal functions express the observed joint frequency of occurrence of
various classes of wind direction, wind speed, and a stability.
534
-------
Integration of the formulae over the area and point sources describes
the simulated concentration at selected location for a certain set of
meteorological conditions. These concentrations, taken together with
the frequency of occurrence of each combination of conditions, produce
the climatologically averaged spatial distribution of concentration.
The CDM program used in this study assumes that the pollutant
be properly simulated by a single wind vector; thus topographic influ-
ences of complex terrain are not currently incorporated into the dis-
persion model. Topographical features of the regions modeled for oil
shale production in Colorado (Section C-2) and coal liquefaction in
Wyoming (Section C-3) are discussed below.
For comparisons with ambient air quality standards the con-
centration of air pollutants are calculated here using averaging times
that fit the various standards. Four air pollutants are included: par-
ticulates, sulfur dioxide (S02), oxides of nitrogen (NOX) and hydro-
carbons (HC). The time periods involved are: annual averages for par-
ticulates, S02, and NOX; 24-hour averages for particulates and S02; and
a 3-hour average for HC. Since photochemical interactions with NO and
X
HC are not considered, no decay with time of NOX and HC concentrations
is assumed. Decay of S02 is accounted for in model calculations by an
exponential decay term having a 3-hour half life.
The results of the dispersion modeling are compared with fed-
eral and state ambient air quality standards. Emissions and ambient
concentrations of NOX (combining both NO and NO2) are expressed as NO2
equivalent and compared to the N02 standard. This amounts to a worst-
case assumption for NO2 in that NO emissions are assumed to consist
entirely of N02. However, as mentioned above, no photochemical atmo-
spheric dispersion model has been used, and therefore we have not ad-
dressed the possibility that photochemical oxidant formation could be
the most significant limit on emissions of NO,, and HC.
.X.
535
-------
2. Modeling a TOSCO II Oil Shale Plant
a. Characterization of Emission Source
Table 16-13 and Figure 16-1 present the emission source
characteristics required as part of the inputs to the CDM. The emission
rates given in Table 16-13 are those derived and explained in Section B.
Figure 16-1 shows a possible configuration of stacks comprising the
specific emission sources within the 16,000-3/day (100,000-B/D) oil
shale plant, based on the description of a 8,000-m3/day (50,000-B/D)
TOSCO II oil shale complex given by Colony Development Operation.4
Radical changes in the assumed configuration could result in concentra-
tions somewhat different from those calculated here.
b. Characterization of Oil Shale Region
Meteorology and topography will affect the ambient air
quality from a given emission source. The oil shale regions considered
here are the Piceance Basin in western Colorado and the Uinta Basin in
eastern Utah. Because the oil shale deposits developed first are most
likely to be in or near the Piceance Basin, that region is emphasized.
*
(1) Topography. The major oil shale area of the
Piceance Basin lies on the Roan Plateau, bounded by steep escarpments in
all directions. The land surface of the region has been shaped by ero-
sion into valleys and ridges oriented in the north and northeasterly
directions. The difference in elevation from ridge to valley floor
ranges from 62 to 185 m (200 to 600 ft), and most of the valleys are
*The information contained in this section was extracted from Refer-
ence 14.
536
-------
Table 16-13
STACK PARAMETERS AND EMISSION RATES FOR A 16,000-m3/D
(100,000-B/D) TOSCO II PLANT WITH EMISSIONS CONTROLLED*
Location '
1
2
3
4
5
Ul 6
CO
-------
1050m-
-H
en
u
00
11
•>—'
s~>
12
©
12
^—•
11
4 3 3
/v
700m
NOTE: STACK NUMBERS REFER TO TABLE 16-2
NUMBER 10 IS 1500m SOUTH OF PLANT
FIGURE 16-1. TOSCO H PLANT CONFIGURATION
-------
narrow and steep sided. Land elevations above mean sea level (MSL) range
from about 1600 m (5250 ft) near the White River to about 2800 m (9000 ft)
on southern ridge crests.
The Uinta Basin of Utah is a depression bounded by the
Uinta and Wasatch Mountains, the Roan Cliffs, and the cliffs west of the
Douglas Creek Arch. Land features include rough mountains and flat val-
leys, with deep gulleys and rock-capped ridges. Elevations range from
1400 m (4600 ft) to more than 2500 m (8000 ft) MSL.
In general, these steep-sided valleys are unsuitable lo-
cations for plant sites. Moreover, from the point of view of minimizing
pollution potential, oil shale processing facilities should be located
on plateau, rather than valley sites.15 The evidence for the necessity
of such location is sufficiently compelling that the dispersion modeling
reported here is based on the assumption that the oil shale plants will
be located on plateau sites. If an oil shale plant should be located in
a narrow valley, the actual concentrations of pollutants will be higher
than those calculated by the CDM. However, if the facility is located
on a plateau or in a broad valley, as Colony plans for its first plant,
the dispersion model will adequately predict concentration patterns.
(2) Meteorology. The meteorological data required for
application of the CDM are not available within the oil shale region.
Therefore, annual averages were calculated from frequency distributions
of meteorological conditions observed at Grand Junction, Colorado, and
Salt Lake City, Utah because these were the closest weather stations
recording sufficient data. These distributions are the output of the
National Climatic Center's* STAR computer program. However, the wind
*U.S. Department of Commerce, National Oceanic and Atmospheric Adminis-
tration, Environmental Data Service, National Climatic Center, Federal
Building, Asheville, N.C. 28801.
539
-------
data for three stations in the oil shale region show that the differ-
ences in the wind direction frequency distributions between any two
of these stations are at least as great as the differences between Grand
Junction and any of these stations.8 Therefore we have used Grand Junc-
tion meteorology for calculations of air pollutant concentrations ex-
pected in the Piceance Basin. All of the annual average calculations
presented here are based on Grand Junction meteorology. Some other re-
sults based on Salt Lake City meteorology are presented in an earlier
SRI report.8 Sensitivity to meteorology is discussed below in Section
C-5.
Twenty-four hour averages and 3-hour averages were cal-
culated using the assumption that worst-case meteorological conditions
prevailed. Statistical weather records indicate that neutral atmospheric
stability and a light wind of 1.5-m/s occur for 24 hours or longer in the
oil shale region an average of 15 days per year. These conditions have
been shown to be representative of worst-case conditions in the oil shale
region and do not involve use of Grand Junction or Salt Lake City meteo-
rological data. The CDM was used to compute the 24-hour and 3-hour av-
erages for various wind directions, assuming 100 percent frequency of
occurrence of neutral stability and 1.5-m/s winds.
c. Results of Dispersion and Site Modeling
Pollutant dispersion patterns for a 16,000-m3/day (100,000
B/D) TOSCO II plant were calculated using the emission source character-
istics given in Table 16-13 and Figure 16-1 and the characteristics of
possible oil shale sites. Isopleths of concentrations for some of the
pollutants and averaging times are shown in Figure 16-2 through 16-5.
Tables 16-14 and 16-15 summarize model results for the TOSCO II process
and give background concentrations, air quality standards, and the level
of control required to meet each standard. Background concentrations
540
-------
20
1 1 1 T
1 1 1 1 T
T 1 T
N
15
CO
^
Ol
HI
E
I
UJ
CJ
I
—
o
10
BACKGROUND: < 15/tg/m3
PLANT
iiSi REMOTE STACK
16,000 m*/day PLANT WITH EMISSIONS CONTROLLED
STANDARDS
FEDERAL PRIMARY 75
FEDERAL SECONDARY 60
COLORADO 45
CLASS H 10
CLASS I 5
0
I I I I I
I I I I I I I
I I
10
DISTANCE-kilometers
15
20
FIGURE 16-2. ANNUAL AVERAGE PARTICULATE CONCENTRATION
FOR A TOSCO n OIL SHALE PLANT USING GRAND JUNCTION,
COLORADO METEOROLOGY
541
-------
Ul
*>
to
I I I I I I
STAsJARDS (uy/m't
FEDERAL PRIMARY 260
FEDERAL SECONDARY ISO
CLASS H 30
CLASS I 10
REMOTE STACK
16,000 mVdoy PLANT WITH EMISSIONS CONTROLLED
I I I 1 1 I
15 16 17
DISTANCE-kilometers
FIGURE 16-3. 24-HOUR WORST CASE AVERAGE PARTICULATE CONCENTRATION Ug/m3) FOR A
TOSCO I OIL SHALE PLANT UNDER CONDITIONS OF NEUTRAL STABILITY AND A
WEST WIND OF 1.5 msec"1
-------
v>
V
1
_g
STANDARDS (/ig/m*)
BACKGROUND : < 26
FEDERAL PRIMARY 80
CLASS H 15
CLASS I 2
16,000 m'/day PLANT WITH
EMISSIONS CONTROLLED
i 10 -
to
5 -
DISTANCE-kilometers
FIGURE 16-4. ANNUAL AVERAGE S02 CONCENTRATION (Mfl/m3) FOR A
TOSCO E OIL SHALE PLANT USING GRAND JUNCTION,
COLORADO METEOROLOGY
543
-------
£
i
UJ
1
tn
a
16
15
14
13
12
10
900
10
STANDARDS (/ifl/ms)
FEDERAL PRIMARY 365
CLASS n 100
CLASS 1 5
BACKGROUND : 26
(§&> PLANT
16,000 m'/doy PLANT WITH EMISSIONS CONTROLLED
I
12 13 14 IS 16 17
DISTANCE-kilometers
16
19
20
21
FIGURE 16-5. 24-HOUR WORST CASE AVERAGE S02 CONCENTRATION (^q/m) FOR A TOSCO tt
OIL SHALE PLANT UNDER CONDITIONS OF NEUTRAL STABILITY AND A WEST
WIND OF 1.5 msec'1
-------
Table 16-14
CONTROL REQUIREMENTS BASED ON FEDERAL PRIMARY AND COLORADO AIR QUALITY STANDARDS
AND EMISSIONS FROM A 16,000-m3/day (100,000 B/D) TOSCO II PLANT, CONTROLLED
Standard Control
Pollutant Averaging Period
Particulates 1 yr
24 hr
S02 1 yr
24 hr
01
01
HC 3 hr (6-9 AM)
NOY 1 yr
A
Maximum Calculated
(ug/m3)
15
200
18
51
11
23
Background
(Ug/m3)
< 15
15
< 26
26
—
—
Required*
(ug/m3) (percent)
Federal
Primary
75
260
80
365
160
100
Federal
Colorado* Primary
45 None
150 None
None
15 None
— None
None
Colorado
None
25
99+§
—
—
*Based on preliminary Colony Development Operation data. Current measurements suggest that the 26-ug/m3 value
is too high.
tControl required in addition to the best available as specified in Section B.
^Standards for nondesignated areas of Colorado. The 24-hr standard is not to be exceeded more than one day per
year.
§Background concentrations alone may exceed standard.
-------
Table 16-15
CONTROL REQUIREMENTS BASED ON FEDERAL SECONDARY, CLASS I AND CLASS II AIR
QUALITY STANDARDS AND EMISSIONS FROM A 16,000-m3/day (100,000-B/D)
TOSCO II PLANT, CONTROLLED
,£»
OJ
Averaging
Pollutant Period
Particulates 1 yr
24 hr
S02 1 yr
24 hr
Maximum
Calculated
(ug/m3)
15
200
18
51
Background*
(ug/m3)
< 15
15
< 26
26
Federal
Class I
5
10
2
5
Standard
(Ug/m3)
Federal
Class II
10
30
15
100
Control Required'
(percent)
Federal
Secondary
60
150
__
Federal
Class I
67
95
89
90
Federal
Class II
33
85
17
None
Federal
Secondary
None
32
__
"
*Based on preliminary Colony Development Operation data. Current measurements suggest that the 26-ug/m3 value is
too high.
tControl required in addition to the best available as specified in Section B.
-------
were taken from the results of monitoring conducted in the Colorado oil
shale region for Colony Development Operation.16
In calculating the control requirements shown in Ta-
bles 16-14 and 16-15, background concentrations and concentrations re-
sulting from oil shale operations have been considered together for the
federal primary and secondary standards and for the Colorado standards.
This has been done by subtracting the background concentration from the
standard and computing the level of control needed so that the concen-
trations resulting from oil shale facilities do not exceed the remaining
portion of the standard. When background concentrations equal or exceed
a standard, the level of control has been specified as 99+ percent. Fed-
eral Class I and Class II standards are the so-called "nondegradation"
standards; they refer to increases in concentrations and do not involve
background concentrations.
The maximum calculated concentrations and the percent
control requirements given in Tables 16-14 and 16-15 are not always the
same as those that would be derived from a straightforward application
of the calculated dispersion patterns such as Figures 16-2 through 16-5.
Instead, the maximum concentrations used in Tables 16-14 and 16-15 re-
flect our judgment that only concentrations that occur over an appreci-
able area at some distance beyond the plant boundary should be taken as
the basis for a requirement for additional emission control technology.
A control requirement should not be based on a calculated concentration
that occurs in the immediate vicinity of a relative low stack because
in actual commercial operations any such problems would be solved by use
of taller stacks.* Therefore, only concentrations that occur over areas
*The use of taller stacks referred to here concerns replacing relatively
low (about 15 m) stacks with some of moderate height (about 30 m). The
same logic does not apply to avoiding excessive ground level concentra-
tions associated with tall (about 100 m) stacks. See the discussion of
the stack height issue in Section E.
547
-------
of at least 1 km2 at least 1 km away from the plant are included in the
control requirement calculations shown in Tables 16-14 and 16-15.
The judgment just described is of much greater signifi-
cance for oil shale case than for coal liquefaction. Stack character-
istics used in modeling of the oil shale plant emissions are those pub-
lished by Colony4 as part of their plans for an actual facility. In the
coal liquefaction case we have chosen reasonable but hypothetical, stack
parameters for the modeling and have deliberately avoided the low (about
15 m) stacks that can cause anomalously high concentrations in the oil
shale case.
Particulate emissions from the TOSCO II process described
will produce concentrations that exceed all standards listed in Ta-
bles 16-14 and 16-15, escept the federal primary and secondary air qual-
ity standards. Background concentrations for particulates and S03 were
measured in the Parachute Creek area of the Colorado oil shale region by
Colony Development Operation. The analysis of these concentrations16
revealed that the median of the 24-hour averages was about 15 ug/m3.
The average annual background concentration is expected to be less than
15 ug/m3. The combination of background concentrations with plant-
produced concentrations for those standards which are applicable leads
to the conclusion that no additional control is needed to meet the fed-
eral primary 24-hour standard and the Colorado annual standard. The
federal 24-hour secondary standard can be met with approximately 32 per-
cent control of plant emissions. Approximately 95 percent control will
be needed to meet the Class I 24-hour standard and 67 percent will be
needed to comply with the Class I annual standard. The Class II 24-hour
and annual standards require 85 percent and 33 percent controls, re-
spectively.
548
-------
Projected concentrations of S02 do not exceed the federal
primary air quality standards nor the Class II 24-hour standards. Some
4
preliminary measurements suggested a 24-hour average background concen-
tration of SO2 of 26 ug/m3. This is now known to be too high,5 but a
revised measurement has not yet been published. The annual average is
expected to be considerably lower. The addition of background concen-
trations to the calculated concentrations resulting from the plant is
not sufficient to exceed the federal primary air quality standards.
However, S02 concentrations from the plant exceed the stringent Colorado
annual air quality standard, where 99+ percent control is required, since
background concentrations alone may exceed the standard. The federal
Class I annual and 24-hour standards can be met with 89 percent and 90
percent control, respectively. The Class II annual standard requires
only 17 percent additional control.
No additional controls are indicated for N02 and HC in
Tables 16-14 and 16-15. The calculated concentrations of these pollu-
tants are well below the NO2 and HC standards shown. However, as men-
tioned above, no analyses of photochemical oxidant concentrations have
been made.
3. Modeling an H-Coal Syncrude Plant
The Powder River Basin of Wyoming was selected for modeling
the air pollution from plants producing synthetic crude oil from coal
on the basis of physical, economic, and political availability of large
blocks of coal, and the H-Coal process has been selected on the basis of
(1) a relatively well developed technology, (2) high yield of a liquid
product, and (3) availability of process descriptions in the open
literature.
549
-------
a. Characterization of Emission Sources
Table 16-16 and Figure 16-6 present the emission source
characteristics of a 16,000-m3/day (100,000-B/D) coal liquefaction plant
employing the H-Coal process. The emission rates are taken from the
process and control descriptions of Section B of this chapter. These
rates are for a highly controlled plant, one employing the best available
control technology (Section B). Stack characteristics (Table 16-16) were
estimated on the basis of reasonable combustion conditions and other
process requirements, as well as by analogy to the Colony plans for an
oil shale plant. The stack configuration shown in Figure 16-6 was
chosen to occupy an area of about 1 million m3 (250 acres)* and to re-
flect likely capacities of various process units and their associated
stacks. Radical changes in the assumed configuration could result in
concentrations somewhat different from those calculated here.
b. Characterization of Powder River Coal Region
4.
(1) Topography. The strippable coal reserves of the
Powder River Basin are concentrated along a north-south line through
Gillette, Wyoming. The eastern Powder River Coal Basin lies within the
Missouri Plateau in the drainage basin of the Missouri River. The land-
scape consists primarily of plains and tablelands and low-lying hills.
Some areas feature entrenched river valleys, isolated uplands, flat-
topped buttes and mesas, long narrow divides, and ridges 30 to 150 m
(100 to 500 ft) high.
*This area for the conversion process units is consistent with the land
requirement scaling factor given in Chapter 4 and with a published de-
sign for an SRC coal liquefaction facility.17
tThe information contained in this section was extracted from Refer-
ence 18.
550
-------
Table 16-16
STACK PARAMETERS AND EMISSION RATES FOR A 16,000~m3/day
(100,000-B/D) H-COAL PLANT USING POWDER RIVER COAL
Stack
No.*
1
2
3
4
5
6
Description of Unit
Coal dryer—process
Coal dryer — combustion
Steam reformer
Plant (gas fuel)
Plant (coal fuel)
Sulfur plant
Flow Rate'
(all stacks)
(m3/s)
1200
277
603
135
489
27
Temp.
(°C)
63
55
260
260
55
38
No.
of
Stacks
10
2
^ 5
1
4
1
Stack
Height
(m)
30
75
30
30
75
75
Stack
Diameter
(m)
4.
3.
3.
3.
3.
1.3
Gas Exit
Velocity
(m/s)
9.6
19.6
17.1
19.1
17.3
20.3
Emissions (all
(g/s)
Particulates
44
6.6
5.8
1.3
11.7
—
S02
—
27.1
0.19
0.04
47.9
16.
stacks)
NOX
—
257
74
17
454
—
HC
—
4.3
1.0
0.2
7.6
__
*Stack locations are shown in Figure 16-6.
tAt pressure of 87.4 kPa (25.8 inches of mercury) corresponding to an elevation of 1230 m (4000 ft).
-------
1200m-
N
01
01
to
o>
8
NOTE: STACK NUMBERS REFER TO TABLE 16-16
FIGURE 16-6. STACK CONFIGURATION FOR COAL LIQUEFACTION PLANT
-------
The coal basin is part of a topographic depression that
lies between the Black Hills and the Bighorn Mountains. The central
part of the basin consists of a broad plateau, with the strippable coal
near the eastern edge of the rolling, grass-covered upland. Irregular,
rough, broken terrain borders the shallow coal deposits. To the east,
erosion has reduced the terrain to knobs and ridges.
In the northern part of the topographic basin, there are
high open hills north of Gillette and tablelands south of Gillette. The
open hills have a local relief of 120 to 240 m (400 to 800 ft) and the
gently sloping plains and tablelands have local relief of 60 to 120 m
(200 to 400 ft). The southern part of the basin is characterized by
rolling grass-covered prairie cut by broad steam valleys.
(2) Meteorology. Sufficient meteorological data for
application of the CDM are not available for potential coal liquefaction
plant sites within the boundaries of the coal reserve region. However,
a complete weather station is located at Moorcroft, Wyoming, about 25 kra
(15 miles)east of Gillette, and from frequency distributions of meteo-
rological conditions observed there the CDM was used to calculate annual
averages. Considering the topography of the region and the proximity of
Moorcroft to possible plant sites, the meteorology of Moorcroft is a
good approximation of the meteorology of future coal plant sites. The
same type of argument that applied to Grand Junction for the oil shale
region applies here, but with the advantage that the topography of the
Wyoming coal reserves is far less rugged and varied than that found in
the oil shale bearing portions of Colorado.
SRI has recently developed a computer program (WRSCASE)
to determine the days on which worst-case pollutant concentrations oc-
cur. The program takes as input the stack characteristics and emission
rates of a simplified version of a plant and hourly meteorological data
553
-------
for a period considered statistically representative (e.g., 3 years).
It then calculates the hourly pollutant concentrations at several lo-
cations, computes 24-hour (or 3-hour) average concentrations at each
location, and for each pollutant, selects the sequence of meteorologi-
cal conditions that produces the greatest concentration 1 km or farther
from the plant. This program was used with Moorcroft, Wyoming, meteo-
rological data to determine the worst-case sequence for each pollutant
over the appropriate averaging time (24 hours or 3 hours). Table 16-17
lists these worst-case meteorological sequences determined by the pro-
gram and used in the 24-hour and 3-hour average coal liquefaction plant
calculations. When the wind is calm, the wind direction of the previous
hour and a wind speed of 1 m/s are used in model calculations since the
Gaussian plume formulation does not allow for calm winds.
c. Results of Dispersion Modeling
Dispersion of pollutants from a syncrude plant was cal-
culated using the stack characteristics and emission rates listed in
Table 16-16 and the plant configuration illustrated in Figure 16-6.
Figures 16-7 and 16-8 show isopleths of concentrations for various pol-
lutants and averaging times. Tables 16-18 and 16-19 summarize dispersion
model results for a single coal liquefaction plant. Measured values of
background concentrations of particulates in the coal region range from
13 to 21 ug/ra3 (see Reference 16-18). Background levels of SOS, NOX,
and HC have not been measured in the basin. However, 24-hour maximum
and annual average values of SO2 background concentrations have been
measured in nearby Casper,19 and these values are included for reference
in Tables 16-18 and 16-19, Since it can be expected that background
levels in the basin will be less than those measured in the Casper urban
area, it seems safe to assume that no additional controls will be re-
quired for SO2 due to background levels. The method of calculating the
554
-------
cn
01
01
Table 16-17
WORST-CASE METEOROLOGICAL SEQUENCES FOR MOORCROFT, WYOMING
Particulates and NOX
Hour
0100
0200
0300
0400
0500
0600
0700
0800
0900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
S°2
Wind
Direction
10
10
10
6
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
12
(24-hr sequence)
Wind
Speed
(m/s)
11.8
8.2
3.6
2.1
1.5
6.2
6.7
10.8
12.3
11.8
9.8
10.8
12.3
10.3
7.2
8.2
8.7
11.8
8.7
12.3
8.7
14.4
13.4
9.3
Atmospheric
Stability'''
4
4
5
6
6
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
(24-hr sequence)
Wind
Direction*
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
7
8
8
8
. 8
8
8
9
Wind
Speed
(m/s)
10.8
13.4
11.8
15.9
14.4
15.9
18.0
13.4
9.8
18.0
21.6
18.5
20.0
18.5
20,0
17.5
16.4
17.5
15.4
14.9
9.3
7.7
7.7
5.1
Atmospheric
Stability 1"
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
HC (3-hr sequence)
Wind
Wind Speed Atmospheric
Direction* (m/s) Stability
11 1.0 6
11 1.0 3
calm calm 3
*Wind direction sector. The compass is divided into sixteen 22.5° sectors; sector 1 is from 348.75° to 11.24°; succeeding sectors
are in a clockwise direction from sector 1.
tPasquill-Gifford stability categories.
-------
301—r
25
20
15
LU
o
10
BACKGROUND^ I3to2ljug/m3
^^. PLANT
16,000 mVday PLANT WITH EMISSIONS CONTROLLED
N
STANDARDS
FEDERAL PRIMARY 260
FEDERAL SECONDAY 150
AND WYOMING
CLASS II
CLASS I
30
10
i i i i i i i t i
10 15
DISTANCE-kilometers
20
25
30
FIGURE 16-7. WORST CASE 24-HOUR AVERAGE PARTICULATE CONCENTRATIONS
(/ig/m3) FOR A COAL LIQUEFACTION PLANT
556
-------
30
25
20
JO
15
o
<
10
1 I I TT~1 1 1 1 1 1 1 T
BACKGROUND = <
^^t- PLANT
16,000 mVdoy PLANT WITH EMISSIONS CONTROLLED
STANDARDS
FEDERAL PRIMARY 80
WYOMING 60
CLASS 11 15
CLASS I 2
0
-I 1 1 1 1 1 1 1 1 1 1 1 I I i I i I I I I i
10 15 20
DISTANCE - kilometers
25
30
FIGURE 16-8. ANNUAL AVERAGE S02 CONCENTRATIONS (/ig/m3) FOR A COAL
LIQUEFACTION PLANT
557
-------
Table 16-18
CONTROL REQUIREMENTS BASED ON FEDERAL PRIMARY AND WYOMING AIR QUALITY STANDARDS
AND EMISSIONS FROM A 16,000-m3/DAY (100,000-B/D) COAL SYNCRUDE PLANT
00
Pollutant
Particulates
S02
NOX
HC
Averaging
Period
1 yr
24 hr
1 hr
24 hr
3 hr
1 yr
3 hr
(6-9 a.m.)
Maximum
Calculated
(ug/m3)
4
25
2
7
38
15
4
Standard
(Ug/m3)
Background
(ug/m3)
13 to 2l1"
13 to 21t
5*
16*
—
—
Federal
Primary
75
260
80
365
1300
160**
100
Wyoming
60
150*
60
260§
1300§
100**
160*
Control Required
Federal
Primary
None
None
None
None
None
None
None
Wyoming
None
None
None
None
None
None
None
*Control required in addition to the best available as specified in Section B of this chapter.
tMeasured in the Powder River Basin (Reference 18).
^Measured at Casper, Wyoming (Reference 19).
§Not to be exceeded more than once per year.
**NO3 standard.
-------
Table 16-19
CONTROL REQUIREMENTS BASED ON FEDERAL SECONDARY, CLASS I AND CLASS II AIR QUALITY STANDARDS
AND EMISSIONS FROM A 16,000-m3/DAY (100,000-B/D) COAL SYNCRUDE PLANT
Averaging
Pollutant Period
Particulates 1 yr
0, 24 hr
01
!£>
S02 1 yr
24 hr
Maximum
Calculated
(Ug/m3)
4
25
2
7
Background
-------
control requirements shown in Tables 16-18 and 16-19 is the same as that
described for oil shale.
The dispersion calculations (Figures 16-7 and 16-8;
Tables 16-18 and 16-19) indicate that no additional controls are re-
quired to meet any of the standards except the 24-hour Class I particu-
late and SO2 standards. To meet the federal "nondegradation" standard
for particulates, emissions must be controlled by an additional 60
percent, and to meet the "non-degradation" standard for SOu , emissions
must be controlled by an additional 29 percent.
4. Effects of Multiple Plants in a Region
a. Assumptions for Modeling
Lack of definite meteorological data and plant site in-
formation makes it necessary to base the modeling of air pollution from
a complex of plants on a possible, but hypothetical, situation. In the
modeling process, a simplified worst-case situation was devised. Four
plants, identical to the single coal liquefaction plant first modeled,
were sited 6 km apart on a north-south line. The 6-km separation is
about the minimum separation possible for plants using a 20-year supply
of coal from a 9 m (30 ft) seam of Powder River coal. Annual average
pollutant concentrations from the plant complex were calculated using
the Moorcroft annual frequency distribution. In the actual 24-hour
average worst-case, the meteorological sequence was a wind from the
south-southeast for 22 hours with one hour periods with the wind blow-
ing from adjacent sectors.* For this calculation, the sequence was
rotated clockwise by one sector so that for 22 hours the wind blew from
the south. Such a sequence, although hypothetical, was judged to be
possible and would represent the worst-case for the complex of plants
*There are 16 wind direction sectors.
560
-------
assumed. Thus, for the most part, the wind is assumed to be blowing
along the string of plants, causing superposition of plumes. This syn-
thesized sequence of meteorological conditions is likely to occur and
represent a worst-case wind direction.
b. Results for Complex of Coal Syncrude Plants
Figures 16-9 and 16-10 show the complex of four plants
and illustrate results of the dispersion modeling for the two cases that
lead to maximum control requirements. Similar calculations for compari-
son with the complete set of ambient standards have been made. The re-
sults for all of the pollutants and averaging times are summarized in
Tables 16-20 and 16-21. Background concentrations are treated as they
were for oil shale (Tables 16-14 and 16-15).
As shown in Tables 16-20 and 16-21, no additional control
is required to meet the federal primary or secondary standards nor the
Wyoming standards for any of the pollutants modeled. However, Table 16-21
indicates some additional control requirements based on Class I and II
standards. For particulates, 17 percent control is required to meet the
annual Class I standard; 75 percent is required to meet the 24-hour
Class I standards; and 25 percent is needed to satisfy the 24-hour
Class II standard. The annual Class II standard for particulates can
be met with no additional controls.
Again referring to Table 16-21, no additional controls
are needed to comply with the Class II SO standards. For the annual
2
Class I standard for SOg, an additional 67 percent control is needed,
and for the 24-hour Class I S02 standard, an additional 77 percent
control is needed.
561
-------
30
25
20
15
en
a
10
BACKGROUND: I31o2l
j^. PLANTS
FOUR I6.0CO m'/day PLANTS
WITH EMISSIONS CONTROLLED
III
I I L I
N
STANDARDS!
FEDERAL PRIMARY 260
FEDERAL SECONDARY I 50
AND WYOMING
CLASS It 30
CLASS I 10
i i i i i i i i i
10 15 20
DISTANCE-kilometers
25
30
FIGURE 16-9. WORST CASE 24-HOUR AVERAGE PARTICULATE CONCENTRATIONS
(/ig/m3) FOR A COMPLEX OF COAL LIQUEFACTION PLANTS
562
-------
40
35
30
25
V
I 20
UJ
o
o
15 -
10 -
5 f- BACKGROUND
|p*- PLANTS
FOUR 16,000 mVday PLANTS
WITH EMISSIONS CONTROLLED
"1 I I 1—I 1—I 1 1 1 T
N
STANDARDS (//.q/m3)
FEDERAL PRIMARY 80"
WYOMING 60"
CLASS II . 15"
CLASS I 2~
I I I I I I i
10 15
DISTANCE-kilometers
20
25
30
FIGURE 16-10. ANNUAL AVERAGE S02 CONCENTRATIONS
FOR A COMPLEX OF COAL LIQUEFACTION PLANTS
563
-------
Table 16-20
CONTROL REQUIREMENTS BASED ON FEDERAL PRIMARY AND WYOMING AIR QUALITY STANDARDS
AND EMISSIONS FROM A COMPLEX OF FOUR 16,000-m3/DAY COAL SYNCRUDE PLANTS
Pollutant
Particulates
S03
Averaging
Period
1 yr
24 hr
1 yr
24 hr
3 hr
Maximum
Calculated
(Ug/m3)
6
40
6
22
38
Standard
(Ug/m3)
Background
(Wg/m3)
13 to 21*
13 to 21^
5*
16*
Federal
Primary
75
260
80
365
1300
Wyoming
60
150*
60
1300$
Control
(%
Federal
Primary
None
None
None
None
None
Required
)
Wyoming
None
None
None
None
None
NO
HC
1 yr
3 hrs
(6-9 a.m.)
40
100
100
160
**
None
None
None
None
*Control required in addition to the best available as specified in Section B of this chapter.
tMeasured in the Powder River Basin (Reference 19).
^Measured at Casper, Wyoming (Reference 19).
§Not to be exceeded more than once per year.
**N02 standard.
-------
Table 16-21
CONTROL REQUIREMENTS BASED ON FEDERAL SECONDARY, CLASS I, AND CLASS II
AIR QUALITY STANDARDS AND EMISSIONS FROM A COMPLEX OF FOUR
16,000-m3/DAY COAL SYNCRUDE PLANTS
01
Pollutant
Particulates
S03
Averaging
Period
1 yr
24 hr
1 yr
24 hr
Maximum
Calculated
(ug/m3)
6
40
6
22
Background
(Ug/m3)
13 to 2lt
13 to 2lt
5*
16*
Federal
Class I
^ 5
10
2
5
Standard
(Ug/m3)
Federal
Class II
10
30
15
100
Control Required
Federal Federal
Secondary Class I
60 17
150 75
67
77
(%)
Federal
Class II
None
25
None
None
Federal
Secondary
None
None
—
—
*Control required in addition to the best available as specified in Section B of this chapter,
tMeasured in the Powder River Basin (Reference 18).
^Measured at Casper, Wyoming (Reference 19).
-------
5. Sensitivity Analysis
a. Variation of Stack Parameters
The Gaussian plume formulae used in the CDM assume that
air pollutants originate from a point located along the vertical axis of
the physical stack. The distance of the effective source point above
ground level is called the effective stack height, H. The effective
height is a sum of two terms, the physical stack height, h, plus the
plume rise, Ah, i.e., H = h + Ah.
The plume rise is a function of stack characteristics,
wind speed, and distance from the source. Physically, the plume rise is
caused by both the upward velocity of the gas emerging from the stack
and the buoyancy of the hot stack gas in the cooler ambient air. The
buoyancy effect generally dominates. The combined effect is described
by a buoyancy flux parameter, F, whose value can be calculated from the
ambient air temperature and the stack parameters, namely, gas exit veloc-
ity, gas temperature, and stack diameter. The value of F is a measure
of the flow (or flux) of heat energy from the stack, with the reference
or zero level of heat energy being set by the ambient temperature in
accordance with the formula81
F .
where g is the acceleration of gravity, V is the gas exit velocity, R is
the inner radius of the stack, and T and Ta are the absolute temperatures
of the gas and the ambient air, respectively. The plume rise itself, Ah,
is proportional to the one-third power of F and is inversely proportional
to the wind speed. The proportionality constant is different for differ-
ent distances from the source and ranges of F.
566
-------
By using the derived parameter F as the indicator of plume
rise it is possible to reduce the number of possible stack parameters
that must be considered as individual cases in determining how changes
in stack parameters can affect the control requirements presented here.
Quantity F was calculated for all of the stacks used in modeling the oil
shale and coal liquefaction plants, and six nonzero values of F were
identified that could be taken to be typical of six groups encompassing
the range of reasonable stack parameters. Table 16-22 lists the six F
values chosen and indicates several sets of stack parameters that would
lead to each of the F values.
Table 16-23 shows how different combinations of buoyancy
flux, F, and physical stack height, h, yield different values of the
calculated maximum concentration of air pollutants emitted by a single
stack. The maximum concentration used to normalize the values shown in
the fourth column of Table 16-23 is that of Case 1, i.e., at a distance
of 1 km from a low (15.2 m or 50 ft) stack with no buoyancy flux.
Higher concentrations less than 1 &m from the source are not included
for consideration in the table for the reasons given above in Section
C-2, namely, the fact that unacceptably high concentrations close to a
low stack will almost certainly be reduced by using higher stacks rather
than by employing more stringent emission control systems.
Some meteorological assumptions are indicated explicitly
in Tables 16-22 and 16-23. In both of these, an ambient temperature of
5°C (41°F) was used for the calculations. In Table 16-23 the meteoro-
logical assumptions are those appropriate for a worst-case situation,
namely, neutral stability and a wind constant in direction and speed
at 1.5 m/s.
If the ambient concentration of an air pollutant can be
attributed entirely to a single stack within a plant, results like those
567
-------
Table 16-22
STACK CHARACTERISTICS THAT RESULT IN VARIOUS
BUOYANCY FLUX VALUES (F VALUES)
s3 Exit Velocity Gas Temperature Stack Diameter
F* (m/s) (°C) (m)
Any diameter
1.3
1.9
3.0
0.8
3.0
4.0
2.0
1.5
2.1
1.6
2.0
4.0
4.0
3.0
2.0
4.0
3.0
5.5
4.0
2.5
3.0
3.4
4.9
3.6
*For ambient temperature equal to 5°C.
0
9
9
9
9
60
60
60
60
68
68
68
68
104
104
104
104
190
190
190
190
302
302
302
302
Any velocity
20.4
9.6
3.9
22.5
17.8
9.3
11.9
17.0
8.6
14.9
10.8
6.8
7.9
7.4
20.6
19.0
18.0
10.0
7.6
17.4
21.7
14.9
10.0
14.9
Ambient
38
38
38
100
55
60
300
500
751
751
500
100
145
500
300
50
260
100
500
700
481
700
300
500
568
-------
Table 16-23
SINGLE STACK SENSITIVITY ANALYSIS RESULTS*
Case
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
m4
s3
0
0
0
0
9
9-
9
9
68
68
68
68
104
104
104
104
302
302
302
302
Stack Height
(m)
15.2
30.5
61.0
121.9
15.2
30.5
45.7
76.2
15.2
24.4
45.7
76.2
38.1
45.7 '
76.2
121.9
15.2
30.5
61.0
121.9
Normalized
Value
1.000
0.786
0.164
0.027
0.252
0.118
0.066
0.031
0.0042
0.0042
0.0042
0.0038
0.0025
0.0025
0.0021
0.0017
0.0001
0.0002
0.0002
0.0002
*A constant wind direction and neutral stability were used
in this analysis. Results will vary for other stabilities
and a nonconstant wind direction. Wind speed used here is
1.5 m/s.
tA value greater than that used as the maximum occurred < 1 km
from source.
Distance
from Source
(km)
it
2
5
it
2t
3
5
15I
15
15
15
20
20
20
20
569
-------
displayed in Tables 16-22 and 16-23 are adequate for assessing the im-
pact of a change in stack parameters. For instance, a stack 76-m high
by 1.3 ra in diameter emitting a fixed rate of some pollutant with an
exit velocity of 20.3 m/s and a temperature of 38°C has an F value of 9,
as given in Table 16-22, and would be Case 8 of Table 16-23. Replace-
ment of this by a Case 3 stack, one releasing the pollutant at the same
rate but at a height of 61 m and at ambient temperature, would lead to
a factor of 5.3 (i.e., 0.164/0.031) increase in the maximum concentra-
tion and would result in the new maximum occurring at a distance of 2 km
from the stack instead of the previous 5 km.
To better understand the sensitivity of the dispersion
pattern of an entire plant, in which emissions from a single stack do
not dominate, a two-stack sensitivity analysis was performed, based on
two sets of stack parameters that are fairly characteristic of the many
stacks listed in Table 16-16 for a coal liquefaction plant. A listing
of the buoyancy flux values and stack heights for the coal liquefaction
plant reveals that a stack having an F value of 9 accounts for 18 per-
cent of the S02 emissions and that stacks having F values near 60 ac-
count for the other 82 percent. We used the CDM to calculate dispersion
patterns resulting from the combination of two stacks having these F
values on an 82/18 ratio of emission rates. The calculations were made
for a variety of assumed stack heights. Results are presented as the
first nine cases shown in Table 16-24. Similar listing and grouping
based on the emissions of the other pollutants from the coal liquefac-
tion plant leads to a two-stack model that has 90 percent of the emis-
sions from stacks having an F value of about 60 and 10 percent of the
emissions from stacks having an F value near 190. Cases 9 through 18
in Table 16-24 show how the calculated maximum concentration changes
with various combinations of physical stack heights for the two stacks.
570
-------
Table 16-24
TWO-STACK SENSITIVITY ANALYSES RESULTS
Maximum Concentration
Case
1
2
3
4
5
6
7
8
9
F1
m4
s3
9
9
9
9
9
9
9
9
9
Stack
Height!
(m)
15
15
15
30
30
30
75
75
75
Fj,
m4
s3
60
60
60
60
60
60
60
60
60
Stack
Heightg
(m)
30
75
122
30
75
122
30
75
122
Normalized
Value
1.0
1.0
1.0
0.46
0.46
0.46
0.15
0.14
0.12
Distance from Source of
Maximum Concentration
(km)
it
it
it
2t
2t
2t
5
5
5
Case
10
11
12
13
14
15
16
17
18
F4
m4
s3
60
60
60
60
60
60
60
60
60
Stack
Height 1
(m)
30
30
30
75
75
75
122
122
122
F4
m4
s3
190
190
190
190
190
190
190
190
190
Stack
Height,,
(m)
30
60
122
30
60
122
30
60
122
Distance from Source of
Normalized Maximum Concentration
Value
1.0
1.0
1.0
0.75
0.75
0.75
0.50
0.50
0.50
(km)
10
10
10
10
10
10
14
14
14
*A constant wind direction and neutral stability were assumed.
vary for other stabilities and a nonconstant wind direction.
tWind speed was assumed to be 1.5 m/s.
Results will
571
-------
b. Roles of Other Variables
Changes in the configuration of stacks located within a
plant may or may not have a significant effect on pollutant concentra-
tions. If new stack locations do not differ appreciably from previously
assumed locations, that is, stack locations are shifted within the previ-
ously defined boundaries of the plant, changes in calculated concentra-
tions will be minimal. However, if the location of a stack is changed
to a position that is removed from the confines of the plant area (or
vice versa), pollutant patterns may be significantly affected, and con-
centrations and resulting control requirements should be recalculated.
Moreover, for a stack having a small effective stack height (the sum of
plume rise and physical stack height), movement of the stack from one
side of the plant boundary to the other may cause an appreciable dif-
ference in concentrations at receptor locations near the plant boundary.
When a significant portion of the pollutant emissions emanate from such
a stack, the maximum concentration is usually close to the stack. For
this study, a receptor must be located at least 1 km from the plant
boundaries to qualify as the point at which the maximum concentration
occurs. Therefore, if the wind direction is roughly constant (as it is
for 24-hour and 3-hour averages), movement of such a stack from the down-
wind edge of the plant boundary to the upwind edge (or vice versa) could
greatly affect the maximum concentration. In this case, concentrations
and control requirements should be recomputed. However, for most stacks,
maximum concentrations occur at distances sufficiently removed from the
plant so that relocation of a stack within the confines of the plant
will alter the shape and magnitude of pollutant cbncentration patterns
only slightly.
Pollutant concentrations are directly proportional to
emission rates. Thus, if the emission rates of all stacks within a
plant are changed by the same factor, pollutant concentrations will also
572
-------
change by that factor. However, if the emission rates of some, but not
all, stacks change, pollutant concentrations must be reassessed, unless
the dispersion pattern, or at least the maximum concentration of the
pattern, can be approximated as being due to a single emission source.
Such an approximation will be warranted to the extent that a single
stack dominates the emissions.
Finally, the meteorology assumed in a calculation obvi-
ously has a significant influence on the concentration pattern and lev-
els calculated. While a systematic analysis of meteorological parameters
similar to that just described for stack parameters was not performed,
some indication of the sensitivity of the calculations to meteorological
assumptions can be obtained from a comparison of two COM results for
the TOSCO II oil shale plant. Reference 2 gives annual average calcu-
lations of ambient air quality near a 16,000-m3/day (100,000-B/D) oil
shale plant based on both Salt Lake City and Grand Junction meteorology.
The results presented here in Tables 16-14 and 16-15 include annual
averages based on Grand Junction data. If Salt Lake City data had been
used instead, the annual average maximum concentrations would change
from 15 to 30 ug/m3 for particulates, 18 to 15 ug/m3 for S02, and 23 to
20 wg/m3 for NO3. The change for particulates leads to an estimate of
additional control required that is appreciably higher than those given
in Tables 16-14 and 16-15.
c. Conclusions from the Sensitivity Analysis
Because of the relatively small effort within this proj-
ect that could be devoted to a sensitivity analysis of atmospheric dis-
persion modeling, the conclusions presented here are tentative.
The very large range of maximum concentrations associated
with the various cases of stack parameters shown in Tables 16-23 and
573
-------
16-24 suggests that the calculated control requirements are extremely
sensitive to the choice of stack parameters. Although the range is
narrowed considerably by selection of stack parameters most likely to
be employed in practice (i.e., notice the reduced range of maximum con-
centrations in Table 16-24, compared with that in Table 16-23), the un-
certainty in maximum concentrations remains substantial. A range of a
factor of 3 or 4 can be found in Table 16-24, even after the low (15 m)
stacks are ruled out. The interpretation of the limited sensitivity
analysis performed here is derived from the summary presented in Ta-
ble 16-24 and the results, described above for oil shale, that indicate
the unsuitability of 15 m stacks. On this basis a range of a factor of
3 or 4 (suggested by the 0.12 to 0.46 range in Table 16-24) is probably
a reasonable estimate for maximum concentrations that would be associ-
ated with likely stack parameters. Therefore, a maximum concentration
calculated to be 100 units could be as low as 40 or 50 units or as high
as 150 or 160 units, depending on the parameters of the stacks employed
in the plants.
The suggestion that 15 m stacks are unacceptably low as
sources of substantial emissions is one of several implications that
emerge from this sensitivity analysis. Another implication, emphasized
by the F = 0 cases of Tables 16-22 and 16-23, concerns the high potential
for air pollution associated with stacks emitting pollutants at ambient
temperature. The need for very substantial application of particulate
emission control to the ore preparation (i.e., crushing) stages of the
TOSCO II oil shale plant arises from the emission of large quantities
of dust at ambient temperature. A third implication is the significant
improvement in ambient air quality in the vicinity of a plant that can
be achieved through use of tall stacks. This is most pronounced for the
low F values shown in Table 16-23, where increasing a moderate (30 m)
stack to a tall (120 m) stack cuts the maximum concentration by a factor
574
-------
of more than 20. A fourth implication, shown by the increase in distance
of the maximum concentration point as stack height is increased, is that
the lowered maximum concentration is necessarily accompanied by an in-
creased area and distance affected by the air pollution. This fact is
one of those that has led EPA to restrict the stack height that can be
used to meet ambient air quality standards. (See Section E.) Finally,
an implication that is directly related to the one just named, is that
the overlap of plumes from two or more plants is greater when tall stacks
lead to dispersion over a larger area surrounding the plant. Comparison
of Cases 2 and 4 in Table 16-23 suggests that the area affected in the
tall (120 m) stack case is 25 times that affected by the moderate (30 m)
stack case, a factor comparable to the reduction in level of the maximum
concentration in the two cases. Thus, the need for a multiple-plant,
regional, air pollution analysis is greater for the tall stack cases.
D. Control Requirements
i*
To provide a unique estimate of the control required in addition to
the estimates given in Section C (Tables 16-14, 16-15, 16-18, 16-19,
16-20, and 16-21), a particular comparison ambient air quality standard
must be selected. The actual setting of these standards for regions in
which synthetic fuel plants may eventually be located will be one criti-
cal factor that could affect deployment of the plants. In deriving con-
trol requirements, the Class II standards proposed by EPA were selected
as one of three sets of standards that the states could choose to pre-
vent significant deterioration of air quality in regions now enjoying
relatively unpolluted air.
Of the three levels of standards proposed by EPA, Class II repre-
sents those that are strict but not so strict that they preclude indus-
trial development. The other two levels are Class I, intended for
575
-------
application in regions that are to remain underdeveloped, and Class III,
equivalent to the existing federal secondary standards (or primary when
no secondary standards exist). We have chosen Class II as the comparison
standard because (1) concern over air pollution in the Colorado and
Wyoming areas considered in Section C makes it unlikely that air quality
there will be allowed to be degraded to the most lenient standard, and
(2) the most strict standards will not be applied if a significant syn-
thetic fuels industry is to be brought into existence.
Control requirements for an oil shale plant, based on application
of Class II standards to the dispersion modeling results of the pre-
ceding section, are shown in Table 16-25. The validity of the control
requirements given in Table 16-25 depend not only on the comparison
standard chosen but on the particular inputs of emission and meteorologi-
cal data used in the dispersion modeling. Sensitivity to these inputs
was discussed in Section C-5. To compensate for local effects of un-
necessarily low (about 15 m in height) stacks, only concentrations that
are calculated to apply over areas more than 1 kms in size and more than
1 km in distance from the plant are used to derive the control require-
ments given in Table 16-25. Hence, the calculated maximum concentration
of particulates for the 24-hour worst case is taken as 200 ug/m3 rather
than the peak concentration greater than 300 ug/m3 shown in Figure 16-3.
Figures 16-4 and 16-5 show other cases summarized in Table 16-25.
Table 16-26 presents the control requirements derived for the H-
Coal plant modeled in Section C. Again, Class II standards are used for
comparison. In this case, no violation of the Class II standards indi-
cated by the calculations based on emissions from a single 16,000-m3/day
(100,000-B/D) coal liquefaction plant. Only the particulate emissions
come close to exceeding the comparison ambient air quality standard.
Figures 16-7 and 16-8 show the dispersion pattern of the particulate and
SOg emissions leading to the control requirements summarized in Table 16-26,
576
-------
Table 16-25
CONTROL REQUIREMENTS BASED ON A SINGLE 16,000-m3/DAY
(100,000-B/D) OIL SHALE PLANT*
Pollutant
Particulates
S03
NOX
HC
Calculated
Concentration
(Ug/m3)
200
18
23
11
Averaging
Time
24 hr
1 hr
1 yr
3 hr
Class II
Standard
(Ug/m3)
30
15
1001"
160*
Control
Requirement51
85
17
None
None
*Plant is controlled to best available control level as defined in
Section B. Control requirement is in addition to that level.
tFederal primary standard for N02; no Class II standard exists.
tFederal primary standard for hydrocarbons, 6-9 a.m.; no Class II
standard exists.
Table 16-26
CONTROL REQUIREMENTS BASED ON A SINGLE 16,000-m3/DAY
(100,000-B/D) COAL LIQUEFACTION PLANT*
Pollutant
Particulates
S02
NOX
HC
Calculated
Concentration
(Ug/m3)
25
2
15
1
Averaging
Time
24 hr
1 yr
1 yr
3 hr (6-9
a.m.)
Class II
Standard
(Ug/m3)
30
15
loot
160*
Control
Requirement
None
None
None
None
*Plant is controlled to best available control level as defined in
Section B. Control requirement is in addition to that level.
tFederal primary standard for N02 ; no Class II standard exists.
tFederal primary standard for hydrocarbons, 3 hr, 6-9 a.m.; no
Class II standard exists.
577
-------
Table 16-27 presents values for control requirements for coal
liquefaction plants based on dispersion modeling of the complex of four
plants shown in Figures 16-9 and 16-10. The combination of plant loca-
tions and meteorology used for the modeling of emissions from a complex
of plants represents a worst-case situation. Comparison of Tables 16-26
and 16-27 shows that for multiple plants the maximum concentrations of
pollutants are increased by a factor of approximately 3.
Table 16-27
CONTROL REQUIREMENTS BASED ON A COMPLEX OF FOUR
16,000-m3/DAY (100,000-B/D) COAL LIQUEFACTION PLANTS*
Pollutant
Particulates
SO2
NOX
HC
Calculated
Concentration
(ug/m3)
40
6
40
3
Averaging
Time
24 hr
1 yr
1 yr
3 hr (6-9
a.m.)
Class II
Standard
(ug/m3)
30
15
lOO1"
160*
Control
Requirement
(%)
25
None
None
None
*Each plant is controlled to "best available control" level as defined
in Section B. Control requirement is in addition to that level.
tFederal primary standard for NO2; no Class II standard exists.
^Federal primary standard for hydrocarbons, 6-9 a.m.; no Class II
standard exists.
The increase in maximum particulate concentration is not as large be-
cause the single-plant maximum in that case is closer to the plant and,
therefore, the overlap between the dispersion patterns of the different
plants occurs farther out from the position of the single-plant maximum.
The increases over the single-plant case are sufficient to indicate some
578
-------
need for additional control of particulate emissions from coal liquefac-
tion plants.
Table 16-28 summarizes emissions, ambient concentrations, standards,
and control requirements for synthetic liquid fuel plants.
1. Conclusions
A general conclusion that can be drawn from the foregoing
analysis is that control beyond the best available technology will be
needed for particulate and SO2 emissions from synthetic liquid fuel
plants located in relatively undeveloped regions of the United States.
In the absence of nondegradation standards for N03 and HC, there is no
apparent need for improved control of these pollutants.
Specific conclusions are as follows:
• Particulate emissions from oil shale plants may have to
be reduced. The TOSCO II retorting process modeled here
requires an additional 85 percent control beyond that of
the best available 'technology to meet the Class II 24-
hour standard of 30 ug/m3. Other oil shale processes
are expected to have lower particulate emission control
requirements.
• Sulfur dioxide (S02) emissions from oil shale plants
may have to be reduced by an additional 17 percent
beyond that of the best available technology to meet
the Class II annual standard of 15 p-g/m
• No additional control on emissions of nitrogen oxides
(NO ) and hydrocarbons (HC) from the oil shale plant
X
are indicated by comparisons with air quality standards
for nitrogen dioxide (N02) and hydrocarbons. No
Class II standards exist for these pollutants. Be-
cause the scope of this work did not include photo-
chemical reactions in the dispersion modeling, the
conclusion regarding NO and HC emissions is not
X
based on comparisons with ambient standards for
photochemical oxidant.
579
-------
Table 16-28
SUMMARY OF EMISSIONS AND CONTROL REQUIREMENTS
Control
Amount Device or
Type (kg/hr) Method
Oil shale
Particulates 107,700 Baghouse,
cyclone,
scrubber
SO2 2671 Treated fuels,
tail-gas
0, NOX 5343
00
® HC — Incinerator
Coal liquefaction
Particulates 28,300 Multiple
cyclones,
Venturi
scrubber,
electro-
static
precipitator
SOS 2700 Scrubber
NO 2890 None
HC 47.2 None
Emissions
Efficiency Remaining
With Best With Best
Control Control
(%) (kg/hr)
99.66 370
47 1417
65 1849
272
99.12 250
88 330
2890
47.2
Ambient Air Quality
Comparisons
Calculated from
Best Control Case
(Ug/m3)
200
18
23
11
25
2
15
4
Class II
Standard
(Ug/m3)
30
15
100t
ieot
30
15
100*
160*
Additional
Control
Requirement
(%)
85
17
None
None
None
None
None
None
*Based on Table 16-15 and accompanying text.
tFederal primary standard. No Class II standard exists.
^Federal primary standard. No Class II standard exists.
-------
• Emissions from a single large coal liquefaction plant
employing best available control will not result in
violation of ambient air quality standards for any of
the four pollutants considered. However, particulates
and SO2 are within factors of 1.2 and 7.5, respectively,
of violating Class II standards, while the other two
pollutants, NO2 and HC, are far from violation of the
relevant comparison standards (federal primary).
• Dispersion modeling based on a worst-case configuration
of a complex of four coal liquefaction plants indicates
a need for 25 percent additional control of particulates.
Ambient concentrations of SCL remain below Class II stand-
-------
achieving additional control. Because hydrotreating
of fuel oil is an integral part of oil shale proc-
essing and because additional hydrotreating may be
needed for NO control, it would be premature to
X
recommend FGD for oil shale plants. Only the con-
tinued improvement of FGD technology is recommended;
the 90 percent control expected from FGD units would
be adequate to meet the estimated requirement,
Oil Shale NOX Control—No requirement for additional
control of NOX has been established by comparison of
dispersion modeling results with ambient air quality
standards. However, because the achievement of emis-
sions consistent with best available control is likely
to require a reduction of the nitrogen content in raw
shale oil, the feasibility of more extensive hydro-
treating of plant fuels should be studied. This has
significance beyond the oil shale plant because the
product oil, with its high nitrogen content, is a
candidate for sale as a fuel oil as well as a re-
finery feedstock.
Air Quality Standards in Undeveloped Regions—Both the
setting of nondegradation standards and the designa-
tion of regions within which the standards will apply
are issues. The conclusions presented in this chapter
based on Class II standards are not the only ones pos-
sible, and it is recommended that the tables in Sec-
tion C be used by readers interested in control re-
quirements based on other standards that could be
applied.
Tall Stacks--Use of tall stacks (higher than about
100 m) to disperse pollutants sufficiently to avoid
violation of ambient air quality standards in the
vicinity of industrial plants is a subject of current
controversy, especially for electric power plants.
The results presented in this chapter illustrate the
sensitivity of control requirements to the height of
stacks employed in a plant. Additional analysis of
the physical, economic, and legal aspects of this
issue, should be carried out if more definitive con-
trol requirements are desired.
Control Requirements Specific to Unit Operations--
Additional dispersion modeling would make it possible
to assign control requirements to unit operations
582
-------
within the energy conversion facilities. If more
definitive control requirements are desired, addi-
tional analysis should be performed to better re-
solve the location within the plant in which control
requirements would be most important and productive.
• Multiple Plants and Emission Sources in a Region—
The most significant air pollution issue associated
with synthetic liquid fuels concerns the regional
impact of large-scale development of both energy
facilities and population. The preliminary analysis
of a complex of four liquefaction plants in the
Powder River Basin has predicted a factor of 3 in-
crease in concentrations calculated for some pollu-
tants and averaging times. Alternative approaches
to determining control requirements based on re-
gional, multiplant considerations should be iden-
tified, developed, and compared.
• Sensitivity Analysis—The preliminary analysis of
the sensitivity of the calculations used in this
chapter to variations in emission parameters con-
firms the importance of specifying these in esti-
mating control requirements. This limited work,
reinforced by implications of the preceding recom-
mendations on tall stacks, unit operations, and
multiple plants, leads us to a recommendation for
further sensitivity analysis. Such work would be
especially important if dispersion modeling cal-
culations become the basis for determining whether
a plant would meet the nondegradation standards at
its proposed location.
583
-------
REFERENCES
1. E. E. Hughes, E. M. Dickson, and R. A. Schmidt, "Control of Envi-
ronmental Impacts from Advanced Energy Sources," EPA-600/2-74-002,
Stanford Research Institute, Project 2714 (1974).
2. E. E. Hughes, P. A. Buder, C. V. Fojo, R. G. Murray, and
R. K. White, "Oil Shale Air Pollution Control," EPA-600/2-75-009,
Stanford Research Institute, Project 2714 (1975).
3. "Air Quality Implementation Plans," U.S. Environmental Protection
Agency, Federal Register, Vol. 39, No. 235, Part III (December 5,
1974).
4. "An Environmental Impact Analysis for a Shale Oil Complex at
Parachute Creek, Colorado," Vol. I, Part I, Colony Development
Operation (1974).
5. Robert E. Smith, Atlantic Richfield Company (Colony Development
Operation), private communication.
6. R. L. Goen, C. F. Clark, and M. A. Moore, "Synthetic Petroleum for
Department of Defense Use," AFAPL-TR-74-115, Stanford Research
Institute, Project 3401 (1974).
7. "Compilation of Air Pollution Emission Factors," AP-42, Second
Edition, U.S. Environmental Protection Agency (April 1973).
8. Proceedings: Flue-Gas Desulfurization Symposium—1973, EPA-650/2-
73-038 (December 1973).
9. "The Cost of Clean Air," U.S. Government Printing Office Document
No. 93-122 (September 1974).
10. "Environmental Impacts, Efficiency, and Cost of Energy Supply and
End Use," Final Report, HIT-593, Vol. 2, Hittman Associates, Inc.
(January 1975) .
11. "A SASOL Type Process for Gasoline, Methanol, SNG, and Low-Btu Gas
from Coal," EPA-650/2-74-072 (July 1974).
584
-------
12. D. 0. Martin and J. A. Tikvart, "A General Atmospheric Diffusion
Model for Estimating the Effects on Air Quality of One or More
Sources," Air Pollution Control Association Paper No. 68-148 (1968).
13. K. L. Calder, "A Climatological Model for Multiple Source Urban Air
Pollution," presented at the First Meeting of the NATO Committee
on the Challenges of a Modern Society, Paris, France (26-27 July
1971).
14. Final Environmental Statement for the Prototype Oil-Shale Leasing
Program, Vol. I., "Regional Impacts of Oil Shale Development,"
U.S. Department of the Interior (1973).
15. "Parachute Creek Valley Diffusion Experiments," Battelle Pacific
Northwest Laboratories (September 1972).
16. "An Evaluation- of Existing Air Quality Data Obtained at the Para-
chute Creek Site of Semi-Works Plant," Dames & Moore (July 1973).
17. "Demonstration Plant: Clean Boiler Fuels from Coal, Preliminary
Design/Capital Cost Estimate," R&D Report No. 82—Interim Report
No. 1, prepared by the Ralph M. Parsons Company for the United
States Department of the Interior, Office of Coal Research (1973).
18. Final Environmental Statement^ for the Development of Coal Resources
in the Eastern Powder River Coal Basin of Wyoming, Vol. I, "Re-
gional Analysis," U.S. Department of the Interior (1974).
19. "Air Quality Data—1972 Annual Statistics," Environmental Protec-
tion Agency, Monitoring and Data Analysis Division, Research
Triangle Park, North Carolina (March 1974).
20. A. D. Busse and J. R. Zimmerman, "User's Guide for the Climatologi-
cal Dispersion Model," U.S. Environmental Protection Agency, Re-
search Triangle Park, North Carolina (1973).
585
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17—SECONDARY ENVIRONMENTAL IMPACTS
FROM URBANIZATION
By Barry L. Walton and Edward M. Dickson
A. Sources of Secondary Environmental Impacts
The environmental effects of the operation and construction of syn-
thetic liquid fuel plants can be considered to be "primary" or "direct"
impacts. The environmental consequences that arise from the attendant
urbanization and behavior of residents can be considered to be "secon-
dary" or "indirect" impacts. These secondary effects can contribute
significantly to the overall environmental change that is likely to oc-
cur in a predominantly rural region that undergoes substantial growth at
a fairly rapid pace. Sources of secondary impacts derive from municipal
services (fresh water, production of waste water and solid waste), land
use (construction of dwellings, roads, and utility corridors; effect on
water run-off patterns), habitation (automotive air pollution, energy
utilities, animal mortality), and recreation/leisure activities (use of
parklands, vandalism, alteration of habitats). This chapter is prima-
rily concerned with these secondary effects as they apply to the coal and
oil shale regions of the West. Some of these effects can be quantified
using scaling factors for readily predicted changes, and others can only
be projected in a general way, based on empirical evidence from past
occurrences.
B. Urban Growth: Coal and Oil Shale Regions of the West
Urban areas in Wyoming, Montana, North Dakota, and Colorado occupy
a very small fraction of the total land area. For example, Gillette,
586
-------
in Wyoming's Powder River Basin, occupies only abour 10,000 acres of
the over 3 million acres of Campbell County. Towns in these states are
widely dispersed (50 to 100 miles apart).
Urban growth on the open grasslands of Montana, Wyoming, and North
Dakota is characterized by sprawling communities with small populations.
Urban development in the oil shale country of Colorado, which is charac-
terized by a broken landscape of cliffs, river valleys, and plateaus,
would be restricted to the broad-bottomed river valleys, the only land
suitable for town-making.
Nearly all of the towns in the coal regions of Montana, Wyoming,
and North Dakota, 'and in the oil shale regions of Colorado have small
populations. Gillette, Wyoming (1975 population of 11,000), and Rangeley,
Colorado (1970 population of 2150),3 typify their regions. Population
growth from the construction and operation of a 100,000-B/D (16,000-m3/D)
coal liquefaction plant would add an estimated 2400 primary jobs to em-
ployment (see Chapter 6) in coal mining, while a 100,000-B/D oil shale
complex would add 1700 jobholders in oil shale country. The 2400 job-
holders, their families, and the associated service personnel and their
families would likely locate in the one or two towns close to the lique-
faction facility and the coal mines.
C. Quantifiable Impacts
1. Scaling Factors
Tables 17-1 and 17-2 provide some of the important scaling
factors for urban living applied to predicted urban growth in the coal
and oil shale regions of the West. The data in Table 17-3 are a compil-
ation of automotive emissions scaling factors for various levels of con-
trol anticipated for the future. However, recent postponements in the
587
-------
Table 17-1
SCALING FACTORS FOR URBAN LIVING
Item
Unit'
Quantity
Fresh water consumption
National average
Domestic 40%
Commercial 18%
Industrial 24%
Public uses 18%
Colorado
Wyoming
Montana
Waste water production
National average
Colorado
Wyoming
Montana
Solid waste production
National average
Residential and commercial electric
power consumption
Private automobiles
National average
Colorado
Wyoming
Montana
Distance traveled per passenger automobile
Land requirements for dwelling units
Streets and roads (municipal and rural)
National average
Colorado
Wyoming
Montana
Acreage or municipal and rural roads
Gal/capita day 150
170
200
190
Gal/capita day 120
140
160
150
Lbs/capita day
1000 kWh/capita
Cars/capita
Miles/car-year
Acres/person
1400
5.2
0.48
0.55
0.51
0.49
10,000
0.065
Mileage/capita 1.8 X 10 2
3.6 X 10"2
1.2 X 10-1
1.1 X 10-1
Acres/mile
12
*Conversion factors:
4.05 X 10sm2.
1 gal = 3.79 x 10~3m3; 1 mi = 1.61 km; 1 acre =
588
-------
Table 17-2
WATER RUNOFF COEFFICIENT "c" AND
RAINFALL IN WYOMING AND COLORADO
(Fraction of Rainfall Flowing into Rivers and Streams)
Undisturbed land
Eastern Wyoming
Piceance Basin*"
0.07-0.09
0.04-0.08
Disturbed land
Suburban
Light industrial"
Gravel roadways*
0.25-0.40
0.50-0.80
0.15-0.30
Rainfall
Gillette/eastern Wyoming
Average annual
Peak daily**
Piceance Basin Colorado
Average annual*
Peak daily
**
11-15 (27-38)
2.8 (7.1)
12-24 (30-61)
2.8 (7.1)
in./yr (cm/yr)
in./yr (cm/yr)
in./yr (cm/yr)
in./yr (cm/yr)
*Average annual runoff of 1 in./yr (Reference 3) with annual
rainfall of 11 to 15 in. (Reference 4).
tAverage annual runoff of 1 in./yr (Reference 3) with annual
rainfall of 12 to 24 in. (References 1, 5).
^Reference 6.
§Reference 7.
**Reference 8, assuming the same peak daily rainfall for Piceance
Basin.
589
-------
Table 17-3
AVERAGE EMISSION FACTORS FOR HIGHWAY VEHICLES BASED ON NATIONWIDE STATISTICS
Hydrocarbons
Carbon*
Monoxide Exhaust^"
Year
1970
1975
1980
1990
2000*
R/mi
78
50
23
12
3.4
g/km f?/mi g/km
48 7.8 4.8
31 5.0 3.1
14 2.4 1.5
7.5 1.3 0.81
2.1 0.41 0.25
Crankcase Nitrogen*
and Oxides
Evaporation (NOX as NOs)
g/roi
3.9
1.5
0.53
0.38
0.38
g/km g/mi
2.4 5.3
0.93 5.0
0.33 3.1
0.24 1.8
0.24 0.4
g/km
3.3
3.1
1.9
1.1
0.25
Particulates
Exhaust
g/mi
0.38
0.38
0,38
0.38
0.38
g/km
0.24
0.24
0.24
0.24
0.24
Tire Wear
g/mi
0.20
0.20
0.20
0.20
0.20
g/km
0.12
0.12
0.12
0.12
0.12
Sulfur
Oxides (80s)
g/mi
0.20
0.20
0.20
0.20
0.20
g/km
0.12
0.12
0,12
0.12
0.12
*1975 standards - 3.4 g/mi.
1976 standards - 3.4 g/mi.
t!975 standards - 0.41 g/mi.
1976 standards - 0.41 g/mi.
$1975 standards - 3.9 g/mi.
1976 standards - 0.4 g/mi.
§We assume 1976 standards are met for all vehicles in 2000.
Source: "Compilation of Air Pollutant Emission Factors," 2nd Edition, Supplement 2, U.S. Environmental Protection
Agency (April 1973).
-------
imposition of increasingly stringent emissions standards, suggest that
the relevant factors applied in any given time frame of this study are
uncertain.
The scaling factors given in Tables 17-1 through 17-3 have
been used to derive the results shown in Tables 17-4 through 17-7 for
the Powder River Basin in Wyoming and the Piceance Basin in Colorado for
the maximum credible implementation scenario. The significance of the
results given in the tables is amplified from the standpoint of environ-
mental concerns in the following sections of this chapter.
2. Water-Related Impacts
a. Runoff
The paving of streets and the roofing of structures alter
the runoff of precipitation because there is less open ground to absorb
it. This results in the alteration of stream flows manifested both by
an increase in quantity and by a compression in time of the flow*
The runoff Q can be expressed by the simple equation
Q = CIA
where C is a constant, I is the precipitation rate, and A is the area
affected.^
Table 17-2 gives the fractional runoff coefficient for
various activities that cover the land surface with water-diverting
*Less time elapses between the falling of the precipitation and the on-
set of runoff flow, and the runoff flow ceases quicker after the pre-
cipitation ends.
tQ is usually given in ft3/s, I in in./hr, and A in acres.
591
-------
Table 17-4
IMPACTS FOR CAMPBELL COUNTY, WYOMING, COAI. LIQUEFACTION AND METHANOL PRODUCTION--
MAXIMUM CREDIBLE IMPLEMENTATION SCENARIO
to
Quantities Derived from MCI
and Figure 22-2
Impact
Fresh water consumption
Waste water production
Solid waste production
Residential and commercial
electric power consumption
I,and araa directly affected
by urbanization (cumulative)
Municipal and rural road dis-
tance (cumulative)
Acres affected by municipal
Quant Ity
200
160
1400
5.2
0.065
1.2 X 10"1
12
Units
Gal/day person
Gal/day person
Lbs/person yr
1000 KWh/person-
yr
Acres/person
Miles/person
Acres/mile
1975
17
17
17
17
17
17
2000
1980
22
22
22
22
22
22
2600
1990
60
BO
60
60
60
60
7200
2000
110
110
110
110
110
110
13,000
Units!
1000 people
1000 people
1000 people
1000 people
1000 people
1000 people
miles
1975
3.4
2.7
24
88
1100
2000
2.4
1980
4.4
3.5
31
110
1400
2600
3.1
1990
12
9.6
84
310
3900
7200
8.6
2000
22
18
150
570
7200
13,000
16
Units"
10s gal/day
10s gal/day
10s Ibs/yr
106 Wh/yr
Acres
Miles
104 acres
and rural roads (cumulative)
Increased runoff from urban-
ization during peak annual
periods
Increased runoff from munlc-
ipal and rural roads during
peak annual periods
C = 0.16 to 0.33 Dimenslonless
A Area
C = 0.08 to 0.23*
1100 1400 3900 7200 acres
2,4 3.1 8.6 16 ID4 acres
120 to 160 to 440 to 810 to ft^/s water
250 320 900 1700
1300 to 1700 to 4800 to 9000 to ft3/s water
3900 5000 14,000 26,000
•Runoff, Q * CIA (C = a constant, I = precipitation rate, A = area affected).
tAssumes penk dally rainfall of 2.8 Inches occurs In a 4-hr period due to thunderstorm activity.
*1 ff'Vs = 0.646 X 10" gal/day. ,
'.Conversion factors: 1 gal = 3.79 X 10-°ma ; 1 acre = 4.05 x lO3*,8 ; 1 mi - 1.61 km; 1 in. = 2.54 cm; 1 ft3 = 2.83 X 10 in".
-------
Table 17-5
IMPACTS FOR nAI'FIKLI) AMD RIO BLANCO COUNTIES, COLORADO, OIL SHALE DEVELOPMENT —
MAXIMUM CREDIBLE IMPLEMENTATION SCENARIO
Quantities Derived from MCI
and Figure 22-13
Scenario for Year
Ol
CO
u
Impact
Fresh water consumption
Waste water production
Solid waste production
Residential and commercial
Land arua directly affected
by urbanization (cumulative)
Municipal and rural road
mileage (cumulative)
Acres affected by municipal
and rural roads (cumulative)
Increased runoff from urban-
ization during peak annual
periods
Increased runoff from munic-
ipal and rural roads during
peak annual periods
Quantity
170
140
1400
5.2
0065
3.6 X 10"2
12
C = 0.17-0.36
1 = 0.7*
A
C = 0.07 to 0.26*
Units
Gal/day person
Cal/day person
r>hs/person yr
1000 kWh/yr
person
Acres/person
Milos/person
Ac res /mi lu
Dimension less
Area
1975
23
23
23
23
23
23
830
1500
1
1980 1990 2000 Units* 1975
50 220 245 1000 people 3.9
50 220 245 1000 people 3.2
50 220 245 1000 people 32
50 220 245 1000 people 120
50 220 245 1000 people 1500
50 220 245 1000 people 830
1800 7900 8800 miles 1
1300 14,000 16,000 acres ISO to
380
2.2 9.5 11 10* acres 490 to
1800
1980
8.5
7.0
70
260
3300
1800
2.2
390 to
830
1100 to
4000
1990
37
31
310
1100
14,000
7900
9.5
1700 to
3500
4700 to
17,000
2000
42
34
340
1300
16,000
8800
11
1900 to
4000
5100 to
20,000
Units*
10s gal /day
10s gal/day
10s Ibs/yr
10s Wh/yr
Acres
Miles
104 acres
ff'Vs water
ft"/s water
*Runoff, Q = CIA (C = a constant, I = precipitation rate, A = area affected).
tAssumes peak daily rainfall of 2.8 in. occurs in a 4-hr period duo to thunderstorm activity.
^Conversion factors: 1 gal = 3.79 x 10~3m3; 1 acre = -1.05 x lO^m2 ; 1 mi = 1.61 km; 1 in. = 2.54 cm; 1 ft3 = 2.83 x
-------
Table 17-6
AUTOMOTIVE POLLUTION IMPACTS FOR CAMPBELL COUNTY, WYOMING, COAL LIQUEFACTION AND METHANOL PRODUCTION —
MAXIMUM CREDIBLE IMPLEMENTATION SCENARIO
Impact
Ul
-------
Table 17-7
AUTOMOTIVE POLLUTION IMPACTS FOR GARFIELD AND RIO BLANCO COUNTIES, COLORADO, OIL SHALE DEVELOPMENT-
MAXIMUM CREDIBLE IMPLEMENTATION SCENARIO
Quantities Derived from MCI
Scenario for Year
Impact
Private automobiles
Automobile travel
Impact
Quantity
0.55
10
Scaling Factor
Units
Cars/person
1000 miles/car-yr
and Figure 22-13
1975
23
13
1980
50
28
1990
220
121
2000
245
135
Units*
1000 people
103 cars
1975
0
13
130
1980
1
28
280
1990
15
121
1210
2000
20
135
1350
Units*
100,000 B/D
10s cars
10s miles/yr
Air pollution from automobiles
Cn
<£>
Particulates
S03
Hydrocarbons
NOX
CO
Mileage Use mileage data
for the appro-
priate year from
Table 17-3
0.58
0.2
6.5
5.0
50
0.58
^ 0.2
2.9
3.1
23
0.58
0.2
1.7
1,8
12
0.58
0.2
0.8
0.4
3.4
g/mi
g/mi
g/mi
g/mi
g/mi
0.
0.
0.
0.
6,
08
03
85
65
50
0.16
0.06
0.81
0.87
6.4
0.70
0.24
2.1
2.2
14
0.78
0.27
1.1
0.54
4.6
10s
10s
10e
106
10s
kg/yr
kg/yr
kg/yr
kg/yr
kg/yr
*Conversion factors: 1 mi = 1.61 km; 1 g/mi =0.62 g/km.
-------
materials and undisturbed areas. Urbanization of undisturbed lands
could be expected to increase runoff 3 to 5 times that of the undis-
turbed landscape. Much of this extra water goes into storm drains and
sewers. In rural areas, new roads will increase runoff into streams.
Table 17-2 also shows the range of annual rainfall for
the two regions. Much of the nonsnow precipitation occurs during thunder-
storms, with thunderstorms occurring about 30 days per year in eastern
Wyoming and about 40 days per year in western Colorado.3 We assume a
peak daily rainfall of 2.8 in./day (7.1 cm/D) for both regions. Thunder-
storms will induce the most damaging runoff.
b. Increased Salinity
It is predicted that the withdrawal of river water for
municipal use will increase the concentrations of dissolved salts in
the Upper Colorado Basin, which experiences problems with increasing
salinity.9 Each milligram per liter increase in dissolved solids per
unit volume (salinity) increases the economic detriment in the lower
Colorado Basin at the rate of $230,000 per mg/g, increase. For an oil
shale industry of 1.5 to 2.0 million B/D, the increase in dissolved
solids (mg/jfc) from the increase in residential water consumption is
estimated at 0.6 to 1.0 mg/jj, which gives a total annual detriment of
$1.2 to 2.3 million per year.
c. Waste Water
Analysis has shown that the cost of a shale- or coal-
derived synthetic crude oil is insensitive to the cost of water, con-
sequently, a plant could easily afford to treat urban waste water for
use. However, it can be readily calculated that the population induced
by an oil shale plant would generate waste water at a rate that would
satisfy only about 10 percent of the water requirements of a single
596
-------
plant. Thus, a population of almost 100,000 people would produce only
enough waste water per year to satisfy a single 100,000-B/D (16,000 m3/D)
oil shale plant. Clearly, reuse of residential waste water could at best
make only a small contribution to meeting the water needs of an oil shale
industry.
3. Air Quality Impact
Table 17-8 compares the automotive air pollution with that
from an oil shale plant. As can be readily seen, the automotive air
pollution is 1/40 to 1/900 that of the air pollution from the oil shale
industry. Thus, the impact on regional air quality derived from the
atmospheric dispersion modeling of Chapter 16 will be a good represen-
tation of the total effect on air qualify in the Piceance Basin.
D. Nonquantifiable Impacts
1. Impact of Increased Land Use
Three major urban land uses will develop around the towns in
the coal and oil shale regions: Land use of permanent housing and rec-
reation areas for the operating force of the plant and mines, and for
the service personnel and their families. Land use for temporary hous-
ing for the construction force for the plant (often temporary housing in
trailers evolves into permanent housing in the same trailers). Land use
for commercial development, roads, and utility corridors.
All of these land uses disturb range1and, open space, and
watershed adjacent to a town. Unpaved roads and graded lands, highly
subject to wind and water erosion, create dust and contribute to topsoil
degradation. The sparse groundcover and low rainfall contribute to soil
instability in areas of disturbed vegetation.
597
-------
Table 17-8
AIR POLLUTION FROM AUTOMOBILES AND OIL SHALE PLANTS
Impact Scaling Factor
Quantities Derived from MCI
Scenario for Year
Oi
<£>
00
Particulates
S02
Hydrocarbons
N0a
103 g/s-100,000 B/D
394 g/s-100,000 B/D
76 g/s-100,000 B/D
514 g/s-100,000 B/D
Air pollution from automobiles
Particulates
SOS
Hydrocarbons
NOX
CO
1975
0
0
0
0
1980 1990 2000 Units 1975
1 15 20 100,000 B/D 0
1 15 20 100,000 B/D 0
1 15 20 100,000 B/D 0
1 15 20 100,000 B/D 0
2.5
1.0
27
21
210
1980
103
394
76
514
5,1
1.9
26
28
200
1990
1545
5910
1140
7710
22
7.6
67
70
440
2000
2060
7880
1520
10,280
25
8.6
35
17
150
Units
g/a
g/s
g/s
g/s
g/s
g/s
g/s
g/s
g/s
*Chapter 16.
tFrom Table 17-7.
-------
2. Water Quality Degradation
The relatively arid areas of the Powder River and the Piceance
Basin afford considerable opportunity for water quality degradation.
Sparse groundcover in the Powder River Basin, when disturbed by construc-
tion activity, leads to erosion and stream siltation following rains. In
these areas, which are already short of water for urban use, an increase
in water consumption will lead to stream degradation through flow reduc-
tion. Urban construction on important underground water recharge can
lead to the lowering of water tables. Diversion of rainwater runoff
through construction activity or the rechannelling of streamflow can
lead to water quality degradation. Road construction on the steep un-
stable hillsides of the Piceance Basin often leads to landslides, which
fill or block streambeds.
Much of the water in the areas under consideration flows in
underground aquifers. In the Powder River Basin, these aquifers are un-
likely to be affected by construction activities or urban growth except
through increased usage for residential or industrial use. In Colorado,
many of the recharge areas for aquifers lie at the base of cliffs and in
the flat areas along rivers. Some disturbance of underground aquifers
in this area is possible.8
3. Impact on Recreation Areas
Scaling factors cannot be used to generalize environmental
impacts that stem from increased recreational or leisure time activities
in an area because the effects of these activities are related to the
nature of a given locale and the socioeconomic status of the inhabitants
of the settlements involved. Particular to this category of impact are
the activities of increased use of public parkland, hunting and fishing,
and off- and on-the-road travel.
599
-------
Growth of population brings heavier use of public parklands.
Unless the quantity of park-like land with public access increases along
with the population, the existing areas receive more intense use—some-
times exceeding their capacity to recover from wear and tear.
People frequently seek outdoor recreational activity on pri-
vate lands—sometimes by trespass. As the nation becomes increasingly
motorized, leisure activity has more and more involved off-the-road
driving with such vehicles as motorcycles, dune buggies, four-wheel-
drive jeeps and trucks. Much of this off-the-road operation is destruc-
tive to vegetation, disruptive to wildlife, and it creates dust and noise
problems. Often, access by these vehicles leads to vandalism of historic
sites, archeological resources, and unique features of the environment,
not to mention litter, which is a common product of off-the-road travel.
State and federal agencies own nearly 35 percent of the land
in the Northern Great Plains Resources Program study area, with these
lands forming a virtual patchwork quilt on the land. Many different
federal and state agencies control land. The recreational value of the
land is most likely to be seriously affected by growth. The biological
responsiveness of the land and the biological carrying capacity of the
land are most likely to be impacted last. Population growth already
impacts several areas; for example Flaming Gorge near Rock Springs,
Wyoming; Keyhole State Park in northeastern Wyoming near Gillette and
Sheridan, Wyoming; and Custer National Forest near Colstrip, Coal de-
velopment in Wyoming would likely make Keyhole State Park Wyoming's most
heavily used park.10 The Northern Great Plains area and the Rocky Moun-
tains to the west now contain uncrowded recreation areas. Population
growth will impact the quality of recreation by introducing crowding and
heavy use of the most accessible recreation areas. Rivers and reservoirs,
for example, are prime recreation use areas. With a growing demand for
600
-------
water by energy companies, surface area reductions in many reservoirs
are to be expected. More people will share less water for recreation.
The recreation habits of residents in the Northern Great Plains
area differ from those of out-of-state tourists. Tourists tend to fre-
quent the better known national parks and monuments. Those residents
who hunt and fish generally use state lands, national forests, and Bu-
reau of Sport Fisheries and Wildlife areas. An increase in the resident
population from coal mining and conversion will impact local recreation
opportunities most heavily, with city and county parks, state parks
close to mining towns, and federal lands close to mining activities the
most seriously affected. In Wyoming, the annual influx of visitors to
Yellowstone National Park, which totals over 2 million people, dwarfs
the 300,000 Wyoming residents. In another part of the state, however,
in Natrona, Converse, and Niobrara counties (along the Platte River) over
90 percent of the fishing in 1970 was by residents.10 The impacts from
new residents will overshadow the impacts from tourists in most recrea-
tion areas other than national parks and monuments.
4. Impact on Animal Populations
Increased population brings with it increased road mileage and
road travel in rural areas. This travel endangers the lives of large
and small animals that frequently cross the roads: antelope, squirrels,
skunks, deer, rabbits, turtles, snakes and raccoons. Nocturnal animals
are especially susceptible. Studies have confirmed that a large cause
of death among wild animals is their being struck by vehicles on highways,
Increased numbers of people increase the legal and illegal
hunting and fishing pressure on game animals and sport fish. In addi-
tion, there is an increase in destruction for destruction's sake—espe-
cially of predatory animals, birds of prey, and snakes.
601
-------
The layout of roads, habitation, and recreational areas can
affect animals and plants, in a region differentially. Some species
adapt well to human activity and even increase in numbers as domestic
vegetation substitutes for native forage, or as the number of predators
is lessened. Human habitation harms other animals or birds when home
range territories are diminished or transected, or when a unique feature
essential to part of their life cycle (e.g., trout spawning beds in
streams') is destroyed.
Other subtle factors can also be important to the viability
of wildlife habitat. For example, the sage grouse and sharptailed
grouse prefer certain sagebrush areas as strutting ground for their
mating ritual. In the Powder River Basin development will lead to more
power utility lines which in the past have given birds of prey an un-
natural but strategic vantage point from which to attack grouse; several
grouse colonies have been decimated in the past by this means.11
In the Piceance Basin, development will withdraw critical
winter range in the river valleys for deer, antelope, and elk in the
White River and Colorado River Basins. The availability of winter range
determines the size of the herd that can be supported by the available
habitat. Destruction of winter range has a far more severe effect on
herd size than similar destruction of the more abundant summer range.
E. Siimma ry
There are many indirect environmental consequences of the urbani-
zation that would be induced by coal and oil shale conversion facilities
developments. Among those that can be estimated quantitatively are ef-
fects on precipitation runoff, waste water production, and air quality
impacts from automobiles. We have shown that there is little chance of
using urban waste water to satisfy all the needs of an oil shale plant
because a single plant needs about 10 times as much water as the
602
-------
population induced by the plant will produce. We have also shown that
the automobile contribution to air pollution will be small compared to
the pollution caused by the plants themselves.
Important, but nonquantifiable, impacts include effects on land use
patterns, over use and abuse of recreational and rural landscapes, and
increased animal mortality from being struck by automobiles.
603
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REFERENCES
1. "Ecological Studies," Geoecology Associates, et al., Boulder,
Colorado, prepared for the Colony Development Operation, Atlantic
Richfield Company (May 1974).
2. "impact Analysis and Development Patterns, Related to an Oil Shale
Industry," THK Associates, Inc. et al., prepared for the Colorado
West Area Council of Governments and the Oil Shale Regional Plan-
ning Commission, Denver, Colorado (February 1974) p. 73.
3. W. T. Bryson and R. T. Laskey, "Restocking After Fishkills as a
Fisheries Management Strategy," paper presented at the 1973 Tri-
State Fisheries Conference, Burr Oak State Park, Gloucester, Ohio,
February 14-16, 1973.
4. National Academy of Engineering, Rehabilitation Potential of Western
Coal Lands, National Academy of Sciences.(Ballinger Publishing Com-
pany, Cambridge, Massachusetts, 1974) p. 124.
5. "Final Environmental Statement for the Prototype Oil Shale Leasing
Program," U.S. Department of the Interior, Vol. I (1973) p. 11-110.
6. D. K. Todd, The Water Encyclopedia (Water Information Center, Inc.,
Port Washington, New York, 1970) p. 77.
7. L. C. Urquhart, ed., Civil Engineering Handbook, 3rd edition, p. 82
(McGraw-Hill Book Company, Inc., New York, New York, 1950).
8. "Final Environmental Impact Statement: Proposed Development of Coal
Resources in the Eastern Powder River Coal Basin of Wyoming," U.S.
Departnent of Agriculture, U.S. Department of the Interior, Inter-
state Commerce Commission, Vol. I (October 18, 1974).
9. "Project Independence Blueprint Final Task Force Report. Potential
Future Role of Oil Shale: Prospects and Constraints," Federal
Energy Administration, Interagency Task Force on Oil Shale, under
the direction of the U.S. Department of the Interior (November
1974) pp. 186-189.
604
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10. J. R. Davidson and C. Phillips, "A State Parks System for Wyoming:
The Choices and Commitments," prepared for the Wyoming Recreation
Commission by the Water Resources Research Institute, University
of Wyoming, Laramie, Wyoming (May 1974) p. 11.
11. B. Marker, Wyoming Game and Fish Department (personal communication)
605
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18—HEALTH ISSUES IN SYNTHETIC LIQUID FUELS DEVELOPMENT
By Robert V. Steele
A. Introduction
There is little question that synthetic liquid fuels development
will produce adverse effects on human health due both to the further
emission of pollutants already regulated and the release of yet to be
identified toxic, carcinogenic, or other health-impairing agents. How-
ever, owing to the lack of concrete data on which to base an analysis,
the extent of such effects cannot be predicted quantitatively until some
development takes place and the appropriate clinical and epidemiological
studies are carried out. All that can be done at this stage is to dis-
cuss the health issues that are likely to arise as a synthetic fuels
industry develops and to point out the critical areas in which research,
planning, and testing will be necessary to forestall or minimize dele-
terious effects on human health.
B. Effects of Industrial Development in New Areas
To the extent that synthetic fuels development is carried out in
areas that currently enjoy low levels of environmental pollution, in-
creased levels of health effects are likely to occur in these areas.
The impacted population will consist not only of the current residents
of these areas, whose numbers are small in many cases, but also of plant
and mine workers and their families who will have migrated to the devel-
opment sites. Even with moderate levels of growth, the new population
associated with development could swamp the current population in many
areas after 10 or 15 years, as shown in Chapter 22.
606
-------
Since the number of cases of impaired health should be proportional
to both the ambient concentration of pollutants and the number of people
exposed, a "square law" might be proposed to express the health impacts
of additional development. The "square law" says that health effects
increase roughly as the square of the level of production, since both
ambient pollutant concentrations and population exposed are roughly
proportional to this quantity. Although it would be difficult to make
any quantitative formulation of this "square law," the notion indicates
that the level of effects may be higher than would be initially expected
due to the remote siting of much of the development.
The most obvious health effects would be those related to increased
levels of pollutants for which EPA has set standards, especially air
pollutants such as NO , SOS, particulates, oxidants, and so forth. The
EPA primary standards for these pollutants are designed to protect human
health. EPA secondary standards are designed to protect human welfare
by minimizing the effects on plant life, materials, etc. If these ambient
air quality standards are rigorously enforced, then few health effects
would arise from these sources of pollution. As discussed in Chapter 16,
there are many variables, however, that determine ambient concentrations
of pollutants, including the relative location of plant sites, weather
conditions, secondary pollutant releases due to increased population, and
so forth. Control measures may not necessarily be applied until some
level of pollution is reached at which health effects begin to appear.
Even then, it may take several years before appropriate control measures
can be implemented.
Another area where time lags may occur between the onset of health
effects and the implementation of control regulations is the emission of
compounds specific to the new synthetic fuel processes that have not
previously been regulated. Careful advance planning and testing will be
required to ensure that the releases of all substances that affect health
607
-------
are accounted for and quantified so that appropriate regulations can be
formulated, if necessary.
C. End Use Impacts
Due to the potential for the widespread use of synthetic liquid
fuels in automotive transportation, there is a great potential for im-
pacting the health of large numbers of people. The effects of interest
are those that arise from differences in the combustion of synthetic
fuels compared with those that arise from the combustion of conventional
fuels.
The most pronounced differences in automotive pollutant emissions
are in the combustion of methanol or methanol-gasoline blends compared
with the combustion of gasoline. Reductions in the emissions of auto-
motive pollutants (NO , CO, hydrocarbons, and aldehydes) have been re-
X
ported for straight methanol fuel1'2 and methanol/gasoline blends,3 with
the exception that aldehyde emissions are higher than for gasoline.
Formaldehyde is a partial oxidation product of methanol and it accounts
for most of the aldehyde emissions from methanol combustion. It can act
as a respiratory irritant and an allergenic agent. The use of advanced
catalytic converters can reduce CO, hydrocarbon, and aldehyde emissions
by an order of magnitude for both gasoline and gasoline/methanol com-
bustion.3 Although differences remain in emissions between the two cases,
the levels are so low that the differences are no longer as significant.
A problem in the use of methanol is that it displays acute toxic ef-
fects both through vapor inhalation (the maximum allowable exposure is
200 ppm compared with 400 ppm for octane) and through absorption by the
skin.* It is also acutely toxic when ingested orally.4 However, this is
not likely to be a problem in fuel use, especially if blends are employed.
Rather, the routine contact with both vapor (methanol has a vapor pressure
of 100 mm of Hg at 20°C compared to 10 mm of Hg for octane) and spilled
608
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liquid poses a significant health hazard to service station attendants
and others who frequently handle or are exposed to automotive fuels.
Differences in the emissions from the combustion of fuels refined
from shale or coal syncrude and those from combustion of conventional
fuel have not been identified. It is likely that the only significant
differences would be in the trace elements or unburned hydrocarbon
emissions. For example, it is known that upgraded shale oil and coal
syncrude contain higher fractions of aromatics than do natural crudes.5
This aromatic fraction is largely converted to gasoline, and the aromatic
content of exhaust gas is apparently proportional to the aromatic content
of the gasoline. Therefore, higher emissions of aromatics may occur from
the use of synthetic gasoline. It is not known whether or not any of
these aromatic compounds will be among those identified as carcinogens.
However, it has been reported that carcinogens in raw shale oil are de-
stroyed in the process of hydrotreating (upgrading) to produce synthetic
crude oil.
Both coal and oil shale contain toxic trace elements. (See Ta-
bles 4-13 and 4-14.) It is likely that many of these will be removed
during coal liquefaction and shale oil upgrading. However, analyses of
the syncrude products have not been carried out, and there is no indica-
tion as yet of the extent to which trace elements will find their way into
refined products.
D. Localized and Occupational Health Problems
An important concern in coal and oil shale conversion activities is
the possibility of adverse health effects on workers and on local communi-
ties. This concern is centered more around the possible release of car-
cinogens, toxic trace elements, or more exotic pollutants than it is
around pollutants whose release is currently regulated and that can be
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readily controlled. It is well known that substances derived from coal,
such as coal tar, contain carcinogenic compounds. Raw shale oil is also
known to contain carcinogens. The toxic trace elements in coal and oil
shale are discussed in Chapter 4.
The main questions concerning these and other toxic materials are
whether will they be released to the environment, and if so, what will
be the quantities involved. It has been reported that a coal liquefac-
tion pilot plant operated by Union Carbide had to be shut down in 1960
*7
because the plant workers developed cancerous lesions on their skins.
Some mechanisms of airborne release of cancer-inducing material can be
inferred from this report. However, since such reports have not been
received from other operations, more would have to be known about the
actual operating conditions of the plant to draw any conclusions gen-
erally applicable to coal liquefaction.
At one point it was feared that the disposal of large quantities of
spent shale would create a cancer hazard due to the presence of carcino-
genic compounds such as benzo[a]pyrene in the carbonaceous residue on the
spent shale. However, tests carried out for The Oil Shale Company (TOSCO)
indicate that the carcinogenic potential of spent shale is low, due to
the very small concentrations of benzo[a]pyrene and other polycyclic aro-
o
matic hydrocarbons. Raw shale oil has a mild carcinogenic potential,
comparable to some intermediate refinery products and fuel oils.8 Up-
graded shale oil has a carcinogenic potential about an order of magnitude
less than that of raw shale oil, consistent with the belief that poly-
cyclic aromatics are broken down by hydrogenation. Thus, oil shale and
its products do not appear to present a serious cancer hazard. However,
safe plant operating procedures should be enforced to prevent the workers
from contact with intermediate retorting products, which display a "mild"
carcinogenic potential.
610
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The release of other toxic substances should be carefully studied
to insure that these materials are not released to work areas or the gen-
eral environment. The pathways and ultimate fates of many substances,
including toxic trace elements, in the conversion process are not well
understood. Thus, basic chemical and analytical studies should be car-
ried out to determine the contents of all waste streams from synthetic
liquid fuel processes to determine if health hazards might be created by
these streams and if abatement procedures may be needed.
Another area of concern is the potential for contamination of local
water supplies through runoff from solid waste disposal piles—primarily
spent shale and coal ash. Although current plans for coal and oil shale
conversion incorporate measures to prevent such contamination, some moni-
toring of waste disposal practices will help to insure that contamination
does not occur accidentally—during flash floods, for example. In addi-
tion, there are subtle effects that might go easily unnoticed. Examples
are percolation of highly saline water through spent shale piles to under-
lying aquifers and the disposal of coal ash in mined out areas where
aquifers have already been disturbed, which would cause further contam-
ination.
E. Research Needs
A great deal remains to be learned about the health effects of syn-
thetic liquid fuel production and use. The need for research in this area
is large, but just as important is the timing with which the research is
carried out. To have the greatest effect in moderating human health im-
pacts, the research should be carried out simultaneously with the devel-
opment of the synthetic fuel technologies.
The following important data are needed:
611
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• Identification of all toxic substances, including carcinogenic,
teratogenic, and mutagenic agents, in waste streams.
• The transport of these substances through the environment.
• The fate of these substances in the environment, including
mechanisms of degradation and transformation.
• The potential for human health impairment at the concentration
levels expected from releases from full-scale plants.
The strong need for the type of data indicated above has prompted a num-
ber of government agencies to institute research programs to acquire data
on health effects of energy technologies. In particular, EPA has begun
a study, to be performed by SRI, concerned with radioactive contaminants
associated with new energy technologies including coal liquefaction and
oil shale conversion. In addition, the EPA Office of Energy, Minerals,
and Industry has established several programs in this area. Other organi-
zations, such as the National Institute of Environmental Health Sciences
and the National Institute for Occupational Safety and Health, have held
workshops in health aspects of energy conversion. Furthermore, the Bio-
medical and Environmental Division of the Energy Research and Development
Administration (ERDA) will be responsible for carrying out health effects
research on ERDA-supported technology programs.
There is, therefore, a reasonable expectation that important health
effects data will be obtained on synthetic fuel technologies as they are
developed and reach the stages of final commercialization. If thorough
research and appropriate measures for control and regulation are carried
out, it is possible that health effects of synthetic fuels development
may be minimal. To insure this, careful coordination of the research
efforts of government agencies and private industry is required, along
with thoughtful and timely application of research results.
612
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REFERENCES
1. Reed, T. B. and R. M. Lerner, "Methanol: A Versatile Fuel for
Immediate Use," Science (December 28, 1973), p. 1299.
2. Bernhardt, W. E. and W. Lee, "Engine Performance and Exhaust Emis-
sion Characteristics from a Methanol-Fueled Automobile," presented
at "Future Automotive Fuels—Prospects Performance Perspective,"
a Symposium sponsored by General Motors Research Laboratories,
October 6-7, 1975.
3. Wigg, E. E., "Methanol as a Gasoline Extender: A Critique," Science
(November 28, 1974), p. 785.
4. Cooper, V. R. and M. M. Kini, "Biochemical Aspects of Methanol Pois-
oning," Biochemical Pharmacology, Vol. 11 (1962), p. 405.
5. Goen, R. L., et al., "Synthetic Petroleum for Department of Defense
Use," Stanford Research Institute, ARPA Contract No. F30602-74-C-
0265 (November 1974).
6. Halley, P. D., "Hazardous Chemicals in Raw and Upgraded Shale Oil,"
Workshop on the Health Effects of Coal and Oil Shale Mining, Con-
version and Utilization," University of Cincinnati, January 27-29,
1975.
7. Weaver, N. K., "Environmental Health Aspects of Alternative Fossil
Fuel Technologies," address delivered to National Institute of
Environmental Health Sciences Energy Workshop, Research Triangle
Park, N.C., May 27, 1975.
8. Atwood, M. T. and R. M. Coombs, "The Question of Carcinogenicity
in Intermediates and Products in Oil Shale Operations," The Oil Shale
Corporation, Rocky Flats Research Center (May 1974).
613
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19—WATER AVAILABILITY IN THE
WESTERN UNITED STATES
By R. Allen Zink
A. Introduction
The production of synthetic liquid fuels from coal and oil shale
*
involves water intensive processes. For projected synthetic fuel
plants in the eastern states, it appears that—on a major watershed
basis—the water impact will be small even in the dry months of dry
years (see Chapter 20). However, for the oil shale region in Colorado
and the coal region of the Northern Great Plains, the situation is more
complex. The water problem in the semiarid, energy-rich West is not
simply one of getting enough water to satisfy demands, it is also the
problem of establishing a decision making mechanism to select the
priorities that will dictate future allocations of a limited amount of
water. The western region has reached the point at which the order of
those priorities will soon have to be set.
The demands on the West's limited budget of water come from many
directions:
• Irrigation of crops
• Livestock watering
• Domestic use (status quo)
• Urban development (growth)
*
Advances in the technologies such as processing oil shale while still
underground hold promise of reducing the water required by one-half
or more; also, dry cooling towers in coal conversion processes, al-
though considerably more expensive than the contemplated wet cooling,
could reduce water use.
614
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• Industrial production
• Aesthetic values
• Recreational use
• Energy development
West of the 100th meridian, there is an imminent water budget
dilemma that will pit the many needs in direct competition. The
primary contributing factors to this competition are:
• Generally arid conditions (precipitation of approximately
14 inches per year)
• Population growth
• Increasing use of irrigation in agriculture
• Federal subsidies of water that result in cheap
irrigation water for agricultural projects
• Stated national goal of reducing dependence on
foreign sources of energy, with consequent interest
in new domestic sources.
• Extensive coal and oil shale resources in this arid
region.
• Rising interest in protection of the fragile
environment.
In view of this competition, some hard decisions will have to be
made affecting different people with different needs. How does the
energy-poor New Englander feel about the Montana rancher whose land is
being stripped of its character? How does that rancher feel about
gasoline shortages in Los Angeles? These decisions will have both
regional and national implications, and presently existing laws and
institutions may not be up to the task of making the necessary choices,
This chapter sets out the nature and sources of the complex problems
implicit in western water for energy development.
615
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B. Water Rights and the Federal Government
A major factor in the issue of water for energy in the West is the
role of the federal government—both as a claimant to certain amounts of
water, and as an institutional disburser of water. From the perspective
of the western states, a more accurate statement would be the federal
government as claimant to uncertain amounts of water. The situation is
so unsettled that neither private investors nor state governments can act
with confidence in planning projects where water will be needed.
This section explores the source and dimensions of the federal claims,
.the conflicts created by them, and the implications of the situation for
energy development.
1. Scope of Federal Water Rights
When the United States government obtained the territories that
are now the western states, it assumed sovereign dominion and power over
all the land, mineral resources, and water. The government encouraged
development of the new territory through homesteading and stock grazing
land grants, and new states were carved out of the territories. Of the
original federal domain, much of the land continues to be property of the
United States. Table 19-1 shows the percentages of federally owned land
in the mineral rich states of Colorado, Wyoming, and Montana:1 Of
greater significance is the contribution that federally owned lands make
to natural water runoff in the major river basins of the West--66 percent
of the Missouri River Basin and 96 percent of the Upper Colorado River
Basin. From a strictly proprietary standpoint, the federal government
has a powerful equitable argument for ownership and control over waters
arising on "its" property. The U.S. Constitution, in fact, gives Con-
gress the power
616
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to dispose of and make all needful Rules and Regulations
respecting the territory or the Property belonging to the
United States; and nothing in this Constitution shall be
so construed as to prejudice any claims of the United
States 2
Table 19-1
PERCENTAGE OF FEDERALLY-OWNED LAND IN
COLORADO, MONTANA, AND WYOMING
Federally-Owned
State Land (%)
Colorado 36.3
Montana 29.6
Wyoming 48.2
Other sources of federal power over water are also found in
the Constitution. Indeed, the war power has been relied upon to justify
the Tennessee Valley Authority project.3'4 Under the supremacy clause,
treaties are superordinate to state law; thus, federal power exists to
construct improvements on international watercourses pursuant to a treaty
obligation, irrespective of state law.5 The general welfare clause of
the Constitution has been cited as authority for federal action vis-a'-vis
a privately.held water right.4'6 Federal power over waters capable of
use as interstate "highways" (waterways) arises from the commerce clause
of the Constitution.5 An early Supreme Court case held that this power
to regulate commerce necessarily includes control over navigation.7 Thus,
Congress may control the navigable waters of the United States and keep
them open and free.
Of the above impressive federal powers over water, all but two
would—if exercised to the detriment of a privately held right—result in
617
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compensation being paid by the federal government for that private loss.
Exercise of federal power over navigable waters would not result in com-
pensation being paid to one whose loss occurs with the exercise of the
power:
Ownership of a private stream wholly upon the lands of an
individual is conceivable; but that running water in a
great navigable stream is capable of private ownership is
inconceivable.8
That is, no power resides in an individual to acquire a property right
in a navigable stream; therefore there can be no taking away of said
right and no compensation would be paid. Similarly, exercise of federal
power over a federally-owned proprietary water right could not result in
an individual loss for which compensation would be forthcoming.
These last two federal powers are most feared by the states
because of the extent of the powers and because when they are exercised
no compensation is paid to those whose water rights are displaced. Each
of these powers will be discussed in turn.
2. Federal Power Over Navigable Streams
Federal power over large navigable streams such as the Missis-
sippi or Delaware Rivers seems reasonable since such waterways have served
as highways for interstate commerce throughout our country's history.
However, application of the doctrine has been so extensive that true
navigability is no longer the test. Thus, a stream is navigable if it
can be made so by reasonable improvements.9 A stream is navigable if it
affects the navigable capacity of the mainstream.10 The definition of a
"navigable stream" reaches so far that one must explore in order to find
a nonnavigable stream. The impact on state action is clear, for the
state's power to authorize appropriation of water "...is limited by the
superior power of the [federal government] to secure the uninterrupted
618
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navigability of all navigable streams within the limits of the United
States."10 The extended definition of navigable streams has potentially
provided Congress with the necessary tool to establish sweeping national
water legislation with, e.g., a "Federal Water Board" reviewing every
application for water, superseding all prior state allocations—and no
compensation would have to be paid.11
3. Federal Properietary Water Rights
For the few nonnavigable streams that escape the definition
extension discussed above, or for all western streams arising on federal
lands—in the event Congress does not establish plenary power over the
nation's waters—the.power of the Congress under the property clause to
deal with its "water" property is impressive.
As previously described, federal land holdings in the West are
substantial. The underlying force of the proprietary federal claim to
western water is based on the argument that unless and until the United
States gives up control or ownership^of such lands and waters, they re-
main under the control of the federal government.
It is argued that, relative to these lands, federal legisla-
tion of 1866,12 1870,l3 and 1877 (the Desert Land Act)14 served to sever
federal water from the federal land, making the water available for dis-
position through the laws of the respective states. Support for the
argument came from the U.S. Supreme Court in California-Oregon Power
Company v. Beaver Portland Cement Co.:15
The fair construction of the provision now under review
is that Congress intended to establish the rule that for
the future the land shall be patented separately...with
the result that the grantee will take the legal title to
the land conveyed, and such title, and only such title,
to the flowing waters thereon as shall be fixed or ac-
knowledged by the customs, laws and judicial decisions
619
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of the state of their location.... What we now hold is
that following the Act of 1877, if not before, all non-
navigable waters then a part of the public domain be-
came publici juris, subject to the plenary control of the
designated states....
The language seems clear. However, subsequent cases have had the result
of severely weakening the message. The first warning to the states came
in Federal Power Commission v. Oregon,16 known as the Pelton case. In
Pelton the Supreme Court acknowledged that the Desert Land Act severed
the water from the land, but the Court made a critical distinction between
"public lands" and "reserved lands," holding that the Act applied only to
public lands. Public lands, the Court said, are those lands owned by the
federal government that are subject to disposal under federal public land
laws, e.g., land available for homesteading or mining. Reserved lands
are not so subject, but are those lands being held by the federal govern-
ment for a particular purpose—e.g., national recreation areas, national
forests, national wildlife preservation areas, and petroleum reserves for
national defense.
Federal power to reserve water for these public land reserva-
tions was first recognized in Winters v. United States.17 The Supreme
Court held that, in the case of the Indian reservation before it, even
though the subject of water rights was not mentioned in the documents
used to create the land reservation, there existed an implied intent
on the part of the federal government to reserve sufficient water aris-
ing on traversing or bordering the Indian land to make the land usable.
The Court said:
The power of the government to reserve the waters and
exempt them from appropriation under the state laws is
not denied and could not be....,10 That the government
did reserve them we have decided....
620
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In a federal district court case involving a federal land
reservation in Nevada for the United States Navy,20 Nevada attempted to
force the United States to seek a state water permit before taking water
from the land. Again, the court held that there was no requirement for
compliance with state law—the act of reserving the land for military
purposes removed the land and water from the Desert Land Act and indi-
cated an intent to reserve sufficient water for the purposes of the land
reservation.
The Supreme Court addressed the issue again in Arizona v. Cali-
fornia ,5 in which several kinds of federal reservations were before the
Court. After affirming the validity of the Winter's doctrine in the
Indian water question before it, the Court upheld the Special Master's
finding that
The principle underlying the reservation of water rights
for Indian Reservations [is] equally applicable to other
federal establishments such as National Recreation Areas
and National Forests. We agree...that the United States
intended to reserve water sufficient for the future water
requirements of the Lake Mead National Recreation Area,
the Havasu National Wildlife Refuge, the Imperial Na-
tional Wildlife Refuge and the Gila National Forest.23
The Court proceeded to describe a quantified standard for
Indian reservation water related to the number of irrigable acres, but
left unmeasured the water allocation for the other federal reservations,
saying only that they shall have an amount of water "reasonably needed
to fulfill the purpose" of the reservation.
The Court also reiterated the Winter's holding that the effec-
tive date for determining the priority of these water rights is the date
the land was withdrawn from public land status, i.e., the date the res-
ervation was created. As a result, water appropriations made prior to
such date are vested in the appropriator, but appropriations made
621
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subsequent to that date are not vested and could be subject to taking
without compensation through exercise by the federal government of its
water rights.
4. Summary of Federal Water Power
The federal government has the constitutional power to develop,
regulate, and allocate—including making allocations to itself—all west-
ern water resources, and it can do so irrespective of state laws. When
acting under the commerce clause's navigation power, the government need
pay no compensation for disrupted private investments.
Furthermore, the federal government can withdraw large tracts
of its western land from public sale or lease. These reservations have .
a water right in an amount necessary to accomplish the purposes of the
reservation, and the priority of the water right is the date of the land
withdrawal. Any private water rights acquired subsequent to that date
are junior to the federal right and can be usurped without payment of
n
compensation.
5. Federal Reserved Lands in the Oil Shale Region
The operation and impact of federal power is seen in the oil
shale region of the Upper Colorado Basin. Seventy-two percent of the
land in the region is owned by the federal government, and that federal
land contains 79 percent of the region's oil shale.23 Of the total fed-
eral land in the region, reservations have been carved out (1) for future
Navy fuel needs24 and (2) for purposes of "investigation, examination
and classification."25 The Naval Oil Shale Reserves were clearly made
for the contemplated development of the hydrocarbon resource. If the
Arizona v. California31 "purpose of the reservation" test is applied to
determine the amount of water implicitly reserved by the action of the
622
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Executive Orders, the result is an amount of water needed to support the
mining and retorting operation. This figure has been estimated at not
less than 200,000 acre-ft per year.86 The priority of the federal water
right in this amount dates from the issuance of the Executive Orders es-
tablishing the reservations. Again, private rights acquired after those
dates are junior to the federal right.
The reservation made in this region by the 1930 Executive Order
"...for the purposes of investigation, examination, and classification"
is less easily handled under the Arizona v. California test. It is ar-
gued that "investigation, examination, and classification" are bare ad-
ministrative geological functions requiring very little water, and that
there was no purpose -stated encompassing government development of oil
shale in commercial quantities.37 If this argument is accepted, then a
new statement by the federal government would be necessary to the effect
that commercial development of the oil shale resource on the reservation
tract is the federal purpose. The federal government could then have the
necessary water, but the priority date of the water right would be the
date of the new statement rather than the 1930 date of the original
Executive Order. Private water rights derogated by the "newly contem-
plated" oil shale development would be senior to the federal rights and
therefore would have to be compensated in the taking by the federal
government,
6. Implications of the Federal Power
The amount of water for all the various "purposes" of federal
reserved land in the West is a matter of speculation. For example, it
may be argued that a purpose of the extensive national forests reserva-
tions is the production and control of water, thereby creating a federal
water right in the total amount of the water arising on that forest land.
623
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One study28 has pointed out that
The federal theories underlying reservations and navigation
servitude assume that the United States can leave its owner-
ship or authority in suspended animation and can call it in
piecemeal or in toto whenever it feels that the time has
come for a project....
The uncertainty of that "suspended animation" has angered and frustrated
state authorities in their efforts to deal with both state interests in
water and the interests of their private citizens.
7. Attempts at Resolution
Colorado has recently tried to remove federal water rights and
interests from suspended animation in particular cases. A little used
federal law states the following:39
Consent is given to join the United States as a defendent
in any suit (1) for the adjudication of rights to the use
of water of a river system or other source, or (2) for the
administration of such rights, where it appears that the
United States is the owner of or is in the process of ac-
quiring water rights by appropriation under state law, by
purchase, by exchange, or otherwise, and the United States
is a necessary party to such suit. The United States,
when a party to any such suit, shall (1) be deemed to have
waived any right to plead that the state laws are inappli-
cable or that the United States is not amenable thereto by
reason of its sovereignty, and (2) shall be subject to the
judgments, orders and decrees of the court having juris-
diction. . . .
Colorado did include the United States as a party in a state
court water rights adjudication and the United States refused to par-
ticipate. The matter ultimately was carried to the U.S. Supreme Court
where Colorado prevailed.30 31 The victory is a limited one, however,
for the decision does not give the states power to quantify federal
624
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water rights generally.* The result is a mechanism for a slow, pain-
staking, expensive, ad hoc measuring of federal water claims, with the
federal government unrelenting in its point of view. Now that the case
is back at the state court level (to where the U.S. Supreme Court sent
it saying, "Proceed") the federal government is listing its claims in
vague and expansive terms. Typical is the federal claim for its water
rights in the Arapaho National Forest in Colorado:
The United States of America hereby claims certain quanti-
ties of the surface, ground and underground waters, both
tributary and nontributary, which were unappropriated as
of the reservation dates.... The United States claims
direct water rights, storage water rights, transportation
rights and well rights for purposes which include, but are
not limited to, the following: growth, management and
production of a continuous supply of timber; recreation;
domestic uses; municipal and administrative-site uses;
agriculture and irrigation; stock grazing and watering;
the development, conservation and management of resident
and migratory wildlife resources including birds, fishes,
mammals, and all other classes of wild animals and all
types of aquatic and land vegetation upon which wildlife
is dependent; fire fighting and prevention; forest im-
provement and protection; commercial, drinking and sani-
tary uses; road watering; watershed protection and man-
agement and the securing of favorable conditions of water
flows; wilderness preservation; flood, soil and erosion
control; preservation of scenic, aesthetic and other pub-
lic values; and fish culture; conservation, habitat pro-
tection, and management. With respect to the category of
fish culture, conservation, habitat protection, and man-
agement, the United States claims the right to the main-
tenance of such continuous, uninterrupted flows of water
and such minimum stream and lake levels as are sufficient
in quantity and quality to:
*Left unanswered is the effect of the statute on permit-type states, such
as Wyoming and Montana, where water rights are determined administra-
tively, not judicially.
625
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(1) Insure the continued nutrition, growth, con-
servation, and reproduction of those species
of fish which inhabited such waters on the
applicable reservation dates, or those spe-
cies of fish which are thereafter introduced.
(2) Attain and preserve the recreational, scenic,
and aesthetic conditions existing on the ap-
plicable reservation dates, or to preserve
those conditions which are thereafter caused
to exist.32*
It is important, after catching a breath, to emphasize the gov-
ernment's early-stated caveat that the federal claim is "...not limited
to...." the purposes stated in this exhaustive list. Stunned by the
vigor of the federal government's activities in the aftermath of the
Eagle County decision, the Colorado Water Conservation Board passed the
following resolution;T
Whereas the federal government has now filed numerous
claims for water rights in the State of Colorado...to
establish federal claims to much of the water origi-
nating in Colorado...; and
Whereas the federal government is claiming an unspeci-
fied and unknown amount of water...; and
Whereas the granting of the claims sought by the United
States could seriously jeopardize the existing system
of water rights within the State of Colorado, could
create a dual system of administration and decrees,
could require water users needlessly to re-adjudicate
rights already acquired and decreed under state law,
could adversely affect Colorado's rights under the
Colorado River Compact and the Upper Colorado River
Basin Compact, and will cast an almost impossible burden
*Taken directly from the U.S. filing papers in the Colorado Court. The
lengthy quote is felt necessary to make the point.
tColorado Water Conservation Board; Resolution passed at the meeting of
January 18, 1973. (Emphasis added.)
626
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upon the citizens of this state in attempting to protect
their individual water rights;
Now therefore, be it resolved...that the Board does hereby
recommend to the Governor...[etc.]...that all steps neces-
sary and proper, including appropriate funding, be taken
and authorized to adjudicate them and thereafter adminis-
ter them in accordance with state law....
The Board is calling for the fiscal resources to oppose the
federal water lawyers. The gauntlet was thrown when the open-ended fed-
eral claims were filed.
There have been numerous attempts in the U.S. Congress to leg-
islate a solution to the problem of seemingly open-ended federal water
claims, but none of the measures was passed.33 For the most part, they
were introduced by western congressmen seeking to subject virtually all
federal water claims to state law.
Nevertheless, most people agree that something must be done to
remove the federal water cloud. Two national studies have called for
congressional action to require federal cooperation in pursuit of a solu-
tion. The Public Land Law Review Commission recommended a complete quan-
tification of all federal water claims, including public notice of all
prospective water uses under federal reserved rights; this group also
recommended that provision be made for payment of compensation where the
exercise of a federal right would interfere with water rights vested
under state law prior to the 1963 decision in Arizona v. California.*
In its 1973 report,34 the National Water Commission called for a quanti-
fication only of existing federal water uses, with future reserved rights
*Reference 1, pp. 147-149.
tSee Sect. 10 for discussion of National Water Commission treatment of
the intricate Indian water rights issue.
627
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to be exercised through compliance by the federal government with the
law of the state in which the federal project is located; the priority
of the federal water right so acquired would be the date of the applica-
tion for state permit or otherwise as determined by state law.
Legislation has been drafted by the Land and Natural Resources
Division of the U.S. Department of Justice at the request of the Secre-
tary of the Interior, acting in his capacity as Chairman of the U.S.
Water Resources Council. The proposed act seeks "...to provide for the
inventorying and quantification of the reserved, appropriative, and other
rights to the use of water by the United States...,"35 including an in-
ventory of Indian water rights. The act provides for judicial review in
federal court of the administrative determinations made in pursuit of
the comprehensive inventory. No provision is made for the payment of com-
pensation and there is no intent to subject federal rights to state law:
...more than ever before, in this day of awareness of eco-
logical necessities and environmental and other values
which may be antithetical to the economic objectives of
many local water developments, it would seem clear that
the public interest does not necessarily require that all
future development under the United States reserved rights
yield to immediate development under state law.35
A noted commentator, Dean Frank J. Trelease, has pointed out
that such a proposed inventory could cause great problems in that the
federal agencies concerned
...may prepare inventories which are grandiose claims of a
pie-in-the-sky order, which may confirm the worst fears of
state planners [and energy developers] who will see little
left for them, and which may unnecessarily becloud titles
to unused waters, perhaps deterring development even more
than the present uncertainties.36
The response of the Department of Justice to this criticism is
that the provision for adjudication of claims made by the administrative
628
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agencies will keep the inventory accurate. The rebuttal is, of course,
that everything is still in favor of the federal government.
Despite such criticism, some action to reduce the uncertainty
of the dimension of federal (and Indian) water rights would be welcomed
by all concerned. The status quo is simply unacceptable. As a first
step, then, this proposed legislation could serve to get the quantifica-
tion process underway, and other lingering points of controversy—such as
the issue of compensation—could be addressed at a later time in the proc-
ess. Investors in energy development would have some sense of stability
in their decision making for the first time since the Arizona v. California
decision of 1963.
8. The Mexican Treaty of 1944
Unquantified federal (and Indian) water rights act as a desta-
bilizing influence on the western water-for-energy picture. The major
destabilizing factor is the uncertainty of the amounts which might sud-
denly—or someday—be demanded. There is one instance in which the
amount is quantified—the obligation to provide water 1.5 million acre-ft
per year* to Mexico under the treaty of 1944.37 As an international
treaty obligation, the pledge occupies a special place in both interna-
tional and U.S. domestic law.
Treaties are made by the President, with the "advice and con-
sent" of the Senate,36 and, together with the Constitution and the laws
*In addition, "...in any year in which there shall exist in the river
water in excess of that necessary to satisfy the requirements of the
United States and the guaranteed quantity of 1,500,000 acre-feet...the
United States...[will attempt] to supply additional quantities of water.
up to a maximum of 1,700,000 acre-feet...." (Reference 37, Article 15).
629
-------
of the United States, they stand as "the Supreme Law of the Land."39
Treaties, therefore, are superordinate to actions taken by the states
individually or collectively:
It is the necessary result of the explicit declarations of
the Federal Constitution...that where there is a conflict
between a treaty and the provisions of a state constitution
or of a state statute...the treaty will control. Its pro-
visions supersede and render nugatory all conflicting pro-
visions in the laws or constitutions of any state.48
This means that before a state can allocate "its" waters, or before a
compact between two or more states can allocate the water of shared
watercourses, provision must be made for deducting water amounts prom-
ised by treaty by the federal government. This is acknowledged in the
Upper Colorado River Basin Compact:
Nothing in this Compact shall be construed as...affecting
the obligations of the United States of America under the
Treaty with the United Mexican States....41
Thus, the 1.5 million acre-ft promised to Mexico is to be deducted from
the Colorado River flow for any given year before allocating the remainder
via the pertinent compacts.
It has not been decided how the obligation is to be borne be-
tween the Upper Basin states and the Lower Basin states—in particular,
whether or not the Lower Basin tributaries should be taken into account
in computing the amount of surplus which, under the Colorado River Com-
pact, is to be used for meeting the treaty commitment. If the Lower
Basin tributaries share the burden, it would lessen the Upper Basin's
share of the treaty obligation, thereby making available more Upper
Basin water for oil shale development (or other) purposes.
In the drawn-out treaty negotiations, the original offer of
the United States in 1929 was for one-half of the 1.5 million acre-ft,
which was the amount used for irrigation and domestic purposes by Mexico
630
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from the Colorado River in 1928.42 However, the treaty covers three
rivers: the Colorado River, the Rio Grande, and the Tijuana River. It
is said that powerful political forces in Texas, desirous of getting a
maximum amount of Rio Grande water for Texas agriculture, effectively
bartered away "extra" Colorado River water to get additional Rio Grande
water under the treaty.* The result is that the United States, contrib-
uting approximately 30 percent of the flow of the Rio Grande, under the
treaty takes about 50 percent, while Mexico, contributing virtually
nothing to the flow of the Colorado, takes roughly 10 percent of the
average annual flow of the Colorado River. From a quantity standpoint,
considering these two major rivers, the figures are shown in Table 19-2.
Table 19-2
FLOWS AND ALLOCATIONS IN THE COLORADO RIVER
AND THE RIO GRANDE
(million acre-ft)
River
Colorado
Rio Grande
Approx.
Yearly
Flow
15
2
U.S.
Contri-
bution
15
0.67
Mexican
Contri-
bution
0
1.33
U.S.
Allo-
cation
13.5
1.0
Mexican
Allo-
cation
1.5
1.0
Thus, the United States contributes a total of 15.67 million acre-ft per
year and receives 14.5 million acre-ft in allocations, while Mexico
*As a matter of interest, from Ft. Quitman, Texas, to the Gulf of Mexico,
70 percent of the Rio Grande's water originates in Mexico (Reference 42,
p. 375).
631
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contributes 1.33 million acre-ft per year and receives 2.5 million
acre-ft per year.
Although the Colorado River will soon be overallocated from
the U.S. standpoint alone, it is practically impossible that any dip-
lomatic adjustments will be made to the amounts of those obligations.
In the first place, the parties have come to rely on the provisions of
the treaty; for example, Mexico uses its Colorado River water to irri-
gate 450,000 acres in the Mexicali Valley, a field cultivation valued at
$200 million.42 Second, now that Mexico has discovered significant quan-
tities of oil, there will be a desire in Washington to preserve access
to this oil as a hedge against future Arab (and other) embargoes.
Recent action in Washington reinforces this good faith commit-
ment. In the Colorado River Basin Project Act,43 Congress addressed the
issue of projected water shortages, specifically mentioning the augmen-
tation possibilities of desalination, weather modification (mountain
snowpack augmentation) and interbasin transfers. With respect to such
augmentation, Congress declared that
The satisfaction of the requirement of the Mexican Water
Treaty from the Colorado River constitutes a national
obligation which shall be the first obligation of any
water augmentation project...authorized by Congress.*
Still further evidence of the national commitment followed
Mexican complaints about the poor quality of the water it was receiving.
After discussions were held at the head-of-state level and lower dip-
lomatic levels, Congress passed a law44 aimed at decreasing the salinity
*The figure used in the Act is 2.5 million acre-ft which represents the
1.5 million acre-ft Treaty obligation plus 1.0 million acre-ft for cal-
culated Basin losses in supplying the Treaty amount at the border (Ref-
erence 42, Section 202).
632
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of the Colorado River so that the quality of the water received by Mexico
will be equal to (or better than) that found in the lower main stem of
the river.
Both of these treaty-related actions have implications for the
water-for-energy picture. With respect to augmentation, whatever water
quantities are provided will be a dividend; the extra water will be a
"bonanza" addition to the river's total flow while the amount dedicated
to meeting the Mexican Treaty obligation will remain constant. The net
increase represents additional water for energy development (or other)
purposes. With respect to the water quality issue, until the desalina-
tion plant provided for in the legislation is built and comes on-line,
low-salinity water is to be released upstream at federal water storage
locations to dilute the high-salinity water heading for the border.
Water for dilution will come "off the top" of the available water supply
of the Colorado system as a federal obligation—reducing the net amount
available for allocation under the compact and state law formulas.
9. The Federal Government as a Disburser of Water
The Reclamation Act of 190245 provided authority and funding
for the construction of storage and diversion facilities to provide water
for irrigating semiarid lands, thereby "reclaiming" the lands from their
near-desert condition. Later amendments broadened the uses to which the
water could be put, such as municipal and industrial uses, and provided
for production and sale of electrical energy in conjunction with recla-
4- R
mation projects.
*This diplomatic and political action made moot the legal question of
whether or not the 1944 treaty addressed the issue of water quality.
633
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In 1967, the Bureau of Reclamation of the Department of the
Interior initiated a program under which it planned to sell water from
the Boysen* and Yellowtail^ Reservoirs to industrial users for industrial
purposes. Table 19-3 shows the status of these industrial water sales.
On October 16, 1973, the Environmental Defense Fund and others
filed suit in U.S. District Court in Billings, Montana, to declare the
water contracts null and void and to put a halt to the industrial water
marketing program. Defendants in the original lawsuit included the
Secretary of the Interior, the Army Corps of Engineers, the Commissioner
of the Bureau of Reclamation, and others. The suit has been amended and
parties to the suit have been added, but basically the stage is set for
a probable trial in late 1975.
The plaintiffs maintain, inter alia, that47
• Both Boysen and Yellowtail Reservoirs were authorized by
Congress for the exclusive purposes of providing water
for agricultural irrigation, hydroelectric power, flood
control, silt control, and supplementation of stream
flows.
• Defendants have failed to provide water for agricultural
irrigation purposes from these reservoirs.
• Defendants plan to sell to industry 697,000 acre-ft of
water annually from Yellowtail which exceeds its usable
storage capacity.
*The Boysen Reservoir is in Wyoming on the Wind River, a tributary to
the Bighorn and Yellowstone Rivers. Completed in 1952 by the Bureau
of Reclamation, it has a total capacity of 952,400 acre-ft of water,
of which 549,900 is usable.
tThe Yellowtail Reservoir lies on the border between Wyoming and Montana
on the Bighorn River. This Bureau of Reclamation project was completed
in 1967, and has a capacity of 1,375,000 acre-ft of water of which
613,700 is usable.
634
-------
U
Ul
Purchaser
Table 19-3
INDUSTRIAL WATER CONTRACTS
BOUSEN AND YELLOWTAIL RESERVOIRS
Contract
Date
Yellowtail Reservoir
Kerr-McGee Corp.
Shell Oil Co.
Humble Oil and Refining Co. (now Exxon Corp.)
Peabody Coal Co.
Reynolds Mining Corp.
International Geomarine Corp.
-assigned to Coal Conversion Corp.
-assigned to John S. Wold, Casper, Wyoming
Gulf Mineral Resources Co. (now Gulf Oil Corp.)
Peabody Coal Co.
Colorado Interstate Gas Co.
American Metal Climax, Inc.
(Ayrshire Coal Co. Division)
Panhandle Eastern Pipe Line Co.
Shell Oil Co.
Norsworthy & Reger, Inc.
-assigned to Westmoreland Resources
Norsworthy & Reger, Inc.
Cardinal Petroleum Co.
Yellowtail Reservoir Subtotal
Boys en. Reservoir
Sun Oil Co.
Total Yellowtail, Boysen Sales
8/15/69
Water To Be
Used In
Wyoming
Acre-ft
Per Year Sold
11/09/67
11/22/67
12/14/67
5/24/68
6/19/69
6/20/69
7/13/70
8/25/71
3/02/70
5/22/70
9/04/70
1/20/71
1/11/71
2/10/71
3/01/71
7/22/71
4/21/71
5/07/71
Unspecified
Unspecified
Unspecified
Montana
Wyoming
Wyoming
Montana
Montana
Wyoming
Wyoming
Wyoming
Montana
Montana
Wyoming
Wyoming
50,000
28,000
50,000
40,000
50,000
50 , 000
50,000
40,000
30,000
30,000
30,000
20,000
30,000
50,000
50,000
623,000
35,000
658,000
Source: Reference 47.
-------
Defendants have also received applications from indus-
trial firms and other nonagricultural entities for water
option contracts covering an additional 1,281,000 acre-ft
of water per year as follows:
Acre-ft To Be Diverted From
431,000 Yellowtail and Boysen Reservoirs
630,000 Unspecified locations on Wind-Bighorn-
Yellowstone River System
220,000 Powder River
1,281,000 Total Additional Applications
• Other major appropriations of water from the Yellowstone
River and tributaries have been made by industry, without
recourse to the U.S. Government, totalling in excess of
1,000,000 acre-ft of water per year.
• In violation of federal law, defendants have not deter-
mined rights of existing water users; determined future
agricultural water needs in the region; determined avail-
ability of alternative water supplies; required indus-
trial water users to employ best available water conser-
vation techniques; analyzed alternative sources of energy
supply; or adequately analyzed any alternative course of
action other than maximum U.S. Government promotion and
subsidy of maximum private industrial and energy
development.
The averments continue, but the point is very clear: is this .
action on the part of executive agencies of the U.S. Government ultra
vires, i.e., is it in fact not authorized by, or even in derogation of,
laws passed by Congress? The question in the Yellowstone Basin will be
answered by the District Court (and the Appeals Courts), but a look at
congressional intent in the Colorado River Basin is enlightening.
The Colorado River Basin Project Act of 1968, which authorized
the Central Arizona Project, states that:
636
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...long-term contracts relating to irrigation water supply
shall provide that water made available thereunder may be
made available by the Secretary [of the Interior] for
municipal or industrial purposes....48
The legislative history of the Act elaborates on this section:
The provision for conversion of irrigation water supply to
municipal and industrial uses was included so that it would
be possible to progressively increase the amount of water
available for municipal and industrial supply as the needs
for these uses increase.49
It is particularly interesting that this inclination on the
part of the Congress toward municipal and industrial uses took place
five years before there was an "energy crisis." It is very likely that
Congress will observe the above-described litigation in the Yellowstone
River Basin. If the ultimate outcome of the suit supports the principal
argument of the plaintiffs—that the scope of the original authorizing
legislation, dating back to 1902, does not provide for industrial use of
reclamation water—Congress may move quickly to amend that legislation
so that water for energy development is available from the Boysen and
Yellowtail storage projects. However, at that juncture Congress will
have to deal with the other value-laden issues in the suit. This will
require an open discussion, at the national level, of the tradeoffs
between agriculture and energy development for this pristine but increas-
ingly visible region.
Another reclamation-related issue is the degree to which the
federal reclamation scheme operates in respect of the laws of the state
in which the project is located. Section 8 of the Reclamation Act of
190250 provides:
That nothing in this act shall be construed as affecting
or intended to affect or to in any way interfere with the
laws of any State or Territory relating to the control,
appropriation, use, or distribution of water used in
637
-------
irrigation, or in any vested right acquired thereunder,
and the Secretary of the Interior, in carrying out the
provisions of this act, shall proceed in conformity
with such laws....
As clear as this language may appear, the courts have inter-
preted it in recent years in a way that gives great flexibility to fed-
eral action. Thus, in Ivanhoe Irrigation District v. McCracken51 the
U.S. Supreme Court said, in regard to Section 8 of the Act:
It merely requires the United States to comply with
state law when, in the construction and operation of
a reclamation project, it becomes necessary for it to
acquire water rights or vested interests therein.
In addition, in City of Fresno v. California52 the Court said:
The effect of Section 8...is to leave to state law the
definition of the property interests, if any, for which
compensation must be made [under the federal govern-
ment's constitutional obligation to compensate for the
taking of property.]*
The sum of these two cases would indicate that Section 8 applies only to
the acquisition of waters for a reclamation project in a given state and
not to the distribution of those waters. In the landmark case of Arizona
v. California, the Court again considered the effect of Section 8 and
affirmed the concept that state law can have no control over the issue of
reclamation water distribution:
[Where Congress has] undertaken a comprehensive project
for the improvement of a great river and for the orderly
and beneficial distribution of water, there is no room
for inconsistent state laws....
*Reference 51, p. 291.
fReference 52, p. 630.
638
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The Court went on to say that no water could be had under the Boulder
Canyon Project other than through contract with the federal government's
designated agent, the Secretary of the Interior.
If Section 8 of the Reclamation Act leaves only the acquisition
of water for reclamation projects to state law, it is an open question as
to the interplay of federal water rights under the navigation servitude
and the reservation doctrine vis-a-vis the Section 8 provisions. In an
analysis of the broad federal power over water, developed earlier in this
paper, it was concluded that the federal power to acquire water was vir-
tually unlimited. If that is the case, the combined powers of acquisition
and distribution would appear completely vested in the Congress. A major
problem is that this result has been reached in piecemeal fashion through
P 1
judicial decisions culminating in Arizona v. California. Juxtaposing
the Boysen/Yellowtail and Boulder Canyon situations, it may evolve that
the Supreme Court will be constrained to find different national purposes
for different major river basins—the encouragement of energy development
in the Colorado River Basin but not in the Yellowstone Basin. All of
this calls for clarification and positive statements by the Congress on
the "details" of our unstated national energy policy.
10. Indian Claims to Western Water
a. The Problem
A factor in the quest of water for energy development in
the West is the ultimate water demand likely to be made by the many
Indian reservations through or near to which flow watercourses feeding
the Yellowstone and Colorado Rivers (Figure 19-1). A serious problem
does exist as shown by the following situation.
In February 1973, John Love Enterprises received a permit
from the state of Wyoming to construct a $4.3 million water reservoir
639
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W Y 0 M N G
FIGURE 19-1. INDIAN RESERVATIONS IN THE COAL-AND
OIL-SHALE-RICH REGIONS OF THE WEST
640
-------
and pipeline facility for industrial and commercial purposes in the
Powder River Basin. The amount of water was 42,500 acre-ft to be drawn
from the Little Big Horn River, which feeds the Bighorn River and thence
the Yellowstone. The Crow Indians of Montana, through whose reservation
the Little Big Horn flows, have protested the proposed appropriation
through an announcement published in several newspapers (Figure 19-2).
The Indians warned that "...the Crow Tribe has paramount rights to the
water of the Little Big Horn River and all other rivers and streams or
other bodies of water which flow through or exist upon the Crow Indian
Reservation, Montana,"63 The announcement went on to say that anyone
negotiating for water from the proposed project would do so "at their
own risk" (Figure 19-2). In other words, mere compliance with state law
might not be enough for John Love Enterprises to be assured of the water
right it sought.
There is ample authority for the position taken by the
Indians, as will be demonstrated. The basic questions in an analysis
of Indian water rights are threefold:
/»
• What is the theory on which the rights are based?
• What is the measure of the right? (i.e., the quan-
tity of water).
• What is the relationship of the Indian rights to
water rights administered under state law?
b. Theory of Indian Water Rights
The key to Indian water rights is a 1908 U.S. Supreme
Court case, which produced what is widely known as the "Winters Doc-
trine."17 The facts of the case reveal a dispute between Indians of the
Fort Belknap Reservation and non-Indian appropriators of waters of the
Milk River, a nonnavigable Montana waterway. The Fort Belknap Reserva-
tion was created in 1888 by a treaty between the Indians and the United
641
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PUBLIC NOTICE
Re: Paramount Rights off the Crow Tribe of Indians to
the Waters of the Little Big Horn River
To Whom It May Concern:
The Crow Tribe Water Resources Commission of the Crow Indian Reservation, Montana, has
learned that one John Love, who may be acting for himself or as an agent for an organization
known as John Love Enterprises, has obtained from the State of Wyoming permits for diversion of
waters from the Little Big Horn River and other streams for creation of a reservoir in Wyoming.
The Tribe has reason to believe that Mr. Love has been and is negotiating with certain parties for
the prospective sale of waters from this planned reservoir. It is even reported that he intends to bring
these waters back onto the Crow Reservation for industrial and other purposes there.
You are hereby advised that the Crow Tribe has paramount rights to the water of the Little
Big Horn River and all other rivers and streams or other bodies of water which flow through or exist
upon the Crow Indian Reservation, Montana. The Tribe has held these water rights by virtue of its
aboriginal title to the lands of the Reservation and beyond, as well as by virtue of the Treaty of
May?, 1868, with the United States government, 15 Stat. 649-51. You should be aware that federal
courts has consistently held that these and other Indian water rights apply not only to present
but also future tribal needs and uses, of any variety, an the Reservation.
The Tribe, with the assistance of expert water engineers and officials of the United States
government, has been seriously engaged in the development of plans for construction of its own
reservoir entirely within the Reservation. The reservoir would be created by diversion of waters from
the Little Big Horn River.
In view of the Tribe's aboriginal, paramount rights to the waters of the Little Big Horn River
and the existing plans for use of the same in the creation of a tribal reservoir, it it evident that any
efforts by Mr. Love, or anyone else, to divert the waters of this river upstream for any purpose
constitute a clear violation of tribal water rights. Moreover, the Crow Tribe will not pcrm.it any
waters diverted from the Little Big Horn River without tribal permission to be brought back on the
Crow Reservation.
A letter from the Director of the Office of Indian Water Rights, United States Department
of Interior, makes clear, the federal government intends to take any necessary legal action, includ-
ing suits in federal court, to protect tribal water rights. Therefore, the government can be expected
to enjoin any efforts to divert waters of the Little Big Horn River upstream from the Crow Reserva-
tion. The government or the Crow Tribe might well seek money damages for any injuries or violations
ef its rights in this connection.
You are advised that any interests negotiating with Mr. Love, or any other parties ether than
the Crow Tribe, da so at their own risk. If you find yourself in such a situation at present, yew are
urged to immediately contact the Office of Indian Water Rights, Bureau of Indian Affairs, United
States Department of the Interior, Washington, D. C. 20242; or the Crow Tribe, Crow Agency, Mon-
tana, 59022, Telephone (406) 638-2671; or the tribal attorneys, Wilkinson, Cragun & Barker, I73S
New York Avenue, N.W., Washington, D. C. 20006, Telephone (202) 833-9800.
Sincerely,
David Stewart, Chairman
Crow Tribal Council
Daniel C. Old Elk, Chairman
Crow Tribal Water Resource* Commission
Crow Indian Reservation
Crow Agency, Montana 59022
Paid Advertisement
FIGURE 19-2. CROW INDIAN NEWSPAPER ANNOUNCEMENT
642
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States. Subsequent to the treaty, and before the Indians put the water
to use, Winters and other non-Indians, at a point upstream from the res-
ervation, diverted the waters of the Milk River for their own use. The
United States, as trustee and on behalf of the aggrieved Indians, filed
suit to enjoin the upstream appropriations.
The Court held that, although not explicitly mentioned in
the documents creating the Fort Belknap Reservation, there existed an
implied reservation of rights to the use of waters that rise on, traverse,
or border on the Indian land, with a priority dating from the time of
creation of the reservation by treaty. The language of the Court has led
to two interpretations of the source of the right. One line of reasoning
jt
argues that with re'gard to Indian reservations created by treaty, water
rights were retained by the Indians at the time the treaty was made.
Furthermore, so the reasoning goes, the documents were silent on the ques-
tion because there was no intent on the part of the Indians to transfer
the water rights. The alternative view (and apparently the view of most
legal writers) holds that the water rights were in fact transferred, but
that the federal government, under its own powers, "reserved" an amount
of water from proximate streams to support an agricultural existence for
the Indians. In the case of Arizona v. California,17 in which the Court
approved water allocations to various Colorado River Basin Indian reser-
vations, the Court alluded to "...the broad powers of the United States
*Some Indian reservations were created by Executive Order and Act of
Congress. For example, the Northern Cheyenne Reservation was created
by Executive Order on November 26, 1884. The Fort Peck Reservation was
created by Act of Congress on May 1, 1888.
t"...(T)he treaty (in Winters) was not a grant of rights to the Indians,
but a grant of rights from them—a reservation of those not granted."
(Reference 55)
643
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to regulate navigable waters under the Commerce Clause and to regulate
government lands under Act 4, Section 3 of the Constitution."54 The
Court stated that Winters was good law, and that as the United States
government did in that case it did here—reserve water rights for the
Indians effective as of the time the Indian reservations were created.
The court did not directly answer the question of the source of the water
right itself (i.e., aboriginal rights, reserved by the Indians and there-
fore reserved by the federal government versus rights reserved by the
federal government as a government gesture to enable the purposes of the
Indian enclaves to be fulfilled) . To this date the issue has not been
directly litigated.
Nevertheless, whatever the source of the right, case law
and legal scholars are in agreement that there is an Indian water right
associated with each reservation, and the priority of that right is at
least as old as the reservation itself.
c. Measurement of Indian Water Rights
The measurement of the right is related to which of the
above sources the courts eventually recognize. In Arizona v. Cali-
fornia,31 the U.S. Supreme Court was dealing with Indian reservations
located on the "hot, scorching sands" of the lower Colorado River Basin.
The Court held that the amount of water reserved is to be measured by
the irrigable acreage of the Indian reservations. The National Water
Commission points out that this may be acceptable for reservations on
which fanning and ranching are expected to take place, but that other
reservations better suited for other types of occupations (e.g., hunting,
Q
fishing) may have water rights measured by different formulas. In
Winters,17 the Court asked the following rhetorical question: "The
Indians had command of the lands and the waters—command of all their
beneficial use, whether kept for hunting, and grazing roving herds of
644
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stock, or turned to agriculture and the arts of civilization. Did they
give up all this?" Even under the restrictive view of the measurement of
Indian water rights, the phrase "command of the...waters...(which might
be) turned to...the arts of civilization..." indicates that one possible
measurement for reservations located in the coal and oil shale areas is
an amount of water necessary for development of these industries. The
view that Indian water rights are aboriginal and are to be used as the
Indians desire, would certainly allow for the use of the water rights for
energy development.57 Remaining untested is the freedom with which these
water rights could be sold for use at a greater distance from the reser-
vation and whether such marketing constitutes an acceptable use of the
water rights.
d. Relation of Indian Water Rights to Water Rights Adminis-
tered Under State Law
Unfortunately for the states, no matter which "source"
theory is propounded, Indian water rights are not subject to control
s
under state allocation systems. If the rights are seen as flowing from
Indian treaties with the United States, the treaties take precedence over
state law under the supremacy clause of the U.S. Constitution.58 The
supremacy clause applies with equal force to remove the water rights
from state jurisdiction where the rights stem from congressional and
executive authoritative action. Thus, state laws regarding acquisition,
vesting, priority, preference, and transfer of water rights have no ap-
plicability to Indian water rights.
Indian rights are similarly a thing apart from interstate
compacts governing distribution of the water in interstate watercourses.
The Yellowstone River Compact provides that "Nothing contained in this
Compact shall be so construed or interpreted as to affect adversely any
rights to the use of the waters of the Yellowstone River and its Tribu-
• • c a
taries owned by or for Indians, Indian Tribes, and their Reservations.
645
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Both the Colorado River Compact60 and the Upper Colorado River Basin
Compact41 exclude Indian water rights from their consideration; that is,
they are dividing up water left after Indian (and other federally pro-
tected) water rights are deducted from the respective river's total flow.
e. Scope of the Problem
Returning to the original problem of John Love Enter-
prises, it perhaps is clear just how open-ended the rights of the Crow
Indians are. The Crow Reservation was formed by the Treaty of May 7,
1868. At best, only holders of vested rights prior to that date can be
sanguine about the sanctity of their rights. State-approved water rights
with a later date are subject to being denied by the higher priority of
the Indian rights—and no compensation would be paid.
The oil shale region is just as vulnerable. The rights
adjudicated in the case of Arizona v. California31 amounted to 1 million
acre-ft of water. A look at the number of Indian reservations on the
Colorado River or on tributaries of the Colorado is instructive. With
the exceptions of those noted, water quantities demanded and ultimately
adjudicated for these reservations remain to be determined. Whatever
the amounts, the water will come off the top of the available water in
the Colorado River Basin, cutting down on the amounts remaining to the
states for allocation for agricultural, energy development, municipal,
recreational, and other uses.
646
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Tributary
Indian Reservation
Green River
Kanab River
San Juan River
Little Colorado River
Gila River
Colorado River
Uintah
Ouray
Kaibab
Ute Mountain
Southern Ute
Jicarilla
Navajo
Hopi
Zuni (via Zuni River)
San Carlos
Fort Apache (via Salt River)
Salt River (via Salt River)
Ft. McDowell (via Salt River)
Gila River
Papago
Hualapai
Fort Mojave*
Chemehuevi*
Colorado River*
Ft. Yuma*
Cocopah*
f. Conclusions
The open-ended nature of Indian water rights is unaccept-
able to all concerned. As one observer has noted:
This uncertainty is not good for Indians; it is
not good for non-Indians. It gives neither Indians
nor non-Indians a clear title, and leaves as the
source of Indian water rights a conglomerate mass
of unconstrued treaties, agreements and executive
*The total of these entries were adjudicated at 1,000,000 acre-ft in
Arizona v. California.21
647
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orders. Indians occupy thousands of square miles
in the Western states...The time for an orderly
procedure which will end the Indian water right
chaos has long passed.61
The National Water Commission believes that an across-the-board adjudi-
cation is not necessary. Instead, the Commission calls for the fol-
lowing:62
• Inventory of existing Indian water uses (to be
placed in state records for informational
purposes).
• Quantification of water necessary to accomplish
a sound economic development plan for each res-
ervation (responsibility to rest with the Secre-
tary of the Interior).
• Quantification of rights wherever a non-Indian
project is planned for a basin in which there
is an Indian reservation (e.g., the John Love-
Crow Indian situation).
When Indian rights are exercised in a basin whose water
is completely appropriated, the Commission recommends that the Indians
get the water, and that the persons who lose the water be compensated
by the federal government as follows:63
• No compensation for projects developed after
June 3, 1963, the date of the Arizona v.
California. (Presumably, this case put the
water developer on notice regarding Indian water
rights.)
• Where possible, the federal government will
provide substitute water from its own water
rights.
• No compensation when developer had actual notice
of a conflicting Indian claim at the time of
development.
• No compensation for values created by federal
subsidy.
648
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Because the Yellowstone and Colorado Basins are virtually
closed to further appropriations (especially the Colorado), it would
seem that complete adjudication of Indian water rights in these regions
would be desirable to create some certainty for future decisions.
C. Interstate Allocation of Water
1. Allocation by the Court
When a river flows across the boundaries of two states, or
forms the boundary between two states, disputes can arise over the proper
use of the waters by each of those states. When a case or controversy
exists between two states, the U.S. Constitution provides that the U.S.
Supreme Court shall have original jurisdiction.* This means that in
such disputes the Supreme Court acts as a trial court, determining not
only the law but resolving questions of fact as well.
A good example is the U.S. Supreme Court case of Wyoming v.
Colorado.64'65 Wyoming sued Colorado, and two Colorado corporations,
to prevent a proposed diversion from their natural basins of the waters
of the Laramie River, a nonnavigable interstate stream rising in Color-
ado and flowing into Wyoming. Colorado maintained that it could dispose
of all the waters within its borders. The Court held otherwise:66
The contention of Colorado that she as a state rightfully
may divert and use, as she may choose, the waters flowing
within her boundaries in this interstate stream, regard-
less of any prejudice that this may work to others having
rights in the stream below her boundary, cannot be main-
tained. The river throughout its course in both states
is but a single stream, wherein each state has an inter-
est which should be respected by the other.
*U.S. Constitution; Article III, Section 2. Federal law adds that the
jurisdiction shall be exclusively in the Supreme Court in disputes be-
tween two states: United States Code; Volume 28, Section 1251(a). Note
that because the trial is held in the highest court in the land, there
is no opportunity for appeal.
649
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The Court went on to say that the doctrine of prior appropriation would
apply and the Court enjoined Colorado from diverting water from the
Laramie River in a manner that would deny water rights held by prior
appropriators in Wyoming. The Court determined the dependable flow of
the river and then proceeded to make firm allocations to Colorado and
Wyoming. The rule of law applied by the Court is known as the doctrine
of "equitable apportionment."
The Supreme Court does not see itself as an expert in water
allocations, and encourages what amounts to "out of court settlements"
by the states. In this regard, the U.S. Constitution states that "No
state shall, without the consent of Congress...enter into any agreement
(i R *y
or compact with another state.... However, Congress had made it clear
that it also encourages the resolution of interstate water disputes by
the concerned states themselves, and that approval of such agreements or
compacts would be readily given.
2. The Colorado River Basin
The implications of Wyoming v. Colorado were not lost on the
states of the Upper Colorado River Basin; they knew that there was much
water development activity going on in the Lower Basin states, and they
feared that an interstate application of the doctrine of prior appropri-
ation to those developments in the Lower Basin could eventually deny any
use of the Colorado River to the more slowly developing Upper Basin
states. Accordingly, they sought an agreement with the Lower Basin
states, which would preserve to them some water rights in the Colorado
co
River Basin. The result of those negotiations was the Colorado River
Compact of 1922.69>7°
650
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The Colorado River Compact has the following features:
• Designates two basins—Upper and Lower with dividing point
at Lee Ferry, Arizona (near Utah/Arizona border).
• Each basin to receive in perpetuity 7.5 million acre-ft
of water oer year.
• Lower Basin may increase its annual consumptive use
by 1 million acre-ft in addition to the initial
allocation of 7.5 million.
• Upper Basin is obligated not to deplete the flow at Lee
Ferry below an aggregate of 75 million acre-ft for any
period of 10 consecutive years.
• Within each basin, no specific allocation is made to
individual states.
• The Compact does not apply to Indian water rights.
In the Boulder Canyon Project Act of 1928,7O Congressional
consent was given to the River Basin states
to negotiate and enter into compacts or agreements, sup-
plemental to and in conformity with the Colorado River
Compact...for a comprehensive plan for the development
of the Colorado River and providing for the storage,
diversion and use of the waters of the River.
Representatives of the Upper Basin states of Wyoming, Utah, Colorado,
Arizona, and New Mexico, in 1946, joined with President Truman's appoin-
tee in forming a Commission to develop what was to be the Upper Colorado
River Basin Compact. The Commission worked for two years to produce the
document. One of the major stumbling blocks was how to deal with water
rights of the federal government and Indian tribes in the Basin. The
Commission's difficulties in this regard are illustrated by the follow-
ing response of the U.S. Department of the Interior to a Commission
inquiry:71
The Compact should not attempt, in our judgment, to
define, limit, or in any manner to determine the powers
of the United States in, over, or to the waters of the
651
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Colorado River System. The extent to which those powers
should be exercised is a matter for determination by the
Congress.
Recognizing that the federal landholdings are extensive in the Upper
Basin, this significant water factor's absence weakened the impact of
the final pjoduct. The applicable section of the resulting Compact
contains the following critical language:41
Nothing in this Compact shall be construed as
(a) Affecting the obligations of the United States
of America to Indian tribes;
(b) Affecting the obligations of the United States
of America under Treaty with the United Mexican
States;
(c) Affecting any rights or powers of the United
States of America...in or to the waters of the
Upper Colorado River System...;
(d) ...;
(e) Subjecting any property of the United States of
America...to the laws of any state....
Other provisions of the Compact are
• Detailed apportionment
— 50,000 acre-ft per year of consumptive use to Arizona,
— Balance of consumptive use to Colorado (51.75%); New
Mexico (11.25%); Utah (23%); Wyoming (14%).
• Existing rights must be satisfied out of apportionments.
• Apportionments only for beneficial use.
• Procedures for equitable curtailment in time of water
shortage.
• Procedures for dealing with evaporation and seepage
losses.
• Consumptive use of water by United States (and Indians)
to be charged as a use by the state where made.
652
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• Each state and the United States can acquire water rights
or construct project works in a signatory state (subject
to certain conditions).
• Power generation is "subservient" to agricultural and
domestic uses.
• Failure of a state to use apportionment shall not con-
stitute a relinquishment of such right.
• No prohibition on trans-basin (interbasin) transfers of
water.
In addition to the aforementioned problem of unquantified
federal and Indian water rights, there are energy development water
problems between the lines of the two Colorado River Compacts. The
initial problem lies in the use by the draftsmen of the Compact of the
*
figure of 15 million acre-ft of virgin flow at Lee Ferry, Arizona, as
the average flow of the river for making allocations between the Upper
Basin and the Lower Basin. From 1922 to 1967, the average virgin flow
was only 13.7 million acre-ft.72 Because the Lower Basin is guaranteed
an average annual flow of 7.5 million acre-ft with the Upper Basin re-
ceiving the balance, the corresponding average annual flow available to
the Upper Basin for these years was only 6.2 million acre-ft. When the
Upper Colorado River Basin Compact percentage allocations are applied,
the following figures result:
Acre-ft
Arizona 50,000
Colorado (51.75%) 3,183,000
Utah (23.00%) 1,414,000
Wyoming (14.00%) 861,000
New Mexico (11.25%) 692,000
* "Virgin flow" is the water which, e.g., would flow by Lee Ferry if
there were no man-made diversions of the River Basin.
653
-------
The resulting allocation to Colorado is far less than that state's con-
tribution to the flow of the River, estimated at 11.46 million acre-ft
per year.73 Of its total contribution, then, Colorado is allocated only
28 percent.
When these compacts were drawn up, it was not foreseen that
large scale energy development in the national interest would take place
in western Colorado. From the following statement of a Conservation
District official, it is clear that the water squeeze on the state is
not appreciated by Colorado:74
It appears that Colorado is going to be asked to produce
large amounts of both liquid and electrical energy with
the largest percentage of both of them to be exported.
But right now we are not really sure what our answer to
that result will be....If Colorado is to be asked (and
right now it is more like a demand) to furnish energy
for the rest of the U.S., then it may be necessary to
re-examine the allocations of the already limited
Colorado River supplies....Colorado may be forced to
prevent or limit the building of energy-exporting
facilities in the future unless other states are will-
ing to make some kind of agreement with Colorado to
help us solve this problem.
But the other states in the Colorado River Basin have their own energy
development, irrigation, and municipal growth water requirements. It
is difficult to get more water out of a river by describing it differ-
ently—no new compact could perform that miracle. It would seem that
allocations of values will be of equal importance with allocations of
quantities; i.e., a reassessment of how a given amount of water should
best be used. In this regard, the Colorado water official stated:69
Colorado is pressing forward with planned irrigation
projects; we are not willing to totally trade off our
western Colorado agricultural base for the production
of energy.
654
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The answer, of course, is not to deal in "total trade offs," but to
negotiate in a new and open manner national, regional, and state con-
cerns and values.
3. The Northern Great Plains
There are two interstate rivers near the coal development
region of the Northern Great Plains. These are the Belle Fourche River,
rising in Wyoming and flowing into South Dakota, and—more significantly-
the Yellowstone River, beginning in Wyoming, running through Montana and
on into North Dakota. There are interstate compacts covering each of
these rivers.
The Belle Fourche Compact of 1943 makes a division of the un-
appropriated waters of the Belle Fourche River Basin as follows:
South Dakota 90 percent,
Wyoming 10 percent.
The amount of water available to Wyoming is approximately 20,000 acre-ft
per year,75 not a major factor in the water for energy picture. What is
of interest, however, it a comment made by the President of the United
States in signing the legislation under which Congress approved the
Compact.76 Article XIV(c) contains the following language:
The United States...will recognize any established use,
for domestic and irrigation purposes, of the apportioned
waters which may be impaired by the exercise of Federal
jurisdiction in, over, and to such waters; provided that
such use is being exercised benefically, is valid under
the laws of the appropriate state and in conformity with
this compact at the time of the impairment thereof, and
was validly initiated under state law prior to the ini-
tiation or authorization of the Federal program or proj-
ect which causes such impairment.
655
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The Congressional act contained the same language through which the fed-
eral government was bowing toward existing state water rights vis-a-vis
future federal projects. This clearly upset the Chief Executive:77
In signing the Belle Fourche River Basin Compact Bill,
I find it necessary to call attention...to the restric-
tions imposed upon the use of water by the United States.
The procedure prescribed by the bill for the exercise of
the powers of the Federal Government would not be entirely
satisfactory in all circumstances, but the prospects in
fact for the exercise of such powers in the Belle Fourche
basin are not great. For streams where conditions are
otherwise and there appears to be a possible need for
Federal comprehensive multiple-purpose development or
where opportunities for important electric power proj-
ects are present, I believe...(this)...Compact should
not serve as a precedent. In such cases the compact and
the legislation should more adequately reflect a recog-
nition of the responsibilities and prerogatives of the
Federal Government.
This statement strongly illustrates the latent federal water interest
and power waiting in the wings. This tension and its ramifications were
discussed in another section, but it is clear that these interstate
compacts exercise little real constraint on federal water rights. Sim-
ply stated, the President is saying that interstate compacts should
merely divide up—as between the signatory states—that water remaining
after federal and Indian water interests are satisfied. Furthermore,
the division will be subject to future federal and Indian water needs.
Interestingly enough, the Yellowstone River Compact of 1950 is
stripped of the language which troubled the President. Significantly,
U.S. "sovereignty" and "jurisdiction" over the subject waters are inter-
jected into the Compact. Thus:78
Nothing in this Compact shall be deemed to impair or
affect the sovereignty or jurisdiction of the United
States of America in or over the area of waters af-
fected by such Compact...,(or) any rights or powers
656
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of the United States of America...in and to the use of
the waters of the Yellowstone River Basin....
By way of emphasis, in the legislation approving the Compact, Congress
reserved the right to amend the Compact, presumably unilaterally, or to
"7 Q
repeal it entirely/ In this regard, the U.S. Supreme Court has ac-
knowledged that the Congress is not bound by its approval of an inter-
state compact.
Notwithstanding this profound weakness of the instrument, the
features of the Yellowstone River Compact are as follows:
• Existing rights are confirmed as of January 1, 1950.
• Unappropriated waters of interstate Yellowstone
tributaries are apportioned^
Tributary Wyoming (%) Montana (%)
Clarks Fork 60 40
Bighorn 80 20
Tongue 40 60
Powder 42 58
Each of the Compact states (Wyoming, Montana, North
Dakota) may divert and impound water in another state
for its own use.
Tributaries arising entirely in one state are wholly
allocable by that state.
Diversion of water out of the Yellowstone subbasin
is prohibited unless approved by all three signatory
states.
*That is, Congress can legislate in a manner inconsistent with its prior
approval of a compact (Reference 80).
tThere are no interstate tributaries running into North Dakota; hence,
no tributary water allocation is made to North Dakota.
657
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Energy development in the arid Powder River Basin coal fields,
lying north and south of Gillette, Wyoming, will require large amounts of
water. Much thought and planning have gone into interbasin transfers of
water to the Powder River Basin. As noted above, for the Yellowstone
subbasin, this is prohibited unless all three states approve of the
transfer.81
If consent should not be forthcoming, there is another alterna-
tive. Because neither the Colorado River Compact, nor the Upper Colorado
River Basin Compact restrict interbasin transfers, Wyoming can divert
water from its Upper Colorado River Basin share. This interbasin trans-
fer would bring water from the Green River Basin, a headwater tributary
of the Colorado River eastward across the state to the Powder River Basin.
D. State Systems for Water Allocation in the West
1. General Systems
Because of the generally arid conditions in the West, a special
legal doctrine evolved, which allowed water to be physically moved away
from the source of the water (river, lake) to a place where it could be
put to use. This represented a departure from the riparian law of the
water-rich eastern United States inherited from water-rich England—the
riparian doctrine gives equal rights to the waters of a river or stream
to all whose lands border on the river or stream. Each user is entitled
to a "reasonable" amount, but under no circumstance may the water be used
*The Wyoming share is 14 percent. Typically, then 14 percent of 6.2 mil-
lion acre-ft gives Wyoming 861,000 acre-ft for allocating within the
state. Of this amount "...the feasibility of exporting 100,000 to
200,000 acre-ft is now under consideration." Note: As used here, "Ex-
port" refers to the interbasin transfer of this amount of water from
the Upper Colorado Basin to the Powder River Basin (Reference 7.3, p. 40).
658
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outside of the basin of the waterway. The riparian doctrine provides
that the water right exists whether or not it is exercised, and the
right is not forfeited by nonuse.
The appropriation doctrine of the West appears in the early
California case of Irwin v. Phillips,8 in which two gold miners were
squabbling over the right to use the waters of a stream. The court's
decision "announcing" the doctrine was based on the need to protect the
rights of those...
...who by prior appropriation have taken the waters from
their natural beds, and by costly artificial works have
conducted them for miles over mountains and ravines, to
supply the most important interests of the mineral
region...(Where, as here)...two rights stand upon an
equal footing, when they conflict they must be decided
by the fact of priority....
The doctrine's major features are as follows:
• A right to the use of water is created by a diversion of
the water from a stream for a beneficial use.
/
• The first to so acquire the right shall have a priority
in law: "first in time is first in right." (In the
event of a shortage, the last to divert and make use of
the stream is the first to have his water supply shut
off.)
• Water can be used at any location without regard to the
distance of the use from the stream.
With some embellishments over time, such as the feature of relating
back,* this approach stood as the water law of the West. No government
*The priority of a right is established by commencing work on an appro-
priation. If the work is continued with due diligence, then upon com-
pletion, the priority of the completed right relates back to the time
the work was commenced.
659
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approval was required to establish the water right. Subsequent statutes
merely confirmed the court developed doctrine.*
2. The Need for Certainty of Water Rights
Although it fully embraced the doctrine of prior appropriation,
Wyoming legislatively instituted a permit system to improve the record
keeping of water rights, thereby injecting more certainty into the status
of the water rights of the individual. Thus, anyone desiring to appropri-
ate water in Wyoming must first make application to the state engineer—
diversion of water without a permit from the state engineer is a punish-
able offense.83 The engineer must approve the application if he finds
that the proposed use is a beneficial use, that the proposed use will not
impair the value of existing rights, and that the proposed use is not
otherwise detrimental to the public welfare.84
Wyoming went to the permit system in 1890—Montana in 1974.
Montana was responding to increasing demand for a system that would pro-
vide conclusive determination of existing rights.85 A 1972 Montana con-
stitutional amendment86 prodded the legislature into action. The new
law's declaration of policy and purpose is instructive:87
The legislature declares that this system of centralized
records recognizing and establishing all water rights is
essential for the documentation, protection, and preser-
vation and future beneficial use and development of
Montana's water... .
*For example, the Colorado constitution provides that..."(t)he right to
divert the unappropriated waters of any natural stream to beneficial uses
shall never be denied. Priority of appropriation shall give the better
right..." (Article XVI, Section 6. See also Wyoming Laws 1869, Chap-
ter 8 and Chapter 22).
660
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The law requires '...each person claiming an existing right...to file a
I f o o
declaration.... The court then adjudicates the status of existing
decrees. Based on its final decree, individual certificates of water
rights are issued, with copies filed at the county clerk's office.89
Because Colorado continues not to be a permit-system state,
record-keeping shortcomings have created problems. A random search of
court decrees was less than a satisfactory way for would-be appropri-
ators to discover existing senior rights to a given stream. To remedy
this, the Colorado legislature in 1969 called for
...a tabulation in order of seniority of all decreed water
rights and conditional water rights...Such tabulation
shall describe each water right and conditional water
right by some appropriate means and shall set forth the
priority and amount thereof as established by court
decrees,9°
The tabulation was to be published, corrected, and published in final
form by October 1971; however, special legislative action moved this
deadline to October 1972. The legislation said that in November 1974
(and every two years thereafter) the latest tabulation must be presented
by the state engineer to the water judge for public hearings:
A copy of (the court's) judgment and decree shall be filed
with the state engineer (for placement in his records to
show) the determinations therein made as to priority, lo-
cation, and use of...water rights and conditional water
rights. . . .91
It should be emphasized that the above procedure does not alter one's
right under the Colorado constitution to appropriate water. This is
9 2
accomplished by diverting the water and putting it to beneficial use.
However, the tabulation and adjudication procedure does affect the
priority of one's appropriative rights. Thus, failure to come forward
at the time of the tabulation and adjudication could result in a senior
661
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right (relatively speaking) slipping to the most junior right of all.
The right still exists, but in time of water shortage it will be the
first one cut off.
These mechanisms provide a degree of certainty and they go a
long way toward reducing the number of "stale" or "paper" rights going
unused. Included in the efforts of the states to eliminate such rights
are abandonment provisions in the law. Thus, e.g., Montana law provides
that
If an appropriator ceases to use all or part of his ap-
propriation right, or ceases using his appropriation
right according to its terms and conditions, for a period
of ten (10) successive years...there shall be a prima
facie presumption that the appropriator has abandoned
his right in whole or for the part not used.93
Wyoming uses a figure of five years after which time the water right is
forfeited.94 In Colorado, failure to use the water right for a period
of ten years creates a rebuttable presumption of abandonment.95
Although designed to make available water that is going unused,
the forfeiture statutes have the unintended effect of encouraging waste,
in that a holder of a "dusty" water right might be encouraged to use the
water profligately to avoid forfeiture of the right.96
The certainty of rights, discussed above, has a positive eco-
nomic effect. Knowing what water is available and what the order of
priority is, a potential investor (whether in irrigation or energy pro-
duction) is in a much better position to make an investment decision.
662
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3. Transfer of Water Rights
Where all the water available to the state is spoken for,
5^
either by absolute decreed rights or by conditional rights as it is in
Colorado, it becomes necessary to consider a transfer of the right from
one type of use to another, e.g., from irrigation to the production of
synthetic fuels. Such a transfer very likely would require a change in
the place of use and a change in the point of diversion of the water.
The law in most western states allows such transfers, subject
to the administrative procedures of the particular state involved. The
delay and red-tape caused by some of those administrative procedures were
points of criticism made by the National Water Commission in its 1973
Report.97 The Commission stated that "...any person or organization
having the right to use water should be entitled to transfer such right,
and all statutes, judicial decisions, and administrative regulations to
the contrary should be repealed."98 An example of how transfer of water
rights was thwarted may be seen in a Wyoming law, which made a water
right appurtenant to the land benefiting from the right—"Water rights
for the direct use of the natural unstored flow of any stream cannot be
detached from the lands, place or purpose for which they are acquired...."99
This situation was changed, perhaps as a result of the National
Water Commission's recommendation, by a 1974 Wyoming law which allows the
change
provided that the quantity of water transferred—shall
not exceed the amount of water historically diverted
under the existing use, nor exceed the historic rate
of diversion..., nor increase the historic amount con-
sumptively used..., nor decrease the historic amount
*See footnote on page 19-46
663
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of return flow, nor in any manner injure other existing
lawful appropriators.100
Notwithstanding the intentions of the new law, administrative convolu-
tions continue. An example of the red-tape involved in a transfer of
rights is provided by the Panhandle Eastern Pipe Line Company. Panhandle
proposed to purchase water rights with an 1884 priority date from a ranch
on the North Platte River and to convert the use from irrigation to in-
dustrial (coal gasification). The proposal also included a one-hundred-
mile change in the point of diversion. The Wyoming administrative auth-
ority, the Board of Control, denied the requests on several grounds:101
• Failure to show that holders of other rights would be
protected from injury.
• Unresolved discrepancies in the accounting of all the
water rights involved.
• The distance involved and the time lag between the pro-
posed point of diversion and the present point of di-
version made it impossible to assess general compliance
with the Supreme Court decree requirements in Nebraska
v. Wyoming (1945) regarding administration of the North
Platte River.
Panhandle had to resort to the Laramie County District Court, which re-
versed the Board's findings and sent the proposal back for reconsidera-
tion. Panhandle finally prevailed, with the Board granting a permit to
divert 26,500 acre-ft of water with a stipulation that diversions were
not to deprive any Wyoming water right holder of previously entitled
North Platte River water. This exhausting, costly, and time-consuming
process clearly has a chilling effect on the free transfer of water
rights.
Montana law on transfer of water rights allows a change if it
is determined "...that the proposed change will not adversely affect the
rights of other persons."102 In Colorado, unrestricted transfer is
664
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allowed where no other right is injured.103 The kind of injury contem-
plated is seen in the situation where an upstream irrigation appropri-
ator "A" sells his water right to a synthetic fuel producer "B" who
contemplates a total consumptive use of that water. Such use would in
fact reduce the flow of water as seen by a downstream appropriator "c"
because some of the water contained in the water right of "A" histori-
cally returned to the stream after performing the irrigation function.
Thus, the best "B" can hope for is "A's" water right scaled down by the
amount of return flow customarily seen by "C."
To allow time to check for injury to other appropriators,
Colorado law allows for a trial period after the change. Thus, the
change is a1lowed -
subject to reconsideration by the water judge on the
question of injury to the vested rights of others dur-
ing any hearing...in the (subsequent) two calendar
years...104
4. Interbasin Transfers
The transfer of a water right to a different place of use can
logically be extended to rather great distances. The institutional re-
sistance to such moves on an interstate basis is discussed in another
section, but even within a given state the issue of interbasin transfers
creates strains on the system. Generally, under the principles of the
appropriation doctrine, the basin of origin has no right to receive the
natural flow of the basin's streams.1CE Thus water in one basin may be
appropriated and put to beneficial use in another basin. A prime example
of this is the use by the "front range" metropolitan areas of Denver and
Fort Collins, Colorado, of water flowing on the "other" side of the
Rocky Mountains, on what is called the "western slope." About one-half
of Denver's water comes from such transmountain diversions.106 The water
.demand of cities is typically given a statutory preference over other
665
-------
uses, which means that although the priority may be later in time, the
Q Q Q 9
allocation system will supply these needs first. ' In Colorado, pre-
ferred users are given the power of condemnation over other users, thus--
with payment of just compensation—a growing Denver could condemn an
energy company's absolutely vested water right on the western slope and
transfer the water over the mountains for its municipal uses.107
5. Conditional Decrees
Since many energy companies are holders of Colorado conditional
decrees some discussion is necessary. As previously mentioned, the pri-
ority of a right is established by commencing work on an appropriation.
The decree is conditioned upon (1) completion of the work accomplishing
the diversion, and (2) application of the water to a beneficial use.
When that is done, the decree becomes absolute and the priority of the
completed right relates back to the time the work was commenced. To
eliminate speculation in water rights, the law requires that the would-
be appropriator exercise ' due diligence" in his work to complete the
diversion. Every second calendar year he must obtain a finding by the
water referee that reasonable diligence has in fact been exercised.
Otherwise the conditional decree (and its precious priority date)
lapses. ° This law means that those energy companies holding on to
conditional decrees while their energy development plans crystalize
must make some effort at actually constructing their water project. A
similar squeeze is presented in the permit states of Montana and Wyom-
ing. Montana law allows the administrative authority to establish a
time limit
for commencement of the appropriation works, completion
of construction and actual application of the water to
the proposed beneficial use. [The authority] shall con-
sider the cost and magnitude of the project, the engi-
neering and physical features to be encountered, and, on
666
-------
projects designed for gradual development and gradu-
ally increased use of water, the time reasonably nec-
essary for that gradual development and increased
use....109
For good cause, the time limit may be extended, but, in absence of such
an extension, the permit and its priority date will be revoked if the
work is not "commenced, prosecuted or completed" in the time allowed or
if the water is not being applied to the contemplated beneficial use.110
Under Wyoming law, the state engineer must specify a time limit
on the permit, not to exceed five years.111 For good cause the time
limit may be extended. Again, failure to comply may lead to revocation
of the permit. This presents a dilemma for the energy company contem-
plating construction of a synthetic fuels plant; if the water project is
completed, satisfying this statute, the permit may nevertheless be re-
voked if the water right thus perfected goes unused for a five-year
period while construction is completed on the fuel plant. This is be-
cause of the abandonment provisions of the Wyoming water law previously
discussed.94
6. Public Interest in Water
In its comprehensive study of water issues, the National Water
Commission dedicated part of its effort to noneconomic or social values
in water. The study concluded that the appropriation doctrine does not
provide for protection and preservation of scenic, aesthetic, recrea-
tional, and environmental values. The Commission called upon the states
for legislative action:113
• Reserving portions of streams from development and
setting them aside as "wild rivers."
• Authorizing a public agency to file for and acquire
rights in unappropriated water.
667
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• Setting minimum stream flows and lake levels.
• Establishing environmental criteria for the granting
of permits to use water.
• Forbidding the alteration of watercourses without state
consent.
State action has been remarkably responsive. Colorado quickly
passed legislation aimed at the in-stream values issue. One of the new
laws eliminates the requirement of actual diversion to effectuate a valid
appropriation, so that now the only requirement is "...the application of
a certain portion of the waters of the state to a beneficial use."113
Companion legislation gives to the state the opportunity to take advan-
tage of the lack of a diversion requirement. The new law broadens the
definition of the term "beneficial use" to include appropriations by
the state of minimum flows between specific points on natural streams
and lakes "as are required to preserve the natural environment to a
reasonable degree."114'115 Elation by environmentalists may be prema-
ture, however, for the state is not given a preferential right of ap-
propriation. Thus, if the state wishes to appropriate water to main-
tainin minimum flows, it must do so in the same manner as the nongovern-
mental water user. Recalling that Colorado's waterways are already
overappropriated, it would seem that the only practical possibility of
accomplishing the purposes of the legislation would be for the state to
purchase the water rights of others. Whether accomplished by appropri-
ation or by purchase, it is clear that this new water demand will cut
further into any supply available for the synthetic fuels industry.
^"Beneficial use" has not been specifically defined until these recent
statutes. Whether a use was "beneficial" was typically handled on a
case by case basis, with the main thread of the decision being seen in
the question, "is it reasonable and economical, all things considered?1
668
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A 1974 Wyoming law states that
All water being the property of the state and part of the
natural resources of the state shall be controlled and
managed by the state for the purpose of protecting and
assuring the maximum permanent beneficial use of waters
within the state.116'117*
A caveat for energy companies is provided in a later paragraph:
None of the water of the state either surface or under-
ground may be appropriated, stored or diverted for use
outside of the state or for use as a medium of trans-
portation of mineral, chemical or other products to
another state without the specific prior approval of
the legislature on the advice of the state engineer.^118
The state of Montana has also responded to the recommendation
of the National Water Commission that in-stream values are to be pro-
tected through state legal mechanisms. Montana law declares its purpose
is
to provide for the wise utilization, development and
conservation of the waters of the state for the maximum
benefit of its people with the least possible degrada-
tion of the natural aquatic ecosystems...87
To implement the state program, power is given to the state "...to
reserve waters for existing or future beneficial uses or to maintain
* Beneficial use" includes, but it not limited to the following: munici-
pal, domestic, agricultural, industrial, hydroelectric power and rec-
reational purposes, conservation of land resources and protection of
the health, safety and general welfare of the state of Wyoming.
tThe Act goes on to give approval (subject to the decision of the state
engineer) for up to 20,000 acre-ft per year of Madison formation well
water for use in a coal slurry pipeline to carry coal from Wyoming to
Arkansas (Reference 118, Section 1-10.5(c)).
669
-------
minimum flow, level, or quality of water...."119 After defining "bene-
ficial use" in the Wyoming manner (domestic, municipal, agricultural,
etc.) the law goes on to state that "...use of water for slurry to export
coal from Montana is not a beneficial use" (emphasis added) . This com-
pares interestingly with the Wyoming provision on the subject. Wyoming
says yes, if legislative approval is obtained, whereas Montana says no,
period.
The legislative tools with which the mineral-rich states have
equipped themselves will apparently make it harder for energy companies
to get the amounts of water they need for mining and synthetic fuels
production, and once obtained the use of the water will likely be con-
strained by the water quality goals explicitly contained in the language
of the new laws.
7. Pricing of Water
It is said that cheap energy encouraged wastefulness, which
led to energy shortages. A similar comment can be made about water.
The National Water Commission has called for an abandonment of water
subsidies which artificially make water appear to be cheap, and the
Commission encourages a less inhibited system of water rights transfer.120
Their position is that a free market for water will result in the evolu-
tion of true value reflecting the most productive economic use for the
water.
Professor Charles J. Meyers, in a legal study done for the
National Water Commission, made the following observation:121
...(W)hen criteria of allocation other than willingness
to pay are used, it is very difficult to decide which
uses (or users) of a resource will be most productive...
The price system produces an unambiguous and usually
quite satisfactory answer. The party in whose hands
670
-------
the property will be most productive is the party who
values it most highly and is willing to pay the most
for it.
Others are fearful of what can happen if water goes to the highest bidder.
They point to the need for increased planning to avoid the tragedy of
what free market land development did to Los Angeles.122 The bidding is
real. At the time that farmers were paying $20 per acre-ft for water,
one energy company was prepared to pay up to $1200 per acre-ft to secure
the use of the water for energy development.123 "To an energy company,
even a high price of water is a minor expense, both in terms of the other
costs of energy production, and in terms of the profitability of the
jf *1 r-i A
operation. a -The price elasticity of water is illustrated in a study
which revealed that doubling the price of water caused an 11.4 percent
increase in the price of agricultural products, while the doubling raised
the cost of electric power by only 1 percent.125
Thus, a totally free market could conceivably result in a
going rate" for water affordable only by energy companies—thereby
eliminating other uses, such as agricultural, recreational, and envi-
ronmental .
Under the protections built into the "beneficial use" provi-
sions previously discussed under the section entitled Public Interests
in Water, the necessary first-step tools exist to determine the equiva-
lent economic values of these other water uses, and to create a politi-
cally, if not economically, well-balanced water allocation scheme. The
result is analogous to the concept of comprehensive land use planning
where zoning predetermines the land use balance—parks, industrial,
residential, etc. The water supply would be "zoned" to create a poli-
tically acceptable distribution, but within those constraints, free and
unfettered transfer of rights would be encouraged, with the highest bid-
der prevailing.
671
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The shortcomings of the present system lie in the failure of
the various legislatures to supply the "equivalent economic values"
which the state engineer can use in judging appropriation applications.
8. Groundwater
While groundwater has been heralded by some as a great source
of water for energy development, others have warned of the havoc that
could result from an unstructured, haphazard use of this resource.
In his well-respected 1942 water law treatise, Wells Hutchins,
pointed out that "...complete coordination of surface and ground waters...
remains a most difficult (problem) owing to the invisibility of sub-
terranean waters and the mass of data required to prove satisfactorily
their origin, quantity, and movements."126
Groundwater hydrology, replete with misinformation, misunder-
standings, and mysticism, "...has always been a favorite refuge for
quacks and pseudoscientists...(and) practitioners of the willow branch
or the brass welding rod."127 Nevertheless, strict attention to the
quantity and quality of underground water, especially in its interrela-
tionship with surface water flows, is called for by two national study
commissions,128 >129
As long as there were sufficient supplies of surface water,
the groundwater issue was not an important one. Accordingly, Western
water law developed for the allocation of surface streams almost to the
exclusion of consideration of groundwater disputes. The occasional
groundwater controversy was handled with a separate set of rules taken
from the common law. The general common law rule, inherited from England,
provided that waters beneath the land are property of the landowner who
may withdraw them irrespective of the effect on others. Because this
produced a harsh result on neighboring property, two modified doctrines
672
-------
arose; the "reasonable use rule" stated that any use is subject to the
similar rights of others who would be negatively affected by an unreas-
onable withdrawal; an extension of this rule became the "Correlative
rights doctrine," which gave co-extensive and co-equal rights to adjoin-
ing landowners. The Western appropriation doctrine for surface waters
was, in some cases, applied to groundwater giving the first person to
put the water to beneficial use the senior right.
As water became more and more scarce in certain places in the
West, the inadequacy of this treatment of groundwater resources was made
clear. The initial corrective step was to draw distinctions between
underground waters tributary to natural streams and those enclosed in
impervious basins". The former were the first to be reexamined because
wells that removed water from tributary groundwater, by definition, af-
fected surface rights in the stream toward which the groundwater was
moving. Hydrologically speaking, such tributary groundwater is a part
of the stream it feeds.130 Wyoming's groundwater law recognizes this,
as follows:
...where underground waters and the waters of surface
streams are so interconnected as to constitute in fact
one source of supply, priorities of rights to the use
of all such interconnected waters shall be correlated
and such single schedule of priorities shall relate to
"L *^ 1_
the whole common water supply....
Colorado law makes the important distinction between tributary and non-
tributary groundwater and applies the surface water appropriation rules
to tributary water. Nontributary water is catalogued in designated
groundwater basins for administration by a special commission. 32 A
permit from this commission is necessary before a well may be drilled
in a designated groundwater basin. The commission must deny the permit
if there are no unappropriated waters in the basin, or if the proposed
673
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appropriation would unreasonably impair existing water rights from the
source or would create unreasonable water waste.133
Wyoming law designates certain groundwater areas as "control
areas" where any of the following circumstances exist:134
• The use of underground water is approaching a use equal
to the current recharge rate.
• Groundwater levels are declining or have declined
excessively.
• Conflicts between users are occurring or are
foreseeable.
• The waste of water is occurring or may occur.
• Other conditions exist or may arise that require
regulation for the protection of the public
interest.
If there is an inadequacy of water in the designated control area, the
state engineer may close the area to further appropriation, apportion
a measured amount among the appropriators, shut down or reduce with-
drawals by junior appropriators, specify a system of rotation of use,
and for future permits—if any are granted—he may institute well spac-
ing requirements. 3S
Montana simply includes groundwater in the statutes that allo-
cate surface streams.136 However, there is administrative power pro-
vided for regulating the construction, use, and sealing of wells to pre-
vent the waste, contamination, or pollution of groundwater.137
A critical factor in the husbandry of groundwater resources is
the "recharge rate"—the rate at which an underground basin replenishes
itself after a given amount of water is withdrawn. In a truly impervious
basin, the recharge rate may be zero. When one withdraws water in this
situation, one is said to be "mining" the water resource. Like minerals,
once it's gone, it's gone. The term "mining" is also applied to re-
chargeable basins where the rate of withdrawal is greater than the
674
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recharge rate. In this case, the water table lowers, allowing adjoining
waters—which may be contaminated—to flow into the underground basin.
Demand placed on groundwater resources by energy companies has
created political tensions in mineral rich areas. In a move still draw-
ing hostile fire, Wyoming passed legislation providing up to 20,000
acre-ft of groundwater for use by Energy Transportation Systems, Inc.,
(ETSI).*138 ETSI proposes to use the water for a coal slurry pipeline
to carry Wyoming coal over 1,000 miles to power generating stations in
Arkansas. The water is to come from the Madison limestone formation
underlying northeastern Wyoming (and western South Dakota), brought up
by wells drilled to a depth of 3,500 to 4,500 ft. According to the U.S.
Geological Survey, the formation contains from 500 million to 1 billion
acre-ft of water with an annual recharge rate of 100,000 acre-ft. Those
legislators who voted for the measure approving the use of the water
were apparently swayed by the cited recharge rate and by the claim that
the water was highly saline and therefore of little use for other pur-
poses. Both of these factors are now coming under attack. The recharge
rate is under continuing study by the state,* and some Madison formation
water brought up near Gillette, Wyoming, has proved to be of higher qual-
ity than that under present use for municipal purposes.139 The matter
at this point is unresolved, but the situation is illustrative of the
problems faced by all the parties concerned. As a final note, because
the Madison water table (which also underlies South Dakota) may be
detrimentally lowered, South Dakota is contemplating a suit against
Wyoming in the United States Supreme Court to halt the proposed action. 40
*The legislation makes this particular use subject to the approval of
the state engineer.
tSee, for example, "Underground Water Supply in the Madison Limestone,
Wyoming State Engineer's Office, Cheyenne, Wyoming, December (1974).
675
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9. State Action Generally
The power of the states to control the waters flowing through
or underlying their lands, vis-a-vis federal power, is discussed at
length in another section. However, it is worth observing at this point
that the states want as much control as they can get (preferably com-
plete control), and, also, that they will use it. In 1974, the Montana
legislature passed a sweeping three-year moratorium on further water
development in the Yellowstone River Basin. The legislature's statement
3fc I'll
of policy behind the action is as follows:
The legislature, noting that appropriations have been
claimed, that applications have been filed for, and
that there is further widespread interest in making
substantial appropriations of water in the Yellow-
stone River Basin, finds that these appropriations
threaten the depletion of Montana's water resources
to the significant detriment of existing and pro-
tected agricultural, municipal, recreational, and
other uses, and of wildlife and aquatic habitat. The
legislature further finds that these appropriations
foreclose the options to the people...to utilize
water for other beneficial purposes, including muni-
cipal water supplies, irrigation systems, and minimum
flows for the protection of existing rights and aqua-
tic life. The legislature...declares that it is the
policy of this state that before these proposed ap-
propriations are acted upon, existing rights to water
in the Yellowstone Basin must be accurately determined
for their protection, and that reservations of water
within the basin must be established as rapidly as
possible for the preservation and protection of exist-
ing and future beneficial uses.
Accordingly, no applications will be processed for new appropriations or
transfers of use until the three years are up, or until a final
*The moratorium expires in March of 1977.
676
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determination of existing rights has been made.*143 An example oi the
moratorium's effect is provided by the experience of the Intake Water
Company. In an effort to provide 245,000 acre-ft of water for energy
development, Intake proposes to construct a dam on the Powder River in
Montana at a point four miles north of the Wyoming-Montana border.
Twenty-one miles of the 24-mile-long reservoir will lie in Wyoming, but
the proposal must await the passing of the three-year moratorium.
E. Water Requirements for Coal and Oil Shale Development
The water requirements for the production of syncrude and methanol
from coal and syncrude from oil shale are different, but the amount for
both types of production are large. As we have seen, the allocation
of water in the West is a complex subject. Basic to the problem of al-
location is the question of the amount of water that is available. This
section sets projections of water demand for coal and oil shale develop-
ment against available water supplies and their possible augmentation.
1. Syncrude and Methanol from Coal
Just how much water is available for coal development in the
semiarid Northern Great Plains states of North Dakota, Montana, and
Wyoming is an important question because of large water requirements of
some of the processes contemplated for the coal once it is out of the
ground. The alternative processes for coal development are given in
Figure 19-3, along with the location of the processing, whether in-state
or out-of-state. The alternative that requires virtually no water, of
course, is the shipment of mined coal out of the region by train to
*The moratorium does not apply to projects of less than 14,000 acre-ft
capacity.
677
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COAL MINE
OUT OF STATE
COAL CONVERSION
IN STATE
COAL CONVERSION
00
UNIT
TRAINS
SLURRY
PIPELINE
GASIFICATION
LIQUEFACTION
OR METHANOL
ELECTRIC
THERMAL
GENERATION
FIGURE 19-3. COAL DEVELOPMENT ALTERNATIVES, IN-STATE
AND OUT-OF-STATE
-------
water-rich areas for processing. At the other extreme is the alternative
of burning the coal in a power plant located at the mine to generate
electrical power, which would consume large amounts of water for cooling.
The various alternative uses of coal and their associated water require-
ments are shown in Table 19-4.
The likelihood is that the future will see a mix of the various
alternatives, and the availability or nonavailability of water at a given
geographic location at a given price will be a major determinant in what
particular coal utilization alternative is selected. Other factors will
also go into the decision, including population impacts, jobs created,
and tax assessing opportunities for state and local governments.
The major rivers that flow through the Northern Great Plains
all come together to swell the Missouri River. Looking upstream from
Sioux City, Iowa, one sees a net flow (the virgin flow less present day
depletions) of 21,821,000 acre-ft/year. Table 19-5 reveals that, even
in low water years, a net of 5,970,000 acre-ft/year of this water is
available for all future uses—energy development of all forms as well
as agricultural, municipal, industrial uses, and fishing habitat and
wildlife improvement programs.
Projections of the Northern Great Plains Resources Program
for the year 2000 show 41 gasification plants and 19,400 MW of electrical
generating capacity.143 Assuming a consumptive use (no discharge) of
9,500 acre-ft/year of water for each gasification plant and 12,000 acre-ft/
year for each 1000 MW of electricity, the water required for gasification
and electrical power generation in the year 2000 would total about
620,000 acre-ft/year. Water used consumptively to revegetate areas
stripped to provide coal for these uses is estimated at about 31,000
acre-ft/year.146 Projected additional agricultural consumptive use,
based on 1.6 acre-ft per acre, is conservatively estimated at about
679
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O)
Table 19-4
ANNUAL WATER CONSUMPTION FOR VARIOUS COAL USES
Use
Facility Size
Water Required
(103 acre-ft)
Coal
Required
(million tons)
Thermal electric
power generation
Methanol from coal
Gasification
Liquefaction
Slurry pipeline
Unit trains
1000 MW
100,000 B/D
250 million SCF/D
100,000 B/D
25 million tons/year
61 million tons/year
12
15
9.5
*
29
18.8
Negligible
4.5
13
9.5
35
25
61*
Relative Water
Requirement
(acre-lt/million
tons of coal)
2670
1150
1000
830
750
Assumes wet cooling; with dry cooling this figure could be reduced to about 12,000 acre-ft.
The exact capacity of a system of unit trains has not been determined. The analysis assumes
61 million tons of coal could be exported by unit trains in the tenth year.
Source: References 143 and 144, and Table 4-5, Chapter 4.
-------
Table 19-5
UPPER MISSOURI RIVER BASIN WATER AVAILABILITY AND DEPLETIONS
Average Year Critical Year
(103 acre-ft) (103 acre-ft)
Historic flow1 28,321
Depletions for past use3 6,500
Water supply available after 1970 21,8213 14,200s
Indian requirements in Montana and Wyoming4 2,637 2,637
Committed to authorized Bureau of Reclamation projects5 1,293 1,293
Remaining water subject to Indian claims6 17,891 10,270
Suggested water quality control required on main stem7 4,300 4,300
Available for additional development by Indians and non-Indians8 13,591 5,970
128,321,000 is an estimated value of long-time (1898-1972) average annual flow at Sioux City, Iowa, prior to any water development in the
... basin above Sioux City. It was derived from streamflow records adjusted for known and reported developments throughout the upper basin
00 and the measured and estimated depletions associated with those developments.
1-1 2Above Sioux City 6,500,000 is a composite of water depletions for all projects in operation in 1970. Estimates include irrigation, im-
ports, exports, land treatment measures, stockponds, rural domestic uses, evaporation from major impoundments, minerals, and mining,
industrial, and municipal uses. It represents water currently consumed and no longer available to meet additional future needs.
3A measure of the expected average annual water production between 1898-1972 repeated, but with current uses accounted for. It is equal
to the historic flow less all depletions for 1970 level of development.
4Compiled from inventories of land and water by consulting engineering firms under contract. Refinement in these preliminary numbers will
evolve as studies continue. (Indian water requirements do not necessarily define Indian water rights.)
sCongress has authorized six units to be constructed by Bureau of Reclamation in the basin under the Pick-Sloan Missouri Basin Program.
They are in the construction or preconstruction stage. The expected depletions above Sioux City for authorized projects total 1,293,000
acre-ft from Garrison, Oahe, and O'Neill Units.
6These figures are the residual flows after subtracting projected Indian claims in Montana-Wyoming and committed waters of authorized
Bureau of Reclamation units from the water supply available as of 1970 level of development. These totals represent water available for
further development in the Dakotas and is subject to the undetermined paramount rights of Indians in the Dakotas, for which land, and
water inventories have not begun.
74,300,000 acre-ft is the annual equivalent of 6000 cubic ft/s currently thought to be the flow between and from main stem reservoirs
required for recreation, flow maintenance, public health, and water quality control.
8These figures represent average and critical year water quantities available for future development in the Dakotas if water quality con-
trol flow requirements are maintained, and the demands listed in 4 and 5 are met.
3This value is an estimate derived from a recent operations study of the main stem reservoirs at 1970 development level. That study de-
termined that water quality control could be maintained and also allow 9,900,000 acre-ft annually as the additional tolerable depletions
which the system storage could accommodate. 14,200,000 is the sum of 9,900,000 and 4,300,000.
Source: Reference 14.
-------
1,900,000 acre-ft/year for the year 2000.
147
Fishery habitat and wild-
life improvement programs could consume about 320,000 acre-ft/year.148
These consumptive uses are totaled in Table 19-6.
Table 19-6
PROJECTED ANNUAL CONSUMPTIVE USE OF WATER
FOR THE YEAR 2000—NORTHERN GREAT PLAINS STATES
Use
Gasification and electric
power generation
Revegetation
Municipal
Agricultural
Fishery habitat and wildlife
improvement
Total*
Water
(103 acre-ft/year)
620
31
14
1900
320
2890
*Total does not add due to rounding.
In addition to these projected uses are the syncrude and
methanol water demands projected by the maximum credible scenario for
the year 2000, shown in Table 19-7. The sum of these state demands is
the total competing water figure for syncrude and methanol production
(last column, Table 19-7).
682
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Table 19-7
SYNCRUDE AND METHANOL CONSUMPTIVE WATER DEMANDS FOR THE YEAR 2000
State
Wyoming
Montana
North Dakota
O Total^
00
CO
Number of
Liquefaction
Plants
13
11
0
Water for
Liquefaction
Plants*
(103 acre-ft/yr)
377
319
0
Number of
Methanol
Plants*
13
10
21
Water for
Methanol Plants*
(103 acre-ft/yr)
195
150
315
Number of
Coal Mines to
Support Those
Plants*
81
66
76
Water for
Coal Mines*
(103 acre-ft/yr)
12
9.9
11.4
Total
Water Needs
(103 acre-ft/yr)
584
479
326
1390
*Plant size and resource requirements from Tables 6-3, 6-6 (Chapter 6).
tTotal does not sum due to rounding.
-------
The sum of all these competing uses must then be compared to
the earlier available water figure of 5,97 million/year.
103 acre-ft/year
Demands other than syncrude
and methanol 2890
Syncrude and methanol 1390
Total 4280
The conclusion is that there is enough water available in the upper
Missouri River system to support the maximum credible scenario for syn-
crude and methanol production in that region while still meeting projec-
tions for all other demands.
This conclusion is not entirely valid, however, because the
geographical distribution of the water is not coincident with the dis-
tribution of the coal resource. Typical of this situation is the Powder
River Basin of northeastern Wyoming and southeastern Montana where the
maximum credible scenario has sited the major coal effort for these
states. This area is extremely coal-rich and markedly water-poor. One
of the water facts of life of the entire region becomes very clear very
quickly; the flows in the rivers are seasonal, ranging from a maximum in
the late spring to a minimum (in some cases zero) flow in the late summer
and fall, as illustrated by the historic Yellowstone River Basin flows
shown in Figure 19-4. To control flooding at times of high flow and to
provide water for release in dry seasons, the storage reservoirs listed
in Table 19-8 have been constructed on many of the region's rivers. The
prime impetus for their construction was to provide a reliable source of
water for irrigation of agricultural land in the dry season. Some of
these existing storage areas could, perhaps, be tapped to provide water
684
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Table 19-8
MAJOR RESERVOIRS THAT AFFECT STREAM FLOWS IN THE NORTHERN GREAT PLAINS
Storage (thousand/acre-ft)
Stream Reservoir
Missouri Fort Peck
Lake Sakakawea
Oahe
Milk Nelson
Clarks Fork Cooney
Wind-Bighorn Bull Lake
Pilot Butte
00 Boysen
01 Buffalo Bill
Bighorn
Upper Sunshine
Lower Suhsine
Powder Lake DeSmet
Tongue Tongue
Heart Dickinson
Heart Butte
Grand Bowman-Haley
Shadehill
Inactive
and Dead
4300
5000
5500
18.7
0
0.7
5.4
252.1
48.2
502.3
1.0
1.9
0
5.9
1.2
6.8
4.3
58.2
Active
10,900
13,400
13,700
66.8
24.4
151.8
31.5
549.9
373.1
613.7
52.0
54.9
239.0
68.0
5.5
69.0
15.8
30.0
Flood
Space
3700
5800
4300
—
—
—
150.4
259.0
—
—
—
—
—
150.5
72.9
269.6
Total
18,900
24,200
23,500
85.5
24.4
152.5
36.9
952.4
421.3
1,375.0
53.0
56.8
239.0
73.9
6.7
226.3
93.0
357.8
R,
R,
R,
R,
R,
R,
P,
R,
R,
R,
FC,
FC,
FC,
Irr.
Irr.
Irr.
Irr.
FC,
Irr.
FC,
Irr. , S
Irr., D
R,
R,
R,
R,
R,
R,
Uses*
Irr. , N, P, M, I
Irr., N, P, M, I
Irr. , N, P, M, I
Irr., P, M, I
, P
Irr. , P, M, I
, D, I
, S, P, I
Future Industry
Irr.
Irr.
FC,
FC,
FC,
, M, I
, M, I
Irr. , M, I
M, I
Irr.
*R - recreation (includes fish & wildlife), FC - flood control, Irr. = irrigation, N = navigation,
P = power, M = municipal, I = industrial, S = stockwater, D = domestic.
Source: Reference 149.
-------
I-
o
u
cr
CO
Q
<0
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230
MO
190
170
ISO
140
130
110
90
70
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Mil. FEi. MAD. AW MAT JUNE JUIV AUG. SEP OCT NOV DEC
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190
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150
130
110
90
70
50
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20
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' JAN. FEB MAR APR MAY JUNE JULV AUG. SEP. OCT NOV OEC.
2.300
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. § g 8 § § 8 s 8 8 '!
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Ml. FEI MAR. APR MAY JUNE JULY AUG S(P OCT. NOV DEC
2.300
2.100
1,900
o ' 70°
t '.500
UJ ' t00
5 '.300
"* 1.200
u.
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THOUSAND
! 8 1 8 1 § 1
300
200
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*
/
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Nl
r
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J
VEL
>!ON
1
/
;
i
.ow
EY,
A
n
i
i
i
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1
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rAN
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1
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I
VER
I 194
V
4 19
•--
M .
-S,
^
JAN FEI MAR »PR MAT JUNE JUIT AUG SEP OCT NOV DEC
Source: Reference 144
FIGURE 19-4. HISTORIC YELLOWSTONE RIVER BASIN FLOWS
686
-------
for energy development as described below. Consideration may also be
given to building additional impoundment facilities—with the impetus for
construction this time being the storage of a water supply for the year
around operation of various coal processing plants. The storage develop-
ment potential for rivers close to the Gillette, Wyoming, coal resource
focal point is not impressive vis-a-vis the projected amounts of water
needed. Table 19-9, which is a summary of surface water resources avail-
able or subject to development, shows that the Powder River and Tongue
River reservoirs could only provide a total of 131,000 acre-ft/year, far
short of Wyoming's projected need of 584,000 acre-ft/year for syncrude
and methanol. For this reason, major aqueduct pipelines would be neces-
sary to bring in water from the reservoirs listed in Table 19-8. Con-
struction of these water conveyance lines could make it unnecessary to
construct several small capacity (but close-in) reservoirs. Figure 19-5
shows several ways of bringing water from where it is to where it will be
needed. Route 1C could bring up to 135,000 acre-ft/year to the coal
region. Route 1A could transport up to 435,000 acre-ft/year. However,
under the latter alternative, there would not be enough water remaining
for other demands, including the full 6000 cubic ft per second flow nec-
essary to preserve instream values. (See Table 19-5, Note 7.) For this
reason, route IB may be more acceptable in that the diversion is at a
point farther downstream where an equivalent amount of withdrawal would
have a lesser impact because the 6000 cubic ft per second standard would
be met. Another alternative is route 2, which could provide water from
Lake Oahe in South Dakota, although the distance involved would represent
significant pipeline construction costs. This alternative has been chal-
lenged by the state of South Dakota, which insists that Lake Oahe water
should be reserved for future irrigation needs in the state. The South
Dakota Attorney General, William Janklow, has said on this issue, "Let
them try and take that water away from us—they'll need a federal marshal
along every mile if they want to build that pipeline."151
687
-------
01
00
00
_ f — - ^
\
I
NORTH DAKOTA \
""SOUTH DAKOTA/
KEY
Indian Reservation
Generalized Aqueduct
Route
Source '. Reference 75
Sioux Ci ty
FIGURE 19-5. MAJOR POTENTIAL DELIVERY SYSTEMS, NORTHERN
GREAT PLAINS COAL RESOURCE REGION
-------
Table 19-9
SUMMARY OF INDUSTRIAL WATER RESOURCES
FOR THE UPPER MISSOURI RIVER BASIN
Water (acre-ft/year)
Bighorn and Wind Rivers
Boysen Reservoir
Bighorn Lake
Little Bighorn Reservoir
Powder River
Moorhead Reservoir
Hole-in-the-Wall Reservoir
Tongue River
Tongue River Reservoir
Other development with
major storage
Yellowstone River
Main stem (with regulation
by offstream reservoirs,
or Allenspur)
Shoshone River
Modification of Buffalo
Bill Reservoir
Green River
Importation and diversion
Total
Available
Potential
Montana Wyoming Montana Wyoming
85,000
262,000 435,000
50,000
254,000
40,000
57,000 51,000
20,000
60,000
60,000
1,356,000* 344,000*
50,000
108,000
262,000 520,000 1,513,000 937,000
*About 1,7 million acre-ft would remain in the Yellowstone River for
other future development and for minimum flows,
tWyoming's share of Clarks Fork Yellowstone River.
Source: Reference 150.
689
-------
A final alternative would be to take water from the Fontanelle
Reservoir on the Green River over the Continental Divide to the North
Platte River, and then remove it from the North Platte at the place where
the river passes closest to the coal resource. Routes 1A, IB, and 1C
raise the institutional restriction of the Yellowstone River Compact,
which forbids any signatory state (Wyoming, Montana, and North Dakota
are signatory states) from moving water out of one basin into another
(e.g., out of the Bighorn River Basin into the Powder River Basin) with-
out the consent of the other states. Route 2 avoids this problem, but,
as previously mentioned, it is expensive and it invites a hostile re-
sponse from South Dakota. Route 3 avoids the institutional problem in-
asmuch as the Upper Colorado River Basin Compact (the Green River is a
tributary of the Colorado River) does not constrain interbasin transfers.
Removal of this high quality water, however, would exacerbate the salinity
problem of the lower Colorado River states.
Referring to Figure 19-5, Route 4 would provide water from Lake
Sakakawea for the processing of North Dakota coal, and Route 5 would
bring main stem Missouri River water to coal development sites in north-
eastern Montana. These routes appear to have fewer political or insti-
tutional problems associated with them.
South Dakota is also a major factor in one of the options de-
picted in Figure 19-3, the transportation of coal from the Powder River
Basin to distant processing points via coal slurry pipeline. Present
proposals call for obtaining the water for the slurry from deep wells,
which tap into the geologic Madison limestone formation underlying the
Powder River Basin. However, the Madison aquifer, reported as having as
much as 1 billion acre-ft of water, also underlies western South Dakota.
Extensive pumping in Wyoming may lower the water table or cause a drop
in the quality of the water presently being pumped out of the Madison
formation by South Dakota citizens. South Dakota has pledged to go to
690
-------
court to challenge the large-scale pumping envisioned for the coal
slurry pipeline option.151
A number of organizations have begun to plan for the future of
this region in general, and in the utilization of the region's coal in
particular, but there has been no integration of the planning process.
Energy companies are filing plans for construction of small storage
reservoirs that will satisfy their particular water-for-energy needs,
but that, it may be argued, runs counter to the interests of local
citizens with other needs for that water, interests of the state con-
cerned, interests of the region as a whole, and national interests.
2. Syncrude from Oil Shale
The maximum credible scenario projects 20 large (100,000 B/D)
oil shale plants by the year 2000. At a water scaling factor of 16,000
acre-ft/year for each such plant, the total water required for the 20
plants would be 320,000 acre-ft/year. Because the oil shale resource
lies in the Upper Colorado River Basin, this water requirement must be
met from supplies in that basin.
The total water available to the Upper Colorado River Basin
states for all uses is conservatively estimated to be 5.8 million acre-
ft annually.*152 Present uses (including reservoir evaporation) require
3.71 million acre-ft per year.153 Projected increases in annual demand
for the year 2000 are shown in Table 19-10. If the increase in water
demand of 2.75 million acre-ft/year is added to the 3.71 million acre-ft/
year of present use, the total demand for the year 2000 would be 6.46
million acre-ft/year.
*Some figures are as high as 6.3 million acre-ft/year; see Reference 155.
691
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Table 19-10
PROJECTED INCREASE IN WATER DEMAND FOR THE
UPPER COLORADO RIVER BASIN
Category of Use
Municipal
Environmental (fish, wildlife,
recreation, water quality)
Agricultural (primarily irrigation)
Mineral production
Coal fired electric generation
Coal gasification
Syncrude from oil shale
Total
Increase in
Water Demand
(103 acre-ft/yr)
750
150
800
115
475
140
320
2750
Source: Reference 154.
Clearly if there is but 5.8 million acre-ft/year of water avail-
able to the Upper Basin, there would not be enough water under the pro-
jected demand to accommodate all users. A Department of the Interior
study, which projected an oil shale development amounting to only three-
fourths that of the maximum credible scenario, indicates that the water
shortfall will occur in the early 1990s.
156
There is little hope of increasing Upper Basin supplies at the
expense of the Lower Basin. The Lower Basin of the Colorado has committed
its full share of water available to it under the 1922 Colorado River Com-
pact, considering its present demands and projected plans for energy (and
other) development.
692
-------
Although water supplies can be increased through snowpack aug-
mentation (i.e., winter cloud seeding resulting in greater water runoff
in the spring), the estimates of the increase range only from 6 to 9 per-
cent.157 A proportionate increase in the Upper Basin supply would thus
be from 350,000 to 520,000 acre-ft/year—not enough to meet the projected
deficit of 660,000 acre-ft/year.
The allocative formula of the Upper Colorado River Basin Com-
pact of 1948 further demonstrates the foreseeable shortages on an indi-
vidual state basis within the Upper Basin. Under the maximum credible
scenario Colorado's Rio Blanco and Garfield counties experience the bulk
of oil shale development. The 1948 Compact, after allocating 50,000
acre-ft/year to Arizona, gives Colorado 51.75 percent of Upper Basin
water, or 3.00 million acre-ft/year. The Compact operates to require
the water for Colorado's oil shale development to come from its allo-
cated Upper Basin share. The result is that Colorado will experience a
projected water resource shortfall by the early 1990s when the 3.00 mil-
lion acre-ft/year figure of available water will be surpassed by in-state
demand.158
The MCI projects a maximum oil shale development effort in the
Piceance Basin of northwestern Colorado. In the southern part of the
Basin, surface water will have to be transported to the oil shale site.
In the northern part of the basin, close to the White River drainage sys-
tem, a different situation exists. There, groundwater will have to be
pumped at the outset of mining operations to keep the mine itself de-
watered; indications are that this water will be initially of sufficient
quantity and quality for retorting and refining needs, in addition to
meeting water requirements of crushing, mining, and processed shale dis-
-i c Q
posal. Depending on the salinity, the water may also meet drinking
water and sanitation needs.1 ° However, as the water table lowers, the
quality of the pumped water will deteriorate and fewer and fewer
693
-------
productive uses can be made of the water. Thus a twofold problem appears;
excess "unsatisfactory" water will have to be disposed of in a way that
avoids contaminating surface waters and water of a satisfactory quality
will have to be obtained from a surface source to meet the needs of the
operation.
The White River produces about 610,000 acre-ft of water per
year. However, claims on the parts of Utah, other downstream states,
the federal government, and Indians through whose reservations the river
flows—in addition to prior appropriation claims of agricultural inter-
ests—leave little, if any, of this water available for oil shale de-
velopment.161
Even in areas where surface water rights are granted, some
means will have to be provided to transport the water from the source to
the mining operation. Because ice formation in winter would hinder
T c o
transport via canals, buried pipelines appear to be necessary. At-
lantic Richfield, e.g., has filed for 50,000 acre-ft/year of White River
water, proposing to transport the water 36 miles through a 48-inch diam-
eter pipeline.163
Oil shale developers have also filed water claims for Colorado
River water, seeking to pump the water over the Book Cliffs to the Pi-
ceance Creek drainage area. It has been pointed out that this would be
a very expensive lift system.164
To illustrate the degree of the allocation problem, the total
claims made on Colorado River water flowing near the oil shale resource
165
area exceed the entire flow of the river during some seasons.
If the allocative dilemma is resolved, the magnitude of the
demand forecast makes it clear that for White River and Colorado River
water to be available for year around oil shale operations, additional
water development projects will be necessary to store the disproportionate
694
-------
spring flow; in the spring, 60 percent of the White River's annual flow
occurs in 120 days.
There is a continuing investigation into the method of syncrude
production from oil shale by in situ processes in which the shale is
mined and crushed underground through blasting and is then retorted in
place. The raw shale oil product is pumped out for further processing.
From a water standpoint this process is particularly attractive because
total water needs are thought to be about one-fourth those of "conven-
tional" processing.167 (Water savings result because shale does not have
to be wet down or slurried in the mining, crushing, or retorting phases
of the operation; moreover, because the process takes place underground,
there is no need for dust control, or for compacting spent shale in the
disposal phase, which is the most water intensive aspect of all. )
However, the in situ process is considered to be in an experimental phase
and it is not clear that it will ever be a viable alternative to present
water intensive processes.169 f
Assuming that the forecasts are accurate and that the predicted
shortfall does occur, the answer will be to increase the water supply and/
or to reconsider from an institutional point of view where the available
water supplies should go. It has been pointed out that snowpack enhance-
ment to augment spring runoff water will ease the problem but will not
solve it. Interbasin transfers, e.g., from the Columbia River, are costly
and politically unpalatable. More efficient agricultural methods will
save some water, but state laws which operate to encourage the profligate
use of a water right will have to be changed. The market transfer of
water rights from agricultural use to energy development use is possible
if laws unfettering such transfers are implemented (see Section D). It
will be important to do this in a knowing way so that the desired amount
of agriculture production is preserved. If freely spent "energy" dollars
buy up all of agriculture's water rights, land reclaimed through Bureau
695
-------
of Reclamation projects and irrigation over the years will revert to its
original condition. This will, of course, have a profound effect on the
local society, which developed as an "agricultural culture." Because
such decisions have both a regional and national character to them, as
well as a profound local impact, some kind of mechanism will be neces-
sary to make intelligent choices for all concerned.
F. Coal Transport: Pipeline versus Rail
There are going to be hard choices in the coal-rich states on the
Northern Great Plains concerning the best use of their precious water
resources. Because coal-burning electric power plants and coal conver-
sion technologies such as gasification and liquefaction are water inten-
sive processes, serious consideration is being given to transporting the
coal out of the region for use or processing in locations with sufficient
water resources.
There is great demand for coal at long distances from western coal
fields. For example, utilities in Texas and Arkansas, hard-pressed by
oil and gas shortages, and eastern utilities, faced with clean-air con-
straints on the use of high-sulfur eastern coal, are interested in having
western coal carried to their boilers for electric power generation.
The question is how best to transport the huge quantities of coal.
The two practical alternatives are transport (1) by railroad, and (2) by
coal slurry pipeline.
The policy of the United States is to move away from dependence on
foreign oil. To that end, the U.S. Senate in 1974, passed a bill calling
for all oil-burning electric power generating plants to convert to coal.
An amendment to that law, sponsored by Senator Henry Jackson (D. Wash.),
precipitated the present debate over railroads versus coal slurry pipe-
lines. The amendment proposed to give to slurry pipeline companies the
696
-------
federal power of eminent domain, whereby the pipeline companies could
acquire the necessary rights-of-way to lay the pipe from coal producing
areas to the consumer. The measure died in the House of Representatives
of the 93rd Congress for want of time. Reintroduced in the 94th Congress,
it was referred to the Committee on Interior and Insular Affairs, where
it remains with little likelihood of being brought to the floor.*
1. Coal Slurry Pipelines
In a coal slurry system, coal at the mine mouth is pulverized
into particles as fine as or finer than ground coffee. The resultant
powder is then mixed with water in a one-to-one ratio with water pro-
ducing a slurry with the consistency of cream. This coal slurry is
pumped through a pipeline, which is laid underground and which surfaces
at pumping stations located at about one-hundred-mile intervals. At its
destination, the slurry is "dewatered" (usually by centrifuge). The
transport water can be used as "make-up" or cooling water in a liquefac-
tion, gasification, or power generating plant operation.''" In an electric
power plant, the moist powdered coal is readily usable by the boilers.
Coal slurry pipelines are not a new idea. In London in 1914,
a short pipeline of 1950 ft served to transport coal from Thames River
barges to a nearby boiler plant. In 1958, a 108-mile coal slurry pipe-
line was built to move coal from the Ohio coalfields northward to Cleve-
land. In full operation, that line carried over one million tons of
coal per year. There is a 273-mile pipeline currently carrying five
*Private communication.
tSlurry water must be treated before plant use at the delivery end. How-
.ever, the cost of the energy product is relatively insensitive to this
added expense.
697
-------
million tons per year from a Peabody Coal Company mine in northeastern
Arizona to a steam plant in southern Nevada. This line, known as the
Black Mesa pipeline, is owned by the Southern Pacific Transportation
Company.
There are many attributes of a coal slurry pipeline transport
system that have gained it attention:
• The pipeline is underground, and is therefore
- Environmentally unobtrusive
- Relatively invulnerable to damage
- Not affected by severe weather or low ambient
temperatures.
• The pipeline is extremely reliable.
• The pipeline can follow a straight path through steep and
rugged terrain.
• Pumping stations are run on electricity, which can be
generated by domestic coal.
• Operation is not labor intensive (a factor that means
both limited vulnerability to labor disputes and lim-
ited exposure to inflation escalation).
• The coal slurry mixture is nonflammable (an obvious
safety feature).
• The coal can be washed of unwanted impurities during
slurry preparation.
A coal slurry pipeline gains still more attention when it is
compared with coal carriage by rail:
• For an equal amount of coal, a pipeline consumes 20
1 *7 f}
percent less energy than rail transport.
• Rail transport requires increasingly precious petroleum
to power the diesel locomotives.
• Land dedicated to rail lines is not usable for other
purposes (compared with the restored land over a buried
pipeline).
• There is a lower product loss with the pipeline.
698
-------
• There is a higher industrial injury/death rate per
ton-mile for movement by rail.
• A rail line typically must traverse a 10 percent or
more greater distance in reaching the consumer (be-
cause of accommodations made for terrain).
• Subject to economies of scale, it is significantly
cheaper to move coal by pipeline.
For the proposed 1000-mile coal slurry pipeline from the Powder River
Basin in Wyoming to Pine Bluff, Arkansas, the savings over rail are
estimated at one-third to one-half, or $14 billion over a 30-year
period.
2. Railroad Transport of Coal
The response by the railroads to the challenge of the coal
slurry pipeline has been both defensive and competitive.
The defensive arguments are fundamentally ones of survival:
"Whatever benefits may be found in the slurry pipeline are greatly out-
weighed by the price to be paid through the weakening of our railroad
system." 73 There is concern that "...the cream will be skimmed from
the railroads' business leaving the remaining customers with the very
real prospect of wholesale abandonment of lines no longer economically
viable."173 There is fear that loss of coal traffic of nearly-bankrupt
eastern railroads to slurry pipelines will be the final blow to the
survival of the railroads.
* ...or fourteen billion dollars our customers need not and would not
pay through their monthly electric bills."171 (These are apparently
dollars current to the year the expense is incurred; and this figure is
also apparently not discounted to a present value.)
699
-------
On the competitive side, the railroads claim they are ready
now to handle greater coal traffic; that long-term coal carrying con-
tracts spurred by energy demands will enable the railroads to attract
the investment capital needed to build new hopper cars and new, heavy-
duty locomotives, and to repair trackage and roadbeds showing wear. The
railroads boast of the "pipeline-like" unit trains, which may consist of
more than 100 high-capacity coal cars with an individual weight of as
much as 110 tons, made of lightweight aluminum to maximize the payload.
The unit train is indeed a major cost-saving advance from traditional
single-car shipments in mixed trains. High-horsepower locomotives pro-
vide the power for the mile-long string of hopper cars, loading at one
point of origin and unloading at a single destination. To make the unit
train cost-effective, long-term contracts of 10 years or more, large-
volume shipments per train and per year, and a single destination are
all necessary.174'175
Outside railroad circles, there is concern that (1) the rail-
roads cannot, in fact, handle the prospective increased coal-carriage
even with extensive roadbed rebuilding and great investment in new equip-
ment and (2) that an all-out carriage effort would be at the expense of
impaired movement of other freight and passengers.1
3. Critical Factors
The proposed large-volume transfers of coal from western pro-
ducing areas to major consumers would appear to represent a shining op-
portunity for the operation of unit trains. In fact, Montana went from
near zero unit-train shipments in 1968 to 7.7 million tons in 1972. The
1972 figure represents 94 percent of the coal shipped out of the state.
But the vast coal movements contemplated raise questions even for the
acclaimed unit train. The proposed Wyoming-Arkansas slurry pipeline is
designed to move 25 million tons per year to a single destination. Taking
700
-------
into account the empty return trip for the railroad alternative, this
corresponds to 20-unit train trips per day. On the delivery route, the
constant flow of high-payload trains could cause serious roadbed mainte-
nance problems. Any down-time for maintenance would cut into the sys-
tem's reliability.* In the words of one utilities executive, "...this
is what concerns (the utilities): the capability to deliver continuous,
I I "1 rj o
reliable service... By way of contrast, the reliability of the Con-
solidated (Ohio) slurry pipeline was 98 percent, and that of the Black
•1 ty Q
Mesa pipeline, 99 percent.
The railroads make the point that slurry pipelines use scarce
western water to carry the coal through the pipe. The Wyoming to Arkan-
sas line will use 15,000 to 20,000 acre-ft per year. The pipeline people
respond with the observation that the water used will be saline water
from deep-water wells (3500 ft to 4500 ft) drilled into the Madison
geologic formation which, according to the U.S. Geological Survey, con-
tains from 500 million to 1 billion acre-ft of water with an annual re-
charge rate of 100,000 acre-ft.' The salinity, and the cost of the water
as a result of drilling, make it unattractive for competing purposes. By
way of rejoinder, the pipeline supporters point out that if trains were
to carry the coal foreseen in the projected doubling of coal output by
*Under a combination of restrictions including maintenance, classifica-
tion, and scheduling, "...the average freight car moves both loaded and
empty, only 56 miles a day."
tThere is dispute as to the salinity issue and as to the recharge ratio
on this Madison formation water. One drilling near Gillette, Wyoming,
brought up water with a saline concentration of only 500 parts per
million (ppm), better quality water than that presently being used for
municipal purposes in Gillette. The recharge rate is under continuing
investigation. (Telephone interview with Mr. Paul Rechard, Department
of Water Resources, University of Wyoming, Laramie, Wyoming, March 12,
.1975. )17£
701
-------
1985, the locomotives would burn an additional 2.5 billion gallons of
diesel fuel per year.*176
Another resource issue is the competing demand for steel rep-
resented by these two modes of energy transport. The buildup of each
mode would require large amounts of steel.''' The proposed Wyoming-
Arkansas slurry line, for example, calls for 460,000 tons of steel.
Whatever comparative railroad figure is used, it must include the cost
of replacing cars, locomotives, and track worn out during an equivalent
30-year operating period. An electric utility spokesman has put that
figure at 795,000 tons of steel.180 The Project Independence Blueprint
study made the point that the overall projected railroad need of 16 mil-
lion tons of steel compared closely with the figure needed for all-out
pipeline construction and therefore, it concluded, "...for the critical
investment and construction items there is in general little basis to
choose between the modes."176 However, this does not take into account
the multiple-use character of railroads. Not that coal cars can be used
for other purposes, but rather that (1) an increased trackage network
with well maintained roadbeds could support increased freight car and
passenger car traffic, and (2) the business boom experienced by the rail-
roads through coal-related growth might allow the fiscal flexibility to
respond to other freight and passenger demands.
*The coal liquefaction scenario (Chapter 6) scale factors show that if
the locomotives were powered by synthetic fuel derived from coal, this
would require 33 million tons of coal per year.
tHowever, the percentages are not overwhelming vis-a-vis other U.S. com-
peting steel demands. Of the 111 million tons of steel produced in the
U.S. in 1973, 3.2 million tons went to rail transportation and 0.85
million tons went into the manufacture of pipe for pipelines.
702
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The "all of one or all of the other" approach taken so far for
the sake of comparing the two modes has served to highlight their attri-
butes, shortcomings, and important differences. As will be argued later,
the more likely approach involves a well reasoned mix of the two modes
to meet the nation's needs.
4. Eminent Domain for Pipeline Right-of-Way
Before reasoning the mix, one is faced with the essence of the
Jackson amendment: providing the slurry pipeline companies with the
federal power of eminent domain. Acquisition of a right-of-way is a
matter of settled law. If one wishes to traverse another's private
property, one must negotiate with the owner and strike a bargain. If
accord is reached, a document is drafted, executed, and in many states,
recorded as a kind of property right: right-of-way across another's
land by virtue of and for the purposes stated in the agreement. Of
course, the seeker of the right-of-way can make an outright purchase
of the property if that is desirable, or if that is the only alterna-
tive. Right-of-way across public lands may be a matter of negotiated
fee or of legislative grant , where a public purpose described in law is
accommodated. In dealing with an owner of private property, that owner
can thwart the progress of right-of-way attainment by refusing to bar-
Rain. Thus, for example, wherever the proposed route crosses the pri-
vate property of a railroad, the railroad might well refuse to negoti-
ate. The likelihood of impasse becomes clear in the proposed Wyoming-
Arkansas slurry pipeline, which would cross railroads at 44 points.
*A right-of-way across private grounds may also be acquired by prescrip-
tive easement; i.e., through long-term, undisturbed use. In the large-
scale operation contemplated, however, such an accomplishment is unlikely.
t.Since the pipeline company represents head-on economic competition to the
railroads, this is to be expected.
703
-------
Consistent with the Fifth Amendment to the U.S. Constitution, individual
states and the federal government have the power to grant the right of
eminent domain to pipeline companies when just compensation is paid, and
where the taking is in the public interest. There are statutes in many
states giving to oil and gas pipeline companies the power of eminent
domain for the purpose of securing rights-of-way within that particular
state for the building, maintenance, and operation of their pipelines.
These statutes also proffer the right to construct the lines along or
across public highways, railroads and streams, and across public land.
Federal legislation permits the Secretary of the Interior to grant ease-
ments of way for oil and gas pipelines over public lands of the United
States, and over Indian lands.182'183 The federal power of eminent
domain is given to natural gas companies,184 and during the Second World
War (and through 1947), it was given for the construction of oil pipe-
lines.185
Organized, vehement opposition by the railroads would very
likely thwart a state-by-state effort by the coal slurry pipeline pro-
ponents to secure reasonably consistent eminent domain authority. Each
state would have different strings attached to its grant of the power,
even if the power were granted. Railroad opposition to petroleum pipe-
lines starting back in the 19th century is enlightening on this point.
5. Railroad Opposition to Pipelines
In 1846, the first successful oil pipeline was built of two-
inch wrought iron pipe. It covered a distance of five miles from Pit
1 ft 6
Hole, Pennsylvania, to the Miller Farm railroad station. The
* See, e.g., Reference 181.
704
-------
railroads favored these lines, which fed oil from drilling areas to
railroad loading racks for rail transshipment. As the pipelines ex-
tended to greater distances, cutting into railroad oil-carrying business,
the railroads refused to allow them permission to cross their tracks.
To remedy the situation, the Pennsylvania and Ohio legislatures, in 1872,
passed laws granting pipelines the power of eminent domain in their ac-
quisition of rights-of-way. Thus, the pipelines could, by law, cross
under the railroad tracks. The success of the oil pipelines was clear
and convincing: the railroads were forced to reduce their rates.
In 1958, the Consolidated Coal Company's coal slurry pipeline
was put into operation, carrying over one million tons per year from the
Ohio coal fields to utilities in Cleveland. When this pipeline was
opened, railroad coal-carrying rates were $2.63 per ton, rising later
to $3.47 per ton. The successful operation of the pipeline resulted in
ski ft 7
a reduction in railroad rates to $1.88 per ton.
The success of this pipeline led to a proposal in 1959 to build
a coal slurry pipeline from West Virginia to eastern seaboard generating
plants. The proposal was never implemented because of railroad opposi-
tion to efforts at obtaining rights-of-way from the state legislatures
concerned.
The next efforts were made in Congress where, on March 21, 1962,
bills were introduced simultaneously into the House and Senate to confer
T o Q
the federal power of eminent domain on coal slurry pipeline companies.
The bills died, as a result of intense, organized railroad opposition.
*It has been asserted that this pipeline success created the impetus for
~L Q Q
the railroad introduction of the unit train concept.
705
-------
6. Pipeline Regulation
Coal slurry pipelines, as do the railroads, come under the con-
trol of the Interstate Commerce Commission (ICC) by virtue of Section 1
of the Interstate Commerce Act.190 As such, the pipeline companies, once
operating, must maintain reasonable rates, avoid discrimination, file
tariffs of rates and charges, submit to regulations of rates, "...and
otherwise conduct their business in the manner of a federally regulated
common carrier."191 The Black Mesa Pipeline Company files its reports
with the ICC and is regulated by the ICC. However, pipelines operating
strictly intrastate engaged solely in transporting wholely owned coal to
wholely owned storage or processing facilities would not come under ICC
regulation.198
7. Pipeline Impact on Railroads
To better understand the relative impact of slurry pipeline
competition on the railroads, a look at some statistics may be helpful.
In 1974 western railroads carried 15.5 percent of the nation's total
coal carried, while eastern and southern railroads carried 84.5 per-
cent.193 Burlington Northern, by far the largest coal-carrying western
railroad, carried 4.7 percent of the nation's total-coal-carried, while
owning 5.3 percent of the nation's hopper cars. The second ranking
western railroad, Union Pacific, carried 1.9 percent of the nation's
coal, while owning 2.4 percent of the nation's hopper cars. By re-
gional comparison, the eastern leader, Penn Central, carried 14 percent
of the nation's total, while owning 16.5 percent of the nation's hopper
cars. In the category of coal-carrying, Burlington Northern and Union
Pacific (the West's largest coal carrying railroads) rank sixth and
thirteenth, respectively. In ownership of hopper cars owned, they rank
sixth and tenth, respectively.
706
-------
Figure 19-6(d) illustrates that the overwhelming concentration
of major coal-carrying rail lines and linkages lies in the eastern half
of the United States.
Coal has not been the major factor in development of western
railroads, whereas for some eastern railroads, coal accounts for as much
as 50 percent of their business. Thus, for the most part, western rail-
roads would be losing potential coal-carrying business to a competing
coal slurry pipeline, whereas eastern railroads could lose both potential
and existing coal-carrying business. Loss of that existing coal traffic
could mean bankruptcy for the marginal eastern railroads. It happens
that the proposed major coal slurry pipelines (e.g., Wyoming to Arkansas;
Colorado to Texas) lie predominantly in the western half of the United
States. And the paths of the proposed lines appear not to strike a
redundant path with existing rail lines.
Because, as Figures 19-7(a) and (b) show, moderate-volume,
short slurry pipelines are less economically competitive, there is pro-
portionately less economic demand in the eastern sector to construct
pipelines. In addition, eastern pipelines would most likely strike a
redundant path with existing rail lines of the fiscally strained eastern
railroads. This is because of the high density of eastern coal-carrying
rail lines, as illustrated in Figure 19-6(d).
8. Proposed Resolution
The slurry pipeline/railroad tension may be viewed from two
public policy standpoints. On the one hand, slurry pipeline technology
should be immediately utilized:
"Growing efficiency in transportation requires that new
technological opportunities be seized promptly. With a
constantly changing technology, the lag between average
practice and the best possible practice is critical....
707
-------
a. Location of Major Coal Deposits
EXISTING
PROPOSED
b. Existing and Proposed Coal-Slurry-Pipelines
FIGURE 19-6- COAL DEPOSITS IN RELATION TO
TRANSPORTATION FACILITIES
708
-------
c. Major Western Coal-Carrying Railroads
d. Major Eastern Coal-Carrying Railroads
FIGURE 19-6. Continued
709
-------
INCLUDES SLURRY PREPARATION
100
200 500 1,000
DISTANCE-miles
2,000
a. Coal-Slurry-Pipeline Transportation Costs
3.U
4.5
-c 4.0
S
JC
~£ 3.5
i
>• 3.0
<•>
or
Ul
5 2.5
2.0
1 fS
1,00
\
\
3-MILE
V
\
1
TRANSPORT DISTANCE
1973 COST BASIS
UNIT 1
a>0.6«/
'
>SPI
RAINS -
Ion-mil*
:OAL
CELINE
^
^
12 15 18
10° TONS PER YEAR COAL
b. Coal Energy Transmission
Source: Reference 195
FIGURE 19-7. ECONOMICS OF COAL SLURRY TRANSPORTATION
710
-------
Prompt adoption of new technological opportunities
enhances the returns to the public...from private
initiative in innovation."*194
On the other hand, this kind of efficiency must be contrasted with the
broader purposes served by governmentally preserving and supporting a
multiuse rail service (passenger movement, freight movement, defense
network) that might otherwise die in a pure, free market setting. Thus,
in light of the need to consider these dimensions, while at the same
time seeking to meet the nation's energy needs, eminent domain power
might be granted only in cases where (1) the economics of a pipeline are
attractive compared with other transportation alternatives, (2) construc-
tion would not strike a redundant path with existing rail lines, and
(3) operation of the slurry pipeline would not result in an economic
death blow to a neighboring railroad coal hauler. In the same spirit
and form of the proposed Jackson Amendment, this additional formula
would be applied by the Secretary of the Interior prior to his author-
izing the exercise of eminent domain power by a particular project.
*Ironically, these remarks were directed at encouraging expanded use of
the unit train concept.
t"The power of eminent domain granted pursuant to this title shall be sub-
ject to regulations promulgated by the Secretary of the Interior to in-
sure that the exercise of such power by a carrier is compatible with the
public interest. Said regulations shall require that, prior to the ex-
ercise of any carrier of the power of eminent domain, the Secretary
shall find...that the project—
(1) would help meet national needs for coal utilization;
(2) is superior to available alternate means of transportation of coal;
(3) may be impeded or delayed unless granted the power of eminent
domain; and
(4) involves no significantly greater disruption to the environment
than other modes of transportation or utilization of the coal
, , "136
resources involved.
711
-------
It may well be that the projected doubling of coal production
by 1985 will create considerable coal-carrying and other business for
all railroads even as slurry pipelines are built. For example, railroads
will handle short hauls to liquefaction, gasification, and power plant
facilities; unit trains will be used to haul western coal to intermodal
transfer points on waterways, such as Duluth, Minneapolis-St. Paul, and
HC
St. Louis; general growth in the Rocky Mountain and Northern Great
Plains states will be reflected in increased general freight revenues;
and finally, increased coal-carrying business by eastern railroads may
take them far enough along economically that consideration can be given
to increasing slurry pipeline construction through an easing of eminent
domain restraint.
G. Summary
The Western water problem is centered around the oil shale region
located principally in the Piceance Basin, in the Upper Colorado River
Basin, and coal-rich Powder River Basin of northeastern Wyoming and
southeastern Montana. The following are major issues in both regions:
* Available water supply and augmentation potential
* Competing demands and their alternatives
* Projected energy development
* Energy development alternatives
* Federal control or influence
* Indian water rights
* State laws and interests
* Interstate river basin compacts
*Burlington-Northern studied slurry pipelines for possible use from the
Great Plains coal area to Duluth and St. Louis for intermodal transfer
to barge transportation. Their study rejected the idea in favor of
1 9 "7
movement of the coal by rail.
712
-------
1. Water Availability
Irrespective of institutional factors which may inhibit a
given water-seeker from securing the water he needs, nature provides a
limit in terms of the annual precipitation. In the coal-rich Northern
Great Plains region, from a total quantity standpoint, there is probably
enough water to support a major coal development effort—including
coal liquefaction and methanol production. However, the coal and the
water locations are not congruent. As a result, the coal will have to
be transported to the water, or water will have to be brought to the
coal by aqueducts combined with water storage facilities.
*
In the oil shale region of Colorado, projected real water
uses will consume all the available annual precipitation. Thus, for
maximum oil shale development, water would have to be shifted from
other demands to oil shale development.
2. The Federal Interest
The federal government has a complex role in the water area.
Because it has claims to water to support the land which it owns (50
percent of the land of the western states), it is a disburser of water
from reclamation projects, and it has broad constitutional power to
control (if it sought to exercise it) the allocation of virtually all
the nation's water. These latent powers overshadow state and private
water-use decisions. The federal government is also the promise-keeper
for the Mexican Treaty of 1944, which promises 10 percent of the
Colorado River's annual flow to Mexico in perpetuity.
As distinguished from "paper" water rights, which are claimed but not
used.
713
-------
3. Indian Water Rights
Indian claims to western water also present a serious issue.
Indian water rights extend at least as far back as the time of the
various treaties forming the existing reservations. Unfortunately, the
amounts of water under these Indian rights are generally in dispute,
and it appears that separate court proceedings will be necessary to
determine the amounts in each case. Finally, Indian claims are clearly
not subject to the law of the states in which the reservations lie.
4. State Water Laws
Neither the federal power over water, nor Indian water rights
is subject to state control. If the federal power were fully exercised,
the states would be preempted and left with no allocative powers except
those given them by the federal government.
In the absence of federal exercise of that sweeping power, the
states have developed varying systems to apportion their water. The
humid eastern states rely on the riparian doctrine of water law, inher-
ited from England, by which lands bordering streams have the right to
use the flowing water subject to the considerations of downstream users.
The water-poor western states developed the appropriation doctrine,
which awards water to the individual who diverts the water from the
stream for a beneficial use, and in the event of water shortage, the
water right secured earliest in time prevails.
Wyoming has a permit system to help keep records of water
rights. Colorado has recently introduced a recordation mechanism, but
not before more water rights were established than there is water in
the rivers of the state. Montana' s concern over who would get what
amounts of water, and for what purposes, caused it to establish a
three-year moratorium, to expire in 1977, on the issue of new water
714
-------
rights.
A significant problem in the state law area in terms of water
for energy development is the transferability of a water right. The
degree to which a water right can be bought and sold, the degree to
which the purpose of the water right can be changed (e.g., from agri-
cultural use to energy development use), time restrictions on when the
water can be taken (e.g., agricultural needs are typically summer needs
while energy development needs would be year around), restrictions on
the point of diversion and the point of application of the water (in-
cluding the interbasin transfer problem), and the advisability, from
the state's standpoint, of having all agricultural water rights bought
up by energy development companies, all bear on the subject of trans-
ferability.
States are now recognizing the need to reserve certain amounts
of water for in-stream values such as recreation, fish life, and water
quality. Whatever water is used for this purpose will have to come from
the available supply and this will worsen the problem of shortfall.
The large projected water demands have placed a strain on
state laws relating to groundwater use. Only very recently has there
been a move to protect the water table from haphazard exploitation and
contamination. The groundwater issue is so new that recharge rates
of these underground reservoirs are generally unstudied and unknown.
5. Interstate Allocation of Water
The U. S. Supreme Court is the potential arbiter of the
respective water rights of two states with a river that forms their
common border and of the rights to water from a river that flows
through two or more states. The Supreme Court and the U. S. Congress
have encouraged the states concerned to develop formulas for sharing
715
-------
the water—subject to Congressional approval of the agreements.
In the areas considered in this study, there are four such
interstate compacts: the Colorado River Compact of 1922; the Upper
Colorado River Basin Compact of 1948; the Belle Fourche River Compact
of 1943; and the Yellowstone River Compact of 1950. These compacts in
no way delimit federal or Indian water rights. Accordingly, they could
be rendered moot if full federal power were exercised over the nation's
water. In the absence of the exercise of that power, the allocative
formulas have been operable.
Particular problems with the compacts relate to the fairness
of the formulas themselves and the numbers used, especially because the
compacts were made long before the region became a focal point for
energy development. For example, Colorado's annual contribution to the
Colorado River is over 11 million acre-ft per year, but the state is
allocated only about 3 million acre-ft per year. Because Colorado is
the primary oil shale development area, the state is angry that it is
being forced, essentially, to shift agricultural water to energy devel-
opment use as a result of its meager allotment under the compacts.
Another institutional barrier may be seen in the Yellowstone
River Compact, which prohibits interbasin transfers without the consent
of all signatory states. This could prevent transfer of water into the
Powder River Basin—rich with coal but short of water—even from nearby
river basins such as the Bighorn or Yellowstone.
6. Transport of Coal: The Slurry Pipeline Issue
Planners looking at the total impact of a major coal conversion
program in the Northern Great Plains are attracted by the possibility of
transporting the coal out of the region for processing elsewhere. An
intense political battle is being waged over the granting of eminent
716
-------
domain power to pipeline companies so that they can construct the pipe-
lines to these distant processing points. The chief opponent to pipe-
lines is the railroad lobby because railroads want to reserve coal
transportation to themselves. Impressive arguments can be presented in
favor of each of the means of transport. It is a water-related matter
because the pipelines would use large amounts of western water to form
the slurry, although the amount of water is far less than if the coal
were converted in the region. Economics appear to favor the pipeline,
while the railroads argue that they face bankruptcy without the coal-
carrying business and that the country needs its railroads to cary
people and other commodities.
To sum up, there is at present no comprehensive effort on the
part of the Congress to deal with the difficult political value questions
implicit in the question of water for energy development in the West.
There is no hint of action going beyond the joint study of the Northern
Great Plains Resource Program and the Environmental Impact studies for
the Colorado oil shale region. The water sought for energy development
is vital to the way of life of the western states. The economic base,
and the very culture of Colorado, Wyoming, Montana, and North Dakota
could be greatly altered if the region's energy-rich resources are devel-
oped without a comprehensive water plan.
717
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REFERENCES
1. Public Land Law Review Commission, One Third of the Nation's Land,
(U.S. Government Printing Office, Washington, D.C., 1970), p. 327.
2. U.S. Constitution, Article IV, Section 3.
3. Ashwander v. TVA, 297 U.S. 288 (1936).
4. U.S. Constitution; Article I, Section 8.
5. U.S. Constitution; Article I, Section 8.
6. United States v. Gerlach Live Stock Co., 339 U.S. 725 (1950).
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718
-------
18. United States v. Rio Grande Dam and Irrigation Co., 174 U.S.
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719
-------
34. Water Policies for the Future, National Water Commission (U.S.
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51. 357 U.S. 275 (1958).
720
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52. 372 U.S. 627 (1963).
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63. Reference 34, p. 481.
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721
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81. Reference 59, Article X.
82. 5 Cal. 140 (Supreme Court of California, 1855).
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81. Wyoming Statutes, Section 41-203.
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87. Montana Laws, Section 89-866 (1974).
722
-------
88. Reference 87, Section 89-872.
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91. Reference 90, Section 148-21-27 (2).
92. Colorado Constitution, Article XVI, Section 6.
93. Reference 87, Section 89-894.
94. Reference 83, Section 41-47-1.
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98. Reference 34, p. 269.
99. Reference 83, Section 41-3.
100. Reference 83, Section 41-4.1.
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102. Reference 87, Sections 89-892 and 89-893.
103. Reference 90, Section 148-21-21(3).
104. Reference 90, Section 148-21-20(6).
105. City and County of Denver v. Sherrif, 105 Colo. 193, 96 P.2d 836
(1939).
106
. Rocky Mountain Mineral Law Newsletter, Vol. VI, No. 6; 1 (1973).
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108. Reference 90, Section 148-21-17(4)
109. Reference 87, Section 89-886(2).
723
-------
110. Reference 87, Section 89-887.
111. Reference 83, Section 41-206.
112. Reference 34, p. 274.
113. Reference 90, Section 148-21-3(6).
114. Reference 90, Section 148-21-3(7).
115. Trelease, F. J., Water Law: Resource Use and Environmental Pro-
tection (West Publishing Co., St. Paul, Minn., 1974), pp. 42-49.
116. Reference 83, Section 41-10.5(a).
117. Reference 83, Section 41-1.42 (1975).
118. Reference 83, Section 41-10.5(b).
119. Reference 87, Section 89-890(1).
120. Reference 34, pp. 497, 260.
121. Meyers, C. J., Market Transfer of Water Rights, National Technical
Information Service (Springfield, Virginia, 1972), p. 5.
122. Reference 107, p. 297.
123. Telephone conversation with Mr. Jerome Hinkle, Environmental Pro-
tection Agency, March 28, 1975.
124. Fletcher, K., "Water/Energy in the West," paper presented to EPA
Environmental Impact Statement Seminar; Denver, Colorado, March 6,
1975.
125. Lofting, E. M. et al., "Economic Evaluation of Water," Water Re-
sources Center, University of California, No. 67 (1963), p. 41.
126. Hutchins, W. A., Selected Problems in the Law of Water Rights in
the West, U.S. Department of Agriculture Misc. Pub. No. 418 (U.S.
Government Printing Office, Washington, D.C., 1942), p. 146.
127. Crosby, "A Layman's Guide to Ground Water Hydrology," quoted in
Reference 115, p. 457.
724
-------
128. Material Needs and the Environment Today and Tomorrow (U.S. Gov-
ernment Printing Office, Washington, D.C., 1973), p. 8-8.
129. Reference 34, p. 246.
130. Hall v. Kuiper, Supreme Court of Colorado, 510 P.2d 329 (1973).
131. Reference 83, Section 41-133.
132. Reference 90, Section 148-18-5.
133. Reference 90, 148-18-6(4).
134. Reference 83, Section 41-129(a).
135. Reference 83, Section 41-132(a).
136. Reference 87, Sections 89-865 to 89-899.
137. Reference 87, Section 89-869(2)(d).
138. Reference 83, Section 41-10.5(d).
139. Telephone interview with Mr. Paul Rechard; Department of Water
Resources, University of Wyoming; Laramie, Wyoming, March 12, 1975.
140. Gapay, L., "Far West's Shortage of Water May Block Energy Schemes,"
The Wall Street Journal (December 16, 1974), p. 1.
141. Reference 87, Section 89-8-103.
142. Reference 87, Section 89-8-105.
143. "Coal Development Alternatives," State of Wyoming, Department of
Economic Planning and Development (December 1974).
144. Effects of Coal Development in the Northern Great Plains, Northern
Great Plains Resource Program, Denver (1975), p. 73.
145. Reference 144, p. 79.
146. Reference 144, p. 74.
147. Reference 75, p. V-5.
725
-------
148. Reference 75, Note 1, p. 75.
149. Reference 75.
150. "Appraisal Report on Montana-Wyoming Aqueducts," Department of
Interior.
151. Richards, W., "Water is Key to Coal Pipeline Fight," Washington
Post, Washington, D.C. (December 1, 1975).
152. "Report on Water for Energy in the Upper Colorado River Basin,"
U.S. Department of the Interior, Washington, D.C., U.S. Government
Printing Office (July 1974), passim, pp. 61-62.
153. Reference 152, p. 12.
154. Reference 152, p. 11.
155. "Water Supplies of the Colorado River," Tipton and Kalmback, Inc.
(1965).
156. Reference 152, p. 63.
157. Water Resources Council, "Water Requirements, Availability,
Constraints, and Recommended Federal Actions," Project Independence,
Federal Energy Administration (November 1974).
158. Reference 157, Note 8, p. 64.
159. "Final Environmental Statement for the Prototype Oil Shale Leasing
Program," Vol. Ill, U.S. Department of the Interior (1973), p. IV-60.
160. Reference 159, p. IV-60.
161. Sparks, F. L. , "Water Prospects for the Emerging Oil Shale Indus-
try," Quarterly of the Colorado School of Mines, Vol. 69, No. 2
(April 1974), p. 98.
162. Reference 161, Note 13, p. IV-61.
163. Atlantic-Richfield Company, Water Right Application #W-196, Water
Division No. 5, State of Colorado.
164. Delaney, R., "water for Oil Shale Development," Denver Law Journal,
Vol. 43 (1966), p. 78.
726
-------
165. Reference 164, p. 78.
166. Cooley, F. G., "The Physical Background (of Oil Shale Development),"
Quarterly of the Colorado School of Mines, Vol. 69, No. 2 (April
1975) .
167. Reference 166, Note 11, p. 1-23.
168. Reference 166, p. 1-22.
169. Reference 166, Note 13, p. 111-28.
170. Huneke, J. M., Vice President, Energy Transportation Systems, Inc.
Statement presented to Hearing before Senate Subcommittee on Min-
erals, Materials and Fuels, June 11, 1974, p. 23.
171. Lewis, F. W., -President, Middle South Utilities, Inc. Statement
presented to Hearing before Senate Subcommittee on Minerals,
Materials and Fuels, June 11, 1974, p. 93.
172. Forbes, L. T., Vice President, Norfolk and Western Railroad; Hear-
ing before Senate Subcommittee on Minerals, Materials and Fuels,
June 11, 1974, p. 125.
173. Hanifin, J. W., President, The Chessie System, Hearing before
Senate Subcommittee on Minerals, Materials and Fuels, June 11,
1974, p. 123.
174. Glover, T. O., et al., "Unit Train Transportation of Coal," Bureau
of Mines, Department of Interior Information Circular 8444, U.S.
Government Printing Office, Washington, D.C. (1970), p. 5.
175. Keystone Coal Buyer's Manual (McGraw-Hill Book Company, New York,
1968), p. 269.
176. Federal Energy Administration, "Project Independence Blueprint:
Analysis of Requirements and Constraints on the Transport of
Energy Materials," (November 1974), p. 9.
177. "The Railroad Paradox: A Profitless Boom," Business Week Magazine
(September 8, 1973), p. 57.
178. Oprea, G., Vice President, Houston Lighting and Power Company,
Hearing before Senate Subcommittee on Minerals, Materials and
Fuels, June 11, 1974, p. 109.
727
-------
179. Montfort, J. G. and E. J. Wasp, "Coal Transportation Economics,"
San Francisco, Bechtel Corp., p. 2.
180. Richie, R. E., President, Arkansas Power and Light Company, Hearing
before the Senate Subcommittee on Minerals, Materials and Fuels,
June 11, 1974, p. 207.
181. Iowa Code Annotated, Section 490.25.
182. Oil Leasing Act of 1920, Section 20.
183. 30 U.S. Code Annotated, Section 229.
184. Natural Gas Act, 15 U.S. Code 717.
185. 15 U.S. Code 715, annotation.
186. "Pipelines in the United States and Europe and Their Legal and
Regulatory Aspects," Special Committee for Oil, Organization for
Economic Co-Operation and Development, Paris, OECD (1969), p. 5.
187. Job, A. L., "Transport of Solids in Pipelines," Ottawa: Department
of Energy Mines and Resources, Info. Circular Number 130 (1969).
188. McAvoy, P. W. and J. Sloss, Regulation of Transport Innovation,
Random House, New York (1967), p. 29.
189. Senate Bill 3044 and House Resolution 10864, March 21, 1962.
190. 49 U.S. Code, Section 1.
191. Johnson, A. M., Petroleum Pipelines and Public Policy (Harvard
University Press, Cambridge, Mass., 1967), p. 32.
192. "The Pipe Line Cases of 1914," 234 U.S. 548 (1914).
193. Coal Traffic Annual, National Coal Association, Washington, D.C.
(1974), p. 3, 4, 5, 22.
194. Johnson, L. B., 1966 Economic Report of the President; quoted in
McAvoy, P. W., et al., Regulation of Transport Innovation (Random
House, New York, 1967), p. vii.
195. "Slurry Pipelines," The Oil and Gas Journal, December 24, 1973,
pp. 44-50.
728
-------
196. SB 2652, Amendment 1175.
197. Reference 176, p. VII-28,
729
-------
20—WATER AVAILABILITY IN THE EASTERN UNITED STATES
Drafted by Ward C. Stoneman, consultant
Revised by Edward M. Dickson,
R. Allen Zink, and Barry L. Walton
A. Introduction
This chapter treats the question of water for synthetic fuel plants
in the eastern United States under the maximum credible implementation
(MCI) scenario for 1980-2000. Water requirements are set against water
supply, and the availability of water from a legal standpoint is dis-
cussed.
The Water Resources Council (WRC), which is the agency charged with
developing, coordinating, and assessing water resources planning informa-
tion for the entire nation, is the source of the data on water supply and
nonsynthetic fuel requirements used in this chapter* For the analysis,
synthetic fuel plants are located according to the planning areas estab-
lished by WRC in its study'75 Water Assessment.1
The '75 Water Assessment provides greater detail concerning water
demands, uses, and resources than the previous assessment of 1968. New
concerns for increasing energy production within the United States have
*Arden O. Weiss, Chairman of WRC's National Programs and Assessment Com-
mittee for the '75 Water Assessment has kindly made data available to
this study—data that are, however, preliminary and subject to revision,
WRC is not, of course, responsible for any errors in use or interpreta-
tion of this data.
730
-------
changed projected water resource demands dramatically in some regions.
WRC is currently working with the Bureau of Mines to determine future
water resource requirements for planned and anticipated coal conversion
processes of various types. In addition, WRC is reevaluating estimates
for future withdrawal and consumptive uses for electric power generation.
Figure 20-1 shows the major river basins of the United States; these
correspond to the WRC's water resource regions. Figure 20-2 shows the
subareas established by the WRC that are affected by the MCI. The aggre-
gated subareas (ASA) within each region follow major river watersheds
and are composed of one or more subareas. For purposes of defining river
watershed areas the WRC has normally maintained county lines as subarea
boundaries.
B. Water Requirements
Data developed by WRC on "Current and Future Annual Water Require-
ments" for each ASA for the '75 Water Assessment are used here to provide
a regional estimate of the quantities of water required for synthetic
fuel plants located in the East. Water requirements for plants hypo-
thetically sited by the MCI in Illinois, Kentucky, Ohio, and West Virginia,
are given in Table 6-3 (Chapter 6). Table 20-1 summarizes these require-
ments for the year 2000; the requirements for plants in Kentucky are di-
vided into eastern and western components; WRC ASA designations are also
given.
Table 20-2 lists the consumptive water uses for the plants (Ta-
ble 20-1), the additional water consumption projected by the WRC, and
determines the percentage water consumption as a function of both the
total water supply and the indigenously produced water supply for each
ASA in which the relevant subareas reside. Data in the upper half of
Tab.le 20-2 indicate that, on a gross regional basis, the impact on the
water resources of each ASA would appear to be small.
731
-------
-1
00
!• J
-•
_V-
MISSOURI BASIN
-L-.-.,
|
(ARKANSflS-WHITE-RED
COLORADO I
FIGURE 20-1. WATER RESOURCE REGIONS OF THE UNITED STATES
-------
FIGURE 20-2. SUBAREAS FOR THE 1975 WATER ASSESSMENT
(Water Resources Council)
733
-------
Table 20-1
EASTERN UNITED STATES MAXIMUM CREDIBLE IMPLEMENTATION
SCENARIO WATER REQUIREMENTS IN THE YEAR 2000
State
Illinois
Kentucky
East
West
Ohio
West Virginia
Requirement
(103 acre-ft/yr)*
415
266
(133)
(133)
133
134
WRC
ASA
No.
705
502
505
502
504
WRC
Subarea
No.
714
507*
515
507+
505
*103 acre-ft/year is about 1.2 X 106m3/year.
tNote that the Eastern Kentucky and Ohio water require-
ments are in the same WRC subarea.
However, such conclusions are on an annual basis. The lower part
of Table 20-2 shows the relationship of the high and low flow months to
the average monthly flow. The "worst case" is the driest month of a dry
year in Eastern Kentucky and Ohio (ASA 502) . Then average daily flows
are only 26 percent of the average monthly flow, and during that month
only 95,000 acre-ft would be available compared to the 22,000 acre-ft
required by the synthetic liquid fuel plants. Thus, in the driest month
of a dry year, the synfuel plants would require about 23 percent of all
indigenous water in this region.
Table 20-3 compares the consumptive use requirements for synthetic
liquid fuel plants with the consumptive use requirements projected by
734
-------
Table 20-2
FUTURE WATER DEMAND COMPARED TO WATER SUPPLY IN THE YEAR 2000
Illinois
Eastern Kentucky and Ohio
Western Kentucky
Supply
Total
Median Year* (103 acre-ft/y)
Dry year (10 acre-ft/y)
Indigenous (Surface)
Median year (10 acre-ft/y)
t 3
Dry year (10 acre-ft/y)
(ASA 705; subarea 714) (ASA 502; subareas 503, 507, 509) (ASA 505; subareas 510, 511, 515)
132,000
69,300
14,400
14,400
71,400
46,100
24,650
15,000
106,000
58,700
41,6OO
14,300
West Virginia
(ASA 504; subarea 505)
12,100
8,310
11,800
8,250
w
Projected total of nonsynthetic
fuel uses (10 acre-ft/y)
Synthetic liquid fuel (10 acres-ft/y)
uses (from Table 20-1)
• Fraction of dry year total supply (%)
• Fraction of dry year indigenous supply (%)
Fluctuations in total supply
• Highest flow month compared to mean
monthly flow in a dry year (%)
• Lowest flow month compared to mean
monthly flow in a dry year ft)
0.6
3
1,638
691
0.6
2
151
7.6
0,2
0.9
162
50% chance of being drier
5% chance of being drier
relevant subarea underlined
-------
WRC for electric plants in the same ASA; the requirements are generally
comparable in magnitude.
Table 20-3
PROJECTED WATER CONSUMPTION BY ELECTRICITY GENERATING
AND SYNTHETIC LIQUID FUEL PLANTS IN THE YEAR 2000
(103 acre-ft/year)
Area
111 i no i s
(ASA 705)
Eastern Kentucky
and Ohio
(ASA 502 ^
Western Kentucky
(ASA 505)
West Virginia
(ASA 504) '
Electricity
Generation
Plants
70
477
254
88
Synthetic
Liquid Fuel
Plants
415
266
133
134
Total
485
743
387
222
C. Water Supply
1. Illinois
This area (ASA 705) consists entirely of Subarea 714. This
area straddles the Mississippi River and includes portions of Southern
Illinois and East-Central Missouri. The Wabash River in Illinois, di-
rectly to the east of this subarea is in Subarea 515 (see Western Ken-
tucky section 2-a, below). The plants in this subarea are sited on the
Illinois side of the Mississippi River to remain as close to the coal
fields as possible. The river basins included are as follows:
736
-------
• Kaskaskia
• Big Muddy
• Cache.
Existing water storage capacity totals 1,640,000 acre-ft.
This storage is in two major lakes on the Kaskaskia River. There is
additional potential storage capacity of 1,240,000 acre-ft.
Flows in the Big Muddy River range from a low of 10,000 acre-
ft/year in dry years to 268,000 acre-ft/year in median years. Existing
water storage capacities total 119,000 acre-ft. This storage is pri-
marily on Rend Lake, which is on the river. There is additional poten-
tial storage capacity of 758,000 acre-ft. Current and projected with-
drawals for thermal cooling from the Basin are negligible. In view of
the low flows in dry years and the relatively small flow from existing
storage, the Big Muddy would not appear to be a primary candidate for
the location of even a small syncrude plant unless the plant either
drew water from the mainstem of the -Mississippi River or located a source
for transbasin diversion.
2. Kentucky
a. Western Kentucky
The WRC has divided this area (ASA 505) into three sub-
areas: 510, 511, and 515 (Figure 20-2), We have sited the western
Kentucky synthetic fuel plants in subarea 515.
Although Subarea 515 spans both sides of the Ohio River
mainstem, the main river basin in the subarea is the Green River Basin
with a total area of 9273 mis in 31 counties. Except for a relatively
small area in northern Tennessee, the Basin's natural drainage area is
entirely within Kentucky. The drainage basin is roughly 60 to 80 miles
wide and 160 miles long.2 The Green River and its tributaries flow
737
-------
through the heart of Kentucky's western coal region. The average annual
runoff in the Basin is 15-20 inches.2 Three major federal reservoirs
are in the area—Nolin, Rough, and Barren. Moreover, the identified ad-
ditional storage potentials in the Basin amount to approximately 1 mil-
lion acre-ft.2
The general precipitation runoff-storage situation in the
Ohio River Basin is as follows: Of the total precipitation, over 60 per-
cent is lost to the atmosphere by evaporation and transpiration. The
remainder, averaging annually 17.3 inches equivalent depth over the
drainage area, flows to the Mississippi River.2 Generally, sufficient
runoff for summer and fall use could be stored during each high water
season without holding stored waters from year to year except in very
high water use areas and during periods of extreme or extended drought.
Even in lower tributaries, streams may run dry during periods of low
precipitation, especially where ground water seepage is deficient.
Existing storage capacities have been developed generally
for flood control and for control of low stream flow because the mainte-
nance of stream flow is important to the preservation of water quality
in the region.
While total flows in the region appear adequate to sus-
tain the needs of the synthetic liquid fuel plants, attempts to establish
the long-term water supply for necessary plants may require the develop-
ment of considerable storage capacity or use of existing storage. In
addition, general factors relating to the uncertainties of future devel-
opments would affect the amount of water that is available.
b. Eastern Kentucky and Ohio
The WRC has divided this area (ASA 502) into three sub-
areas: 503, 507, 509. The synthetic liquid fuel plants, however, have
738
-------
all been sited in subarea 507 which contains 37 counties in Kentucky,
Ohio, and West Virginia.
The major rivers in the ASA are the
• Pittsburgh
• Cincinnati
• Little Miami
As this is an area of rugged terrain in the Appalachian
mountains, industrial sites are at a premium.
3. West Virginia
This area (ASA 504) consists entirely of subarea 505. The
Kanawha River basin includes six major subbasins:3
Drainage Area
Subbasin (mi2)
New River ' 6918
Greenbrier River 1656
Elk River 1532
Gauley River 1420
Coal River 899
Pocatalico River 359
Average annual precipitation in the Basin as a whole is approx-
mately 43.5 inches. If annual precipitation less than 85 percent of the
mean is considered to be a drought condition, 16 of the 76 years for
which weather records have been kept for Charleston, West Virginia, would
be classified as drought years; 1904, 1930, and 1953 were particularly
severe.3
The Kanawha Basin has the highest sustained flow of the tribu-
taries of the upper Ohio River. There are no major natural lakes in the
739
-------
basin. Streamflows are subject to wide seasonal variations and to rela-
tively wide variations between extremely wet and dry years,3 and thus
access to storage capacities would appear essential to satisfy the water
demands of the synthetic fuel plants.
The terrain of the area features steeply rising hills and nar-
row valleys, which lie along the watercourses of the streams and rivers.
All of the important existing industrial, residential, and transportation
facilities and networks in the basins are located in these valleys. Be-
cause of the topography, industrial sites in the basin are at a premium.
D. Legal Aspects of Water Availability
1. Riparian Law
Unlike water rights in the western states, which are governed
by an "appropriation" system, water rights in the eastern states are gov-
*
erned by riparian law. Under riparian law, the right to use water at-
taches to the land over which the water flows. Thus, historically, a
riparian right has been a property right.
Early in American history the rules of English riparian law
were incorporated into the law of the respective states:
• "Prima facie the proprietor of each bank of a stream is
the proprietor of half of the land covered by the stream;
but there is no property in the water."4
• "Every proprietor has an equal right to use the water
which flows in the stream; and, consequently, no propri-
etor can have the right to use the water to the prejudice
of any other proprietor."4
*Riparian relates to that which is located on the banks of a natural
watercourse.
740
-------
• "Without the consent of the other proprietors who may
be affected by his operations, no proprietor can...
diminish the quantity of water which would otherwise
descend to the proprietor below."4
• "Every proprietor, who claims a right...to diminish
the quantity of water which is to descend below, must,
in order to maintain his claim, either prove an actual
grant or license from the proprietors affected by his
operations, or must prove an uninterrupted enjoyment
of twenty years."
• "Though the proprietor may use the water while it runs
over his land as an incident to the land, he cannot
unreasonably detain it or give it another direction, and
he must return it to its ordinary channel when it leaves
his estate."4
There is also a rule that water may be used only on riparian
land by its proprietor. Thus, if a riparian parcel of land is divided
and sold in such a manner that what was one large, riparian parcel be-
comes one riparian and one nonriparian parcel, there are no water rights
associated with the newly created nonriparian land. In other words, water
rights are incidental to lands bordering on streams and cannot be created
or transferred independently. Thus, use of water is strictly limited to
uses on riparian lands.
Some states have modified this practice by establishing a test
of reasonableness of the nonriparian use. If lower riparians claim in-
jury because of a nonriparian's use of the waters of a stream, the courts
will look to the nonriparian's application of the water to determine
whether it is reasonable. Generally, the cases indicate that any produc-
tive use except waste* is considered reasonable by the courts. Consequently,
*As used here, "waste," is a legal term meaning, roughly: an abuse or
.destructive use of property by one in rightful possession.
741
-------
the party seeking to enjoin a diversion by a nonriparian must prove, in
addition to injury, that the use to which the diversion is put is un-
reasonable.
When the stream flow is insufficient to satisfy all users be-
cause of low flow, then the rule of "correlative rights" comes into play:
All riparians must suffer diminution of use equally.
The general law of riparian water law is in effect in the
states in which the eastern syncrude and methanol plants would be sited
but the modified rule of reasonable use of diversions is in effect in
Kentucky and Illinois.
The National Water Commission made attempts to determine how
riparian water law actually works in practice in those states in which
it is in effect. The Commission found the general situation to be as
follows: As a consequence of the riparian rules and the absence of rec-
ords, the public planner and private investor are confronted with the
following uncertainties in water resource development:
• What is the existing demand on supply?
• What is potential demand on supply?
• What supply security will present development have in the
future?
• What kind of private consensual arrangements can be made
to safeguard supply?6
Thus our general knowledge of how the riparian system works in actual
practice in the states of the East and of how present water rights actu-
ally relate to supply is limited. This also applies to the transfer of
water rights under riparian law. One type of transfer is common; a sale
of riparian land automatically transfers the seller's water rights to
the purchaser. This is not the interesting case in terms of the devel-
opment of a law of water transfers. The interesting case is where the
742
-------
water is sought to be sold apart from the land. It is here that we have
almost no information about the operation of the riparian system. Evi-
dently such transfers are rare in that system, due probably to the plenti-
fulness of water in most of the areas where the riparian system is in
effect, but it may also be due to the legal difficulties of attempting
to transfer riparian rights except as an incident to a sale of riparian
land.7
The actual fact is, of course, that power plants using once-
through cooling water have been built in the three states under consid-
eration in this study; large chemical processing plants have been devel-
oped in West Virginia along the Kanawha; other industrial operations,
which require an assured supply of water, have flourished in the states
under consideration here. Most such plants are located along the main
stems of the major rivers, ones whose flow throughout the year is as-
sured (often with the assistance of major storage projects) and, where
the consumptive uses of the plants either diminish the total flow so
little that no downstream riparian is injured, or that no downstream
riparian is in a position to complain. Shortage of water also plays an
important part in the ability to maintain an assured flow for a number
of uses. Where this is the case, the common law doctrines of riparian
water law may be inapplicable. What often happens is that state and/or
federal statutes authorizing the projects became the legal means by which
the storage and allocation of water is established (see Section E, below),
In the "humid East" these storage projects generally are aimed at cap-
turing and controlling flood waters, waters which could not be of use to
any riparian anyway and in most cases constitute a positive threat. The
storage of flood waters for later use in the maintenance of stream flows
and related or dependent uses appears to present little or no controversy,
In fact, the National Water Commission did not consider this aspect of
the problem in its strictly legal studies in the area.
743
-------
In summary, a description of the riparian law which obtains in
the eastern states under consideration in this study, while perhaps nec-
essary for background, is of little assistance in determining whether or
not water would actually be available.
In contrast with the appropriation law system, the effect of
riparian law is more in the nature of a negative influence over new de-
velopments rather than a positive system for the identification and de-
termination of quantitative rights in water uses. This is especially
true when the contrasted appropriation system has been strengthened
through application of a state permit system. Water rights under rip-
arian water law doctrines tend to be uncertain, thereby compounding the
difficulty of any attempt to ascertain whether water would be available
for the projected development of synthetic fuel plants. Moreover, rip-
arian water law, and the traditions on which it is founded, does not
readily lend itself to the development of positive water use permit
systems. Proposals that riparian states should enact permit systems
like those in effect in some western states have been firmly rejected
by the eastern states.
2. Position of the States
The National Water Commission asserted that "no crisis in water
use exists generally in the humid East" and that the uncertainties over
the state of knowledge of water rights, supply, and demand "have not yet
caused serious problems in the East, for water supplies have been abun-
dant."6 This situation may have changed in the short time since 1973
when the Commission issued its final report. Water supplies in the East
may become generally "critical" at a more rapid rate than was anticipated,
For Project Independence, the Water Resources Council polled
the states concerning water related problems in connection with energy
744
-------
developments.8 Those states that attended the WRC regional conferences
as a follow-up to the WRC questions "expressed a belief that the Federal
government must first propose a definitive policy on energy self-
sufficiency including time frames and needs before states can do ade-
quate long range planning."9 In the area of "water rights" and legal
impediments, the states expressed views indicative of problems that would
be encountered by an attempt to establish the plants in the East as a
matter of federal policy without that policy also having been adopted by
each involved state for itself. In the matter of water rights the states
held strong opinions regarding federal jurisdiction over water rights.
They felt that energy self-sufficiency would be impeded due to litiga-
tion if the federal government were to move strongly into the water rights
area. In fact, a suggestion was made that Congress should enact legisla-
tion assuring that water rights granted under state law be protected. It
was felt that under most present systems, water rights can be acquired
by negotiated purchase or by condemnation and most state water laws are
well adapted to provide water for self-sufficiency.8 In the matter of
legal impediments almost all states indicated that compliance with water
rights acts and water quality control acts would impede energy develop-
ments. However, it was pointed out that regulatory laws may help and not
hinder the best use of water and that energy developments should proceed
only under strict and rigidly enforced controls. In fact, concern over
the adverse impacts of rapid development of energy sources has prompted
states to consider or enact stringent regulatory measures for mining,
o
facilities-siting, and related activities.
In view of the foregoing, and because "Federal water projects
are seldom initiated without strong State support and almost never under-
taken in opposition to State desires,"8 it appears that not only state
law--in the sense of the riparian law governing water rights—but state
policies and administration directed toward water resources development
745
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will heavily influence the question of water availability for projected
synthetic fuel plants.
The following is a brief summary of the situation as it pertains
to three of the states considered in this chapter.
a. Illinois10
• The Illinois state constitution contains no water
policy statement for the state.
• Water use in Illinois is governed primarily by its
state court fashioned rules of law. Generally, in
this regard, the courts follow the common law of
England, modified as the courts find rules that are
in harmony with the state's legal system.
• Periodically, attempts have been made to implement
the common law through legislation. These attempts
have failed, but there is some disconnected legis-
lation that deals with certain phases of water use.
• There have been relatively few court cases reported
regarding water use in Illinois.
• Under the riparian doctrine, the courts have dis-
tinguished between artificial and natural uses. The
latter use, which includes those needs that are ab-
solutely necessary for the existence of civilization
(i.e., drinking water, water for household purposes
and for watering livestock) has a clear priority
over all other uses in times of drought. Each
proprietor may, when necessary, use all of the water
in a stream for these purposes without liability to
a lower proprietor on the stream.
• The rule of reasonable use appears to apply in Illi-
nois, but its effect in practice is uncertain.
• The state's courts have taken a strict view of what
constitutes a navigable stream. It must be in the
nature of a highway that bears commerce. A stream
that is not naturally navigable cannot be made so
by deepening, widening, etc. (Legally, if this state
view conflicts with the federal view, the latter
prevails.)
746
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• The attorney general has expressed the opinion that
the Department of Public Works and Buildings may per-
mit the withdrawal of water from a public body of
water through a pipeline for industrial and manufac-
turing purposes if it determines that to do so will
be in the public interest and if the riparian rights
of lower riparian owners are not adversely affected
by diversion of the water.
• Diversion between basins has been considered by the
state's courts mainly as a problem of burdening the
riparian owners of the water course from which the
diversion was made. That is, a riparian proprietor
has the right to natural flow, unaugmented by diver-
sions from other basins.
• The state has broad eminent domain powers for the
acquisition of property for water management and
development. The Departments of Public Works and
Buildings and of Conservation are the primary
agencies with the power to exercise eminent domain.
The state has also delegated this power to a number
of its subunits of government: cities and villages,
counties; townships; soil and water conservation
districts; subdistricts of same; port, sanitary,
river conservancy, surface water protection, and
public water districts; and water authorities.
• Under the state's regulatory authorities, permits
or approvals are required for the drilling of wells,
impoundments, and channel encroachments. Some of
these permits require the applicant to obtain the
consent or approval of downstream riparian propri-
etors .
• Approximately seven state-level departments, in-
cluding 42 divisions and seven boards or commis-
sions are involved in one aspect or another of de-
velopment, maintenance, operation, and regulation
of the state's water resources. In addition, the
state has numerous subunits of government, including
special purpose districts, which have powers and
duties relating to water resources development and
utilization.
• As a matter of policy, water management functions in
Illinois are centralized. The Department of Business
and Economic Development, Division of Water and
747
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Tl
Natural Resources, is the state's lead agency in
the coordination of water resources management and
development policies.
• In general, the power of home rule has not been
granted to local governmental units by the state.
It has granted powers to local governments to de-
velop water resources on a categorical basis:
sewage, water supplies, etc. In general, this
has led to creation of special purpose districts
to solve local problems. These districts have
home-rule-like powers for special purposes in
some cases.
• Coordination between the state and the federal
government, including the Corps of Engineers and
the Soil Conservation Service, on matters of water
resource management and development is the re-
sponsibility of the state's Department of Business
and Economic Development.
• The state follows the policy of seeking the great-
est degree of overall development of each reser-
voir project in the state. The Rend Lake project
on the Big Muddy is a recent example; the project
provides water resources for multipurpose opera-
tions: municipal, industrial, and agricultural
water supply; recreational facilities; flood pro-
tection; minimum downstream low-flows; pollution
abatement; and other purposes. The project was
carried out by the state's Division of Waterways.
• The Rend Lake project is also an example of the
state's policies towards multigovernmental coop-
eration. The Rend Lake Conservancy District, the
state, and the federal government participated
directly in the project, with the latter two
coordinating with the many other agencies and
districts involved.
b. Kentucky3
Riparian rights under Kentucky law have been nar-
rowed by legislative action. A riparian propri-
etor has the right to withdraw waters for agricul-
tural and domestic purposes without a permit.
748
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• With the above exception, and the one cited in the
following, all other public water users in Kentucky
must obtain a permit from the state's Division of
Water. The statutory permit system requires the
permittee to maintain certain records of with-
drawal .
• No permit is required for industrial or manufac-
turing operations provided that the water with-
drawn "is returned in substantially the same
quantity and condition as it is withdrawn...."
• Kentucky's permit system does not operate to
allocate the state's waters, although the Divi-
sion of Water has the power to apportion short-
ages. (This power has apparently never been
exercised.) The permit system in effect appears
to be a step towards improved record keeping and
a potential basis for the exercise of increased
state control of water uses should future demands
so require.
• The state requires permits for the construction
of impoundment dams and other forms of water con-
tainment, and for obstructions.
• The state requires permits or exercises authority
over water resource related activities concerning
drilling or abandoning wells, developments in flood
plains, construction of public water supply, and
flow regulation.
• By statutory declaration, "it is declared the
policy of the Commonwealth to actively encourage
and to provide financial, technical and other
support for the projects that will control and
store our water resources in order that the con-
tinued growth and development of the Commonwealth
might be assured."
• Approximately nine departments, including eight
divisions, and five Boards or commissions are in-
volved in the state's water resources.
• The Division of Water within the Department of
Natural Resources is the state function assigned
the primary responsibility for developing the
state's water resources, preventing floods, and
749
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controlling water usage within the state. The
Division also holds the power of eminent domain.
The state has enabled a number of water resource
related special purpose districts: conservancy,
flood control (subdivided into city flood control
districts, flood control districts, and levee
districts), sanitation, soil conservation, and
water districts.
Responsibility for development of the state's
water resources is "ultimately" centralized at
the various state agencies. The extent and prac-
tical nature of home rule in the state is unclear.
However, it is thought to be extensive for a num-
ber of purposes.
c. West Virginia
• The riparian law of water rights obtains as the
common law of West Virginia in practically un-
modified form with respect to its origins in the
English common law.
• Most of the water rights cases in the state deal
with the protection of property against water
damage due to excesses of water on lands of
others.
• There has been little or no litigation concern-
ing diversion between basins. Strict adherence
to riparian doctrines would appear to preclude
such diversions, but apparently there has been
no significant diversion in the state.
• Impoundments are permitted by the state (for
example the Buffalo Creek impoundment was under
state permit): the state regulates little else
with respect to the use of water resources.
• There are approximately six state departments,
including six divisions, and six boards or com-
missions, which are responsible for state's
water resources in one way or another.
• The Division of Water Resources within the De-
partment of Natural Resources is the "lead
agency," to the extent that the state does
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exercise responsibility, for water resources devel-
opment and management.
• Three special purpose districts have been created
by the state: soil conservation, watershed im-
provement, and public service districts.
• Home rule obtains in West Virginia by a 1936 amend-
ment to its constitution.
The foregoing overview summary of the laws, policies, and
administrative scope of the three states may be deceptive for its appar-
ent simplicity. If the states and their local units of government are
involved at ail in the siting of projected synthetic fuel plants—and it
is difficult to see how they would not be under existing federal-state
law unless the Congress were to enact legislation which simply preempts
all state law in water related questions—then the plants will be sited
within the context of complex, perhaps exceedingly complex, legal, policy
and administrative frameworks which, for the most part, are unique to
each state. This also means that a particular solution to a problem, or
a cluster of problems, related to water availability in one state or
locale will not necessarily assist in solutions to similar problems in
the other states. From a practical point of view, the issue of water
availability in the eastern states may depend more on factors other than
apparent quantitative flows. Many of those factors result because of the
fact that the states under consideration have no experience with
water shortages and therefore have no policy or legal traditions
behind them from which to deal with the problem.
It is evident from the material reviewed for this study
that the states under consideration in this chapter are strong opponents
of trends leading to a centralized planning, implementation, and regu-
latory approach toward water resources: "Resistance (by the riparian
states) to the granting of firmer rights has already been demonstrated by
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the general refusal to adopt appropriation style permit systems giving
users in the East rights similar to western appropriation rights."5 The
main argument by the states for retention of the present methods of
water resources development and the allocation of water rights on a
project-by-project basis appears to be that the rule of "reasonable use"
provides a greater flexibility in meeting shifting water demands than
would a rigidly applied appropriative system coupled with a "permit"
authority. Under riparian law, the basic conflict appears to be between
certainty and flexibility: "Courts have responded (to this conflict)
generally by expressing the notion that riparian rights must be flexible,
and yet practical priorities are recognized. It does seem fair to con-
clude that reasonableness represents a rule of accommodation, and subject
to legitimate claims for accommodation, priority in time is likely to
give priority in right over new users competing for an insufficient
5
supply."
Maintaining the riparian system—with all its uncertain-
ties—on a notion of flexibility is all very well when water quantities
and qualities are sufficient to allow plenty of room for maneuvering to
take advantage of that flexibility. In the event—which now seems to be
in the offing—that there is no more room to maneuver between existing
demands on the water resource, low-flows in drought years, and increas-
ingly poor water quality in the available supply, the riparian system
would probably come under considerable stress if faced with substantial
demands for new water resources related to economic growth. Of course,
it is impossible to predict how the states may respond to such a situa-
tion, and mapping alternative possibilities would be gross speculation
at this time.
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E- Federal Programs That Relate to Water Resource Development In
the East
The following summary identifies the major federal agencies and
their programs that relate to water resources development in the eastern
states. The discussion does not treat the federal power to conduct such
programs in the states because that power applies to both the eastern
and the western states. The information is drawn primarily from two
staff studies for the National Water Commission,11'12 plus additional
more recent material.
From the federal government point of view there are two underlying
factual differences between the eastern and the western states:
• The federal government is not a substantial landholder in
the eastern states.
• Traditionally,the eastern states have not been beholden as
have the western states to the federal government's appli-
cation of massive resources in the development of water
resources projects for new irrigation and other land
development.
These two historical facts account for the substantially different
bases for relationships between the states and the federal government
in the East and in the West.
If the primary concern of the states in the "arid West" has been
the application of federal resources and funding to the development of
water resources to bring water to those lands, then by contrast the
primary concern of the states in the East with respect to the federal
government has been to seek assistance in keeping excess waters—flood
waters—off the lands of the state.
To continue this contrast, while the Bureau of Reclamation has been
the federal agency most involved in the development of major public works
devoted to the development and conservation of water resources for appli-
cation to arid lands, the Corps of Engineers has had a much longer
753
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tradition (since 1824) of flood-control works in the eastern and mid-
western states. (Navigation is also the responsibility of the Corps.)
The most recent programs of the Corps for reservoirs are directed
to multipurpose developments, meaning that a major reservoir project
must serve multiple water resources purposes. Primarily it has been
the Corps which has undertaken, on behalf of the federal government,
the large reservoir projects that relate to improved water resource
management and use. It is the Corps that would be involved in any fu-
ture major works for water storage, although where pumped storage and
hydroelectric power are involved the Federal Power Commission and the
utility itself undertake the primary responsibilities.
It is not necessary to review the Corps' responsibilities, programs,
policies, and practices here because they have been well documented
through recent studies and public controversies. However, from a plan-
ning point of view, it is important to note that the Corps is running
into increasing difficulty in obtaining approval for its water resources
development, management, and control projects. The very recent events
surrounding the Corps-proposed project to build a $30 million dam on the
Red River Gorge in eastern Kentucky is an example that is geographically
and politically pertinent to this study. The Council on Environmental
Quality (CEQ), in a rare action, has publicly opposed the Corps' proj-
ect. In its general nature, the project is a typical multipurpose res-
ervoir project of the type undertaken in the eastern states. Local
landowners have succeeded in obtaining a temporary restraining order
from a federal court in Louisville to halt the project. They have been
joined by a number of conservation groups.* The controversy has split
*Under present doctrine, conservation groups must join with plaintiffs
who would actually be injured by the proposed developments in order to
achieve standing.
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the former and present members of the congressional delegation. Oppo-
sition has been going on since at least 1968 when the former Justice
and Mrs. Douglas took a walking tour through the area to underscore their
personal protests. It is an issue in local elections. The Corps remains
adamant on the issue that it need not provide further quantitative infor-
mation concerning certain aspects of the project, nor does it think it
has overlooked the major social and cultural changes that would be
wrought through consequential developments. This could force each plant
either to go to the main stem of major rivers in the area, such as the
Ohio and the Mississippi, or to storage projects for each plant's water
needs. The latter could well meet with local opposition as intense as
that directed at the Red River project if the project were developed
under the eminent domain powers of public authority, which might prove
to be a necessity.
In addition to the Corps, the Soil Conservation Service (SCS) has
had long standing water resource development and control authority and
programs. The responsibilities, powers, programs, and general methods
of operation of the SCS are the same in the eastern states as they are
in the western states, except that the agency relates to the Corps of
Engineers as the developer of large project works instead of the Bureau
of Reclamation.
The Federal Power Commission is the federal agency with exclusive
powers to license hydroelectric projects. Unlike the statutorily estab-
lished policies of the other two agencies mentioned above, the court
interpretation of the powers of the FPC is that it may exercise its lic-
ensing authority in direct derogation of state laws and policies. This,
too, has been the basis for intense controversy—both political and
legal--in the eastern states over specific projects that have been pro-
posed but not yet approved.
755
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Until recently, the programs of the federal government could be
expected to provide stability and certainty of water supplies for major
industrial and municipal needs in the face of uncertain and "flexible"
(or shifting) water rights under riparian law. Intense opposition to
the projects of these development oriented agencies has introduced a
strong element of uncertainty into the question of assured and available
water supplies for the proposed plants. From a planning point of view,
there are no "mechanisms" or "devices" that could be introduced at this
time to provide a greater degree of certainty in these areas. Resolu-
tion may well depend on political resolution of the underlying factors,
such as the relationship of economic growth to environmental protection.
As a final point, the effect of water pollution controls on water
availability should be mentioned. It may be that enforcement of water
pollution control laws and regulations by each state will reduce the
importance of the riparian doctrine as the major allocator of water
uses. The stream standards set for each major river and stream are
based, in part, on calculated minimum flows during dry years and dry
periods during each year; that is, on the average minimum capacities
of the flows to abate pollution. Any substantial impact on these stream
standards of withdrawals for consumptive uses would tend to increase the
burden of additional pollution control of all other dischargers.* In
this way, the states may be forced to allocate the quantity and quality
of major stream flows among users, which would have the effect of achiev-
ing a limited appropriation system-by-permit, although in a relatively
indirect manner. With the ability of the states and the federal govern-
ment to develop water storage and control projects almost at will under
serious challenge and with the increasing competition among water users
*The Miami Conservancy District in Ohio has taken this approach, for
example, with the municipal dischargers along the river. The inter-
dependency of stream users and dischargers is increased with drinking
water standards are included in the balancing.
756
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for what amounts to the assimilative capacity of water courses, and with
the newly created drinking water standards responsibilities of the EPA,
the question of water rights in the eastern states may become a matter
of administrative determination of the departments of environmental pro-
tection of the states rather than the divisions of water, as is the
present structure.
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REFERENCES
1. '75 Water Assessment, Water Research Council, unpublished.
2. "Ohio River Basin Comprehensive Survey."
3. "Kanawha River Basin Comprehensive Survey."
4. Blackstone (George Sharswood), J. B. Lippincott & Co. (Philadelphia,
1878).
5. Davis, "Riparian Water Law: A Functional Analysis," Legal Study
No. 2, National Water Commission (1971).
6. "water Policies for the Future," National Water Commission (Govern-
ment Printing Office, Washington, D.C., 1973).
7. Meyers and Posner, "Market Transfer of Water Rights," Legal Study
No. 4, National Water Commission (1971), NTIS Accession No. PB 202 602
8. "Water Requirements, Availabilities, Constraints, and Recommended
Federal Actions," Water Resources Council, Federal Energy Administra-
tion, Project Independence Blueprint, Final Task Force Report (Gov-
ernment Printing Office, Washington, B.C., 1974).
9. "Water for Energy Self-Sufficiency," U.S. Water Resources Council
(Government Printing Office, Washington, D.C., 1974).
10. Upper Mississippi River Comprehensive Basin Study.
11. Ely, N. , "Authorization of Federal Water Projects," National Water
Commission (1971), NTIS Accession No. PB 206 096.
12. Trelease, F. , "Federal-State Relations in Water Law," National Water
Commission.
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21--THE IMPACT OF INDUSTRIAL GROWTH ON RURAL SOCIETY
By Peter D. Miller
A. Introduction
The people of the Northern Great Plains and the Rocky Mountains have
witnessed the beginning of an industrial revolution in their region. Be-
cause of an international conflict half a world away, domestic resources
of coal and oil shale have suddenly increased in value. An entire domes-
tic energy industry, based on the mining and retorting of oil shale and
the mining and processing of coal into synthetic fuels, has become more
viable almost overnight owing to the new scarcity of once-cheap energy.
This scarcity has stimulated intense interest in the abundant deposits
of coal and oil shale in the West that have never before been mined on
a large scale.
Concomitant with this interest, the Western regions rich in oil
shale and coal are experiencing the initial stage-setting for industrial-
ization and urbanization. In one of the most remote places in the con-
tinental United States, Colorado's Piceance Basin on the western slope
of the Rockies, Rifle, Colorado, now regularly hails visitors from gov-
ernment, banking, industry, academia, and other walks of life rarely
seen before in that vicinity. A similar scene can be observed in Gil-
lette, Wyoming, located at the center of about one-fifth of the U.S.
continental deposits of coal. At an early hour on a typical day, the
motel coffee shop serves hard-hatted construction workers and miners,
Stetson-hatted cowhands and tourists, bankers, real estate agents,
trailer salesmen, government officials, and researchers. Processions
of businessmen, lawyers, branch managers, salesmen, investment analysts,
759
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government bureaucrats, and social scientists stream through the town.
Older residents watch the parade with a mixture of awe, excitement, and
irritation. Many of them have become interview-hardened from being asked
the same questions repeatedly, having developed from extensive practice
a smooth, routine answer to every question. For some, opinions about the
coal mining industry have hardened, too; it is either "raping the land-
scape" or "the best thing that ever happened to Wyoming." Retail sales
are booming, land prices are bid up, wages are high; merchants, land-
owners willing to sell, and construction workers therefore derive some
immediate benefits from the new industry. They are likely to feel
strongly that the industry benefits everyone.
A common topic of conversation in Gillette concerns rumors of new
coal mines, electrical generating facilities, or a uranium mine and proc-
essing complex. Announcements are made, modified, retracted, and made
again. People talk hopefully or apprehensively, depending on their point
of view, about possibilities for employment and prosperity or possibili-
ties for a disastrous cycle of boom and bust.
Development of these coal and oil shale resources to the extent nec-
essary to free the United States from dependence on foreign sources of
energy would require industrialization of regions in the West that here-
tofore have known only a rural way of life. Wherever industrialization
has occurred in the past, it has profoundly changed the values, life-
styles, and organization of society. The purpose of this chapter is to
outline the social changes likely to result from mining for synthetic
fuels development. Since qualitative and quantitative data on social
impacts are to be found in the impacts that have occurred in similar
settings in the past, past and present mining and industrial communities
were studied for evidence applicable to social impacts of synthetic fuels
development.
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The consequences of energy development decisions necessarily spread
out in many directions. Which ones are applicable in social impact as-
sessment depend largely on the interests of those affected by these deci-
sions. Some groups are interested in site-specific impacts, while others
are concerned with national and international consequences. Some set
their sights on the twenty-first century, while others are most concerned
about the here and now. Some view social impacts exclusively in terms of
planned consequences, while others focus their attention on effects that
may have been ignored. These divergent interests can be considered in
terms of space, time, and purpose.
Some impacts are clearly meaningful only at the site-specific level.
Examples are disturbances of ground surface, reduction of vegetation, un-
sightly disposal of mine wastes, and other problems of reclamation. Other
impacts are concentrated in the locality or county where mining takes
place. Effects on the fiscal and institutional capacity of local govern-
ments to absorb growth are examples. At the regional (multistate) level,
social impacts may involve political relationships between energy-producing
states and energy-consuming states. National social impacts concern the
attainability and desirability of energy independence and the appropriate
balance among domestic production, imports, and conservation. Finally,
energy development decisions can have worldwide repercussions, affecting
trading relationships, currencies, and international stabilization.
Because of the different size of the units involved in space, it is
difficult to compare social impacts at one level with those at another
level. The balancing of favorable consequences at one level with unfav-
orable consequences at another level is a task for the political process.
Social impacts can vary in time as well as in space. Although the
term "impact" suggests a definite time, in practice it is difficult to
identify exactly when that time occurs. Neither the causes (energy
761
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development decisions) nor the effects (social impacts) are momentary
occurrences. Energy development decisions may begin to cause social
consequences at any time along the way to implementation—corporate plan-
ning, congressional debate, passage of legislation, lawsuits, project
planning, environmental impact reporting, project modification, mine and
plant construction, mine and plant operation. Similarly, some impacts
may be felt immediately, while others may be delayed, or extended. Some
may be reversible, others irreversible. Here again, it is important to
make comparisons in terms of similar units. Impacts that take place dur-
ing a construction period, for example, may not be indicative of impacts
that take place during an operating period.
A crucial distinction in the assessment of social impacts is the
one between intended and unintended consequences.1 The intended conse-
quences of energy development decisions have to do with increasing domes-
tic energy production to reduce dependence on imports. Decisions of such
magnitude often lead to unintended consequences that prove to be at least
as important as the intended ones. The National Environmental Policy Act
and the growing emphasis on technology assessment attest to the signifi-
cance of unintended consequences. Environmental impact reporting and
technology assessment are two means of attempting to assure consideration
of issues that otherwise would have been neglected. Knowing these im-
pacts in advance enables decision-makers to take better account of them
in their planning, or to reevaluate their plans.
In assessment of the potential social impacts of a synthetic fuel
industry, the discussion is organized as follows:
• The interests of various parties involved in or affected by
energy development decisions.
• Local impacts of energy development and analysis of the dy-
namics and economics of growth that would result from very
rapid energy development, compatible with a "maximum credible
level of development.
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• Controlled growth consistent with considerations of the inter-
ests of the various concerned parties.
Chapter 23 analyses the effects on the urban growth process of vary-
ing plant sizes, construction schedules, and rates of population growth,
and considers the implications of this analysis for increased energy de-
velopment in Appalachia and southern Illinois.
B. Interest Groups
All groups to be affected by decisions regarding energy development
should be included in a discussion of social impacts. At a minimum, the
following groups would be affected by energy development: local govern-
ment; state government; federal government; ranchers and farmers; work-
ers and other residents; businessmen; new employees and other newcomers;
energy industrialists; environmentalists; and energy consumers. This
is a diverse assortment of interest groups. Some of them are better-
organized and better-financed than others and thus better able to com-
municate their position to the general public. Some of them claim to
speak for others, and within each group, there may be sharp differences
of opinion. Nevertheless by examining the interests of each group sep-
arately and assessing the impact of energy development on each it is
possible to indicate the problems that would be created for a region
subjected to the dynamics of growth discussed in Section C, following.
1. Local Government
Local officials in the coal-producing regions of the Rocky
Mountain and Northern Great Plains states are generally oriented to the
needs and interests of a local constituency, with strongly-held beliefs
* Impacts on railroads and some impacts on Indians are discussed in Chap-
ter 19.
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about what is good and bad for their own. They tend to be conservative
in the sense of approaching change cautiously and wishing to preserve the
status quo. As a general rule, they believe that government and planning
should be minimized. At the same time, they are concerned about the de-
cline of the economic base and population that has afflicted many rural
towns and counties. While some of them view energy development as a
means to revitalize the local economy and promote growth, others view
energy development as a threat to traditional ways of life and regard the
costs of very rapid growth as greater than the benefits.
The mining of energy minerals and their conversion to synthetic
fuels would bring large numbers of people to regions of the Rocky Mountain
and.Northern Great Plains states that now have a typical population den-
sity of two people per square mile. This influx of people would quickly
overwhelm the present institutional capacity of local governments: hous-
ing, schools, roads, utilities would have to be provided in relatively
short order.
The building of new cities or the expansion of existing ones
does not require only money. It also requires an "infrastructure capac-
ity," a network of local service industries, public services, and skilled
work force and management, which is formed by the gradual accumulation of
the requisite social and economic structure. In almost all areas where
energy minerals are plentiful, this capacity would have to be imported,
that is, attracted to the region.
Building or expanding a city in the midst of a sparsely popu-
lated region requires a sizable public investment. The quicker the pace
of development, the more urgent the need for revenues to provide services.
At the same time, localities faced with energy development are operating
in a high-risk situation. Unable to collect the bulk of tax revenues
until after development impacts have occurred, they must nevertheless
invest, in effect, in a market whose future is uncertain. Changes in
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world oil prices, trade balances, geopolitical arrangements, and so on,
could easily remove the need for these energy projects and turn the en-
tire urban apparatus into a ghost town. If intensive western energy
development proved unprofitable, the depopulated remains of these local-
ities would be saddled with indebtedness.
Local governments, however, have little to say about the scope,
intensity, or location of energy development. In many areas of potential
mineral development, land ownership is fragmented among different juris-
dictions such that the mineral estate is almost exclusively under federal
control, while local governments retain control over surface improvements.
At the same time; local governments have little control over the emerging
economic base associated with energy development. Without the capacity
to raise funds to meet development costs, these localities could find
themselves in the position of bearing a large part of the social and
economic burden for supplying national energy demands.
Rock Springs, Wyoming, for example, which had lapsed from a
railroad boom town in the 1880s to a declining rural town, has become a
small industrial center in the last five years. Industrial activity in
trona mining and soda-ash refining, oil drilling, as well as coal mining
and electrical generating facilities more than doubled the town's 1970
population of 12,000 to 26,000 in 1975. Rock Springs Mayor Paul Wataha
referred to the high risks inherent in very rapid development when he
stated, "l don't see how we could have adequately prepared for this.
Even if in 1970 we could have persuaded the voters to pass bond issues,
how were they to know the companies wouldn't change their minds?... If
we could have had the same growth over a ten-year period instead of two
years, things would have been a lot better." The implication is that
to avert problems of industrialization/urbanization, one would have had
to slow the rate of local growth. Similarly, Gillette, Wyoming, doubled
its population between 1960 and 1970 (3600 to 7200), and, at the present
765
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rate of growth, will see its population double again by 1977. Once the
scene of early coal mining activity, and of an oil boom in the 1950s,
Gillette reverted to relative quiescence in the 1960s until the current
coal boom. Like Rock Springs, it could well develop into a major west-
ern industrial center.
2. State Government
State governments, like local governments, have an interest in
maximizing tax revenues while minimizing expenditures for which they are
responsible. They share with the regional public an interest in gaining
the maximum value for their natural resources. In energy development,
the interests of state officials appear to converge with those of local
officials. They both wish to ensure the economic stabilization of local
jurisdictions by regulating the pace of development so that it does not
interfere with orderly growth. State officials have wider responsibility
for coordination and planning, of course, and may have to reconcile di-
verse interests within their states. State officials must also respond
to federal pressures for increased coal leasing and mining.
The governors of the Rocky Mountain and Northern Great Plains
states have reached some consensus (if not total agreement) on the condi-
tions they believe should govern coal mining, with local autonomy as a
major theme. Montana Governor Thomas Judge stated, for example, "if we
are going to produce [coal], it's doing to be on our terms—not on terms
somebody else dictates."3 In a letter to the Senate Interior and Insular
Affairs Committee, North Dakota Governor Arthur Link stated the position
of North Dakota: "The State of North Dakota desires to assist in the
effort to meet the 'energy needs' (to be distinguished from mere 'energy
demands') of the nation. But, concurrent with the offer of assistance,
this state will demand necessary environmental, social, and economic safe-
guards to protect the state. North Dakota will not 'subsidize' the energy
766
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needs of the rest of the nation by bearing a disproportionate share of
the social and environmental costs of massive energy production."4 The
recently-formed Western Governors' Regional Energy Policy Office adopted
19 substantive and eight procedural policies for energy production. Re-
garding social and environmental impacts of energy production, the gov-
ernors resolved "to obtain timely assistance for local political entities
which are affected by energy development impacts from such appropriate
sources as an energy industry or state or federal government," and "to
weigh the critical need for food production in the assessment of possible
adverse impacts of energy production on top soil, water supply, water
quality and air purity."5 The position of the governors of the Western
coal-producing states is to cooperate with federal and industry efforts
to develop the coal resource to the extent such development is compatible
with enhancement of living standards and maintenance of environmental
values,
3. Federal Government
The federal government includes diverse interests related to
the social impact of energy development. Debates within the federal gov-
ernment over such issues as the role of energy conservation, the rights
of surface landowners, definition of a fair return to the Treasury from
use of the public lands, the scope, pace, and location of coal leases,
the feasibility of reclamation, the nation's position in international
trade, and the allocation of western water have so far not led to a
coherent energy policy. In general, however, federal officials have an
interest in reducing American dependence on energy imports.
The ability to cut oil imports as a result of increased domes-
tic energy production would promote other international interests of the
United States. The United States currently imports about one-fourth of
the total oil in the world market. Former Interior Secretary Morton has
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argued that the energy needs of developing countries depend on the United
States foregoing some of these oil imports.6 This would help preserve
existing trade relationships and earn the goodwill of other energy con-
suming nations.
Federal officials with responsibility for managing the economy
have an interest in keeping energy prices down. Although the era of
"cheap energy" is undoubtedly over, it is still desirable to minimize
the shock of adjustment to higher energy prices. Moreover, circulation
of the dollars domestically would be a more desirable alternative than
exporting them.
The federal government also has a clearly recognized responsi-
bility to foster orderly community development, and to maintain equitable
and efficient administration of all its natural resources. Energy devel-
opment is a high-risk venture for the public sector as well as for the
private sector. If citizens, producers, and consumers are to benefit
equitably from energy production, some sharing of the costs and risks of
such development will probably be necessary. Although states and locali-
ties can provide some assistance, only the federal government has the
resources to manage this sharing.
Over a long period, federal policy has been directed toward
preventing the burden of community development from falling solely on
local residents. Federal compensation for local development costs may
be traced back to the federal ordinance of May 20, 1795, in which one-
sixteenth of every township was deeded to the township for support of
schools. Land grants to the states for specific national purposes, such
as higher education, continued throughout the nineteenth century. Con-
cern about the federal government's sovereign immunity from tax liabil-
ity led to the establishment by Congress in 1907 of a revenue-sharing
formula whereby the counties in which federal timber was harvested would
768
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receive one-fourth of all sales revenues for roads and schools. The
formula for federal forest lands in Oregon and California was even more
generous: 50 percent of income from valuable Pacific Northwest timber
was allocated to the counties under the Oregon and California Act of
1937. Similarly, under the Knutson-Vandenberg Act of 1964, timber har-
vesters can be required to pay for reforestation and other improvements
to the public lands. Congress also recognized the adverse impact of
military bases on local fiscal capacity to the extent of providing spe-
cial compensation for schools and other costs.
As a proprietor, the federal government has an interest similar
to that of other.landowners—to obtain the maximum revenues from use of
the land, to prevent environmental degradation, to manage its resources
wisely, and to exercise effective control over the use of its land. Thus
the federal government has an interest in guaranteeing a fair return to
the Treasury for the extraction of valuable resources. The Department of
the Interior has procedures for leasing its mineral holdings (see Chap-
ter 7 for a detailed discussion). In addition, it has recommended a new,
Q
more participatory leasing program consisting of three phases:
Nominations. In contrast to the past practice in which nomina-
tions for leased land were received exclusively from the mining industry,
the proposed regulations allow for nominations also to be received by
the Bureau of Land Management (BLM) from citizens and from local and
state officials. In addition, nominations against the leasing of fed-
eral lands for coal mining purposes would be accepted.
Planning. The BLM would undertake an integrated program of
land use planning and resource management in relation to multiple-use
goals.? Coal leasing decisions would be based on multiple-use principles
of the BLM rather than solely on considerations pertaining to the mining
industry. The BLM would seek to resolve conflicting land uses, prepare
769
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a land use plan, select lease tracts from nominations, and prepare a
leasing schedule.
Leasing. Leasing would take place within the context of over-
all land use planning objectives and field office objectives. The BLM
field office would handle the lease sales.
As managers, federal officials have an interest in resolving
the many controversies that divide the country over energy policy and
environmental protection. They need to have at least a minimal con-
sensus on the amount of domestic energy production necessary to reduce
dependence on imports while at the same time protecting the people and
the environment of the coal-producing regions. Without some such mini-
mal consensus, disputes will probably reach the courts in increasing
numbers and although legal scholars disagree over whether the courts
have a legitimate role in this area,10'11 the courts may become involved.
4 . Ranchers and Farmers
Ranching and farming are traditional modes of land use in the
rural western coal-producing states. Generally, the rancher's interest
consists in keeping things as they have been, improving the productivity
of the range, preserving a sufficient water supply, and keeping a depend-
able source of labor. Since it takes 30 to 40 acres to graze a cow on
the western range, very large tracts of land are necessary for profitable
ranching. Ranchers also have a particular interest in keeping the price
of land low if they intend to continue ranching. If the price of land
rises, taxes also rise, and ranch profits are reduced.
Intensive coal mining and industrial activity would threaten
ranchers1 and farmers' traditional ways of life. Major decisions regard-
ing land use, water use, and other matters of importance to ranchers and
farmers would probably be made in increasing numbers by people far re-
moved from the local community. The process of industrialization tends
770
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to elevate the importance of economic rationality and to reduce the im-
portance of values that cannot be measured in dollars and cents. In-
tangibles such as aesthetic appeal, environmental amenities, or open
space tend to lose out to easily quantifiable values such as product
sales. It is often argued, that because traditional land uses such as
ranching and farming are less profitable in the short run than strip
mining, mining constitutes the land's "highest and best use." Resource'
management and environmental management can be integrated with coal min-
ing when renewable resources are dealt with but involves consumptive
(nonrenewable) use of a resource and therefore cannot be managed on the
basis of securing a sustained yield. Customary mining practice is to
recover the most easily accessible and valuable reserves first, and to
mine less accessible and valuable resources later. The interests of the
mine operator are thus not tied to resource conservation in the same way
that the interests of livestock grazers and farmers are tied to the con-
tinuing productivity of the land.
Some ranchers have been offered high prices for the right to
mine coal under their land, but some have refused to strike a bargain.
They may feel that continued occupancy means more to them than the sub-
stantial profits they would realize from sale or lease, or they may have
concluded that reclamation after surface mining is not possible. Those
who have chosen to sell or lease have reaped substantial financial bene-
fits. They were free to retire or buy land elsewhere and relocate their
ranches and farms. Incentives to sell or lease may include the desire
to move out of an area surrounded by mining operations, future lack of
an adequate water supply, higher taxes resulting from high land values
and assessments, or difficulties in recruiting a work force. The high
wages offered by the new mining industry in areas like Campbell County,
Wyoming, have made it difficult for ranchers to rely on a steady supply
"of labor. Where high school students can drop out and make twice what
771
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their teachers make, part-time jobs at the ranch no longer seem attrac-
tive. Ranch hands and virtually anyone else employed at lower wages are
candidates for higher-paying industrial employment. Other employers must
then pay higher wages to match the competition.
5. Workers and Other Residents
The opportunity to earn higher wages would benefit residents
who were prepared to adapt to the industrial environment. Young people
with limited opportunities elsewhere would especially benefit. Many of
them would receive on-the-job training in the specialized skills neces-
sary to operate a modern surface mine, synthetic fuels facility, or power
plant. This would enhance their employability in the energy industry and
in other industries. They would enjoy higher income and greater mobility
than otherwise possible. Those residents who either chose to remain out-
side the new industrial environment or who were unable to occupy a place
within it would be left behind by energy development. In general, the
aged, the poor, and the hard core unemployed would be put at a disadvan-
tage by the higher cost of housing and retail goods resulting from local
development-induced inflation.
6. Businessmen
Merchants would benefit from energy development. In Rock
Springs, Wyoming, for example, retail sales jumped from $31,000,000 in
1970 to 859,000,000 in 1973.2 Virtually anyone who owned a business
supplying goods and services to the new industry and its employees would
gain, but businessmen engaged in the sale of farm and ranch machinery
would probably not gain. Increased demand for housing and land would
also benefit builers and land developers. Professional incomes would
probably rise. These business opportunities would attract new people to
772
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the growing community and would make a larger variety of goods and serv-
ices available to residents.
7. New Employees and Other Newcomers
People are attracted to mining towns by the prospect of employ-
ment at relatively high wages. For the unemployed, productive work is ob-
viously a benefit. Many are attracted by the excitement of starting up
a new industry, or by the stimulation of a booming industrial town. One
indication of the extent of opportunity open to coal mining employees is
the fact that little formal education is required as a qualification for
relatively high-paying jobs.12 A study of North Dakota's coal mining and
utility plant work force revealed that 42 percent of the coal employees
they questioned* terminated their education after 12 years. Forty per-
cent of the total number of mechanics, welders, carpenters, dozer opera-
tors, and truck drivers they questioned^ had less than 8 years of formal
education,12 but most had had some vocational training. Despite their
lack of formal education, which would have disqualified them for many
lesser-skilled jobs with other employers, they were able to find employ-
ment and on-the-job training. Moreover, if the study data are generally
indicative, the coal companies tend to promote from within. For example,
more than 63 percent of the dragline operators (the most highly skilled
position) had held four or more positions with their current employer.12
Thus opportunities for advancement as well as for entry are very good.
On the other hand, newcomers to less stable communities can
experience some hardships. For example, Gillette, Wyoming, which has
experienced a very high rate of population growth due to energy
*Sample size: (n = 241).
tSample size: (n = 64).
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development, found that its ability to accommodate the newcomers was
limited. Housing costs rose rapidly until home ownership was beyond the
means of the new residents, despite their increased incomes. By 1970,
the median rent of $140 a month in Campbell County (where Gillette is
located) was the highest in Wyoming.13 Even trailers were being rented
at higher prices than fixed housing would have brought in ordinary times.
Many latecomers could find housing only in tents.
Trailer camps typically offered a cramped dwelling space with
no yard, little privacy, and sometimes no sewage hookup. Gillette's
rapid growth also led to overcrowded schools, strains on public safety
manpower, and a sudden need for medical and public health services. 4
Signs of social malaise such as alcoholism, crime, divorce, suicide, and
similar problems began to increase, according to local clinical psycholo-
gists.15 The need for such specialized social services as family therapy,
mental health counseling, and alcohol detoxification soon became appar-
ent, but the clinic and the jail were forced to function as all-purpose
caretakers in the absence of these services . High rates of turnover
and absenteeism are thus added to the costs of production. These
problems have caused needless suffering.
8. The Energy Industrialists
The economics of the extractive industries favor rapid devel-
opment of resources to minimize the time and money invested before sales
of the resource. Particularly in the current period of high prices for
energy minerals, the incentives for rapid exploitation of western coal
reserves are very strong. It is reasonable to expect that mining activ-
ity will be greatest when energy prices are at their highest. Coal min-
ing activity would probably decline if coal prices declined. Thus,
energy industrialists are interested in assuring production as soon as
possible.
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Energy industrialists also have an interest in minimizing the
risk in undertaking new large-scale development. Availability of key
equipment such as draglines (now back-ordered several years at many
mines), the availability of skilled labor, expected future demand for
energy, costs of transporting coal, and commercial feasibility of syn-
thetic fuels conversion technologies are the kinds of uncertainties
likely to be faced by any industry contemplating large-scale innovation.
Uncoordinated and contradictory policies among the federal
agencies involved with energy development are another source of uncer-
tainty to the energy industry. Policies and regulations of the follow-
ing federal agencies have to be taken into account in corporate planning:
Energy Research and Development Agency, Federal Energy Administration,
Environmental Protection Agency, Mine Enforcement and Safety Administra-
tion, Bureau of Mines, Bureau of Reclamation, and Bureau of Land Manage-
ment. Changes in mining practices mandated by Congress, the courts, and
the states complete the picture of uncertainty. Industry spokesmen state
that they would like to have clearly articulated laws and regulations
regarding energy development. To the extent that decisions to undertake
extensive energy development would remove regulatory and legal uncer-
tainties, these decisions would benefit the energy industry.
9. Environmentalists
Although environmentalists have no direct economic stake in
energy development decisions, they have an interest in preserving wilder-
ness values, natural resources, and rural, land-based ways of life. En-
vironmentalists are a varied interest-group, consisting of fishermen,
hunters, hikers, wilderness seekers, and others who wish to preserve
opportunities for outdoor recreation, scientific study, or simple en-
joyment. Although economists have attempted to quantify such values17
environmental values also have a symbolic dimension for environmentalists.
775
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Unique features of land in the United States have become symbols of na-
tional identity and have thus acquired a protected status. One of the
most popular patriotic songs extolls the nation's "shining seas, purple
mountain's majesties, and amber waves of grain." The National Parks,
and to a lesser extent all public lands are a cultural resource of sym-
bolic value even for those who rarely visit them. Reverence toward land,
traditional in most agrarian and nomadic cultures, including that of the
Indians and early white settlers, is being revived by environmentalists
as a philosophy of resource use. This philosophy means that environ-
mentalists will (and do) exert their influence to control growth, prevent
pollution, and conserve and preserve wilderness areas.
Controlling growth. The goal of controlling growth is based
on the observation that growth may not always be compatible with human
welfare. Environmentalists question the "conventional wisdom" that eco-
nomic growth and population growth always work to everyone's benefit.
Some unintended consequences of growth may be depletion of resources,
inequitable distribution of wealth, and externalties such as pollution
of air and water.
Conservation. The goal of conservation is an attempt to come
to terms with the unpleasant fact of limited resources. It suggests pre-
serving resources (such as energy reserves) for future use rather than
using them up at an excessive rate. Environmentalists believe that con-
servation efforts will soften the effects of reaching resource limits.
Preventing pollution. The goal of preventing pollution stems
from the desire to minimize adverse health effects of polluted air and
water, and to have the freedom to enjoy pure air and water. Recognizing
that industrial growth is a primary cause of air and water pollution,
environmentalists seek ways of regulating industry in order to minimize
or prevent pollution. In the environmentalists' view, the Rocky Moun-
tain and Northern Great Plains states are the most endangered by energy
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development, because these regions have the largest quantities of clean
air and pure water to lose.
Extensive development of western coal reserves could lead to
uncontrolled urbanization and industrialization of previously rural
areas, rapid depletion of domestic energy reserves, weakening of incen-
tives to practice energy conservation, increased pollution of air and
water, and loss of wilderness of semiwilderness areas, all of which would
be directly contrary to the interests and concerns of environmentalists.
10. Energy Consumers
Energy'consumers would benefit from extensive energy develop-
ment in at least two ways: assured energy supplies, and less reliance
on imports.
The Arab oil boycott reminded consumers of the vulnerability
of some sources of energy supplies. Extensive domestic energy develop-
ment would help assure consumers of continued supplies. This would in
turn assure a continued flow of goods and services that depend on energy
consumption.
C. Dynamics of Urban Growth Related to Public Expenditure
Correlative to energy development and its consequences from the
points of view of the various interest groups is the question of growth
as it relates to economics. Local growth is neither the blessing that
boosters have often portrayed nor the disaster that no-growth advocates
have portrayed. To make informed choices about desirable rates of eco-
nomic development, local and state officials need to have more precise
information about the relationship between growth and public expendi-
tures than is generally available. While a full-scale analysis of all
possible alternatives cannot be made here, some aspects of the
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relationship between growth and public expenditures that can contribute
to understanding of decision options, are presented. In general, eco-
nomic development brings additional population; growing towns and cities
require an investment in public services and governmental organization.
Unless the locality finds a way of financing these improvements, economic
development and population growth will not necessarily benefit it. From
the local and state perspective, the decision calls for a judgment whether
the investment in public services required for a given rate of growth will
be worthwhile.
1. Stages of Urban Growth
Localities faced with rapid urbanization have two choices.
They can attempt to meet demands for public services and facilities before
they occur, or they can allow public works and organizational development
to lag behind. In the first choice, they risk being overextended if pop-
ulation growth proves to be less than anticipated. For example, this
could happen if mining activity were prematurely curtailed by declining
energy prices or other uncertainties in the energy industry. In the sec-
ond choice, existing public services are continually inadequate for the
level of demand. This case tends to be more prevalent under conditions
of rapid population growth because the normal life-cycles of bond issues
cannot keep up with the pace of expansion. In addition, residents may
be reluctant to accept higher taxes and bond issues until they become
absolutely necessary. The choices are depicted graphically in Figure 21-1.
A midway course between unmet demand and excess capacity would involve the
least risk to the locality, but this level may be difficult to determine
while expansion is still in progress.
Very rapid spurts of housing and commercial building construc-
tion often lead to an "echo effect" in later years.18 Assuming an ap-
proximately equal useful life, buildings completed during the same
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t-
I
H
tO
LLl
o
_l
03
Z>
Q.
LOCAL PUBLIC WORKS
AND ORGANIZATION
DEVELOPMENT
DEMAND FOR SERVICES
EXCESS CAPACITIES
TIME
A. PUBLIC INVESTMENT LEADING DEMAND
LU
2
H
CO
LU
O
_J
m
Q-
DEMAND FOR SERVICES
LOCAL PUBLIC WORKS
AND ORGANIZATION
DEVELOPMENT
DEFICIENCY IN CAPACITIES
TIME
B. PUBLIC INVESTMENT LAGGING DEMAND
FIGURE 21-1. PUBLIC INVESTMENT COMPARED TO DEMAND
FOR PUBLIC SERVICES
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construction period will all "wear out" at roughly the same time. An
initial period of boom construction necessarily creates a second con-
struction boom because the rate of replacement tends to resemble the
original rate of construction. Figure 21-2 contrasts the construction
boom with the constant rate of construction and replacement. The con-
stant rate results in a flat age-profile of buildings in which ages and
conditions are varied, while boom and bust cycles of extreme severity
are built into the local economy by an initial construction boom. Since
rents are partially a function of a building's age and condition, there
would be little basis for variation in rental values other than location,
and hence little diversity of lessee choice.
Successive increments of population growth do not necessarily
have identical characteristics. In changing from a crossroads to a vil-
lage, then to a town, and finally into a city, different kinds of deci-
sions are called for at each step. A town has different requirements
from a set of villages with equal numbers of people. It has been sug-
gested that this process be treated as a sequence of steps involving
progressively higher expenditures.19 As Figure 21-3 shows, the first
improvements to be made are well-drilling (or reservoir construction),
road-building, septic tank installation, and school-building. Later, the
town may decide to invest in a sewage system, a hospital, and an addition
to the school building. At this point, the town may adopt zoning ordi-
nances and building codes. When these steps occur in rapid succession,
previous investments are made obsolete before they wear out. Before the
next phase arrives, development of a local bureaucracy for planning and
service delivery becomes critical. Coordinating transportation, educa-
tion, health services, water use, and land use for a city of 25,000-
50,000 is a major job. At this population level, the stakes are much
higher than before, particularly when revenue sources to pay for these
commitments are uncertain. Although revenue bonds can pay for some of
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tr
o
Z)
tr
o
o
u.
o
LJ
CD
BOOM
BOOM
ECHO
1980
1990 2000
YEAR
2010
CO
l-
CL
o
Z)
cr
(-
en
O
o
a:
LJ
CD
1980
1990
2000
YEAR
2010
FIGURE 21-2. "BOOM" CONSTRUCTION AND ITS ECHO EFFECT CONTRASTED
WITH FLAT-AGE-PROFILE CONSTRUCTION
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3
CL
o
CL
00
to
FOUR-LANE ROADS INTERCHANGES
NEW SCHOOL SITES
NEW TOWN CENTER
WATER IMPORTATION OR EXPROPRIATION
SOLID WASTE DISPOSAL SITE DEVELOPMENT
HEALTH FACILITIES
SEWAGE TREATMENT FACILITIES
CENTRAL
SCHOOL EXPANSION
FRINGE AND STRIP COMMERCIAL DEVELOPMENT
SUBDIVISIONS
MOBIL HOME/PREFABRICATED HOUSING PROJECTS
CORPORATION YARDS
LOCAL WATER (SPRINGS, WELLS)
,TWO-LANE ROADS
SEPTIC TANKS
SINGLE SCHOOL DISTRICT
FIGURE 21-3. MAJOR INVESTMENTS AND DECISIONS VS. POPULATION
GROWTH FOR AN URBANIZING SMALLTOWN
-------
these costs, these bonds are generally repaid from user charges, not
taxes.
2. Population Growth and Per Capita Costs
It might seem reasonable to expect per capita costs of public
services to drop as population rises because of possible economies of
scale. Once an initial capital investment has been made, the locality
has a certain excess capacity that can be used to absorb new growth.
Incremental additions to structures and facilities are usually easier to
finance when building on an existing base than when starting anew. Many
economies of scale in the delivery of local public services are related
to increased population densities. Services whose costs are mainly as-
sociated with geographical dispersion include police and fire protection,
garbage collection, and other field or patrol services. If (other fac-
tors being equal) population growth occurs within a relatively concen-
trated area, the costs of serving 30,000 people can be far less than
twice the costs of serving 15,000 people. Similarly, public investments
in buildings and equipment may be made with lower per capita costs where
population is relatively concentrated rather than dispersed. Hospitals
and schools, for example, can benefit from such economies of scale.
In practice, however, declining per capita public costs thought
to result from population growth have not materialized in the western
coal-producing counties during periods of rapid growth. In a detailed
study undertaken for the Northern Great Plains Resources Program* by the
*The Northern Great Plains Resources Program is an intergovernmental
agency composed of representatives of the States of Montana, Wyoming,
North Dakota, South Dakota, and Nebraska, and the Department of Inter-
ior, Department of Agriculture, and the Environmental Protection Agency.
783
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Bureau of Reclamation and the Institute of Applied Research at Montana
State University, it was found that direct per capita public expenditures
actually increased faster than the population in the sample.20 The sam-
ple included Sheridan and Campbell counties in Wyoming, Big Horn and Rose-
bud counties in Montana, and Mercer and Oliver counties in North Dakota.
The impacts experienced in these counties typify those to be expected in
other counties in the same region in which energy development takes place.
First, the study projected future populations for the "most probable"
schedule of energy development generated by direct and secondary employ-
ment at coal mines, gasification plants, and generating facilities. Sec-
ond, the study projected future public service needs in the areas of
health care, social services, schools, fire protection, law enforcement,
travel and transportation, municipal services, recreation facilities, and
planning. Third, it estimated the costs of these governmental services
and facilities and compared these costs with revenues likely to be avail-
able. The comparison showed that during the construction period revenues
would be inadequate to cover costs and that after the construction period
revenues would be adequate in all sampled counties except Sheridan County.
Municipalities would experience greater difficult in financing services,
however, because industrial complexes are not expected to be constructed
within corporate limits.
Figure 21-4 illustrates the pattern of per capita public ex-
penditures rising faster than population during periods of rapid popula-
tion growth. A jurisdiction of 15,000 population, for example, spending
4 million dollars a year would be spending more than twice that sum—9
million dollars—when its population reached 30,000. At an annual rate
of population growth of 5 percent, total public expenditures, corrected
for inflation, would double approximately every 13 years.
Rosebud County, Montana, where coal mining has taken place but
no major construction has occurred, saw its per capita expenditures jump
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1C
20
30 40 50 60 70
POPULATION- thousands
SOURCE: BUREAU OF RECLAMATION (1974)
90
100
FIGURE 21-4. CORRELATION OF GOVERNMENT EXPENDITURES
TO POPULATION
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from $88 in 1969-70 to $121 (in constant 1967 dollars) in 1973-74, an
increase of almost 40 percent. While taxable valuations rose during that
period, they did not rise sufficiently to pay for increased expenditures.
According to the Montana State Department of Natural Resource and Conser-
vation, even these increased per capita public costs represent a minimum
"make-do" budget.31 The same pattern was revealed in Forsyth, the county
seat of Rosebud County. While population rose from 2000 to 2800 as a
result of coal development from 1970 to 1974, expenditures (in constant
dollars) doubled. Per capita public expenditures rose from $81 to $116
(constant 1967 dollars) during that period. An increase of 18 percent
in municipal taxable valuations stands in sharp contrast to the town's
100 percent increase in expenditures.
3. Growth and Revenue
The examples given above lessen assurance that services to
accommodate rapid rates of population growth can always be financed from
anticipated revenues. There are at least eight reasons why this might
be the case.
Demographic Characteristics—The costs of urbanization are
affected by demographic characteristics of the immigrants as well as by
their sheer numbers. Five hundred additional young families a year, for
example, would have more impact on school budgets than would equal num-
bers of elderly people. For example, Campbell County, which had the
largest proportion of school-age population of any county in Wyoming
five years ago, can be expected to increase this proportion still further
in subsequent years. Since schools consume at least half of all local
government expenditures, this increase alone would have a large impact.
The elderly, on the other hand, would require larger expenditures for
public health and hospitals. Itinerant laborers without families would
786
-------
have minimal impact on school budgets. However, their demand for housing
would be greater than that by equal numbers of family members because of
the greater incidence of one-person households. The younger the incoming
population, the more need for expenditures on recreational facilities.
Population requiring the more labor-intensive governmental services, such
as social welfare, mental health counseling, manpower development, and
vocational training, also cause greater per-capita public expenditure.
Diversity of Services—With rapid urbanization, government must
assume many of the traditional "caretaker" functions since newcomers can-
not depend on personal ties in the community. The newcomers exert pres-
sure for public services not only because of their number but because of
their greater dependency on government as well. This is particularly
true if the newcomers come from larger urban areas in which dependence
on government is heavy. Straight extrapolations of costs resulting from
population growth may not indicate the full extent of future costs be-
cause "a wider variety of services is likely to be demanded because of
the greater diversity of the new populations."20
Narrow Financial Base—Local jurisdictions are generally less
able, legally and politically, to impose new or greater taxes than are
higher jurisdictions. Dependent on the property tax and on grants from
state and federal government, localities stand on a narrow financial base.
Municipalities are particularly vulnerable because industrial complexes
located outside town boundaries generate no property tax revenues for the
town. Local revenue sources are generally less varied and therefore less
adequate. States can impose severance taxes, license fees, royalties,
income taxes, sales taxes, establish reclamation bond funds, etc., but
there is no guarantee that these revenues will be distributed to the lo-
calities where the taxes were collected. It has been the practice in a
number of states to put severance tax revenues, for example, into the
787
-------
general fund, remitting only the surplus above state general expendi-
tures to the counties that generated the revenues.
Intercounty Disparities—Just as counties within the same
state might be burdened unequally by the costs of urbanization, counties
in two different states can experience the same disparity. It would be
feasible, for example, for large numbers of people to live in Sheridan,
Wyoming, and to commute to work in Montana. In that case, property tax
revenues on the plants would be generated for Montana while Sheridan
would pay the costs. Sheridan would therefore experience particular dif-
ficulty in financing its growth.
Tax Breaks—Many states grant tax breaks to new industry as an
inducement to locate in the state. For example, Montana taxes new indus-
trial property at only 7 percent of its "true and full value" for the
2 2
first three years. Machinery and equipment are taxed at 30 percent of
their value. New industries in North Dakota may be completely exempt
from property and corporate income taxes for five years. These practices
remove a source of revenue during the period of fastest growth when it is
most needed by urbanizing areas.
Indirect Benefits to Outsiders—Although industrial growth cre-
ates secondary employment, it does not necessarily broaden the local tax
base as much as is often forecasted. Most of the local secondary employ-
ment would be in the services, sales, and government sectors. Relatively
little of it would occur in a diversified industrial base on the local
level. Large-scale coal mining in Wyoming would generate employment in
Ohio where draglines are manufactured, in the Great Lakes states where
steel is produced. Thus a substantial proportion of the benefits of
secondary employment would accrue to states outside the western coal-
producing regions.
788
-------
Settlement Patterns—Since many economies of scale in the
delivery of local public services are related to increased population
densities, these economies may not materialize unless certain critical
densities develop. Factors inhibiting such densities from developing
include incentives toward rural land subdivision, the desire to escape
municipal taxes, regulation, zoning, and building codes, and other well-
documented dynamics of urban sprawl.23 Dispersed residential settlement
may also be fostered by geographical barriers such as unstable soils,
steep slopes, or other rough terrain. In such cases, settlement will
tend to spread out along easily buildable sites in river valleys rather
than assuming a circular distribution. Unwillingness to accept land-use
controls at the county-wide or state-wide levels may also facilitate
settlement patterns that fail to realize economies of scale in the de-
livery of public services. Similarly, access to centralized facilities
such as hospitals is reduced by dispersion of residential settlement, in
which case effective delivery of such services can only be made with
increased transportation costs.
Limited Size—The localities considered in this report are
attempting to build governmental services on a relatively restricted
base. Their population and their institutional capacity are limited in
the beginning, and so they may not yet have reached the point where they
can realize economies of scale. It has been suggested that such econo-
mies only begin to be realized at the size of 100,000 or 200,000 popu-
lation.^ None of the localities studied here is expected to reach that
size as a result of projected energy development.
4. Tax Lag
A final problem faced by towns trying to finance urbanization--
tax lag—deserves separate consideration. Even if there were no tax
breaks for industry and no intercounty disparities, the costs of
789
-------
urbanization would still generally occur before the taxes to finance
them arrived.
Tax structures represent the bargain struck between industry
and the general public for the privilege of doing business. Since min-
eral extraction removes wealth from its original jurisdiction, mineral
taxes are in part a form of compensation. As extractive industries deal-
ing with foreign countries have found, taxation has become a device for
tacitly sharing the wealth. A "fair" tax rate in such cases has come to
mean a proportion of profits derived from sale of the raw mineral. Al-
though the American coal and oil shale producing states do not exercise
sovereign powers, they have similar interests at stake. They will want
to assure themselves, at a minimum, that the costs of minerals develop-
ment will not exceed their ability to finance required public expendi-
tures. Beyond that, they may seek to regulate various aspects of indus-
trial development by manipulating tax incentives and disincentives.
Montana, which is a leader in mineral taxation, has four major
taxes that pertain to coal mining: the Net Proceeds Tax, the Resource
Indemnity Trust Account Tax, the Strip Coal Mines License Tax, and the
Corporation License Tax.82 The Net Proceeds Tax, or severance tax, is
based on the gross dollar value of coal extracted, less the cost of min-
ing and marketing it, and may be averaged over five or more years. This
value is then included in the assessed property of the firm and thus
becomes subject to county property taxes. However, a drawback is that
revenues are not collected until after public costs have occurred.
Another potential drawback relates to the procedure for determining the
valuation of net proceeds. One of the advantages of vertical integra-
tion is the opportunity for a firm to sell crude products to itself at
below-market prices, thereby lowering taxable valuation. For in-state
mining and conversion operations, this could represent a substantial
loss of revenue.
790
-------
Reclamation fund taxes can be based either on the value of
coal extracted, the quantity of coal extracted, or on the anticipated
cost of reclamation. When the reclamation bond is equivalent to the
value of the coal extracted, the bond operates as a surety that recla-
mation work is actually performed because there would be no net benefit
in forfeiting the bond. The alternative of holding a bond equivalent to
the cost of reclamation has been tried in some Appalachian states, but
it has been found in a significant number of cases that these were
treated as "slip-out costs" by firms unwilling to perform reclamation.
In one eastern state, an ingenious operator has apparently circumvented
the reclamation tax entirely by stripping the overburden without touching
the coal and then selling the land to another operator. Montana's rec-
lamation fund imposes a tax of $25 plus 0.5 percent of the gross value
of coal extracted. Under the vetoed federal strip mine legislation, a
federal reclamation fund would collect 35 cents a ton to reclaim "orphan
lands"—abandoned by untraceable strip mine operators—and sell them to
responsible owners.
States have the option of remitting revenues to the general
treasury or of earmarking tax revenues for specific purposes and/or
counties. For example, Kentucky treats severance taxes as general-
purpose revenue, sending only the surplus above the state expenditures
back to the county from which the coal eas extracted. Other states ear-
mark these taxes specifically for road maintenance and reclamation work
in those counties. Montana's reclamation fund tax is earmarked for the
counties where land has been disturbed. In addition, its Strip Coal
Mines License Tax, levied proportionally to the heating value of the
coal, collects amounts ranging from 12 to 40 cents a ton. Of this
amount, the county contributing the coal receives one cent per ton.
Finally, Montana's Corporation License Tax imposes a flat 6.75 percent
-tax on net income earned in the state, of which one-fourth is earmarked
for schools.
791
-------
D. Policy Options for Controlled Growth Rates
The problems attendant to growth cited in the previous section and
the interests of the various stakeholders cited in Section B can be ad-
dressed through various federal, state, and local policies. Such poli-
cies should deal realistically with the choices open to the western
coal-producing regions, recognizing the interdependence of rapid growth
and subsequent decline. "Every region which is declining today," accord-
ing to a report by the Old West Regional Commission,* "is so doing be-
cause the momentum of some earlier growth carried it to levels it could
not sustain."25 The vulnerability of these regions to the changing for-
tunes of extremely specialized economies suggests an approach "which is
neither opportunistically promotional nor dogmatically preservationist,
but which keeps local growth rates within a range to which the existing
communities can adapt without hardship."26 For these regions to avert
the boom-and-bust cycle to which they have been subject in the past, the
Old West Regional Commission's report concludes, "the new urban develop-
ment prospects arising from coal developments should not be regarded as
a means of 'saving' declining towns...."SE Policy options to achieve
desirable rates of growth can be divided into the broad categories of
nonfiscal instruments and fiscal instruments.
1. Nonfiscal Options
Prospects for land use controls at the federal level appear
dim since Congress has rejected federal land use legislation and has
failed to override presidential veto of legislation to implement land
*The Old West Regional Commission is an intergovernmental organization
consisting of the governors of North Dakota, South Dakota, Nebraska,
Wyoming, Montana, and federal representatives.
792
-------
use controls on federally owned coal lease tracts. However, some land
use controls are now indirectly applied by the federal government, for
example, in the EPA air quality control regions. Thus, existing legis-
lation may be sufficient to authorize some land use controls on the part
of federal agencies. The Bureau of Land Management and the Forest Serv-
ice, two agencies with substantial experience in multiple-use planning,
have established a land use plan for management of the Decker-Birney area
of southeastern Montana.26 Their plan, produced in cooperation with Mon-
tana officials and after extensive consultation with landowners and others
in the Decker-Birney area, seeks to accommodate the diverse interests of
livestock grazers, timber producers, recreationists , and coal producers.
The EPA could establish land quality categories, similar to its
air quality categories, to guide decision-makers on land use. Rather
than approaching energy development on a mine-by-mine basis or on the
basis of overall requirements, EPA could evaluate land use on the basis
of relevant impact factors. Such impact factors might include:
• Vegetative and wildlife production.
• Competing land use requirements (such as farming, ranching,
recreation, or residential use).
• Water consumption.
• Institutional and fiscal capacity of localities to absorb
population growth.
• Net energy considerations.
A system of land quality categories would help solve two problems that
are prevalent in environmental regulation—individual case-by-case
treatment on the one hand, and inflexible across-the-board rules on the
other hand. Instead, environmental standards could be applied to cate-
gories of conditions. For example, the need for reclamation could be
treated as something not necessary in all places and at all times but
only where some evident impact occurs. The needs of localities for
793
-------
assistance in accommodating different rates of population growth could
be treated similarly.
Various tools of growth management are available at state and
local levels. Montana, Wyoming, and North Dakota have enacted laws reg-
ulating the siting of synthetic fuels conversion facilities and electri-
cal generating facilities. These laws incorporate some of the regulatory
features mentioned above as impact factors in the context of possible
federal regulation. Their effect will undoubtedly be to impose some
state control over the scope, pace, and timing of energy development
within the state. Montana and several other states in the coal-producing
region have also enacted environmental protection legislation, which could
regulate energy development impacts. Cities and towns can control growth
by the indirect means of limiting the number of sewer or utility connec-
tions or limiting the reservoir capacity of municipal water systems. If
they wish to promote concentrated settlement patterns, they can adopt an
"urban service boundary" beyond which public services will not be ex-
tended. One successful policy instrument, put into practice by the town
of Ramapo, New York, in 1969, required phased construction of public
service facilities in parallel with land development. Ramapo's ordinance
tied the rate of population growth to the rate at which public capital
improvements could be financed. Other conditions besides those associ-
ated with timing can be attached to building and construction permits
within local jurisdictions. For example, a specific finding on the part
of a planning commission that sufficient public facilities exist may be
required as a condition of granting a particular building or construction
permit. In addition, local jurisdictions can adopt special-purpose zon-
ing ordinances (such as agricultural zoning, conservation zoning, devel-
opment district zoning, and down-zoning), and quotas or moratoria on
building and construction permits.27
794
-------
2. Fiscal Options
The federal government has a long tradition of aiding locali-
ties serving a national purpose which are adversely affected by their
efforts. For example, military bases may occupy land that would other-
wise belong to the city or county property tax base. However, federally
owned land is exempt from local property tax obligations. At the same.
time, the presence of the military base might create a heavy burden of
public expenditures for schools. Congress enacted legislation in 1950
to provide funds to school districts in areas affected by federal ac-
tivity.7 Public Law 874 was intended to aid school districts in financ-
ing current educational expenses. It now accounts for an average of 5
percent of the operating expenses of about 10 percent of the school dis-
tricts in the United States, containing about 30 percent of the nation's
public school enrollment. These payments continue as long as the federal
activity remains in the area. Public Law 815 provides financial assist-
ance for construction of school facilities in districts where the federal
presence creates a need for such new facilities. These laws could well
serve as a model for federal assistance to localities experiencing rapid
population growth under pressure of energy development.
With regard to development of oil in the outer continental
shelf, the Department of Commerce has recommended federal compensation
of coastal states adversely impacted by energy development.28 A similar
arrangement could be formulated for coal mining. Such compensation takes
three forms in the recommendation: (1) general revenue sharing, (2) ad-
verse impact grants, and (3) front-end loans.
General Revenue Sharing—A percentage of federal bonus bid and
royalty revenues could be earmarked for states affected based on impact
factors.
795
-------
Adverse Impact Grants—States could apply on an individual
basis to the federal government for assistance based on demonstrated
environmental, economic, or administrative costs associated with re-
source development.
Front-End Loans—States could receive low-cost federal loans
to finance public facilities and services needed to accommodate resource
development.
State governments can recover the costs of rapid population
growth by means of valuing and taxing all productive wealth. For exam-
ple, Montana enacted a 30 percent severance tax on coal, earmarking the
revenues for schools, roads, recreational facilities, conservation, and
reclamation. Reclamation bonds can be required as a condition of per-
mission to mine coal. Similarly, the posting of a bond to cover the cost
of expanded public facilities and services can be required.
The options discussed in this section do not offer a complete
solution to the problems of energy development, environmental protection,
and local growth. Many outstanding problems are not addressed, such as
the issue of surface owners' rights, water rights, as discussed more fully
in Chapter 19, and the allocation of resources to food and fiber production
ns well as energy production.
Although localities can limit population growth, the nation as
a whole cannot do so, given the fact of at least some national population
increase (even if at declining national birth rates). Nevertheless, while
it searches for patterns of settlement that serve national needs without
adversely affecting the quality of life, the nation can promote equitable
and orderly local growth.
796
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REFERENCES
1. R. Merton, "The Unanticipated Consequences of Purposive Social
Action," American Sociological Review (September 1936).
2. E. Morgenthaler, "A Town in Wyoming Finds an Industrial Boom is
Accompanied by Woes as Well as Wealth," Wall Street Journal (July
30, 1974).
3. L. Hicks, "Who Owns the Big Sky?" Sierra Club Bulletin (July-
August 1974).
4. Letter from North Dakota Governor Arthur Link to Senate Interior
and Insular Affairs Committee, May 15, 1974.
5. General Policies of the Western Governors' Regional Energy Office,
July 28-29, 1975, Policies 11 and 12.
6. Former Secretary of Interior Rogers Morton, speech delivered at
Western Governors' Conference, Denver, Colorado, January 1975.
7. Public Laws 874 and 815.
8. Letter from former Secretary of Interior Rogers Morton to Western
Governors, January 17, 1975.
9. M. Clawson, The Bureau of Land Management (Praeger, New York, N.Y.,
1965) .
10. N. Glazer, "Towards an Imperial Judiciary?" The Public Interest,
(Fall 1975) .
11. J. Sax, Defending the Environment (Knopf, New York, N.Y., 1971).
12. A. Leholm and L. Leistritz, "Profile of North Dakota's Coal Mine
and Electric Power Plant Operation Work Force," paper prepared for
presentation at the 35th Annual Meeting of the Montana Academy of
Sciences, Eastern Montana College, Billings, Montana, April 26,
1975.
797
-------
13. 1970 Census, U.S. Department of Commerce.
14. Effects of Coal Development in the Northern Great Plains, Northern
Great Great Plains Resources Program (April 1975).
15. E. Kohrs, "Social Consequences of Boom Growth," paper delivered at
American Association for the Advancement of Science Rocky Mountain
Meeting, Laramie, Wyoming, July 24-26, 1974.
16. R. Solow, "The Basic Economics of Scarce Natural Resources," paper
delivered at MIT Club of Northern California, Natural Resources
Conference, September 25, 1975.
17. J. Krutilla and A. Fisher, The Economics of Natural Environments
(Johns Hopkins Press, Baltimore, Maryland, 1975).
18. \V. Thompson, "Planning as Urban Growth Management," paper delivered
to the 57th Annual Conference of the American Institute of Planners,
Denver, Colorado.
19. R. Twiss, "Strategies for Planning in the Upper Colorado River
Basin, in A. Crawford and D. Peterson, Eds., Environmental Manage-
ment in the Colorado River Basin (Utah State University Press,
Logan, Utah, 1974).
20. "Anticipated Effects of Major Coal Development on Public Services,"
final report for the Northern Great Plains Resources Program, Bureau
of Reclamation and Institute of Applied Research, Montana State
University (January 1975).
21. A. Tsao, "Final Environmental Impact Statement for Colstrip Electric
Generating Units 3 and 4," Energy Planning Division, Department of
Natural Resources and Conservation (January 1975).
22. Revenue Codes of Montana, 1947, Section 84-301,
23. "The Costs of Sprawl," Real Estate Research Corporation, prepared
for the Council on Environmental Quality (April 1974).
24. W. Thompson, A Preface to Urban Economics (Johns Hopkins Press,
Baltimore, Maryland, 1965).
25. "Adaptation or Reversal: Policies for the Quality of Life in the
Economically Declining Parts of Montana, North Dakota, and Wyoming,"
Old West Regional Commission (February 1975).
798
-------
26. "Decker-Birney Resource Study," Bureau of Land Management and
Forest Service (April 1974).
27. Management and Control of Growth, Urban Land Institute (Washing-
ton, D.C. , 1975) .
28. "Report to the Marine Petroleum and Minerals Advisory Committee,'
Working Group on Impacts of Offshore Oil and Gas Development
(September 10, 1975).
799
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22—POPULATION GROWTH CONSTRAINED SYNTHETIC
LIQUID FUEL IMPLEMENTATION SCENARIOS
By Barry L. Walton
One approach to limiting the impacts of synthetic fuels production
in a region is to constrain the population growth rate of the community.
This chapter describes the preparation of scenarios on this theme and
presents several alternative scenarios.
Each synthetic fuels plant of building block size has a defined
labor force associated with its construction and operation phases. The
primary jobholders during these phases induce additional population in
the area through secondary support employment and families. The effect
of this induced population can be treated analytically by applying an
appropriate population multiplier to the labor force of the primary in-
dustry. This process can be used to construct a population profile for
each type of synthetic fuels building block plant. On the basis of
these profiles, detailed scenarios projecting the population increases
under given conditions of industrial development can be plotted for a
given region. The method can be used to construct scenarios that are
applicable to nearly any technology and relevant region.
To illustrate the procedure, the following pages contain a descrip-
tion of the steps involved in constructing a fuel production schedule for
a region that is limited by a planned population growth rate. Sample
scenarios are given that depict the effect of introducing, on a planned
schedule, coal mining and coal liquefaction or methanol production in
Campbell County, Wyoming, and oil shale development operations in
800
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Garfield and Rio Blanco counties, Colorado. A multiplier of 6.5 was
chosen lor reasons explained in Chapters 12 and 23.
It is important to note that the profile for a 100,000 B/D
(16,000 m3/D) coal liquefaction plant is essentially identical to a
250 million cubic foot per day (23 million m3/D) coal gasification
plant. Thus, the method immediately possesses useful generality.
Step One: A population profile for each type of facility is
prepared. Figure 22-1 shows the resulting population profiles
for coal mines, coal syncrude, methanol, and oil shale build-
ing blocks. Sources of the data for the building block facil-
ities are Chapters 4 and 6. The profiles in Figure 22-1
already include the effect of the population multiplier of
6.5 (assuming a constant population during each yearly inter-
val) . Aggregation of the work force and the associated pop-
ulation into the profile facilitates construction of the
scenarios and yields reasonably realistic population profiles.
Step Two: The current population for the county or region is
established from census data or by using population estimates
from local government officials. For this study, the esti-
mated 1975 populations for Campbell county, Wyoming (17,000),
and for Garfield and Rio Blanco counties combined (23,500)
were obtained from local planning officials.
Step Three: Annual growth rates of 2 percent, 5 percent and
10 percent compounded continuously were applied to the cur-
rent population to determine a set of theoretical population
growth trajectories for the appropriate region. Figures 22-2
through 22-10 show growth curves of 2 percent, 5 percent,
and 10 percent annual growth for the two selected areas.
801
-------
Step Four: Paper cut-outs of the building blocks from Fig-
ure 22-1 laid on the population graph made during Step Three
enable rapid construction of the final aggregate population
projection. Rearranging the cut-outs on the population
growth graph allows any growth rate to be easily approxi-
mated. (Use of separate cut-outs of the construction and
operating phases greatly aids in experimentation and in the
drawing of the final profile.) Figures 22-2 through 22-7
show a number of alternatives for Campbell county, Wyoming,
derived by this method; Figures 22-8 through 22-10 show a
number of alternatives for Garfield and Rio Blanco counties
in Colorado. Once the start-up date for each plant is
determined for each scenario, the net fuel production sched-
ule is fixed and can be calculated. The insets to each
figure show the fuel production schedule and water consump-
tion needs for each scenario that were obtained by using
the fuel output and water requirement scaling factors from
tables in Chapter 6.
The implications of these population growth constrained scenarios
are reported in Chapter 23.
802
-------
00
o
CO
25
| 20
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O
tf 5
3 10
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I 5
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OPERATION
TIME-
A. COAL LIQUEFACTION 100,000 B/D
OPERATION
TIME
B. COAL LIQUEFACTION 30,000 8/D
OPERATION
TIME
C. OIL SHALE 100,000 B/D
f YEARS
OPERATION
TIME
20
w
I"
»..
i'
UJ
OL
30
25
120
PEOPLE -t
_ «~
U>OU>
PEOPLE -
OPERATION
TIME •-
E. METHANOL 50,000 OEB/D, STRETCHED OUT CONSTRUCTION PERIOD
OPERATION
TIME-
F. METHANOL 50,000 OEB/D, NORMAL CONSTRUCTION PERIOD
^$3
B
YEA^^
?$^x/V>X^->?-x?*
^CONSTRUCTION;
OPERATION
D. OIL SHALE 50,000 B/0
TIME-
G. METHANOL 25,000 OEB/D
FIGURE 22-1. TOTAL POPULATION ASSOCIATED WITH INDIVIDUAL PLANT CONSTRUCTION
AND OPERATION BUILDING BLOCKS. All building blocks include the mines
that supply the plants. The actual labor force is multiplied by 6.5 to account
for induced secondary employment and families. The data for these building
blocks come from the scaling factors derived for the Maximum Credible
Implementation Scenario.
-------
Q
190
180
170
160
150
140
130
120
I 110
o
.
3
O
- 100
o
i- 90
2
0.
g 80
70
60
50
40
30 -
20 -
t
10 -
0 -
1975
600
500
400 -
9
I
O 300
g ZOO
8:
100 -
—
1975
1980
1985
1990
1995
2000
1975
M
1985
1990
1995
100,000 B/D
COAL SYNCRUDE
100,000 B/D
COAL SYNCRUDE
—I
1 1
( I )
(2 )
PERMANENT LABOR FORCE AND
ASSOCIATED POPULATION
CONSTRUCTION LABOR FORCE
AND ASSOCIATED POPULATION
30,000 B/D SYNCRUDE
50,000 OEB/D METHANOL
I960
1985 1990
YEAR
1995
2000
FIGURE 22-2. EFFECTS OF THE MAXIMUM CREDIBLE IMPLEMENTATION
SCENARIO UPON POPULATION IN CAMPBELL COUNTY,
WYOMING. Assumes that one quarter of all the Scenario's
development in Wyoming occurs in Campbell County
This assumption is expected to be on the low side.
804
-------
PERMANENT LABOR FORCE AND
ASSOCIATED POPULATION
CONSTRUCTION LABOR FORCE
AND ASSOCIATED POPULATION
REPRESENTS CONTRIBUTION
OF MINES
1975
1980
1985 1990
YEAR
1995
2000
FIGURE 22-3. FIVE PERCENT CONSTRAINED POPULATION GROWTH
RATE SCENARIO FOR CAMPBELL COUNTY, WYOMING
ILLUSTRATED WITH COAL LIQUEFACTION PLANTS AND
ASSOCIATED MINES. The larger sized plants cause rapid
changes in population.
805
-------
190
180
170
160
150
140
130
120
-S 110
c
o
100
90
§ 80
Q.
70
60
50
40
30
20
:
o
m
u 200
o
100
Ol
1975
1980
1985
1990
1995
PERMANENT LABOR FORCE
AND ASSOCIATED POPULATION
CONSTRUCTION LABOR FORCE
AND ASSOCIATED POPULATION
REPRESENTS CONTRIBUTION
OF MINES
1975
1980
1985
1990
1995
2000
YEAR
FIGURE 22-4. MODIFIED FIVE PERCENT CONSTRAINED POPULATION
GROWTH SCENARIO FOR CAMPBELL COUNTY, WYOMING
ILLUSTRATED WITH COAL LIQUEFACTION PLANTS AND
ASSOCIATED MINES . By building only the smaller sized
coal liquefaction plants, large fluctuations in population
can be avoided
806
-------
190
PERMANENT LABOR FORCE
AND ASSOCIATED POPULATION
CONSTRUCTION LABOR FORCE
AND ASSOCIATED POPULATION
6MINES @5MT/Y
@5 MT/Y
=—•—
E MINES
1975
1980
1985
1990
1995
2000
YEAR
FIGURE 22-5. FIVE PERCENT CONSTRAINED POPULATION GROWTH
SCENARIO FOR CAMPBELL COUNTY, WYOMING IN
WHICH ONLY COAL MINES ARE DEVELOPED. Under
these conditions growth in population can be made very
smooth. By 2000, 54 mines, each producing 5 million
tons/year, would be exporting 270 million tons of coal
per year
807
-------
190
ISO
170
160
150
140
150
120
f 110
o
i
£ 100
I
o
»= 90
O 80
Q.
70
60
50
40
30
20
:
o
0 250
I- il200
-
50
o1—
1975
1930
1990
1995
2000
I 1 OPERATING LABOR FORCE AND
1 ' ASSOCIATED POPULATION
CONSTRUCTION LABOR FORCE
AND ASSOCIATED POPULATION
(I) 50,000 OEB/D
1975
2000
FIGURE 22-6. FIVE PERCENT CONSTRAINED POPULATION GROWTH
SCENARIO FOR CAMPBELL COUNTY, WYOMING
ILLUSTRATED WITH COAL TO METHANOL CONVERSION
PLANTS. Severe fluctuations in population ore apparent.
808
-------
190
180
170
160
150
140
130
120
I 110
a
r
O
~ 100
i
O
5 90
_i
3
a.
o 80
70
6C
p 300
1 °25°
- o a 200
2 HI
O 150
0*0 100
< 5
40
:
0
1975
0
1975
I960
1985
1990
1995
OPERATING LABOR FORCE AND
ASSOCIATED POPULATION
CONSTRUCTION LABOR FORCE
AND ASSOCIATED POPULATION
J
1980
(985
YEAR
1990
1995
2000
FIGURE 22-7. F\VE PERCENT CONSTRAINED POPULATION GROWTH
SCENARIO FOR CAMPBELL COUNTY, WYOMING
ILLUSTRATED WITH COAL TO METHANOL CONVERSION
PLANTS WITH EXTENDED (5 YEAR) CONSTRUCTION
PERIODS . By extending the construction time, the
fluctuations in growth can be avoided.
809
-------
PERMANENT LABOR FORCE
AND ASSOCIATED POPULATION
CONSTRUCTION LABOR FORCE
AND ASSOCIATED POPULATION
100,000 B/D
OIL SHALE
100,00 i B/D OIL SHALE
50,000 B/D OIL SHALE _
50,000 B/D OIL SHALE
1975
1980
1985 1990
YEAR
1995
2000
FIGURE 22-8. FIVE PERCENT CONSTRAINED POPULATION GROWTH
SCENARIO FOR OIL SHALE DEVELOPMENT IN
GARFIELD AND RIO BLANCO COUNTIES, COLORADO
810
-------
BO 85 90 95 2000
PERMANENT LABOR FORCE AND
ASSOCIATED POPULATION
CONSTRUCTION LABOR FORCE
AND ASSOCIATED POPULATION
1975
1980
1985
1990
1995
2000
YEAR
FIGURE ZZ-9. TEN PERCENT CONSTRAINED POPULATION GROWTH
SCENARIO FOR OIL SHALE DEVELOPMENT IN
GARFIELD AND RIO BLANCO COUNTIES, COLORADO
811
-------
80 85 90 95 2000
OPERATING LABOR FORCE
ASSOCIATED POPULATION
CONSTRUCTION LABOR AND
FORCE AND ASSOCIATED
POPULATION
1975
1980
1965
1990
1995
YEAR
FIGURE 22-10. MAXIMUM CREDIBLE IMPLEMENTATION SCENARIO
FOR OIL SHALE DEVELOPMENT IN GARFIELD AND
RIO BLANCO COUNTIES, COLORADO. The resulting
annual population growth rat* it about 17 percent.
2000
812
-------
23--COMPARATIVE IMPACTS OF CONTROLLED AND
UNCONTROLLED URBANIZATION
By Peter D. Miller
A. Introduction
Growth and prosperity have traditionally been linked. As human
groups move beyond bare subsistence and begin to produce more than they
consume the surplus creates a form of wealth. Specialization of labor,
industrial organization, and technological efficiency increase productiv-
ity and thus support larger populations. The capacity to generate new
wealth, built into the process of growth, soon becomes dependent on
growth. New products and new ways of generating demand are harnessed
to the engine of growth. Jobs, firms, and entire industries become
bound up with more and more growth. Annual increases in gross national
products and national incomes are registered in the confident belief that
they mean a better standard of living for all. Yet many observers now
doubt whether the traditional alliance of growth and prosperity is still
viable.
Critics of growth have made three kinds of arguments that merit the
attention of anyone contemplating the prospect of more growth. The
first is that "spaceship earth" has certain natural limits—of resources,
of carrying capacity, of the necessities of life—that are rapidly being
approached at present rates of depletion. While the capacity to generate
wealth has indeed been increased by growth, so the second argument goes,
control of the means of production has concentrated this wealth in a few
hands, leaving many in poverty. The third argument is that social costs,
negative externalities, spillover effects, and other unanticipated
813
-------
consequences of growth have polluted air, water, and land to such an
extent as to make life unlivable.1 None of these ideas is particularly
new. Malthus, the first prophet of overpopulation, was preoccupied with
natural limits. Inequitable distributions of wealth resulting from con-
trol of the means of production were, of course, a major concern of Marx
and his followers. Externalities were first identified by the economist
Alfred Marshall. If these ideas have acquired more cogency in recent
years, it is because the effects they point to are visible on a local
as well as the global level.
The following analysis focuses on the comparative impacts of two
levels of growth on two specific areas, the Powder River Basin of Wyoming
and the Piceance Basin of Colorado. The dynamics of growth are described
in such a way, however, that they can be generalized to other areas.
With appropriate modifications for technological variables, the analysis
is applicable to large-scale energy production, mining, and industrial
development in general.
B. Impact of the Maximum Credible Level of Synthetic Fuel Production
The "maximum credible" (described in Chapter 6) case describes the
situation in which real-world constraints other than technical and
physical limits are absent. It is the level of synthetic fuels produc-
tion that would be achieved if labor could be attracted in sufficient
numbers, if there are no obvious bottlenecks in the supply of steel,
pipe, and other materials, if there were no obvious shortage of capital,
if deliveries of "walking draglines," to scoop up strippable coal were
assured as soon as they were needed, if residents of the coal mining
regions and their elected representatives had no objections to the in-
dustrialization plan, if there were no lawsuits by environmenalists,
ranchers, Indians, or anyone else who could be adversely affected in
fact by the Federal Coal Leasing Program, and if world energy prices
814
-------
remained stable for the foreseeable future. The maximum credible case
is thus by no means to be construed as a prediction, but rather as a
theoretical upper limit to the level of production. Other factors, as
we shall see below, begin to constrain development of synthetic fuels
long before the theoretical upper limit is reached.
1. Population
Figure 22-2 in the previous chapter shows the population that
would be generated in Campbell County, Wyoming, from coal liquefaction
plants, methanol plants, and coal mines just sufficient to fuel them
(captive mines only), according to the maximum credible level of produc-
tion. In Figure 22-1, it is assumed that Campbell County would produce
one fourth of the synthetic crude oil produced in Wyoming, probably a
low figure. The present population of 17,000 would double by 1985,
triple by 1988, and increase by a factor of 7 before the end of the
century. Population density in the county, now 3.5 people per square
mile (0.74 people per km3), would be 20 to 25 (7.7 to 9.7 people per
km?). Compared to that, the current annual rate of 5.5 percent in the
county and Gillette's 7 percent seems leisurely. Since the county is
experiencing great difficulty in keeping up with the growth that has
already occurred, it would undoubtedly experience even greater diffi-
culty in the maximum credible case. It is evident that the major in-
crements of growth come from the construction of coal liquefaction and
methanol plants. The operating labor force and associated population
for a 100,000-B/D (16,000 m3/D) coal liquefaction plant are also sub-
stantial.
Figure 22-2 shows steep peaks and valleys for coal-related
employment. This in part results because data are presented on a year-
by-year basis, while in fact employment would be added and would taper
•off more gradually. However, even if the data were presented on a daily
815
-------
basis, peaks and valleys would still exist, only with rounded corners.
In short, there would be severe discontinuities in the local economy and
the fortunes of the county would swing up and down in response to the
fortunes of the coal mining industry. With extremely large units of
production, it is almost impossible to avoid such instability.
2. Housing
According to the 1970 census, Campbell County ranked second
highest in Wyoming in the proportion of its housing containing one or
more persons per room—14 percent. This proportion has probably gone up
in the intervening five years. Nevertheless, if the same ratio of dwell-
ing units to population (3.4) were maintained for future years, the
maximum credible case would require the construction of 5000 additional
housing units by 1985, 10,000 by 1988, and 30,000 by the end of the
century. Failure to meet these requirements would result in additional
real estate speculation and extremely high rents, probably on a scale
that would drive out those who did not own property and whose wages did
not compensate for these increases. Campbell County's 1970 median rent
of $140 a month was already the highest in the state. Rents have gone
up by a factor of 2 or 3 with a 5-mile (8 km) radius of Gillette during
the last 5 years, according to the Campbell County Planning Department.
The actual limits of local growth would probably be reached well before
synthetic fuels production attained a small fraction of its maximum
technically-credible level.
3. Age Distribution and Schools
If present trends continued, the age distribution of the in-
coming population would be younger than average. In 1970, Campbell
County had the highest proportion of under-18 population in Wyoming,
•42 percent. Its school-age population (5 to 18 years of age) was about
30 percent of the total in 1970, and has risen since then to about
816
-------
one-third the total population. If that proportion remained no more
than one-third, the number of school children in 1988 would be equiva-
lent to the county's present total population, in the maximum credible
case. The school population alone would be a medium-sized town of
40,000 by the end of the century. Classroom expenditures and school
personnel salary expenditures would be quite large.
4. Public Expenditures
Total county governmental expenditures, using the correlation
developed by the Bureau of Reclamation,8 would be over $10 million a
year in 1985, $16 million a year by 1988, and $38 million a year (con-
stant 1970 dollars) by tne end of the century. Per capita expenditures,
currently $260, would rise to about $290 in 1985, $310 in 1988, and $320
by the end of the century (constant 1970 dollars). If 1970 proportions
were maintained, about half would go to schools, an eighth for highways,
one-twelfth for public welfare and public health, and the rest for other
,'
expenses. These expenditures would be a bare minimum, inasmuch as the
raw data from which the correlation between population and expenditures
was developed came from counties that had delayed necessary expenditures
as long as possible. Unless tax structures were overhauled, the bulk of
these public expenditures would be financed by old and new individual
residents and/or by future generations through long-term debt obliga-
tions. The maximum credible case of synthetic fuels production, then,
would impose substantial, perhaps insurmountable burdens on local gov-
ernment .
C. Development Constrained by a 5 Percent Annual Growth Rate
Relationships between the global trends mentioned above and local
impacts have been brought home to the American people in recent years.
Natural limits are readily understandable to anyone who has waited in a
817
-------
gasoline line, paid high prices for groceries, or had a well run dry.
When local taxes go up as the natural resources of a region are ex-
tracted, inequitable income distribution becomes a topic of concern.
Moreover, the crowding, tension, and other conditions of boomtown growth
provide ample evidence of the unfortunate by-products of rapid urbaniza-
tion. These considerations suggest that the largest possible scale of
development may not always be equivalent to the best scale of develop-
ment for all concerned.
To meet these concerns, we have treated local rates of population
growth as a factor that might constrain industrial development. Just
as there are limits to what can be done with available materials and
technology, there are limits to how fast a region can grow without im-
pairing a decent quality of life. In many cases, these limits are im-
posed by the courts or the political process, and so they vary according
to the tolerance of affected interest-groups. In other cases, these
limits are breached at a cost that often appears in hindsight to have
been too great to pay. At that point, costly remedial measures may have
to be taken. Although planners disagree on what an optimum growth rate
might be in theory, they sense that it is not large. A planner in one
rural western county said he considered growth rates between 1 and 2
percent a year to be ideal. Some planners have referred to a 5 percent
annual growth rate as "hyper-urbanization." There is no magic number
that can guide all development planners in all circumstances; however,
an approximate indication can be drawn from the experience of cities,
towns, and counties that viewed their growth rates as excessive.
*The annual growth rate, r, is derived from the formula P = P (1 +r)n
*C 1
where P is the population at the beginning of the time period, PS is
the population at tne end of the time period, and n is the number of
years in the time period.
818
-------
Santa Clara County, California (San Jose), which is generally con-
ceded to be an example of the unfortunate consequences of uncontrolled
development, grew at an annual rate of 5 percent between 1960 and 1970.
Santa Barbara and Riverside Counties, two other fast-growth areas of
California, added population at the rate of more than 4 percent a year.
Boulder, Colorado, another example of what many consider "runaway growth,'
increased its population every year at a rate approaching 6 percent. In
Phoenix, Arizona, and Albuquerque, New Mexico, two cities of the South-
west where local growth has become a major public concern, the rates
were under 3 percent. Thus it seems reasonable to select 5 percent
additional growth per year as an upper limit of the rate communities can
tolerate. Few would consider such a figure ideal, as many adverse im-
pacts appear well below that rate, but almost all would agree that annual
growth rates exceeding 5 percent impose severe burdens on community in-
stitutions, services, and resources. By using such a figure hypotheti-
cally as a constraint on development, we do not mean to suggest that
f1
population can be limited by law or regulation. Instead, our intention
is to show the consequences of controlling growth on the basis of popu-
lation (by whatever means society deems acceptable), contrasted with the
impact of development constrained only by technical and physical factors.
Although economic growth is usually defined as increased per capita
output, such a measure is not useful in small towns and surrounding
regions because of the difficulties of disaggregation and because these
are not self-sufficient economic entities. Growth is conceptualized
here as urbanization and is measured by increases in population. Eco-
nomic growth and urban growth are of course highly correlated, but the
definition used here does not assume growth is tied to increased per
capita output or to net welfare.3
819
-------
1. Smooth Growth Rates as a Mathematical Approximation
Rates of population growth are not always uniform from year to
year. In reality they may vary a great deal, and a compound annual
average taken between two points in time smooths out these differences.
For example, a town could grow rapidly at 10 percent a year for 5 years,
then slow down to 0.25 percent for the next 5 years, and still finish
out the 10-year period with a 5 percent annual growth rate overall. If
continuity and stability were of any value to the townspeople, this would
hardly be a desirable state of affairs. If they sought to maximize these
values, they would try to add no more than a fixed percentage to their
number every year, apportioning new residents over time as evenly as
possible. In practice, of course, they could not always attain this
ideal. However, a smooth rate of growth represents a reasonable objec-
tive, given the available alternatives. Hence the use of a constant
growth rate as a possible constraint on development is realistic.
2. Selection of Base Year
The projection of growth rates into the future is sensitive
to the base year chosen. It makes a great deal of difference whether a
given constraint might start in 1960, 1965, 1970, or 1975. The smaller
the population base, the smaller the number of people added by fixed
percentage increases. For any period when population is increasing,
earlier base years will tend to depress future values, while later base
years will elevate future values. Gillette, Wyoming, for example, num-
bered 3600 people in 1960, 7200 in 1970, and was estimated by the county
planner to contain 11,000 people in 1975. If the base year of 1960 were
selected, and 5 percent a year were added to its population then, it would
gain fewer than 2300 people in 10 years. The same growth rate and the
same time period applied to the 1975 population adds nearly 7000 people.
Therefore we have selected the current year's population as the starting
820
-------
point for all projections, even though growth rates may have exceeded
5 percent in previous years.
3. Selection of Geographical Base
Future values are also sensitive to the geographical base
chosen. Larger geographical units, with more people in them to start
with, can accommodate larger numbers of additional people than can
smaller geographical units with fewer people, assuming equal growth
rates. Five thousand new people added to Detroit would hardly be
noticed, but the same number added to Gillette create substantial prob-
lems. Three principles governed selection of the geographical base:
• Since social impacts are often obscured when the nation
as a whole or even the Northern Great Plains as a whole
is examined, it was necessary to narrow the focus to where
visible impacts actually take place—where people live,
work, shop, play, or pass the time of day.
• A commuting distance between home and work of more than
35 miles (56 km) was considered impractical for the vast
majority. In a similar problem involving selection of the
boundaries of a regional housing market, Sternlieb et al.,
found that 86 percent of the commuters sampled lived within
35 miles (56 km) of their place of work.4 The quality and
layout of roads were examined in deciding how far people
might live from where they work. Existing towns within
35 miles (56 km) from the place of work were considered
the most likely areas of new settlement.
• A geographical base could have been selected by including
all the area within a 35 mile (56 km) radius of adjacent
places of work. Populations for the parts of counties
included in such a circle could then have been estimated
from known population densities. For the sake of admin-
istrative simplicity, however, counties were used as the
geographical base. The county is the planning unit that
would have to react to impacts that occur, and counties
have been selected so as to be broadly inclusive of the
vast majority of immigrants. Growth rates would not be
identical in every part of a county (unless immigrants
happened to settle proportionally in exactly the same
821
-------
places as older residents). Instead, existing towns could
be expected to capture a greater proportion of new resi-
dents than their present proportion of older residents.
Gillette, Wyoming, for example, had slightly more than
half of Campbell County's population in 1970. Its
"capture rate" of new residents will, however, probably
be at least 80 percent. At that rate, if the county
grows at 5 percent a year, Gillette will grow at about
7 percent a year. This pattern would pertain to all
counties in which the "capture rate" of towns will ex-
ceed their present population share, as is generally the
case in the West. Figure 23-1 illustrates this pattern.
The use of a county-wide average growth rate thus tends
to underestimate impacts on towns.
4. Employment-to-Total-Population Multipliers
Labor requirements for the coal mines, oil shale mines, and
synthetic fuels production facilities have been derived from industry
sources and are explained in Chapter 4. The ratio of total population
3%
FIGURE 23-1. GROWTH RATES ARE HIGHEST NEAR THE CENTER OF
ACTIVITY AND FALL OFF WITH DISTANCE. The
radii shown are for purposes of illustration only;
actual radii depend strongly upon the actual location.
822
-------
to size of the labor force, known as the population multiplier, is usu-
ally derived from an "export base model" in which various assumptions
are made about the dynamics of the local economy and demographic charac-
teristics of immigrants. The export base model assumes that basic indus-
trial employment generates additional services and related secondary
employment. Urban growth rates are assumed to be more or less thoroughly
determined by expansion of the industrial (export) base. It is not
always clear, however, that the cause-and-effect relationship proceeds
only one way. The efficiency of the local service industries and of
local public management in fact often determines the rate of "basic"
industrial growth.5 The model also assumes that sufficient labor is
available and can be attracted to the town at whatever wages it may be
necessary to pay. If the export base model is relied on for precise
population predictions, its assumptions about the direction of causality
and the likelihood of attracting labor are likely to yield inaccuracies.
If it is used only to compare two hypothetical growth rates, as it is
here, the oversimplifications are relatively harmless. The multiplier
is the product of two numbers: locally generated secondary employment,
and average family size. If 2.6 indirect local jobs are necessary for
every industrial job, and if average family size is 2.5, the multiplier
will be 6.5. Figure 23-2 shows schematically the basis for population
multipliers. Total population added can then be estimated by multiplying
the industrial labor force by this number.
For precise predictions of future population, several refine-
ments are possible. An input-output model of the regional economy could
be constructed, and direct employment, secondary employment, and multi-
pliers could be calculated for each industry. Multipliers vary accord-
ing to the size of the community because larger towns and cities already
have some existing capacity to provide needed public and private serv-
•ices. Smaller towns, on the other hand, have less capacity to start
823
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Resource Mining and Conversion Employment
Mining
Miners
Managers
Conversion
Facilities
Operators
Managers
Related
Periphera
Employme
i •
i .
nt
Support
Employment
Created by Domestic
Requirements of
Employees and Families
Families Associated with Foregoing Employment
FIGURE 23-2. BASIS OF POPULATION MULTIPLIER CONCEPT
with and therefore require greater additional secondary employment.
Since the propensity to shop locally affects the size of the multiplier,
distance from major trade centers could be taken into account in select-
ing an accurate predictive value. A lower multiplier could be used for
the construction labor force than for the operating labor force, on the
assumption that fewer construction workers will bring their families.
Finally, labor force participation rates may be broken down by age and
sex to allow for varying demographic characteristics of immigrants. A
model incorporating these and other elements has been constructed for
the U.S. Department of Agriculture,6
Our purpose here, however, is not to predict total population
resulting from all industries but to compare the impacts of two hypo-
thetical levels of development in mining and synthetic liquid fuels
production only. These two hypothetical levels of development are
constrained in one case by technical and physical factors only, and
824
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in the other case by a 5 percent annual growth in population. Neither
of these constraints will be the operative limits in real life. A mul-
tiplier of 6.5 has been selected for the Powder River Basin of Wyoming
and the Piceance Basin of Colorado. Because towns in those regions are
presently small, and because mining and manufacturing usually have large
multipliers, there is good reason to believe that a multiplier of 6.5
underestimates actual added population. The likeliest sort of error in
such an analysis, then, would be to understate the severity of local
impacts that could be expected to occur.
D. A 5 Percent Annual Growth Rate in Campbell County
If Campbell County added 5 percent a year to its population in the
future, its growth rate would approximately duplicate what it has ex-
perienced in the past 5 years (1970-1975). Figure 22-3 depicts an
attempt to fit a combination of small and large coal liquefaction plants,
along with associated coal mines, under a 5 percent growth curve. Phased
to minimize discontinuities, the population profile still exhibits minor
jumps during years of peak labor force in the construction of the small
liquefaction plants. Major peaks and valleys appear after 1990, when
construction of the large liquefaction plants would begin. Even limiting
production capacity to 300,000 B/D (48,000 m3/D) by the end of the cen-
tury, the necessary facilities still could not be accommodated within a
5 percent growth rate, as the figure shows. Further study of Figure 22-3
reveals that a 5 percent growth rate is practically incompatible with
construction of the extremely large, 100,000 B/D (16,000 ms/D) liquefac-
tion plants. One would have to wait until 1990 to begin construction of
such a facility (doing nothing until then) to keep additional population
within the 5 percent growth constraint.
825
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1. The Alternative of Building Smaller Plants
Figure 22-4 (Chapter 22) depicts an alternative that smoothes
out the rate of development considerably—building relatively small
(30,000-B/D or 4800 m3/D capacity) liquefaction plants only. This would
create a 210,000-B/D (34,000 m3/D) capacity by the year 2000, compared
with a 290,000-B/D (46,000 m3/D) capacity in the case of both large and
small plants, and compared with a 400,000-B/D (64,000 m3/D) capacity in
the maximum credible case. Although the growth rate depicted by Fig-
ure 22-4 would actually be closer to 6 than to 5 percent until after
1990, employment would not be subject to massive increases and declines.
Instead, it would rise more or less steadily if start-up construction of
succeeding plants were phased to coincide with final year construction of
preceding plants.
Assuming that housing in Campbell County would become neither
more nor less crowded than it is at present (i.e., that the ratio of
dwelling units to people would be constant), necessary additions to the
housing stock would be substantial although not nearly as large as those
required by the maximum credible case. As population rose in a 5 percent
growth rate from its present 17,000 to about 57,000 by the end of the
century, additional (cumulative) housing requirements would be as fol-
lows: 1700 by 1980, 4300 by 1985, 6400 by 1990, and 12,000 by 2000.
While these requirements are certainly modest compared to those of the
maximum credible case, they would still mean adding between 400 and 500
new dwelling units a year, a substantial effort for a small or medium-
sized town. In practice, a large proportion of these would be mobile
homes, and some additional crowding would result from any shortfall in
the provision of housing.
Assuming the school-age population remained one-third of the
total, the county school system would have to absorb nearly the
826
-------
equivalent of its 1970 pupil population by 1980, under the 5 percent a
year growth constraint. There would be 7500 pupils in 1980, more than
10,000 in 1985, 12,500 in 1990, and more than 19,000 by the end of the
century. Demands for classroom space, teachers, and administrative
capacity would rise accordingly. In contrast with the maximum credible
case, increased requirements would be steadier, more predictable, and
approximately half the size. However, the increase would still be sub-
stantial in the near-term when financing would be the most difficult
to obtain, and some crowding, double sessions, increased pupil-teacher
ratios, etc., could be expected if construction and organizational de-
velopment fell behind schedule. Although impacts would not be of the
same order as those in the maximum credible case, they could still be
characterized as moderately severe.
Using information from Reference 2, public expenditures in
Campbell County in constant 1970 dollars would total $6.7 million a
year in 1980, $9.4 million a year in 1985, $11 million in 1990, and
818 million in the year 2000. Major spending differences between the
growth-constrained case and the maximum credible case would only begin
to show up after 1985. Prior to 1985 (in the hypothetical cases de-
picted in Figures 22-2 and 22-4, population growth would advance fairly
steadily in both cases. The discontinuous growth exhibited by the maxi-
mum credible case would yield no benefits in reduced expenditures
because the county would only have to gear up again for resumed growth
after momentary declines. Thus its expenditures in all likelihood
would not decline along with temporary losses of population, but would
continue to climb for several years after any leveling-off in growth
rate. After 1985, annual expenditures in the growth-constrained case
would be about half the annual expenditures in the maximum credible
case. On a per capita basis, county expenditures would rise from $262
currently to $290 in 1980, $295 in 1985, $300 in 1990, and $310 in 2000
827
-------
(constant 1970 dollars). Differences between these values and com-
parable values associated with the maximum credible case are of the
order of only a few dollars. Individual tax burdens in the maximum
credible case would be only slightly higher than those in the growth-
constrained case. Because much greater numbers of people would be pay-
ing the slightly higher taxes, the differences between the two tax rates
would tend to be minimized. As far as local governmental capacity is
concerned, the chief advantage of the growth-constrained case would be
to allow the county to defer necessary expenditures for a longer time.
Slower growth would provide more flexibility and would help prevent the
formation of crises such as have occurred in the recent past.
2. The Alternative of Exporting Coal from the Region
Some local and state officials have occasionally expressed a
preference for a policy of having coal extracted and transported else-
where to be processed. The advantage of the "strip it and ship it"
philosophy, for these officials, is that mining activities in themselves
would not disrupt the region as much as would be combination of mining
and conversion to synthetic fuels at the site. The most disturbing
impacts, as noted above, come from construction of extremely large
industrial facilities in a relatively short span of time. Moreover,
the permanent labor forces associated with liquefaction and methanol
plants are only slightly less than the peak-year construction labor
forces. Thus large numbers of people would be required both to build
and to operate these facilities. Compared with these numbers, the
labor force and associated population brought about by coal mining
alone would be small. Figure 22-5 shows that a growth rate of only
2 percent a year would be compatible with extraction of about 90 million
tons (8.1 billion kg) of coal a year by the year 2000. Constrained only
by a 5 percent a year growth in population, Campbell County could mine
828
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270 million tons (240 billion kg) of coal a year by the year 2000. The
labor force and associated population in coal mining alone is so small
that it would allow local and state officials much greater regulatory
flexibility in choosing appropriate growth rates. While conversion
facilities are not practical below a certain size and level of employ-
ment, coal mines are practical to operate in a variety of sizes. A
more than adequate amount of coal extraction is compatible with growth
rates generally regarded as manageable.
3. The Alternative of a Longer Construction Period
One cha-racteristic of coal liquefaction and methanol plants
that makes them difficult to adapt to a small town is their short con-
struction period. With a short, say, three-year construction period,
the distribution of work throughout time is typically uneven: moderate
levels of effort during the first and third years, intensive level of
effort during the second year. This unevenness is probably unavoidable
during a short construction period because some allowances must always
be made for start-up time, recruiting a large work force, and proper
sequencing of the installations of parts of the plant. Figure 22-6
depicts a possible construction and operation schedule for four small
(25,000 OE B/D or 4000 OE m3/D) and two large (50,000 OE B/D or 8000
OE m°/D) methanol plants. This schedule can almost be accommodated
within a 5 percent annual growth constraint, except for the peak year
of construction effort. This feature clearly creates sharp jumps and
drops in the demand for labor and hence in associated population. A
region subject to this instability would require either a highly mobile
labor force or some other source of local employment to take up the
slack during periods of lesser coal-related employment.
The incentives for a firm to minimize the construction period
are clear. A plant under construction is tying up capital nonproductively,
829
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and meanwhile there is interest to pay on borrowings to finance con-
struction (unless sufficient equity financing is available). The in-
centives for the public to have the construction period lengthened are
equally clear. As Figure 22-7 shows, it is possible to smooth out the
rate of population growth considerably by substituting a 5-year for a
3-year construction period. Periods of unemployment are reduced almost
to zero, and the only period of very sharply rising demand for labor
occurs at the onset of construction of the first large methanol plant.
This stability brings obvious advantages to public officials, who can
plan for the expansion of services, housing, etc., more readily when
growth is steady than when there are violent upswings and downswings.
E. The Maximum Credible Level of Oil-Shale Mining and Retorting—
Piceance Basin
Fewer alternatives are available in oil-shale development than in
coal development because it is not practical to retort oil shale (ex-
tract crude oil from shale rock) far from the site where it is mined.
Transportation of oil shale over long distances could not possibly com-
pete economically with transportation of the crude oil product (after
upgrading) through pipelines. Oil shale must be mined and retorted at
the site or not at all. Thus the option of developing a relatively
simple mining operation without an associated industrial complex does
not exist.
Abundant deposits of oil shale are found in the Piceance Basin, a
remote area of the Rocky Mountains' Western Slope, located in Rio Blanco
and Garfield Counties, Colorado. The two counties currently have a com-
bined population of 23,500 (1975 local planners' estimates). About half
this number live in four towns: Meeker and Rangely in Rio Blanco County,
and Rifle and Glenwood Springs in Garfield County. Grand Junction, to
the south, is presently a major population center and could be expected
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to experience some impacts associated with oil-shale development in later
years after highway access from the resource development sites was improved.
It has been excluded from the unit of analysis considered here, however, on
the basis of principles described above: (1) Rio Blanco and Garfield Counties
are small enough in population and in land area to form a coherent planning
unit that would show the effects of proposed development. Yet they are not
so small that those effects would be distorted. Their land area is
6300 square miles (16,000 km2) compared with 4800 in Campbell County,
Wyoming. Adding Mesa County (Grand Junction) would create a land area
too large to behave as a unit; (2) The only heavy-duty route between
Grand Junction and places of oil-shale employment follows a zig-zag
course northeast for 60 miles, then 20 miles to the northwest. A daily
160-mile (260 km) round trip would be intolerable for almost everyone.
A slightly more direct route exists, but it is now only a dirt road in
parts and would only cut about 10 miles from the one-way commuting
distance even if it were improved; (3) In accordance with the objective
of analyzing the implications of growth for administrative units, Rio
Blanco and Garfield Counties have been selected as the geographical
base. Piceance Creek is about in the center of this two-county area,
and the layout of roads in the region also makes this area a logical
unit for the analysis of local impacts.
The maximum credible level of oil-shale mining and retorting would
require an annual rate of population growth of between 16 and 19 percent
between 1975 and 1990, after which growth would level off. Population
would grow almost tenfold during the first 15 years. As Figure 22-10
shows, the population of the two counties would climb to 56,000 in 1980,
135,000 in 1985, 220,000 in 1990, and level off to 245,000 in 1995.
This population would not be distributed evenly over the vast land
area of the two counties. The presence of the White River and Routt
National Forests in the eastern portion of the two counties would
831
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preclude residential development in about 1000 square miles (2600 km8).
Steep canyon sides and higher elevations would also be unsuitable for
residential development. The only land remaining would be along broad
valleys and upland plateaus. Much of this would be restricted as well
because of lack of access by road. Areas classed as suitable for resi-
dential settlement by a recent study made up only 7 percent of the area
of Garfield County, and 17 percent of Rio Blanco County.7 Since oil
shale lands in the Piceance Basin were included in the classification,
the actual proportions would be somewhat less. Existing towns would
likely absorb the bulk of the increased population, with the remainder
absorbed along existing transportation routes. The only other Colorado
county to have undergone industrialization recently, Pueblo County, has
82 percent of its population living in urbanized areas. As an indicator
of expected urban population in Rio Blanco and Garfield Counties, this
proportion is probably low; nevertheless it would yield an urbanized
population of 176,000 in 1990. Rifle and Meeker, closest to the oil
shale sites, could well become cities of 50,000 or 60,000 people.
Such sudden increases in population would strain every social and
institutional resource in the region. Mobile homes would be strung out
along every canyon and river valley, the Colorado River would receive
urban waste water, schools would be vastly overcrowded or nonexistent,
public expenditures would soar faster than population, and services
would be unable to catch up with growth. Real estate speculation would
become a major industry, while tourism, which grew during the 1960s,
would probably decline. Labor turnover would probably be high. Com-
petition for scarce land in valleys and upland plateaus would pit resi-
dential development against recreation, farming, transportation, tourism
and other interests seeking to use the same land. If the oil shale
industry were developed to its maximum possible extent, opportunities
for diversification of the local economy would decline. The maximum
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credible level of oil shale production would lead to the sacrifice of
"option values" for land use, that is, the implementation of decisions
whose consequences might be irreversible.
F. Oil Shale Development Constrained by a 5 Percent Annual Growth
Rate—Piceance Basin
Figure 22-8 shows the extent of oil shale development possible
within an annual growth rate of 5 percent. In contrast to the maximum
credible case, population would rise gradually from its current 23,500
to 28,000 in 1980, 41,000 in 1985, 52,000 in 1990, 65,000 in 1995, and
79,000 by the end of the century. Daily capacity for crude oil produc-
tion would be 400,000 barrels (64,000 m3/D) one-fifth of the capacity
hypothesized for the maximum case. Instead of boomtowns of 50,000
people by 1990, cities closest to places of oil shale employment would
number only about 10,000 inhabitants. Reduced population pressures
would allow for needed planning of residential development so that
mobile home sites and other settlements could be located with least
damage to environmental values and amenities. Due to the shortage of
suitable residential land, however, some real estate speculation and
competing land uses could still be expected. The strain on local gov-
ernmental fiscal capacity would be substantial, particularly in the
area of schools and roads, but not nearly as severe as in the maximum
case. For those services whose cost rises steeply with geographical
dispersion, practically no economies of scale would be realized. Even
if immigrants settled predominantly in the existing towns of Rangely,
Meeker, Rifle, and Glenwood Springs, those towns themselves are sep-
arated from one another by large distances. Rangely, for example, is
78 miles (130 km) away from Meeker, and Meeker is another 67 miles
(110 km) from Glenwood Springs. Thus needed public expenditures for
those services would continue to rise throughout the entire course of
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growth. These expenditures would be small compared with those required
by the maximum level of development.
Unlike Campbell County, Wyoming, Rio Blanco and Garfield Counties,
Colorado, have not experienced boomtown growth rates recently. Garfield
County's growth rate between 1960 and 1970 was 2 percent a year, and Rio
Blanco County lost population in that decade. A growth rate of even as
little as 5 percent a year would be a big jump, while a growth rate of
16 to 19 percent annually would be extremely high. This lack of com-
parable experience would undoubtedly handicap the western Colorado
counties in adapting to rapid industrial and urban growth.
G. Implications for Appalachia
The coal mining regions of Appalachia currently have a much larger
population base than the resource-rich regions of the West. Eastern
Kentucky, southern West Virginia, and southwestern Virginia still have
substantial reserves of bituminous coal averaging 10,000 to 12,000 Btu
per Ib (23 MJ/kg to 28 MJ/kg) and a labor force experienced in the tech-
niques of coal mining. The Big Sandy Area Development District, a 5-
county region of eastern Kentucky, contains 143,000 people (1972 local
planners' estimate). The 5 counties—Floyd, Johnson, Magoffin, Martin,
and Pike—form a land area of 1979 square miles (5100 km8), less than
half the area of Campbell County, Wyoming. It would appear that a popu-
lation base of that size could-more easily absorb the growth induced by
a synthetic fuels industry than Campbell County could. Before reaching
such a conclusion, however, it should be noted that the present popula-
tion is overwhelmingly rural. Only 10 percent live in towns of more
than 2000, and only 15 percent live in towns of any size at all. Coal
mining in Appalachia has traditionally coexisted with a predominantly
rural culture. A synthetic fuels industry, on the other hand, would
834
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require large urban concentrations, and these simply do not exist near
the coal fields. Thus while the present population base is numerically
adequate to accommodate such an industry, it is not distributed in ways
that are immediately useful to the industry.
Related to the low degree of urbanization, Appalachia has been
deficient in the social institutions necessary to manage an industrial
economy. County governments in the coal-producing regions undertaxed
productive resources and so never received a fair share of the region's
wealth. As a result they were unable to finance needed services such as
education, road-building, utilities, planning, and so forth. The capac-
ity to deliver services adaptable to an urban environment has never de-
veloped in Appalachia, partly because these were not needed by a popu-
lation traditionally reliant on kinship as the source of mutual aid,
and partly out of distrust of government in general. New industries
have not been attracted to Appalachia because the region either chose
not to or failed to develop this institutional and service capacity.
As far as a new industry such as synthetic fuels is concerned, then, the
region is really no better adapted to urbanization and industrialization
than is the sparsely populated Powder River Basin.
In Appalachia, constraints besides the size of the population base
are of the greatest significance. Bitterness on the part of many people
in the region toward the coal mining industry has flared up in recent
years in acts of industrial sabotage costing millions of dollars.8 In
less dramatic ways, grass-roots organizations like Miners for Democracy
and Appalachian Coalition Against Strip Mining have questioned the wisdom
of industry domination of their region and have begun to attract a fol-
lowing in Congress and in state legislatures. The United Mine Workers
of America has begun to take a much tougher bargaining stance than did
previous union leadership. The collective bargaining agreements of
December 1974 brought coal miners nearer to wage parity with other
835
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industrial workers than previous negotiations had even attempted to do.
The greater productivity of the coal mines has increased the amounts gen-
erated for the union's health and welfare fund by the tonnage royalty.
Also, the greater educational attainment and lesser age of the new labor
force make workers less tolerant of unnecessarily low safety standards
and working conditions. These factors are probably more important con-
siderations on the part of the mining industry as to the location of
synthetic fuels facilities than are demographic factors.
H. Implications for Southern Illinois
Judging by demographic and geophysical characteristics, southern
Illinois would appear to be less disrupted by the growth of a synthetic
fuels industry than the other regions would. In contrast to the sparsely
populated West, southern Illinois has a large enough population base to
accommodate industrial growth without sustaining a large percentage im-
pact. In contrast to Appalachia, it is not isolated by geographical
and cultural factors from modern industrial society. The 6-county area
of Franklin, Jefferson, Perry, St. Clair, Washington, and Williamson
Counties comprise a land area of 3112 square miles (8100 km2), somewhat
smaller than Campbell County, Wyoming, in size. Their total population,
however, is 437,500, large enough to absorb a new labor force and asso-
ciated population without severe stress. Unlike Appalachia's population,
it is concentrated in urban areas in a way that makes it accessible to
industrial employers. In only 1 of the 6 counties is the population
predominantly rural—Washington County, with 78 percent of residents
in rural places. St. Clair County's population is overwhelmingly urban
(83 percent) due to the presence of East St. Louis. The other 4 counties
have a rural-urban mix of about half and half. Thus the urbanized base
necessary for industrial growth is substantially already in place.
836
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The necessity for large numbers of immigrants to the area would be
lessened by the prevalence of higher-than-average unemployment rates.
Rates ranged from 3.9 percent in Washington County to 6.8 percent in
Franklin County in 1970. Even if renewed coal mining activity in the
past 5 years has employed some of these people, a large amount of un-
employment in neighboring cities has probably persisted. St. Louis,
Missouri, had 16,000 unemployed persons in 1970; Evansville, Indiana,
had 2700 unemployed persons.8 Some proportion of Chicago's 64,000 un-
employed might also be attracted to employment in southern Illinois.
Southern Illinois has an established coal mining industry. The
6-county region produced 37 million tons (33 billion kg) of coal from
20 operating mines in 1972, more than half of the total coal production
in Illinois in that year. Two billion tons (1.8 trillion kg) of strip-
pable reserves and 19 billion tons (17 trillion kg) of deep reserves
remain in the region. The coal has a heating value of 11,000-12,000 Btu
per pound (26 MJ/kg to 28 MJ/kt), about midway between that of Powder
River Basin coal and Appalachian coal. Southern Illinois has a rela-
tively diversified set of service industries, and access to a large
urban center, St. Louis, for many industrial needs. Existing service
industries and governmental capacity should therefore reduce requirements
for additional population, relative to the other resource-rich regions.
In southern Illinois agriculture has a relatively higher value than
in Appalachia, or than ranching and farming in the resource regions of
the West. Agriculture would undoubtedly be disturbed by large-scale
surface mining operations, to some extent. This impact, however, would
be mitigated by the following factors:
(1) The reclamation potential of southern Illinois farmland
is greater than that of either the arid western regions
or Appalachia. (See Chapters 13 and 15.) Its superior-
ity over the arid West is that rainfall can be expected
to be adequate to stabilize and restore the land. Its
837
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superiority over Appalachia is due to the fact that the
county consists of flatlands and rolling hills rather
than steeply contoured slopes.
(2) Surface mining in southern Illinois could actually im-
prove agricultural productivity because it would break
up the subsurface impervious soil layer, or hardpan,
that prevents adequate drainage.
I
(3) Custom and practice in southern Illinois indicate that
agriculture and coal mining can coexist more readily than
in the other resource-rich regions. Many coal miners
have traditionally worked their own farms in addition to
being employed at mining. The proportion of farm oper-
ators (as defined by the 1970 Census) who worked 100 days
or more per year off the farm was more than half for the
region, while the statewide figure was one-third. While
the discipline of a large industrial workplace might not
be compatible with such dual employment, the mining ac-
tivity itself clearly is.
Southern Illinois also derives some advantages from being close
to eastern and midwestern energy markets, Ohio River and Mississippi
River barge transportation routes, and a major rail terminus from the
West. Compared to the other regions discussed, it is well located for
domestic energy production.
I. Summary
In assessing the impact of development, we usually apply the con-
cept of damage, reversible or irreversible, only to the natural environ-
ment. Certain actions can cause irreversible environmental damage; for
example, radioactive wastes contamination and the extinction of rare
species are examples of irreversible consequences of human action.
Whether environmental consequences are long-lasting or not depends on
human ability to regulate development in accordance with environmental
standards. Similarly, adverse social consequences are controllable by
concerted effort and proper planning.
838
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The foregoing analysis has suggested that adverse social impacts
could be mitigated by the following actions:
• Building smaller plants (conversion facilities).
• Exporting coal.
• Phasing employment buildups and layoffs so as to minimize labor
shortages and unemployment.
• Pay-as-you-grow system of public finance to avert tax lag.
• Fair valuation of all taxable productive wealth.
• Governmental-industry cooperation in community-building.
• Rational land use policy for agricultural, range, industrial,
residential, and recreational uses.
• Full public participation in decision-making affecting funda-
mental values and interests.
• Diversification of local economies.
• A system for compensating involuntary displacees.
• Adequate reclamation of land.
It has been shown that the consequences of a 5 percent annual
growth rate are far less severe for communities than production at the
maximum theoretical level would be. The dynamics of growth at the
theoretical upper limit of synthetic fuels production would probably
cause lasting damage in the form of costs payable by future generations,
cycles of boom and bust, massive disturbances of land, rapid, perhaps
unwanted change in living conditions, and narrowing of options. A
5 percent growth rate would allow time for needed planning and devel-
opment of public services and amenities. The job of community-building,
in short, would be brought within the range of possibility by such a
constraint.
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REFERENCES
1. MIT Report to the Club of Rome, Limits to Growth, Signet, New York
(1972), R. Barnet and R. Muller, Global Reach, Simon and Schuster,
New York (1974), E. J. Mishan, Technology and Growth, Praeger, New
York (1973), exemplify the three strains of criticism.
2. Bureau of Reclamation and Montana State University Center for Inter-
disciplinary Studies, "The Anticipated Effects of Major Coal Devel-
opment on Public Services, Costs and Revenues in Six Selected
Counties," Billings (1974).
3. W. Thompson, A Preface to Urban Economics, Johns Hopkins, Baltimore
(1965) and H. Richardson, Urban Economics, Penguin, Baltimore (1971),
4. G. Sternleib, et al., Housing Development and Muncipal Costs,
Rutgers University, Center of Urban Policy Research, Brunswick,
New Jersey (1973).
5. H. Blumenfeld, "The Economic Base of the Metropolis," Journal of
the American Institute of Planners, v. 21 (1964).
6. L. Bender and R. I. Coltrane, "Ancillary Employment Multipliers for
the Northern Plains Province," paper presented at joint meeting of
Western Agricultural Economics Research Council, Committee on
Natural Resource Development and Community and Human Resource
Development, Reno, Nevada (January 7-9, 1975).
7. "A Description of Physical Characteristics," THK Assoc. , Inc.,
unpublished report for the Oil Shale Regional Planning Commission,
Rifle, Colorado (1973).
8. H. M. Caudill, My Land is Dying, Dutton, New York (1973) .
9. Population and Other Demographic Data from "County and City Data
Book, 1972, A Statistical Abstract Supplement," U.S. Government
Printing Office, Washington, D.C. (1973).
840
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-600/7-76-004B
2.
3. RECIPIENT'S ACCESSIOONO.
TITLE AND SUBTITLE
IMPACTS OF SYNTHETIC
Automotive Market
Volume II
LIQUID FUEL DEVELOPMENT —
5. REPORT DATE
May 1976
6. PERFORMING ORGANIZATION CODE
ECU 3505
7.AUTHORIS) E.M. Dickson, R.V. Steele, E.E. Hughes,
B. L. Walton, R.A. Zink, P.D. Miller. J.W. Ryan. P.B.
Simmon, B. R. Holt. R. K. White, E. C. Harvey, R. C
R. Cooper, D. F. Phillips, W. C. Stoneman
8. PERFORMING ORGANIZATION REPORT NO
ECU 3505
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Stanford Research Institute
Menlo Park, California 94025
10. PROGRAM ELEMENT NO.
EHE 623
11. CONTRACT/GRANT NO.
68-03-2016
12. SPONSORING AGENCY NAME AND ADDRESS
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
13. TYPE OF REPORT AND PERIOD COVERED
Final, Series 7
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES Work was compieted by EPA contract entitled, "impacts of Synthetic
Liquid Fuel Development—Automotive Market," No. 68-03-2016, covering period June 20
1974 to June 14. 1976. Work was completed as of June 14, 1976.
16. ABSTRACT
This study assesses the impacts of the development of synthetic liquid fuels
from coal and oil shale; the fuels considered are synthetic crude oils from coal
and oil shale and methanol from coal. Key issues examined in detail are the
technology and all of its resource requirements, net energy analyses of the techno-
logical options, a maximum credible implementation schedule, legal mechanisms for
access to coal and oil shale resources, financing of a synthetic liquid fuels
industry, decision making in the petroleum industry, government incentive policies,
local and national economic impacts, environmental effects of strip mining, urbani-
zation of rural areas, air pollution control, water resources and their availability
and population growth and boom town effects in previously rural areas.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
coal
oil shale
synthetic fuels
methanol
air pollution
environmental impact
economic impacts
boom towns
water resources
strip mining
control technology
incentive policies
h.lDENTIFIERS/OPEN ENDED TERMS
synthetic fuels tech-
nology
net energy analysis
c. COSATI Field/Group
3. DISTRIBUTION STATEMENT
19. SECURITY CLASS (This Report)
UNCLASSIFIED
21. NO. OF PAGES
860
20. SECURITY CLASS {This page}
UNCLASSIFIED
22. PRICE
EPA Form 2220-1 19-73)
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